Fossil Fuels

Rising gasoline prices have a way of bringing out the hidden energy pundit in all of us. Most speculation tends to focus on why oil prices might be rising and on how high they might go. But a second strand of questioning is probably even more important: What do rising prices mean for the world? There’s a lot of wisdom that’s accumulated over the past few decades in attempts to answer that question. But I have to wonder whether there aren’t some fundamental changes that might render a lot of it obsolete. It’s always been difficult to pin down the economic impact of high oil prices for one simple reason: high prices and high economic growth tend to go hand in hand. Strong economies drive rising oil demand which in turn raises gasoline prices; even if that shaves off a bit of economic growth, the net outcome still looks positive. Think of it like wind resistance in a foot race: it slows you down, but it probably isn’t going to send you heading backwards. One of the main ways that economists have tried to cut through this complication is by distinguishing between high oil prices that result from demand spikes and ones that follow supply cuts. Demand driven oil shocks should be relatively benign. Supply driven ones, in contrast, should be far more devastating. For many observers, that explains why the 1970s oil shocks were so damaging, and why many subsequent ones were far less severe. I suspect, though, that something has changed in the world economy to throw a wrench in all of this. We now live in a world where U.S. economic health doesn’t drive global oil demand and prices the same way that it used to. Once upon a time, if the U.S. economy was flagging, the only way to generate a oil big price increase was to have a supply shock. That meant that oil spikes were rare in periods where the U.S. economy was shaky; for the most part, oil shocks hit when the U.S. economy was relatively strong, probably blunting their effects. But we now live in a multispeed world. Western economies can be on their knees, but oil demand can still be on the upswing due to healthy growth in China, India, and other emerging economies (not least those that also export oil). It’s become far more likely that we’ll have price spikes during periods where the U.S. economy is already weak. That makes historical precedent harder to go by. There’s another way to think about this. I mentioned that economists like to split oil spikes into ones driven by low supply and ones spurred by high demand. Casual analysis would put a price spike driven by economic growth in the developing world in the latter category. But what seems like a demand shock if you’re sitting in Shanghai looks a lot more like a supply shock if you live in San Francisco. Surging demand in the developing world takes barrels off the market in the same way that falling production in Iraq or Nigeria would. My guess is that these new “demand” shocks will hit the U.S. economy much more like supply shocks have in the past. That’s bad news. So is there anything the United States can do beyond getting its energy policy right? I’ll throw one idea out there: it could work on boosting export relationships with those countries that are driving economic growth. If an economic boom in the developing world rasies oil prices, and that slows the U.S. economy down, strong export relationships with the sources of that growth will tend to provide a countercyclical balance. There’s some evidence that Japan benefits from a similar sort of arrangement with oil exporters: the Japanese current account balance tends to improve, rather than weaken, when oil prices jump. Perhaps the United States could ultimately do the same?

Gasoline prices are the talk of the town right now. Lots of stories are circulating about where prices are on a historical basis and what this summer might bring. $4 a gallon? $5? Some have predicted even $6 a gallon. Wait, it gets better. You’d think you were at a horse auction the way analysts are talking these days. Here’s a quick graphical look at gasoline prices, to put things in perspective. First, good news for people who love bad news about gas prices (which includes environmentalists and Republican presidential candidates—strange bedfellows indeed): average retail gas prices in the United States are higher right now than they ever have been this time of year. That claim is absolutely true. Figure 1 shows where average U.S. gasoline prices have ranged between 1994 and 2011, according to the U.S. Energy Information Administration (EIA). Over that period, prices this time of year have gone as low as under $0.96 per gallon (in 1999) to as high as $3.19 per gallon (in 2011). This week’s $3.58 is a full 12 percent higher than the next highest year at this time, which occured exactly one year ago. Prices are more than $1 per gallon higher than median February prices between 2006 and 2011. Figure 1. U.S. Retail Gasoline Prices (Weekly Data, All Grades and All Formulations, EIA) What can U.S. consumers expect to pay at the pump this summer? Here’s a quick back-of-the-envelope calculation. If recent seasonal trends hold, prices would rise by around $0.50 per gallon between January and June. That would mean average U.S. gas prices of just over $4 per gallon this summer. So if history is any guide, $4 gasoline is not only possible this year, it’s probable. When it comes to gas prices, though, national averages don’t tell the whole story. Prices at the pump vary hugely depending on where you are in the country, for various reasons. Figure 2 shows retail gasoline prices in four U.S. cities: Los Angeles, New York, Denver, and Cleveland. The difference between what you pay in Los Angeles and Denver is staggering. The disparity has only gotten more pronounced the last few months. Kobe Bryant and the Lakers are dropping more than $4 per gallon to fill their tank, while the Birdman and the Denver Nuggets are paying just $3 or so. No wonder things are so bad in Lakerland right now. Figure 2. Retail Gasoline Prices in Four U.S. Cities (Weekly Data, All Grades, EIA) For average U.S. prices to reach $5 per gallon, let alone $6 or more, it would take a pretty serious disruption to the global oil market. Further supply losses in the Middle East could certainly take prices that high, but for now, I’d call that a tail risk: the chances it’ll happen are low, but there’s still a material chance. Tail risks in the oil market are exactly what Wall Street oil traders are bracing themselves for.  In the words of a Citi energy strategist, “We face a bifurcated market: a crisis in the Middle East could send prices through the roof; the eurozone debt problems could trigger a collapse.” The odds favor no major change one way or the other, but traders are assigning a higher-than-usual probability that prices could swing much higher or much lower in 2012. This isn’t the first time the media has been abuzz with reports that summertime gas prices might reach outrageous highs. Just last spring, people were saying the same thing, predicting $6 gasoline by the summer, only to see prices decline over the rest of the year. But as far as gasoline prices are concerned, 2012 has gotten off to a terrible start.

