How Likely Is $4 Gasoline?

The recent 19 cent per gallon surge in the average retail price of gasoline has raised concerns that sustained high oil prices and seasonally-stronger refining margins could push US gas prices to $4.00 this spring. But while the recent seasonal patterns make it likely that prices will strengthen from the current $3.13 per gallon to at least $3.50, even with a weak economy, going much beyond that would probably take more than just the routine level of annual refinery maintenance. Breaking the next even-dollar milestone for the national average by the Fourth of July would require a combination of serious supply problems and expensive oil.

Although it may not be obvious at the gas pump, weak refining margins have shielded gasoline consumers from the full impact of $100 oil, so far. Using the commodity prices on the New York Mercantile Exchange as a simple proxy for refining margins, wholesale gasoline has averaged only $0.12/gallon above crude oil this week, well below the average for 2006 and 2007, and much lower than the second quarters of both years, when prompt gasoline futures averaged $0.63/gal. over the light sweet crude contract. That suggests that if oil prices remained near their current level, and refinery maintenance and unanticipated shut-downs were comparable to the last couple of years, then retail gasoline could average as much as $3.70/gal. nationally this spring, perhaps reaching $3.90/gal. for brief periods. In its most recent weekly oil report, however, the Energy Information Agency of the Department of Energy anticipates lower refinery maintenance than last year, along with lower gasoline demand, so those figures look like upper bounds, unless you live on the West Coast.

Californians routinely pay more for gasoline, for reasons I've described at length. Among other factors, the state-mandated fuel formulation is harder to make, and the gasoline tax is 17 cents per gallon higher than the national average. Residents of San Francisco are already seeing street prices above $3.70/gal., though they can beat that by at least 30 cents if they shop around. L.A. appears to be about a dime lower. From those levels, $4.00 gas confined to California won't require much of a stretch.

Trying to gauge the likely course of national gasoline prices this spring is complicated by uncertainties about ethanol. In previous years, shortages of ethanol have contributed to higher gas prices. At the moment, after accounting for transportation by rail and the $0.51/gal. blenders' credit, ethanol prices look cheaper than wholesale gasoline, so the continued expansion of ethanol production might help hold down increases in gasoline prices by a few cents per gallon. The wild card is the increased Renewable Fuel Standard created by the 2007 Energy Bill. It requires refiners to add about one-third more ethanol than they did last year. Logistical bottlenecks could impede that process and push up the price of the ethanol that can reach end markets, nudging gas prices even higher.

The scenario for a $4.00 per gallon average US retail gasoline price thus requires a combination of several non-routine factors: a larger-than-expected reduction in gasoline production than from scheduled refinery maintenance alone, a difficult transition to the higher ethanol mandate, or something that impeded our imports of a million-plus barrels per day of gasoline from offshore. And it's predicated on sustained oil prices at or above $100/barrel--a highly uncertain proposition, given the tension between weakening demand and a weakening dollar. The only thing certain about $4.00/gal. gasoline is that if oil prices keep rising, we'll get there eventually. This spring might only be our first shot at it.

A Cold, Dim January

The case for global warming, which has gained much wider acceptance in the US in the last several years, rests in simplest terms on the observation of temperature trends and their extrapolation into the future. The general hypothesis about the role of greenhouse gas emissions and the other factors that nudge the global climate in one direction or another fits those observations pretty well. But what if the key temperature trend broke, or appeared to? Would that undermine the scientific consensus, and by extension the growing policy consensus to address the problem more directly, such as with a cap on emissions? A blog posting making the rounds on the Internet might put that question to the test, though in my assessment it falls well short of demonstrating that the earth is now cooling, rather than warming.

Start with two facts: First, the global temperature this January, measured by both satellite- and land-and-ocean-based instruments, was significantly colder than last January's, which had been significantly warmer than any January in at least a century. From one January to the next we have experienced a fairly dramatic cooling, on the order of 0.7 degrees C or 1.2 deg. F. As the blog cited above put it, that's almost enough to wipe out the last century's worth of warming. Next, consider that this cooling has occurred at a time when the sun's output is at a cyclical minimum, with the onset and intensity of the next sunspot cycle still in doubt. Humans are hard-wired for pattern-seeking, and it's not hard to connect these dots and start to worry that greenhouse gas emissions might not matter as much as we thought, and that we could be on the threshold of another Maunder Minimum, which coincided with the "Little Ice Age"--remember Frost Fairs on the Thames and Washington dodging ice floes while crossing the Delaware?

Given only the information above, one might logically conclude that 2007 must have been an unusually chilly year, globally. In fact, it turns out to have been the second-warmest year on record, behind 2005 and in a statistical tie with 1998. And when you examine the temperature data from NASA's Goddard Institute for Space Studies, you see that despite a 0.75 deg. C drop from one January to the next, only two months last year were 0.1 degrees or more colder than the average for that month this decade, which so far has averaged 0.3 deg. C warmer than the 1990s. The mean global temperature in 2007 was actually a full degree Fahrenheit warmer than the average for the 1950s through 1970s, the baseline period against which the "temperature anomalies" reported by NASA are calculated. If the long-term trend reflected is this data is going to be broken, it will take a lot more than one cold January--a January that incidentally was still slightly warmer than the same-month average for 1951-1980--to signal that we're in a cooling trend, or no longer warming.

The variability of the sun's output hasn't gone unnoticed. Having invested a lot of time in poring over the scientific literature on climate change, I can assure you that climate scientists are not ignoring the behavior of the largest heat source within four light years. As NASA's Dr. Hansen explains, however, even a sustained period of solar output at the current low levels would not overwhelm the warming effect from greenhouse gases, which is accelerating with increasing emissions. Another Maunder Minimum would be unlikely to produce the same results as the last one, because today's atmospheric CO2 is about 25% higher than the prevailing level, then. The earth might not warm as quickly as it has been, but it probably wouldn't start cooling off.

Climate is what we expect, weather is what we get, and both are subject to complex influences and patterns. I'm not prone to dismissing the arguments of climate skeptics out of hand, but at this point the swing from last year's unusually warm January to this year's cold one--with a warm spring and summer between them--seems better explained by the current La Niña episode than by a quiescent sun and the onset of global cooling. If the next couple dozen months turn out to be mostly cooler than the recent average, and if the sunspot cycle hasn't ramped up by then, I would have to revisit that conclusion.

By the way, Energy Outlook just received some very welcome recognition, being cited by The Times (of London) as one its "Top 50 Eco Blogs."

Quit While We're Ahead

The nation's Strategic Petroleum Reserve is back in the news. The Senate Committee on Energy and Natural Resources, chaired by Jeff Bingaman (D-NM) is holding hearings on the management of this program by the Department of Energy, focusing on its policy of continuing to fill the reserve, regardless of price. Senator Byron Dorgan (D-ND) has introduced a bill that would suspend SPR additions until oil prices are significantly lower. With the SPR approaching its maximum capacity, and with oil prices having crossed the $100 mark, a time-out seems appropriate, in order to ensure that the SPR does not contribute to the high energy prices that are fueling inflation, rather than acting as a moderating influence.

Conceived in the 1970s, the SPR has provided an insurance policy in case of a serious disruption in the global oil market upon which the US relies for its oil imports, which have more than doubled since the SPR opened in 1975. Although SPR oil has been loaned to refiners on numerous occasions, it has only been released via sale during perceived crises, including the Gulf War and after Hurricane Katrina. When President Bush took office in January 2001, the SPR inventory stood at 541 million barrels (MB). Since then, this administration has added a net 157 MB of oil, including 49 MB in 2002, when the price of WTI averaged $26.15/bbl, another 37 MB in 2003 ($30.99) and 2004 ($41.47), and 27 MB (at roughly $53,) prior to Katrina in 2005. Since then, purchases for the SPR have been running at a slower rate, with 7.7 MB injected during 2007, when oil averaged $72.41/bbl.

