Fossil Fuels

This past December, Mexico passed a historic energy reform that has the potential to fundamentally transform the country’s oil, gas, and electricity sectors. In this brief that I co-authored with James Taylor, founding partner at Vianovo, we lay out the importance of the soon-to-be-announced secondary legislation, provide an outline of the newly formed regulatory regime, and explore the types of opportunities that the reform will create. Mexico is the world’s 9th largest producer of oil and the third-largest in the Western Hemisphere (behind the United States and Canada and ahead of Venezuela). It has vast untapped shale oil reserves, estimated to be the 5th largest in the world, according to the U.S. Energy Information Administration. As the third largest supplier of crude oil to the United States (after Canada and Saudi Arabia), Mexico accounts for roughly 12 percent of its northern neighbor’s total imports. The lion’s share of Mexico’s crude oil exports (85 percent) head to the United States—all supplied via tanker, as Mexico does not have international oil pipeline connections. While Mexico has immense oil and natural gas supplies, it has been on a decade-long track toward becoming a net energy importer. Oil production has been steadily declining, falling by 1 million barrels per day since 2004. With limited domestic refining capability and strong demand, the country is already a net importer of refined petroleum products, such as lighter grade gasoline and diesel. And in natural gas, Mexico’s growing consumption needs (for power generation and to meet industry demand) outstrip its productive capacity, leaving the country as a net importer of the fuel. Mexico’s main supplier of natural gas is the United States, with imports arriving both as liquefied natural gas (LNG) and via an integrated and growing network of cross-border natural gas pipelines. You can read the rest of the brief here.

As the standoff between Russia and Ukraine drags on, there are increasing calls to use U.S. oil and gas exports to weaken Vladimir Putin’s hand. There’s something to this, but it’s likely to be a lot less powerful than most pundits seem to think. Europe imports about thirty percent of its natural gas from Russia. Russia could, in principle, cut off some or all of that supply. That prospect presumably makes European leaders less willing to take strong positions against Russia in its confrontation with Ukraine. People have argued that boosting U.S. natural gas export capacity (or, more precisely, changing policy to make that more likely in the future) could do two things. First, in the current crisis, it could deter Putin from using the gas weapon, lest he encourage Europeans to make concerted efforts to shift their long-term gas procurement to the United States when that becomes possible in a few years. Second, in future crises, it could blunt the Russian gas weapon, since U.S. exports would be available to fill in for Russian supplies. (You might have noticed that I haven’t said anything about oil. That’s because the idea that U.S. oil exports would give Europe some sort of special buffer is silly. The world oil market is pretty flexible, and U.S. exports would be a drop in an already large sea. To the extent that Europe is constrained in its ability to switch oil sources quickly, that’s because of infrastructure, something U.S. exports wouldn’t change.) There are two essential things to keep in mind when thinking through the claims about natural gas exports. First, decisions about whom to export to and import from are made by commercial entities, not by governments. When a U.S. analyst says, “we should tell Europe we’ll sell them our gas”, the first response should be, “who’s ‘we’”? (The second response should be, “who’s Europe?”) The U.S. government doesn’t get to sell gas to anyone; it can create a framework in which commercial entities can sell gas, but after that, it’s up to those businesses to decide where the gas goes. Similarly, “Europe” doesn’t buy gas – all sorts of European companies do, within European and national regulatory frameworks. Second, surging natural gas into Europe to respond to a crisis requires that there be infrastructure in place that can accommodate that surge. In the case we’re talking about here, that means having a bunch of unused (or partly used) European natural gas import terminals that can suddenly absorb newly arrived U.S. supplies. And remember – back to the first point – these terminals will be built by private players. So what does this all mean for the big strategic claims? It is difficult to see how U.S. exports will substantially erode the long-run share of Russian gas in Europe. It is far more profitable for buyers of U.S. natural gas to ship it to Asia – where prices are far higher – than to Europe. (The exception is if European companies are willing to pay a hefty premium to get their gas from the United States – but remember, these are commercial entities, which makes it very difficult for them to do that.) There is, of course, a knock on effect from that, since if U.S. gas frees up other supplies that were destined for Asia, those supplies can potentially move into Europe instead. But Russia remains a relatively low-cost supplier into Europe, and can trim its prices to keep its market share. Moreover, unlike European gas companies, the big Russian players have much tighter ties with the state. If Moscow wants them to keep their share in the European market for strategic reasons, it may be able to make them do that. Russia would lose money – an important piece of geopolitical harm – but its leverage wouldn’t be slashed. What about supplying gas to Europe in a crisis? Here the basic constraint is infrastructure. Gas demand is seasonal, so during some parts of the year, there may be underutilized LNG import terminals. [UPDATE 3/6: Moreover, with a weak European economy, there is currently a lot of unutilized European