Five Myths About the "Carbon Asset Bubble"

• The idea that efforts to mitigate climate change expose fossil fuel assets to the risk of a bubble-like collapse has attracted some high-profile supporters.
• However, the notion of a "carbon bubble" depends on questionable assumptions concerning our current knowledge of climate change, the rate of adoption of renewable energy technology, and how such assets are valued.

In their recent Wall St. Journal op-ed, Al Gore and one of his business partners characterized the current market for investments in oil, gas and coal as an asset bubble. They also offered investors some advice for quantifying and managing the risks associated with such a bubble. This is a timely topic, because I have been seeing references to this concept with increasing frequency in venues such as the Financial Times, as well as in the growing literature around sustainability investing.

Although bubbles are best seen in retrospect, investors should always be alert to the potential, particularly after our experience just a few years ago. In this case, however, I see good reasons to believe that the case for a “carbon asset bubble” has been overstated and applied too broadly. The following five myths represent particular vulnerabilities for this notion:

1. The Quantity of Carbon That Can Be Burned Is Known Precisely
Mr. Gore is careful to differentiate uncertainties from risks, which he distinguishes for their amenability to quantification. For quantifying the climate risk to carbon-heavy assets, he refers to the widely cited 2°C threshold for irreversible damage from climate change, and to the resulting “carbon budget” determined by the International Energy Agency (IEA). As Mr. Gore interprets it, “at least two-thirds of fossil fuel reserves will not be monetized if we are to stay below 2° of warming.” That would have serious consequences for investors in oil, gas and coal.

The IEA’s calculation of a carbon budget depends on a factor called “climate sensitivity.” This figure estimates the total temperature change resulting from a doubling of atmospheric CO2 concentrations. The discussion of climate sensitivity in the recently released Fifth Assessment Review of the Intergovernmental Panel on Climate Change (IPCC) sheds more light on this parameter, which turns out not to be known with certainty. Their Summary for Policymakers includes an expanded range of climate sensitivity estimates, compared to the IPCC’s 2007 assessment, of 1.5°-4.5°C with a likelihood defined as 66-100% probability. It also states, “No best estimate for equilibrium climate sensitivity can now be given because of a lack of agreement on values across assessed lines of evidence and studies.”

The draft technical report that forms the basis for the Summary for Policy Makers provides more detail on this. It further assesses a probability of 1% or less that the climate sensitivity could be less than 1°C. That shouldn’t be surprising, since temperatures have already apparently risen by 0.8°C above pre-industrial levels. At the same time, the report indicates that recent observations of the climate — as distinct from the output of complex climate models — are consistent with “the lower part of the likely range.”

In other words, while continued increases in atmospheric CO2 resulting from increasing emissions are widely expected to result in warmer temperatures in the future, the extent of the warming from a given increase in CO2 can’t be determined precisely before the fact. For now, at least, the CO2 level necessary to reach a 2°C increase would be consistent with calculated carbon budgets both larger and smaller than the IEA’s estimate. That means that the basis of Mr. Gore’s suggested “material-risk factor” — as distinct from an uncertainty — is itself uncertain.

2. The Transition to Low-Carbon Energy Is Occurring Fast Enough to Threaten Today’s Investments in Fossil Fuels
There is no doubt that renewable energy sources such as wind and solar power are growing at impressive rates. From 2010 though 2012 global solar installations grew by an average of 58% per year, while wind installations increased by 20% per year. Yet it’s also true that they make up a small fraction of today’s energy production, and that the risks for investors of extrapolating high growth rates indefinitely proved to be very significant in the past.

For further clarity on this, consider the IEA’s latest World Energy Outlook, the agency’s analysis of global energy trends, which was just released on November 12. The IEA projects global energy consumption to grow by 33% from 2011 to 2035 in its primary scenario, which reflects expanded environmental policies and incentives over those now in place. In that scenario, the global market share of fossil fuels is expected to fall from 82% to 76%, but with total fossil fuel consumption still growing by 24% over the period. Only in their “450″ scenario, based on similar assumptions to its carbon budget, would fossil fuel consumption fall by 2035, and then only by 11%.

Moreover, in its April 2013 report on “Tracking Clean Energy Progress,” the IEA warned, “The drive to clean up the world’s energy system has stalled.” This concern was based on their observation that from 1990 to 2010 the average carbon dioxide emitted to provide a given unit of energy in the global economy had “barely moved.” That’s hardly a finding to be celebrated, but it serves as an important reminder that while some renewable energy sources are growing rapidly, fossil fuel consumption is also growing, especially in the developing world — and from a much larger base.

The transition to lower-carbon energy sources is inevitable. However, it will take longer than many suppose, and it cannot be accomplished effectively with the technologies available today. That’s a view shared by observers with better environmental credentials than mine.

3. All Fossil Fuels Are Equally Vulnerable to a Bubble
As Mr. Gore correctly notes, “Not all carbon-intensive assets are created equal.” Unfortunately, that’s a distinction that some other supporters of the carbon asset bubble meme don’t seem to make, particularly with regard to oil and natural gas. The vulnerability of an investment in fossil fuel reserves or hardware to competition from renewable energy and decarbonization doesn’t just depend on the carbon intensity of the fuel type — its emissions per equivalent barrel or BTU — but also on its functions and unique attributes.

The best example of this might be a recent transaction involving the sale of a leading coal company’s mines. What’s behind this wasn’t just new EPA regulations making it much harder to build new coal-fired power plants in the US, but some fundamental, structural challenges facing coal. Power generation now accounts for 93% of US coal consumption, as non-power commercial and industrial demand has declined. This leaves coal producers increasingly reliant on a utility market that has many other--and cleaner--options for generating electricity. That’s particularly true as the production of natural gas, with lower lifecycle greenhouse gas emissions per Megawatt-hour of generation, ramps up, both domestically and globally. Coal accounts for about half of the global fossil fuel reserves that Mr. Gore and others presume to be caught up in an asset bubble.

Compare that to oil, which at 29% of global fossil fuel reserves, adjusted for energy content, still has no full-scale, mass-market alternative in its primary market of transportation energy. Despite a decade-long expansion, biofuels account for just over 3% of US liquid fuels consumption, on an energy-equivalent basis. They’re also encountering significant logistical challenges and concerns about the degree to which their production competes with food. This has contributed to efforts in the EU to limit the share of crop-based biofuels to around 6% of transportation energy. Biofuels have additional potential to displace petroleum use, particularly as technologies for converting cellulosic biomass become commercial, but barring a prompt technology breakthrough they appear incapable of substituting for more than a fraction of global oil demand in the next two decades.

Electric vehicles offer more oil-substitution potential in the long run, though they are growing from an even smaller base than wind and solar energy. Their growth will also impose new burdens on the power grid and expand the challenge of displacing the highest-emitting electricity generation with low-carbon sources.

Meanwhile, natural gas, at 20% of global fossil fuel reserves, offers the largest-scale, economic-without-subsidies substitute for either coal or oil. In any case, it has the lowest priority for substitution by renewables on an emissions basis, and so should be least susceptible to a notional carbon bubble.