In retrospect, most of those additions look like a good investment, though since oil prices started rising in 2003, they have been controversial. While they certainly contributed to the pressures that have caused oil prices to triple since the end of 2003, that contribution has been relatively minor, weighed against the growth of China, a war in Iraq, chronic unrest in Nigeria, and the deliberate impairment of the Venezuelan oil sector. But although the contemplated fill rate of 125,000 barrels per day (bpd) constitutes only 1.25% of US oil imports and 0.3% of global oil trade, it abets the psychology of a market speculating that even higher prices lie ahead. Although a policy of buying predictably, whether prices were low or high, had its merits in the past, that policy has run its course in terms of the marginal benefits of any further additions.

As of last week, the SPR stood at 96% of its maximum capacity of 727 million barrels. At its maximum drawdown rate of 4.4 million bpd, the difference between 96% and 100% would only be one week of supply, at the end of 23 weeks. In any crisis severe enough to cause us to drain the SPR at its maximum sustainable rate for 5 months, it's hard to envision one week making much of a difference; however, it makes a difference now, by implicitly validating a bullish view of prices and competing with refiners' purchases. Any contribution by the SPR program to higher oil prices only compounds the forces driving wholesale inflation to levels we haven't seen in decades.

While I would like to see the next administration undertake a comprehensive review of the entire SPR strategy, the question today is much simpler. Is it prudent for the government to continue buying oil at an all-time record price, or should it take a breather while the market sorts itself out? If oil is still trading over $100 in six months, the DOE could resume buying, without having lost anything meaningful to our security--energy or otherwise. And while no one can be sure that suspending the SPR fill would dampen the market's enthusiasm for $100 oil, it surely can't hurt.

Our Nano-future, Now

I recall reading K. Eric Drexler's landmark book on nanotechnology, "Engines of Creation," sometime in the late 1980s or early 1990s and being bowled over by the potential it represented, including science-fictional possibilities of being able to build objects and devices essentially one atom at a time. As was the case with the first stages of biotechnology, no one could predict the kind of practical fruits that such an entirely new area of science would yield, or how quickly. Lately, I've been struck by the appearance of multiple applications of nanotechnology to energy, at least on a laboratory scale. Whether any of these ultimately becomes commercial may matter less than the signal this sends about how rapidly nanotechnology is maturing and being integrated into technologists' toolkits.

A decade ago, the most promising energy-related nanotechnology research appeared to be the use of carbon nanotubes for hydrogen storage. That work is still progressing, and if hydrogen becomes a mainstream transportation fuel, nanotubes ought to give pressurized storage and metal hydrides some stiff competitions. In the meantime, however, a number of other lines of nanotech R&D are producing interesting results with possible energy applications. These discoveries run the gamut from the merely intriguing to the potentially transformational. Here are some of the recent announcements:

• Silicon nano-wires that dramatically increase the energy storage capacity of Lithium-ion batteries, while also reducing recharging times. If they work as expected, we might be able to bypass plug-in hybrid cars (PHEVs) and go straight to long-range electric vehicles, or build practical PHEVs with very small onboard generators.
• Nanowire solar cells that allow for greatly increased photovoltaic efficiency at little or no extra cost. That would reduce the area necessary to generate a desired quantity of power, while incidentally reducing the cost of the non-PV components of a solar power installation.
• Nanowire fabrics that generate electricity from the energy of the wearer's motion. Initially these might provide power for medical devices or sensors, but eventually could recharge your phone or iPod--or even make entirely unanticipated forms of consumer electronics possible.
• Nanoparticles that enhance the electrolysis of water for hydrogen production. Reducing the energy losses from electrolysis could make truly zero-emission hydrogen from renewable electricity more competitive with hydrogen produced from natural gas--the main source today--and it might also make reversible fuel cells an effective solution for matching the intermittent output of wind and solar power to grid demand patterns.

As exciting as all this is, it's also worth noting that we don't yet understand all the risks entailed in working at nano-scale. We needn't worry about the possibility of "self-replicating assemblers"--the genesis of the infamous "Gray Goo Problem"--for some time. Nevertheless, nano-materials, objects with at least one dimension of approximately one-billionth of a meter in length or less, may pose health risks, because biological life on earth never evolved to deal with them. As with the development of any new industrial chemical, the long-term environmental impacts of these materials must be addressed in tandem with their applications. A bit of caution is in order, though it still appears that a field that not long ago seemed highly speculative could have an impact on the problems of energy security and climate change in the near future.

The Tax Debate

It's not unusual for politics to focus more on perceptions than reality, but there are few areas in which those perceptions are more divorced from fact than on the subject of taxes, and that is particularly true in this election cycle. Various candidates propose tax cuts, the repeal of tax cuts, a "fair tax", and other options affecting taxation, but few of them begin by describing the magnitude of current taxation, its allocation between individuals and corporations, and the relative tax rates paid by these different segments. The resulting distortions are especially glaring when it comes to the taxes paid by the energy industry.

The debate over whether to tax the oil industry to fund subsidies for alternative energy and energy efficiency is a small aspect of the larger discussion over the appropriate level of taxation on businesses and individuals. The argument to withdraw certain tax benefits from the highly-profitable US oil industry is founded on the perception that the oil industry is under-taxed, violating Americans' sense of fairness. While it is indisputable that the domestic oil and gas industry has been making money hand over fist, the perception that it pays less tax than other industries is not only false but entirely contradicted by the government's own data in this regard.

The income tax on individuals raises about $1 Trillion annually, three times the amount collected from taxing corporate income. According to the Energy Information Agency of the Department of Energy, in 2006 the 29 companies included in its Financial Reporting System paid $90 billion in income tax--or 25% of all US corporate income tax receipts--on pre-tax income after adjustments of $222 billion. That yielded an effective tax rate of 40.7% before counting the $8 billion in production and other taxes they paid. This group of companies, which includes ExxonMobil, Chevron, ConocoPhillips, Valero, Tesoro and the US operations of BP and Shell, had combined revenues of $1.4 Trillion and accounted for about half of US oil and gas production and 80% of refining. By comparison, the effective tax rate on all US manufacturing companies was 22%. In other words, the oil and gas industry is already taxed about twice as heavily as all US industry.

It shouldn't surprise us that our perceptions about the tax burden on the energy industry are wrong, because commonly-heard assertions about the relative income taxation of individuals turn out to be equally flawed. In contrast to our sense that this burden falls mainly on middle-class Americans, the most recent data from the Congressional Budget Office show that the 2nd, 3rd and 4th quintiles of households by income, roughly corresponding to lower-middle, middle, and upper-middle income Americans, together earned 41.6% of all income and paid 16.6% of federal personal income tax liabilities in 2005, while the top 20% earned 55.1% of income and paid 86.3% of the personal income tax. The lowest quintile actually received a net credit. Nor is it true that this allocation has become less fair over time. Since 1980, the share of the income tax collected from the middle class has fallen by half, from 35%, and the load carried by the top quintile has increased by a third.

Now, it's possible to evaluate these figures and conclude that oil companies and wealthy individuals should pay out an even higher fraction of their incomes in taxes. The US still has a substantial budget deficit, and the likelihood of reducing expenditures by enough to close that gap seems low, when entitlements, defense spending and interest on the national debt account for most of the federal budget. But we need to understand that raising those taxes will have consequences, too. Energy companies already pay double the effective tax rate of all manufacturers, and raising their taxes will make them less competitive with other sectors of the economy, and with foreign firms, at a time when we claim to place a high premium on energy security.

We must also be realistic about how close alternatives and efficiency really are to being able to displace our oil imports. Domestic oil and gas still account for 45% of US energy production--eight times the contribution of the rapidly-growing non-hydroelectric renewable energy sector. Doubling our ethanol output over the next decade will only replace 3% of our net petroleum imports. In that light, penalizing our largest domestic energy sources to support our smallest, and basing the argument on a fundamental misunderstanding of how the country's tax burden is apportioned, seems unlikely to advance the cause of energy independence.

