US petroleum product exports have been in the news, along with the welcome discovery that we are apparently on track to become a net exporter of these fuels this year, for the first time since the 1940s. This is a far cry from energy independence, as various oil skeptics have been quick to point out, but it's still a noteworthy inflection point in energy trends. However, I've also seen stories suggesting that US consumers will pay a lot more at the pump as a result of this change, to which the most succinct response so far is "rubbish." Being a net exporter hasn't suddenly connected US fuel prices to the world market, as if they had somehow been insulated from it until now. In fact, we've been exporting products for many years--as I know from personal experience--but for most of that time we just happened to be importing more. The net effect of our new status on prices here will be minimal, while the main impact will be a positive nudge to our trade deficit.
I am sympathetic to the present urge to see a cloud in every silver lining; we seem to be going through one of those phases in our history. At the same time we should understand that to the extent net petroleum product exports aren't entirely good news, it's because the main driver of this departure from a long trend of steadily increasing net imports was the sudden slowdown of consumer activity that accompanied the recession and financial crisis, from which we are still recovering. And while I agree that more efficient cars have contributed, recent fuel economy improvements have been too incremental to our fleet of 240 million light-duty vehicles (passenger cars, SUVs and light trucks) to have made such a big dent in demand, quite so soon. Mainly, we're driving less, as the statistics on vehicle miles traveled indicate. That might be better news if it reflected a massive lifestyle change, instead of the grim reality of millions of un- and under-employed Americans for whom driving has become a luxury.
Even in that negative context, the fact that we are now exporting more gasoline and other petroleum products than we import is a plus, since without buoyant non-US demand, US refiners might have been forced to reduce operations by more than they have, or to idle more facilities and lay off staff. Today's net exports imply a positive margin between crude oil imports and product exports sufficient to cover refiners' costs, even after netting out freight. That results in more economic activity and value added here, driven by overseas demand, following the same export-led strategy that other industries are pursuing in order to compensate for lower US demand for their output.
More exports and fewer imports mean a smaller trade deficit, but the question on some people's minds is apparently whether this is being accomplished at the expense of US consumers. That might have been the case if, for example, exports had been banned until recently and refiners forced to create an artificial glut of petroleum products to drive down prices. (That's effectively the case in some other countries.) Instead, the US has long been part of a global market for both crude oil and refined products, and refiners and traders have always been alert for gaps between regional markets that could be profitably exploited. When I traded refined products for Texaco's west coast refineries in the 1980s, we occasionally took advantage of export opportunities, even though we were more often importers. When I traded products in London, my team routinely sold cargoes of gasoline, diesel or jet fuel from the US into Europe and Asia, and we did the reverse when the "arbitrage" worked in the other direction. We accounted for just a small portion of the trade in cargoes passing back and forth between continents, which continues today.
As a result of this global market in refined petroleum products, US consumers of gasoline and other fuels have always been competing with consumers in other countries, whether we realized it or not, especially in parts of the country where refiners have easy access to export markets. That's been true since the days when my former employer's advertising touted its success in "lighting the (kerosene) lamps of China". In terms of the impact on domestic prices, it doesn't matter much whether we're net exporters or net importers, as long as we're connected to the global market--a linkage that has saved our bacon on many occasions when US refineries were hit by hurricanes, blackouts, or other disasters.
A more tangible way to test the consequences of product exports involves comparing past and present crude oil and gasoline prices. Making that comparison accurately is complicated by the breakdown of the main US oil market indicator, the price of West Texas Intermediate crude, which for more than a year has been burdened by excessive inventory at Cushing, OK and other factors. For now the price of Louisiana Light Sweet (LLS) is a better gauge of the oil market. LLS has been relatively unaffected by WTI's problems and trended much closer to global oil prices, such as UK Brent crude. It turns out that 104% of the higher retail price of gasoline this November vs. a year ago is explained by the $23 per barrel increase in LLS since then. In other words, crude prices have increased by slightly more than gasoline, suggesting that raw material costs still have a much larger impact on prices at the pump than does the recent shift in US petroleum product trade patterns.
Although the evidence that product exports don't hurt consumers is strong, I don't expect it to dispel this handy new rationale for complaining about gas prices. After all, the price of gasoline is one of the most visible and volatile prices we're exposed to, and for which we have few practical alternatives. Having a narrative to explain these spikes and dips is empowering, even if it's wrong. However, in the midst of all the grumbling it's worth spending a moment thinking about the benefits of having an oil refining industry that has been able to find alternative outlets for its products while it waits for the US economy to recover, instead of yet another manufacturing industry on the ropes, shedding jobs and moving offshore.
Tuesday, December 06, 2011
Thursday, December 01, 2011
Why Does Gazprom Oppose Shale Gas?
I see that Russia's national gas company, Gazprom, is warning Europeans about the environmental risks of shale gas development. Aside from the hypocrisy stemming from a Russian legacy of environmental disregard that rivals the worst excesses committed anywhere, along with the likelihood of Gazprom profiting if it can deter competition from proliferating shale drilling technologies like hydraulic fracturing (a.k.a "fracking") and horizontal drilling, this looks quite clever. Environmental concerns--exaggerated or not--are the Achilles heel of shale drilling. We've seen how how effective environmental opposition to fracking has been in places like New York state. The mere fact of Gazprom's warning about shale drilling doesn't constitute a winning argument either for or against the practice, but the reasons they would be moved to comment might shed further light on shale's potential, which they publicly dismiss as a temporary phenomenon.
