VW Scandal Puts Diesel's Future at Risk

• If the VW scandal sours consumers on diesel cars, the potential winners and losers extend well beyond the auto industry.
• European refineries look especially vulnerable to such a shift, while US refiners, along with manufacturers of electric vehicles, stand to gain.

Whether or not Volkswagen's diesel deception proves to be "worse than Enron," as a Yale business school dean commented, it is more than just the business scandal du jour. Its repercussions could affect other carmakers, especially those headquartered in Europe. And if it triggered a large-scale shift by consumers away from diesel passenger cars, that would have major consequences for the global oil refining industry, oil and gas producers, and sales of electric and other low-emission cars.

The scale of the problem ensures that it will not blow over quickly. Nearly 500,000 VW diesel cars in the US were equipped with software to circumvent federal and state emissions testing, and the company has indicated that 11 million vehicles are affected, worldwide. Even if Volkswagen's retrofit plan passes muster with regulators in the US, Europe and Asia, the resulting recall could take years to complete.

It's also still unclear whether VW's diesel models are unique in polluting significantly more under real-world conditions than in laboratory testing. Regulators in Europe appear to suspect the problem is more widespread. Other companies use similar emission-control technologies--from the same vendors--to control the NOx and particulates from smaller cars equipped with diesel engines. The French government announced plans to subject 100 diesel cars chosen at random from consumers and rental fleets to more realistic testing.

VW faces investigations and lawsuits in multiple countries. While those are underway, the claims of every carmaker selling "clean diesels" and the reputation of a technology that European governments have bet on as a crucial tool for reducing CO2 emissions and oil imports are likely to be under a cloud. How consumers react to all this will determine the future, not only of diesel cars, but of the future global mix of transportation fuels and vehicle types.

Start with oil refining. As long ago as the early 1990s, when I traded petroleum products in London, the European shift to diesel was creating a regional surplus of motor gasoline and a growing deficit of diesel fuel, or "gasoil" as it is often called outside North America. Initially, trade was the solution: The US was importing increasing volumes of gasoline to meet growing demand and had diesel to spare. The fuel imbalances of the US and EU were well-matched, in the short-to-medium term.

As this shift continued, the wholesale prices of diesel and gasoline in the global market adjusted, affecting refinery margins on both sides of the Atlantic. Marginal facilities in Europe shut down, while others invested in the hardware to increase their yield of diesel and reduce gasoline production. US refiners also invested in diesel-making equipment.

The aftermath of the financial crisis and recession increased the pressure on Europe's refiners, as did the rapid growth of "light tight oil" production in the US. Europe's biggest export market for gasoline dried up as fuels demand slowed and US refineries reinvented themselves as major exporters of gasoline.

Diesel cars still make up less than 1% of US new car sales but have accounted for around 50% of European sales for some time. If governments and consumers were now to lose their confidence in diesels and shift back toward gasoline, it would wrong-foot Europe's refineries and leave them with some big, underperforming investments in diesel hardware.  A persistent slowdown in diesel demand would alter corporate plans and strategies as refinery profits shifted. In the meantime, US refineries stand to benefit from a bigger outlet for their steadily rising gasoline output.   

If consumers did retreat from diesel passenger cars--trucks are unlikely to be affected--the shift back to gasoline is likely to be less than gallon-for-gallon, because competing technology hasn't stood still since 2007, when the US Congress enacted stricter fuel economy standards and the Environmental Protection Agency's tougher tailpipe NOx standard went into effect. New gasoline cars are closing the efficiency gap with diesels, thanks to direct injection, hybridization and other strategies. At the same time, the number of new electric vehicle (EV) models is growing rapidly, their cost is coming down, and infrastructure for EV charging is sprouting all over.

EVs still accounted for less than 1% of the US car market last year, but the combined sales of the Chevrolet Volt, Nissan Leaf, Tesla Model S and over a dozen other plug-in hybrid and battery-electric models nearly matched those of the standard Prius hybrid "liftback". EVs are still not cheap, despite generous government incentives that mainly benefit high-income taxpayers. Most still come with a dose of "range anxiety", but they are greatly improved and getting better with each new model year.

Even in Europe, where EVs haven't sold very well outside Norway, a big shift away from diesel would surely help EVs gain market share. If European consumers bought 9 gasoline cars and one EV for every 10 new diesels they avoided, European refiners would soon see not just a shift, but a net drop in total fuel sales. Nor would refineries be the only part of the petroleum value chain to be affected. Global oil demand would grow more slowly as well, bringing "peak demand" that much closer.

For now, this scenario is hypothetical. VW may yet solve its technical problem, bringing the 11 million affected vehicles into compliance with minimal impact on performing and fuel economy. Meanwhile, regulators could find that most other carmakers have been in compliance all along, particularly those selling cars that use the urea-based Selective Catalytic Reduction NOx technology; the rest might only need a few tweaks.