Some readers of my last post noted that the decline in oil consumption in the United States since 2007 caused the boom in fuel exports that the country has experienced. Is the export boom due solely to a decline in U.S. demand? Before getting into that, let’s take a step back and acknowledge that no one’s disputing the reality of the phenomenon itself: U.S. refined product exports have shot upwards in a remarkable way since 2005 or so. In hindsight, I think I might have undersold the economic magnitude of the trend. Fuel exports brought in an estimated $88 billion to the United States last year, which amounted to four percent of total U.S. exports by value. As a December AP article noted, “Measured in dollars, the nation is on pace this year to ship more gasoline, diesel, and jet fuel than any other single export, according to U.S. Census data going back to 1990.” It continued: “Just how big of a shift is this? A decade ago, fuel wasn’t even among the top 25 exports. And for the last five years, America’s top export was aircraft.” So soaring fuel exports weren’t even on the radar just ten years ago; now, they’re in the limelight. We can quibble about relative weight of the underlying drivers, but there’s little room to debate their outcome, which is economically notable in its own right. I’d still argue that the demand-side of the fuel export story is about relative demand growth (or shrinkage, in the case of the United States) in the United States and other neighboring countries, which is how I framed it in my last post. A drop in U.S. demand alone wouldn’t have caused the boom. I would agree with other analysts that, yes, the significant decline in U.S. refined product demand has been of paramount importance in moving the country toward net product exporter status—but without stronger demand growth elsewhere, the boom would not have occurred. Figure 1 leaves little doubt that U.S. product supplied (the EIA’s approximation of petroleum product consumption) has waned since the onset of the Great Recession in 2007. After climbing to 19.2 million barrels per day (mb/d) in the summer of 2005, it declined steeply into 2010, where it’s more or less plateaued around 17 mb/d (3-month average). Figure 1. U.S. Product Supplied of Finished Petroleum Products (Rolling 3-Month Average, January 1990–November 2011, EIA) A quick look at U.S. motor gasoline and distillate demand over the last five years shows the extent of the damage—and that demand is still severely impaired. As of the most recent EIA monthly data (November 2011), U.S. gasoline consumption is still shy of last year’s levels for this time of year, let alone those of 2007, which it trails by about 8 percent (Figure 2). High prices at the pump and a sluggish consumer economy have weighed on domestic gasoline demand. Figure 2. U.S. Finished Motor Gasoline Supplied (2007–2011, EIA) Domestic distillate demand (a type of oil product that includes diesel and heating oil) is in better shape, fluctuating around last year’s seasonal demand, but it’s only barely begun to touch 2007 levels (Figure 3). Figure 3. U.S. Distillate Supplied (2007–2011, EIA) But look what’s been happening at oil demand growth in two of the countries I mentioned in my last post, Mexico and Brazil, with ports proximate to the U.S. Gulf. In Mexico, demand rebounded to 2006 levels in no time after a taking a beating in late 2008 (Figure 4). Look at oil demand in Brazil (Figure 5), which is continuing to show robust growth. Demand there is a full 17 percent higher in the fourth quarter of 2011 than over the same period four years earlier. Figure 4. Oil Consumption in Mexico (2000-2011, IEA) Figure 5. Oil Consumption in Brazil (2000-2011, IEA) Consumption growth in these export markets is pulling volumes south from the U.S. Gulf Coast (and to a much lesser extent, East Coast), providing demand for U.S. refineries that are confronting stalled consumption at home. That substitute demand has buoyed profit margins for refiners in the southern United States enough for the boom in fuel exports to occur. The fact that refineries in the Gulf are adept at processing low-quality oil (heavy and high in sulfur) makes them a natural source for Venezuelan and Mexican crude, among others, which they’re now sending back south and elsewhere as processed fuel. So will the U.S. fuel export boom hold up in the future? Answering that question requires thinking through several ways in which oil supply and demand trends might shift in the coming years. The outlook depends in large measure on how you think the economies of the United States and Latin America will fare going forward and when you think American drivers will get back to their old ways. In the United States, gasoline prices, unemployment rates, and consumer spending growth will all factor into that calculation. Western Hemisphere refinery capacity additions and oil production growth will also likely matter. The United States remains the world’s biggest gasoline consumer, guzzling about nine times more than the next biggest, Japan. And it’s still a long way from being a net oil exporter. It may send fuel away, but it still imports a whopping net 9 mb/d of crude oil—more than twenty times the net amount of fuel it exports. But net U.S. crude imports, too, are on the decline for the first time since the 1980s—perhaps the topic for another post.