If Russia's leaders have anything to fear from the development of shale gas in Europe, much of the blame rests with their own behavior. Gazprom alone has access to the largest conventional natural gas reserves on earth--more than the entire natural gas reserves of Iran--and it has built the pipelines necessary to make Russia the dominant gas supplier to Europe. The latest addition to that network, the Nordstream pipeline--a source of some controversy of its own a few years back--opened just last month. They are also almost certainly correct that European shale gas would be more expensive than Russian gas, at least initially, if you ignore its value in providing Europe with some much-needed leverage with a supplier that hasn't hesitated to play hardball in the past, to the point of cutting off gas shipments during contractual disputes--in winter.
Since Gazprom's credibility on the economic and commercial merits of shale gas development is effectively nil, it makes perfect sense that they would pick up on the environmental arguments that have slowed development elsewhere and in some cases brought it to a standstill. The effectiveness of these arguments is enhanced because they contain a grain of truth: Like all other industrial-scale activities, shale gas drilling is not risk-free. It is possible for a drilling contractor to fail to cement a well properly, creating a chance of contaminating nearby water wells, although some presumed instances of this turned out to have other causes. It's also possible for a driller to mishandle fracking fluid or produced water above ground and affect surface water supplies. Then there are the allegations that leaking methane from shale gas wells negates any emissions benefits and renders the gas at least as bad as coal for climate change--never mind that these claims have been comprehensively examined and disproved.
Although I expect debate on these points to continue for some time, I believe that ultimately shale gas drilling will proceed on a large scale in the US and globally, with some minor tweaks to a regulatory system that already does a pretty good job of monitoring the activity and weeding out those producers that aren't diligent enough about protecting the public and environment. I would also argue that this scenario must be exactly what Gazprom's management believes will happen in Europe, absent a lot more support for those who oppose shale gas for a variety of reasons, including its competition with the more expensive forms of renewable energy. That doesn't automatically make European opponents of shale drilling convenient tools for the resource nationalism of an increasingly authoritarian neighbor, but it certainly ought to make them exercise great caution before entering into any "strange bedfellows" alliances with as self-interested a party as Russia's state energy complex.
If Russia's leaders have anything to fear from the development of shale gas in Europe, much of the blame rests with their own behavior. Gazprom alone has access to the largest conventional natural gas reserves on earth--more than the entire natural gas reserves of Iran--and it has built the pipelines necessary to make Russia the dominant gas supplier to Europe. The latest addition to that network, the Nordstream pipeline--a source of some controversy of its own a few years back--opened just last month. They are also almost certainly correct that European shale gas would be more expensive than Russian gas, at least initially, if you ignore its value in providing Europe with some much-needed leverage with a supplier that hasn't hesitated to play hardball in the past, to the point of cutting off gas shipments during contractual disputes--in winter.
Since Gazprom's credibility on the economic and commercial merits of shale gas development is effectively nil, it makes perfect sense that they would pick up on the environmental arguments that have slowed development elsewhere and in some cases brought it to a standstill. The effectiveness of these arguments is enhanced because they contain a grain of truth: Like all other industrial-scale activities, shale gas drilling is not risk-free. It is possible for a drilling contractor to fail to cement a well properly, creating a chance of contaminating nearby water wells, although some presumed instances of this turned out to have other causes. It's also possible for a driller to mishandle fracking fluid or produced water above ground and affect surface water supplies. Then there are the allegations that leaking methane from shale gas wells negates any emissions benefits and renders the gas at least as bad as coal for climate change--never mind that these claims have been comprehensively examined and disproved.
Although I expect debate on these points to continue for some time, I believe that ultimately shale gas drilling will proceed on a large scale in the US and globally, with some minor tweaks to a regulatory system that already does a pretty good job of monitoring the activity and weeding out those producers that aren't diligent enough about protecting the public and environment. I would also argue that this scenario must be exactly what Gazprom's management believes will happen in Europe, absent a lot more support for those who oppose shale gas for a variety of reasons, including its competition with the more expensive forms of renewable energy. That doesn't automatically make European opponents of shale drilling convenient tools for the resource nationalism of an increasingly authoritarian neighbor, but it certainly ought to make them exercise great caution before entering into any "strange bedfellows" alliances with as self-interested a party as Russia's state energy complex.
Tuesday, November 29, 2011
Message to Durban: It's The Economy
What if they held a UN climate conference and no one came? That's certainly not the case at this year's COP-17 (Conference of the Parties) meeting now underway in Durban, South Africa, but with expectations for dramatic progress low, and a breakthrough on the scale needed to salvage the expiring Kyoto Protocol nearly unimaginable, it could be where the UN-led process is headed. If Durban fails to deliver the goods, it won't be because the participants were any less concerned about climate change than those at past sessions. Nor will it be because of the latest release of Climategate emails, as embarrassing as some of them should be for the scientists involved. The reason is much simpler, and it's the same one that helped Bill Clinton unseat George H.W. Bush in 1992: "It's the economy, stupid." The solution to climate change is unlikely to be found in Durban or any future COP site until the leaders in Brussels, Washington and other capitals come to grips with the massive economic challenges they face and create the framework for a return to robust growth.