​In that case, the scandal might eventually die down without putting small diesel cars into the grave, as a mock obituary in the Financial Times suggested. Carmakers would have a hard time increasing diesel's penetration of markets like the US, but loyal diesel customers around the world might conclude that these cars still provide them the best combination of value, convenience and drivability. Having driven a number of diesels as rentals and at auto shows, I wouldn't dismiss that possibility too lightly. The jury is likely to be out for a while.

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

How Much Will Low Oil Prices Stimulate Demand?

• Since weak oil demand growth is a major ingredient in the current oil price crash, higher demand stimulated by low prices could be a moderating factor.
• While US demand has risen since prices fell, there are several reasons why the global response may be slower to appear and less dramatic.

One of the main factors that will determine the depth and duration of the current slump in oil prices is the extent and timing of a resulting rebound in demand. It is likely to occur first in countries like the US, where fuel taxes are low and consumers see the results of lower oil prices at the  gas pump relatively quickly--a $1.65 per gallon drop already, since June. However, other factors besides taxes could impede faster demand growth elsewhere. 

From 2007 to 2009 the combination of high oil prices and a weak economy reduced US petroleum demand by almost 2 million barrels (bbl) per day, compared to its 2006 peak. The first volumes backed out of the market were imported refined products, which had grown rapidly from the mid-1990s until 2005. Low domestic demand and expanding US oil production then led US oil refiners to seek new markets, particularly in Latin America. US petroleum product exports have increased by around 1.7 million bbl/day since the recession began.

These refiners might reasonably expect their domestic and foreign markets to grow faster with oil prices dramatically lower. So far, it's hard to see more than hints of this in the lagged data from the US government or API, which reported December gasoline demand at a 7-year high. It's also hard to discern how much can be attributed to oil prices, rather than to US economic growth and a falling unemployment rate. The October update of vehicle miles traveled from the US Department of Transportation was still well below its 2008 peak but showed a modest upward trend, although that seems to have begun before oil prices fell.

Other indicators are also mixed. By the end of last year sales-weighted fuel economy of new vehicles sold in the US had declined by 0.7 miles per gallon from its August 2014 peak. That reflected US consumers buying larger vehicles, including more SUVs, fewer hybrids and only slightly more plug-in electric cars than in the prior year. Despite this retreat, full-year-average fuel economy tracked by the University of Michigan still showed a more than 5 mpg gain since 2007, equating to 20% better fuel efficiency. So the roughly 45 million cars and light trucks sold in the US in the last three years--nearly a fifth of today's light-duty fleet--will use less gasoline than the ones they replaced, even in the most robust response to low gas prices imaginable.

Globally, growth prospects seem equally mixed. Since last July the International Energy Agency has reduced its forecast of 2015 petroleum demand growth by a cumulative 500,000 bbl/day, to +0.9 million bbl/day, as the global economy weakened.  These conditions could combine with currency-related effects to dampen, or at least delay, a potential surge in global oil demand due to low prices. 

Because oil is traded in US dollars, the dollar's recent strength shrinks the oil savings experienced by other importing countries. While all of these countries are paying less for oil than they did last summer, exchange rates have eroded 10-30% of that benefit. The chart above displays this effect for the Euro and Japanese Yen. Closer to home, currencies like the Mexican and Colombian Pesos have depreciated by 12% and 29% since June, respectively.  That could prove significant, since Mexico's refined product imports from the US averaged over 500,000 bbl/day in 2014 (through October), along with over a million bbl/day to the rest of Latin America.

Since petroleum products are sold in local currency, after tax at the pump, consumers in many countries have seen a smaller drop to which they might respond, compared to US consumers. The average German gasoline price has fallen by just 19% since June and the average UK price by 20%, compared to 42% in the US. Meanwhile state-controlled gasoline prices in Brazil and Mexico have  gone up. That's unlikely to induce more driving.

So far the weekly figures  for US refinery throughput are up compared to last year, implying higher expected product sales. However, US inventories of gasoline and diesel fuel have also been growing for the last several months. If rising demand doesn't erode inventory gains soon, refiners may need to reduce processing rates, and that would feed back to oil prices. The next few months of energy statistics should tell a very interesting story.

 

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

Will Falling Prices Shift Oil Industry's Focus to Cost Reduction?

• Lower oil prices may have less impact on US oil production from shale than competitors in Saudi Arabia and elsewhere appear to assume.
• The cost of  producing tight oil is not static, and US producers have various options for cost reduction, including optimizing their logistics. The newly elected Congress can help.

Oil prices have dropped by more than 20% since July, based on futures contracts for UK Brent crude. Some expect prices to rebound relatively quickly, apparently including at least one large oil services company. However, indications that the official policy of Saudi Arabia may have shifted away from its customary role of "swing producer" raise the possibility of an extended period of lower prices. This is new territory for the relatively young US shale industry.