Oil's Geothermal Opportunity

Reading a recent article about the expansion of California's geothermal power capacity at the Geysers, northeast of San Francisco, I was again struck by how little geothermal energy resembles higher-profile, intermittent renewable sources such as wind and solar power, and how similar it is to the development and lifecycle management of large oil fields. That extends to dealing with a problem that wind and solar never face: although the wind will blow and the sun shine long after the last human is around to observe them, the type of geothermal reservoirs that we have successfully tapped gradually deplete, as their stored energy is carried away and their natural pressure declines--not unlike an oil or gas field. When you consider all the similarities, it is remarkable that more oil companies have not embraced this technology as the nearest alternative to their core business of finding hydrocarbons underground and bringing them to the surface.

Although I grew up less than 200 miles from the Geysers, I was surprised to see that in 2006 the field supplied almost 5% of California's electricity--more than wind and solar power combined--and it did so around the clock, operating in either baseload or load-following modes that wind and solar can't emulate without expensive energy storage. At the same time, despite significant investment in recent years, the area now produces about a quarter less power than it did at its peak a generation ago, because of the loss of steam pressure in the main reservoirs in contact with the hot rocks. A major project to recharge the water supply of the field recently restored about 10% of its generating capacity, and the new drilling and additional turbines described in the San Jose Mercury News article will increase that further, though with a finite, depleting life.

Geothermal is a natural fit for oil companies, because it capitalizes on existing oil and gas skills such as 3-D seismic interpretation, horizontal and directional drilling, reservoir management, and the extensive experience some companies have gained in reservoir heat management, which is a key aspect of enhanced oil recovery, ultra-heavy oil production, and in-situ oilsands development. The business model of a geothermal field, with its large up-front investment and gradually declining output--boosted at later stages by enhanced recovery projects--looks nearly identical to the established oil and gas model, with two exceptions, both of which make oil companies nervous. The market for the electrons it produces is quite different from those for oil and gas, and its economics are subject to the vagaries of government incentives, such as the renewable energy Production Tax Credit.

Of the large international oil companies, only Chevron (in which I own stock) seems to have a significant focus on geothermal energy, and much of that was inherited with its acquisition of Texaco, my former employer, and later Unocal. According to their corporate website, Chevron operates geothermal plants in Indonesia and Thailand generating a combined 1273 MW of power. As big as that is in geothermal terms, it only equates to about 5% of the company's daily production of natural gas. That proportion isn't limited by the size of the available geothermal resources, even in the US, but by the historically lower profitability of geothermal power, compared to upstream oil and gas projects. As access to new hydrocarbon reserves becomes increasingly constrained by geopolitics and other factors, and as legislation puts a higher premium on low-emissions energy sources, the relative attractiveness of geothermal opportunities should increase for all of these firms.

The R-Words

Despite much political rhetoric to the contrary, economists are not yet certain whether the US economy is in a recession, or merely experiencing a period of slowing growth. If history is any guide, and if we're lucky enough to experience a brief contraction instead of a lengthy slump, we might not even know for sure until after it's over. But with the odds of one now much higher than they were last year, I was surprised to read an article in the Financial Times suggesting that the prospect of a recession doesn't figure in the plans of many large energy companies. A review of some data from the early 1990s indicates that the industry is not as recession-proof as it might wish to believe.

Even without a recession, the growth of US gasoline demand has already slowed significantly from an average of just under 2% per year from 1992-2002 to about 1% per year over the last five years, as gasoline prices rose in tandem with crude oil. The Department of Energy hasn't finalized its 2007 figures, yet, but gasoline demand growth appears to have fallen below 0.5%, thanks to near-record prices in the second half of the year. But that's not as low as it can go. During the recession of 1990-91, gasoline demand shrank by an average of 1% per year, at a time when the average gasoline price was well under $2.00 per gallon in 2007 dollars. A couple of years of 1% declines would cut US gasoline demand by 180,000 barrels per day (bpd.)




Viewed in isolation, that doesn't sound like much. Now put it in the context of a federal renewable fuels mandate that will add another 4.5 billion gallons of ethanol per year within two years, or around 300,000 bpd, and two massive refinery expansions in Texas and Louisiana, which together could add at least another 250,000 bpd of gasoline supply by 2010. The net change over that period would reduce the current US gasoline deficit--the average daily quantity we must import--from 1.1 million bpd of finished gasoline and blending components to 400,000 bpd.

So far, this all sounds fairly positive for both the industry and the country as a whole: more domestic output, less consumption, and all at the expense of some foreign suppliers. The problem from an industry perspective, however, is what this could do to refining margins, because of the way the market functions. Imports come in when the local supply falls short and the local wholesale price increases by enough to cover the foreign price, plus freight and a profit for the importer. And while those imports are arriving, all the domestic refiners supplying that market benefit from the higher price, increasing the margin they make on the crude oil they process. Taking 700,000 bpd out of gasoline imports might still leave us short over the course of the year, but it would reduce the frequency and possibly the duration of periods when imports would be required in areas that don't rely on them for their base supply. I don't see how that could fail to take a bite out of refining margins, which for the last several years have been sufficiently robust to transform the refining sector from a perennial drag on oil company profitability into a major earnings contributor.

Irrespective of what might happen to crude oil prices in a slowdown, recessions and refineries don't go well together. Companies with a large exposure to refining, particularly the pure-plays and those with expansions coming on-stream in the next two years, ought to be thinking very seriously about how a recession might affect them, and making their plans accordingly.

And One Cent

Oil futures finally closed above $100 per barrel yesterday, yet the context could not have been more different from the first time the market flirted with this level, last November. Then, the global economy was still perceived as growing strongly, albeit overhung with housing and debt troubles, and the US stock market was 7% higher. Now, the world economy is losing momentum, and the push above $100/barrel seems less like a bold move into uncharted territory and more like the late-race effort of a tired marathon runner.

Reading the market has never been easy, and it is even more challenging when the trends and underlying fundamentals shift out of alignment. Although the oil market's $4.50/barrel move yesterday was apparently prompted by several superficially bullish news items, upon further reflection at least two of those look bearish. OPEC's contemplation of a cut in production, which helped push prices higher, must be seen as a purely defensive measure, a tactic to forestall a precipitous drop in oil prices when winter's higher demand abates and economic growth continues to weaken. OPEC learned some bitter lessons in this regard in the late 1990s.

Another event that fueled the market's jitters yesterday was the unfortunate accident at AlON USA's Big Spring, TX oil refinery. But with due deference to the injured workers and their families, it requires a deep-seated bias to view this event as anything but negative for oil, and mildly positive for refining margins. The shutdown of a 70,000 barrel per day refinery, representing less than 0.5% of US refining capacity, will put more oil into a market in which inventories have been growing steadily since the first week of January. Big Spring runs high-sulfur crude oil, so the differential between West Texas Intermediate and West Texas Sour should widen. That seems a poor reason for WTI to spike, unless the market is being driven by investor psychology and technical indicators, not fundamentals.

With the equity markets weak and the debt markets in a funk, there is a lot of money floating around looking for a big return, somewhere. At the same time that forecasts of 2008 oil demand are still being revised downward, investors are piling into oil futures in search of a fast buck, creating a recipe for higher volatility. It's hard to see $100+ oil being sustained, barring some event that actually takes a big slice of production off the market, rather than merely increasing anxiety about such a prospect, a la Venezuela.

As I've noted before, the price of oil is a peculiar indicator. Until it passes through the value chain and emerges as higher prices for petroleum products and the goods and services that require oil as an input, it remains a highly theoretical barometer for most people. Weak refining margins have buffered consumers from the full retail effects of the recent excursions into the high $90s, and with US gasoline inventories well above their seasonal norms, marketers will have a hard time passing on yesterday's uptick, except in the area directly served by the Big Spring refinery. The larger question is whether yesterday's $100 close will affect the behavior of consumers or investors, and if so, how? Perhaps having breached the magic mark, we will tuck it away in the backs of our minds until oil hits the next psychologically-significant milestone, as we seem to have done with $3.00 per gallon gasoline.