LNG import capacity year-round; whether that persists indefinitely remains to be seen. Even in the current case, though, Russian imports into Europe greatly exceed spare LNG import capacity.] Were Russia to cut gas supplies to Europe during a crisis, if prices rose high enough, those terminals could be used to surge in some supplies. During other times (notably winter, when gas demand is most acute) the terminals will be fully utilized, making them unavailable to bring in new LNG supplies. The only way around that is to overbuild. This might happen by mistake, but unless European policymakers offer financial incentives, profit-seeking firms won’t do it on purpose. There is one other wrinkle worth thinking about here. The United States is currently able to take a harder line against Russia than Europeans are in part because the U.S. economy is insulated from energy-related turmoil. Were the prospect of surging gas into Europe a real one, we’d be having all sorts of debates here about the economic fallout for the United States from escalation with Russia. [UPDATE 3/6: It’s worth distinguishing here between swinging U.S. gas from Asian to European customers, which wouldn’t affect the U.S. market, and boosting total U.S. exports, which would.] Ironically, while being more connected to European gas markets might give the United States more tools in a future crisis, it could also deter Washington from aggressively confronting Russia.

The current Economist has an article on U.S. oil and gas that repeats an increasingly common view: tight oil will make “future oil shocks less severe” since “frackers can sink wells and start pumping within weeks”. (Here’s a variant from The Atlantic last August.) That speedy response means that “if the oil price spikes, [drillers will] drill more wells”, quickly spurring new production, and taming any price spike. This is severely flawed – a point that recent experience reinforces. It is undeniably true that the time from drilling to production is far lower for tight oil than for traditional wells. But that doesn’t mean that industry can respond quickly and powerfully to oil market shocks. Imagine that a disruption in the Strait of Hormuz threatened to send oil prices up from one hundred to two hundred dollars a barrel for a span three months. How would U.S. oil producers respond? The first thing they’d do is ask themselves whether new investment would make sense over the full life of any new well rather than just over the span of the disruption. Let’s take a best-case scenario: a developer realizes that something is afoot on Day 1 of the crisis and is confident the price rise will last three months. If you assume that about 20 percent of a well’s output comes in its first year, and that production declines by about 50 percent in a straight line over the course of that year, then you end up with 6-7 percent of total production during the period of elevated prices. Wells with break-evens up to 106 or so dollars a barrel, rather than merely 100 dollars a barrel, are now in the money. This will not spur radical change. (If I was doing this carefully, I’d discount future cash flow, making the up-front revenue boost more consequential. But the basic qualitative point would still stand.) Even if you extend the crisis to six months, you get a maximum break-even of about 112 dollars a barrel, a relatively small increment. And this assumes that drillers act instantly upon a supply disruption; in reality, making a decision to drill, mobilizing resources to begin production, and actually drilling and fracking a well would delay the start of production and further blunt the slightly-above-normal returns. One can argue with the numbers I’ve used to make this point, but the basic qualitative conclusion is solid. In fact the numbers I’ve just presented overstate how strong drillers’ response would be. In the short run the number of rigs available for drilling is fixed. (I could make a similar argument about other capital and people needed to initiate production, but it’s useful to focus on one thing.) It’s true that producers can move rigs from natural gas toward oil, but that’s happened so much over the last couple years that there isn’t a huge margin to do that today. Over time, you could see more rigs get ordered. But companies aren’t going to order a bunch of rigs that will be active for a few months and then sit idle once prices return to normal – that’s not a profitable proposition. Instead companies faced with an impending price spike will bid for a fairly fixed set of rigs. Since those rigs are newly valuable – you can now make a bit more money using each one because oil prices are higher – companies will be willing to pay more. The break-even price for a given well will therefore rise, moving some seemingly profitable but marginal prospects back into the red, and leaving them untapped as a result. This dynamic also explains why newly cash-flush producers won’t be able to blindly plow all their money back into increased production even if they were inclined to: the necessary rigs wouldn’t be there. And there’s one more constraint: transportation. Even if drillers can respond quickly, that doesn’t mean that they can get the oil they produce to market. If there isn’t sufficient pipeline or rail capacity to quickly move newly produced oil to market, companies aren’t going to produce that oil. It takes a decent amount of time, of course, to expand transport capacity. This won’t always be a big constraint, but it’s one more strike against the “tight oil production is always going to be super-responsive” line. We’ve recently had an ugly piece of real-world experience in natural gas that backs this all up. Henry Hub natural gas prices rose from $4/MMBtu to about $5.50/MMBtu over the span of a few weeks in January. They’re still elevated. So are rigs rushing toward newly profitable opportunities in natural gas? Absolutely not: the gas-directed rig