I've seen a number of Tweets suggesting that the US will release oil from its Strategic Petroleum Reserve (SPR) sometime in the next month or two, perhaps in tandem with other member countries of the International Energy Agency. Although circumstances might provide several possible rationales for such a release, including the implementation of tougher sanctions on Iran's oil sector and the possibility that Hurricane Isaac will disrupt some production in the Gulf Coast, it's hard to avoid a political interpretation, as well. As we head into a close Presidential election, gas prices are rising again, and that's never good for an incumbent. Selling oil from the SPR is one of the few levers available that might affect short-term energy prices. However, much has changed since the Clinton administration released 30 million barrels (via exchange) in the lead-up to the 2000 election. In particular, the country's switch from net importer to net exporter of petroleum products implies that a release in response to events other than a physical disruption in oil supplies could result in some of the benefit of such a release being exported, as well.
When it comes to uses of the SPR, I'm a purist, probably 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. The SPR was designed to provide a backstop for our vital energy supplies in a true physical emergency, not as a tool for price manipulation. I've also suggested for some time that the SPR is overdue for a comprehensive reassessment of its structure. Our energy situation has changed significantly since the mid-1970s, when the present SPR was established, and we are in the midst of the biggest changes in US energy supply and demand patterns in decades. We ought to invest the time and money required to bring this institution into the 21st century. Earlier this year, I also suggested an alternative mechanism for leveraging SPR inventories without depleting them. These are tasks for after the election, whoever wins. For now, we have what we have, and we should think carefully about the implications of using it in situations less compelling than a war in the Persian Gulf or an unanticipated disruption in North American or global supplies.
One of the changes that must be taken into account is our recent shift in refined product exports, about which I've written previously. US refineries are capitalizing on the expansion of domestic oil production in a period of weak US demand to continue to operate at high utilization rates and export the resulting surplus output to growing economies in Latin America and elsewhere. This is generally a good thing, because it helps preserve capacity that might otherwise no longer be available when our own economy eventually resumes healthier growth. It also sustains employment we would sorely miss in a terrible job market. Furthermore, we have benefited greatly in reliability and flexibility from participating on both sides of the global market in refined products. Still, although I view our petroleum product exports as generally positive--just as I do Boeing's exports of jetliners--I wouldn't advocate using petroleum stockpiles purchased with tax dollars to drive down oil prices to give these refiners an even bigger export advantage. Yet because of its temporary nature, in contrast to new pipelines or new production, that's exactly where at least some of the benefit of SPR oil released in the absence of a serious supply crisis would go now.
That doesn't mean I regard rising oil or gasoline prices as harmless to the economy. Consumers are facing the highest pump prices heading into Labor Day weekend since 2008, and that could have a ripple effect throughout the economy. But even if one ignores the longstanding bi-partisan principle that the SPR is intended only as a crisis-management tool, its effectiveness at moderating oil-price volatility is limited. Last year's coordinated SPR release, prompted by the Libyan revolution, had little persistent effect on either oil or gasoline prices. A release now is likely to be no more effective when US refineries are already running above 90% utilization and the current 4-week averages show 3.6% of US gasoline production and 23% of diesel output being exported. None of these statistics suggest refiners are experiencing difficulties in obtaining feedstocks, other than on price. Putting SPR oil into such a market might boost refiners' margins for a while, but it's doubtful it would do much for the product prices that matter to consumers.
There are sharp differences between President Obama and Governor Romney, not least on energy policy. We're sure to hear more about energy from both campaigns in the weeks ahead, and I plan to analyze their positions closer to election day. However, one factor this election doesn't need is a release of oil from the SPR that appears to be aimed at dampening gasoline prices that often decline after Labor Day without intervention, rather than being justified by a tangible threat to US oil supplies, and that fails to take into account the added complexity of net product exports. That wouldn't serve the interests of voters, taxpayers or consumers, and it would come at the expense of a little bit of our collective energy security.
Monday, August 27, 2012
Wednesday, August 22, 2012
The Unlevel Playing Field for Energy
An editorial in last weekend's Wall St. Journal led me to a recent analysis by the US Energy Information Agency (EIA) summarizing the costs of the federal government's various "subsidies" for energy from different sources. This is both useful and timely, since discussions of specific subsidies such as the expiring wind production tax credit inevitably lead to questions about how incentives for renewable energy compare to those for oil, gas, nuclear, and other more traditional sources. As the Journal noted, the EIA stopped short of comparing these incentives on the basis of the relative productivity of different energy sources, but even without that it's still apparent that the category of new renewable electricity--excluding hydropower--received 21% of the federal energy benefits for 2010, while accounting for less than 3% of domestic energy production that year, when oil and gas, which provided 49% of US energy production, received less than 8% of these benefits. Whether on an absolute or relative basis, renewables receive much more generous federal support than oil and gas.
Before digging further into the EIA's analysis, I should point out an important distinction between the federal expenses and incentives covered in the report and the externalities that are frequently conflated with them. It is certainly true that many of these energy technologies involve significant impacts that aren't reflected in their market prices, and that the production and especially the consumption of fossil fuels create serious environmental and security externalities. However, to whatever extent federal subsidies address externalities they do so indirectly, at best, and in many cases inefficiently. The focus of this posting, just like the EIA report's, is on the federal government's cash outlays and "tax expenditures"--deductions, credits, etc.--that have a direct bearing on the federal deficit and debt burden that are the subject of intense debate in this election cycle.
The tables in the report's executive summary reveal several key facts. Between 2007 and 2010 federal energy subsidies in constant dollars more than doubled to $37.2 B, with most of the increase going to renewables and energy efficiency, except for a sizable bump in low-income energy assistance payments. $14.8 B of the increase originated with the 2009 stimulus bill, none of which was directed at oil and gas, but which appropriated nearly $8 B to conservation and efficiency. Overall, renewables received $14.7 B, split 55/45 between electricity and biofuels, while nuclear received $2.5 B and oil and gas $2.8 B. The latter figure is lower than you'll see elsewhere, because among other incentives that the EIA chose to exclude from its analysis was the Section 199 deduction for manufacturers, which is budgeted at around $1 B/yr for oil and gas firms. The logic behind that exclusion seems sound, because US manufacturers of biofuels, wind turbines, solar panels and other renewable energy equipment qualify for the same tax credit, and at a higher rate than oil companies.
I was also struck by the fact that oil and gas received just $70 million out of the more than $4 B spent on R&D. If there's one category in which federal expenditures on renewables should be expected to dwarf those for conventional energy, this is it, and they did so by a factor of more than 20 times. (Coal R&D received more than $0.6 B, presumably for clean coal technologies.)
It's also the case that while the growth of renewable energy output from 2000-10 was dramatic, the relatively smaller net changes in oil and gas output in that period masked the substantial replacement of depleting resources that would have otherwise resulted in a large drop in output, especially for natural gas. This is precisely the aspect of the mature oil and gas industry at which these federal incentives are aimed, to enable US projects to compete with the international opportunities to which many of these companies have access.
The authors of the report suggested caution in comparing the allocations of incentives to the energy produced by each technology, because some of these incentives were paid for projects still under construction and in some cases represented the front-loading of what would otherwise have been a 10-year stream of tax credits. Fair enough. Yet even with the conservative assumption that the entire $4.9 B of non-R&D subsidies for wind power in 2010 came in the form of cash grants in lieu of the 30% investment tax credit for new wind turbines that would produce for 20 years at a 30% capacity factor, that still equates to a subsidy of more than 16% of the average present wholesale value of all the electricity those turbines will produce, using prevailing industrial sector electricity prices as a proxy for wholesale prices. By comparison, the $2.7 B of oil and gas tax incentives for 2010 represented just 1% of the wholesale value of US production of these fuels, before refining.
A serious debate about the appropriate level of US energy subsidies should begin with the facts, rather than with misperceptions. It should also focus first on the goals of such incentives, before jumping to the details of this tax credit vs. that one. What do we want these measures to achieve? If it's simply the promotion of energy production, then the current incentive system looks too heavily skewed in favor of renewables. If it's jobs, then we should be realistic about how many can be added by such a capital-intensive sector. If it's the promotion of both energy security and innovation, then at least parts of the current system look directionally right, though I'd argue that we'd benefit from spending more on renewable energy R&D and less on the deployment of mature-but-expensive technologies like wind. However, if emissions and climate change are our primary concerns, then these incentives are not a terribly effective way to address them. My own expectation is that regardless of whether the wind tax credit is extended for another year, most of the tax incentives that the EIA assessed here will eventually be swept away by tax reform focused on reducing corporate tax rates to improve US competitiveness, while eliminating loopholes to make the changes revenue-neutral.
Before digging further into the EIA's analysis, I should point out an important distinction between the federal expenses and incentives covered in the report and the externalities that are frequently conflated with them. It is certainly true that many of these energy technologies involve significant impacts that aren't reflected in their market prices, and that the production and especially the consumption of fossil fuels create serious environmental and security externalities. However, to whatever extent federal subsidies address externalities they do so indirectly, at best, and in many cases inefficiently. The focus of this posting, just like the EIA report's, is on the federal government's cash outlays and "tax expenditures"--deductions, credits, etc.--that have a direct bearing on the federal deficit and debt burden that are the subject of intense debate in this election cycle.
The tables in the report's executive summary reveal several key facts. Between 2007 and 2010 federal energy subsidies in constant dollars more than doubled to $37.2 B, with most of the increase going to renewables and energy efficiency, except for a sizable bump in low-income energy assistance payments. $14.8 B of the increase originated with the 2009 stimulus bill, none of which was directed at oil and gas, but which appropriated nearly $8 B to conservation and efficiency. Overall, renewables received $14.7 B, split 55/45 between electricity and biofuels, while nuclear received $2.5 B and oil and gas $2.8 B. The latter figure is lower than you'll see elsewhere, because among other incentives that the EIA chose to exclude from its analysis was the Section 199 deduction for manufacturers, which is budgeted at around $1 B/yr for oil and gas firms. The logic behind that exclusion seems sound, because US manufacturers of biofuels, wind turbines, solar panels and other renewable energy equipment qualify for the same tax credit, and at a higher rate than oil companies.
I was also struck by the fact that oil and gas received just $70 million out of the more than $4 B spent on R&D. If there's one category in which federal expenditures on renewables should be expected to dwarf those for conventional energy, this is it, and they did so by a factor of more than 20 times. (Coal R&D received more than $0.6 B, presumably for clean coal technologies.)
It's also the case that while the growth of renewable energy output from 2000-10 was dramatic, the relatively smaller net changes in oil and gas output in that period masked the substantial replacement of depleting resources that would have otherwise resulted in a large drop in output, especially for natural gas. This is precisely the aspect of the mature oil and gas industry at which these federal incentives are aimed, to enable US projects to compete with the international opportunities to which many of these companies have access.
The authors of the report suggested caution in comparing the allocations of incentives to the energy produced by each technology, because some of these incentives were paid for projects still under construction and in some cases represented the front-loading of what would otherwise have been a 10-year stream of tax credits. Fair enough. Yet even with the conservative assumption that the entire $4.9 B of non-R&D subsidies for wind power in 2010 came in the form of cash grants in lieu of the 30% investment tax credit for new wind turbines that would produce for 20 years at a 30% capacity factor, that still equates to a subsidy of more than 16% of the average present wholesale value of all the electricity those turbines will produce, using prevailing industrial sector electricity prices as a proxy for wholesale prices. By comparison, the $2.7 B of oil and gas tax incentives for 2010 represented just 1% of the wholesale value of US production of these fuels, before refining.
A serious debate about the appropriate level of US energy subsidies should begin with the facts, rather than with misperceptions. It should also focus first on the goals of such incentives, before jumping to the details of this tax credit vs. that one. What do we want these measures to achieve? If it's simply the promotion of energy production, then the current incentive system looks too heavily skewed in favor of renewables. If it's jobs, then we should be realistic about how many can be added by such a capital-intensive sector. If it's the promotion of both energy security and innovation, then at least parts of the current system look directionally right, though I'd argue that we'd benefit from spending more on renewable energy R&D and less on the deployment of mature-but-expensive technologies like wind. However, if emissions and climate change are our primary concerns, then these incentives are not a terribly effective way to address them. My own expectation is that regardless of whether the wind tax credit is extended for another year, most of the tax incentives that the EIA assessed here will eventually be swept away by tax reform focused on reducing corporate tax rates to improve US competitiveness, while eliminating loopholes to make the changes revenue-neutral.
Tuesday, August 07, 2012
Are Films the Answer to Understanding Energy's Complexities?