Mountains of CO2

Carbon sequestration looks like an essential tool for bridging the global energy economy between its fossil-fuel present and its greenhouse-gas-free future. Despite the recent cancellation or reorientation--depending on your perspective--of the Department of Energy's Futuregen initiative, the deployment of carbon capture and sequestration (CCS) technology to coal-fired power plants is quite possibly the only thing that will keep them viable, at least in the developed world. But carbon sequestration looks expensive, both in terms of the cost per ton of the carbon dioxide it keeps out of the atmosphere, and in the energy it would consume in the process. A discovery at UCLA could change that calculation and make CCS cheaper and more effective than with current technology.

Understanding why CCS is so difficult today requires a little knowledge about combustion and gas separation chemistry. When fossil fuels are burned in air, the resulting flue gas still contains all of the nitrogen of the original air, plus water vapor and CO2 from the hydrogen and carbon in the fuel, along with pollutants resulting from fuel impurities such as sulfur or the conversion of some of the nitrogen into nitrous or nitric oxide. It's not easy to separate the diluted CO2 from the rest of these gases, and the current industrial mechanisms for doing this require a lot of hardware and use a lot of energy.

The main current alternative involves burning the fuel in pure oxygen, either partially in a gasifier or completely in O2-blown combustion. The end-result of both of these processes is mainly water and CO2, which are easily separated, allowing the latter to be compressed and injected into depleted oil reservoirs or other geological storage. Unfortunately, producing the quantities of oxygen required by this approach adds significant costs and reduces net power output. In order for CCS to become cheap and easy, we need a simple, low-cost way to extract CO2 from a gas stream, and that's just what the researchers at the California NanoSystems Institute at UCLA appear to have developed, in the form of novel zeolite crystals with a very high affinity for CO2.

Zeolites are already used in a variety of industrial processes. One of their main features is their incredible porosity, which creates almost unimaginable surface area in a very small volume of material. Maximizing that surface area is important, because of the way other chemicals react with the catalysts or linking structures deposited on these surfaces. A pound of the new CO2-absorbing zeolite would have an effective surface area greater than 200 acres. And according to the paper the developers published in Science last week, a liter of zeolite could soak up 83 liters of CO2 gas, storing it until deliberately released. That means that power plant flue gas could be routed through beds of zeolite and emerge virtually CO2-free. From there, the CO2 could be released in pure form for compression and geological storage, or, if the zeolite proves cheap enough to make, it could simply be carted off for disposal. That strategy might even work for soaking up the CO2 from car engines, before it gets into the air.

Before we get too excited about the prospect of burying all of our CO2 in the form of zeolites, however, we need to realize how much we're talking about. The US produces almost 6 billion tons per year of CO2 from the combustion of fossil fuels. At 83 liters of CO2 stored per liter of UCLA's zeolite, we're still talking about 9 cubic miles of material, every year. And in terms of your car's exhaust, it would take about 175 gallons of the stuff to soak up the CO2 produced from burning 12 gallons of gasoline. In other words, while it could be used as a sort of "catalytic converter" for automotive CO2, your car would need a zeolite tank ten times larger than its fuel tank, and you'd have to empty it at every fill-up.

Even if the material in question might not be the best long-term disposal method for CO2, this could still be a hugely important development. If this zeolite proves to be as easy to mass-produce as those already in wide use, and if the CO2 it absorbs can easily be stripped out later, it could make carbon capture and sequestration extremely cost-competitive, compared to other ways of reducing greenhouse gas emissions. And because we already have an industry producing zeolites for other purposes, we might be able to mass produce this substance soon enough to make a difference, depending on how long it takes to get out of the laboratory.

Miles Per Dollar

Have you ever encountered an idea so blindingly simple and obvious that you slapped your forehead in frustration that it didn't occur to you first? I had one of those moments the other day, reading an article that popped up on my personalized MSN portal, concerning fuel economy comparisons. The link appears broken, but the gist of author's argument was that if we focused on how many miles our vehicles travel on a dollar's worth of fuel, rather than per gallon, we might make fewer unnecessary trips and choose more efficient vehicles to start with. I agree with that logic, though from my perspective "mp$" could be even more useful as we enter a world in which the gallons we're using aren't directly comparable, and as electricity enters the transportation mainstream, resisting easy conversion to gallons without heroic assumptions and creating potentially over-optimistic assessments of the overall efficiency of plug-in hybrid cars.

As fuel diversity increases, the utility of measuring vehicle energy efficiency in terms of miles per gallon (mpg) diminishes, unfortunately coinciding with a much greater emphasis on mpg thanks to last year's Energy Bill that raised the required new car fleet standard to 35 mpg. This is more than a technicality, when you consider that carmakers get to count "flexible fuel vehicles" (FFVs) that can run on E-85 or gasoline as though they achieved higher mileage on ethanol, rather than about a quarter less. The Energy Bill, which included provisions strongly promoting E-85 and FFVs, at least limited the contribution of this factor to 1.2 mpg of a carmaker's average through 2014, phasing out to zero in 2020.

I could not find any cars that were available in all possible energy permutations, but the 2008 Chevrolet Tahoe large SUV came close. It's available in gasoline, FFV and hybrid versions. With retail gasoline averaging $2.96/gal. this week and E-85 at $2.48/gal. (both varying widely by state,) and using the EPA's fuel economy estimates for this vehicle on both fuels, the "mp$" comparison is interesting:

• Tahoe V8 on gasoline: 5.4 mp$
• Tahoe V8 on E-85: 4.8 mp$
• Tahoe Hybrid on gasoline: 7.1 mp$

While I'm sure there are locations where E-85 would have an advantage over regular gasoline, that requires it to be priced in a way that fully reflects its 25% lower energy content.

The next comparison is between gasoline and diesel, which has been significantly more expensive than gasoline this winter. There are a few manufacturers with comparable cars available in both fuels, including Mercedes and Volkswagen. Since I couldn't find 2008 diesel results for VW, I picked the former's E-series sedan to compare. Since the gasoline E350 requires premium fuel, I added $0.25/gal. to the US average price.

• E350 6-cyl. on premium gasoline: 5.9 mp$
• E320 Bluetec turbodiesel: 7.9 mp$

Finally, let's compare a Prius-style hybrid with the likely result for a plug-in hybrid, such as the Chevrolet Volt. In the absence of actual efficiency data for the Volt, I assume it would be comparable to the Prius on gasoline. Electric efficiency should be around 4 miles per kilowatt-hour. The average residential electricity price last year was 10.7 cents/kWh, with some markets considerably above that and others offering time-of-day pricing that would allow for overnight recharging at a lower price, so the following is a rough estimate:

• Prius or Volt on regular gasoline: 15.5 mp$
• Volt on residential electricity: 37.4 mp$
• Volt in 50/50 driving mix: 22.0 mp$ (very impressive, but not quite the 100 mpg equivalent often touted)

Miles per dollar has much to recommend it, particularly for its simplicity and alignment with the priority consumers put on value. However, it also has two key disadvantages. Unlike mpg, it changes every time fuel prices do, so any comparisons based on mp$ are only snapshots at a point in time. Nor does it address the emissions associated with that dollar's worth of energy, though mpg doesn't do that, either. A carbon tax or cap-and-trade system would help align fuel prices with their environmental consequences and make the resulting mp$ comparisons reflect both price and emissions. In that case, mp$ would be a significant improvement over mpg, particularly in helping consumers cut through an increasingly complex set of different fuel and power-train options. And while I don't expect Congress to rewrite the new CAFE standard in mp$ terms, or carmakers to embrace a metric that calls some of their marketing into question, how hard would it be for consumer-oriented car websites to display mp$ alongside mpg? More information might just lead to better decisions.

Adversaries or Allies?