That observation might seem paradoxical, given the linkage between economic growth and the growth of greenhouse gas (GHG) emissions. One climate change expert at Shell recently questioned whether it's even possible to reduce these emissions, because the expansion of low-emission energy sources is merely displacing fossil fuels into other markets where the appetite for them remains insatiable. We've also seen the rebound in emissions that occurred once the US economy began to recover from the worst effects of the financial crisis and recession that began in 2008, and a new report from the International Energy Agency projects a similar result globally. Yet it's also the case that prosperity and concern for the environment go hand in hand, along with the capacity to afford the costs and penalties that a massive global reduction in GHGs would entail. It's no coincidence that the UN climate process and parallel US efforts lost most of their previous momentum during the Great Recession.
Although the "road map" that came out of 2007's Bali climate conference was ambitious, its timetable for developing a new set of binding emission-reduction commitments to dovetail with the end of the 2008-12 "first measurement period" of Kyoto looked achievable, allowing for some slippage. Just two years later, the delegates to Copenhagen were lucky to come away with a last-minute set of voluntary, non-binding commitments that, even if they were all implemented, would barely shift the trajectory of rising emissions. Nor did last year's meeting in Cancun restore the Bali road map.
At this point, even the less ambitious proposals on the agenda in Durban ultimately depend on developed countries that are grappling with high unemployment, crippling deficits and debt, and political turmoil underwriting large investments in the developing world. The present structure of the European Union--the primary supporter of action on climate change--is itself in jeopardy, and European economies are facing an oil price shock arguably as large as that of 2008. It's questionable that the EU can even pay for its own future emissions reductions, let alone subsidizing reductions and climate adaptation in the developing world. Meanwhile, support for Kyoto among other large emitting countries is flagging, and the US appears little closer to taking on binding emissions commitments than it was in 1997.
I don't dismiss the possibility that the Durban talks may accomplish more than just punting the ball to next year's session in Qatar. However, if they don't, then the folks that are footing the bills for this seemingly endless succession of sprawling confabs--wonderful for local chambers of commerce and tourism, but practically meaningless for tackling global emissions--should consider calling a hiatus pending the resolution of the global economic problems that will undermine any agreement they could reach in the interim. There might even be a scientific justification for that, in the form of a new, peer-reviewed paper in Science suggesting that the global climate's sensitivity to increasing concentrations of CO2 might not be as strong as previously thought. If Schmittner, et al, are correct, then we might have a bit more time before extreme climate change becomes imminent. Let's hope so, because it looks a lot more fruitful to reboot this whole effort once the global economy is back on an even keel.
That observation might seem paradoxical, given the linkage between economic growth and the growth of greenhouse gas (GHG) emissions. One climate change expert at Shell recently questioned whether it's even possible to reduce these emissions, because the expansion of low-emission energy sources is merely displacing fossil fuels into other markets where the appetite for them remains insatiable. We've also seen the rebound in emissions that occurred once the US economy began to recover from the worst effects of the financial crisis and recession that began in 2008, and a new report from the International Energy Agency projects a similar result globally. Yet it's also the case that prosperity and concern for the environment go hand in hand, along with the capacity to afford the costs and penalties that a massive global reduction in GHGs would entail. It's no coincidence that the UN climate process and parallel US efforts lost most of their previous momentum during the Great Recession.
Although the "road map" that came out of 2007's Bali climate conference was ambitious, its timetable for developing a new set of binding emission-reduction commitments to dovetail with the end of the 2008-12 "first measurement period" of Kyoto looked achievable, allowing for some slippage. Just two years later, the delegates to Copenhagen were lucky to come away with a last-minute set of voluntary, non-binding commitments that, even if they were all implemented, would barely shift the trajectory of rising emissions. Nor did last year's meeting in Cancun restore the Bali road map.
At this point, even the less ambitious proposals on the agenda in Durban ultimately depend on developed countries that are grappling with high unemployment, crippling deficits and debt, and political turmoil underwriting large investments in the developing world. The present structure of the European Union--the primary supporter of action on climate change--is itself in jeopardy, and European economies are facing an oil price shock arguably as large as that of 2008. It's questionable that the EU can even pay for its own future emissions reductions, let alone subsidizing reductions and climate adaptation in the developing world. Meanwhile, support for Kyoto among other large emitting countries is flagging, and the US appears little closer to taking on binding emissions commitments than it was in 1997.
I don't dismiss the possibility that the Durban talks may accomplish more than just punting the ball to next year's session in Qatar. However, if they don't, then the folks that are footing the bills for this seemingly endless succession of sprawling confabs--wonderful for local chambers of commerce and tourism, but practically meaningless for tackling global emissions--should consider calling a hiatus pending the resolution of the global economic problems that will undermine any agreement they could reach in the interim. There might even be a scientific justification for that, in the form of a new, peer-reviewed paper in Science suggesting that the global climate's sensitivity to increasing concentrations of CO2 might not be as strong as previously thought. If Schmittner, et al, are correct, then we might have a bit more time before extreme climate change becomes imminent. Let's hope so, because it looks a lot more fruitful to reboot this whole effort once the global economy is back on an even keel.
Tuesday, November 22, 2011
Our Shifting Energy Diet
It's fairly easy to agree on the desirability of shifting our energy diet away from fossil fuels and toward more renewable or sustainable sources, but it's much harder to agree on the time scale involved. While recognizing the great potential of renewable energy technologies such as wind, solar and geothermal power, along with advanced, non-food-based biofuels, I am convinced that the transition will take much longer than many hope--longer than many will have patience for, in light of pressing concerns about energy security and the environment. When considering future shifts in our energy diet, it's instructive to review some of the changes we've already experienced, and how long they took. The graph below displays the relative contribution of America's main energy sources since 1949, based on data from the Energy Information Agency of the US Department of Energy.