The issues and choices surrounding our use of energy have rarely been more complex than today, yet our main channels for information about them are discouragingly shallow. The web is often more effective at spreading misperceptions than fact-based analysis. When our visual media focus on energy, it's usually to flash bad news before flitting on to the next story, leaving behind images of burning oil platforms or blacked-out cities. One bright spot is the recent wave of documentary films on energy topics. Films engage us on a deeper level, and the energy challenges we face deserve such longer-form treatment. August seems like a perfect time to suggest a few of them to you. If you're reading this blog, then I'm betting you might at least consider watching a movie about energy instead of the latest summer blockbuster.
Although it was hardly the first serious film about energy, the recent trend seemed to start with "Gasland". For all its inaccuracies, which have been documented by groups outside industry, that film helped start a national conversation about the right way to develop the enormous unconventional oil and gas resources that new combinations of technology have unlocked. In the spirit of making that dialog more constructive and even-handed, you should also know about two other documentaries covering the same topic and region from a different angle. To many of the farmers and other landowners in depressed counties of New York and Pennsylvania, fracking is not a curse but an actual or potential lifeline. Seeing "Truthland" and "Empire State Divide" might not convert fracking skeptics into gas industry supporters, but it should at least fill in some of the gaps left by the "Gasland's" starkly one-sided portrayal of shale gas.
Another energy film I recently ran across, "spOILed", offers a timely reminder that despite oil's many problems it remains an essential ingredient of our global civilization, providing affordable mobility and a host of products that have made our lives much easier than those of our ancestors--or of people in countries that still lack reliable access to energy. "spOILed" is also very much a movie about the dangers of Peak Oil, which envisions a world in which declining oil production, rising demand in developing countries, and geopolitical risks create persistent and growing shortages of oil. This is particularly sobering when combined with a sense of just how challenging it will be to obtain the services that oil now provides from other energy sources. Unfortunately, the film's message was undermined by occasionally jarring choices of visuals, some hyperbolic claims--no indoor plumbing without oil?--and by political overtones that might limit its effectiveness with the wider audience it appears to target.
The energy film project that I'm most excited about is one aimed consciously at finding and cultivating "The Rational Middle" in the energy debate. According to its director, Gregory Kallenberg, it started with a TED talk following his previous film, "Haynesville", which examined the impact of shale gas in Northern Louisiana. As I understand it, the current project consists of 10 short videos on energy, four of which have been released on the group's website so far. From the episodes I've seen, Mr. Kallenberg's team assembled an impressive group of experts, including Amy Myers Jaffe of the Baker Institute at Rice University, Michael Levi of the Council on Foreign Relations, former Energy Information Agency Administrator Richard Newell, and Dr. Michael Webber of the University of Texas. The series is being launched with a road show featuring panels of some of the same experts interviewed in the films, starting with a session at this year's Aspen Ideas Festival. The films are focused on information and process, rather than on selling one point of view. Aside from a few assertions in a couple of interviews, the factual presentation in the initial videos was very sound. I expect to have more to say about The Rational Middle as additional episodes become available.
If the we are to develop effective energy policies for the 21st century, the public's desire for clean, secure, reliable and affordable energy must be grounded in facts and figures that help us to differentiate realistic expectations from wish fulfilment. I'm encouraged that a growing number of filmmakers seems willing to explore energy issues in the depth they deserve, with production values that will connect with today's audiences, rather than turning them off. Enjoy!
Although it was hardly the first serious film about energy, the recent trend seemed to start with "Gasland". For all its inaccuracies, which have been documented by groups outside industry, that film helped start a national conversation about the right way to develop the enormous unconventional oil and gas resources that new combinations of technology have unlocked. In the spirit of making that dialog more constructive and even-handed, you should also know about two other documentaries covering the same topic and region from a different angle. To many of the farmers and other landowners in depressed counties of New York and Pennsylvania, fracking is not a curse but an actual or potential lifeline. Seeing "Truthland" and "Empire State Divide" might not convert fracking skeptics into gas industry supporters, but it should at least fill in some of the gaps left by the "Gasland's" starkly one-sided portrayal of shale gas.
Another energy film I recently ran across, "spOILed", offers a timely reminder that despite oil's many problems it remains an essential ingredient of our global civilization, providing affordable mobility and a host of products that have made our lives much easier than those of our ancestors--or of people in countries that still lack reliable access to energy. "spOILed" is also very much a movie about the dangers of Peak Oil, which envisions a world in which declining oil production, rising demand in developing countries, and geopolitical risks create persistent and growing shortages of oil. This is particularly sobering when combined with a sense of just how challenging it will be to obtain the services that oil now provides from other energy sources. Unfortunately, the film's message was undermined by occasionally jarring choices of visuals, some hyperbolic claims--no indoor plumbing without oil?--and by political overtones that might limit its effectiveness with the wider audience it appears to target.
The energy film project that I'm most excited about is one aimed consciously at finding and cultivating "The Rational Middle" in the energy debate. According to its director, Gregory Kallenberg, it started with a TED talk following his previous film, "Haynesville", which examined the impact of shale gas in Northern Louisiana. As I understand it, the current project consists of 10 short videos on energy, four of which have been released on the group's website so far. From the episodes I've seen, Mr. Kallenberg's team assembled an impressive group of experts, including Amy Myers Jaffe of the Baker Institute at Rice University, Michael Levi of the Council on Foreign Relations, former Energy Information Agency Administrator Richard Newell, and Dr. Michael Webber of the University of Texas. The series is being launched with a road show featuring panels of some of the same experts interviewed in the films, starting with a session at this year's Aspen Ideas Festival. The films are focused on information and process, rather than on selling one point of view. Aside from a few assertions in a couple of interviews, the factual presentation in the initial videos was very sound. I expect to have more to say about The Rational Middle as additional episodes become available.
If the we are to develop effective energy policies for the 21st century, the public's desire for clean, secure, reliable and affordable energy must be grounded in facts and figures that help us to differentiate realistic expectations from wish fulfilment. I'm encouraged that a growing number of filmmakers seems willing to explore energy issues in the depth they deserve, with production values that will connect with today's audiences, rather than turning them off. Enjoy!
Wednesday, August 01, 2012
Last Hurrah for the Wind Power Tax Credit?
Ahead of Thursday's meeting of the Senate Finance Committee, a bipartisan deal has apparently omitted the expiring production tax credit (PTC) for wind power from a package of "tax extenders"--various expiring federal tax provisions, including the annual "patch" for the Alternative Minimum Tax. This development might surprise some of the industry's supporters, but the politics of wind have changed since I last examined this issue in February. A measure that once enjoyed solid bi-partisan support is now caught between two presidential campaigns that hold diametrically opposed views on its fate.
A quick review of the PTC seems in order. This tax credit, which covers a variety of technologies but with wind as the main beneficiary, dates back to 1992--interrupted by several past expirations but then revived in essentially its present form. That's significant, because during the same 20 years in which the PTC has been escalating annually with inflation--from 1.5 ¢ per kilowatt-hour (kWh) to the present level of 2.2 ¢/kWh--the cost of wind turbines and their output has fallen significantly. In the same period, US installed wind capacity grew from 1,680 MW to nearly 49,000 MW as of the first quarter of 2012. So in effect, we're subsidizing today's relatively mature onshore wind technology by a larger proportion than we did when it was in its infancy. That makes no sense, especially in the current environment.
The US wind industry has received substantial government support in recent years. When the long-standing tax credit against corporate profits proved to be much less beneficial during the financial crisis, the administration gave wind developers a better option within the stimulus: a 30% investment tax credit that could be claimed as up-front cash grants, instead of having to wait until power was generated and sold over the normal 10 year period of the PTC. From 2009-11 the wind industry received a cumulative $7.7 B, in addition to ongoing tax credits on older projects, manufacturing tax credits for new wind turbine factories, and loan guarantees for selected wind farms. And even with new turbine installations in 2012 running well below their record rate of 10,000 MW in 2009, the wind projects that qualify for the PTC this year could receive a total of $4.5 B over the next decade.
Many people seem to want to equate the tax breaks that wind and other renewable energy technologies receive with the controversial tax benefits for the oil and gas industry, without realizing how unfavorable that comparison truly is for renewables. Subsidies for technologies such as wind are much higher per unit of energy produced, consistent with their intended purpose of bridging the competitive gap vs. conventional energy. Yet since the total output of new renewables is still relatively small, the disparity in total subsidies is much larger than it appears. One way to illustrate that is that if the oil and natural gas produced in the US received tax credits at the same rate per equivalent kWh as wind power, then the annual oil and gas tax preferences that the Congress and President Obama have been sparring over for the last three years wouldn't be $4.8 B per year, but around $100 B per year.
As the Reuters article makes clear, there will be other opportunities for the PTC to be reinserted in the extenders bill or other legislation. However, by persistently arguing for extending the existing credit without modification, the wind industry and its supporters may be misreading the public's appetite for such generous subsidies in a period of protracted economic weakness, notwithstanding the recent Iowa poll. Despite its rapid recent growth wind still contributes less than 4% of the nation's electricity and just 1% of our total energy consumption, and the green jobs angle is wearing thin. Last year's expiration of the ethanol blenders credit set a precedent for ending another large, generous subsidy before its beneficiaries agreed they were done with it. If congressional Republicans line up behind their party's standard bearer on this issue, the wind industry will have missed its opportunity for a graduated, multi-year phaseout of the PTC, instead of stepping off a cliff in 2013.
A quick review of the PTC seems in order. This tax credit, which covers a variety of technologies but with wind as the main beneficiary, dates back to 1992--interrupted by several past expirations but then revived in essentially its present form. That's significant, because during the same 20 years in which the PTC has been escalating annually with inflation--from 1.5 ¢ per kilowatt-hour (kWh) to the present level of 2.2 ¢/kWh--the cost of wind turbines and their output has fallen significantly. In the same period, US installed wind capacity grew from 1,680 MW to nearly 49,000 MW as of the first quarter of 2012. So in effect, we're subsidizing today's relatively mature onshore wind technology by a larger proportion than we did when it was in its infancy. That makes no sense, especially in the current environment.
The US wind industry has received substantial government support in recent years. When the long-standing tax credit against corporate profits proved to be much less beneficial during the financial crisis, the administration gave wind developers a better option within the stimulus: a 30% investment tax credit that could be claimed as up-front cash grants, instead of having to wait until power was generated and sold over the normal 10 year period of the PTC. From 2009-11 the wind industry received a cumulative $7.7 B, in addition to ongoing tax credits on older projects, manufacturing tax credits for new wind turbine factories, and loan guarantees for selected wind farms. And even with new turbine installations in 2012 running well below their record rate of 10,000 MW in 2009, the wind projects that qualify for the PTC this year could receive a total of $4.5 B over the next decade.
Many people seem to want to equate the tax breaks that wind and other renewable energy technologies receive with the controversial tax benefits for the oil and gas industry, without realizing how unfavorable that comparison truly is for renewables. Subsidies for technologies such as wind are much higher per unit of energy produced, consistent with their intended purpose of bridging the competitive gap vs. conventional energy. Yet since the total output of new renewables is still relatively small, the disparity in total subsidies is much larger than it appears. One way to illustrate that is that if the oil and natural gas produced in the US received tax credits at the same rate per equivalent kWh as wind power, then the annual oil and gas tax preferences that the Congress and President Obama have been sparring over for the last three years wouldn't be $4.8 B per year, but around $100 B per year.
As the Reuters article makes clear, there will be other opportunities for the PTC to be reinserted in the extenders bill or other legislation. However, by persistently arguing for extending the existing credit without modification, the wind industry and its supporters may be misreading the public's appetite for such generous subsidies in a period of protracted economic weakness, notwithstanding the recent Iowa poll. Despite its rapid recent growth wind still contributes less than 4% of the nation's electricity and just 1% of our total energy consumption, and the green jobs angle is wearing thin. Last year's expiration of the ethanol blenders credit set a precedent for ending another large, generous subsidy before its beneficiaries agreed they were done with it. If congressional Republicans line up behind their party's standard bearer on this issue, the wind industry will have missed its opportunity for a graduated, multi-year phaseout of the PTC, instead of stepping off a cliff in 2013.
Thursday, July 26, 2012
How Secure Are Green Jobs?
It's been an article of faith among advocates of "green jobs" from expanding renewable energy deployment that wind and solar installation jobs are secure because they can't be sent offshore, even as the manufacturing of wind turbines and solar equipment increasingly shifts to Asia. A story in MIT's Technology Review casts doubts on that assumption, for reasons that have much to do with recent reductions in the cost of solar photovoltaic (PV) cells, modules and panels. Green jobs, which in any case shouldn't be viewed as the main selling point of renewable energy, turn out to be much like other jobs in facing competition from automation, as well as from globalization.