The final version of the Energy Bill that passed last December omitted several provisions that were near and dear to the hearts of its original sponsors and their supporters. One of those measures, the repeal of specific tax benefits for oil and gas companies, has just been reintroduced in the House of Representatives, sponsored by Congressman Rangel (D-NY.) Unfortunately this bill, which would also extend the renewable energy production tax credit (PTC) that is due to expire at the end of the year, repeats the error of pitting a key component of our current energy supplies against a growing segment of future supply. That is hardly a recipe for achieving energy independence, or in any way enhancing our energy security. I believe the impetus behind this urge to rob Peter to pay Paul stems from a misunderstanding of basic oil industry economics, distorted by the enormous profits that the big firms are earning in the current high-price environment.

Let's begin by acknowledging that the PTC should be renewed, and not just for another year or two. We can argue about whether it should eventually be phased out, as renewable energy becomes more competitive with conventional energy, but our all-or-nothing approach to this subsidy plays havoc with the pace of development of wind power and other alternatives. But that does not mean that the funding for the PTC should come at the expense of critically-needed supplies of oil and gas. With the US already reliant on imports for two-thirds of our crude oil needs and a growing share of our natural gas consumption, that is folly.

No one can argue that oil companies are suffering today, though it is also clear that US-based companies face enormous obstacles to remain globally competitive, when the vast majority of the world's oil reserves are controlled by national oil companies. Viewing the pending tax bill as counterproductive doesn't require justifying the industry's record profits or arguing that they are over-taxed already. Rather, it requires the simple recognition that today's huge profits are not being generated by projects currently under construction or in the planning stages, but by projects that were completed in the past, when oil prices and construction costs were much lower. Projects that were approved in the 1980s and 1990s with the expectation of earning a few dollars per barrel of profit are now generating margins in the tens of dollars per barrel. However, many of those mature producing projects also experienced years such as the late 1990s, when those returns were nonexistent or negative.

Other than helping to determine the total size of a company's capital and exploratory budget, the current profits on existing projects have nothing to do with decisions about which new projects to develop and which to put on hold. Those decisions are made based on calculations of expected net present value, after paying all relevant royalties and taxes, foreign and domestic. That's why the provision of HR.5351 that would limit the ability of companies to deduct foreign production taxes from their US income is so insidious. At a time when foreign governments are increasing royalties and taxes on new production, and with project costs having spiked dramatically in the last five years, anything that makes the incremental economics of new oil projects less attractive will result in lower future supplies, and still higher prices.

Every year, oil producers must replace the amount by which their annual output has declined, as a result of the depletion of mature reservoirs. A recent study by CERA put that rate at around 4.5%, though many believe it is higher. At a 4.5% decline rate, the US must replace the equivalent of over 200,000 barrels per day, just to stay even. That's equivalent to the net energy contribution of 14 billion gallons per year of ethanol, or the average output of 42,000 MW of wind power capacity. At that scale, anything that promotes renewables at the expense of the new oil projects needed to maintain output seems unlikely to result in a net energy gain for the country. In reality, we need both, if we're going to make a dent in our oil imports, as everyone seems to desire.

I know this is a tough sell, after a year in which ExxonMobil made $40.6 billion--after paying $30 billion in tax--and my old company, Chevron, reported $18.7 billion in after-tax income. But the real issue is not how much of those profits their shareholders (including me) should get to keep, but how to ensure that any additional tax burden is not added in a way that makes new production less attractive. Ultimately, we need the contribution of the new forms of energy that HR.5351 is seeking to promote via the extension of the PTC and other subsidies, but we still need the steady stream of oil and gas production that its funding mechanism would put at risk, if we want to get to a greener energy future without increasing our dependence on OPEC in the process.

A Pre-Determined Shift

The presidential race has shifted significantly with the results of Super Tuesday and the subsequent primaries, including yesterday's "Chesapeake" primaries, in ways that have important implications for US energy and environmental policy. Prior to Super Tuesday, it still looked possible that someone would win a major-party nomination without a strong commitment to addressing climate change. That prospect now seems very remote, and the impending alignment of a stronger federal focus on climate change with a greater emphasis from Corporate America suggests big changes ahead for how we produce and consume energy. The 2007 Energy Bill, with its mandates for biofuels and efficiency, was only a foretaste of what is likely to come.

One of the primary tools I use in my consulting practice is scenario planning, a process that assesses possible future outcomes for a specific question or issue by winnowing a broad range of uncertainties down to a few critical drivers of change. Periodically, this process also identifies fundamental forces that, upon examination, prove not to be very uncertain at all, making them quite powerful in shaping the future. A US Presidency that puts a high priority on addressing climate change aggressively now looks like such a pre-determined element.

Consider the positions of the two leading Democrats, Senator Clinton and Senator Obama, and the two leading Republicans, Governor Huckabee and Senator McCain. All four are on the record supporting a cap & trade system for reducing greenhouse gas emissions, with Senator McCain having co-authored the earlier legislation from which the pending Warner-Lieberman Cap and Trade Bill evolved. Their campaign websites, particularly those of Senators Clinton and Obama, are replete with proposals for improving energy efficiency and promoting renewable energy. Even though the Democratic Party's incredibly convoluted process for awarding delegates makes it extremely difficult to guess the outcome of the party's convention in Denver in August, and despite the slim possibility that someone other than Senator McCain could capture the Republican nomination in the Twin Cities in early September, the Intrade prediction market currently assesses the chances of someone other than the four candidates above becoming the next President at less than 2%.

Yesterday, at the annual energy industry conference hosted by Cambridge Energy Research Associates, a sister company of my sponsor John S. Herold, Inc., the CEO of ConocoPhillips expressed concern about a loss of US influence in the world, if we continue to "oppose action on climate change." I don't think he needs to worry. The leaders of the countries committed to combating global warming can read the tea leaves as well as Intrade's speculators; they see change coming, as we all should.

A dramatically different US stance on climate change in 2009 is now a virtual certainty. That means its consequences are, too: Sooner or later, we'll be paying even higher prices for fuel and electricity; efficient light bulbs and appliances will no longer be optional; and cars will generally become smaller, lighter, and more complex--and hence more expensive, at least in the short-to-medium term. I wonder if we're as ready for the reality of all that as many seem to be for the abstraction of tougher climate policies. We have about a year in which to prepare ourselves.

The Natural Gas Option

As I noted in last Friday's posting, two recent scientific studies have severely undermined the environmental rationale for conventional biofuels, including corn ethanol. But if corn ethanol no longer looks attractive as a combined solution for our energy security and climate woes, where should we turn for a better alternative? As odd as it might sound to promote a fossil fuel, rather than another form of renewable energy, our lack of focus on natural gas as a transportation fuel seems equally surprising and illogical to me. It might not be the long-term answer to our complex needs, but making greater use of natural gas in vehicles could provide a broad range of benefits, with fewer drawbacks than some of the alternatives we are pushing now.

In addition to the natural gas-fueled buses that are becoming commonplace in big cities, cars running on compressed natural gas (CNG) are already on the road, including CNG taxis and fleet vehicles. For consumers, Honda sells a natural-gas version of its popular Civic model, which can refuel either at home or at commercial CNG stations, of which there are about 850 nationwide. Although the EPA estimates that the equivalent fuel economy of the Civic GX is about the same as a gasoline-powered four-cylinder Civic, its calculated annual fuel cost comes in $658 lower. Unfortunately, it would take just over ten years to pay out the car's higher sticker price, relative to a comparably-equipped gasoline model. If demand for CNG vehicles took off, their cost premium should come down dramatically, since the technology involved is much less intricate than a hybrid's.