count declined 4 percent last week (half those rigs went to oil and the other half were inactive) and has fallen 20 percent over the last year. This is due in part to the fact that the cold snap driving prices up right now is ultimately going to dissipate, and in part because we don’t have the right infrastructure in place to move additional natural gas production to market quickly. (It’s also because using available rigs to drill for oil remains more profitable than moving them to gas, despite the price spike.) To be certain, this story would look different if we were talking about long-term increases in the price of oil. A run-up like the one we saw in the 2000s, which unfolded over the span of almost a decade, would give drillers plenty of time to respond. (Though experience in the oil sands in the 2000s suggests that capital and labor constraints – and resulting cost inflation – would still be a major drag.) But for the sorts of oil price spikes we worry about most – those driven by sudden and intense geopolitical disruptions – the responsiveness of tight oil production is likely to do a lot less to blunt the consequences than many people seem to hope.

Science published an interesting and useful new paper on methane leaks in natural gas operations yesterday – but the New York Times chose to highlight the one thing in it that’s both unoriginal and shaky. Understanding that flaw reveals some useful pointers for policymakers. The heart of the Science paper is a review of studies on methane emissions from natural gas. Figure one from the paper (reproduced above) alone justifies the paper’s publication. A quick glance at the figure reveals a couple things. First, most serious estimates of methane emissions are higher than those reported by the EPA. (By “serious” I’m basically referring to estimates that include uncertainty bounds; it’s tough to put much stock in the rest.) Second, though, if you look at the space where those estimates overlap, it’s not much in excess of the EPA estimates. The review points to an incremental, not radical, upward revision of methane leakage estimates. The Times, however, chooses to focus on a single sentence deep in the paper. The authors write: “Climate benefits from vehicle fuel substitution are uncertain (gasoline, light-duty) or improbable (diesel, heavy-duty)”. This is the only reference to vehicles in the paper. Yet the Times headline is “Study Finds Methane Leaks Negate Benefits of Natural Gas as a Fuel for Vehicles” and the Times story quotes the paper’s lead author as saying: “Switching from diesel to natural gas, that’s not a good policy from a climate perspective”. There are two large problems with this. The first is that the observation has nothing to do with the analysis in the Science paper. The sole sentence in the paper that addresses diesel-to-gas switching cites a two-year-old Proceedings of the National Academy of Sciences (PNAS) paper – nothing new is added. More problematic is that the 2012 paper, which is mostly excellent, stumbles when it comes to comparing diesel with natural gas. Why? If you dig up the references that the PNAS paper uses you’ll find that it assumes CNG-fueled vehicles are 20.7 percent less efficient than diesel-fueled ones. There is a citation for this – and indeed many CNG-fueled vehicles suffer a severe efficiency penalty. But this is far from universal. Diving a couple references deep reveals that the figures are not for CNG-fueled trucks in general but for urban buses – one of the worst cases (and perhaps the worst case) for CNG. Moreover, the original reference has pretty big uncertainty bounds, though those are dropped as the paper’s contents are exploited elsewhere. A quick spin through reports unearthed by a Google search about the CNG efficiency penalty reveals a wide range of estimates – from no penalty at all to a bit north of the 20.7 percent that the PNAS authors use – depending on the engine technology chosen and how (and where) the vehicle is driven. If you adopt the more favorable estimates for the efficiency penalty – which tend to correspond to more modern engines (though not universally) and to non-urban applications – switching from diesel to CNG is indeed mildly beneficial for the climate. This raises the second issue. The PNAS study – which uses the EPA estimates that the Science paper challenges – already claims that diesel-to-CNG switching isn’t beneficial for the climate. The Science paper doesn’t say anything new about that. In particular, contrary to the Times reporting, it isn’t the new estimates of methane leakage that drive the Science conclusion – it’s primarily the implicit assumptions about engine efficiency. In fact, even with zero methane leakage, the methodology in the PNAS paper points to scant climate benefit (only about 10 percent lower emissions) from switching from diesel to CNG. That suggests that if people are worried about climate dangers associated with switching from diesel to CNG, and they’re focused on methane leakage, then they’re looking in the wrong place – or at least missing the central piece of the puzzle. It might make more sense for policymakers to focus on boosting the efficiency of the natural gas engines that people adopt rather than fixating on methane leakage. Perhaps when CAFE rules give special credit for natural gas vehicles, the rules could impose minimum standards on those engines’ efficiency. This would be analogous to the way different kinds of natural gas fired power plants have been treated by EPA regulations – standards for new plants are far more welcoming to high-efficiency natural gas plants than for lower-efficiency gas technologies. In the long run, it’s mainly carbon dioxide, not methane, that will determine how much the planet warms. Making sure natural gas powered vehicles are as efficient as possible would cut the carbon dioxide emissions associated with them – and, as a bonus, the amount of methane released too.