Joe Romm of the Center for American Progress and Joe Nocera of the New York Times have gotten into quite the fight over the Keystone XL pipeline -- and I seem to have gotten caught in the middle. Nocera’s Saturday column quotes me thusly: “The argument you hear is that because [Keystone XL] increases greenhouse gas emissions, we shouldn’t tolerate it.  Well, so do the lights in my house.  You have to be discriminating.” Here’s Romm’s response: “Seriously. That may be the lamest analogy in the history of energy and climate. Nocera is actually analogizing the GHG emissions increase from 900,000 barrels a day of dirty tar sands oil with flicking on the lights in your house!” Yes, seriously. Upon reflection, the analogy turns out to be even better than I previously thought. Let’s do some numbers. The GHG emissions increase from substituting 900,000 barrels a day of “dirty tar sands oil” for the typical barrel of oil consumed in the United States is, at most, about 20 million tons of carbon dioxide each year. This estimate is based on assuming a 15% increase in per-barrel emissions, which is the upper limit given by the expert that Romm cites; I’m setting aside the fact that we’re actually talking about less than 900,000 barrels, since part of what would be carried isn’t bitumen, but rather lower-carbon dilluent. On the other hand, residential lighting generated (PDF) 137 million metric tons of carbon dioxide emissions for the United States in 2008. So yes, flicking on the lights in our houses is actually a lot worse for the climate than substituting “dirty tar sands oil” into the energy mix. (Side note: If you believe that the circa 900,000 barrels would not back out any other oil – something that, to be blunt, is totally implausible – then the maximum emissions increase from adding that oil works out to about the same as the annual emissions from U.S. residential lighting.) Does that mean that we should prohibit people from turning on their lights? Of course not – that was my point. Even the most anti-economist types implicitly weigh costs and benefits all the time when they think about what constitutes wise climate action. None of them advocate going to a lightless society, because the costs would clearly outweigh the benefits. So it isn’t enough to just say “there’s a ton of carbon there” in order to argue that we shouldn’t do something. You can do that with way to many things – including, yes, turning on your lights. As I told Nocera, we need to be discriminating: there are big pools of carbon that are worth burning, and there are big pools of carbon that aren’t. Well meaning people can disagree as to whether 900,000 barrels a day of tar sands oil falls in the former category or the latter one. The mere fact that the pool in question is big isn’t enough alone to place it off limits.

A forthcoming paper in the influential Journal of Geophysical Research has measured concentrations of methane and other alkanes in air near oil and gas operations in Weld County, Colorado, and has used that to infer rates of methane leakage from natural gas production in the region. Their results, which were reported last week by Nature and the Associated Press, point to much higher methane emissions than consensus inventories have previously found. Indeed some have read the results as confirming the highly controversial estimates of methane leakage published last year by Cornell professor Robert Howarth and his colleagues. The new study is far more sophisticated and careful than what’s been published so far. It deserves serious attention. But after several days of working through the data and analysis, I’m skeptical of some of the results and interpretations. That doesn’t mean that I think that the paper is wrong – it’s premature to say that – but, given the attention it’s been getting, I think it’s worth putting some of the potential problems out in public. One note before I dive in: Some of my observations may seem a bit oblique. Recent experience has started to convince me that, when there’s a problem with peer-reviewed scientific work, it’s important to correct the formal scientific record, rather than just responding on the web. Alas, many scientific journals have bars on publishing material that’s already been made public elsewhere. In this case, I may end up submitting a technical “Comment” to JGR, so I’m going to have to be careful not to preempt myself here. I apologize to readers for whom that makes this post difficult to evaluate. Now on to the four issues that I want to flag. The first two have to do with the paper itself; the second two are problems with how it’s being interpreted. Assumptions about the composition of leaked gas. The authors need to make some assumptions about the ratio of methane to propane in vented gas in order to do their analysis. They do that in three different ways in order to bracket uncertainty. There’s no reason, however, to assume that their three cases bracket the range of reasonable possibilities. Alas, it turns out that their results are highly sensitive to the choice of ratio. If, for example, the methane-to-propane ratio in vented gas is a lot higher that in any of their three candidates, the implied rate of methane leakage is much lower than what they estimate. If, on the other hand, the methane-to-propane ratio in vented gas is lower than in any of their three candidates, the implied rate of methane leakage is even higher than their alarming estimates. This, to me, is the biggest problem in the paper, and introduces a lot of uncertainty around the results. Are we really talking about gas wells? The paper presents its final results as if it’s found out that there’s a lot of leakage from natural gas production. But a large fraction of the wells it uses to come up with chemical profiles for vented gas aren’t gas wells. In particular, the sorts of methane-to-propane ratios that it uses aren’t actually representative of gas wells – they’re representative of condensate (basically oil) wells with significant amounts of associated gas. In won’t get into the weeds here, but when I rework the numbers, I come to one of two conclusions: there’s a lot of methane leakage in the area they’ve studied, and it’s coming from condensate wells, or there isn’t much methane leakage there, but it’s coming from gas wells. Why isn’t this just nitpicking? Because people are already taking the paper and trying to extrapolate it to genuine gas wells in places like Pennsylvania. It’s far from clear, though, that one can do that, if we aren’t actually talking about gas wells in the first place. A peculiar spin on uncertainty. The paper presents several different estimates of methane leakage (based on different methodologies) all with clearly reported uncertainties. Reporting has emphasized the full range of possibilities. But the range over which the different estimates overlap is actually pretty small, and it is close to the lowest, and least alarming, possible methane leak rates. It’s not clear to me why the upshot of this paper (setting aside the other issues I’ve flagged) isn’t that leakage rates are probably in this lowish area. To understand why I’m puzzled, let me sketch an analogous example. Through decades of work, we know that the mass of the neutron is about 1.67E-27 kg. Now let’s say that I come up with a new experiment that shows that the mass of the neutron is between 1.5E-27 kg and 3.34E-27 kg. No one should write an article declaring “Mass of Neutron May Be Twice Previously Agreed Level”. They should look at my work and say: “Given that other methods peg the mass of the neutron at 1.67E-27 kg, and this new experiment is consistent with that, we should probably stick to what we know”. They should chalk the upper end of my experiment’s range up to the fact that my experimental method happens to be imprecise. The same is true for this paper. Just because one approach in the paper can’t chop uncertainty down doesn’t mean that methane emissions might be stratospheric – it means that you should juxtapose that approach with other ones in order to narrow down the range of possibilities. Apples, oranges, and the Howarth study. The authors of the JGR paper report a “best guess” estimate that 4% of Weld County gas production is leaked. Howath tells Nature, “I’m not looking for vindication here, but [the JGR] numbers are coming in very close to ours, maybe a little higher”. Indeed the similarily between the JGR and Howarth numbers is one of the main reasons that the JGR paper has attracted attention. But this comparison doesn’t work. In Howarth’s percentage calculation, the denominator is expected gas production from wells drilled during the period under study; in the JGR paper, that denominator is gas production during the period under study itself. These are different numbers, which means we’re talking about different ratios. Bottom line? There’s a lot of fantastic observational data in the JGR paper. I suspect that there’s more that can be done with it to shed light on methane leakage. For now, though, I’m not ready to rely on its results.