From the end of 2010 to the first half of this year, as the rapid development of light tight oil (LTO) from shale deposits was adding more than 2.9 million barrels per day (bpd) to US output, the benchmark price of West Texas Intermediate crude oil (WTI) averaged $96/bbl. The global oil price, represented by UK Brent, averaged $110/bbl for the same period. Having now fallen to the $80s, if prices were to stay here or lower for long, we should expect to learn a great deal about the actual cost structure of new and existing LTO production in the Bakken, Eagle Ford, Permian Basin and other shale plays.

Based on my experience of several oil-price declines from the inside during my time at Texaco, Inc., I'm skeptical that many LTO producers would be inclined to trim output from currently producing wells, other than as a last resort. From late 1997 to the end of '98, WTI prices fell by almost half, from around $20/bbl to under $11--equivalent to roughly $15 today.  Prices for heavier grades of oil fell to single digits. After months of that, revenues from some oil fields no longer covered variable costs, and upstream management took the decision to shut in high-cost production. Once prices revived, they discovered that some of that capacity had been lost essentially permanently.

I suspect there would be even greater uncertainty and hesitation today about shutting in producing shale wells for any significant period, especially in light of the limited experience with such wells. The bigger question is whether the drilling of new wells would slow or stop, resulting in a gradual slide in output as existing wells decline.

Then and presumably now, however, the first option in a situation like this is generally to cut costs, rather than output. I saw this in the mid-1980s, when oil prices fell by nearly 60% and took more than a decade to recover fully, then again in the late '90s, and during periodic, smaller market corrections. Suppliers were squeezed, big projects deferred, and employees saw travel, raises and benefits curtailed. Similar actions now could make a difference in keeping new shale drilling going.

Even for relatively efficient operators, it can be surprising how much expense can be reduced without affecting near-term productivity, and many of those savings would persist if prices recovered. LTO producers might ultimately become more profitable after weathering a period of weak prices.

A heightened focus on costs would also likely extend beyond producing company budgets and supplier agreements. One of the biggest non-production costs for LTO is transportation, whether paid directly by the producer or deducted by the purchaser from the market price.  Because of its rapid growth and the constraints of existing infrastructure, a high proportion of LTO output must currently be shipped by rail--up to one million bpd in the second quarter of 2014.

Rail offers flexibility and can reach many destinations, but it is expensive.  For example, if it costs over $10/bbl to ship Bakken crude to the Gulf Coast by rail, that means that with WTI at $78/bbl the producer might realize less than $70/bbl at the wellhead.  Pipelines are often cheaper to use, though not in all cases. The current tariff on the existing Keystone Pipeline for taking oil from the Canadian border to Cushing, OK, the storage hub for WTI, works out to around $4/bbl. If oil prices stayed low for a while, that might increase interest in the proposed Bakken Marketlink Project. It would connect the Bakken shale operations to the Keystone XL pipeline, the prospects for which look decidedly better after the outcome of Tuesday's mid-term election.

Another aspect of transportation costs that could come under a different kind of pressure relates to federal restrictions on shipping oil and petroleum products by vessel between US ports. Under the "Jones Act", only US-flagged, -owned and -crewed ships can perform such deliveries, even though the rates for such shipments are normally significantly higher than on foreign-flag tankers in comparable service. This is a significant factor in current petroleum trade patterns, in which refined products from Gulf Coast refineries are often shipped halfway around the world, while blenders and marketers on the east and west coasts must import gasoline and other products from outside North America.

And as long as US crude oil exports are prohibited, with a few exceptions, the combination of the Jones Act and the export ban effectively keep LTO bottled up on the Gulf Coast--depressing its price--or force it onto rail. Amending the Jones Act to exempt LTO, or the issuance of a waiver to that effect from the Executive Branch, could increase producers' margins while expanding the supply options for US refineries on the other coasts. I wouldn't be surprised to see this taken up by the new Congress early next year.

 Based on the current behavior of oil markets, the global impact of the US shale oil boom has been greater than many expected and seems very much in the national interest of the US--and of US consumers--to keep it going. It remains to be seen whether measures such as new pipeline infrastructure and reform of shipping regulations, together with more traditional forms of expense reduction, could boost producers' returns on LTO sufficiently to sustain drilling at roughly current rates while oil prices are weak. 

Even if both drilling and tight oil production slowed for a while, this price correction won't spell the end of the shale boom. As the Heard on the Street column in the Wall Street Journal put it recently, "Once someone has cracked it, it can't be unlearned. Barring a prolonged period of very low prices, the US oil industry isn't about to disintegrate." Rather than an existential crisis, the current weakness in oil markets looks like a test of adaptability for this new but important energy sector.

