The Impact of the Global "Sweet" Crude Bulge

• The recent slide in global oil prices has been compounded by the pressure that rising US shale oil production is putting on the price of sweet crude benchmarks like Brent.
• OPEC's producers may suffer as much as those in the US, while consumers benefit from significantly lower fuel prices than last year.

When the US went to war in Iraq in 2003, the price of oil embarked on a trend that took it from around $30 per barrel to nearly $150 before collapsing in the recession in 2008. This time, as a new US-led coalition takes on ISIS with a bombing campaign in Iraq and Syria, the price of oil is falling, down 20% in the last two months. It's not just that global economic growth has weakened recently, or that soaring shale oil output in the US has averted another oil crisis. Oil's current downturn also reflects the fact that new production from the Bakken, Eagle Ford and other shale deposits is particularly well-suited to undermine oil's global benchmark prices, for Brent and West Texas Intermediate, both of which are made up of light sweet crude oil streams.

The numbers for US shale, or "light tight oil" (LTO) as it's often called, are impressive, especially to those accustomed to watching the gradual ebb and flow of different oil sources over long periods. In the 12 months ending in June 2014, US oil production grew by 1.3 million barrels per day (MBD), not far short of Libya's pre-revolution exports. Since January 2011, the US added 3 MBD, or about what the UK produced at its peak in 1999. In fact, since 2010 incremental US LTO production has exceeded the net decline of the entire North Sea (Denmark, Norway and UK) by around 2 MBD, contributing to a significant expansion of Atlantic Basin light sweet crude supply.

The New York Mercantile Exchange defines light sweet crude as having sulfur content below 0.42% and an API gravity between 37 and 42 degrees. That's less dense than light olive oil. The specification for Brent is similar. Much of the LTO produced from US shale formations fits those specifications, and what doesn't is typically even lighter and lower in sulfur.

The current "contango" in Brent pricing, in which contracts for later delivery sell for more than those for delivery in the next month or two, is another sign of a market that is physically over-supplied: more oil than refineries want to process, with the excess going into storage. However we also see indications that the historical premium assigned to lighter, sweeter crude versus heavier, higher-sulfur crude is under pressure.

One example of this is the gap or "differential" between Louisiana Light Sweet, which wasn't caught up in the delivery problems that plagued West Texas Intermediate for the last several years, and Mars blend, a sour crude mix from platforms in the Gulf of Mexico. From 2007-13 LLS averaged around $4.50 per barrel higher than Mars, while for the first half of this year it was only $2.75 higher and today stands at around $3.40 over Mars.

And while OPEC's reported Reference Basket price has been falling in tandem with Brent, its discount to Brent had also narrowed by about $1 per barrel, prior to the price plunge of the last couple of weeks, compared with the average for 2007-13. Considering that OPEC's basket includes light sweet crudes from Algeria, Libya and Nigeria that sell into some of the same Atlantic Basin markets as Brent, that looks significant.

By itself a narrowing of the sweet/sour "spread" of only a dollar or so per barrel isn't earth-shattering. However, because the surge of US oil production is effectively focused on the oil market segment represented by the price of Brent, it compounds the pressure on OPEC, many of whose members link the price of their output to Brent. This might help explain why the response of OPEC's leading producer, Saudi Arabia, has been to cut prices rather than output, in an apparent effort to maintain market share rather than price level.

The Saudis know better than anyone how that movie could end. The Kingdom's1986 decision to implement "netback pricing", linking the price of its oil to the value of its customers' refined petroleum products, helped precipitate a price collapse so deep that it took oil prices 18 years to reach $30/bbl again, by which time the dollar had lost a third of its value.

Whether aimed at US shale producers or as a reminder to the rest of OPEC, which appears to be unprepared to make the output cuts necessary to defend higher oil prices, the Saudi action increases the chances that oil prices will over-correct to the downside, rather than rebounding quickly. If so, the impact of the sweet crude bulge in the Atlantic Basin--only a little more than 3% of global oil supplies--could play a disproportionate role in prolonging the pain producers will experience until oil markets eventually reach a new equilibrium.

In the meantime, US consumers are benefiting from gasoline prices that are already $0.15 per gallon lower than this week last year. Today's wholesale gasoline futures price for November equates to an average retail price well below $3.00 per gallon, after factoring in fuel taxes and dealer margins, compared to last year's average retail price for November of $3.24. After factoring in lower diesel and heating oil prices, the fall in oil prices could put an extra $10 billion in shoppers' pockets for this year's holiday season.