Before I launch into the post, I thought it might be good for me to introduce myself to you readers, since I’m going to be blogging pretty regularly in the coming months. I joined CFR last October as a fellow for energy and national security as part of a larger Sloan Foundation-funded initiative, the Program on Energy and National Security. I’m delighted to be a part of the CFR and am looking forward to working on this new energy program. Before coming to CFR, I spent some time in academia and in financial services. On the academic side, I studied economics and finance at the University of Chicago, Cambridge, and Oxford. I did a bit of teaching in those areas at Oxford, which was fun (hopefully my students would say the same). While at Oxford, I spent some time working with the late Matthew Simmons, of Simmons & Co. Intl. (and a terrific guy, I might add), on private equity and non-profit ventures he was putting together in 2009–2010. Just before joining CFR, I headed up oil research at Louis Capital Markets in New York. So that’s me. In terms of the blog, I’m planning on focusing mostly on the economic, political, and financial aspects of oil and natural gas. I’ll venture a little further afield from time to time into financial markets or the broader economy. I’m going to make charts and graphs a feature of my posts, since they’re a great way to capture trends and relationships and don’t take long to digest. Today’s topic: a hidden U.S. export boom. There’s starting to be more and more coverage in the mainstream media, but I still wonder whether it’s sunk in to most Americans just how historic the changes going on right now in oil production in the United States really are. Last year, for the first time since the U.S. Energy Information Administration (EIA) began comprehensive data (in 1993), annual U.S. crude exports of petroleum products exceeded imports in 2011 (see Figure 1). Figure 1. U.S. Net Imports of Petroleum Products (1993–2011) U.S. refineries sent away an average of 380 thousand barrels per day (kb/d), on a net basis, last year. That is a steep and remarkable drop from years past. In October 2005, net imports were just shy of 4.0 million barrels per day (mb/d). The trend is even more remarkable in individual product categories, for which U.S. Department of Energy data extend back to 1945 (Figure 2). Unlike total U.S. net import data, data for the two major refined products, motor gasoline and distillates (a category that includes diesel and heating oil), are available reaching back to the end of World War II. The last time the United States was a consistent net importer of finished gasoline was in 1959. Net distillate imports oscillated between positive and negative territory during the early 1990s, but the United States hasn’t consistently imported diesel and other distillates since the 1950s. Figure 2. U.S. Net Imports of Finished Motor Gasoline (left) and Distillates (right) (1945–2011)   Where has the oil been going? Mexico and Brazil have become two major customers, among others (Figure 3). As of November 2011, net exports of petroleum products to Mexico had risen to nearly 600 kb/d, a record level, while the net flow to Brazil was a volatile 137 kb/d.       Figure 3. U.S. Net Imports of Refined Products from Mexico (left) and Brazil (right) (2004–2011)   An equally dramatic story has been playing out in the flow of products to and from OPEC member countries (Figure 4). Just 5 years ago, OPEC sent 1.0 mb/d (net) to the United States. That quantity has fallen markedly. Net imports from OPEC are still positive, but not by much—a paltry 230 kb/d on average since 2010. Figure 4. U.S. Net Imports of Refined Products from OPEC Members (2004–2011) U.S. exports of petroleum products are booming (Figure 5). After remaining stagnant between 750 kb/d and 1.0 mb/d between 1990 and 2005, exports began to explode higher. The trend is still in its early stages. I don’t think it’s one that will live and die based on how fast the U.S. economy recovers—Figure 5 clearly shows that exports were moving higher before the Great Recession began in 2007, though the slowdown in the U.S. appears to have catalyzed the boom. Figure 5. U.S. Exports of Finished Petroleum Products (1981–2011) So what’s behind the trend? I’d point to four forces. First, North American oil production gains have reduced the country’s reliance on imported oil—not just products, but crude as well—as more oil came from Canadian and U.S. sources. Second, economic growth in Central and South America that outpaces that of the United States is leading to quicker fuel consumption growth in these markets, which is pulling additional volumes south of the border. Third, geographic proximity and highly efficient refining capacity in the Gulf of Mexico means that growing oil streams, from Canadian heavy to U.S. unconventional, are being sent to the Gulf, from which refined products are then sent outward. Fourth, U.S. law mandating the use of ethanol as a gasoline additive has reduced domestic demand for conventional gasoline and boosted supply. I wouldn’t bet against the export boom in the coming decades, either. I don’t think it’s a flash-in-the-pan phenomenon. I agree with forecasts that see Canadian heavy crude production, at 1.1 mb/d in 2005, coming close to tripling by 2015, while U.S. shale oil production could swell to 3.0 or so mb/d by 2020. The Gulf Coast remains the obvious refining outlet for these liquids. Although the pace of fuel demand growth in the United States may come close to returning to pre-recession levels if the European crisis passes, it will likely increase even more rapidly in Brazil and elsewhere in Latin America. Economic growth in Latin American and the Caribbean should on average be significantly faster than in the United States in the coming years. The IMF sees the growth differential narrowing from 3.1 percentage points in 2009 to 1.7 in 2013, but that’s still a wide margin. The implications of the trend for the economy and policy? More on that later. But for now, a remarkable boom that highlights just how quickly things are changing on the American energy scene—to the benefit of the United States.  