4. A Large Change in Future Fossil Fuel Demand Would Have a Large Impact on Share Prices
Although Mr. Gore’s article includes a good deal of investor-savvy terminology, it is entirely lacking in two of the most important factors in the valuation of any company engaged in discovering and producing hydrocarbons: discounted cash flow (DCF) and production decline rates. Unlike tech companies such as Facebook or even Tesla, the primary investor value proposition for which depends on rapid growth and far-future profitability, most oil and gas companies are typically valued based on risked DCF models in which near-term production and profits count much more than distant ones.

At a conservative discount rate of 5%, the unrisked cash flow from ten years hence counts only 61% as much as next year’s, while cash flow 20 years hence counts only 38% as much. Announced changes in near-term cash flow due to unexpected fluctuations in production or margins would normally be expected to have a much bigger impact on share prices than an uncertain change in demand a decade or more in the future.

This is compounded by the decline curves typical of many large hydrocarbon projects. If the first 3-5 years of a project account for more than half its undiscounted cash flows, it won’t be very sensitive to long-term uncertainties, nor would a company made up of the aggregation of many projects with this characteristic. This is even truer of shale gas and tight oil projects, which yield faster returns and decline more rapidly.

I can’t speak for Wall Street's oil and gas analysts, but I’d be surprised based on past experience in the industry if the risk of a 10% or greater drop in global demand for oil or gas in the 2030s would have much of an effect on their price targets for companies — certainly not enough to qualify as a bubble.

5. Fossil Fuel Share Prices Don’t Already Account for Climate Risks
The assertion of a carbon bubble in fossil fuel assets ultimately depends on investor ignorance of climate-response risks, presumably because companies haven’t quantified those risks for them. To the extent the latter condition is true, it represents an opportunity for companies seeking to capitalize on the boom in sustainability-based investing.

However, you needn’t be an adherent of the Efficient Markets Hypothesis for which Eugene Fama was named as a recipient of this year’s Nobel Prize in Economics to realize that thanks to the Internet, average investors have access to most of the same information on this subject as Mr. Gore and his partners. Institutional investors, who make up the bulk of the shareholding for at least the larger energy firms, and the analysts who follow these companies have the resources to access even more information.

Nor is the idea of a carbon bubble exactly new. Mr. Gore didn't create it, and I’ve been following it for a couple of years, as it took over from waning interest in Peak Oil. It’s not an obscure risk, either, in the sense that sub-prime mortgages and credit default swaps were in the lead-up to the failure of Lehman Brothers in 2008. It’s becoming more mainstream every day, although the burden of proof that this risk is mispriced rests with those advocating this view.

Before concluding, a word of disclosure is in order. As you may gather from my bio, I spent many years working with and around fossil fuels, though my ongoing involvement in energy is much broader than that. As a result of that experience, my portfolio includes investments in companies with significant fossil fuel holdings. I strive for objectivity, but I can’t claim to be disinterested. However, neither can Mr. Gore. As a major investor in renewable energy and other technologies through the firm cited in the article and other roles, he has as much at stake in promoting the idea of a carbon bubble — and on a very different scale — as I might have in dispelling it.

The carbon bubble is an interesting hypothesis, even if I don’t yet find the arguments made in support of it convincing. Despite that, I see nothing wrong with investors wanting to track their carbon exposure, consider shadow carbon prices, or ensure they are properly diversified. However, the biggest risk I see that might eventually warrant considering divestment of fossil-fuel-related assets isn’t based on the merits of this analysis, but on the possibility of creating a self-fulfilling prophesy by means of drumming up social pressure on institutional investors. You might very well think that applies to this Wall St. Journal op-ed. I couldn’t possibly comment.

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

EPA's Ethanol Adjustment Falls Short of Reform

• As the ethanol blend wall arrives, the EPA has proposed adjusting downward the federally mandated level of corn ethanol to be blended into gasoline.
• This would relieve pressure on fuel blenders and retailers, but doesn't solve a problem widely expected to require bigger adjustments each year.

Last Friday the US Environmental Protection Agency proposed significant adjustments to the 2014 Renewable Fuel Standard, the federal biofuel mandate that the EPA administers. The headline change was a nearly 3 billion gallon reduction in the required biofuel volume for next year. However, as various observers, including the editors of the Washington Post, failed to differentiate, less than half of that reduction was truly discretionary. The remainder was a necessary acknowledgement of the persistently slow pace of cellulosic biofuel development and entirely in keeping with precedent.

I've written extensively about the ethanol blend wall and the need to reform the RFS and what that might look like. I don't intend to rehash those issues today. Rather, I'd like to focus on the specifics of the EPA's announcement, and why as the Post stated, "it doesn't go far enough."  Because of the way the RFS targets roll up, it's not easy to see exactly what the Agency has proposed doing with each category of biofuel under the mandate.

The first aspect requiring clarification is that the roughly 99% cut in the most restrictive category of the RFS, the target for cellulosic biofuel, is nothing new. It's at least the fourth consecutive annual reduction by my count, reflecting that the substantial volumes of cellulosic biofuel projected back in 2007 were more than merely ambitious. Several new cellulosic facilities, including plants belonging to DuPont and POET, are scheduled to start up within the next year. I hesitate to call them commercial-scale, not just but their output will be less than that of typical corn-ethanol plants, but because their commerciality can't truly be known until they're started up, de-bugged and running smoothly.

Together with another plant that has already started up, these facilities will still not come close to producing the 1.75 billion gallons of cellulosic biofuel originally mandated for 2014. For the first time, though, EPA's newly revised range of 8-30 million gallons might prove realistic.

Because the RFS's "cellulosic" category rolls up within the larger, less-restrictive "advanced" biofuel category, it wasn't obvious that the effective new 2014 target for non-cellulosic advanced biofuel, which includes biodiesel, as well as ethanol from sugar cane, actually represents a modest increase from 2013 and essentially no change from its original level of 2 billion gallons.

The only truly discretionary change in the EPA's proposal falls on the least-restrictive RFS category of "renewable biofuel." As a result, the 2014 mandate for ethanol produced from corn and other grains would be cut from 14.4 billion gallons to 13.01 billion gallons--the most important figure in the entire proposal and one you won't find in the EPA's press release. 2014 US gasoline sales are expected to be just sufficient to absorb that quantity of ethanol without exceeding the 10% blending limit in place for most US gasoline, other than E85 and the literal handful of stations selling E15, the EPA's approved 15% blend. This reduction represents a milestone and should be welcomed by consumers worried about the cost and quality of the fuel they buy.

The corn ethanol industry is understandably displeased with this proposal, which makes it clear that when push comes to shove, the EPA's preference is for more advanced biofuels over corn ethanol. But the bigger issue is the one to which the Washington Post's editorial alludes: a one-year fix cannot address the structural problems of a rule that is on a trajectory to diverge farther from its planned version of the future with each passing year.

The outcome is far from settled. The EPA's 60-day comment period is just beginning, and numerous legislators, trade associations, and companies will want to have their say about it. They should hear from ordinary consumers, too.

Will Self-Driving Cars Revolutionize Vehicle Efficiency?

• Innovators are developing the systems necessary for cars to drive themselves. Some, including Google, have already staged impressive demonstrations.
• However, synergies with alternative fuels appear modest, and the largest efficiency gains from self-driving cars are likely to be deferred until they dominate the market.  