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

Exporting US Oil to Mexico

• Mexico could become a major export destination for surplus US light crude oil, despite being one of the largest oil suppliers to the US, mainly of heavy oil.
• If structured as an exchange for other barrels, such exports might not require re-writing US oil export regulations, unlike sales to non-neighboring countries.

Two of the biggest energy stories of the last twelve months have been the reform of Mexico's oil sector after 75 years of state monopoly and the US oil industry's drive to gain approval to export a growing surplus of domestic light crude oil. The prospect of exporting US oil to Mexico connects these developments in a surprising way. It should make sense geographically and economically, though regulatory hurdles remain. Yet it could also increase tension between US oil producers and refiners over the merits of exporting crude versus refined products.

At first glance, the idea seems counterintuitive. Our southern neighbor was the third-largest exporter of oil to the US last year, consistently ranking above Venezuela. However, most of Mexico's oil is heavy and sour, in contrast to the light, low-sulfur "tight oil" (LTO) produced from US shale formations like the Eagle Ford of Texas.

Mexico has experienced supply and demand trends similar to what the US saw prior to our shale revolution. Total oil and gas liquids production has fallen by 25% since 2004, largely due to the declining output of Maya crude from the supergiant Cantarell field, while demand for refined products grew by around 20% in the same period. Lightening the crude oil slate of Pemex's oil refineries with LTO imported from the US could augment efforts to increase throughput and yields of transportation fuels.

The Commerce Department's recent approval for two US companies to export lightly-processed condensate, which despite its similarities is technically not crude oil, was followed by a hold on similar applications. These events have fueled both enthusiasm and confusion concerning US oil exports, which are still politically controversial, after decades of declining US production and periodic price spikes.

An easier sell might involve the exchange or "swap" of surplus LTO for imported heavy oil, and Mexico makes an ideal partner for this kind of transaction. Existing law at least recognizes the potential for such swaps with "adjacent countries", though it remains to be seen whether such a deal could be made to fit language specifying that the oil received be of "equal or better quality".

As a former oil trader, it strikes me that the best ways to close that gap might be to structure an LTO vs. Maya swap as a barrel-for-barrel exchange in which the US party would collect a financial premium in recognition of the quality difference--money being another measure of quality--or a "ratio exchange" in which every barrel of LTO delivered would be matched by a larger quantity of Maya, at a proportion determined by the refining values of the two oils. Either option would still require some regulatory finesse, but of a much different type than approving the outright, net export of US oil production.

The biggest stumbling block to an exchange of LTO for Mexican crude would probably be one of the same ones impeding the general lifting of a US oil export ban that the Washington Post has called "an economically incoherent policy." While US oil producers argue that allowing exports would enable their product to be sold for its global value and incentivize even higher future production, US oil refiners see exports as a threat to their margins and to the growth of their own exports of refined products. These have been crucial in sustaining arguably the world's best refining industry in the face of a weak economy and declining demand at home. 

Mexico is at the heart of this trend. Its imports of LPG, gasoline, diesel and other fuels from the US have increased to over 500,000 barrels per day (bpd) in recent years. Mexico accounted for 44% of all US gasoline and gasoline blending components exported last year, along with 10% of diesel fuel exports and 15% of LPG. I don't think it's controversial to suggest that exporting light crude oil to Mexico would come at least partly at the expense of our refined product exports to the country.

This boils down to the familiar economic dilemma of exporting raw materials versus capturing the value added from selling manufactured goods. I'm sympathetic to the refining industry's concerns, and not just as a former refinery engineer. However, those concerns would carry more weight if US refineries had the capacity to process all of the LTO the US is likely to produce in the years ahead, and to pay a world-market price for it. Refiners might benefit from access to lower-priced crude, but if driving down the value of LTO in a confined market choked production, net US oil imports would be higher than otherwise and the economy would be worse off.

Stepping back from the details of that debate, exporting US light crude oil in exchange for Mexican heavy crude looks attractive within a broader and increasingly credible vision of North American energy self-sufficiency. That wouldn't mean cutting North America off from the global oil market, but it would put us and our neighbors in the enviable position of being able to select imports based on opportunity rather than necessity. A reformed and revitalized Mexican oil industry, importing and exporting oil with its neighbors as it makes sense, could be a cornerstone of that vision.

A different version of this posting 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.

Energy Projects Seem Less Urgent in A Post-Energy-Crisis World

• Rather than being another component of an ongoing energy crisis, opposition to various energy projects points to the alleviation of a decades-long string of US energy crises.
• The audience for concerns about pipelines and fracking would be much smaller if oil were still at $145 per barrel and natural gas over $10 per million BTUs.

To someone living in 1974, during the first energy crisis of the last 40 years, the idea of mass protests to block a pipeline for importing crude oil from Canada would have seemed incomprehensible.  Our environmental awareness has expanded in the interim, along with new channels for exchanging information, including "enduring misconceptions".  Yet the current opposition to so many different energy projects--natural gas drilling, long-distance transmission lines and even wind farms--can also be viewed as an unintended consequence of recent energy successes on a broad front.