A substantially different version of this post was previously published on the website of Pacific Energy Development Corporation

US Strategic Gasoline Reserve: Solution or Band-Aid?

• The new Northeast Gasoline Reserve addresses some of the shortcomings of the current, 39-year-old federal emergency crude oil reserve, or SPR.
• Whether or not the DOE considered other options, the upcoming Quadrennial Energy Review provides an ideal opportunity to rethink our strategic energy stockpiles.

The recent announcement that the US Department of Energy (DOE) would establish a strategic gasoline stockpile to serve the Northeast was at least partly a response to calls for such a reserve in the aftermath of the fuel distribution problems caused by “Superstorm” Sandy in 2012. Secretary Moniz also framed it as part of a broader effort to beef up US energy infrastructure.

Although it is encouraging to see the DOE recognize the limitations of the current US Strategic Petroleum Reserve (SPR), I was disappointed that the new stockpile appears merely to copy the Clinton-era Northeast Heating Oil Reserve, in both quantity and approximate location, rather than reflecting a thorough rethinking of the entire concept of strategic fuel inventories, involving all stakeholders.

As I noted in a post here last summer, the crude oil SPR and its Gulf Coast facilities were envisioned and stocked for a different world of falling domestic oil production, rising oil imports–mainly through Gulf Coast ports–and US refineries that supplied only domestic customers. Yet while the SPR’s roughly 700 million barrels in storage should now last much longer in an emergency than they would have done in the previous decade, the reserve’s other shortcomings have grown as the US energy situation has evolved in the last several years.

For starters, it holds too much light sweet crude oil. Once in short supply, the US now has such abundant supplies of this grade, thanks to the shale production in North Dakota and Texas, that US refineries may eventually not be able to refine it all, without expensive upgrades or under-utilization of their costly conversion hardware.

The SPR's oil is also increasingly in the wrong place. While oil imports into the Gulf Coast have been falling rapidly, California now imports more than half its crude oil needs, with half of those imports sourced from the Middle East. The existing Gulf Coast SPR provides virtually no coverage in the event of a disruption in California’s supplies.

Finally, as became apparent in the wake of Sandy and of 2005′s hurricanes Katrina and Rita, a crude oil SPR provides little benefit if the refineries necessary to process its oil have been shut down by storms, electricity outages, or other causes. And more recently, the emergence of the US as a major net exporter of petroleum products raises questions about the extent to which SPR oil might be used to produce fuel for non-US customers.

The announced Northeast Gasoline Reserve represents a step towards addressing these shortcomings, positioning refined products near major markets. That avoids the possibility that refinery capacity might not be available when required, and it circumvents at least part of the distribution infrastructure–pipelines and ports–that might fail in a future Sandy-like emergency.

The title of the DOE’s press release also hints that the Northeast reserve might be just the first, with others to follow. Additional locations should be chosen with regard not just to today’s vulnerabilities, but those under a variety of future scenarios. However, while this decision moves in the right direction in several ways, it does not even address all the vulnerabilities highlighted by Sandy.

Sandy presented governments and consumers in the Northeast with both a shortfall of supply, from local refineries and long-distance product pipelines, and a massive failure of local infrastructure. Many distribution terminals had product in their tanks that they couldn’t deliver due to power outages, flooding or closed roads, while numerous gas stations were shut due to a lack of power to operate pumps and payment systems, product to sell, or both. Without addressing these local distribution issues, it is conceivable that the new gasoline reserve might contribute no more in a future emergency than the Northeast Heating Oil Reserve did after Sandy, supplying mainly first responders. While still useful, that would fall well short of the consumer benefits that the Senators from New York and Massachusetts seemed to be touting.

I also can’t help wondering whether the team at DOE that devised this measure considered alternatives such as those in use in Europe. The EU requires each member country to maintain 90 days’ inventory of oil and refined products and gives countries latitude in how to provide for that. In the UK, and as I recall at least several other EU countries, the responsibility for maintaining strategic stocks falls on the fuels industry. That approach offers significant benefits.

Aside from avoiding the need for governments to maintain idle inventory at taxpayer expense for many years, this option would also disperse fuel stocks across a much larger number of locations. That would reduce the risk that the strategic reserve facility itself might be incapacitated by the same event that triggered a call on its stocks, or might end up on the wrong side of temporary distribution bottlenecks.  It should also reduce the likelihood of an offsetting reduction in commercial fuel inventories, such as appears to have occurred in New England following the establishment of the Heating Oil Reserve in late 2000.

