Will Fewer Young Drivers Today Mean Lower Fuel Demand Tomorrow?

• Driver's licenses for those under 40 years of age are down in several large, developed countries, including the US. This is only partially explained by a weak economy.
• If this shift in attitudes towards driving persists, future demand for both cars and fuel could be permanently reduced.

Current forecasts from the Energy Information Administration indicate that US gasoline demand peaked in 2007 and is expected to decline steadily for at least the next two decades.  One of the most intriguing factors aligned with this shift, which would have been almost unthinkable only a few years ago, involves a surprising reduction in the number of licensed drivers under 40 years of age.  A new study from the Transportation Research Institute (TRI) at the University of Michigan helps to explain a trend that is apparently not unique to the US.

Prior to the Great Recession, US gasoline demand had grown by 1-2% per year, with few interruptions. Since the recession, it has been shrinking for reasons that don't appear to be temporary. New cars are becoming more fuel-efficient, and Americans are consistently driving less than before the recession,  as indicated in the latest statistics on vehicle miles traveled.  To some extent this is an understandable response to gasoline prices that have remained significantly higher in real dollars than they were from 1982-2006. However, there may be other, deeper shifts underway.  If a segment of younger Americans has not only delayed getting a driver's license, but may never get one, then the decline in motor fuel demand is likelier to be permanent.

Once I started reading the survey results in the new study by the TRI's Brandon Schoettle and Dr. Michael Sivak, I knew I also needed the context of their 2011 paper on "Recent Changes in the Age Composition of Drivers in 15 Countries." That study showed that from 1983 to 2008 the number of licensed drivers in the US as a percentage of each age group up to 40 had dropped significantly, while the opposite was true for those over 50. (See chart below.) The authors found similar shifts in 7 other developed countries, including Canada, the UK, Germany and Japan, with a 2012 update indicating a further decline in US pre-40 licensing through 2010. Interestingly, Spain, Poland, Israel and several other countries exhibited increases in licensing among both younger and older drivers.

In their current paper, the authors used an online, non-random survey of 618 under-40 non-drivers to explore the reasons for their status. The top reasons their respondents gave for not having a driver's license seemed mainly practical, rather than philosophical. Many of those under 30 reported being "too busy or not enough time to get a driver's license",  or "able to get transportation from others." The "cost of owning and maintaining a vehicle" was the second-most common reason among all respondents, and as the authors noted, that is consistent with the relatively high unemployment or full-time student status of this group--46% and 21%, respectively.

Other common responses suggest that at least some of those without licenses are in that position by intention, rather than necessity. Nearly 40%--likely including some overlap--reported a preference for biking, walking or public transportation as a primary or secondary reason, while 9% cited environmental concerns and 8% mentioned online alternatives to driving.

Having grown up in a time and place where obtaining a driver's license as close as possible to one's 16th birthday was both a rite of passage and a practical necessity, this is that rare energy issue that's hard for me even to relate to. Yet when I look at the above chart, with its mirror-image shifts, I'm struck by the similarity between recent under-40 driver's license data and those for the cohorts born between the World Wars.  Are the current license rates of Millennials and late-Gen-X'ers the anomaly, or will those of my Baby Boomer and early Generation X peers turn out to be uniquely high? Only the passage of time can clarify such questions.

While the authors stopped short of assigning cause and effect, it seems reasonable to conclude that at least part of what we're seeing here is the result of the stubbornly persistent youth unemployment of a tepid recovery and the "New Normal" economy. A few years of much stronger economic growth might shrink the gap shown in Figure 1, by addressing the reasons that many of those surveyed gave for not having a driver's license, particularly since only 6% of them reported they never learned to drive.  Of course that doesn't explain why more than a third of those in the 30-39 age group, who ought to be the most financially settled, indicated they planned never to get a license.

The survey's results and their implications ought to be of great interest to producers of conventional and alternative fuels, established auto manufacturers, car rental firms, as well as transportation planners and policy makers.  Even electric-vehicle startups like Tesla might wonder whether for a significant segment of their natural future market, the choice won't be between an EV and a conventional car, but between a car and not driving at all. This is a trend that bears watching.

 

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

Will the Keystone XL Decision Be Based on Incorrect Assumptions?

• Some of the facts about the Keystone XL pipeline project that President Obama cited in an interview last month turned out to be wrong. That's significant, if he is the ultimate decision-maker on this question.
• Whatever his assessment of the pros and cons of the project, the politics of Keystone are trumping the facts, indicating the decision is likely to be deferred as long as possible. 