This chart, which compares the proportional, rather than absolute contribution of each source as a percent of the total, shows that the US energy diet has experienced constant change over the last seven decades. Some of these changes have been dramatic, such as the erosion of coal's market share in the 1950s and '60s by oil and natural gas, while others, such as the resurgence of biomass-based energy since the 1970s are less dramatic but still noticeable. On the scale of this graph the non-biomass renewables that I've lumped together appear relatively steady, because the recent rapid growth of wind and solar energy has so far only compensated for a contemporaneous decline in hydropower output. I'd expect the growth of that green segment to be more obvious in a few years, though still not on the scale of nuclear power.
The chart also reminds us that however prominent a given energy source might have become during this period, none overwhelmed the others. We talk a great deal about oil's dominance, yet it never exceeded a 48% share of our energy diet, and it has recently fallen below 37%. In fact, you'd have to go all the way back to the 1920s to find an energy source with a market share above 60%, which coal still enjoyed during the early years of oil's rise as the combination of mass-produced cars and the big oil finds in East Texas and Oklahoma upended the US energy landscape. That's one reason I generally find forecasts of renewables capturing 80% of the energy market within a few decades to be improbable.
Perhaps the most relevant example for renewables of a disruptive energy technology capturing a significant share of the market is commercial nuclear power, which contributed just 0.1% of US energy in 1962. That's about what solar provides today. Yet even with a major push by utilities and government and broadly favorable market acceptance until after the Three Mile Island accident, it still took nuclear power 25 years to reach a 6% share of total US primary energy, and nearly 40 years to reach its current 8% or so. Today's renewables also face similar limits on their potential market penetration, albeit due to very different factors relating to intermittency and the high cost of energy storage.
What would it take for renewables to repeat the model of oil's success against coal? In the absence of a high carbon price or incentives on a level unlikely to be either politically feasible or affordable in the current environment, I believe it would require technologies that don't just reduce greenhouse gas emissions or local pollutants, but actually enable something new and very attractive to consumers and businesses, along the lines of the quantum leaps in mobility and other economic activity that oil made possible. Otherwise, their promoters should be prepared to play a long game, in much the same way that the conventional energy industry did when it was building its market post World War II. Do investors and policy makers have the patience that requires?
By the way The Energy Collective is offering a free virtual conference on November 30 on the subject of "How to Save A Planet on A Budget." The conference includes panel discussions and case studies moderated by Marc Gunther of Fortune magazine, Jesse Jenkins of the Breakthrough Institute, and Gernot Wagner, economist at the Environmental Defense Fund. To register click here.
I'd also like to wish my US readers a pleasant Thanksgiving weekend.
This chart, which compares the proportional, rather than absolute contribution of each source as a percent of the total, shows that the US energy diet has experienced constant change over the last seven decades. Some of these changes have been dramatic, such as the erosion of coal's market share in the 1950s and '60s by oil and natural gas, while others, such as the resurgence of biomass-based energy since the 1970s are less dramatic but still noticeable. On the scale of this graph the non-biomass renewables that I've lumped together appear relatively steady, because the recent rapid growth of wind and solar energy has so far only compensated for a contemporaneous decline in hydropower output. I'd expect the growth of that green segment to be more obvious in a few years, though still not on the scale of nuclear power.
The chart also reminds us that however prominent a given energy source might have become during this period, none overwhelmed the others. We talk a great deal about oil's dominance, yet it never exceeded a 48% share of our energy diet, and it has recently fallen below 37%. In fact, you'd have to go all the way back to the 1920s to find an energy source with a market share above 60%, which coal still enjoyed during the early years of oil's rise as the combination of mass-produced cars and the big oil finds in East Texas and Oklahoma upended the US energy landscape. That's one reason I generally find forecasts of renewables capturing 80% of the energy market within a few decades to be improbable.
Perhaps the most relevant example for renewables of a disruptive energy technology capturing a significant share of the market is commercial nuclear power, which contributed just 0.1% of US energy in 1962. That's about what solar provides today. Yet even with a major push by utilities and government and broadly favorable market acceptance until after the Three Mile Island accident, it still took nuclear power 25 years to reach a 6% share of total US primary energy, and nearly 40 years to reach its current 8% or so. Today's renewables also face similar limits on their potential market penetration, albeit due to very different factors relating to intermittency and the high cost of energy storage.
What would it take for renewables to repeat the model of oil's success against coal? In the absence of a high carbon price or incentives on a level unlikely to be either politically feasible or affordable in the current environment, I believe it would require technologies that don't just reduce greenhouse gas emissions or local pollutants, but actually enable something new and very attractive to consumers and businesses, along the lines of the quantum leaps in mobility and other economic activity that oil made possible. Otherwise, their promoters should be prepared to play a long game, in much the same way that the conventional energy industry did when it was building its market post World War II. Do investors and policy makers have the patience that requires?
By the way The Energy Collective is offering a free virtual conference on November 30 on the subject of "How to Save A Planet on A Budget." The conference includes panel discussions and case studies moderated by Marc Gunther of Fortune magazine, Jesse Jenkins of the Breakthrough Institute, and Gernot Wagner, economist at the Environmental Defense Fund. To register click here.
I'd also like to wish my US readers a pleasant Thanksgiving weekend.
Thursday, November 17, 2011
Is the Photovoltaic Price Trend Sustainable?