The alleviation of what seemed to many a permanent energy crisis might not be obvious, because it has crept up on us. But consider a few of the big-picture elements that have changed:

In crisis mode, US energy security was focused on steadily rising oil and later natural gas imports, while "energy independence" was a goal embraced by politicians but rarely energy experts. Cars offering better fuel economy were available but entailed trade-offs in size and performance. Today, oil imports are falling, the US is a net exporter of refined petroleum products, and public concern about Peak Oil is waning, as measured by internet search activity. Ethanol from corn supplies 10% of US gasoline demand, while other forms of renewable energy are growing rapidly, from a small base. The big question for the federal government this summer is how many natural gas export facilities to allow. Meanwhile, the threshold for fuel-efficient cars has shifted from 30 mpg to 40 mpg, offered in numerous attractive models.

Another way to gauge the success of technologies like hydraulic fracturing, or "fracking", in shifting our energy landscape is to remind ourselves how bad we thought today's situation would be, just a few years ago.  In 2005 the official US annual energy forecast projected oil imports to increase from 11 million barrels per day (MBD) in 2003 to nearly 15 MBD by this year, due to rising demand and domestic production that was expected to remain flat, at best (see below chart.)

The Energy Information Agency (EIA) also expected US natural gas imports to increase steadily, reaching 3.5 trillion cubic feet  (TCF) of LNG imports this year, on their way to 6 TCF per year by 2022. As a consequence, in 2005 the EIA forecast that coal would still generate 48% of US electricity by 2013.
 

Now imagine energy prices in that alternative 2013. With US natural gas suppliers importing an average of 90 LNG tankers per month, would the wellhead price of gas still be under $4 per million BTUs, or closer to the $16 price paid in some international markets? And with US refiners importing up to twice as much crude oil as they are actually on track to do this year, in the context of sanctions on Iran and turmoil in North Africa, how likely does it seem that oil would be at $105-110/bbl, instead of much higher? $100 oil is a drag on the economy, but US consumers have adjusted to gasoline priced around $3.50-3.75/gal., on average. Every $1 per gallon above that would take another $130 billion per year away from other purchases, with adverse effects on the US economy.

More to the point, in such an environment how much tolerance would there be for opposition to oil pipelines or gas drilling that had the potential to lower energy prices, or at least reduce imports and enhance energy security? If oil were above its 2008 high of $145/bbl, and gasoline flirting with $5 per gallon, it would surely be much harder for elected officials to delay approving projects like the Keystone XL pipeline, or to sustain gas drilling moratoria. Ironically then, the successful large-scale application of shale drilling techniques, which has resulted in a 29% increase in US natural gas production and 33% rise in oil production since 2004, helped make it possible for opponents of Keystone or fracking to be heard, rather than dismissed out of hand.

I was recently struck by a reported remark by a pipeline executive. "Shale is everywhere," he said, but it won't be produced everywhere because "people make choices." I agree with that insight, while recognizing that such choices are available mainly because altered economic conditions and the same technologies to which some now object have enabled us to shed an energy crisis mindset.  This situation might have future parallels for other technologies that have escaped much pushback, so far. 

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

It's Time To Reform US Ethanol Policy

• Virtually all of the assumptions underlying the Renewable Fuels Standard enacted in 2007 have changed, as the US emerges from energy scarcity into abundance.
• The linkage between the RFS and food prices is controversial, but a new quantitative model underscores concerns, especially for its impact on developing countries.

This April, two separate bills were introduced in the US House of Representatives to reform, or repeal, the federal Renewable Fuel Standard (RFS) that mandates how much ethanol and other biofuels must be blended into gasoline. A similar bill has just been introduced in the Senate. To understand why reform or repeal makes sense now, we should recall the factors that led Congress to enact this standard six years ago and consider how many of the basic assumptions underlying its design have changed since then.

That requires a review of US fuel consumption and import trends, commodity prices, and the impact of the RFS on food prices. After summarizing the other points I want to focus on the last one, based on an interview I conducted with Dr. Yaneer Bar-Yam, an expert on complex systems who has developed a model that explains the behavior of food prices since the introduction of the first, less ambitious RFS in 2005.
In the fall of 2007, when Congress was debating the Energy Independence and Security Act that included the current, enhanced RFS, the US energy situation looked dire. For four years oil prices had been rising more or less steadily from their historical level in the low-to-mid $20s per barrel (bbl) to around $90, on their way to an all-time nominal high of $145/bbl the following summer. US crude oil production was in its 22nd consecutive year of decline, while our crude oil imports had climbed to 10 million bbl/day, twice domestic production that year.