Self-driving cars, also referred to as autonomous cars, have been in the news for several years. Interest in them spiked in September 2012, when Google announced it would make the technology available to the public within five years. Yet while this could be revolutionary in many ways, the most relevant question for us here concerns their potential to reduce transportation energy demand. At this point the likely effects of self-driving cars on fuel consumption and fuel choice appear less spectacular and more uncertain than their other selling points.

Although the entire concept of a self-driving car might seem science-fictional, it shouldn't greatly surprise anyone who has reflected on the implications of drone aircraft, GPS, smartphones, and the increasing electronification of average cars for the last several decades. From that perspective, the most important constraints on their emergence probably depend less on technology than on social and regulatory factors.

The development of self-driving cars and their precursors has been embraced by some of the biggest names in the global automotive industry, including GM, Toyota, Audi, BMW, Volvo, and Nissan, which announced plans to make the technology available across its entire product line sometime in the next decade. (Nissan also recently reported that its EV sales are lagging years behind plan.)

Suppliers to the OEMs are also making important contributions. I vividly recall driving a car equipped with radar adaptive-cruise control and other then-cutting-edge safety features in city traffic at the 2009 D.C. Auto show, courtesy of Robert Bosch, LLC. All I had to do was tap the gas pedal to engage the system and then steer, while the car did the rest. Systems like this are already appearing in production models.

The two main ways in which self-driving cars could affect future transportation energy usage involve making the operation of vehicles more efficient and enabling bigger changes in vehicle design than would otherwise be feasible. Some of these benefits would start to accrue from the day the first autonomous car left a dealership, but most would require either a critical mass of such cars in the fleet, or overwhelming dominance of the fleet. That could happen sooner in fast-growing developing countries, where legacy fleets are smaller, than in the developed world.

Consider operational changes first. Highway fuel economy could be improved by 20% by means of "drafting"--one car using the car ahead to reduce wind resistance--in automated , self-organized "platoons" of multiple cars. This, together with the avoidance of collisions, would also reduce traffic congestion, variously estimated at costing up to 2.9 billion gallons of fuel each year in the US, or up to 2% of US gasoline demand. The combined potential of these savings, assuming 100% market penetration of autonomous cars, might reach 10 billion gallons per year, a quantity larger than the gasoline displaced by corn ethanol in the US.  Of course achieving such savings depends on having large numbers of self-driving cars on the road; imagine the risks if a daring driver in a conventional car attempted to join a platoon of tightly packed autonomous cars.

The efficiency gains from unattended autonomous parking don't require critical mass, and they might be significant, especially in congested urban areas, where one study suggested parking consumes up to 40% of gasoline used. However, most of these potential fuel savings could also be achieved through simpler and more easily implemented means, such as parking-space sensors and smartphone apps. And while self-driving cars might make car-sharing more popular, fewer vehicles wouldn't automatically translate into less fuel consumption if the same or more miles are driven.

The second major category of energy savings is associated with structural changes made possible by self-driving cars, mainly resulting in smaller and lighter vehicles. If cars no longer collided with each other or with inanimate objects, they wouldn't need to be nearly as robust. Saving weight saves lots of fuel. Yet it's hard to see how this process could begin before autonomous cars reached nearly 100% market penetration, since for many years they must share the road with millions of cars driven by fallible humans.

Nor is it obvious that self-driving cars would be infallible. We've already seen ordinary models exhibit random self-starting, due to malfunctioning of remote starter systems that would make up just one small subsystem of an extraordinarily complex self-driving architecture.

Some have suggested that the downsizing and weight savings facilitated by autonomous cars would hasten the adoption of battery-electric cars. The cost of today's EVs is driven largely by battery size, which is in turn a function of the vehicle's weight and its desired performance. A smaller, lighter car could make do with a smaller, cheaper battery pack. Cheaper EVs might well sell faster. However, if that must wait until enough self-driving cars are on the road for downsizing and radical lightening to become safe, it's a reasonable bet that improvements in battery technology in the intervening decades will have largely bypassed this potential benefit.

In the interim, while there might be some less-significant synergies between EVs and autonomous vehicles, neither technology is likely to depend on the other for its attraction to potential buyers. Nor do I see any obvious benefits from self-driving cars for helping alternative fuels like CNG, LNG or biofuels to gain market share.

On balance, if the average medium-term unique fuel savings of self-driving cars are limited to the 10-15% that I calculate--impressive but not game-changing--then  the opportunities to improve safety and driver productivity seem like much more important motivators for this technology, for now. I also discovered a fair amount of skepticism about how soon fully autonomous cars would be widely acceptable to both consumers and regulators. Today's energy concerns might look quaint by the time such cars arrive in sufficient numbers to have a meaningful impact on them.

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

Energy Security Four Decades After the Arab Oil Embargo

• The Arab Oil Embargo of 1973-74 focused our attention on energy security and set in motion drastic changes in the way we produce, trade and consume energy.
• With US energy output approaching or exceeding 1970s levels, some experts now advocate prioritizing competition from non-petroleum fuels over reducing oil imports.

Forty years ago this month the United States and other Western countries experienced a new phenomenon as an embargo on oil deliveries from a group of the world’s largest oil exporters took effect. The embargo was a response to the military support that the US and some of its allies were providing to Israel during the Yom Kippur War then underway in the Middle East. A recent session hosted by the US Energy Security Council commemorating these events included a fascinating conversation between Ted Koppel and Dr. James Schlesinger, US Secretary of Defense at the time of the embargo and later the first US Energy Secretary.

The other, related purpose of the meeting was a presentation and discussion on the proposition that fuel competition provides a surer means of achieving energy security than our pursuit of energy independence for the next four decades following the Arab Oil Embargo. This idea warrants serious consideration, since energy independence, at least in the sense of no net imports from outside North America, is finally beginning to appear achievable.

The 1973-74 embargo was the first oil shock of a tumultuous decade, and it triggered a true crisis. The US had relied on oil costing around $3 per barrel (bbl), not just to fuel our transportation system, but also for 17% of our electricity generation and numerous other uses. The US was then one of the world’s largest oil producers but required imports comprising about one-third of supply to balance our growing demand. With the sudden loss of over a million barrels per day of oil imports from the Middle East, and lacking the sort of strategic petroleum reserve that was established a few years later, an economy already battling inflation was tipped into recession.

The embargo rattled more than the US economy; it challenged basic assumptions of American life, including our sense of entitlement to cheap and plentiful gasoline. Before the oil crisis, gasoline prices hovered around the mid-30-cent mark, with occasional local “gas wars” taking the price down to the high-20s--the inflation-adjusted equivalent of $1.60 per gallon now. Of course with average fuel economy around 13 miles per gallon, the effective real cost per mile wasn’t necessarily lower than today’s.

Within a year gas was over 50¢ at the pump, and by the end of the decade it passed $1.00/gal. for the first time. The gas lines that resulted from the unexpected supply shortfall and the federal government’s efforts to limit the ensuing increase in prices were an affront to drivers, a category that encompassed most of the over-16 population.

That first oil crisis and the subsequent energy crisis resulting from the Iranian Revolution in 1979 set in motion a number of important changes, including a sharply increased focus on energy efficiency, a deliberate effort to diversify our sources of imported oil, a pronounced shift away from oil in power generation — to the point that it now makes up less than 1% of US power plant fuel — and the beginnings of our search for affordable, renewable alternatives to oil.