It has been widely assumed among pundits and policy makers that the continued expansion of solar photovoltaic (PV) installations will drive down PV costs until the electricity they produce is competitive with conventional power sources without the need for subsidies. This belief is grounded in both recent PV cost trends and the well-known "experience curve" effect in manufacturing, in which costs tend to fall in proportion to cumulative output. However, anyone following the fortunes of big PV manufacturers like First Solar, SunPower, and China-based Suntech and Trina Solar might have reason to question this conventional wisdom. Their latest earnings reflect an industry stressed by softening demand in its core market in Europe and facing global overcapacity along the supply chain. This has me wondering how much of the recent decline in PV prices was due to the inherent progression of the technology, and how much to unsustainable market and competitive pressures.
The solar industry has made tremendous progress in the last several years. One indication of that is the price trend for PV in the annual "Tracking the Sun" survey from Lawrence Berkeley Lab. Between 2007 and 2010 the average cost of PV installed in the US fell by around 22%, with the largest portion of that drop occurring last year, followed by a further 11% decline in the first half of this year. Most of the reduction is attributable to the falling price of solar modules, rather than from the non-module, or "balance of system" costs (inverters, structures, installation, etc.) The fact that these declines coincided with an explosion of global PV capacity and output seems entirely consistent with expectations about the likely path of PV costs. Cumulative global PV capacity doubled twice in that interval, based on figures in the newly released Renewables 2011 Global Status report from REN21, so we'd expect to see strong experience-curve cost reductions.
The problem is that the industry dynamic behind this trend didn't much resemble the pristine image that the term "experience curve" evokes, of diligent engineers relentlessly focused on continuous improvement. Without diminishing the contribution of a lot of smart people, a key driver was the tough competition for market share between silicon-based PV, which had to overcome a major bottleneck in the supply of its primary raw material, polysilicon--the price for which spiked and subsequently collapsed--and cheaper but less efficient thin-film PV technologies relying on entirely different chemistries such as cadmium telluride and copper, indium, gallium and selenium.
A further hint that this wasn't quite the standard picture of predictable cost declines promoted by the PV industry is that PV prices appear to have been falling faster than actual costs, which in the case of at least some manufacturers are no longer dropping much at all. This can be inferred from the compression of gross margins reported by the leading firms, and in results that show profits stalling or falling even as volume grows. SunPower, the largest US silicon-based PV maker, reported a net loss for the third quarter of 2011, following a loss in Q2, and issued guidance forecasting a loss in 4Q, as well. We'll get a better picture of the health of the big China-based producers when they report 3Q earnings next week, but in the second quarter Suntech, the world's largest solar panel maker, reported a substantial loss, even though sales were up by a third from a year earlier, similar to results at rival JA Solar. In response Suntech and other Asian producers have apparently slowed planned expansions and reduced throughput at existing facilities, while US PV leader First Solar postponed its new factory in Vietnam.
It's a testament to the ingenuity of the big, established PV producers that they haven't all shared the fate of Solyndra after investing so much in expanding capacity ahead of demand--a major accomplishment in itself when demand has been growing by roughly 80% per year--only to see the market weaken due to a prolonged economic slump and a financial crisis in Europe that has undermined the ability of governments to provide generous subsidies for PV installations. Assumptions about the future cost trend of PV won't mean much if the industry doesn't emerge from its current difficulties as a collection of healthy firms with solid balance sheets and financial performance that investors find attractive. That will require better margins achieved by some combination of improved pricing power--implying better matching of capacity to demand--and cost reductions that don't just rely on further scale-up, which will become less fruitful as experience-curve benefits stretch out.
In other words, even if PV manufacturing costs continue to fall quickly for the next few years, it's less clear that the PV prices paid by project developers, businesses and consumers will follow suit, particularly if the current low margins lead to a global shakeout or consolidation among producers. Time will tell whether the solar industry can sustain the cost path that it's been on, or if future cost reductions will be more modest, in which case a number of scenarios for future PV penetration and renewables-based emissions reductions would require revision.
The solar industry has made tremendous progress in the last several years. One indication of that is the price trend for PV in the annual "Tracking the Sun" survey from Lawrence Berkeley Lab. Between 2007 and 2010 the average cost of PV installed in the US fell by around 22%, with the largest portion of that drop occurring last year, followed by a further 11% decline in the first half of this year. Most of the reduction is attributable to the falling price of solar modules, rather than from the non-module, or "balance of system" costs (inverters, structures, installation, etc.) The fact that these declines coincided with an explosion of global PV capacity and output seems entirely consistent with expectations about the likely path of PV costs. Cumulative global PV capacity doubled twice in that interval, based on figures in the newly released Renewables 2011 Global Status report from REN21, so we'd expect to see strong experience-curve cost reductions.
The problem is that the industry dynamic behind this trend didn't much resemble the pristine image that the term "experience curve" evokes, of diligent engineers relentlessly focused on continuous improvement. Without diminishing the contribution of a lot of smart people, a key driver was the tough competition for market share between silicon-based PV, which had to overcome a major bottleneck in the supply of its primary raw material, polysilicon--the price for which spiked and subsequently collapsed--and cheaper but less efficient thin-film PV technologies relying on entirely different chemistries such as cadmium telluride and copper, indium, gallium and selenium.