When President Obama commented on the merits of the Keystone XL pipeline project in an interview in the New York Times last month, the Washington Post suggested that his remarks “give opponents reason for hope.” Although he confirmed that the White House’s main objective criterion for making this decision was still the pipeline’s greenhouse gas impact, the President also speculated about the project’s job-creation potential and the ultimate destination of the crude oil it would carry. This appeared to endorse arguments raised by opponents of the project. These issues deserve more than the dismissive treatment they received in the interview.

With regard to the number of direct construction jobs that the northern leg of the Keystone XL Pipeline (KXL) might create, I don’t know whether the right number is the 2,000 the President cited or the tens of thousands estimated in an earlier State Department study. However, fact checking by both PolitiFact and AP concluded he was wrong.

In any case, this administration lacks credibility on counting such jobs. Consider the White House's metric of “jobs created or saved” for assessing the impact of the 2009 stimulus, or the routine touting of projects with “green jobs” potential, not just in terms of their direct employment gains, but also their indirect job creation estimated via generous multiplier effects. Either indirect jobs are always relevant, in which case KXL would create far more jobs across the economy than the President seems willing to admit, or they also aren’t relevant to justifying clean energy and other, more favored infrastructure projects.

The more interesting issue Mr. Obama brought up relates to the disposition of the oil-sands crude that the KXL would ultimately carry from Alberta to the Gulf Coast. For starters, this isn’t relevant for whatever volume of North Dakota production the pipeline might also carry, since current rules prohibit its export to anywhere except Canada. Of the pipeline’s planned capacity of 830,000 barrels per day, some would be used to ship US crude to US destinations, some would carry Canadian  oil destined for US refineries in the mid-continent, while an unspecified remainder would arrive at the Gulf Coast.  However large the latter figure might be, it’s doubtful that much of it would ever leave these shores. To understand why, you need to consider the quantity of US oil imports of similar quality currently coming into the Gulf.

Overall, Gulf Coast crude oil imports have fallen by around a third since 2007, but they still amount to around 4 million barrels per day – 5x the total capacity of the KXL. Unsurprisingly, much of the crude imported into the Gulf is either sour or heavy, since the refineries in the region have invested billions of dollars in the hardware required to process such crudes, which are typically cheaper than lighter, sweeter grades. A quick glance at the countries of origin of the import mix confirms this, with suppliers such as Mexico, Saudi Arabia, Venezuela, and Iraq dominating recent imports. Imports from Algeria, Angola, and Nigeria have been slashed by surging production of light, sweet crude in Texas and other states.

In the interview, President Obama said, “So what we also know is, is that that oil is going to be piped down to the Gulf to be sold on the world oil markets, so it does not bring down gas prices here in the United States.” For him to be right about that, we must believe that the current importers of around 2.7 million barrels per day of generally similar crude from South America and the Middle East would ignore the arrival in their market of new supplies from Canada and continue to buy from existing suppliers, and that those other suppliers would be able to continue to charge the same prices as before, despite significant new competition. Although I wouldn’t argue that oil sands crude would never be exported from the Gulf, imagining that most of it would simply sail right by the closest and largest global refining center equipped to handle this type of crude oil reflects a remarkably superficial view of how oil markets actually work.

The Keystone XL decision process clearly encompasses both factual and political considerations.  On the facts alone and the criteria set by the administration, the pipeline would eventually have to be approved, since even in the worst realistic case its impact on global greenhouse gases would be minimal--on the order of 0.4% of global emissions--while it offers clear benefits including reliability of supply. The protracted delays in approving this project provide all the evidence needed to confirm that political considerations outweigh the facts. Deciding now in favor of either side offers limited political benefits but carries huge risks; continuing to leave the issue in suspense has paid dividends at little apparent political cost.

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

Unlocking the UK's Shale Gas Potential

• Following estimates of substantial shale gas resources underlying parts of Britain, the UK government is proposing incentives for companies and local communities to encourage its timely development.
• Even if it ultimately proved less transformative than in the US, shale gas could balance the UK's future energy mix, while setting an example that other shale-rich EU countries could follow. 

Shale gas development has been slow out of the starting blocks in Europe, for reasons that have been widely discussed.  These include differences in mineral rights ownership, smaller onshore oil and gas service sectors, and significantly fewer onshore wells drilled in the past, compared to the US.  Local opposition to hydraulic fracturing also plays a role in some countries. Last month the UK government announced new proposals intended to address some of these challenges and make shale gas more attractive to produce there. The Prime Minister underlined these proposals in an op-ed in Sunday's Telegraph.