Why would it suddenly make sense to consider installing utility-scale solar panels using the robots highlighted in the article? PV module costs have declined dramatically in the last two years. As I've noted in other postings, this trend reflects the expected experience curve effects--such goods become cheaper as you produce more of them--but also the fierce competition resulting from enormous over-building of global PV manufacturing capacity as countries competed with each other to offer generous subsidies for this industry. One consequence of these PV hardware price declines is to increase the share of "non-module" costs in the total installed cost of solar panels. Because the power produced by PV is still more expensive than conventional energy in most markets, that tends to shift the focus of innovation toward ways to reduce the costs of the mounting hardware, inverters, and labor used to put these arrays in place.
The article makes it clear that only certain parts of the solar installation trade are currently threatened by robotic installation. Robots apparently aren't suited to rooftop and small ground installations, yet. However, with politicians busily blurring the distinctions between outsourcing and offshoring, while neglecting the ongoing transformation of work by automation, computing and telecommunications, it's worth recalling that energy remains a capital-intensive commodity business. Keeping costs down is crucial for both energy providers and their customers, and thus for the entire economy they energize. When labor is involved in producing energy, its productivity must be very high, or it naturally becomes a target of innovation and process reengineering. That needn't mean low wages, but it does imply fewer workers working smarter, with more automation.
The energy industry offers excellent opportunities in many sectors, especially those that are growing rapidly because of new technology or the removal of artificial constraints. Yet we shouldn't fool ourselves that these jobs are any more protected or permanent than any others, especially in segments that aren't yet cost-competitive.
Why would it suddenly make sense to consider installing utility-scale solar panels using the robots highlighted in the article? PV module costs have declined dramatically in the last two years. As I've noted in other postings, this trend reflects the expected experience curve effects--such goods become cheaper as you produce more of them--but also the fierce competition resulting from enormous over-building of global PV manufacturing capacity as countries competed with each other to offer generous subsidies for this industry. One consequence of these PV hardware price declines is to increase the share of "non-module" costs in the total installed cost of solar panels. Because the power produced by PV is still more expensive than conventional energy in most markets, that tends to shift the focus of innovation toward ways to reduce the costs of the mounting hardware, inverters, and labor used to put these arrays in place.
The article makes it clear that only certain parts of the solar installation trade are currently threatened by robotic installation. Robots apparently aren't suited to rooftop and small ground installations, yet. However, with politicians busily blurring the distinctions between outsourcing and offshoring, while neglecting the ongoing transformation of work by automation, computing and telecommunications, it's worth recalling that energy remains a capital-intensive commodity business. Keeping costs down is crucial for both energy providers and their customers, and thus for the entire economy they energize. When labor is involved in producing energy, its productivity must be very high, or it naturally becomes a target of innovation and process reengineering. That needn't mean low wages, but it does imply fewer workers working smarter, with more automation.
The energy industry offers excellent opportunities in many sectors, especially those that are growing rapidly because of new technology or the removal of artificial constraints. Yet we shouldn't fool ourselves that these jobs are any more protected or permanent than any others, especially in segments that aren't yet cost-competitive.
Friday, July 20, 2012
Food vs. Fuel and the Midwest Drought
It was bound to happen. As long as US corn output continued to climb year after year, the federal mandate to blend steadily increasing quantities of ethanol into gasoline could be accommodated without creating a shortage of this staple grain. Unfortunately, crops are subject to all sorts of uncertainties, including the severe drought conditions that the middle of the country is experiencing this year. Estimates for this year's corn crop have been revised downward, and corn prices have already broken through $8 per bushel, up from less than $6 a month ago, with consequences for the livestock, processed food and ethanol industries, as well as for export markets. As soaring feed grain prices begin to translate into higher grocery prices for meat, poultry, dairy and other goods, will consumers demand relief from the EPA, which has the authority to curtail ethanol volumes? The current betting appears to be that the administration will stand fast on the mandate, but anything can happen in an election year.
Ethanol now accounts for at least 10% of US gasoline blending, by volume. To meet that demand, ethanol producers will require around 5 billion bushels of corn. In recent years, the ethanol industry's expanding corn demand was met by a combination of increasing yields and planting more acres in corn. However, corn yields per acre are dropping sharply this year, potentially pushing output below last year's 12.4 billion bushels, if conditions don't improve soon. That's in contrast to earlier expectations that this year's corn crop would exceed last year's by 20% . This isn't the first time that the food vs. fuel trade-off inherent in crop-based biofuels has become an issue, but it might be the first time when both the demand for corn for ethanol is so high and the need for that ethanol in the gasoline blending pool is arguably so low. In this context, food vs. fuel quickly boils down to a debate over the tangible benefits of corn-based ethanol as a fuel. There's growing evidence that those benefits have been oversold, despite industry claims.
Start with the widely touted study from Iowa State University indicating that ethanol saved consumers $1.09 per gallon at the gas pump in 2011 and $0.89/gal. in 2010. I read both the original study and its updated version when they came out. It seemed obvious to me that the authors' grasp of gasoline markets and oil refining were inadequate, but I lacked the time necessary to dig through their math to uncover the source of their exaggerated results. Fortunately, a pair of researchers from MIT and my alma mater, U.C. Davis, have now done that work and concluded that the Iowa State paper's findings--and the claims based on them--depended on a "spurious correlation": the relationships they saw were coincidental.
In contrast to the Iowa State studies, the MIT/Davis paper is very readable, and I recommend it to you. In addition to debunking the statistics, the authors point out the key flaws in their counterparts' logic. Foremost among these is that in order to have a large influence on gasoline prices, ethanol would have to have had a large impact on crude oil prices, which are the largest determinant of gas prices, by far. From 2005-11 US ethanol production expanded by 10 billion gallons per year, the energy equivalent of 350,000 barrels per day of oil, or 0.4% of 2011 global oil supply. I've argued many times that the oil market responds disproportionately to modest changes in supply and demand, but the idea that a few hundred thousand barrels per day could translate into the equivalent of $45/bbl exceeds the wildest dreams of any trader I ever met. The MIT paper concludes with the authors summarizing the likely impact of ethanol on gasoline prices as "near zero and statistically insignificant."
However, if ethanol hasn't done much to hold down gas prices, could a drop in US ethanol production resulting from paring back the ethanol mandate to reduce the pressure on corn prices cause a big spike in gasoline prices? That's where the analysis in a paper presented to members of Congress yesterday comes in. Dr. Elam's report suggests that rather than displacing imported crude oil, the main effect of increasing US ethanol use in fuels has been to divert domestic gasoline production into exports, while US crude imports have fallen based on a combination of lower demand (from the recession) and improved product yields per barrel of crude oil refined. Even if you are inclined to be skeptical of these findings because the study was supported by poultry interests, data from the US Energy Information Agency and elsewhere show that US refineries are not fully utilizing their capacity, are exporting significant volumes of gasoline, and have a wider array of domestic and imported crude oils at their disposal than they did just a few years ago. In short, we're in a far better position to forgo a few billion gallons of ethanol this year than we would have been in 2008, the last time food vs. fuel concerns spiked along with gas prices.
Corn growers have experienced droughts before, and in the past the price of corn sorted out who needed it most. However, the market can't prioritize fairly among the competing calls on a drought-diminished corn crop when the single largest segment of demand is locked in place by a federal mandate. This represents a massive distortion that only the government can rectify. I'm sympathetic to the ethanol industry's dilemma. After all, the federal government virtually begged them to overbuild capacity, but it couldn't guarantee they would earn a profit, even when it was providing a $0.45/gal. subsidy for their customers, who are required by law to use their main product. However, the economic and environmental benefits of ethanol are too modest to shield this industry while forcing all other corn users to absorb the likely shortfall in corn supply. The most sensible remedy would be to unshackle ethanol demand, at least temporarily, and waive at least a portion of the ethanol mandate for 2012-13.
Ethanol now accounts for at least 10% of US gasoline blending, by volume. To meet that demand, ethanol producers will require around 5 billion bushels of corn. In recent years, the ethanol industry's expanding corn demand was met by a combination of increasing yields and planting more acres in corn. However, corn yields per acre are dropping sharply this year, potentially pushing output below last year's 12.4 billion bushels, if conditions don't improve soon. That's in contrast to earlier expectations that this year's corn crop would exceed last year's by 20% . This isn't the first time that the food vs. fuel trade-off inherent in crop-based biofuels has become an issue, but it might be the first time when both the demand for corn for ethanol is so high and the need for that ethanol in the gasoline blending pool is arguably so low. In this context, food vs. fuel quickly boils down to a debate over the tangible benefits of corn-based ethanol as a fuel. There's growing evidence that those benefits have been oversold, despite industry claims.
Start with the widely touted study from Iowa State University indicating that ethanol saved consumers $1.09 per gallon at the gas pump in 2011 and $0.89/gal. in 2010. I read both the original study and its updated version when they came out. It seemed obvious to me that the authors' grasp of gasoline markets and oil refining were inadequate, but I lacked the time necessary to dig through their math to uncover the source of their exaggerated results. Fortunately, a pair of researchers from MIT and my alma mater, U.C. Davis, have now done that work and concluded that the Iowa State paper's findings--and the claims based on them--depended on a "spurious correlation": the relationships they saw were coincidental.
In contrast to the Iowa State studies, the MIT/Davis paper is very readable, and I recommend it to you. In addition to debunking the statistics, the authors point out the key flaws in their counterparts' logic. Foremost among these is that in order to have a large influence on gasoline prices, ethanol would have to have had a large impact on crude oil prices, which are the largest determinant of gas prices, by far. From 2005-11 US ethanol production expanded by 10 billion gallons per year, the energy equivalent of 350,000 barrels per day of oil, or 0.4% of 2011 global oil supply. I've argued many times that the oil market responds disproportionately to modest changes in supply and demand, but the idea that a few hundred thousand barrels per day could translate into the equivalent of $45/bbl exceeds the wildest dreams of any trader I ever met. The MIT paper concludes with the authors summarizing the likely impact of ethanol on gasoline prices as "near zero and statistically insignificant."
However, if ethanol hasn't done much to hold down gas prices, could a drop in US ethanol production resulting from paring back the ethanol mandate to reduce the pressure on corn prices cause a big spike in gasoline prices? That's where the analysis in a paper presented to members of Congress yesterday comes in. Dr. Elam's report suggests that rather than displacing imported crude oil, the main effect of increasing US ethanol use in fuels has been to divert domestic gasoline production into exports, while US crude imports have fallen based on a combination of lower demand (from the recession) and improved product yields per barrel of crude oil refined. Even if you are inclined to be skeptical of these findings because the study was supported by poultry interests, data from the US Energy Information Agency and elsewhere show that US refineries are not fully utilizing their capacity, are exporting significant volumes of gasoline, and have a wider array of domestic and imported crude oils at their disposal than they did just a few years ago. In short, we're in a far better position to forgo a few billion gallons of ethanol this year than we would have been in 2008, the last time food vs. fuel concerns spiked along with gas prices.
Corn growers have experienced droughts before, and in the past the price of corn sorted out who needed it most. However, the market can't prioritize fairly among the competing calls on a drought-diminished corn crop when the single largest segment of demand is locked in place by a federal mandate. This represents a massive distortion that only the government can rectify. I'm sympathetic to the ethanol industry's dilemma. After all, the federal government virtually begged them to overbuild capacity, but it couldn't guarantee they would earn a profit, even when it was providing a $0.45/gal. subsidy for their customers, who are required by law to use their main product. However, the economic and environmental benefits of ethanol are too modest to shield this industry while forcing all other corn users to absorb the likely shortfall in corn supply. The most sensible remedy would be to unshackle ethanol demand, at least temporarily, and waive at least a portion of the ethanol mandate for 2012-13.
Wednesday, July 18, 2012
Should the US Become An Oil Exporter, Again?
Last week I missed attending a fascinating panel on the growth of US oil production, hosted by the New America Foundation in Washington, D.C. Fortunately, I was able to catch most of the live webcast, which is still available for replay. Much of the discussion focused on the potential of new "tight oil" production techniques, similar to those used to extract shale gas, to help usher in a new period of relative oil abundance. If this comes to pass, among other things it could challenge long-established views about exporting US oil. The politics of oil exports look absolutely dire at the moment, but the economic and logistical benefits--not just for oil companies but to the nation--are such that we shouldn't dismiss the possibility lightly.