A further hint that this wasn't quite the standard picture of predictable cost declines promoted by the PV industry is that PV prices appear to have been falling faster than actual costs, which in the case of at least some manufacturers are no longer dropping much at all. This can be inferred from the compression of gross margins reported by the leading firms, and in results that show profits stalling or falling even as volume grows. SunPower, the largest US silicon-based PV maker, reported a net loss for the third quarter of 2011, following a loss in Q2, and issued guidance forecasting a loss in 4Q, as well. We'll get a better picture of the health of the big China-based producers when they report 3Q earnings next week, but in the second quarter Suntech, the world's largest solar panel maker, reported a substantial loss, even though sales were up by a third from a year earlier, similar to results at rival JA Solar. In response Suntech and other Asian producers have apparently slowed planned expansions and reduced throughput at existing facilities, while US PV leader First Solar postponed its new factory in Vietnam.
It's a testament to the ingenuity of the big, established PV producers that they haven't all shared the fate of Solyndra after investing so much in expanding capacity ahead of demand--a major accomplishment in itself when demand has been growing by roughly 80% per year--only to see the market weaken due to a prolonged economic slump and a financial crisis in Europe that has undermined the ability of governments to provide generous subsidies for PV installations. Assumptions about the future cost trend of PV won't mean much if the industry doesn't emerge from its current difficulties as a collection of healthy firms with solid balance sheets and financial performance that investors find attractive. That will require better margins achieved by some combination of improved pricing power--implying better matching of capacity to demand--and cost reductions that don't just rely on further scale-up, which will become less fruitful as experience-curve benefits stretch out.
In other words, even if PV manufacturing costs continue to fall quickly for the next few years, it's less clear that the PV prices paid by project developers, businesses and consumers will follow suit, particularly if the current low margins lead to a global shakeout or consolidation among producers. Time will tell whether the solar industry can sustain the cost path that it's been on, or if future cost reductions will be more modest, in which case a number of scenarios for future PV penetration and renewables-based emissions reductions would require revision.
Tuesday, November 15, 2011
Iran Oil Price Risk Returns
Between the Libyan revolution and the shaky US and European economies, oil markets hadn't been paying much attention to Iran's nuclear program until last week's release of a new report from the International Atomic Energy Agency (IAEA.) For the first time, the IAEA presented a detailed picture of a well-organized Iranian effort encompassing projects and technologies that go beyond what could reasonably be construed as having purely civilian purposes. Traders are once again talking about an "Iran risk premium," though the market's initial response has been sufficiently muted that it's hard to distinguish from other factors, such as the narrowing of the spread between West Texas Intermediate and Brent crude and worries about the Euro. As long as the international reaction to Iran remains confined to the well-worn pattern of diplomatic protests followed by incrementally tweaked sanctions that dampen speculation about military options, oil will probably just exhibit some extra volatility.
I've been following this issue for a long time, and almost from the start I've been skeptical of the Iranian government's insistence that their nuclear effort was aimed only at producing electricity. Iran has cheaper and less controversial energy options in abundance. Perhaps the biggest surprise in the IAEA report was that the agency would risk the controversy inherent in releasing a thorough accounting of Iran's efforts to develop capabilities unique to designing and building a nuclear warhead that could be mounted on a missile. Moreover, the report suggests that at least some of these activities did not end in 2003, as the controversial US National Intelligence Estimate of 2007 concluded, but "may still be ongoing."
The oil market risk has several dimensions, the most obvious of which relates to a preemptive attack by the US or Israel. Yet even a stepped-up sanctions regime might either directly impede oil exports from Iran or provoke an Iranian reaction having the same effect, at a time when oil prices are already relatively high. Either scenario might trigger an oil price spike that would largely undo recent efforts to revive the global economy. At the moment, however, neither outcome seems very likely to me.
Whatever the IAEA's findings indicate about Iran's intentions or proximity to becoming a nuclear weapons state, the US has little appetite for initiating an attack with such uncertain outcomes on the basis of intelligence that remains incomplete. The public is hardly clamoring for another war, and the administration seems understandably reticent to take such a step, particularly going into an election year. Israeli public opinion--and even its leaders--appear split on the advisability of independent action against Iran's nuclear complex. Even in terms of sanctions, I would expect a response with more bark than bite that stops short of antagonizing Iran's regime to the point at which it might use its oil weapon. Unfortunately, the longer this protracted confrontation over Iran's nuclear program drags out, the greater the risk of one or more parties miscalculating, with results that could spin out of anyone's control.
The Council on Foreign Relations has put out some useful interviews and analysis on the IAEA report and the possible responses to it. Have a look and draw your own conclusions.
I've been following this issue for a long time, and almost from the start I've been skeptical of the Iranian government's insistence that their nuclear effort was aimed only at producing electricity. Iran has cheaper and less controversial energy options in abundance. Perhaps the biggest surprise in the IAEA report was that the agency would risk the controversy inherent in releasing a thorough accounting of Iran's efforts to develop capabilities unique to designing and building a nuclear warhead that could be mounted on a missile. Moreover, the report suggests that at least some of these activities did not end in 2003, as the controversial US National Intelligence Estimate of 2007 concluded, but "may still be ongoing."
The oil market risk has several dimensions, the most obvious of which relates to a preemptive attack by the US or Israel. Yet even a stepped-up sanctions regime might either directly impede oil exports from Iran or provoke an Iranian reaction having the same effect, at a time when oil prices are already relatively high. Either scenario might trigger an oil price spike that would largely undo recent efforts to revive the global economy. At the moment, however, neither outcome seems very likely to me.