Even more relevant to the thinking behind the RFS, US gasoline consumption stood at a record 142 billion gallons per year and had been growing at an average of 1.6% per year for the previous 10 years–another 2 billion gallons added to demand each year. In its annual long-term forecast for 2007, the Energy Information Administration (EIA) of the US Department of Energy had projected that gasoline demand would grow to 152 billion gal/yr in 2013 and 168 billion gal/yr by 2020. Meanwhile, US net imports of finished gasoline and blending components had reached a million barrels per day in 2006, equivalent to 15 billion gal/yr–equal to the corn ethanol target set by the 2007 RFS for gasoline blending in 2015. And by the way, US corn prices for the 2006-7 market year averaged $3.04 per bushel (bu). In this environment, policy makers regarded ethanol as a crucial supplement to dwindling hydrocarbon supplies, from a feedstock that was cheap and readily expandable.

Without belaboring the events of the last five years, virtually every one of those trends has reversed course. That has occurred partly as a result of the recession and the lasting changes it produced in the US economy, and partly due to an energy revolution that was largely invisible in 2007 but had already begun.

US gasoline consumption peaked in 2007 and has since declined to 133 billion gal/yr last year. The EIA forecasts it to fall to 128 billion by 2020 and 113 billion by 2030. US crude oil output is the highest in 22 years and is set to exceed imports this year, while the US has become a net exporter of gasoline and other petroleum products. Since 2007 US ethanol production has grown from 6.5 billion gal/yr to 13.3 billion gal., and it seems more than coincidental that corn prices had doubled to an average of $6.22/bu by last year.

That brings us to the controversy that has been widely referred to as “food vs. fuel”. In the last several years I’ve read numerous papers attempting to determine by correlation or other empirical methods whether and to what extent the increase in US ethanol production from corn has affected food prices. To put this in context, since 2005 the quantity of corn used for US ethanol production has grown from 1.6 billion bu/yr to 5 billion bu/yr, or from 14% to 40% of the annual US corn crop.

Some studies, such as this 2009 analysis from the non-partisan Congressional Budget Office found a significant influence on food prices. Others, including an Iowa State study recently cited in a blog post from the Renewable Fuels Association, found a negligible influence. What differentiates the work of Dr. Bar-Yam is that he and his colleagues have developed a quantitative model based on two key factors — corn consumed for ethanol and commodity speculation — that closely fits the behavior of a global price index. Their model also accounts for the “distillers dried grain” byproduct from ethanol plants, which returns about 20% of the corn used in the form of protein-upgraded animal feed.

Before speaking with Dr. Bar-Yam, I was a bit skeptical of his results. Aside from skepticism being my default mode in such situations, I had spent a lot of time looking at claims of speculator influence on crude oil prices in the 2006-8 period and was never convinced that they were more than the “foam on the beer”, rather than a basic driver of prices. However, as I was reviewing his paper prior to our call, a light went on.

The curve his model predicted, which closely matched food price behavior, looked very much like the behavior of a process control loop responding to a ramped change in the set point–forget the jargon and think about how the temperature of your home responds to a steady increase in your thermostat setting: overshooting, then undershooting, before converging. We discussed this and he confirmed that it was effectively an "under-damped oscillator", which can be characterized the same way whether you're talking about an electrical circuit or a market. In effect, the steadily increasing corn demand from the ratcheting up of the RFS started corn prices rising, and the presence of lots of speculators, including “index fund” investors, caused the price to successively overshoot and undershoot the equilibrium price track one would expect.

Dr. Bar-Yam explained that he had arrived at these two factors by eliminating factors that other groups had investigated, but that turned out to have no predictive value. These included shifting exchange rates, drought in Australia, a dietary shift in Asia from grains to meat, and linkages between oil and food prices. In his view the focus on ethanol and speculation is validated by the shift in dialog on this issue away from other, extraneous causes.

He also emphasized that his main concern is not the price of processed foods in developed countries such as the US, for which commodity grain costs are only one input, but rather the price paid for simple foods by poor people in the developing world. From that standpoint he doesn’t just want to see the RFS reformed. ”It is important not just to repeal, but to roll back the amount of ethanol used in the US.” He would prefer not 10% ethanol in gasoline, let alone 15%, but about 5%. “The narrative has to shift,” he said, “to recognize that people are going hungry.” Those are powerful words, and I’m still thinking about them.

At current production levels ethanol from corn contributes the energy equivalent of 6% of US gasoline consumption and about 2.5% of total US liquid fuel demand. That’s not trivial, and there’s a whole domestic industry of investors, employees and suppliers who made that happen at our collective request. However, If Dr. Bar-Yam has accurately captured the relationship between ethanol and global food prices, then we urgently need to reassess what we’re doing with this fuel.

We are also in a far better position now to consider scaling back our use of ethanol produced from grain than we were when the RFS was established. With increasing production of shale gas, tight oil and various renewables, the energy scarcity that has defined our policies for the last four decades is far less relevant to our policy choices going forward. I’ll tackle the practical aspects of RFS reform, in terms of the so-called “blend wall” and its impact on gasoline prices, in a future post.