Two hours was not enough time to do justice to all the ramifications of resurgent US oil production, and I know from following the Twitter feed for the event that some in the web audience were frustrated by the limited attention given to the climate implications of these developments. However, if you'd like an overview of the possible economic and geopolitical impact of the US becoming more self-sufficient in petroleum for at least the next decade or two, this stellar panel was highly informative and worth your time. Much of the discussion focused on tight oil, liquid hydrocarbons trapped in rocks that can't be economically tapped by conventional drilling, but that have proved susceptible to combinations of horizontal drilling and hydraulic fracturing similar to those that have unleashed the current shale gas boom. Although the full potential of this resource hasn't been reflected in the latest forecasts from the Energy Information Agency (EIA) of the US Department of Energy, the results from the Bakken shale in the Dakotas and the Eagle Ford shale in Texas are instructive. Together these two fields now produce around 750,000 barrels per day, or 12% of current US crude oil output, up from just a trickle a few years ago. They also hold billions, and possibly tens of billions of barrels of recoverable resources.
I was a little surprised that the first panelist to mention the possibility of exporting some of this oil--with appropriate caveats--was Adam Sieminski, the newly confirmed EIA Administrator. After all, current US law restricts the export of most US crude oil production, with special exceptions for some oil from Alaska, California, and near the Canadian border. In practice, crude exports from those fields have declined to very low levels. Despite that, and even after significant reductions in imports since the onset of the recession, the US is still a major net oil importer. If that's the case, and if US refineries can benefit from the increasing domestic output, why would we even consider exporting any of this new oil?
Unfortunately, the answer doesn't reduce to a neat soundbite; it depends on two key factors that require a bit of explanation. The first issue is the quality of the oil coming out of these tight oil plays, which at least so far has been very high. Oil from different fields varies as much as fingerprints, even when we consider only a few characteristics of concern to refiners, and these differences strongly influence the market values of the various grades of oil. Light crudes refine easily into valuable products like gasoline, diesel and jet fuel, while heavier crudes require more processing, using more expensive hardware, and often yield large quantities of low-value products like petroleum coke, even after intensive refining. There's also sulfur content--the sweet to sour spectrum that overlays the light/heavy distinctions--as well as other impurities. Eagle Ford crude is light and sweet, as is the North Dakota Sweet crude produced from the Bakken. These crudes compare favorably with West Texas Intermediate (WTI), Brent and other premium crude streams.
The second, related factor involves the complexity of US oil refineries and the crude diet they've evolved to run. As production of high quality crudes in the continental US declined over the last four decades, many refiners invested billions of dollars to enable their facilities to run some of the heaviest, most sour crudes from around the world, because these were more readily available and usually significantly cheaper than the light sweet crudes. This trend was particularly evident on the West Coast and Gulf Coast. The addition of complex processing hardware like hydrocrackers, delayed or fluid cokers, and residuum fluid catalytic crackers has given these refineries tremendous flexibility, but it also increased their operating costs and made it harder for them to go back to a diet of much lighter crudes. As a result, while many of them could handle significant quantities of light crude from the tight oil fields, this would be less than optimal, resulting in economic penalties and perhaps eroding the advantages that have recently enabled gulf coast refiners to capitalize on export markets for their products. Those penalties would translate into discounts for the tight oil grades, compared to similar international crudes, much like the large gap in value we currently see for WTI compared to Brent, though for different reasons as discussed previously.
At current production levels, the mismatch of quality and capabilities isn't as big a problem as the lack of infrastructure for transporting these crudes to market. That has resulted in discounts so large that it makes sense for private equity firm Carlyle to plan to ship large quantities of Bakken crude by rail from North Dakota to the Philadelphia refinery they've just acquired from Sunoco. However, if tight oil output grows in line with forecasts such as those in a recent analysis from Citibank, domestic sweet crude refiners will have more than enough supply and the excess must either be sold to heavy crude refineries at a discount or left in the ground. That's where exports come in.
The last time exporting domestic crude became a big issue was in the late 1980s, when output from Alaska's North Slope (ANS) field reached peak levels of roughly 2 million barrels per day, far more than west coast refineries could absorb. I was trading crude on the West Coast at the time, and I observed first-hand the effects of the export restrictions that had been put in place when the Trans Alaska Pipeline was originally approved. Those restrictions didn't just depress the price of ANS crude; they also depressed the price of the California crudes with which ANS competed, and made both types less attractive to produce. West coast consumers benefited from a few years of lower gasoline prices than they would have otherwise paid, but the net result was less industry investment and probably higher oil imports in the long run. By the time ANS exports were finally approved in 1996, the field was already in decline and the biggest opportunity had been missed.
The advantages of allowing a portion of these new tight-oil streams to be exported would derive from the difference between the global market premium for crude of this quality and the typical discount paid for the lower-quality crudes that gulf coast refiners would continue to import in order to optimize their product yields and costs. A difference of just $5 per barrel across a million barrels per day of exports would translate into a nearly $2 billion per year improvement in the US trade balance. The benefits might also include higher tax revenues and royalties if exports supported higher production. The biggest drawback I see is that in the event of a global supply disruption, some domestic crude would be committed to non-US buyers, reducing our emergency cushion. However, that problem might be circumvented by requiring exporters to include provisions in their contracts allowing them to suspend deliveries whenever the US government released oil from the Strategic Petroleum Reserve, or a similar contingency.
Perhaps the best summary of the benefits that US oil exports could provide was given by President Clinton, when he authorized exports from the Alaskan North Slope: "Permitting this oil to move freely in international commerce will contribute to economic growth, reduce dependence on imported oil and create new jobs for American workers." It's probably premature to provide a similar exemption for tight oil now, but it's certainly not too soon to start the national debate that should precede such a decision.
Two hours was not enough time to do justice to all the ramifications of resurgent US oil production, and I know from following the Twitter feed for the event that some in the web audience were frustrated by the limited attention given to the climate implications of these developments. However, if you'd like an overview of the possible economic and geopolitical impact of the US becoming more self-sufficient in petroleum for at least the next decade or two, this stellar panel was highly informative and worth your time. Much of the discussion focused on tight oil, liquid hydrocarbons trapped in rocks that can't be economically tapped by conventional drilling, but that have proved susceptible to combinations of horizontal drilling and hydraulic fracturing similar to those that have unleashed the current shale gas boom. Although the full potential of this resource hasn't been reflected in the latest forecasts from the Energy Information Agency (EIA) of the US Department of Energy, the results from the Bakken shale in the Dakotas and the Eagle Ford shale in Texas are instructive. Together these two fields now produce around 750,000 barrels per day, or 12% of current US crude oil output, up from just a trickle a few years ago. They also hold billions, and possibly tens of billions of barrels of recoverable resources.
I was a little surprised that the first panelist to mention the possibility of exporting some of this oil--with appropriate caveats--was Adam Sieminski, the newly confirmed EIA Administrator. After all, current US law restricts the export of most US crude oil production, with special exceptions for some oil from Alaska, California, and near the Canadian border. In practice, crude exports from those fields have declined to very low levels. Despite that, and even after significant reductions in imports since the onset of the recession, the US is still a major net oil importer. If that's the case, and if US refineries can benefit from the increasing domestic output, why would we even consider exporting any of this new oil?
Unfortunately, the answer doesn't reduce to a neat soundbite; it depends on two key factors that require a bit of explanation. The first issue is the quality of the oil coming out of these tight oil plays, which at least so far has been very high. Oil from different fields varies as much as fingerprints, even when we consider only a few characteristics of concern to refiners, and these differences strongly influence the market values of the various grades of oil. Light crudes refine easily into valuable products like gasoline, diesel and jet fuel, while heavier crudes require more processing, using more expensive hardware, and often yield large quantities of low-value products like petroleum coke, even after intensive refining. There's also sulfur content--the sweet to sour spectrum that overlays the light/heavy distinctions--as well as other impurities. Eagle Ford crude is light and sweet, as is the North Dakota Sweet crude produced from the Bakken. These crudes compare favorably with West Texas Intermediate (WTI), Brent and other premium crude streams.
The second, related factor involves the complexity of US oil refineries and the crude diet they've evolved to run. As production of high quality crudes in the continental US declined over the last four decades, many refiners invested billions of dollars to enable their facilities to run some of the heaviest, most sour crudes from around the world, because these were more readily available and usually significantly cheaper than the light sweet crudes. This trend was particularly evident on the West Coast and Gulf Coast. The addition of complex processing hardware like hydrocrackers, delayed or fluid cokers, and residuum fluid catalytic crackers has given these refineries tremendous flexibility, but it also increased their operating costs and made it harder for them to go back to a diet of much lighter crudes. As a result, while many of them could handle significant quantities of light crude from the tight oil fields, this would be less than optimal, resulting in economic penalties and perhaps eroding the advantages that have recently enabled gulf coast refiners to capitalize on export markets for their products. Those penalties would translate into discounts for the tight oil grades, compared to similar international crudes, much like the large gap in value we currently see for WTI compared to Brent, though for different reasons as discussed previously.
At current production levels, the mismatch of quality and capabilities isn't as big a problem as the lack of infrastructure for transporting these crudes to market. That has resulted in discounts so large that it makes sense for private equity firm Carlyle to plan to ship large quantities of Bakken crude by rail from North Dakota to the Philadelphia refinery they've just acquired from Sunoco. However, if tight oil output grows in line with forecasts such as those in a recent analysis from Citibank, domestic sweet crude refiners will have more than enough supply and the excess must either be sold to heavy crude refineries at a discount or left in the ground. That's where exports come in.
The last time exporting domestic crude became a big issue was in the late 1980s, when output from Alaska's North Slope (ANS) field reached peak levels of roughly 2 million barrels per day, far more than west coast refineries could absorb. I was trading crude on the West Coast at the time, and I observed first-hand the effects of the export restrictions that had been put in place when the Trans Alaska Pipeline was originally approved. Those restrictions didn't just depress the price of ANS crude; they also depressed the price of the California crudes with which ANS competed, and made both types less attractive to produce. West coast consumers benefited from a few years of lower gasoline prices than they would have otherwise paid, but the net result was less industry investment and probably higher oil imports in the long run. By the time ANS exports were finally approved in 1996, the field was already in decline and the biggest opportunity had been missed.
The advantages of allowing a portion of these new tight-oil streams to be exported would derive from the difference between the global market premium for crude of this quality and the typical discount paid for the lower-quality crudes that gulf coast refiners would continue to import in order to optimize their product yields and costs. A difference of just $5 per barrel across a million barrels per day of exports would translate into a nearly $2 billion per year improvement in the US trade balance. The benefits might also include higher tax revenues and royalties if exports supported higher production. The biggest drawback I see is that in the event of a global supply disruption, some domestic crude would be committed to non-US buyers, reducing our emergency cushion. However, that problem might be circumvented by requiring exporters to include provisions in their contracts allowing them to suspend deliveries whenever the US government released oil from the Strategic Petroleum Reserve, or a similar contingency.
Perhaps the best summary of the benefits that US oil exports could provide was given by President Clinton, when he authorized exports from the Alaskan North Slope: "Permitting this oil to move freely in international commerce will contribute to economic growth, reduce dependence on imported oil and create new jobs for American workers." It's probably premature to provide a similar exemption for tight oil now, but it's certainly not too soon to start the national debate that should precede such a decision.
Wednesday, July 11, 2012
The 2013 US Energy Agenda
It's tempting to focus mainly on the energy issues that have come up in the context of the presidential campaign, such as the Keystone XL pipeline, tax breaks for energy companies, and whether and how to regulate hydraulic fracturing, a.k.a "fracking". Yet whoever is inaugurated next January, and however he resolves these issues, he will also face a much wider array of energy concerns, including some that are outgrowths of current policies or have emerged after a long gestation. Though not intended as an exhaustive list, here are a few such issues that merit close attention from the next president's energy team.
They should begin by taking a fresh and objective look at the overall US energy posture and devising a clear and concise way to describe it to the public. Big changes have taken place, with many of the issues that preoccupied us for the last decade or longer having become less relevant or out of date. Topping that list is the sense of energy scarcity that has burdened us since the oil crises of the 1970s and early 1980s. There's a realistic possibility that the combination of "tight oil" and the gas liquids production from shale gas could push domestic US petroleum/liquids production back above its early '70s peak of around 11 million barrels per day. At the same time, our net oil imports are declining, due in large part to the weak economy. However, as the share of fuel efficient vehicles in our car fleet increases, it's reasonable to think that we've already seen the peak of US demand for petroleum fuels, even after the economy returns to healthy growth. The net result might fall short of energy independence, but it will put us in a much better position than our largest economic rivals in terms of real energy security.
Then there's shale gas. Not only has it reversed a worrisome decline in US natural gas production that prompted numerous projects to import liquefied natural gas (LNG), but it has upended our assumptions about future prices and emissions in the electric power sector, while completing the divorce of oil and electricity that began in the 1980s. Now we're talking seriously about exporting natural gas. When you combine all these changes with biofuels that are contributing roughly a million barrels per day to US supply (in volumetric, though not BTU-equivalent terms) the need to revisit some of our most basic assumptions about energy looks compelling.