Whatever the IAEA's findings indicate about Iran's intentions or proximity to becoming a nuclear weapons state, the US has little appetite for initiating an attack with such uncertain outcomes on the basis of intelligence that remains incomplete. The public is hardly clamoring for another war, and the administration seems understandably reticent to take such a step, particularly going into an election year. Israeli public opinion--and even its leaders--appear split on the advisability of independent action against Iran's nuclear complex. Even in terms of sanctions, I would expect a response with more bark than bite that stops short of antagonizing Iran's regime to the point at which it might use its oil weapon. Unfortunately, the longer this protracted confrontation over Iran's nuclear program drags out, the greater the risk of one or more parties miscalculating, with results that could spin out of anyone's control.
The Council on Foreign Relations has put out some useful interviews and analysis on the IAEA report and the possible responses to it. Have a look and draw your own conclusions.
Thursday, November 10, 2011
Breaking Our Oil Addiction
In an article in today's Washington Post an official of the National Wildlife Federation was quoted linking rejection of the Keystone XL pipeline with breaking our addiction to oil. Even with the administration apparently having delayed its decision on the project until 2013--quite possibly killing it--this point merits further exploration. Just how might we go about breaking that "addiction", and when could we reasonably expect the task to be accomplished? As with everything else to do with energy, the answers to those questions must be based on facts and figures, rather than wishfulness.
The brief quote and its context imply that a decision to forgo additional supplies of oil from Canada or any other source would, by itself, move us significantly closer to breaking our addiction to oil, a rather vague phrase brought into common usage by President Bush's 2006 State of the Union address. Of course if delaying or rejecting the pipeline only results in continued or additional oil imports from other countries, that would be counterproductive from an energy security standpoint, and perhaps even from an environmental perspective. Ending our oil addiction requires more than just a real or artificial supply constraint; it calls for enormous quantities of energy from other sources, mainly for transportation, along with significant improvements in the efficiency with which we use that energy. How soon should we expect such a transformation?
Start with electric vehicles, which are essentially the only pathway by which renewable electricity sources like wind, solar and geothermal power would have any impact on our oil consumption, because less than 1% of US electricity is now generated from oil. Even if EVs turn out to be the long-term solution to our transportation needs, as I suspect, it will be many years before they can displace enough fuel demand to make a dent in our oil addiction. The current goal is to have a million EVs on the road by 2015. As ambitious as that target seems compared to current sales of less expensive hybrid cars, that would constitute just 0.4% of the 238 million cars and light trucks in the US as of 2008. Moreover, even if EVs replaced cars of only average efficiency, one million of them would displace just 31,000 barrels per day of gasoline. In other words, it would take more than 20 million EVs to save the volume of oil that the Keystone Pipeline could have delivered annually.
If we want to kick our oil habit quicker than by waiting for a hundred million EVs to turn up, we'll need an energy source that's compatible with the vast majority of existing cars, and the ones like them that will probably dominate new car sales for some time. Consider ethanol, our largest and most successful alternative energy initiative so far. Through August, ethanol accounted for 9.2% of 2011 US gasoline consumption, nearly four times its contribution in 2005. However, before we could use a lot more ethanol in our cars, in the way Brazil has, we would need to overcome some big hurdles. Raising the proportion of ethanol in gasoline above 10% creates logistical and reliability problems, and the flexible fuel vehicles that can run on nearly pure ethanol are relatively scarce. In addition, we would need to produce most of the incremental ethanol from a feedstock other than corn. With the latest disappointing crop forecast from the US Department of Agriculture, ethanol production will consume about 41% of this year's harvest. Whether or not that's already enough to cause major food vs. fuel concerns, doubling corn use for ethanol would clearly push corn prices up drastically and cause ripple effects throughout the global food economy.
The good news is that biofuels--including better fuels than ethanol--can be produced from a wide variety of non-food crops, along with their efficient production from sugar cane in the tropics. The bad news is that with the exception of cane ethanol, none of these has been demonstrated on anything close to the scale required. Two of the largest cellulosic ethanol projects under construction, POET's Emmetsburg, Iowa project and the Vero Beach, FL facility of INEOS Bio, will together be capable of supplying just 0.02% of US vehicle fuel needs. And until these plants are up and running, their owners won't know whether their economics are sufficiently favorable--even with the current $1.01 per gallon cellulosic tax credit--to provide a basis for building more and larger versions. Although some of the many competing processes for producing biofuels from non-food biomass including wood, waste, dedicated energy crops and algae look very promising, they all face major uncertainties in development and scaling-up, including the scale-up of their supply chains, and none is yet ready for prime time. That might still be the case ten years from now.
Of course there are many other fuels we could put in our cars, after some modifications, including methanol, compressed natural gas (CNG), liquefied natural gas (LNG) or possibly even ammonia. However, the production of all of these, aside from a relatively small amount of landfill gas, is currently based on fossil natural gas, and all would require major investments in infrastructure and/or vehicle fleets. For that matter, 78% of the energy content of corn ethanol comes from natural gas and other fossil fuels--it also consumes enormous quantities of water--and most of the incremental electricity consumed by the first EVs will likely be generated from gas.
Although it appears that we have ample resources of natural gas to expand its use beyond current demand, I'm not sure that's quite what environmentalists have in mind when they talk about breaking our addiction to oil. And so far we've only considered alternatives to gasoline, without factoring in the significant demand for petroleum products for moving goods by truck, train and ship, along with aviation fuels, lubricants and many other products. Together, they account for as much oil as we use in cars, with non-oil alternatives for most of them at an earlier stage than for gasoline. And while energy efficiency measures, including the substantial improvements in vehicle fuel economy that are possible on a technology-neutral basis--including shifting cars to fuel-efficient diesels--can help to reduce the size of the mountain we must climb, they can't turn it into a valley.