Most analysts are incredibly bullish about the prospects of shale gas production in the United States. An early preview of the annual U.S. government energy projections, released last month, sees U.S. gas production rising steadily for decades. Petrochemicals producers are building new plants, and other industrialists are conjuring schemes for exporting the fuel. Security hawks dream of compressing the gas and putting it into cars and trucks so that the United States can use less oil. Some environmentalists are relieved that gas will back out coal and thus cut carbon emissions. But what if we’re wrong? I’m not saying that I buy the various arguments out there that claim to show that shale gas reserves are grossly overstated or that shale gas economics is a crock. But energy is an uncertain space that regularly hands out surprises (like, um, shale gas). Relatively immature areas like unconventional gas deserve special care. Moreover, even if the economics of shale gas hold up, public opposition to drilling could curtail supplies. There’s one natural response to this possibility: So what? Private investors are risking their money on shale gas production. Private landowners are leasing their properties. Private chemicals firms are building facilities that depend on abundant supplies of cheap gas. Yes, if the natural gas glut turns out to be less than advertised, they’ll lose money. But investors lose money all the time. There doesn’t seem to be much reason that policymakers should care. That’s true up to a point. But there are several areas where wrong projections could, in principle, have troubling public consequences: Power Plant Regulation. Policymakers are currently considering a range of regulations aimed at reducing pollution from coal fired power plants. These rules, aimed in particular at curbing greenhouse gas emissions, are typically crafted with the aim of ensuring that their benefits exceed their costs. But their estimated costs depend on the alternatives available. In particular, abundant gas makes stringent regulations look less expensive, and hence makes them more likely to be adopted. What happens, though, if that gas turns out to be a mirage? Aggressive regulations based on an expectation of cheap gas could drive coal fired power plants to shut down early; gas plants would take their place; if gas supplies then fell, people would be stuck with expensive gas, since they’d have gotten rid of the immediate alternatives. Some may think that this is still a good outcome – after all, aren’t coal plants dirty? – but, at a minimum, it’s one that should be reached deliberately, not by mistake. Moreover, depending on the details, there’s probably a case for arguing that it’s an outcome we want to avoid. Natural Gas Exports. Several firms have recently applied for permits to export natural gas. Some people worry that the combination of exports and domestic production shortfalls could be economically devastating. My instinct says that this danger is overstated. If U.S. gas production doesn’t meet expectations, domestic prices will rise, and exports will become less economically attractive. To be certain, preexisting export facilities involve sunk costs and thus will have their own momentum, but scary economics are still hard to line up. The capital costs of a liquefaction facility work out to be a bit less than a dollar as much as $1.50 per thousand cubic feet of natural gas. So long as export contracts are closely linked to U.S. gas prices – the U.S. government should probably insist on this – economics should prevail.  As a result, except in a narrow set of circumstances (i.e. that one sunk dollar or so tips the balance between keeping gas at home and exporting it), the fact that export facilities already exist won’t have much impact on whether gas is used at home or sent abroad. After all, the fact that import facilities already exist hasn’t made anyone ship gas to the United States against their economic interests. Large Capital Investments. One might worry, in a similar vein, that people will overbuild gas-using equipment (such as chemicals plants) only to later find gas supplies scarce. If that equipment is expensive, and gas remains a relatively small part of its owners’ costs, then those owners will presumably continue demanding gas despite rising prices. This will leave less fuel for others – and hence those others will face higher prices. This all makes sense, but with a big caveat. We’re talking about enterprises in which gas would remain a relatively small part of costs even given rising prices. (That’s why they won’t shut down.) These are generally not the sorts of enterprises that will get created in response to low gas prices in the first place. As with export terminals, there might be a sweet spot in which sunk costs create their own momentum, but that sweet spot is probably small. Renewable Energy Development. Low natural gas prices are apparently deterring deployment of renewable and nuclear energy, and hence learning and innovation in those sectors. This is a problem regardless of whether gas is scarce or abundant, since reasonably ambitious climate policies will require sequestration of carbon dioxide (including from gas use) or a strong shift to renewable and nuclear power within a couple decades or so. But it is an even bigger problem if natural gas supplies turn out to underwhelm, since in that case, the need to shift to zero-carbon sources would become even more pressing and sudden. This simply reinforces the case for ensuring that prudent deployment of and innovation in zero carbon energy receives solid public support even if the market currently prefers natural gas. Crosscutting Lessons. There are two big bottom lines to this whole analysis. First, the biggest public risks associated with overestimating natural gas potential appear to arise when governments get involved. If private players bet their money on the prospect of cheap gas, they’re the ones who will lose if they turn out to be wrong, but if government creates regulations based on similar assumptions, the public is more likely to end up on the losing end. In the climate space, that’s yet another reason why carbon pricing is so much smarter than rigid regulation – it doesn’t require nearly as much in the way of assumptions. Second, cheap natural gas probably introduces bigger risks when it leads people and firms to foreclose options than when it leads them to expand choices. Policies that shutter existing power plants, or economic incentives that retard energy innovation, introduce bigger public risks than policies that allow new export facilities, or economic incentives that lead people to build petrochemicals plants. Policymakers certainly shouldn’t make policy based on an expectation that the shale boom will turn into a bust. But that doesn’t mean that they should ignore real risks. It would be wise to keep the consequences of being wrong in mind as they move forward.