There are good reasons to compare CNG to ethanol. Much of the energy required to produce corn ethanol comes from natural gas, in the form of ammonia-based fertilizer and process heat generation. And unlike corn ethanol, CNG consumes virtually no petroleum in its manufacture or distribution. Even before the latest studies cast doubt on ethanol's greenhouse gas reduction credentials, the emissions from a CNG-powered car looked lower than those of one running on E-85, when viewed on a full "well-to-wheels" basis, coming in at around 25% less than conventional gasoline and even a bit lower than diesel. Emissions of traditional pollutants are low enough to qualify the Honda GX as a partial-zero-emission vehicle under California's strict regulations.

While both fuels face obstacles to wider distribution, CNG's might be easier to overcome. Ethanol's big problem is its incompatibility with pipelines, forcing producers to ship it long distances by rail, before being blended into gasoline at the distribution terminal nearest the retail site. Natural gas has no long-distance pipeline issues, aside from some regional bottlenecks, but faces something of a "last-mile" problem: compressing it and putting it into a retail dispenser. That still looks simpler than digging up tens out thousands of service stations to put in E-85 tanks, because station owners don't wish to forego diesel or unleaded premium sales to add a low-volume new product.

Whenever you add a new category of demand without changing existing supply, prices tend to go up, and that's certainly one risk of shifting some of our transportation energy burden onto natural gas. However, gas used in transportation represents such a tiny fraction of current consumption that it could increase by a factor of ten without causing major ripples. The US still has significant untapped natural gas resources, and global production is rising steadily. The bigger risk is that high oil prices will spill over to natural gas and shrink the latter's cost advantage, which is currently close to a 50% discount on energy content.

CNG isn't a silver bullet, any more than anything else is. However, it's an excellent alternative that's available now. It unambiguously improves greenhouse gas emissions compared to gasoline, and it enhances US energy security by diversifying our energy imports away from OPEC. Given those attributes, it's a mystery why it was virtually ignored in the 2007 Clean Energy Bill.

Barrel Rattling

The chance that Venezuelan President Chavez will follow through on his threat to cut off oil exports to the US, in retaliation for a freeze on Venezuelan financial assets secured by ExxonMobil, seems minimal. As today's Wall Street Journal notes, he probably gains more through the impact of the threat on oil markets than he could from its actual execution. Still, Mr. Chavez has earned his reputation for being mercurial and unpredictable. With high energy prices already contributing to the weakness of the US economy, how much damage could such an oil cut-off inflict?

As of November, US crude oil imports from Venezuela in 2007 were averaging 1.1 million barrels per day, or about 11% of all our oil imports, with most of it coming into the US Gulf Coast, followed by the East Coast and an occasional cargo to the West Coast. By contrast, that volume amounts to roughly half of Venezuela's total oil exports, corresponding to roughly 20% of the country's GDP at current exchange rates. While the global crude oil market would surely readjust to compensate for a Venezuelan oil embargo against the US, the financial consequences of the temporary chaos following such a move could be proportionally worse for the perpetrator than the victim.

At the same time, we shouldn't underestimate the fallout in domestic energy markets, and for the economy as a whole. Even in a globalized market for crude oil, it would take a while to work around such a significant shift. US refiners would have to scramble to purchase cargoes of oil from more distant suppliers, driving up the cost of shipping and bidding up the price of the nearest substitute grades of oil. Coming at a time when the output from West Africa has been reduced by problems in Nigeria, it could take a couple of months to arrange suitable alternatives. In the interim, commercial crude oil inventories, which have recently recovered to more comfortable levels, would fall dramatically, unless bolstered by releases from the Strategic Petroleum Reserve.

Nor would refiners be the only ones affected. Although oil futures seem to be pricing in some small probability of such an outcome, the actual event would drive prices up by a lot more than a dollar or two. A $10 per barrel spike, about the least I can imagine for such a disruption, would quickly translate into another $0.25/gallon or so at the retail level, pushing us close to a record high for gasoline. That would pinch the average household's budget to the tune of another $20/month, further squeezing a variety of merchants or adding to credit-card debt.

Mitigating against that eventuality is the reality of what such a cut-off would mean for Venezuela. Citgo, the US refining and marketing subsidiary of PdVSA, the Venezuelan state oil company, controls about 5% of US refining capacity. Its facilities would presumably be hit as hard as any others by an embargo. Meanwhile, just as US refiners would drive up the price of non-Venezuelan oil in their search for substitutes, PdVSA would have to discount its oil twice, to keep it flowing. That's because the cost of shipping it to Europe or Asia would be much higher than for the short voyage from Maracaibo to Houston, and because few refineries elsewhere are configured to extract maximum value from the heavy sour crudes that make up much of Venezuela's output.

While I'm skeptical that President Chavez's remarks about suspending exports to the US mean much outside the context of his ongoing dispute with ExxonMobil over the nationalization of their assets in his country, stranger things have happened. Given the general antipathy of his government for ours, I continue to believe that we would be wise to plan for this outcome occurring sooner or later, and wean ourselves from a supplier so bent on creating the perception of unreliability. A gradual divorce would hurt both countries a lot less than a sudden breach.

Ethanol Smoking Gun?

This morning's Washington Post and Wall Street Journal include coverage of important new scientific findings concerning the greenhouse gas benefits of ethanol. They refer to two key papers published in Science on the land-use impact of biofuels. One of these, by Searchinger, Heimlich, et al, suggests that when the global land-use consequences of our diversion of grain into fuel production are considered, the greenhouse gas balance for corn ethanol shifts from a modest reduction to a net doubling, compared to the oil it displaces. And although ethanol from cellulosic sources appears to be less harmful, it may still contribute more to global warming than previously thought. This is a stunning finding, with implications for the entire US energy policy, which prior to the fuel economy and other efficiency provisions of the 2007 Energy Bill has been largely an ethanol policy.

These results are bound to generate controversy, and I would echo calls for them to be confirmed by thorough peer review and additional studies. If they constituted the only concerns about the consequences of conventional ethanol production, prudence would dictate a carefully measured response. However, it has become increasingly clear over the last two years, as US ethanol production and consumption have ramped up dramatically, that it is a mixed blessing, at best. Not only is it no silver bullet for our energy and environmental challenges, but it has also contributed to worrying levels of domestic and global inflation in wholesale and retail food prices.

Public support for ethanol rests on three main benefits: that it enhances energy security, reduces greenhouse gas emissions, and bolsters US agriculture. Of these three attributes, the third is the least ambiguous. Ethanol's energy security contribution turns out to be more a matter of engineering a shift from imported petroleum to the imported natural gas and fertilizer consumed in the cultivation and processing of corn into ethanol, along with a roughly 30% uplift from the solar energy captured by the crops. Its climate change benefits have been viewed as modest but still important, with a generally-accepted figure of a 20% reduction versus gasoline. The latest studies turn that assumption on its head, suggesting that the climate and energy benefits are not actually complementary, but rather trade the former off against the latter. If confirmed by further studies, this conclusion must surely undermine popular and political support for corn-based ethanol.

We haven't had many opportunities to test the relative priority of our concerns about climate change and energy security. The lengthy evolution of the Energy Bill in the Congress last year provided one such occasion, though, when supporters of turning coal into liquid fuels were unable to convince a majority that the energy benefits of this relatively-proven technology outweighed the approximate doubling of greenhouse gas (GHG) emissions it would produce, relative to petroleum products. It's ironic that the GHG outcome for corn ethanol--one of the big winners in the 2007 energy legislation--now looks as bad as coal liquefaction.

In light of the new findings, I believe the most prudent and appropriate course of action would be as follows:

1. Freeze the conventional biofuel portion of the national Renewable Fuel Standard (RFS) in the 2007 Energy Bill at the levels that were in place before its passage. That would re-set the RFS for 2008 to 5.4 billion gallons, rising to 7.5 billion gallons per year in 2012, compared with a requirement for 9 billion gallons this year, rising to 15 billion by 2015.
2. Cap the volume of conventional ethanol eligible for the $0.51/gallon blenders' credit at 7.5 billion gallons per year, effective immediately.
3. Transfer the excess conventional biofuel subsidy--the amount associated with annual conventional biofuel volumes over 7.5 billion gal/yr--to cellulosic ethanol and other advanced biofuels meeting the greenhouse gas savings standards set by the Energy Bill.