The UK's natural gas market has been experiencing problems similar to those the US encountered in the last decade, prior to wide-scale development of shale gas resources.  Natural gas production from the offshore fields of the UK sector of the North Sea, which provided an energy surplus until about ten years ago, has declined rapidly. As a result, the Interconnector UK, a bi-directional gas pipeline linking Britain to continental Europe, has recently operated mainly in import mode. UK natural gas prices have been correspondingly high and volatile, spiking briefly to around $17 per million BTUs this March. Prices in excess of $10/MMBTU are typical.

Against this background, the UK government is understandably interested in pursuing the exploration of the country's potentially enormous shale gas deposits.  In June the British Geological Survey released its detailed estimate for the Bowland shale in the north of England.  With a range of 822-2,281 trillion cubic feet (TCF) of gas-in-place, and a "central estimate" of 1,329 TCF, this looks like a significant resource. Even at the low end of the BGS assessment, and using a conservative figure of 15% recovery based on relevant US shale gas recovery rates, the Bowland could provide 120 TCF or more of technically recoverable gas, the equivalent of over 40 years of current UK consumption.

Two aspects of the government's proposals caught my attention.  First, the Chancellor of the Exchequer indicated his plan to make development attractive for producers with a new tax structure that he intends to be "the most generous for shale in the world." Earnings from shale would be taxed at 30%, compared to 62% for other hydrocarbon projects.  With only a few companies currently exploring for shale, that should attract additional drillers, along with the service companies that perform many of the key activities at the well site. 

I was more intrigued by the proposal--apparently originating with industry--to provide local communities with a benefit of at least £100,000 per well-site that is hydraulically fractured, or "fracked", plus a small share of gas revenue. In a country where the government owns the sub-surface property rights, this could be a crucial step in gaining local support for projects that, in addition to significant economic activity and eventually local employment, will also result in unavoidable increases in noise, traffic and other intrusions in daily life during the weeks or months in which each site is being prepared, drilled, completed and brought on-line, and for the longer periods that crews would be operating in the area.

We've certainly seen the importance of local benefits in promoting receptiveness towards gas drilling in the US, where most shale development has occurred on private land, and where royalties from production provide property owners with regular payments ranging from helpful to lifestyle-altering, depending on production rates and the ownership interests. Sharing financial benefits from shale production at the community level, rather than with individuals, might even galvanize broader-based support than in some parts of the US. Much will depend on whether British communities consider the offered compensation sufficiently generous.

UK shale development still faces significant above- and below-ground uncertainties that only time and drilling can resolve.  Nor is it clear whether development of the Bowland shale would have as large an impact on the UK gas market as shale gas has had here.  Skeptics can be found among opposition politicians and respected energy analysts, though I must say their arguments about high costs and low production rates sound very similar to those that I heard in energy conferences in the US not many years ago.  Signposts to watch include the number of drilling companies moving into the north of England and emulation of the UK government's pro-development policies by other countries.

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

Crashing into the Ethanol Blend Wall

• The long-anticipated arrival of the ethanol "blend wall" for gasoline is the inevitable result of a federal policy designed for a world of expanding gasoline sales that no longer exists.
• This is not just another arbitrary crisis; it is already costing consumers at the pump, and those costs will increase unless the Renewable Fuel Standard is reformed or repealed.

The Energy and Commerce Committee of the US House of Representatives held hearings late last month on the Renewable Fuel Standard (RFS). It’s otherwise known as the ethanol mandate, although it covers biodiesel, as well. The hearings were timely, since at least two bills have been introduced to reform or repeal the RFS.  During the session on July 23rd, Rep. Waxman (D-CA) referred to the “gasoline blend wall, which may be around the corner.” In fact, a review of current gasoline sales and this year’s final ethanol target--just issued yesterday!--confirms that the ethanol “blend wall” has arrived, at least for some of the nation’s refiners. That explains the urgency of the debate about the future of the RFS.

The blend wall is simply the threshold at which the RFS requires more ethanol to be blended into US gasoline than the quantity necessary to dose essentially all of it with the maximum 10% ethanol content for which most cars on the road were designed. Because the Environmental Protection Agency, which administers the RFS, has been unwilling to exercise its flexibility under existing law, the fuels industry must now choose from a set of unattractive options: It can limit mainstream gasoline to 10% ethanol content and absorb substantial RIN costs (see below) or statutory penalties for failing to blend the required volumes of biofuel. It can produce less gasoline than the country needs, or export more of its production, to reduce its renewable fuel obligations. Or it can produce higher-ethanol blends such as E15 and risk the integrity of millions of cars and large portions of the country’s fuels infrastructure, including all but the newest gas station pumps and tanks. All of these choices affect the price consumers pay at the pump.