Wall Street has been busy thinking through what might happen to oil prices (and the global economy) if conditions worsen in the Strait of Hormuz. Various scenarios could unfold, from mild to dire. But an equally important question has escaped similar close scrutiny: What options would policymakers in the U.S. and other IEA member countries have to confront a massive disruption to oil supply in the Persian Gulf, and how should they select from among them? A new Energy Brief from CFR’s Project on Energy and National Security addresses those questions. Written by Bob McNally, the president of Rapidan Group and a former White House senior energy advisor, the article presents four oil market scenarios that might develop in a confrontation with Iran and assesses the options that policymakers would have for mitigating any adverse oil market consequences. McNally sees five major policy options, which are not mutually exclusive and each only a highly imperfect substitute for a well-functioning market: -Allow supply losses to be absorbed by demand destruction resulting from an oil price spike. -Accept a drawdown from private consuming country (OECD) stocks. -Encourage OPEC to increase production that does not flow through Hormuz. -Put in place production surge and demand restraint measures in IEA countries. -Coordinate a drawdown of IEA strategic inventories (SPRs). These options differ sharply in mechanism, feasibility for Washington to impose unilaterally, and likely effectiveness in keeping a lid on oil prices. The first one doesn’t require any action at all, but could have catastrophic consequences for the global economy if the disruption proved long and severe. Last year’s drop off in Libyan oil exports was a reminder that while geopolitical interruptions to the smooth functioning of the market can materialize in a number of ways, OECD policymakers face a limited menu of options when oil comes off the market unexpectedly. Still, even their blunt tools for managing the market, skillfully applied, can considerably lessen the economic damage of a supply rupture.

If analysts and reporters know one thing about sanctions, it’s that if you don’t have complete international cooperation, they don’t work. That instinct has been on full display in recent discussions of oil market sanctions targeted at the Iranian nuclear program. Yes, the United States and Europe might refrain from buying Iranian oil, but so long as China and India are willing to buy the surplus crude, won’t the sanctions be toothless? Some recent research that has been shaping policy discussions suggests that that’s the wrong way to look at the problem. As buyers disappear from the market for Iranian oil, those that remain gain a stronger bargaining position, potentially allowing them to extract large discounts. That is not as effective as a complete cutoff in choking off Iranian oil revenues, but it does get you part of the way. It’s important to recognize that this dynamic is highly nonlinear: it is at its most pronounced as the number of potential buyers gets closer to one. In particular, discounts might become much deeper if India exited the market than if both it and China remained. It’s also worth noting that the decision to extract big discounts would ultimately be a political one: if Beijing decided that it did not want to crank up pressure on Tehran, it could instruct Chinese buyers to pay world prices (or close to that) for Iranian oil. There’s also something more subtle going on. If all Iranian crude suddenly vanished from the world market, the impact on oil prices could be huge. That possibility would deter policymakers from pursuing sanctions in the first place. The existence of China and India as alternative markets for Iran is what assuages policymakers’ fears and lets them pursue sanctions to start with. That dynamic is critical. It makes no sense to compare partial sanctions that are flouted by China and India with airtight sanctions that have no chance of existing. The fact that one or two big countries won’t go along with oil sanctions is precisely what makes those sanctions politically possible. Sanctions that are flouted by China and India are better – and potentially quite a bit better – than no sanctions at all. Until we try them, of course, we won’t know how much the sanctions will bite. For now, though, we know enough to try.