Putting the reserve in commercial hands would also help to ensure that the product maintained in strategic storage always meets current specifications, without the need for a complete turnover of the stockpile that occurred when the Northeast Heating Oil Reserve had to switch from ordinary to ultra low-sulfur diesel a few years ago.

These advantages, when combined with a rigorous auditing and oversight system, should compensate for the distrust that many consumers might feel for the industry as custodian of such a strategic reserve. I hope this option was at least given careful consideration before the administration decided to implement another federally owned fuel reserve.

The US Strategic Petroleum Reserve has been in place for four decades, and the Northeast Heating Oil Reserve for nearly 14 years. Much has changed since these stockpiles were justified and planned, to such an extent that it seems highly improbable that we would wish to implement them in the same way today, particularly in the case of the crude oil SPR. What should a state-of-the-art system of strategic energy storage consist of in 2014 and beyond? That’s the question I would expect the DOE to address with input from a range of stakeholders, including broad representation from the companies that produce and distribute these fuels under normal circumstances.

The press release announcing the gasoline reserve also mentioned the upcoming Quadrennial Energy Review, with its initial focus on infrastructure and participation by many parties outside government. While the composition and charter of that effort don’t appear to align with the needs of a major reform of the SPR system, it should at least be able to assess the fit-for-purpose of the current approach. It even invites public comment.

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

US Oil Demand Returns to Growth

• Early estimates indicate that US oil demand grew by 2% last year, after several years of declining consumption.
• Although superficially consistent with recent GDP data, it's not yet clear whether this reflects a new trend or the results of non-recurring factors. 

After three straight years of declining oil consumption and a substantial net reduction since 2005, preliminary estimates suggest that US demand for petroleum and its products grew by 2% last year. In the estimation of the International Energy Agency (IEA) US demand growth in 2013 even outstripped that of China.  However, it strikes me as an exaggeration--or at least premature--to see signs, as a recent headline in the Financial Times suggested, that "America returns to gas-guzzling oil demand."  Is this a new trend, or just another blip?

The Energy Information Agency (EIA) of the US Department of Energy won't issue final figures on 2013 consumption for a few more weeks. In the interim, the American Petroleum Institute (API) released its estimates for December and the Fourth Quarter, showing a 5.8% year-on-year uptick for the month and a 4.6% increase for the quarter, compared to the final quarter of 2012. API's Chief Economist John Felmy cited "continued progress in domestic manufacturing as well as the broader economy."

The US economy has shown unexpected strength recently but continues to disappoint a sizable majority of Americans, based on recent polling. The economy added just under 200,000 jobs per month last year, while total employment remains  below its pre-recession peak. The government's first estimate at the end of January indicated that US gross domestic product grew by 3.2% in the fourth quarter of 2013, slower than the third quarter's relatively strong 4.1% pace. That puts full-year growth at 1.9%, or less than the 2.8% rate for the 2012 when US oil consumption shrank by 2% from the year before.

In any case, the  linkage between economic growth and oil demand has weakened over time, falling by more than 60% since the mid-1970s and by 20% just since 2000. In fact, following the peak in US oil demand in 2005, estimated oil and natural gas consumption per dollar of real GDP has declined by an average of 1.7% per year, only a little less than the average of post-recession US GDP growth. So annual efficiency gains come close to offsetting the impact of economic growth on US oil demand.

Some of this is the result of specific efficiency improvements, such as the 1.0 mile-per-gallon increase in the fuel economy of vehicles sold in 2013, compared to the previous year. Tracking data from the University of Michigan indicate a 16% improvement in the fuel economy of new cars since the 2008 model year. Of course it takes time for the impact of new higher-mpg vehicles to make a dent in the demand of a fleet of roughly 235 million cars and light trucks. That's even true of plug-in electric vehicles that use no liquid fuel at all. With cumulative US sales of around 160,000, EVs are displacing less than 5,000 barrels per day (bpd) of gasoline at this point, in a 9 million bpd market.

Because the primary use of oil in the US is in transportation, with less than 1% of it going to generate electricity, we should look at indicators of transportation activity for signals about changes in oil demand. The Federal Highway Administration's tally of US vehicle miles traveled (VMT) for 2013 was just 0.6% higher than 2012, through November, and remained more than 2% below its 2007 peak, only slightly more than a decade ago. If there's been a recent shift in driving habits, it's either well-hidden or involves a switch back to putting more miles on less-efficient vehicles--countering the anecdotal trend of the last few years. In the longer term, VMT growth will face headwinds from the changes in driver demographics I described last August.