“China’s leading think tank has outlined a revamped energy strategy,” Xinhua reports today, highlighting a long article published yesterday in People’s Daily. This comes on the heels of a wonderfully titled FT article – “China scythes grain self-sufficiency policy” – claiming that China has given up on its long-standing goal of producing its own food. Chinese resource strategy, it seems, is changing rapidly and radically. But is it really? In a new book published last week, my colleague Elizabeth Economy and I tackle the full sweep of China’s resource quest, from energy and minerals to food and land. By All Means Necessary: How China’s Resource Quest is Changing the World explores the roots of Chinese strategy and its consequences for trade, investment, governance, politics, and security. Two themes that bear on this week’s news emerge: Chinese strategy has deep roots at home that make change slow to unfold – but, as China pursues its resource quest, it is indeed learning and changing. Take the article by Li Wei outlining a new energy strategy. The first thing to note is that this is just one view, albeit from a powerful perch, that feeds into the usual messy process of formulating policy. Western reporting too often assumes that any publication from a prominent government or government-connected Chinese official is effectively law. That’s wrong: China may not have the open politics that the United States does, but there’s still a lot of diversity within the ranks, and any changes that are advocated are sure to be fought over before they’re pursued. The reporting on grain self sufficiency – which is about a new policy rather than a mere study – reflects the slow-to-change nature of Chinese strategy in another way. The actual changes the FT reports are far less revolutionary than the paper’s headline suggests. Chinese leaders appear to remain fixed on self-sufficiency in grain – a goal that, we show in the book, goes back hundreds of years – but are adjusting the way they define that. Is ninety-five percent self-sufficiency enough for security? Eighty-percent? Those are the sorts of evolutionary rather than revolutionary questions that Chinese leaders are grappling with as they confront the reality of feeding a billion people in the face of myriad pressures on Chinese land. The new energy study reflects gradual Chinese change in another way. A decade ago one expected to see “going out” – investing in upstream energy resources abroad – at the heart of most prominent Chinese writing on energy strategy. But there’s essentially no mention of “going out” in the new paper published today. (I’m hedging my bets because I’m using Google Translate so can’t be completely sure; I’d welcome any pointers either way from people who read Chinese on whether there’s mention of outward upstream investment in the study.) Many Chinese strategists have learned over time that overseas upstream investment doesn’t result in security of Chinese energy supplies. This study isn’t the first to reflect that – and the evolved view isn’t universally shared – but it appears to be another piece of evidence that Chinese leaders are learning from experience and becoming more comfortable with markets. Therein is perhaps the biggest lesson from the two reports. It’s the collision of two forces– the deep political, historical, and institutional roots of Chinese strategy at home, juxtaposed with the learning and evolution that happens through experience, good and bad – that has and will continue to shape Chinese resource strategy. Looking at just one while ignoring the other will invariably lead to a distorted view.