The US Energy Security Council is an impressive group that includes many former government officials and captains of industry. They’ve clearly spent a lot of time studying this issue, and their report is worth reading. As I understand their conclusions and recommendations, they regard high oil prices as a bigger risk to the US economy than oil imports, per se, because of the impact of oil prices on consumer spending and the balance of trade. They have concluded that the most effective way to apply downward pressure on prices is not simply to reduce US oil imports, but to introduce meaningful fuel competition into transportation markets, where oil remains dominant with a share of around 93%.

The group doesn’t dismiss the benefits of increasing US oil production from sources such as the Bakken, Eagle Ford and other shale formations, but because these are relatively high-cost supplies, they have concluded that their leverage on global oil prices is limited. That means that higher US oil output couldn’t provide a path back to the price levels that prevailed before the Iraq War, when West Texas Intermediate crude averaged $26/bbl in 2002 and gasoline retailed for $1.35/gal.

This is a reasonable argument, though it’s worth considering that a return to $75/bbl might be feasible, if US production kept rising. That could yield US retail gasoline prices around $2.75/gal., equating to $2.15 in 2002 dollars. This isn’t as far-fetched as it might seem, because the global oil price is determined not by the entire 90 million bbl/day of world supply and demand, but by the last few million bbl/day of incremental supply, demand, and inventory changes.

The Council’s view also appears to emphasize the direct impact of oil prices on consumer spending without recognizing that rising production and falling imports shield the economy as a whole from the worst effects of high oil prices. With oil’s contribution to the trade deficit shrinking steadily, the main impact of higher oil prices is to divert money from consumers to shareholders of oil companies — of which I should disclose I am one. While exacerbating income inequality, that should at least result in a smaller impact on GDP and employment than the combination of rising oil prices and rising imports.

If the discussion had stopped at that point, the meeting would have been just another interesting Washington gabfest. However, the group’s analysis includes a set of actions it has identified as necessary for achieving their desired outcome: US energy security extending beyond the current US oil boom, underpinned by an expanding unconventional gas revolution that is widely expected to last for decades.

Their recommendations include giving fuels like methanol derived mainly from natural gas the chance to compete with gasoline made from oil, and with biofuels.They would start with revisions to the current US Corporate Average Fuel Economy standards to give carmakers incentives — not cash subsidies or mandates — to make at least half of all new vehicles fully fuel-flexible, capable of tolerating a wide range of blends of methanol, ethanol and gasoline. That seems like a no-regrets approach that could be achieved at a very low incremental cost per car. Even if you never bought a gallon of E85, M85, or M15, it could pay for itself by protecting your car from the damage that might result if you inadvertently filled up with gasoline containing more than the 10% of ethanol that carmakers believe is safe for non-flex-fuel cars. Other recommendations include easing regulations for retrofitting existing cars for flex-fuel and forming an alcohol-fuels alliance with China and Brazil.

Yet while I repeatedly heard that the group wasn’t promoting any single fuel, talk of methanol dominated the conversation. The moderator, Ann Korin, even joked that the session sounded like an “alcohol party.” As I later pointed out to her, there wasn’t a single mention of drop-in fuels — gasoline and diesel lookalikes derived from natural gas or biomass. I regard that as a crucial omission, because such fuels would be fully compatible with the billion cars already on the road, rather than just the 60 million or so new cars produced each year. They could provide greater leverage on oil prices by producing pipeline-ready products with which consumers are already familiar, from sources other than crude oil.

Part of the appeal of methanol seemed to be the potential for producing it from shale gas at a cost well below the cost of gasoline, even on an energy-equivalent basis — an important caveat, because a gallon of methanol contains half the energy of a gallon of gasoline. I hear the same argument in support of various pathways for producing jet fuel from non-oil sources, and it subscribes to the same fallacy: that market prices are set by manufacturing costs rather than supply and demand.

Fuel is a volume game. For a non-oil gasoline substitute to drive down oil prices –and thus motor fuel prices– as far as the Council apparently envisions, it would take at least several million barrels per day, on an oil-equivalent basis. Producing six million bbl/day of methanol from natural gas would consume 20 billion cubic feet per day of it. That’s 30% of last year’s US dry natural gas production, requiring 100% of the Energy Information Administration’s forecasted growth of US natural gas production through 2034. A number of other entities have their eyes on that same gas for other applications.

As many of the speakers at the Energy Security Council event reminded us, the world is a very different place than it was in 1973. Among other changes, US energy trends are headed in the right direction, with oil demand flat or declining, production rising and imports falling. That alone makes us more energy secure than we were, either five years ago or in 1972. Future oil supply disruptions are also unlikely to look much like the Arab Oil Embargo.

The Council is certainly correct that our unexpected shale gas bonanza, producing large quantities of new energy at a price equivalent to oil at $25 or less per barrel, provides a unique opportunity to weaken OPEC’s influence on oil prices. In pursuing that goal, however, it’s essential to remain flexible concerning the best pathways for gas to compete in transportation fuel markets, whether as CNG or LNG, or through conversion to electricity, methanol, or petroleum-product lookalikes. Consumer acceptance could prove to be the biggest uncertainty governing the ultimate outcome.

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

Is An Ethanol Compromise on the Horizon?

• The RFS ethanol mandate increasingly benefits farmers and ethanol producers at the expense of motorists, small-engine users, food producers and restaurants.
• Repeal of the RFS looks unlikely, but equitable reforms addressing the needs of all affected groups are possible, if Congress is willing to compromise.

Earlier this month, National Journal hosted an event on the “Biofuels Mandate: Defend, Reform, or Repeal” from Washington, DC. I encourage you to skim through the replay. The session highlighted a wide range of views concerning the US Renewable Fuels Standard (RFS), including those of the corn ethanol and advanced biofuels industries, poultry growers, chain restaurants, environmentalists, and small engine manufacturers. Although these broke down pretty sharply along pro- and anti-RFS lines, I thought I detected hints of the kind of compromise that might resolve this issue. I’d like to focus on the elements of such a deal, rather than rehashing the positions of all of the participants, with one necessary exception.

The most disappointing contributions to the discussion occurred during the interview with Representative Steve King (R, IA) by National Journal’s Amy Harder. If we accept Mr. King’s perspective, we should embrace the RFS as being as relevant today as when it was conceived, with no changes required. That flies in the face of the serious market distortions now manifesting in the “blend wall” at 10% ethanol content in gasoline.

Among other things, Mr. King claimed that a 2008 reduction of $0.06 per gallon in the now-expired ethanol blenders tax credit brought the expansion of the corn ethanol industry to a standstill. The industry’s own statistics tell a very different story, with US ethanol production capacity having grown by a further 86% since that point.

Rep. King also characterized “food vs. fuel” concerns as a bumper sticker issue, with no basis in fact. That issue might be controversial, but it is far too substantive to dismiss so cavalierly. The latest evidence of that is a vote by the European Parliament to cap the contribution of conventional biofuel — ethanol and biodiesel derived from food crops — at 6% of transportation energy out of a 2020 target of 10%, based on concerns about sustainability and competition with food. It seemed fairly clear that the Congressman views the RFS more as a farm support measure than an energy program.