Taken together, these actions would provide corn ethanol producers with a modest amount of headroom for further growth, but without a higher mandate to force their output into the market. At the same time, it would offer even stronger support for organizations developing cellulosic ethanol and other advanced biofuels, which still face significant obstacles to commercial production. What we can't do, however, is to pretend that the latest findings--because they are so inconvenient--are somehow irrelevant. They are strong indicators of the need for a major course correction on our path toward energy security that is also compatible with a safer climate. Expect to hear a lot more on this issue in the weeks and months ahead.

The Carbon Price Signal

The controversy over the cancellation of federal support for the Futuregen "clean coal" power plant project could continue for some time, with supporters referring their case to the Congress. Shifting the federal government's role in supporting carbon capture and sequestration technology to one of financing CCS at commercial coal plants certainly has the potential to move it into the mainstream faster than the Futuregen approach would have, though at the cost of at least a couple of years of project timeline recycling. Absent from this debate, however, is the most important factor in making the technology attractive to commercial power generators. We need to provide power plant investors with a revenue stream for CCS, in the form of a clear price signal on carbon dioxide emissions, whether from a carbon tax or cap & trade.

Yesterday I attended a lecture at Resources for the Future in Washington, DC by the Secretary of the Pennsylvania Department of Environmental Protection, Kathleen McGinty. Her talk focused mainly on the integration of big-picture greenhouse gas strategies such as cap & trade and carbon taxation with more targeted measures, such as state Renewable Portfolio Standards and Pennsylvania's requirement that all power load growth be covered by conservation and demand-side management. She cautioned against relying too much on a carbon price signal for the power sector, when legacy baseline power plants continue to receive substantial capacity payments and benefit from "locational marginal pricing", in which the price of power is determined by the last, most expensive increment. That's an important insight, but I would still conclude that for the wide deployment of CCS--which is otherwise all added cost and no extra revenue--only the prospect of avoiding a significant and relatively certain future cost will induce power plant owners to incorporate physical CO2 management into their facilities, unless it is required by law.

Secretary of Energy Bodman makes the case that since Futuregen was originally planned, a number of commercial coal power plants incorporating "clean coal" technology based on integrated gasification/combined cycle (IGCC) have been proposed, and that these plants are ideally suited for CCS. That's true, as far as it goes. Offering the developers of these plants federal funds to incorporate CCS might indeed accelerate the broad deployment of carbon sequestration, if the only cost difference involved were in the up-front investment required. But the physics of separating and storing CO2 ensure that a plant with CCS will generate less net power and cost more to operate than one without it. Even if CCS costs plant operators nothing up front, they face billions of dollars in higher expenses and lower revenues, over the life of each plant.

Without putting a price on carbon emissions, via either cap & trade or a carbon tax, federal subsidies for CCS construction costs can't make a dent in the emissions from a coal power sector that generated 70% more of the nation's electricity in 2006 than nuclear power and all renewable sources combined, including wind, solar and large-scale hydropower. Unless it includes a forthright discussion of how we establish a price for greenhouse gas emissions, the entire debate over the future of Futuregen rings hollow.

Nukes in the Middle East

This week's Economist makes a pretty good case that Iran has won its confrontation with the West over the issue of nuclear technology, largely as a result of the international interpretation of the recent US National Intelligence Estimate on Iran. That should lead to the gradual unraveling of the measures by the US and its main European allies to block Iran's nuclear enrichment program. But as the old cliché goes, every ending is also a beginning, and it's worth thinking about the kind of future that could grow out of this result. While it could eventually increase tensions in an already fraught region, it might also alter the energy geopolitics of the Middle East and help to address one of the biggest problems facing oil-importing countries: the rapidly growing internal energy consumption of the world's main oil exporters.

Anyone doubting the pivotal nature of the NIE in changing the debate on Iran need only watch the video from the recent World Economic Forum in Davos, Switzerland. In a panel on understanding Iran's foreign policy, the Minister of Foreign Affairs of the Islamic Republic of Iran, Manouchehr Mottaki, delivers the words of the NIE as his principal response to a question about Iran's nuclear ambitions, in his own articulate, minimally-accented English. (You have to skip almost exactly one hour into the video to get to this point. I can't fathom why the WEF folks didn't overlay the simultaneous translation of Mr. Mottaki's earlier Farsi statements, and those of Mr. Hashemi, a key advisor to President Ahmadinejad, into the video.) But without taking anything away from the impressive Mr. Mottaki, the more forthright comment came from the Bahraini banker on the panel, Khalid Abdulla-Janahi, who suggested that everyone in the region is pursuing nuclear power, even if that means that the question of weaponization becomes one of when, not if.

Now, if the idea of nuclear weapons widely distributed among Syria, Egypt, Iran, Israel, and Saudi Arabia is the stuff of nightmares, a Middle East in which the rapidly growing economies of the region lack access to nuclear power might not be much better. According to the International Energy Agency, oil demand in the region is growing at 5-6%/year, adding roughly 1 million barrels per day of consumption since 2004, not far behind the growth of demand in China and India that has garnered so many headlines. Nuclear power could provide a handy alternative to burning all the oil that consumers in China, India, Europe and the US would like to purchase, delaying the arrival of a global peak in oil exports and the economic shockwave that would accompany it. Nuclear power plants can't be built overnight, however, even with hundreds of billions of petrodollars floating around.

Fortunately for those of us who remain suspicious of Iran's intentions, in spite of the NIE and the public rhetoric of undeserved persecution from Iran's officials, the Economist sees a possible way out of the present dilemma. It lies in abandoning demands for the cessation of uranium enrichment as a precondition to negotiations, but with that offer open only for a specified window, rather than indefinitely. Both sides need a face-saving way to sit down with all of the options on the table, and that just might be it. Perhaps the US administration could even foster the creation of a joint, bi-partisan position on this that the leading presidential candidates could endorse, reducing Iran's incentive to wait for a better deal with the next administration. In the meantime, it's an open question when the substantial oil-price risk premium that traders and analysts have attributed to the tensions over Iran's nuclear program will begin to abate, or whether the whole notion of risk premia retains any real meaning, when supply and demand are so precariously balanced.

Virgin Biojet

I've been following the trend-setting ways of Richard Branson's Virgin Group of companies for many years, so I'm not surprised to see them on the cutting edge of alternative fuels for commercial jet aircraft. Running a normal 747 on a blend of 80% jet kerosene and 20% biofuel is a daring move, especially coming just a few weeks after the remarkable Heathrow crash-landing of a British Airways B-777, in which fuel contamination now seems to be the leading focus of the accident investigation. As this article in the San Francisco Chronicle makes clear, it's going to take years of testing before large passenger aircraft are certified to fly on something other than petroleum distillate, but the rewards for finding suitable substitutes have energized both private and military aviation to pursue this goal.

Each generation of new passenger jets seems to be more fuel-efficient than the one before it, with Boeing's new 787 Dreamliner representing the current state of the art, coming in at just a hair under 100 passenger-miles per gallon, compared to an industry average of around 60 mpg. Nevertheless, the cost, emissions and long-term availability of jet fuel derived from crude oil look like major limitations on the future growth of commercial aviation. Fuel accounts for more than a quarter of the US commercial airlines' cost structure and exceeds labor as a component of unit costs per available seat-mile. That's why United has started charging extra for checked bags. This gives airlines a big incentive to find cheaper, more sustainable energy sources for the long-term, an incentive shared by the Pentagon, as it seeks to reduce the cost of its operations and logistics.

None of this changes the fact that aircraft engines and their fuel systems must work in very challenging environments, with widely-varying temperature and humidity. You can make a turbine engine pretty tolerant of fuel quality when it's sitting on the ground generating electricity at a power plant, and I wouldn't be surprised if biofuels became a popular fuel for gas turbines, when natural gas gets back to BTU parity with crude oil. However, put that same engine at 40,000 feet and -40 degrees F., and suddenly fuel quality matters very much indeed. That's why oil refiners are choosy about the crude oils from which they produce jet fuel, and then go to extraordinary lengths to segregate it from any possible source of contamination from the other products in the distribution system.