In order to understand why the blend wall is a serious problem, rather than another arbitrary crisis, we need to examine its two main elements. The first is fairly straightforward, relating to the mechanical integrity of the pumps and seals in automobile engines and fuel systems, as well as refueling infrastructure. While most of these function acceptably with blends of up to 10% ethanol in gasoline, there’s significant controversy about what happens above that threshold. As I noted in June, this issue has become relevant much sooner than the 2007 law anticipated, because US gasoline sales have declined instead of continuing to grow by 1-2% per year, while sales of E85 remain small and mainly regional.

As the head of the American Automobile Association (AAA) indicated in his testimony before Congress, any new product like E15, which consists of 15% ethanol and 85% petroleum gasoline, should have been tested thoroughly before release. Although the EPA conducted extensive testing before certifying E15 for use in 2001 and later model cars, as best I could tell their focus was on vehicle emissions systems, rather than mechanical integrity. Other tests conducted at the behest of the fuels industry identified problems with higher ethanol blends in vehicles not specifically designed as “flexible fuel vehicles” (FFVs) which can use up to 85% ethanol. UL previously tested existing service station product dispensers (gas pumps) and observed leaks and other failures above 10% ethanol. The uncertainties that have been raised by independent testing may not be conclusive, but they can only be resolved by a lot more testing on actual vehicles, not by rhetoric. The bottom line for consumers is that most carmakers won’t warrant any but their latest models for use with E15.

Another important but more obscure aspect of the blend wall relates to a feature of the RFS called Renewable Identification Numbers, or “RINs”. The RFS regulations created RINs for tracking purposes, to provide “the basic framework for ensuring that the statutorily required volumes of renewable fuel are used as transportation fuel in the U.S.” But they also have another purpose. RINs can be separated from the physical gallons of renewable fuel and traded in the market, effectively becoming paper ethanol. Enabling this RIN market, which includes both “obligated parties” — mainly refiners and importers of finished gasoline — and non-obligated parties such as gasoline blenders and traders, provides some flexibility in the RFS compliance system. It allows refiners that cannot blend any more ethanol into their direct fuel sales — or cover their typically larger sales of pre-ethanol product — to satisfy their legal obligations under the RFS by presenting a certificate, instead.

This worked reasonably well when the annual blending target was lower and refiners and marketers could bank RINs for future use by blending more ethanol than required, while remaining under the 10% limit. However, only 20% of the RINs generated in that manner last year could be carried over into 2013, restricting the supply just when the market approached the overall 10% blend wall. My understanding from those who follow this market is that this “bank” will become insolvent sometime next year, limiting new RINs largely to those generated from sales of E85 in the Midwest.

Now, with the blend wall a reality, the limited stock of RINs from past blending is being drawn down at prices that have spiked from a few cents per gallon-equivalent at the start of the year to well over $1.00 recently. Some refiners are spending hundreds of millions of dollars on RINs. It’s hard to determine how much of that is being passed on to consumers in fuel prices, because of the complexities of the RIN market and the agreements that various participants have made concerning the allocation of RINs. If 100% of their cost were passed on, then RINs at $1.00 would add $0.10 per gallon to the price of gasoline at the pump. The higher the annual RFS target ratchets, the higher RIN prices could go, with a recent estimate setting the potential impact on gasoline prices in 2014 at $0.19/gal, with the possibility of even larger increases in diesel prices.

Another potential outcome mirrors a comment made the hearings by the CEO of Cumberland Gulf Group, a large gasoline distributor. He characterized the functioning of the RFS and its RIN provisions as “subsidizing exports and taxing imports.” Refiners that don’t have enough RINs to cover their gasoline production will weigh current RIN prices against the profit they could generate by exporting more of their output to other countries, thus reducing the volume that must be covered by RINs. This could have an even bigger impact on the US gasoline market than merely passing through the cost of RINs. That's because gasoline prices are set by the last increments of supply and demand, and small shortfalls can translate into large price increases. That’s exactly what seems to be happening now in the artificial market the EPA has created in RINs.

The original purpose of the RFS and the law that established it was to reduce US reliance on imported oil, along with reducing greenhouse gas emissions. Because of its lower energy content the ethanol blended into US gasoline this year displaces about 540,000 barrels per day of gasoline produced from petroleum, though with questionable environmental benefits. That’s almost exactly the average quantity of finished gasoline and gasoline blending components exported from the US in the last 12 months reported.  Although that might be at least partly coincidental, it’s a further indication of just how much our national energy situation has changed since the legislation establishing the current RFS was passed in 2007.