I made a New Year’s resolution to spend less time on this blog explaining why other people are wrong. But New Year’s resolutions are meant to be broken -- and some things just beg for intervention. That’s unfortunately the case with “Oil’s Tipping Point Has Passed”, an essay in the current issue of Nature by James Murray, an oceanographer at the University of Washington, and David King, a chemist who was chief scientific advisor to Tony Blair and now heads the Smith School of Enterprise and the Environment at Oxford. The authors write that “there is a potentially more persuasive argument [than the danger of climate change] for lowering emissions: the impact of dwindling oil supplies on the economy”, and then go on at length to explain why. Their bottom line may be correct – there is certainly much to debate here – but their many arguments are almost invariably flimsy. I want to step through a fairly long list of those claims, both because the article is prominent and likely to be read as authoritative, and because the article provides a convenient and fairly exhaustive compendium of misunderstandings about oil. The paper begins with a summary before getting into the main substance: “The idea of ‘peak oil’ — that global production will reach a peak and then decline — has been around for decades, with academics arguing about whether this peak has already passed or is yet to come. The typical industry response is to point to increasing assessments of global reserves — the amount known to be in the ground that can be produced commercially. But this is misleading. The true volume of proven global reserves is clouded by secrecy; forecasts by state oil companies are not audited and seem to be exaggerated.” Perhaps reserves are exaggerated. Perhaps they aren’t. What do the authors cite to support their position? A recent paper by none other than David King. In any case, the essay immediately goes on to more important things: “More importantly, reserves often take 6–10 years to drill and develop before they become part of supply, by which time older fields have become depleted. It is far more sensible to look instead at actual production records, which are less encouraging. Even while reserves are apparently increasing, the percentage available for production is going down. In the United States, for example, production as a percentage of reserves has steadily decreased from 9% in 1980 to 6% today. Production at existing oil fields around the world is declining at rates of about 4.5% (ref. 4) to 6.7% per year. Only by adding in production from new wells is overall global production holding steady.” Little of this makes much sense. Yes, it takes time to convert reserves to production, during which time other fields have declined. Oil producers know that and incorporate it into their planning. The authors seem to suggest that because new investments accompany declines, absolute production increases aren’t possible. That’s silly: just because I draw on my bank account while also earning money doesn’t mean that I won’t become richer. Nor is the fact that production as a percentage of reserves has declined over time a good argument in favor of the claim that we’ve hit a limit to production. Think about it: if a technological breakthrough doubled our reserves tomorrow, the reserve-to-production production-to-reserve ratio would be sliced in half; does anyone seriously think that this would be bad news for oil? Let’s continue: “In 2005, global production of regular crude oil reached about 72 million barrels per day. From then on, production capacity seems to have hit a ceiling at 75 million bar­rels per day. A plot of prices against produc­tion from 1998 to today shows this dramatic transition, from a time when supply could respond elastically to rising prices caused by increased demand, to when it could not (see ‘Phase shift’). As a result, prices swing wildly in response to small changes in demand. Other people have remarked on this step change in the economics of oil around the year 2005, but the point needs to be lodged more firmly in the minds of policy-makers.” Start with something simple: the authors seem to have misread their reference, which reports nearly 82 mb/d of conventional oil production as of 2008 (and another 3.9 mb/d of unconventional production). [UPDATE: A commenter points out correctly that the authors were referring to a narrow set of sources than I did. I think that it’s misleading to segment production in that way, but if ones chooses to do so, the 72/75 numbers hold up.] More problematic, though, is the implicit claim that this is strictly about “economics”. One would not know from this discussion that a large fraction of world oil is produced in states that exercise strategic restraint in their production. It is entirely possible that politics is a much bigger factor than pure economics in explaining what has happened in recent years. The authors then pivot to explaining why they think it will be difficult to expand production: “We are not running out of oil, but we are running out of oil that can be produced eas­ily and cheaply. The US Energy Information Administration optimistically projects a 30% increase in oil production between now and 2030 (ref. 2). All of that increase is in the form of unidentified projects — in other words, oil yet to be discovered.” This simply isn’t true. Unidentified projects don’t involve oil that is “yet to be discovered” – they involve oil that has not been specifically targeted for extraction. In fact, as best I understand, all of the production increase that EIA anticipates comes from oil that has already been discovered. Moreover, not all of it comes from unidentified projects. Indeed the authors seem to acknowledge that just a bit: “Non-conventional oil won’t make up the difference. Production of oil derived from Canada’s tar sands — sometimes called the ‘oil junkie’s last fix’ — is expected to reach just 4.7 million barrels per day by 2035 (ref. 6). Production from Venezuela’s tar sands is currently less than 2 million barrels per day7, with little prospect of a dramatic increase.” That’s right, but it’s beside the point. Among the authors’ apparent blind spots are offshore drilling and tight oil in the Americas and beyond; the potential for increased production in Iraq as security improves; and the possibility of higher Saudi output. None of this gets mentioned in the essay. None of it, of course, shows that oil production will be sufficient going forward, but the argument in the paper falls woefully short of demonstrating the opposite. What about resources other than oil? Here’s how the authors deal with that: “Many believe that coal will be the solution to our energy needs, and will stay cheap for decades. But several recent studies suggest that available coal is less abundant than has been assumed. US coal production peaked in 2002, and world coal-energy production is projected to peak as early as 2025 (ref. 8)…. The US National Research Council’s Committee on Coal Research, Technology, and Resource Assess­ments to Inform Energy Policy noted in 2007 that ‘present estimates of coal reserves are based upon methods that have not been reviewed or revised since their inception in 1974 … updated methods indicate that only a small fraction of previously estimated reserves are actually mineable reserves.’” Let’s start by getting the fact straight again. Yes, U.S. coal production peaked around 2002 (actually in 2001); then, in 2003, it reversed course again and started heading back up. Coal production in 2005, 2006, 2007, and 2008 exceeded 2001 and 2002 levels. More important, production is a function not only of supply but demand. Coal production in the United States has been restrained