The pursuit of alternative forms of jet fuel raises two key questions, relevant to both military and commercial use. First, can the fuel be manufactured to meet the necessary specifications for jet fuel with absolute consistency? Most manufacturers of high-speed diesel engines will not certify a fuel containing more than 20% biodiesel, so Virgin's choice of a 20% biofuel blend for this even more sensitive application looks aggressive. The US military's choice of alternative fuels produced using the Fischer-Tropsch synthesis (FT) and starting with very simple molecules (from natural gas or gasification) looks much safer in this regard. In fact, this route should provide even greater control over the specific properties of the resulting jet fuel blend than if it all came from the distillation and conventional processing of crude oil.

The bigger question is whether any of these substitutes can be produced at a lower cost than oil-based avjet. Although unsubsidized oilseed-based biodiesel typically costs more than untaxed petroleum diesel, fuels produced using FT synthesis could be significantly cheaper. At a typical 60% conversion efficiency, synthetic jet fuel from natural gas would cost about $1.60/gallon, based on gas at $8/MMBTU. That's a lot less than the $2.56/gallon average price that airlines are reportedly paying for Jet-A today, and synthetic jet fuel from coal-to-liquids or biomass gasification might cost even less, at least before the cost of the extra carbon emissions from coal is considered.

For a long time, aviation appeared to be the only transportation segment without a viable energy substitute for petroleum products. The high price of oil, new technology--or at least new applications of an old technology--and the rapid development of the biofuels industry looks set to alter that conclusion in this decade. The prospect of creating synthetic kerosene from scratch from a wide variety of materials at a lower net cost than oil should provide all the incentive necessary for airlines and aircraft and engine manufacturers to plow through the lengthy testing and certification process for these fuels, without cutting any corners on safety. I'll be watching the results of Virgin's test flight with great interest.

Protecting the Bears

Never underestimate the problems of forcing a choice between economic interests and "charismatic mega-fauna." And they just don't get more charismatic or mega- than the polar bears potentially at risk from their proximity to drilling for arctic oil resources in the Chukchi Sea off Alaska. The present controversy arises from the prospect of an imminent oil lease sale proceeding before the Department of Fish and Wildlife issues its finding on whether the area's polar bear population is endangered. Opponents have filed a lawsuit and a bill in Congress to block the lease sale by the Minerals Management Service. Once again, access to vital energy supplies and protection of the environment seem to be in direct conflict, and without an altogether different approach, it is hard to imagine an outcome in which energy wins.

There has been much speculation recently about the degree to which receding polar ice could open up vast new energy resources around the arctic, both within US territorial waters and in waters subject to the UN Law of the Sea Treaty. A few commentators have noted the irony that global warming driven by fossil fuel combustion might make it possible to find yet more fossil fuels. However we look at it, though, we have two colliding realities: rapid changes in the arctic environment as a result of global warming--with accompanying consequences for the indigenous fauna and native humans--and growing concerns about the economic and national security implications of the increasing reliance of the US on foreign oil suppliers. The polar bears are caught in the middle of these trends, and they have powerful friends.

On the surface, it seems easy to dismiss the potential of Chukchi Sea oil and gas resources that have been estimated at 15 billion barrels and 79 trillion cubic feet, respectively, but that are presumably ten or more years away from production. If you believe that within a decade or so the US will be energy independent, anyway, as a result of conservation and a much greater reliance on biofuels, then the prospect of an extra million barrels per day of oil production from Alaska might not sound very urgent or important. That potential must be weighed against the risk that drilling activities, including increased shipping and possible oil spills, would increase the stress on a polar bear population already threatened by climate change. That sounds like a steep price to pay for an insurance policy on energy security that we can achieve in other ways.

But of course, we aren't going to be energy independent within a decade, particularly if we block every new conventional energy project. As I noted last week, the production of cellulosic ethanol mandated under the 2007 Energy Bill is still subject to a number of technical, logistical and economic risks, so we can't be sure that even the 21 billion gallon per year target for 2022, equivalent to just under a million barrels per day of oil--less than 5% of current US demand--can be met. And while achieving the new 35 mpg fuel economy standard for 2020 will certainly reduce gasoline consumption and oil imports, this simply won't be enough to close the large gap between domestic supplies and total demand, even though the latter has stalled for the last three years. The only thing we can predict with certainty about our energy situation ten years from now is that we will still be importing more oil than our neighbors Canada and Mexico can provide.

Common sense suggests that we need a real artic resource policy, not just an ad hoc ruling governing one lease sale, even if the area involved is the size of Pennsylvania. That includes understanding the impact of drilling on all the native fauna, not just the bears, and it should provide as clear a picture as possible of their fate under various scenarios of further climate change, significant amounts of which are already "baked in", with or without drilling. The result ought to be a consensus plan for which parts of the enormous arctic hydrocarbon resource base should be produced and which must be foregone, even with high energy prices and the best available exploitation technology. The gravity of such a decision argues against haste, and especially against squeezing it in during the waning days of an unpopular administration. The companies that would be investing in these resources will only do so if they know they can count on stable policies over the life of these enormously expensive projects, particularly during the critical phase from decision to first production.

Record Gasoline Prices Ahead?

Average retail gasoline prices have eased a little, recently. Weaker winter demand, perhaps further depressed be a slowing economy, has been reflected in steadily rising gasoline inventories, which are now above even their seasonal norms. Regular unleaded is back under $3.00/gallon across much of the country, but before we get complacent about that, it's worth recalling that street prices were closer to $2 than $3 at this time last year, when crude oil was in the mid-$50s, rather than the $92/barrel that West Texas Intermediate has averaged for the last two months. Unless the economy derails all of the normal seasonal patterns, or oil prices suddenly head south, we stand a very good chance of breaking last year's all-time record weekly average price of $3.22/gallon, set last May. That could make gas prices even more of a political football than they already are, as the presidential nominating process culminates this summer.

Although its patterns are often obscured by the volatility of crude oil prices, gasoline has historically been a seasonally-influenced commodity. Its price typically dips after Labor Day, as driving slows, then recovers in the spring, as annual refinery maintenance on the big cracking and reforming process units shrink the inventories that have accumulated during winter (see chart below.) By the time the summer driving season gets into full swing after the Fourth of July, gasoline prices have often already peaked for the year, barring some surprise affecting oil prices or refinery operations.

From "This Week in Petroleum," January 30, 2008, Energy Information Agency, US DOE.

The price difference between gasoline and crude oil on the futures exchange--the so-called "crack spread"--is right where it was for the last three Januaries, at around $6-7 per barrel. However, over the last three years that same relationship has averaged $21/bbl. in the second quarter. If 2008 followed a similar pattern, gas prices could pick up another 35 cents per gallon from current levels, and we'd break $3.30/gal. nationally, with many places over $3.50/gal. for unleaded regular. This is all speculative, of course, but it's worth recalling that the long-time record of $1.35/gal. from early 1981 was broken, in inflation-adjusted terms, following Hurricanes Katrina and Rita in 2005, when prices spiked to $3.07/gal. And I wouldn't look to ethanol for any relief, this year, as corn prices continue to rise and refiners bid up supplies in the scramble to meet the higher Renewable Fuel Standard that just went into effect.

With crude oil again at levels comparable to what we experienced at the peak of the first energy crisis, and the US having outstripped its domestic refining capacity to the tune of over a million barrels per day of gasoline, it would be more surprising if we didn't continue setting new price records for gasoline, year after year, until we finally get a handle on our consumption. Persistent $3 gasoline has had a noticeable affect on demand growth. Unfortunately for consumers, we might get an opportunity to find out what $3.50 will do.