The only one of Mr. King’s comments that seemed to find traction with the other pro-RFS panelists was his odd suggestion that without a mandate for biofuels, the only federal mandate in place would be one for petroleum-based fuels. Certainly, gasoline and diesel have advantages in terms of infrastructure, energy density and the legacy fleet, but he appeared to have something else in mind. From the way others picked up on this, perhaps it was his earlier reference to the tax benefits that conventional fuel producers have long enjoyed. This is the first and easiest element on which to compromise.

If ethanol producers and advanced biofuels developers are convinced that fossil fuels get a better deal from the federal government than the one they have under the RFS and the $1.01 per gallon producer tax credit for second-generation biofuels, it would be a simple matter to replace these programs with the same incentives received by oil and gas producers and petroleum refiners. After all, the biofuel industry already benefits from the Section 199 tax deduction that accounts for a third of budgeted federal tax benefits for the oil industry, and it shouldn’t be hard to devise an accelerated depreciation benefit analogous to “percentage depletion” and the expensing of intangible drilling expenses. Combined, the value of these tax benefits is about 1.3¢ per equivalent gallon of oil or natural gas produced this year.

Other concerns came across clearly. Despite the endorsement of 15% ethanol blends by the Environmental Protection Agency, blending more than 10% ethanol in gasoline creates serious risks for the US’s 500 million existing gasoline engines, large and small. The scale of corn diversion necessary to go beyond 10% is also distorting the US agricultural economy and food value chain, all the way to the restaurants in our communities. However, those engaged in developing new biofuels that don’t rely on edible crops, or that are fully compatible with existing infrastructure and engines, are legitimately worried that the repeal of the entire mandate would strand the significant investments in new technology that have already been made, and possibly smother their industry just as it nears its first commercial-scale deployments. All these points of view struck me as eminently reconcilable within a reformed RFS that recognizes that most of the assumptions of the 2007 mandate are no longer valid.

The starting point for reform of the RFS should be a 10% cap on ethanol from all sources in mass-market gasoline — excluding E85 — combined with measures to give ethanol from non-food sources priority within that cap over ethanol produced from corn or other food crops. The advanced biofuel targets of the RFS should also be scaled back significantly to reflect the reality that the 2007 targets were wildly optimistic. Ideally, they should be adjusted each year based on the previous year’s actual output. In return, the current producer tax credit for cellulosic and other second-generation biofuels could be extended beyond its scheduled expiration at the end of this year, and then phased out over a reasonable, predictable period, perhaps tied to cumulative output.

Finally, since few on the panel seemed impressed by the EPA’s exercise to date of its statutory power to adjust the RFS to fit changing circumstances, that authority should be transferred to another agency, along with clearer guidelines on when adjustments would become mandatory.

I’d be the first to admit that the reforms I’ve outlined above fall well short of the outright repeal of the RFS that many, including myself, would prefer. That’s the essence of compromise. Having just experienced a government shutdown and debt ceiling crisis brought on by the clash of two intransigent positions, this might be preferable to an impasse that leaves an unsustainable status quo untouched. And if the assessment of Representative Welch (D-VT) concerning the appetite of the Congress to take up this matter is accurate, something along these lines might just be achievable.

Reform of the RFS would leave in place for a while longer the outlines of a mechanism that one of the session's panelists accurately described as a Rube Goldberg construction. Short of a guarantee to bail out everyone who invested in biofuels production or research on the basis of the RFS that Congress put in place in 2007, should they fail in a post-repeal market, I’m not sure there’s another course that would be sufficiently equitable to all parties involved.

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

UK Nuclear Deal Is A Bet on Baseload Power

• An agreement to build the UK's first new nuclear power plants since 1995 endorses the role of baseload generation in the future low-emission energy mix.
• Rather than constituting a choice of nuclear instead of renewables, this looks like nuclear plus renewables as a hedge on rising UK natural gas prices.

Monday's agreement between the UK government and French utility EDF and a pair of Chinese firms marks the start of the long-awaited turnover of the country's aging nuclear power infrastructure. The deal is controversial, not least for the power price of £92.50 per megawatt-hour (MWh) guaranteed to the developers. That's equivalent to about $0.15 per kilowatt-hour (kWh) at today's exchange rates. It's also strikingly different from the choices Germany and France itself have made recently.

The UK has a long history with nuclear power, having started up the world's first commercial-scale civilian reactor in 1956, following demonstration units in the US and USSR a few years earlier. Many of the plants built in the construction wave that followed have already been retired, and none has been started up since 1995. Another 40% of the country's remaining 10,000 MW of nuclear capacity is due to shut down by the end of this decade, with all but the newest, largest nuclear plant at Sizewell scheduled for retirement by the early 2020s. Even if the two new reactors that EDF and its partners will build at the Hinkley Point site in Somerset--adjacent to two 1970s-vintage reactors still in service--are completed on schedule, Britain's nuclear output is likely to shrink before it grows again.

The Hinkley C deal hinged on a question that can still only be answered theoretically today: What is the most effective future electric generating mix for achieving the necessary combination of affordability, reliability and low greenhouse gas emissions? In the aftermath of the Fukushima accident the German government decided that nuclear had no place in that mix and doubled down on its commitment to renewable energy, particularly wind and solar power, though that shift appears to require an increase in coal-fired generation to pull off. Meanwhile, France, which currently gets 75% of its electricity from nuclear, has embarked on a plan to reduce its share to 50% while expanding renewables.

The electricity mix in the UK is already changing as large offshore wind projects and onshore wind farms come online, and as the country's inexplicable flirtation with solar power increases. The gas turbines that dominated the previous wave of power plant construction are becoming more expensive to operate as waning UK North Sea gas output must increasingly be replaced by imported gas, while more coal plants shut down. All of this is underpinned by a legally binding commitment to reduce greenhouse gas emissions by 80%, compared to 1990, by 2050.

The UK's options for devising a reliable low-emission electricity mix are limited. If it wanted to build that mix around the combination of gas and renewables that California has chosen, then it would need a cheaper source of gas. That explains the government's interest in shale gas, although the outcome--both in terms of the rate of development and the future extent and cost of shale gas production--remains uncertain. It also can't rely nearly as much on solar, since it receives on average around half as much sunlight as the Golden State. Coal won't fit without carbon capture and sequestration (CCS) that is still expensive, and large-scale hydropower potential appears to be limited. That leaves nuclear as the largest-scale low-emission baseload option to anchor the energy mix, with quick-reacting natural gas turbines left to even out the fluctuations of offshore and onshore wind, and possible future wave and tidal installations.

In that context, it was surprising that the UK energy minister apparentlhy chose to frame this week's transaction as a choice for nuclear over the "blight" of the tens of thousands of wind turbines required to generate the same electricity, annually. Configuring wind power to provide enough reliable baseload energy to make nuclear unnecessary would require more overcapacity, grid upgrades and energy storage than even California's legislators could imagine. That would cost far more than the £92.50/MWh price tag for new nuclear.