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

Food vs. Fuel and the Midwest Drought

It was bound to happen.  As long as US corn output continued to climb year after year, the federal mandate to blend steadily increasing quantities of ethanol into gasoline could be accommodated without creating a shortage of this staple grain.  Unfortunately, crops are subject to all sorts of uncertainties, including the severe drought conditions that the middle of the country is experiencing this year.  Estimates for this year's corn crop have been revised downward, and corn prices have already broken through $8 per bushel, up from less than $6 a month ago, with consequences for the livestock, processed food and ethanol industries, as well as for export markets.  As soaring feed grain prices begin to translate into higher grocery prices for meat, poultry, dairy and other goods, will consumers demand relief from the EPA, which has the authority to curtail ethanol volumes?  The current betting appears to be that the administration will stand fast on the mandate, but anything can happen in an election year. 

Ethanol now accounts for at least 10% of US gasoline blending, by volume.  To meet that demand, ethanol producers will require around 5 billion bushels of corn.  In recent years, the ethanol industry's expanding corn demand was met by a combination of increasing yields and planting more acres in corn.  However, corn yields per acre are dropping sharply this year, potentially pushing output below last year's 12.4 billion bushels, if conditions don't improve soon.  That's in contrast to earlier expectations that this year's corn crop would exceed last year's by 20% .  This isn't the first time that the food vs. fuel trade-off inherent in crop-based biofuels has become an issue, but it might be the first time when both the demand for corn for ethanol is so high and the need for that ethanol in the gasoline blending pool is arguably so low.  In this context, food vs. fuel quickly boils down to a debate over the tangible benefits of corn-based ethanol as a fuel.  There's growing evidence that those benefits have been oversold, despite industry claims.

Start with the widely touted study from Iowa State University indicating that ethanol saved consumers $1.09 per gallon at the gas pump in 2011 and $0.89/gal. in 2010.  I read both the original study and its updated version when they came out.  It seemed obvious to me that the authors' grasp of gasoline markets and oil refining were inadequate, but I lacked the time necessary to dig through their math to uncover the source of their exaggerated results.  Fortunately, a pair of researchers from MIT and my alma mater, U.C. Davis, have now done that work and concluded that the Iowa State paper's findings--and the claims based on them--depended on a "spurious correlation": the relationships they saw were coincidental.

In contrast to the Iowa State studies, the MIT/Davis paper is very readable, and I recommend it to you.  In addition to debunking the statistics, the authors point out the key flaws in their counterparts' logic.  Foremost among these is that in order to have a large influence on gasoline prices, ethanol would have to have had a large impact on crude oil prices, which are the largest determinant of gas prices, by far.  From 2005-11 US ethanol production expanded by 10 billion gallons per year, the energy equivalent of 350,000 barrels per day of oil, or 0.4% of 2011 global oil supply. I've argued many times that the oil market responds disproportionately to modest changes in supply and demand, but the idea that a few hundred thousand barrels per day could translate into the equivalent of $45/bbl exceeds the wildest dreams of any trader I ever met.  The MIT paper concludes with the authors summarizing the likely impact of ethanol on gasoline prices as "near zero and statistically insignificant."

However, if ethanol hasn't done much to hold down gas prices, could a drop in US ethanol production resulting from paring back the ethanol mandate to reduce the pressure on corn prices cause a big spike in gasoline prices?  That's where the analysis in a paper presented to members of Congress yesterday comes in.  Dr. Elam's report suggests that rather than displacing imported crude oil, the main effect of increasing US ethanol use in fuels has been to divert domestic gasoline production into exports, while US crude imports have fallen based on a combination of lower demand (from the recession) and improved product yields per barrel of crude oil refined.  Even if you are inclined to be skeptical of these findings because the study was supported by poultry interests, data from the US Energy Information Agency and elsewhere show that US refineries are not fully utilizing their capacity, are exporting significant volumes of gasoline, and have a wider array of domestic and imported crude oils at their disposal than they did just a few years ago. In short, we're in a far better position to forgo a few billion gallons of ethanol this year than we would have been in 2008, the last time food vs. fuel concerns spiked along with gas prices. 

Corn growers have experienced droughts before, and in the past the price of corn sorted out who needed it most.  However, the market can't prioritize fairly among the competing calls on a drought-diminished corn crop when the single largest segment of demand is locked in place by a federal mandate. This represents a massive distortion that only the government can rectify. I'm sympathetic to the ethanol industry's dilemma.  After all, the federal government virtually begged them to overbuild capacity, but it couldn't guarantee they would earn a profit, even when it was providing a $0.45/gal. subsidy for their customers, who are required by law to use their main product.  However, the economic and environmental benefits of ethanol are too modest to shield this industry while forcing all other corn users to absorb the likely shortfall in corn supply.  The most sensible remedy would be to unshackle ethanol demand, at least temporarily, and waive at least a portion of the ethanol mandate for 2012-13.