Is the U.S. government keeping tens of millions of people poor by focusing its development assistance on renewables rather than gas and coal? It’s a critical question – particularly as the United States ramps up its Power Africa effort – that’s addressed thoughtfully by Todd Moss and Benjamin Leo in a new Center for Global Development paper that Bjorn Lomborg highlighted in a USA Today column this weekend. Moss and Leo estimate that OPIC (Overseas Private Investment Corporation) investment restrictions, which tightly cap the amount of money that can go toward coal or gas, are costing 60 million people access to electricity. But while I’m on board with their basic point – the world’s wealthy should avoid cutting greenhouse gas emissions on the backs of poor people when rich ones are still pumping out so much pollution – I’m skeptical of their bottom line. The Moss and Leo argument is straightforward. Every dollar committed by OPIC to a natural gas power project is accompanied by four dollars (on average) in private funds. In contrast, every OPIC dollar committed to a renewable energy project leverages only 50 cents on average. If OPIC has a ten billion dollar portfolio, dedicating that to gas would generate 50 billion dollars in investment, but directing it toward renewables would yield only 15 billion dollars. Moss and Leo combine these figures with an estimate of the per-person costs of energy access to conclude that focusing on gas could generate access for 90 million people but that investing in renewables would serve only 20-27 million. They also estimate the amount of generating capacity that each type of focus could yield: only 4,200 megawatts (MW) for renewables but 42,000 MW for one-third-less-capital-intensive natural gas. It strikes me that there are three issues with this analysis. Correcting two of them makes the trade-off look less stark, but fixing the third makes it look even worse. The first problem is with the leverage ratios. The historical leverage ratios do not tell us that for every additional dollar OPIC spends on gas the private sector will spend four. They actually tell us nothing about how much private investment a dollar of OPIC spending will leverage, because they don’t tell us what happens at the margin, and they don’t tell us anything about causality. To see why, imagine that private investors planned to spend a billion dollars on natural gas. Now imagine that OPIC stepped up and decided to commit ten million dollars to the same end – and that developers pocketed that money without expanding their projects. We would calculate a stunning 100:1 leverage ratio for this project, even though the actual leverage is zero. It’s entirely possible that public spending on natural gas projects appears to leverage more private capital than spending on renewables does simply because more private capital is already there for natural gas than for renewables. We have no idea, at least based on the numbers that Moss and Leo present, whether OPIC investment attracts more private capital when it’s in gas or in renewables. The second issue has to do with how costs are defined. Moss and Leo focus on power plant capital costs. Those are, to a good approximation, the full costs of renewables. But they also are, of course, far from the full costs of natural gas. (Generation costs for natural gas are typically dominated by the cost of fuel.) Now Moss and Leo note that most of the countries targeted by Power Africa have decent natural gas resources. But there is a cost to using these domestically: foregone export revenues. (And there’s a cost to producing them, namely the labor and capital – probably imported in the latter case – that’s required.) It’s not much use to build gas-fired generating capacity unless there’s affordable fuel for it to use (just ask Indian planners). At a minimum, then, you’d need to argue that consumers will be able to pay for the continued operation of OPIC-backed gas-fired power plants. To be more complete you’d need to look at the full cost of gas-fired generation in any comparison – including foregone investment or revenues resulting from more domestic gas use. There is, however, a third thing that weighs strongly toward Moss and Leo’s bottom line: not all megawatts are created equal. A megawatt of wind or solar doesn’t deliver nearly as much electricity over time as a megawatt of gas-fired capacity can. Assuming that fuel is available at an affordable price – a significant assumption that we’ve just looked at – the 42,000 MW of gas-fired capacity that Moss and Leo estimate are actually more than 10 times as valuable as the 4,200 MW of renewables they flag. What’s the bottom line here? Moss and Leo are right to warn us against shortchanging the poor by being dogmatically opposed to supporting fossil fuel development. But it’s far from obvious that directing OPIC money toward natural gas projects consistently yields bigger energy access payoffs than spending it on zero-carbon electricity. Better to pursue a project-by-project assessment of costs and benefits that focuses on the actual impact of each OPIC intervention, not on associating OPIC with the largest volume of private activity, or on insisting dogmatically that it stay out of almost all fossil fuels.