And that brings us back to the price guarantee, or "strike price", which was apparently the key to getting EDF and its partners to commit to proceed on Hinkley Point. Since the UK's coalition partners had previously determined to provide no subsidies for nuclear power, arrangements such as the loan guarantees offered to US nuclear developers were out of the question. Whether the "contract for difference" scheme chosen to support Hinkley Point's future revenue--funded by ratepayers rather than taxpayers--constitutes a subsidy by another name, it is functionally similar to the Feed-In Tariffs (FITs) offered to wind, solar and other renewables in Germany and elsewhere. For comparison, the current German solar FIT guarantees utility-scale installations the equivalent of £84/MWh for a period extending past the planned start-up of Hinkley C.

Solar and nuclear power aren't interchangeable on the grid, but the spread between them highlights the financial risks involved in the current deal. The UK is placing a potentially expensive bet on low-emission baseload power from nuclear energy, while its biggest neighbors on the Continent are turning away from nuclear to pursue steadily rising shares of intermittent wind and solar power, the cost of which keeps falling. The government's call looks justifiable today for reasons of reliability and as a long-term investment--Hinkley C should still be producing billions of kilowatt-hours a year when the wind turbines and solar panels installed in Britain this year are rust and dust. However, if the UK's Bowland shale turns out to be the first Marcellus-like play outside the US, that price guarantee could cost future British ratepayers hundreds of millions of pounds per year.

Study Sheds Light on the Environmental Impact of Shale Gas

• The view that methane leaks render shale gas "worse than coal" has been further undermined by the release of a new study based on actual measurements at hundreds of gas wells.
• Previous estimates of methane leakage relied on modeling or extrapolation from remote measurements. The University of Texas study addresses these shortcomings.

Since the late 1990s natural gas has been identified by both energy experts and environmentalists as a likely "bridge fuel" to facilitate the transition to cleaner energy sources. This view has recently been challenged by suggestions that methane leakage from natural gas systems--particularly from shale gas development--might be significant enough to negate the downstream climate benefits of switching to natural gas. The results of a new study from the University of Texas, sponsored by the Environmental Defense Fund (EDF) and nine energy companies, should alleviate many of those concerns.

In order to understand why indications of potential natural gas leakage rates well above the previously assumed level of around 1% would cast doubt on the environmental benefits of gas, a brief primer on greenhouse gases (GHGs) is necessary. When present in the atmosphere, these gases contribute to global warming by trapping infrared radiation that would otherwise be emitted to space. Carbon dioxide is the primary GHG implicated in climate change. It currently makes up roughly 400 parts per million (ppm)--equivalent to 0.04%--of earth's atmosphere and is increasing by around 2 ppm per year.

The main constituent of natural gas is methane. Although atmospheric concentrations of methane are much lower than that of CO2, totaling less than 2 ppm, pound for pound it is a much stronger GHG. Its "global warming potential" is 25 times higher than CO2's over a 100-year time horizon, and even higher on a shorter time span. While most atmospheric methane has been traced to natural or agricultural sources, a large increase in atmospheric methane from natural gas production could overwhelm the undisputed downstream emissions benefits of gas in  electricity generation, compared to coal.

Several academic studies raised precisely this concern with regard to natural gas produced from shale by hydraulic fracturing, or "fracking", starting with a widely-publicized paper from a professor at Cornell University in 2010. This work relied on estimates and limited data from early shale production to arrive at a conclusion that shale gas wells leak 3.6-7.9% of their cumulative output. A more recent series of studies from the National Oceanic and Atmospheric Administration (NOAA) and the University of Colorado Boulder used airborne remote sensing techniques to calculate leakage rates similar to Professor Howarth's.

Other studies from groups as diverse as IHS CERA, Carnegie Mellon University, and Worldwatch Institute and Deutsche Bank addressed the same question but arrived at much lower leakage rates and impacts. And earlier this year the US Environmental Protection Agency reduced its previous estimate of overall natural gas leakage to a figure equivalent to 1.7%.

However, until now all scientific studies of this issue--on both sides--were based on limited data, or on indirect measurements obtained at a significant distance from actual production sites. They relied heavily on assumptions about what was happening at large numbers of gas wells, in the absence of direct observations at these sites.

That's what makes the UT study so significant; it is based on a wealth of data from actual, on-site measurements at "190 production sites throughout the US, with access provide by nine participating energy companies." That translates to roughly 500 shale gas wells in different stages of development and production. 

Overall, for the segment of the gas lifecycle they investigated, the UT team found methane emissions that were lower than EPA's latest estimates.  Emissions from "completion flowbacks" were  98% lower, partially offset by somewhat higher observed leaks from valves and other equipment. Although this study did not measure emissions from the entire gas lifecycle, including pipelines, it would be very hard to reconcile their observed average leakage rate of 0.4% of gross gas production with leakage estimates as high as those embraced by many of shale's critics.

Immediate criticisms of this study also missed several crucial points. First, without the industry involvement that they characterized as a "fatal flaw", access on this scale for direct measurements at production sites--surely the gold standard for emissions studies compared to estimates based on assumption-laden models--would have been difficult or impossible to obtain. More importantly, they also ignored the fact that the principal sources of methane emissions found by the UT team involved valves and equipment by no means unique to shale development, many of which should be amenable to hardware improvements or different technology choices.

While the UT team and their sponsors at EDF stated clearly that more work needs to be done to measure methane emissions from other parts of the gas value chain, the current paper convincingly dispels the notion that the emissions from shale gas development are inherently much higher than those for gas produced from vertical wells in conventional oil and gas reservoirs. Since shale gas already accounts for over a third of US natural gas production and is widely expected to dominate future production, that result has large implications for the environmental benefits of further fuel switching and other applications for natural gas.

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

As US Oil Production Revives, New Vulnerabilities Appear

• The expansion of US oil production is centered in a handful of states, and in particular two whose gains more than offset declines in two former production leaders.
• For various reasons the West Coast has missed out on this revival, straining infrastructure and creating new vulnerabilities that should be addressed.

On the front page of today's Wall St. Journal I see that "US Rises To No. 1 Energy Producer." This news builds on a number of recent headlines such as, "US oil production reaches highest level in 24 years." Stories like these aren't as attention-grabbing as they were when this streak began more than a year ago, once shale oil production ramped up dramatically.  What occurred to me this time, however, was how different the current distribution of US oil output is than it was in the late 1980s.

A handful of states still account for the lion's share of US oil production. Then and now, Texas tops the list, exceeding its 1989 output by 37%. At nearly 2.6 million barrels per day (MBD) in the most recent reported month --140% above at its low point in 2007--its share of US oil production had grown to around 35% by June. However, beneath Texas  the list of top oil states has been jumbled in ways few would have anticipated two decades ago.

Alaska, California and Louisiana, the second-, third- and fourth-ranked producers in 1989, then supplied 41% of total US crude oil output. After decades of decline, the same three states now contribute just 17%, excluding production from the federal waters off Louisiana's coast. Meanwhile, thanks to the development of the Bakken shale, North Dakota has jumped from the number  6 spot just five years ago to number two, eclipsing Alaska early in 2012.  Traditional mid-tier producers like Colorado, Oklahoma and New Mexico are also contributing to the overall US oil revival. This surge of highly productive drilling in roughly the middle third of the country, on top of a million-plus barrels per day from the Gulf of Mexico --mainly from deepwater rigs--has scrambled existing oil transportation arrangements.