Energy scarcity isn't the only paradigm that needs to be rethought. The current administration apparently took office with a view that was prevalent in the environmental community and among some in energy circles, that the solutions to climate change and energy security were effectively synonymous and synergistic. That view predates the shale/tight oil revolution and was founded on the notion that renewable energy and efficiency were the only serious answers to both concerns. That linkage was always oversimplified, because it ignored the trade-offs inherent in the shortcomings of every energy technology available. And now, thanks to unexpected technological developments, we face an explicit choice between energy abundance based on hydrocarbons and a lower-emissions future based on renewables and electric vehicles that won't reach the required scale for decades, despite promising early signs. The transition from the former to the latter appears long and largely unpredictable, nor will it be cheap.
The next administration also faces a set of practical issues, along with the big-picture reframing described above. Two of these issues involve urgent tasks. The first is the growing need for a thorough evaluation of the recent and current approach to incentivizing renewable energy technologies and projects. Since early 2009 we've spent tens of billions of dollars on a constellation of federal grants, tax credits, and loan guarantees to stimulate the growth of a domestic renewable and advanced energy industry and the deployment of its products. There's a lot of new hardware on the ground, but the sustainability of this industry looks uncertain. Although only a fraction of the companies that received federal support have failed, the tally has grown large enough--with the addition of Abound Solar last week--that it's no longer acceptable merely to shrug off these losses as par for the course. We need some hard-nosed, detail-oriented outsiders to conduct a comprehensive post-expenditure review and extract the major lessons learned. That should be an absolute prerequisite before anyone contemplates renewing or expanding any of these programs, including the Pentagon's $210 million "green fleet" program.
Another urgent clean-up task is the reform of the federal Renewable Fuel Standard (RFS). This 2007 mandate was premised on the imminent arrival of cellulosic biofuel technologies that have turned out to be much harder than expected to transfer from demonstration to commercial scale. That has resulted in drastic annual revisions to the cellulosic biofuel targets of the mandate, but even these lower targets have not been achieved. Instead, the EPA imposes penalties on refiners and gasoline blenders for failing to blend non-existent volumes, with consumers ultimately absorbing the higher costs at the pump. The attractive vision of abundant renewable fuels has thus turned into a bureaucratic game. And while corn ethanol supplies 10% of gasoline and consumes nearly 40% of the US corn crop, it cannot more than double to meet the entire 36 billion gallon per year RFS target for 2022, nor should we wish it to. Instead, the RFS must be updated to reflect reality, and the associated biofuel-credit trading system should be restructured to squeeze out the fraud that is infecting it, instead of leaving refiners and blenders--and again ultimately consumers--to pick up a tab estimated at $200 million.
These items don't constitute an entire energy agenda by themselves, but together with a few higher-profile proposals from among those that both campaigns will announce and debate during the next four months, they could fill out a worthy first-hundred-days' energy plan for 2013.
They should begin by taking a fresh and objective look at the overall US energy posture and devising a clear and concise way to describe it to the public. Big changes have taken place, with many of the issues that preoccupied us for the last decade or longer having become less relevant or out of date. Topping that list is the sense of energy scarcity that has burdened us since the oil crises of the 1970s and early 1980s. There's a realistic possibility that the combination of "tight oil" and the gas liquids production from shale gas could push domestic US petroleum/liquids production back above its early '70s peak of around 11 million barrels per day. At the same time, our net oil imports are declining, due in large part to the weak economy. However, as the share of fuel efficient vehicles in our car fleet increases, it's reasonable to think that we've already seen the peak of US demand for petroleum fuels, even after the economy returns to healthy growth. The net result might fall short of energy independence, but it will put us in a much better position than our largest economic rivals in terms of real energy security.
Then there's shale gas. Not only has it reversed a worrisome decline in US natural gas production that prompted numerous projects to import liquefied natural gas (LNG), but it has upended our assumptions about future prices and emissions in the electric power sector, while completing the divorce of oil and electricity that began in the 1980s. Now we're talking seriously about exporting natural gas. When you combine all these changes with biofuels that are contributing roughly a million barrels per day to US supply (in volumetric, though not BTU-equivalent terms) the need to revisit some of our most basic assumptions about energy looks compelling.
Energy scarcity isn't the only paradigm that needs to be rethought. The current administration apparently took office with a view that was prevalent in the environmental community and among some in energy circles, that the solutions to climate change and energy security were effectively synonymous and synergistic. That view predates the shale/tight oil revolution and was founded on the notion that renewable energy and efficiency were the only serious answers to both concerns. That linkage was always oversimplified, because it ignored the trade-offs inherent in the shortcomings of every energy technology available. And now, thanks to unexpected technological developments, we face an explicit choice between energy abundance based on hydrocarbons and a lower-emissions future based on renewables and electric vehicles that won't reach the required scale for decades, despite promising early signs. The transition from the former to the latter appears long and largely unpredictable, nor will it be cheap.
The next administration also faces a set of practical issues, along with the big-picture reframing described above. Two of these issues involve urgent tasks. The first is the growing need for a thorough evaluation of the recent and current approach to incentivizing renewable energy technologies and projects. Since early 2009 we've spent tens of billions of dollars on a constellation of federal grants, tax credits, and loan guarantees to stimulate the growth of a domestic renewable and advanced energy industry and the deployment of its products. There's a lot of new hardware on the ground, but the sustainability of this industry looks uncertain. Although only a fraction of the companies that received federal support have failed, the tally has grown large enough--with the addition of Abound Solar last week--that it's no longer acceptable merely to shrug off these losses as par for the course. We need some hard-nosed, detail-oriented outsiders to conduct a comprehensive post-expenditure review and extract the major lessons learned. That should be an absolute prerequisite before anyone contemplates renewing or expanding any of these programs, including the Pentagon's $210 million "green fleet" program.
Another urgent clean-up task is the reform of the federal Renewable Fuel Standard (RFS). This 2007 mandate was premised on the imminent arrival of cellulosic biofuel technologies that have turned out to be much harder than expected to transfer from demonstration to commercial scale. That has resulted in drastic annual revisions to the cellulosic biofuel targets of the mandate, but even these lower targets have not been achieved. Instead, the EPA imposes penalties on refiners and gasoline blenders for failing to blend non-existent volumes, with consumers ultimately absorbing the higher costs at the pump. The attractive vision of abundant renewable fuels has thus turned into a bureaucratic game. And while corn ethanol supplies 10% of gasoline and consumes nearly 40% of the US corn crop, it cannot more than double to meet the entire 36 billion gallon per year RFS target for 2022, nor should we wish it to. Instead, the RFS must be updated to reflect reality, and the associated biofuel-credit trading system should be restructured to squeeze out the fraud that is infecting it, instead of leaving refiners and blenders--and again ultimately consumers--to pick up a tab estimated at $200 million.
These items don't constitute an entire energy agenda by themselves, but together with a few higher-profile proposals from among those that both campaigns will announce and debate during the next four months, they could fill out a worthy first-hundred-days' energy plan for 2013.
Thursday, July 05, 2012
A Sign of Sanity in Solar Manufacturing
I've been writing for some time about the chronic overcapacity in global solar manufacturing and the consolidation this is likely to produce. Now here's a sign that at least one company realizes how bad the situation is. GE is apparently delaying the construction of its previously announced Aurora, Colorado, thin-film solar panel factory, and "taking this opportunity to re-look at our solar strategy." I couldn't find a GE press release to back this up, but it's been reported by RECharge and confirmed by Forbes. It's easy to read too much into a single event, but I think this looks significant, particularly in the wake of Monday's Chapter 7 bankruptcy filing by Abound Solar, incidentally another recipient of a sizable federal renewable energy loan guarantee.
If this information is correct, GE is backing away--for at least 18 months--from building a 400 MW thin-film photovoltaic (PV) solar line in Colorado. That suggests that they have concluded that even a brand new facility using the latest technology and large enough to compete on scale with thin-film leader First Solar wouldn't be able to earn an attractive margin in this market. And as a global competitor, GE would presumably regard the new US tariffs on China-based PV manufacturers as insufficient to resolve global PV overcapacity that appears to be stuck at about the same magnitude as demand, despite the continued rapid growth of the latter.
In the last year I've seen numerous articles and blog posts attributing the recent PV price declines to the predicted scale-related effects that have long anchored the industry's central narrative: If we build and deploy enough PV, the cost will fall to the point at which it will be competitive with conventional electricity generation. That may still be true in the long run, but few of these advocates seem to have understood that the industry was getting ahead of its own narrative--that a big slice of the recent price declines was the result of intense competition among producers who over-expanded and whose margins have contracted sharply or turned negative in the process. That's a good reason for GE to hit the pause button and focus on improving its technology in the lab, rather than the fab, while other, less well-capitalized firms struggle to survive long enough to participate in the expected growth surge when solar reaches "grid parity" on a sustainable basis.
PV is an important energy technology with a bright future, but its present doesn't look so great. It's not unusual for manufacturing industries to experience boom-bust cycles, though in my experience those are more common in commodities like chemicals and fuels. However, it is distinctly unusual for governments to contribute so much to the inflation of the boom part of the cycle through a wide array of incentives, loan guarantees and loans to manufacturers and with subsidies--in some cases extravagantly generous ones--to the industry's customers. Such interference may have been necessary to jump-start PV supply and demand, but it will almost certainly make for a harder and messier landing for companies, investors and employees, and in cases like that of Abound Solar for taxpayers.
If this information is correct, GE is backing away--for at least 18 months--from building a 400 MW thin-film photovoltaic (PV) solar line in Colorado. That suggests that they have concluded that even a brand new facility using the latest technology and large enough to compete on scale with thin-film leader First Solar wouldn't be able to earn an attractive margin in this market. And as a global competitor, GE would presumably regard the new US tariffs on China-based PV manufacturers as insufficient to resolve global PV overcapacity that appears to be stuck at about the same magnitude as demand, despite the continued rapid growth of the latter.
In the last year I've seen numerous articles and blog posts attributing the recent PV price declines to the predicted scale-related effects that have long anchored the industry's central narrative: If we build and deploy enough PV, the cost will fall to the point at which it will be competitive with conventional electricity generation. That may still be true in the long run, but few of these advocates seem to have understood that the industry was getting ahead of its own narrative--that a big slice of the recent price declines was the result of intense competition among producers who over-expanded and whose margins have contracted sharply or turned negative in the process. That's a good reason for GE to hit the pause button and focus on improving its technology in the lab, rather than the fab, while other, less well-capitalized firms struggle to survive long enough to participate in the expected growth surge when solar reaches "grid parity" on a sustainable basis.
PV is an important energy technology with a bright future, but its present doesn't look so great. It's not unusual for manufacturing industries to experience boom-bust cycles, though in my experience those are more common in commodities like chemicals and fuels. However, it is distinctly unusual for governments to contribute so much to the inflation of the boom part of the cycle through a wide array of incentives, loan guarantees and loans to manufacturers and with subsidies--in some cases extravagantly generous ones--to the industry's customers. Such interference may have been necessary to jump-start PV supply and demand, but it will almost certainly make for a harder and messier landing for companies, investors and employees, and in cases like that of Abound Solar for taxpayers.
Friday, June 29, 2012
Could Oil's Surge Sink Renewable Energy?
A new forecast of global oil production by the end of the decade attracted a fair amount of attention this week. The study, from Harvard's Kennedy School of Government, indicates that oil production could expand by about 20% by 2020 from current levels. The Wall St. Journal's Heard on the Street column cited this in support of the view that the influence of "peak oil" on the market has itself peaked and fallen into decline. I was particularly intrigued by a scenario suggested in MIT's Technology Review that this wave of new oil supplies could trigger an oil price collapse similar to the one in the mid-1980s that helped roll back the renewable energy programs that were started during the oil crises of the 1970s. That's possible, though I'm not sure this should be the biggest worry that manufacturers of wind turbines and solar panels have today.
The Harvard forecast is based on a detailed, risked country-by-country assessment of production potential, with the bulk of the projected net increase in capacity from today's level of around 93 million barrels per day (MBD) to just over 110 MBD coming from four countries: Iraq, the US, Canada and Brazil. However, the study's lead author, former Eni executive Leonardo Maugeri, sees broad capacity growth in nearly all of today's producing countries, except for Iran, Mexico, Norway and the UK. Although this is certainly a diametrically opposed view of oil's trajectory than the one promoted by advocates of the peak oil viewpoint, it is accompanied by the customary caveats about political and other risks, along with new concerns about environmental push-back. The latter point is particularly important, since much of the expansion is based on what Mr. Maugeri refers to as the "de-conventionalization of oil supplies", based on the expansion of unconventional output from heavy oil, oil sands, Brazil's "pre-salt" oil, and the "tight oil" that has reversed the US production decline.