not because it’s scarce but because it’s increasingly undesireable. What about the observation that “only a small fraction of previously estimated reserves are actually mineable reserves”? It’s important to put that in context. Previous estimates of coal reserves are astronomical. The mere fact that they have been revised downward tells us essentially nothing about whether the world has enough coal. And then there’s natural gas: “Natural gas is still abundant and large discoveries have been made recently, notably in Israel and Mozambique last year. Power plants using natural gas provide 25%, and rising, of electricity generation in the United States. Production of conventional natural gas in North America peaked in 2001 (ref. 2), but energy companies have worked hard to promote the idea that hydraulic fracturing of shale rock will lead to ‘the age of natural gas’. There is no doubt that US shale-gas resources are immense, but recent reports suggest that both reserves and future production rates have been substantially overstated….” It’s not clear what the authors’ point is here. On the one hand, they cite some of the biggest pessimists in the natural gas world; on the other, they talk about “immense” resources. In any case, the bigger question mark for the purposes of their essay would seem to be whether natural gas can penetrate the transport sector in a big enough way to dent demand for oil. (I happen to be slightly skeptical.) The essay, though, is silent on that count. Having tried to make their case for an inevitable oil shortage, the authors turn to consequences: “What does this mean for the global economy, which is so closely tied to physical resources? Of the 11 recessions in the United States since the Second World War, 10, including the most recent, were preceded by a spike in oil prices. It seems clear that it wasn’t just the ‘credit crunch’ that triggered the 2008 recession, but the rarely-talked-about ‘oil-price crunch’ as well. High energy prices erode family budgets and act as a head wind against economic recovery.” Any scientist knows that correlation and causation are different things. The authors cite a serious paper that claims that expensive oil helped bring the 2008 recession forward by a few months, but don’t have any backup (aside from the fact that it “seems clear” to them) for their claim that pricy crude actually “triggered” it. Instead, they turn to anecdotes: “Another powerful example of the effect of increasing oil prices can be seen in Italy. In 1999, when Italy adopted the euro, the coun­try’s annual trade surplus was $22 billion. Since then, Italy’s trade balance has altered dramatically and the country now has a deficit of $36 billion. Although this shift has many causes, including the rise of imports from China, the increase in oil price was the most important. Despite a decrease in imports of 388,000 barrels per day compared with 1999, Italy now spends about $55 billion a year on imported oil, up from $12 billion in 1999. That difference is close to the current annual trade deficit. The price of oil is likely to have been a large contributor to the euro crisis in southern Europe, where countries are completely dependent on foreign oil.” This is mostly the subject for a future post, but I’ll just point out for now that oil imports have little or no power to predict current account deficits. Both Germany and China, for example, import a lot of oil, yet they have not run current account deficits in recent years. The Italy example is nothing more than cherry picking. As for the claim about the euro crisis, one would presumably need to explain why others with big import bills haven’t been similarly affected in order to conclude as the authors do. They make no attempt to do that, but they do have a bottom line: “Historically, there has been a tight link between oil production and global economic growth. If oil production can’t grow, the implication is that the economy can’t grow either.” Once again, correlation and causation are different things. The U.S. economy, for example, has grown much faster than its oil consumption has. Europe has grown while its oil consumption has remained flat. Could limits to oil production restrain economic growth? Sure. But the case is far less clear cut than the essay suggests. The rest of the Nature article gets into solutions, most of which are eminently sensible, even if one doesn’t buy the authors’ description of the problem. I won’t get into them here, since that’s not the point of this post. But I want to finish with a broad observation. When opponents of action to deal with climate change rest their case on weak and logically unsound arguments, they are rightly assailed by serious scientists – including, quite often, the authors of the present essay. When these same climate experts cross over into talking about oil, it would behoove them to write with the same rigor that they demand of their adversaries elsewhere.

The EIA released a new study last week that attempts to quantify the market impacts of increased natural gas exports from the United States. It’s a useful and informative piece of work, but it also has some important limitations. I want to sort through a couple of those here. The headline from the report is straightforward and in some ways troubling: exports could raise U.S. natural gas prices by as much as 36% over what they would otherwise be. This figure, which has naturally grabbed attention, is for a scenario where exports are ramped up quickly, starting in 2014, to high levels. There are at least two problems, though, with this estimate. The first is practical: this scenario is unlikely to materialize. This is not a flaw in the analysis, since the EIA was studying different scenarios, but it is a problem when it comes to how the report has been received. The second problem, though, is deeper. If you look at the estimated price response that the EIA reports, you’ll notice that prices stay low until the day that exports begin, at which point they jump. This is a sign that the model is not allowing market players to anticipate the increase in exports. If they were able to do that, prices would start to rise before the exports began, as people put gas into storage in anticipation of future opportunities to make money selling it later. That same foresight would also deter early overinvestment in natural gas dependent infrastructure. Both of these dynamics would lessen the ultimate price impact of exports. How much is unclear, but the answer isn’t zero, contrary to the impression left by the study. The other striking finding is that most exports will be balanced primarily by increased production rather than decreased domestic consumption, and that whatever decline in domestic gas consumption happens will come primarily at the expense of gas use in the power sector. This is, in one way, quite worrying, since coal will likely fill most of the gap; on the other hand, if the exported gas displaces coal use overseas, the net climate impact could be a wash. There’s also another dimension, which the report flags as a weakness, that’s understudied: we still don’t know the real impact of exports on availability of feedstock for the chemicals industry. It is actually plausible that ethane availability to domestic petrochemicals firms (ethane is a critical feedstock) could rise, as exports incentivized greater gas production, but some of the ethane was stripped out before the gas was exported. On the other hand, if enough of the ethane is left in the gas at the time of export, domestic manufacturers could suffer. I suspect the net effect either way is small, but it any case, it’s something we should be able to get better purchase on through further study.