When onshore production in Texas and the rest of the mid-Continent shrank in the 1990s and 2000s, the region's pipeline network gradually evolved into the country's principal oil-import conduit. The growth of production in the federal waters of the Gulf of Mexico, which had reached 1.6 MBD at the time of the Deepwater Horizon accident in 2010 but subsequently declined to about 1.2 MBD, meshed well with that model.

Today's big challenge goes against that grain: moving the growing surplus of oil in the upper plains states to markets on the West, Gulf and East Coasts, increasingly by rail. Much of the turbulence we've seen in the US oil market  in the last two years reflects the delays inherent in realigning and expanding that network to accommodate newly abundant domestic supplies.

Yet on the other side of the Rockies, the picture looks very different. When I was trading crude oil for Texaco's west coast refining system in the late 1980s, balancing the crude oil surplus on the Pacific coast required shipping multiple tankers a month of Alaskan North Slope oil to the Gulf, where production was shrinking, and prompted the construction of a new pipeline to send surplus oil to east Texas over land. After two decades of decline from mature fields, along with moratoria on tapping new offshore fields, imports now make up roughly half of west coast refinery supply, even though regional petroleum demand is essentially back to 1989 levels. It remains unclear whether and when California will allow producers to tap the state's potentially game-changing oil resources in the Monterey shale deposit.

Barring further change, the regional nature of these shifts means that the energy security benefits accompanying the revival of US oil production are a party to which the West Coast has not been invited, or has perhaps declined the invitation. That's significant, because it leaves residents of California, Oregon, Nevada and Washington much more exposed to any disruptions in global oil trade, since the existing US Strategic Petroleum Reserve was never intended to provide coverage west of the Rockies. In this light, the appetite of west coast refiners for trainloads of Bakken and Eagle Ford crude looks strategic, rather than just a temporary response to market conditions.

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

Would An Emissions Deal Break the Keystone XL Deadlock?

• A Canadian proposal to facilitate US approval of the Keystone XL pipeline by committing to greenhouse gas reductions gets to the essence of principled objections to the project.
• The offer provides a chance for defined, quantifiable emissions reductions, instead of the highly uncertain emissions consequences of rejecting the permit for this pipeline. 

A couple of weeks ago Bloomberg and others reported that the Canadian Prime Minister had sent a letter to President Obama, proposing to work with the US to reduce greenhouse gas emissions from the oil and gas sector as a way to facilitate US approval of the Keystone XL pipeline (KXL.) It seemed an obvious way to break the current deadlock . If opposition to the pipeline is based mainly on the greenhouse gas emissions profile of Canadian oil sands crude--accurately or not--then environmentalists should have welcomed this overture. Instead, environmental groups have urged the President to reject both the offer and the pipeline.

You would never know it from protest slogans conflating all types of air pollution as if they were identical, but the characteristics and effects of greenhouse gases (GHGs) like CO2 are very different from the smog-forming emissions from automobile tailpipes or the sulfate pollution from coal power plants. For that matter, air containing 400 ppm of CO2 (0.04%) is no more harmful to breathe than pre-industrial air with 280 ppm of CO2. More importantly, the climate consequences of each ton of CO2 emitted to the atmosphere are effectively the same as for every other ton, regardless of where they are emitted or from what source. While scientists can distinguish CO2 from fossil fuel combustion from the CO2 you just exhaled, based on differences in the ratio of carbon isotopes they carry, their effect on global warming is essentially identical.

That sounds trivial, yet it has great value for expanding our options for managing the accumulation of these gases in earth’s atmosphere. Not only don’t we have to treat GHGs the way we do local air pollutants, but it can be more effective not to. In practical terms, that means that unlike the well-established approaches for mitigating smog, it isn’t necessary to tackle all GHG emissions at the source, particularly when it’s expensive or impractical to do so. Saving a ton of CO2 by preventing deforestation or improving vehicle fuel economy is exactly equivalent in its effect on the climate to reducing a ton of CO2 emitted from producing oil, which accounts for less than 20% of the emissions from the oil value chain.

Prime Minister Harper’s proposal has been greeted with skepticism by some environmental groups, including a representative of Sierra Club Canada who expressed doubt that Mr. Harper was serious. I am in no position to comment on that, other than to point out that entering into negotiations on a proposal such as this one would be an excellent test of his government’s seriousness about reducing emissions.

In fact, a proposal to approve Keystone in exchange for reducing emissions provides a test of the seriousness of all the parties involved. If the project is worth pursuing for the Canadian government and Canada’s oil sands producers, then it should be worth additional efforts on their part, over and above those already undertaken, to reduce emissions from oil sands production and to find suitable emissions offsets elsewhere. Of course it’s also a test of how serious President Obama was when he  explicitly linked approval for KXL to “whether or not this is going to significantly contribute to carbon in our atmosphere.” And because the administration’s protracted delays in approving or rejecting the project can fairly be attributed to political considerations, the proposal also tests the seriousness of “movement” organizations like 350.org that influence the politics of Keystone within the President’s political base.

Opponents of the Keystone XL project who are genuinely concerned about addressing climate change ought to at least be willing to consider a framework that links approval of this project to quantifiable and verifiable reductions in greenhouse gas emissions on a comparable scale. Since the determination of such reductions depends on the assumptions governing the alternative state of the world against which these reductions would be compared, that would require a willingness to accept a reasonable set of baseline assumptions about what would happen if this pipeline were not permitted to cross the US border. While I don’t pretend that would be easy, I have trouble seeing how one could reject such a concept outright and still claim to adhere to sound science and consensus policies.

This strikes me as an opportunity to embrace the kind of constructive and responsible compromise, the absence of which in our government so many Americans have lamented. Or, to put it bluntly, is opposition to Keystone really about greenhouse gas emissions, or is it just about symbolism?

The beauty of this offer, if it has actually been made and depending on its details, is that it provides President Obama with a potential two-fer: a pathway for approving a project that would please a large majority of Americans, along with a way to obtain significant greenhouse gas reductions--also pleasing many Americans--without requiring the highly unlikely enactment by Congress of comprehensive climate legislation. If we can do a deal with Russia over Syrian chemical weapons, there should be no impediment to doing a deal with Canada over CO2 emissions.

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

How Falling Oil Imports Doubled the US Strategic Petroleum Reserve

• Falling oil imports have greatly expanded the capability of the US Strategic Petroleum Reserve to replace oil imports in a crisis, although prices would still rise.

• The SPR remains an imperfect backstop. Post-Syria, it is high time for Congress and the White House to address its gaps after four decades of change.

Last week's deal between the US and Russia defused the threat of an attack on Syria's military installations, along with the risks of unintended consequences for Mideast oil exports. However, we shouldn't lose sight of an important energy-related observation in the Wall St. Journal's “Heard on the Street” column as the crisis was peaking. It concerned the extraordinary degree to which reviving US oil production and weaker US energy demand have boosted the effectiveness of US oil inventories, including the US Strategic Petroleum Reserve (SPR).

Without adding a drop — the SPR actually shrank a bit in 2011 — the reserve’s potential to replace daily oil imports in a crisis has soared as those imports have declined. This could prove extremely helpful should the complex talks over securing Syria's chemical weapons break down, and the US and France proceed with missile or air strikes. Longer term, it serves as a further reminder that the existing SPR was designed for another era and is overdue for a major rethink.