Although this de-conventionalization trend is very real, it's one thing to envision a shift to an environment in which oil supplies could accommodate, rather than constrain global economic growth; it's another to see these new supplies bringing about an oil price collapse. It's helpful in this regard to consider the three previous oil-price collapses that we've experienced in the last several decades. The mid-1980s collapse is the one that Kevin Bullis of Technology Review seems to have latched onto, because much like today's expansion of unconventional oil, the wave of new non-OPEC production that broke OPEC's hold on the market was the direct result of the sharp oil price increases of the previous decade, after allowing for inherent development time lags. The analogy to this period looks even more interesting if the new Administrator of the Energy Information Agency of the Department of Energy is correct in speculating that the US government might be willing to allow exports of light sweet crude from the Bakken, Eagle Ford and other shale plays, to enable Gulf Coast refineries to continue to run the imported heavy crudes for which they have been optimized at great expense. That could dramatically alter the dynamics of the global oil market.
However, I see two significant differences in the circumstances of the 1980s price collapse, compared to today. First, oil consumption was then dominated by a small number of industrialized countries, the economies of which were still much more reliant on oil for economic growth than they are today. Second, these economies were already emerging from the major recession of the late-1970s and early '80s--a downturn in which the 1970s' energy price spikes played a leading role. For example, US GDP grew at an annual rate of 7.2% in 1984, the year before oil prices began their slide from the high $20s to mid-teens per barrel. So when new supplies from the North Slope and North Sea came onstream, the market was ready and eager to use them. Lower, relatively stable oil prices persisted for more than a decade.
Current global economic conditions have much more in common with either the late-1990s Asian Economic Crisis or the combined recession and financial crisis from which we're still emerging. Each of these situations included a short-lived global oil price collapse that ended when OPEC constrained output and the economy moved past the point of sharpest contraction. The late-90s oil price collapse looks especially relevant for today, because increased production contributed to it.
A new factor that would tend to make any oil-price slump due to unconventional oil self-limiting is its relatively high cost. Mr. Maugeri makes it clear that his output forecast depends on prices remaining generally above $70/bbl, and that any drop below $50-60/bbl would result in curtailed investment and slower expansion. The picture that this paints for me is one in which new oil supplies would be there if we need them to meet growing demand but not otherwise. That should narrow the implications of such an expansion for renewable energy.
As Mr. Bullis reminds his readers, the connection between oil and renewable energy is much more tenuous than many of the latter's proponents imagine. The US gets less than 1% of its electricity supply from burning oil, so technologies like wind and solar power simply have no bearing on oil consumption, and vice versa. That is less true outside the US, but the trends there are also moving in this direction. So other than for biofuels, a steep drop in oil prices for any reason would have little impact on the rationale for renewables, except perhaps psychologically. The two factors on which renewable energy investors and manufacturers should stay focused are the economy and the price of natural gas, against which renewables actually do compete and have generally been losing the battle, recently.
Time will tell whether the Harvard oil production forecast turns out to be more accurate than other, more pessimistic views. Yet while a drop in oil prices due to expanding supply wouldn't do any good for renewables, the single biggest risk the latter face is the same one that would be likeliest to trigger a major oil price collapse: not surging unconventional oil output, the impact of which OPEC will strive hard to manage, but a return to the kind of weak economy and frozen credit that we should all be able to recall vividly. If anything, the consequences for renewables from that risk look much bigger today than a couple of years ago, because of the global overcapacity in wind turbine and solar panel manufacturing that built up as the industry responded to policy-induced irrational exuberance in several key markets.
The Harvard forecast is based on a detailed, risked country-by-country assessment of production potential, with the bulk of the projected net increase in capacity from today's level of around 93 million barrels per day (MBD) to just over 110 MBD coming from four countries: Iraq, the US, Canada and Brazil. However, the study's lead author, former Eni executive Leonardo Maugeri, sees broad capacity growth in nearly all of today's producing countries, except for Iran, Mexico, Norway and the UK. Although this is certainly a diametrically opposed view of oil's trajectory than the one promoted by advocates of the peak oil viewpoint, it is accompanied by the customary caveats about political and other risks, along with new concerns about environmental push-back. The latter point is particularly important, since much of the expansion is based on what Mr. Maugeri refers to as the "de-conventionalization of oil supplies", based on the expansion of unconventional output from heavy oil, oil sands, Brazil's "pre-salt" oil, and the "tight oil" that has reversed the US production decline.
Although this de-conventionalization trend is very real, it's one thing to envision a shift to an environment in which oil supplies could accommodate, rather than constrain global economic growth; it's another to see these new supplies bringing about an oil price collapse. It's helpful in this regard to consider the three previous oil-price collapses that we've experienced in the last several decades. The mid-1980s collapse is the one that Kevin Bullis of Technology Review seems to have latched onto, because much like today's expansion of unconventional oil, the wave of new non-OPEC production that broke OPEC's hold on the market was the direct result of the sharp oil price increases of the previous decade, after allowing for inherent development time lags. The analogy to this period looks even more interesting if the new Administrator of the Energy Information Agency of the Department of Energy is correct in speculating that the US government might be willing to allow exports of light sweet crude from the Bakken, Eagle Ford and other shale plays, to enable Gulf Coast refineries to continue to run the imported heavy crudes for which they have been optimized at great expense. That could dramatically alter the dynamics of the global oil market.
However, I see two significant differences in the circumstances of the 1980s price collapse, compared to today. First, oil consumption was then dominated by a small number of industrialized countries, the economies of which were still much more reliant on oil for economic growth than they are today. Second, these economies were already emerging from the major recession of the late-1970s and early '80s--a downturn in which the 1970s' energy price spikes played a leading role. For example, US GDP grew at an annual rate of 7.2% in 1984, the year before oil prices began their slide from the high $20s to mid-teens per barrel. So when new supplies from the North Slope and North Sea came onstream, the market was ready and eager to use them. Lower, relatively stable oil prices persisted for more than a decade.
Current global economic conditions have much more in common with either the late-1990s Asian Economic Crisis or the combined recession and financial crisis from which we're still emerging. Each of these situations included a short-lived global oil price collapse that ended when OPEC constrained output and the economy moved past the point of sharpest contraction. The late-90s oil price collapse looks especially relevant for today, because increased production contributed to it.
A new factor that would tend to make any oil-price slump due to unconventional oil self-limiting is its relatively high cost. Mr. Maugeri makes it clear that his output forecast depends on prices remaining generally above $70/bbl, and that any drop below $50-60/bbl would result in curtailed investment and slower expansion. The picture that this paints for me is one in which new oil supplies would be there if we need them to meet growing demand but not otherwise. That should narrow the implications of such an expansion for renewable energy.
As Mr. Bullis reminds his readers, the connection between oil and renewable energy is much more tenuous than many of the latter's proponents imagine. The US gets less than 1% of its electricity supply from burning oil, so technologies like wind and solar power simply have no bearing on oil consumption, and vice versa. That is less true outside the US, but the trends there are also moving in this direction. So other than for biofuels, a steep drop in oil prices for any reason would have little impact on the rationale for renewables, except perhaps psychologically. The two factors on which renewable energy investors and manufacturers should stay focused are the economy and the price of natural gas, against which renewables actually do compete and have generally been losing the battle, recently.
Time will tell whether the Harvard oil production forecast turns out to be more accurate than other, more pessimistic views. Yet while a drop in oil prices due to expanding supply wouldn't do any good for renewables, the single biggest risk the latter face is the same one that would be likeliest to trigger a major oil price collapse: not surging unconventional oil output, the impact of which OPEC will strive hard to manage, but a return to the kind of weak economy and frozen credit that we should all be able to recall vividly. If anything, the consequences for renewables from that risk look much bigger today than a couple of years ago, because of the global overcapacity in wind turbine and solar panel manufacturing that built up as the industry responded to policy-induced irrational exuberance in several key markets.
Wednesday, June 27, 2012
Does All-of-the-Above Energy Include Long Shots?
An article in Tuesday's Washington Post described the current funding woes of US research into nuclear fusion, focused on anticipated budget and job cuts at the Princeton Plasma Physics Laboratory, MIT and several other sites. Aside from the general challenge of funding all of the Department of Energy's programs at a time of huge federal deficits and ballooning debt, it appears that domestic fusion research is being cut mainly to meet our commitments to the International Thermonuclear Experimental Reactor (ITER) being built in France. The article goes on to suggest that fusion has been excluded from the list of "all-of-the-above" energy technologies that the administration has embraced. That raises questions that would merit attention at any time but seem particularly relevant in an election year.
Before discussing its proper priority in US federal energy research and planning, it's important to recognize, as the article does, that fusion is very much a long-shot bet. We know that nuclear fusion works, because it's the process that powers our sun and all the stars. However, that doesn't guarantee that we can successfully harness it safely here on earth for our own purposes. I've heard plenty of energy experts who think that the only fusion reactor we need is the one 93 million miles away, which remains the ultimate source of nearly all the BTUs and kilowatt-hours of energy we use, except for those from nuclear (fission) power plants and geothermal energy.
Unfortunately, the challenges of harnessing the sun's energy bounty in real time, rather than via the geologically slow processes that produced fossil fuels or the faster but still ponderous growing cycles of biofuels, are distinctly non-trivial--hence the debate about whether and how to overcome the intermittency and cyclicality of wind and solar power through optimized dispersal, clever use of Smart Grid technology, or with energy storage that requires its own breakthroughs if it is to be an economical enabler of wind or solar. A working fusion reactor would provide an end-run around all those problems and fit neatly into our current centralized power grid, with what is expected to be negligible emissions or long-term waste. Who wouldn't want that?
Of course fusion power isn't easy, either; it's the definition of difficult. Scientists around the world have been chasing it for at least five decades. I recall eagerly reading about its potential when I was in my early teens. Then, it was seen to be 30-40 years from becoming commercial, and that's still a reasonable estimate, despite significant progress in the intervening decades. I admit I don't follow fusion research nearly as closely as I used to, in all its permutations of stellarators, tokamaks, laser bombardment chambers and other competing designs, all pursuing the elusive goal of "net energy"--getting more energy back than you must put into achieving the temperatures and pressures necessary to fuse the chosen hydrogen isotopes.
So where does a high-risk, high-reward investment like fusion fit into the concept of all-of-the-above energy that now dominates the energy debate on both sides of the political aisle, and in the trade-offs that must accompany any serious energy strategy or plan for the US? After all, "all of the above" is an attempt to recognize the widely differing states of readiness of our various energy options, the time lags inherent in replacing one set of sources with another, and the need to continue to supply and consume fossil fuels during our (long) transition away from them. While I've never seen an official list of what's in and what's out, my own sense of all of the above is that it's composed of technologies that are either commercial today or that have left the laboratory but still require improvement and scaling up to become commercial. In contrast, fusion hasn't left the lab and it's not clear when or if it will, at least on a timescale that's meaningful either for energy security or climate change mitigation. No one can tell us when the first fusion power plant could be plugged into the grid, and every attempt at predicting that has slipped, badly.
Fusion wasn't mentioned once in the Secretary of Energy's remarks to Congress concerning the fiscal 2013 Energy Department Budget, and it was only shown as a line item in his latest budget presentation. Yet I can't think of any other new technology that's customarily included in all of the above that has even a fraction of fusion's potential for delivering clean energy in large, centralized increments comparable to today's coal or nuclear power plants. We could spend all day arguing whether that's as desirable now (or in the future) as it was just a few years ago, but from my perspective it contributes to the option value of fusion. No one would suggest fusion as a practical near-term alternative, but with the prospect of a shale-gas bridge for the next several decades, it might be an important part of what we could be bridging towards.
Overall, the DOE has budgeted just under $400 million for fusion R&D in fiscal 2013, out of a total budget request of $27 billion. That's not insignificant, and devoting 1.5% of the federal energy budget to fusion might be about the right proportion for such a long-term endeavor that is decades from deployment, relative to funding for medium-term efforts like advanced fission reactors and near-term R&D on renewables and efficiency. The problem is that DOE is cutting deeply into US fusion capabilities, not just at Princeton but also at Lawrence Berkeley Laboratory, Livermore, Los Alamos and Sandia, in order to boost US funding for ITER from $105 million to $150 million next year. Only the fusion budgets for Oak Ridge Laboratory, which is managing the US role in ITER, and for the D.C. HQ grew.
I'm certainly not against international cooperation in science, which has become increasingly important as the costs of "big science" projects expand. However, even if ITER represented the very best chance to take fusion to the next level on its long path to deployment, the long-term implications of these cuts for US fusion science capabilities look significant. As with the space program, once the highly trained and experienced fusion workforce and teams are laid off and broken up, it becomes enormously difficult to reconstitute them, if needed. This is particularly true of those with advanced degrees in fields that have declined in popularity at US universities, or for which the majority of current graduates are non-US students who will return to their countries of origin in search of better opportunities. I wouldn't support keeping these programs going just to provide guaranteed employment for physicists, but we had better be sure that we won't need them later. I am skeptical that we can be sufficiently certain today of the likely deployment pathways for fusion to be able to make such an irreversible decision with confidence.