Net Exports and Gasoline Prices

US petroleum product exports have been in the news, along with the welcome discovery that we are apparently on track to become a net exporter of these fuels this year, for the first time since the 1940s. This is a far cry from energy independence, as various oil skeptics have been quick to point out, but it's still a noteworthy inflection point in energy trends. However, I've also seen stories suggesting that US consumers will pay a lot more at the pump as a result of this change, to which the most succinct response so far is "rubbish." Being a net exporter hasn't suddenly connected US fuel prices to the world market, as if they had somehow been insulated from it until now. In fact, we've been exporting products for many years--as I know from personal experience--but for most of that time we just happened to be importing more. The net effect of our new status on prices here will be minimal, while the main impact will be a positive nudge to our trade deficit.

I am sympathetic to the present urge to see a cloud in every silver lining; we seem to be going through one of those phases in our history. At the same time we should understand that to the extent net petroleum product exports aren't entirely good news, it's because the main driver of this departure from a long trend of steadily increasing net imports was the sudden slowdown of consumer activity that accompanied the recession and financial crisis, from which we are still recovering. And while I agree that more efficient cars have contributed, recent fuel economy improvements have been too incremental to our fleet of 240 million light-duty vehicles (passenger cars, SUVs and light trucks) to have made such a big dent in demand, quite so soon. Mainly, we're driving less, as the statistics on vehicle miles traveled indicate. That might be better news if it reflected a massive lifestyle change, instead of the grim reality of millions of un- and under-employed Americans for whom driving has become a luxury.

Even in that negative context, the fact that we are now exporting more gasoline and other petroleum products than we import is a plus, since without buoyant non-US demand, US refiners might have been forced to reduce operations by more than they have, or to idle more facilities and lay off staff. Today's net exports imply a positive margin between crude oil imports and product exports sufficient to cover refiners' costs, even after netting out freight. That results in more economic activity and value added here, driven by overseas demand, following the same export-led strategy that other industries are pursuing in order to compensate for lower US demand for their output.

More exports and fewer imports mean a smaller trade deficit, but the question on some people's minds is apparently whether this is being accomplished at the expense of US consumers. That might have been the case if, for example, exports had been banned until recently and refiners forced to create an artificial glut of petroleum products to drive down prices. (That's effectively the case in some other countries.) Instead, the US has long been part of a global market for both crude oil and refined products, and refiners and traders have always been alert for gaps between regional markets that could be profitably exploited. When I traded refined products for Texaco's west coast refineries in the 1980s, we occasionally took advantage of export opportunities, even though we were more often importers. When I traded products in London, my team routinely sold cargoes of gasoline, diesel or jet fuel from the US into Europe and Asia, and we did the reverse when the "arbitrage" worked in the other direction. We accounted for just a small portion of the trade in cargoes passing back and forth between continents, which continues today.

As a result of this global market in refined petroleum products, US consumers of gasoline and other fuels have always been competing with consumers in other countries, whether we realized it or not, especially in parts of the country where refiners have easy access to export markets. That's been true since the days when my former employer's advertising touted its success in "lighting the (kerosene) lamps of China". In terms of the impact on domestic prices, it doesn't matter much whether we're net exporters or net importers, as long as we're connected to the global market--a linkage that has saved our bacon on many occasions when US refineries were hit by hurricanes, blackouts, or other disasters.

A more tangible way to test the consequences of product exports involves comparing past and present crude oil and gasoline prices. Making that comparison accurately is complicated by the breakdown of the main US oil market indicator, the price of West Texas Intermediate crude, which for more than a year has been burdened by excessive inventory at Cushing, OK and other factors. For now the price of Louisiana Light Sweet (LLS) is a better gauge of the oil market. LLS has been relatively unaffected by WTI's problems and trended much closer to global oil prices, such as UK Brent crude. It turns out that 104% of the higher retail price of gasoline this November vs. a year ago is explained by the $23 per barrel increase in LLS since then. In other words, crude prices have increased by slightly more than gasoline, suggesting that raw material costs still have a much larger impact on prices at the pump than does the recent shift in US petroleum product trade patterns.

Although the evidence that product exports don't hurt consumers is strong, I don't expect it to dispel this handy new rationale for complaining about gas prices. After all, the price of gasoline is one of the most visible and volatile prices we're exposed to, and for which we have few practical alternatives. Having a narrative to explain these spikes and dips is empowering, even if it's wrong. However, in the midst of all the grumbling it's worth spending a moment thinking about the benefits of having an oil refining industry that has been able to find alternative outlets for its products while it waits for the US economy to recover, instead of yet another manufacturing industry on the ropes, shedding jobs and moving offshore.