Having 700 million barrels of oil available in federal facilities along the Gulf Coast has tempted presidents and other politicians, who saw opportunities to benefit from using it to attempt to crush periodic gasoline price spikes. However, the recent situation came much closer to the scenarios the SPR was intended to address when it was begun during the Ford administration, to provide a backstop for our vital energy supplies in emergencies involving the physical interruption of supply. When it comes to uses of the SPR, I’ve always been a purist, perhaps because I can recall sitting in gas lines and participating involuntarily in the bizarre “odd-even” rationing-by-license-plate scheme introduced during the oil crisis following the Iranian Revolution in 1979.

Here’s how the benefits of tapping the SPR in an actual crisis have improved, based on the rapid recent drop in US oil imports. In 2007, the SPR could have replaced just over half of our crude oil imports from countries other than Canada or Mexico for 165 days, at its maximum draw-down rate of 4.25 million barrels per day. With its current inventory and this year’s average crude oil imports through June running at around 7.6 million barrels per day, the SPR could substitute for 100% of our non-North American imports for 163 days. The value of such an insurance policy is rarely appreciated until it is needed.

Of course in practice the situation would be more complicated, mainly for reasons that support the case for rethinking the current 1970s-vintage reserve. One problem is that the oil stored in caverns near the Gulf of Mexico wouldn’t provide much immediate assistance for east coast refineries or for the West Coast, which has become increasingly dependent on imports as production in both Alaska and California declined steadily. Then there’s the issue of quality. Nearly 40% of the SPR oil is light and sweet (low in sulfur), while much of the oil we still import is heavy and sour (higher sulfur), to match the requirements of current refinery configurations. With production of light sweet crude in Texas and North Dakota booming, releasing sweet crude from the SPR could compound regional imbalances and possibly result in reduced refinery utilization. Any redesign of the SPR should take these important shifts into account.

Oil prices jumped just at the thought of a cruise missile attack on Syria, so it’s worth recalling what a back-up supply from the SPR can and can’t do. It can buffer the US economy from the impact of a serious interruption in the flow of crude oil cargoes from the Middle East or elsewhere, for some months. US refineries would continue to operate, as would the planes, trains, trucks and ships they fuel, and on which commerce depends. However, consumers wouldn’t be insulated from the price increases that would accompany any major disruption in Middle East oil exports, because the SPR oil must be auctioned to refiners at market prices. The resulting situation at gas stations might look a lot like price-gouging, with social media rapidly spreading outrage and conspiracy theories. The fallout from that could be disruptive, too, if somewhat less so than widespread fuel shortages and “out of gas” signs.

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.

Do Crude Oil Shipments Make Rail Less Safe?

• The movement of crude oil by rail is expanding rapidly but still represents a small fraction of the hazardous goods transported by rail in North America.
• The devastation caused by an oil train accident in Lac-Megantic, Quebec should galvanize railroads, shippers and regulators to improve rail safety for all hazardous freight. However, it does not justify banning oil-by-rail.

It’s been nearly two months since a train loaded with crude oil from North Dakota derailed and exploded in the Canadian town of Lac-Megantic, Quebec, killing an estimated 47 residents. In the interval since the accident, the relevant authorities have focused on ascertaining the cause of the accident and determining how best to improve rail safety. However, there has also been another, less-customary conversation about whether oil in general, and the specific oil on this train, might be too dangerous to transport by rail at all. That conversation would benefit from some context that appears to be absent.

Both conversations began with a tragedy in a place I recognized immediately. Ten years ago my wife and I passed through Lac-Megantic and drove along the Chaudière river that originates there, on its way to the St. Lawrence. It’s an area of natural beauty and historical significance. The images of destruction and of oil spilled in the river were gut-wrenching.

The investigation is still underway, but it seems significant that the Federal Railroad Administration (FRA) of the US Department of Transportation has already issued an Emergency Order banning the practice of leaving such trains unattended, pending the development of better procedures for securing them safely. Canadian authorities are reviewing their regulations and enforcement, as well as revisiting questions about the specific type of tank car in which the oil was carried. The Wall St. Journal reported that the FRA is also  looking into the testing and classification of crude oil shipments, to ensure that the tank cars used to transport different crude oils are suited to the task. Meanwhile, the rail operator involved in the accident has filed for bankruptcy on both sides of the border.

The second conversation, apparently based on a belief that it is possible to cease our use of petroleum entirely if we only have the will, is occurring in a fact vacuum. Understanding why that particular batch of crude oil was on that specific track on that day requires unpacking a nested set of factors that starts with the fact that oil still accounts for 33% of total global energy consumption, but more importantly supplies 93% of transportation energy. Numerous forecasts, including the latest from the US Department of Energy, anticipate no reduction in global oil use through 2040. Although we’ve displaced much of the oil formerly used to generate electricity and have greatly improved vehicle fuel efficiency, our most successful alternative transportation fuel, ethanol--no stranger to rail accidents--accounted for just 3% of US liquid fuel use last year, when adjusted for its lower energy content.

Although global oil movements are dominated by pipelines, tankers and barges, rail remains an important mode because of its flexibility. It’s also usually cheaper and more efficient than trucking for all but short distances--and safer, too, despite accidents like this one. Although the rapid recent growth of crude-oil-by-rail and its role in the Keystone XL pipeline debate have attracted significant attention, last year’s 234,000 tank-car loads of crude made up less than half of total US petroleum rail shipments and were dwarfed by over 1.5 million tank-car loads of chemicals hauled by rail in 2012.

Crude oil, especially light crudes like those produced from the Bakken and Eagle Ford shales, is flammable, and thus constitutes hazardous cargo. However, railroads routinely carry a wide variety of flammable and otherwise hazardous materials, including propane, gasoline, benzene, ethanol, chlorine gas, sulfuric acid and a range of other chemicals. Safety is not  determined by the cargo--if it was, none of these substances would be on trains--but by the combination of the equipment used to carry it, the rules and processes that dictate how to handle it, and the people who operate these systems. It’s no coincidence that these are the areas on which the investigations and preliminary regulatory responses have focused.

Then there are the market and logistical circumstances that resulted in a St. John, New Brunswick refinery that supplies both Canadian and US consumers and normally processes oil imported by tanker, acquiring oil produced in North Dakota and shipped halfway across the continent by rail. North American oil production is expanding rapidly, with significant economic and energy security benefits. Much of this new oil is found in places not adequately served by the large network of existing pipelines. That situation may eventually be rectified, but in the meantime the mismatch between growing landlocked oil supplies and limited pipeline outlets for them has created an opportunity for rail operators reeling from the much larger shale-gas-induced decline in coal shipments. Serving that need keeps people and trains employed. And that, ultimately, is why a train carrying Bakken crude was on a track in Lac-Megantic this July.

I can scarcely imagine what the survivors of the Lac-Megantic disaster and the families of the victims have been going through for the last two months. Their lives will never be the same. But whatever the cause of the accident is determined to have been--human error, mechanical failure, aging infrastructure or something else--it was not caused by the oil in those tank cars.

In the aftermath of an accident like this, the best thing we can do is to determine why it happened and apply those lessons to make rail transport of all hazardous cargoes safer.  Attempting to use the tragedy to advance a social cause such as “ending our reliance on oil” might be alluring to some, but the communities through which such freight travels in the course of keeping our economy running will benefit much more from the former course of action.

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