I understand that in times like these we must make tough choices; that's the essence of budgeting. I'm also sympathetic to those who might think that fusion researchers have had ample time and support to deliver the goods, already. Yet I can't help being struck by the contradiction of a DOE budget in which US R&D for such a long-term, high-potential technology is cut, at the same time that Secretary Chu and the President are pushing hard for multi-billion dollar commitments to extend the Production Tax Credit for renewable energy and reinstate the expired 1603 renewable energy cash grant program, a substantial portion of the past benefits from which went to non-US manufacturers and project developers. The total 2013 budget cuts for the US fusion labs are equivalent to the tax credits for a single 90 MW wind farm, which would contribute less than 0.01% of annual US power generation. Although we clearly can't fund every R&D idea to the extent researchers might wish, I believe it is a mistake to funnel so much money--about 40% of which must be borrowed--into perpetual support for the deployment of relatively low-impact and essentially mature technologies like onshore wind, when the same dollars would go much farther on R&D.
Before discussing its proper priority in US federal energy research and planning, it's important to recognize, as the article does, that fusion is very much a long-shot bet. We know that nuclear fusion works, because it's the process that powers our sun and all the stars. However, that doesn't guarantee that we can successfully harness it safely here on earth for our own purposes. I've heard plenty of energy experts who think that the only fusion reactor we need is the one 93 million miles away, which remains the ultimate source of nearly all the BTUs and kilowatt-hours of energy we use, except for those from nuclear (fission) power plants and geothermal energy.
Unfortunately, the challenges of harnessing the sun's energy bounty in real time, rather than via the geologically slow processes that produced fossil fuels or the faster but still ponderous growing cycles of biofuels, are distinctly non-trivial--hence the debate about whether and how to overcome the intermittency and cyclicality of wind and solar power through optimized dispersal, clever use of Smart Grid technology, or with energy storage that requires its own breakthroughs if it is to be an economical enabler of wind or solar. A working fusion reactor would provide an end-run around all those problems and fit neatly into our current centralized power grid, with what is expected to be negligible emissions or long-term waste. Who wouldn't want that?
Of course fusion power isn't easy, either; it's the definition of difficult. Scientists around the world have been chasing it for at least five decades. I recall eagerly reading about its potential when I was in my early teens. Then, it was seen to be 30-40 years from becoming commercial, and that's still a reasonable estimate, despite significant progress in the intervening decades. I admit I don't follow fusion research nearly as closely as I used to, in all its permutations of stellarators, tokamaks, laser bombardment chambers and other competing designs, all pursuing the elusive goal of "net energy"--getting more energy back than you must put into achieving the temperatures and pressures necessary to fuse the chosen hydrogen isotopes.
So where does a high-risk, high-reward investment like fusion fit into the concept of all-of-the-above energy that now dominates the energy debate on both sides of the political aisle, and in the trade-offs that must accompany any serious energy strategy or plan for the US? After all, "all of the above" is an attempt to recognize the widely differing states of readiness of our various energy options, the time lags inherent in replacing one set of sources with another, and the need to continue to supply and consume fossil fuels during our (long) transition away from them. While I've never seen an official list of what's in and what's out, my own sense of all of the above is that it's composed of technologies that are either commercial today or that have left the laboratory but still require improvement and scaling up to become commercial. In contrast, fusion hasn't left the lab and it's not clear when or if it will, at least on a timescale that's meaningful either for energy security or climate change mitigation. No one can tell us when the first fusion power plant could be plugged into the grid, and every attempt at predicting that has slipped, badly.
Fusion wasn't mentioned once in the Secretary of Energy's remarks to Congress concerning the fiscal 2013 Energy Department Budget, and it was only shown as a line item in his latest budget presentation. Yet I can't think of any other new technology that's customarily included in all of the above that has even a fraction of fusion's potential for delivering clean energy in large, centralized increments comparable to today's coal or nuclear power plants. We could spend all day arguing whether that's as desirable now (or in the future) as it was just a few years ago, but from my perspective it contributes to the option value of fusion. No one would suggest fusion as a practical near-term alternative, but with the prospect of a shale-gas bridge for the next several decades, it might be an important part of what we could be bridging towards.
Overall, the DOE has budgeted just under $400 million for fusion R&D in fiscal 2013, out of a total budget request of $27 billion. That's not insignificant, and devoting 1.5% of the federal energy budget to fusion might be about the right proportion for such a long-term endeavor that is decades from deployment, relative to funding for medium-term efforts like advanced fission reactors and near-term R&D on renewables and efficiency. The problem is that DOE is cutting deeply into US fusion capabilities, not just at Princeton but also at Lawrence Berkeley Laboratory, Livermore, Los Alamos and Sandia, in order to boost US funding for ITER from $105 million to $150 million next year. Only the fusion budgets for Oak Ridge Laboratory, which is managing the US role in ITER, and for the D.C. HQ grew.
I'm certainly not against international cooperation in science, which has become increasingly important as the costs of "big science" projects expand. However, even if ITER represented the very best chance to take fusion to the next level on its long path to deployment, the long-term implications of these cuts for US fusion science capabilities look significant. As with the space program, once the highly trained and experienced fusion workforce and teams are laid off and broken up, it becomes enormously difficult to reconstitute them, if needed. This is particularly true of those with advanced degrees in fields that have declined in popularity at US universities, or for which the majority of current graduates are non-US students who will return to their countries of origin in search of better opportunities. I wouldn't support keeping these programs going just to provide guaranteed employment for physicists, but we had better be sure that we won't need them later. I am skeptical that we can be sufficiently certain today of the likely deployment pathways for fusion to be able to make such an irreversible decision with confidence.
I understand that in times like these we must make tough choices; that's the essence of budgeting. I'm also sympathetic to those who might think that fusion researchers have had ample time and support to deliver the goods, already. Yet I can't help being struck by the contradiction of a DOE budget in which US R&D for such a long-term, high-potential technology is cut, at the same time that Secretary Chu and the President are pushing hard for multi-billion dollar commitments to extend the Production Tax Credit for renewable energy and reinstate the expired 1603 renewable energy cash grant program, a substantial portion of the past benefits from which went to non-US manufacturers and project developers. The total 2013 budget cuts for the US fusion labs are equivalent to the tax credits for a single 90 MW wind farm, which would contribute less than 0.01% of annual US power generation. Although we clearly can't fund every R&D idea to the extent researchers might wish, I believe it is a mistake to funnel so much money--about 40% of which must be borrowed--into perpetual support for the deployment of relatively low-impact and essentially mature technologies like onshore wind, when the same dollars would go much farther on R&D.
Wednesday, June 20, 2012
Does Energy-Related Drilling Trigger Earthquakes?
Last week the National Research Council published a comprehensive study of the seismic hazards and risks of a variety of energy-related drilling activities. Despite widely publicized reports of drilling-related quakes in Ohio and Arkansas, the report concluded that such events are very rare, compared to both the total number of wells drilled and to naturally occurring earthquakes. Nor are the technologies with the highest rates of induced seismicity necessarily the ones that come first to mind. Rather than ignoring these risks because of their rarity, the committee of university and industry experts that produced the report recommended the development of new protocols for monitoring and managing these risks, as well as further research into the potential for induced seismicity from emerging technologies like carbon capture and storage (CCS.)
The study encompassed four categories of energy-related drilling, including oil & gas exploration and production, geothermal energy, liquid disposal wells, and CCS. Within oil & gas, they looked at conventional production and "enhanced recovery", along with hydraulic fracturing or "fracking". The latter two techniques involve pumping water or some other fluid into a reservoir to stimulate production. For geothermal, they considered conventional geothermal, both liquid- and vapor-dominated reservoirs, and "enhanced" or engineered geothermal systems, which pump fluid into hot, dry rock to extract useful heat. They found recorded seismic events in all categories and sub-categories, though again the numbers are small, particularly for quakes large enough to cause damage: Fewer than 160 recorded events globally over magnitude 2.0 within a period of about 30 years from a well population in the millions, and against a natural annual background of 1.4 million small earthquakes of 2.0 or greater and more than 14,000 larger quakes of 4.0 or greater.
In assessing the incidence of seismic events attributed to or suspected to have been caused by energy activities, the committee set a threshold for what they called "felt seismic events". This is crucial, because all of these technologies routinely cause minuscule events--"microseisms"--that can be detected by a seismometer in close proximity, but would go unnoticed by anyone standing on the surface. Magnitude 2.0 seems to be the lowest level event likely to be felt by an observer in the vicinity, while an event of 4.0 would be accompanied by more shaking over a larger area, and thus felt by many more people. Having grown up in earthquake country, I can attest to this. Anything below about 4.0 would often be mistaken for a train or large truck passing by, while most damage was due to quakes of 5.0 or greater. For comparison, last year's quake in Mineral, VA that affected the Washington Monument and National Cathedral registered 5.8. Only about a dozen of the induced seismic events included in the study were larger than that.
It's important to note that the mechanisms by which various energy-related drilling and injection processes trigger felt seismic events are fairly well understood. Scientists and engineers have known since the 1920s that human activities can trigger quakes, and the geosciences have advanced enormously since then. The main contributing factors identified in the report were the effect of fluid injection on increasing the pressure in the pores of subsurface rocks near faults, along with the "net fluid balance", which they defined as the "total balance of fluid introduced into or removed from the subsurface." As a result of these factors, drilling approaches in which the net fluid balance isn't materially altered, such as in waterflood enhanced oil recovery, or for which the changes are short-lived, as in hydraulic fracturing, tend to have very low rates of inducing felt seismic events. In particular, the study found only one documented felt seismic event, of magnitude 2.8, attributable to shale fracking, out of 35,000 fracked shale gas wells.
By contrast, liquid disposal wells, which steadily increase subsurface pore pressure over time, along with several types of geothermal production, exhibit somewhat higher rates of felt seismic events, though these are still relatively rare and generally minor in impact. At least theoretically, CCS seems to have a somewhat higher potential for causing seismic events, although this has apparently not been manifested in the substantial number of wells injecting CO2 for enhanced oil recovery--cited in the report as 13,000 as of 2007 and many more today. Surprisingly, the largest quakes attributed to human activities were associated with conventional oil production, including a couple of 6+ quakes in California and one measuring 7.3 in Uzbekistan.
One of the most interesting findings in the report was that there is no single government agency in the US with jurisdiction over induced seismic events associated with energy production. Responsibility--and capabilities--appear to straddle the Environmental Protection Agency, US Geological Survey, Forest Service and Bureau of Land Management, along with various state agencies. The committee proposed the development of new coordination mechanisms to address these events, as distinct from the ad hoc cooperation that has taken place to date.
I'm not sure what policy makers--the report was commissioned by the Chairman of the Senate Energy and Natural Resources Committee--and the public will make of these findings. At least from a statistical perspective the technologies assessed here look safe in terms of their seismic risks, and it would be hard to justify sweeping new regulations on the basis of this report. (I don't know how practical the "traffic light" monitoring system the authors propose would be.) On the other hand, with the exception of a few people in naturally quake-prone areas--including one neighbor back in California who thinks they are "fun"--earthquakes are fear-inducing, in both anticipation and experience. Arriving at a consensus on how low a risk of felt seismic events is acceptable might not be easy, especially where natural earthquakes are rare. Although the public's appetite for reassurance seems to be fairly low these days, it's clear that the National Research Council, an arm of the private, non-profit National Academies chartered by Congress during the Lincoln administration, sees no reason to panic about the seismic hazards and risks entailed in energy-related drilling.
The study encompassed four categories of energy-related drilling, including oil & gas exploration and production, geothermal energy, liquid disposal wells, and CCS. Within oil & gas, they looked at conventional production and "enhanced recovery", along with hydraulic fracturing or "fracking". The latter two techniques involve pumping water or some other fluid into a reservoir to stimulate production. For geothermal, they considered conventional geothermal, both liquid- and vapor-dominated reservoirs, and "enhanced" or engineered geothermal systems, which pump fluid into hot, dry rock to extract useful heat. They found recorded seismic events in all categories and sub-categories, though again the numbers are small, particularly for quakes large enough to cause damage: Fewer than 160 recorded events globally over magnitude 2.0 within a period of about 30 years from a well population in the millions, and against a natural annual background of 1.4 million small earthquakes of 2.0 or greater and more than 14,000 larger quakes of 4.0 or greater.