In seeking explanations for last year's higher demand, we also can't ignore one-time factors like weather. Heating-degree-day data for the northeast during the fourth quarter shows a nearly 10% increase compared to 4Q2012. That indicates more days when the average temperature was farther below 65 F, and presumably more consumption of heating fuel as a result--a trend that seems to be continuing this quarter.

Scrutinizing EIA's detailed data on product supplied reveals that around two-thirds of the roughly 300,000 bpd annual increase in demand in 2013 (through October) was in the categories of liquefied petroleum gases (LPG) and low-sulfur distillate, both used for heating. For that matter, much of the growth in LPG demand is being met from the processing of shale gas, rather than crude oil refining, so its inclusion as part of "oil demand" is somewhat misleading. Nor do growing US net exports of refined products, at  around a million barrels per day last year according to API, have any bearing on this discussion, since they aren't included in the figures on which US consumption is gauged.

Another factor to consider when evaluating changes in oil demand is pricing. US retail gasoline prices averaged $0.11 per gallon less in 2013 than 2012, while retail diesel averaged around $0.05/gal. less. Those don't seem like big enough changes to affect demand, but the fourth quarter comparison is more dramatic, with gasoline and diesel $0.22 and $0.15/gal., respectively, less than a year earlier. That, together with a cooler fall, might help explain the fourth quarter bump in API's figures, which showed gasoline demand up by 3.7% year-on-year, and diesel up 5.3%.

Indications of a resurgence in US oil demand growth depend heavily on a single quarter's results, following a quarter of above-trend GDP growth--partially offset by efficiency gains that are expected to grow--and reinforced by cooler weather.  While I can easily imagine that a return to robust US economic growth, combined with persistently weaker fuel prices, could put US oil consumption on an ascending path again, I'd like to see a few more data points before discerning larger implications for global oil demand and prices.

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

US Natural Gas Prices and the Election

Every fall my natural gas utility asks if I'd like to lock in my gas price for the next 12 months.  In some respects the timing for this looks ideal.  Commodity natural gas prices haven't been lower than this year's average since 1999.  Gas is also historically cheap relative to other fuels.  Heating oil recently averaged above $4 per gallon, while the fixed price my natural gas provider is offering equates to $1.36 per gallon, including distribution charges.  However, overhanging this relatively simple choice are big uncertainties related to the economy and the potential impact of regulations on shale gas production.  To complicate matters further, both of these uncertainties are entangled with the outcome of the US presidential election, and my gas provider wants my answer by next Monday.

When I last looked at this question in detail, in 2010, I concluded that the utility's offer was attractive, after scrutinizing then-current gas futures prices and the historical relationship between the futures market and "city gate" prices for Virginia, where I live.  Using the same methodology, this year's offer of $0.62/therm ($6.20/MMBTU) looks reasonable.  Much has changed in the interim, though, in ways that undermine the rationale for locking in consumer gas prices.  The biggest benefit of a fixed price is avoiding nasty surprises during winter heating season.  More than four-fifths of my household's gas consumption occurs from November through March, a period when gas prices used to be alarmingly volatile.  

That's less of a concern, now, with US gas inventories high and supply ample. The same shale gas revolution that has increased domestic supply and backed out imports has also reduced volatility and promoted big shifts in demand. Since 2009 residential gas demand has been essentially flat, while demand from commercial and industrial users has grown by 6.5% and consumption in power generation is up by more than 10%, despite a lackluster economy.  (Gas for use in transportation grew even faster but still constitutes less than 0.2% of total gas demand.)  As a result of these shifts, peak monthly average natural gas prices since the winter of 2009-10 have occurred in summer, coinciding with air conditioning demand. With less winter price volatility, the decision to lock in prices now is mainly a bet on gas prices for the next 12 months.  The outcome of that bet hinges on future supply and demand.

On the supply side, will the surge of US shale gas production continue?  New regulations are among the biggest potential constraints on output.  The EPA has set new rules on emissions during well completion and production, with the most expensive aspect phasing in by 2015.  EPA will also issue new rules on wastewater disposal from fracking by 2014. There is growing pressure on the administration to impose federal regulation of most aspects of shale development, superseding management by the states.  Thus far, the White House has avoided a sweeping crackdown that would disrupt gas markets, and the EPA administrator is on record opposing comprehensive federal regulation of all wells.  However, it's not obvious whether such reticence stems from a basic belief in the national importance of this resource or the simple expedient of not killing the golden goose before the election.  Governor Romney has proposed streamlining regulations affecting gas production. Next Tuesday's outcome should resolve this uncertainty.