One of the experts appearing before Congress characterized ethanol as an additive, rather than a replacement fuel. Until and unless E85 sales grow dramatically, that seems apt. Our elected representatives should now be asking themselves whether it makes sense — in light of altered circumstances and the EPA's decision to defer any administrative adjustments in the RFS until next year — to subject the US motor fuels market and consumers to a new and entirely artificial source of price volatility for the sake of an additive that the CEO of Growth Energy, a major ethanol trade association, testified would continue to be produced and sold in the absence of the mandate. When considered together with serious questions about its impact on food supplies and prices, the case for at least reform of the Renewable Fuel Standard is compelling.

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

Oil's Eastern Hemisphere is Shifting, Too

• OPEC's exports earned record revenue last year, but the pressure on the cartel is increasing as Eastern Hemisphere production expands, along with higher unconventional oil production in North America.
• Increasing supply doesn't guarantee lower oil prices in the future, but it will help accommodate growing demand from the developing world, reducing the risk of price spikes such as we saw in 2008.

No one should be surprised that the turmoil in Egypt has caused jitters in the oil markets.  Although Egypt has recently become a net oil importer, the possibility of extended violence or even civil war poses risks to the tanker traffic through the Suez Canal. This has helped to push UK Brent crude to its highest level since April and contributed to higher prices for West Texas Intermediate (WTI) crude than we've seen in over a year.  Yet while these events provide the latest of many prods to nudge oil prices higher, underlying long-term supply trends look favorable.  That's not just because of surging US oil output, which is largely attributable to shale or "tight oil."

US production of crude oil and natural gas liquids grew by roughly 2 million barrels per day (MBD) from 2008-12, with a similar increase expected by 2020, even in the relatively conservative forecast of the US Energy Information Administration.  As a result, US oil imports are shrinking, scrambling long-established supply patterns in the Atlantic Basin. However, North America isn't the only place where supply is expanding, nor is the shale revolution responsible for the production growth in the Eastern Hemisphere, at least not yet.

The big story there is Iraq. Thanks to the development contracts its government negotiated with international firms after the fall of Saddam Hussein, Iraqi production is growing and might eventually reach the potential suggested by its enormous conventional oil reserves. Whether or not Iraq really has 150 billion barrels of oil in the ground-- this figure ratcheted up over the years in an odd two-step with its historical rival Iran--the consensus is that it has ample scope to boost output at relatively low cost. 

As the Financial Times reported, Iraq's plans to increase oil production capacity from around 3 MBD to 12 MBD, which would put it in the same league with Saudi Arabia, are now in doubt due to multiple concerns.  But even with companies seeking to renegotiate service contracts that looked too lean when they were set, and the Kurdistan Regional Government in the north of Iraq signing deals independently of Baghdad, Iraq produced more oil last year than it had since the outbreak of the Iran-Iraq War in 1980. The International Energy Agency apparently expects Iraqi production to nearly double to 6.1 MBD by the end of the decade.

If this comes to pass, it will significantly alter the dynamics within the Organization of Petroleum Exporting Countries, and possibly change OPEC's role in the market. It would lift Iraq well above other producers like Iran, Kuwait, the UAE, and Venezuela--all clustered around 2-3 MBD--and leave it second only to Saudi Arabia. Given recent Saudi domestic consumption trends, the race for future export leadership could be even tighter.

Despite record oil revenue last year, tensions are growing within OPEC, which had welcomed post-war Iraq back into its ranks and didn't constrain its output with an official production quota.  This accommodation is even simpler today, with OPEC operating without country-specific quotas. Yet in the absence of a large increase in demand for OPEC's oil in the developing world, a steadily expanding Iraq will either force painful adjustments on other members or bust the cartel's quota entirely.  Whether that results in rising inventories or merely higher spare production capacity, it would exert downward pressure on oil prices and on OPEC members' national budgets.

Another important shift is associated with the growth of oil output in Kazakhstan, the second-largest oil producer to emerge from the breakup of the Soviet Union.  Production has increased steadily since the 1990s, reaching 1.7 MBD last year. With the startup of the supergiant Kashagan field later this year, the country's production should exceed 3 MBD by 2020, with exports over 2 MBD. That would make Kazakhstan a bigger factor in global oil markets than Iran, as long as the latter continues to be hemmed in by sanctions. 

No one can predict oil prices in 2020 with any certainty. However, the combination of significant supply growth in North America, Iraq and the Former Soviet Union with flat or shrinking demand in the US and Europe provides headroom for further demand growth in Asia and the Middle East itself.  That doesn't necessarily augur a big drop in prices ahead--much of this new production isn't exactly cheap--but it could signal a period of greater price stability than we've experienced for a while.  That's assuming none of the various crisis scenarios erupts in the meantime.

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