In assessing the incidence of seismic events attributed to or suspected to have been caused by energy activities, the committee set a threshold for what they called "felt seismic events". This is crucial, because all of these technologies routinely cause minuscule events--"microseisms"--that can be detected by a seismometer in close proximity, but would go unnoticed by anyone standing on the surface. Magnitude 2.0 seems to be the lowest level event likely to be felt by an observer in the vicinity, while an event of 4.0 would be accompanied by more shaking over a larger area, and thus felt by many more people. Having grown up in earthquake country, I can attest to this. Anything below about 4.0 would often be mistaken for a train or large truck passing by, while most damage was due to quakes of 5.0 or greater. For comparison, last year's quake in Mineral, VA that affected the Washington Monument and National Cathedral registered 5.8. Only about a dozen of the induced seismic events included in the study were larger than that.
It's important to note that the mechanisms by which various energy-related drilling and injection processes trigger felt seismic events are fairly well understood. Scientists and engineers have known since the 1920s that human activities can trigger quakes, and the geosciences have advanced enormously since then. The main contributing factors identified in the report were the effect of fluid injection on increasing the pressure in the pores of subsurface rocks near faults, along with the "net fluid balance", which they defined as the "total balance of fluid introduced into or removed from the subsurface." As a result of these factors, drilling approaches in which the net fluid balance isn't materially altered, such as in waterflood enhanced oil recovery, or for which the changes are short-lived, as in hydraulic fracturing, tend to have very low rates of inducing felt seismic events. In particular, the study found only one documented felt seismic event, of magnitude 2.8, attributable to shale fracking, out of 35,000 fracked shale gas wells.
By contrast, liquid disposal wells, which steadily increase subsurface pore pressure over time, along with several types of geothermal production, exhibit somewhat higher rates of felt seismic events, though these are still relatively rare and generally minor in impact. At least theoretically, CCS seems to have a somewhat higher potential for causing seismic events, although this has apparently not been manifested in the substantial number of wells injecting CO2 for enhanced oil recovery--cited in the report as 13,000 as of 2007 and many more today. Surprisingly, the largest quakes attributed to human activities were associated with conventional oil production, including a couple of 6+ quakes in California and one measuring 7.3 in Uzbekistan.
One of the most interesting findings in the report was that there is no single government agency in the US with jurisdiction over induced seismic events associated with energy production. Responsibility--and capabilities--appear to straddle the Environmental Protection Agency, US Geological Survey, Forest Service and Bureau of Land Management, along with various state agencies. The committee proposed the development of new coordination mechanisms to address these events, as distinct from the ad hoc cooperation that has taken place to date.
I'm not sure what policy makers--the report was commissioned by the Chairman of the Senate Energy and Natural Resources Committee--and the public will make of these findings. At least from a statistical perspective the technologies assessed here look safe in terms of their seismic risks, and it would be hard to justify sweeping new regulations on the basis of this report. (I don't know how practical the "traffic light" monitoring system the authors propose would be.) On the other hand, with the exception of a few people in naturally quake-prone areas--including one neighbor back in California who thinks they are "fun"--earthquakes are fear-inducing, in both anticipation and experience. Arriving at a consensus on how low a risk of felt seismic events is acceptable might not be easy, especially where natural earthquakes are rare. Although the public's appetite for reassurance seems to be fairly low these days, it's clear that the National Research Council, an arm of the private, non-profit National Academies chartered by Congress during the Lincoln administration, sees no reason to panic about the seismic hazards and risks entailed in energy-related drilling.
Friday, June 15, 2012
Politics and The Global Cleantech Shakeout
For all the enthusiastic comparisons of the cleantech sector to infotech or microelectronics that we've encountered in the last decade, one rarely employed analogy is turning out to be more apt than the rest: Cleantech seems just as capable as dot-coms and chip makers of undergoing an industry shakeout and consolidation at the same time it experiences growth rates that most other industries would envy. US and European solar firms continue to fall by the wayside, and this week saw the sale by the world's leading wind turbine manufacturer, Vestas, of one of its Danish plants to a China-based competitor. Because the cleantech industry has been driven mainly by policy rather than market forces, and has thus been deeply intertwined with politics, the global shakeout now underway will continue to have political repercussions. Should Europe's monetary problems unleash a new financial crisis, then both the cleantech shakeout and its political fallout could expand.
The strained comparisons this week between the failures of Solyndra and Konarka, a much smaller solar panel maker, likely won't be the last example of this that we'll see this year. Although I can understand the temptation to link these two situations, the contrast between an award-winning company that took more than eight years to go bankrupt in an economic and competitive environment vastly different than the one in which it was launched, and a business that was already doomed on the day that its half-billion dollar federal loan was inked should have dissuaded anyone from raising this issue. The analogy looks even worse when you realize that Solyndra was only able to undertake the massive expansion that drove it into bankruptcy as a result of serious deficiencies in the DOE's due diligence process, which failed to spot the crashing price of polysilicon, the previous spike in which had underpinned Solyndra's business model.
Past shakeouts have left other industries in excellent shape, despite the pain they entailed. Numerous US automakers went out of business during the Great Depression, which was also a period of great innovation that set up the survivors to become a pillar of the US economy for the next half-century. It's premature to write the epitaph of US cleantech, which could yet emerge much stronger. At the same time, have we ever experienced such a shakeout in an industry so dominated by government subsidies and industrial policy, against the backdrop of globalized competition with similarly supported industries in Europe and Asia? The ultimate outcome looks highly uncertain.
In the long run, the administration's investments in cleantech will either look farsighted and courageous or tragically mistaken, rooted in a "green jobs" fallacy that emerged as an expedient Plan B after successive failures to legislate a price on CO2 and other greenhouse gas emissions. Of course this year's election won't take place with the benefit of history's verdict. Its energy aspects are likely to be dominated by the behavior of oil and gasoline prices and a potential string of further high-profile cleantech bankruptcies, if the economy remains weak. (The list of DOE loan guarantee recipients doesn't lack for candidates.) Is it due to defects in our system or merely human nature that such events seem destined to overshadow the positive energy visions that both sides will present to voters?
The strained comparisons this week between the failures of Solyndra and Konarka, a much smaller solar panel maker, likely won't be the last example of this that we'll see this year. Although I can understand the temptation to link these two situations, the contrast between an award-winning company that took more than eight years to go bankrupt in an economic and competitive environment vastly different than the one in which it was launched, and a business that was already doomed on the day that its half-billion dollar federal loan was inked should have dissuaded anyone from raising this issue. The analogy looks even worse when you realize that Solyndra was only able to undertake the massive expansion that drove it into bankruptcy as a result of serious deficiencies in the DOE's due diligence process, which failed to spot the crashing price of polysilicon, the previous spike in which had underpinned Solyndra's business model.
Past shakeouts have left other industries in excellent shape, despite the pain they entailed. Numerous US automakers went out of business during the Great Depression, which was also a period of great innovation that set up the survivors to become a pillar of the US economy for the next half-century. It's premature to write the epitaph of US cleantech, which could yet emerge much stronger. At the same time, have we ever experienced such a shakeout in an industry so dominated by government subsidies and industrial policy, against the backdrop of globalized competition with similarly supported industries in Europe and Asia? The ultimate outcome looks highly uncertain.
In the long run, the administration's investments in cleantech will either look farsighted and courageous or tragically mistaken, rooted in a "green jobs" fallacy that emerged as an expedient Plan B after successive failures to legislate a price on CO2 and other greenhouse gas emissions. Of course this year's election won't take place with the benefit of history's verdict. Its energy aspects are likely to be dominated by the behavior of oil and gasoline prices and a potential string of further high-profile cleantech bankruptcies, if the economy remains weak. (The list of DOE loan guarantee recipients doesn't lack for candidates.) Is it due to defects in our system or merely human nature that such events seem destined to overshadow the positive energy visions that both sides will present to voters?
Wednesday, June 13, 2012
The Summer Oil Slump
Instead of US consumers facing $5 gasoline this summer, as some analysts had predicted, we now find prices slipping well below $4 per gallon as oil prices respond to weakening demand, a stronger dollar, and steady supply growth. Yet as welcome as this is, it's largely the result of a mountain of bad news: Not only does financial turmoil threaten the very existence of the European Monetary Union and its currency, the Euro, but economic growth in the large emerging economies is also slowing, at least partly in response to the weakness in the developed countries that constitute their primary export markets. The engine of global growth for the next year or two just isn't obvious. That's the backdrop for this week's OPEC meeting in Vienna.
Before we become too enthusiastic about the prospect of a period of cheaper oil, we should first put "cheap" in context. Even ignoring West Texas Intermediate (WTI), the doldrums of which I've discussed at length, the world's most representative current crude oil price, for UK Brent, has fallen consistently below $100 per barrel for the first time since the beginning of the Arab Spring in 2011. Yet even if it fell another $10/bbl, to about where WTI is currently trading, it would still exceed its annual average for every year save 2008 and 2011. So while oil might be less of a drag on the economy at $90/bbl than at $120, that's still short of the kind of drop that would be necessary for it to provide a substantial positive stimulus, particularly when much of the drop reflects buyers around the world tightening their belts.
The US is in a somewhat better position, thanks to surging production of "tight oil" in North Dakota and onshore Texas. This has more than made up for the inevitable slide in output from the deepwater Gulf of Mexico, two years after Deepwater Horizon and the ensuing drilling moratorium. With much of the new production trapped on the wrong side of some temporary pipeline bottlenecks, parts of the country are benefiting from oil prices that are $10-15/bbl below world prices, although short-term gains are a poor reason to perpetuate those bottlenecks, rather than resolving them and allowing North American production to reach its full potential.
Then there's the issue of speculation, which some politicians blamed for the recent spike in oil prices. To whatever extent that was true--and I remain skeptical that the impact was nearly as large as claimed--we could be about to see what happens when the dominant direction of speculation flips from "long" to "short"--bullish to bearish--as noted in today's Wall St. Journal. Since the main effect of speculation is to increase volatility, we could see oil prices temporarily drop even further than today's weak fundamentals would suggest they should.
All of this will be on the minds of the OPEC ministers meeting in Vienna Thursday, along with the usual dynamics between OPEC's price doves and hawks. The pressures on the latter have intensified as Iran copes with tighter sanctions on its exports and Venezuela's ailing caudillo faces a serious election challenge. OPEC meetings are rarely as dramatic as last June's session, but the global context ensures a keenly interested audience for this one. Given the impact of gas prices on US voters, both presidential campaigns should be watching events in Vienna as closely as any traders. $3.00 per gallon by November isn't beyond the realm of possibility. It would only require a sustained dip below $80/bbl.
Before we become too enthusiastic about the prospect of a period of cheaper oil, we should first put "cheap" in context. Even ignoring West Texas Intermediate (WTI), the doldrums of which I've discussed at length, the world's most representative current crude oil price, for UK Brent, has fallen consistently below $100 per barrel for the first time since the beginning of the Arab Spring in 2011. Yet even if it fell another $10/bbl, to about where WTI is currently trading, it would still exceed its annual average for every year save 2008 and 2011. So while oil might be less of a drag on the economy at $90/bbl than at $120, that's still short of the kind of drop that would be necessary for it to provide a substantial positive stimulus, particularly when much of the drop reflects buyers around the world tightening their belts.
The US is in a somewhat better position, thanks to surging production of "tight oil" in North Dakota and onshore Texas. This has more than made up for the inevitable slide in output from the deepwater Gulf of Mexico, two years after Deepwater Horizon and the ensuing drilling moratorium. With much of the new production trapped on the wrong side of some temporary pipeline bottlenecks, parts of the country are benefiting from oil prices that are $10-15/bbl below world prices, although short-term gains are a poor reason to perpetuate those bottlenecks, rather than resolving them and allowing North American production to reach its full potential.
Then there's the issue of speculation, which some politicians blamed for the recent spike in oil prices. To whatever extent that was true--and I remain skeptical that the impact was nearly as large as claimed--we could be about to see what happens when the dominant direction of speculation flips from "long" to "short"--bullish to bearish--as noted in today's Wall St. Journal. Since the main effect of speculation is to increase volatility, we could see oil prices temporarily drop even further than today's weak fundamentals would suggest they should.
All of this will be on the minds of the OPEC ministers meeting in Vienna Thursday, along with the usual dynamics between OPEC's price doves and hawks. The pressures on the latter have intensified as Iran copes with tighter sanctions on its exports and Venezuela's ailing caudillo faces a serious election challenge. OPEC meetings are rarely as dramatic as last June's session, but the global context ensures a keenly interested audience for this one. Given the impact of gas prices on US voters, both presidential campaigns should be watching events in Vienna as closely as any traders. $3.00 per gallon by November isn't beyond the realm of possibility. It would only require a sustained dip below $80/bbl.
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