The other big uncertainty surrounding gas prices concerns demand.  High shale gas output isn't the only reason gas is cheap today.  Anemic GDP growth such as the 2% rate for the third quarter reported last Friday has helped keep gas prices low.  A stronger economy with higher full-time employment would put upward pressure on prices by soaking up much of the surplus production that has depressed them.  However, the consequences of failing to mitigate January's "fiscal cliff"--federal budget "sequestration" and the expiration of many tax cuts--would likely drive natural gas back toward the lows we saw this spring.  With the economy still the number one issue for most voters, its likely future impact on gas demand is linked with our perceptions of the candidates' economic programs and promises. 

My best bet is to convince my supplier to let me wait until after the election to reply.  There's nothing like additional information to improve the value of a decision. Failing that, I'm inclined to pass on this opportunity.  The possibility of cheaper natural gas next year acts as a modest hedge against the risk of another recession, while the benefits of a stronger economy would more than outweigh any natural gas price increases I might experience on the upside.

Energy Security and Oil Substitution

For the last several years, US energy policy has been operating on the assumption that energy security and climate change were pretty much two sides of the same coin, in terms of motivating changes in our energy production and consumption. The Gulf Coast oil spill and some of the proposals for addressing the vulnerabilities it has exposed reveal the extent to which the connection between these two issues has been oversimplified. I've devoted several recent postings to explaining why renewable energy technologies like wind and solar power will have a minimal effect on our dependence on oil, and why vehicle electrification and biofuels look promising but are likely to be quite limited in their impact on imports for at least the near future. However, that doesn't mean we have no good options today. In fact, some quite prosaic measures could have a significant impact while we're waiting for the slower-cooking ones to ramp up. Something as simple as substituting natural gas for heating oil could be a very useful step, meriting additional support.

The broader concept of energy security, as opposed to simply oil security, gained traction a few years ago, when it appeared that natural gas was about to join the list of commodities for which the US would have to rely on steadily-increasing imports to satisfy domestic consumption. Shale gas is reversing that trend, and we are not at risk of becoming net importers of coal or electricity to any significant extent. From the US energy import and export figures, it's clear that our import dependence problem pretty much starts and ends with oil and its products, particularly when you consider that most of our relatively modest natural gas imports come from Canada. But while we may control our own destiny for electricity and natural gas, oil remains as complicated as ever, in part because most oil, but very little electricity, is used in transportation. If we want to reduce our reliance on oil and oil imports, we must focus on either efficiency and conservation, or on direct substitution. And for now, substitutes for oil in its main uses are still relatively small in scale, entail serious performance penalties, or both. However, if we look beyond the high-profile uses of oil in automobiles or aircraft, there are a few areas for which good, large-scale substitutes are available now.

Consider heating oil, a close cousin of diesel fuel. Although natural gas has been eroding the market share of heating oil in residential and commercial applications for decades, US homes still burn on average around 320,000 bbl/day of heating oil, mainly in the northeast. Commercial and industrial users consume a somewhat smaller quantity. Together, this represents about 10% of total US distillate consumption of around 4 million bbl/day (at least when the economy is healthy), or around 2% of total US petroleum consumption. Every barrel of heating oil displaced by natural gas or other fuels, such as bio-heating oil, could fuel diesel cars and trucks--after being processed into ultra-low-sulfur diesel--or be exported to offset a portion of our other imports. Replacing all of the residential heating oil used in the US would free up enough fuel for around 12 million diesel cars like the Audi A3 TDI that I wrote about a couple of months ago. And with natural gas having gotten much cheaper relative to oil, thanks to the growth of unconventional gas supplies, the economic advantage of switching can be considerable, as illustrated in the graph below, comparing residential gas and heating oil prices in New York.


How practical is this substitution? Well, having lived in a part of the country in which many older homes used oil heat, the biggest obstacle for most homeowners is the cost of replacing the furnace and connecting the house to gas. And there are still regions for which the latter is either cost-prohibitive or simply out of the question, because the gas pipeline network hasn't reached every community and neighborhood. (In such cases, propane, which is increasingly sourced from natural gas, may be a good option.) In the long run, particularly with the discovery of vast natural gas reserves in the Marcellus Shale underlying much of the northeast, the gas will come, and so will the infrastructure. The question is whether that process could be speeded up with a little help, and whether it makes sense to do so.