The newest boom sparked by rising U.S. oil and gas production appears to be in articles about the troubled U.S.-Saudi relationship. The latest installment, provoked by the Iran nuclear deal over the weekend, ran today on A1 in the New York Times. “When you look at our differing views of the Arab Spring, on how to deal with Iran, on changing energy markets that make gulf oil less central,” Greg Gause tells the Times, “these things have altered the basis of U.S.-Saudi relations.” “New sources of oil,” the Times informs us, “have made the Saudis less essential.” The chart at the top of this post ought to put this myth to rest. U.S. imports of oil from Saudi Arabia in August 2013 (the last month for which data is available) were 1.332 million barrels a day. That is higher than for 251 of the 479 months that have passed since the October 1973 oil embargo. Most of the time in which U.S. imports were lower was during the 1980s and 1990s – a period when the U.S.-Saudi relationship was generally solid. In August 1990, when Iraq invaded Kuwait and set off U.S. panic about the potential threat to Saudi oil – ultimately leading to the first Gulf War – the United States imported 1.189 million barrels a day from the Kingdom. That’s less than it does today. To be certain, the United States does not “depend” on shipments of Saudi oil in the way that many imagine, with a devastating embargo possible at any moment. And the precise volume of Saudi sales to the United States, whether high or low, shouldn’t matter much. That’s not because of the U.S. oil boom; it’s because global markets are well integrated. But, like all consumers, the United States depends on the continued flow of Saudi oil into the world market to keep prices at the pump manageable. It also depends on Saudi use of its spare capacity to moderate volatility in the global oil market. The U.S.-Saudi relationship is going through a difficult time. U.S. policies toward Egypt, Syria, and now Iran are worrying leaders in Riyadh. That’s coincided with a boom in U.S. oil production. But it would be wrong to confuse correlation with causation in this case.

America has moved from oil scarcity to oil abundance, and our attitudes need to change in order to keep up. If the stream of headlines and panels is any indication, you’d have to be an idiot to disagree with that claim. So call me stupid, because I just don’t see it. There’s no question that U.S. oil production is booming. The country has passed Saudi Arabia as the world’s biggest liquid fuels producer and is now producing more oil than it imports. The rise in U.S. output, which is poised to continue, is good news for the economy and national security. It’s also something that leaders need to adjust to as they develop policy and strategy. But setting production records and passing milestones is fundamentally different from abundance. By pretty much every meaningful indicator, the abundance story is wrong. Start with physical volumes. The United States imports roughly half of the oil it consumes. If the United States imported half of its labor, no one would say that the country enjoyed an abundance of workers. Oil is no different. Saudi Arabia enjoys oil abundance – it produces far more than it consumes. Ditto for Russia, Kuwait, and a host of others. The United States is not in that category. Prices are an even better indicator. Imported oil has traded around $100 for much of the last several years. You need to go back to 1981 to find real average monthly oil prices over $100 – and that lasted a whopping two months. Even if oil prices were to fall to, say, $70 a barrel, that price would be higher than it was for 346 of the 396 months between January 1974 and January 2007. If oil is so much more abundant than it was, say, a decade or two ago, why are sellers able to charge so much more for it? Real abundance means lower prices, not higher ones. But you say: Aren’t we exporting record amounts of refined products – and now talking about exporting crude? That’s all true. But if we imported a lot of cars, painted them green, and then exported some of them, no one would say that we were enjoying an abundance of cars. (They might say that we enjoy an abundance of green paint.) That’s basically what’s happening with refining: we have an abundance of advanced refineries – more than we need for domestic consumption – but that’s different from having an abundance of oil. As for oil exports, that’s a variation on the same theme. We’re likely heading toward having an excess of light sweet crude relative to simple U.S. refining capacity, so it will make increasing economic sense to export some of the stuff. At the same time, we will continue to have a massive deficit of heavier crudes relative to abundant complex refining capacity; as a result, we’ll continue to be heavily reliant on imports in the aggregate. As with any traded item, it’s the net position that matters most. And that reinforces the essential point. Abundance is the right narrative for a subset of U.S. petroleum refiners. It’s the right narrative for some U.S. states. It’s even the right one for some U.S. oil producers and pipeline operators. (It’s also a good one for natural gas.) And, to be sure, the extreme scarcity narratives (think peak oil) are wrong too. But just because the scare mongers are wrong doesn’t mean that we’re swimming in crude. And, most fundamentally, the position of the United States isn’t the same as that of the petroleum refining sector or the pipeline industry or even the state of North Dakota or Texas. For the United States, genuine oil abundance remains a long way away at best – and it would dangerous to forget that.