An article I ran across recently suggested that the American Recovery and Reinvestment Act of 2009 (the stimulus) included standards and funding for converting oil heating systems to gas. When I reviewed the text, most of that support seemed to be channeled through existing state programs. Nor did I see anything promoting the expansion of the natural gas pipeline and reticulation network (i.e., "last mile"), which remains the crucial step in this process for many small towns and rural communities. A quick search of the current draft of the Kerry-Lieberman climate bill didn't reveal anything along these lines, either, despite the emissions advantage of heating with gas instead of oil. That looks like a glaring omission to me.

The oil spill in the Gulf has provided a wake-up call concerning our continued dependence on oil and the ineffectiveness of energy policies focused mainly on climate change to address it. Renewable electricity isn't an oil substitute, and while converting cars and trucks to run on natural gas or electricity looks like a useful long-term strategy, it won't deliver big oil savings soon. In the meantime, we shouldn't ignore less glamorous measures that can have a quicker impact, such as accelerating the ongoing replacement of heating oil by natural gas and other non-oil fuels.

The Diesel Blues

Except for truckers and the few Americans who own diesel automobiles, most of us pay little attention to the price of diesel fuel at the pump. Anyone who needed to buy heating oil this winter has noticed, however. Because the latter comes from the same part of the barrel as diesel and often differs only in the color of dye added to differentiate it from on-road fuels, heating oil has gotten caught up in the same factors that have driven diesel prices to record heights. This year the combination of normal seasonal patterns, long-term global demand trends, and a 25% spike in oil prices since early December have pushed these "middle distillates" to the brink of $4.00 per gallon.

While the average price of retail gasoline across the US is $0.66/gallon higher than the same week last year, diesel fuel has gone up by $1.13. The dramatic increase in the diesel price bears some of the blame for the recent spike in food-price inflation, compounding the impact of ethanol demand on corn prices. Residential heating oil has followed a similar pattern, currently selling at an average of $1.18/gal. more than a year ago. The question I hear frequently is why a fuel that seems easier to make than gasoline and historically sold at a discount to it should suddenly cost so much more, nearly 60 cents more, right now. The answer requires dispelling a myth and taking one of the biggest global fuel trends into account, bigger even than the rise of biofuels, at least for now.

Start with the notion that diesel is cheaper to make than gasoline. That was once true, when its production was mostly a matter of distilling out the middle fraction of light, sweet crude oils--hence "middle distillates"--and putting them in a tank for distribution. Much has changed since then, including big shifts in average refinery crude slates toward heavier, higher-sulfur crude oils and the promulgation of environmental regulations progressively restricting the sulfur content of diesel sold for on-road use. When I worked at Texaco's Los Angeles Plant (now owned by Tesoro) in the late 1970s, the diesel fuel we produced was permitted to contain up to 0.5% sulfur. After successive reductions, the implementation of the 15 parts per million diesel sulfur specification that went into effect in 2006 has removed 99.7% of the sulfur in diesel fuel, at an exponentially-increasing cost per ton removed, the closer the standard got to zero. As a result of these shifts, big parts of the diesel pool are now refined as intensively as much of the gasoline pool.

Global trends also strongly affect the price we pay for diesel and heating oil. At 20%, compared to gasoline's 45%, diesel's share of total US petroleum consumption is much lower than elsewhere. Globally, diesel outsells gasoline, 27% versus 25%, and its lead looks set to increase. Diesel consumption is closely aligned with economic growth, so the development of Asia has boosted diesel demand much more than gasoline demand, so far. In Europe the higher efficiency of diesel automobiles is a key element of the EU's greenhouse gas reduction strategy, and diesel models outsell their petrol competitors. Because most of Europe's oil refineries were built to yield a similar product slate to ours, this shift has produced a growing surplus of gasoline--a big source of our gasoline imports--and a distillate deficit that the EU's expanding biodiesel production can't begin to close. So when the US imports diesel and heating oil to meet seasonal demand, we are competing directly with Europe and Asia.

The global diesel demand trends and higher production costs described above aren't temporary factors, either, and they ride along on top of the steady rise we've seen in crude oil costs. There's no reason to expect that diesel will revert to being cheaper than regular gasoline, or selling at parity with it as it did in the late 1990s. If anything, the average premium over unleaded regular of about 13 cents per gallon that we've experienced since 2006 is likely to expand further. That's bad news for food prices, and it could make the introduction of new diesel cars here a tougher sell, although on a miles-per-dollar basis, diesel still looks cheaper than gas.