Taking all these considerations into account it's not realistic to imagine that we could break our addiction to oil to any great extent for at least another decade. In the interim, we should certainly pursue all options that could alter the feasibility of such a shift in the years ahead, in a manner consistent with the fiscal constraints we face. I'm also not oblivious to what that implies for greenhouse gas emissions and climate change, though I would point out that our use of oil in transportation is neither the worst emissions offender, nor the easiest high-emitting segment of the US energy economy to tackle in that time frame. In the meantime, we are committed by virtue of scale, infrastructure and fleet requirements to burn many billions of barrels of oil over the next few decades, from wherever they may come. In that light, the administration's decision on the Keystone XL pipeline could prove to be a costly misstep, no matter how much political pressure they were under to withhold approval.
Addendum: Bloomberg has put out an interesting post-decision editorial suggesting that there's no reason for the review of an alternate pipeline route to take as long as the State Dept. has indicated.
The brief quote and its context imply that a decision to forgo additional supplies of oil from Canada or any other source would, by itself, move us significantly closer to breaking our addiction to oil, a rather vague phrase brought into common usage by President Bush's 2006 State of the Union address. Of course if delaying or rejecting the pipeline only results in continued or additional oil imports from other countries, that would be counterproductive from an energy security standpoint, and perhaps even from an environmental perspective. Ending our oil addiction requires more than just a real or artificial supply constraint; it calls for enormous quantities of energy from other sources, mainly for transportation, along with significant improvements in the efficiency with which we use that energy. How soon should we expect such a transformation?
Start with electric vehicles, which are essentially the only pathway by which renewable electricity sources like wind, solar and geothermal power would have any impact on our oil consumption, because less than 1% of US electricity is now generated from oil. Even if EVs turn out to be the long-term solution to our transportation needs, as I suspect, it will be many years before they can displace enough fuel demand to make a dent in our oil addiction. The current goal is to have a million EVs on the road by 2015. As ambitious as that target seems compared to current sales of less expensive hybrid cars, that would constitute just 0.4% of the 238 million cars and light trucks in the US as of 2008. Moreover, even if EVs replaced cars of only average efficiency, one million of them would displace just 31,000 barrels per day of gasoline. In other words, it would take more than 20 million EVs to save the volume of oil that the Keystone Pipeline could have delivered annually.
If we want to kick our oil habit quicker than by waiting for a hundred million EVs to turn up, we'll need an energy source that's compatible with the vast majority of existing cars, and the ones like them that will probably dominate new car sales for some time. Consider ethanol, our largest and most successful alternative energy initiative so far. Through August, ethanol accounted for 9.2% of 2011 US gasoline consumption, nearly four times its contribution in 2005. However, before we could use a lot more ethanol in our cars, in the way Brazil has, we would need to overcome some big hurdles. Raising the proportion of ethanol in gasoline above 10% creates logistical and reliability problems, and the flexible fuel vehicles that can run on nearly pure ethanol are relatively scarce. In addition, we would need to produce most of the incremental ethanol from a feedstock other than corn. With the latest disappointing crop forecast from the US Department of Agriculture, ethanol production will consume about 41% of this year's harvest. Whether or not that's already enough to cause major food vs. fuel concerns, doubling corn use for ethanol would clearly push corn prices up drastically and cause ripple effects throughout the global food economy.
The good news is that biofuels--including better fuels than ethanol--can be produced from a wide variety of non-food crops, along with their efficient production from sugar cane in the tropics. The bad news is that with the exception of cane ethanol, none of these has been demonstrated on anything close to the scale required. Two of the largest cellulosic ethanol projects under construction, POET's Emmetsburg, Iowa project and the Vero Beach, FL facility of INEOS Bio, will together be capable of supplying just 0.02% of US vehicle fuel needs. And until these plants are up and running, their owners won't know whether their economics are sufficiently favorable--even with the current $1.01 per gallon cellulosic tax credit--to provide a basis for building more and larger versions. Although some of the many competing processes for producing biofuels from non-food biomass including wood, waste, dedicated energy crops and algae look very promising, they all face major uncertainties in development and scaling-up, including the scale-up of their supply chains, and none is yet ready for prime time. That might still be the case ten years from now.
Of course there are many other fuels we could put in our cars, after some modifications, including methanol, compressed natural gas (CNG), liquefied natural gas (LNG) or possibly even ammonia. However, the production of all of these, aside from a relatively small amount of landfill gas, is currently based on fossil natural gas, and all would require major investments in infrastructure and/or vehicle fleets. For that matter, 78% of the energy content of corn ethanol comes from natural gas and other fossil fuels--it also consumes enormous quantities of water--and most of the incremental electricity consumed by the first EVs will likely be generated from gas.
Although it appears that we have ample resources of natural gas to expand its use beyond current demand, I'm not sure that's quite what environmentalists have in mind when they talk about breaking our addiction to oil. And so far we've only considered alternatives to gasoline, without factoring in the significant demand for petroleum products for moving goods by truck, train and ship, along with aviation fuels, lubricants and many other products. Together, they account for as much oil as we use in cars, with non-oil alternatives for most of them at an earlier stage than for gasoline. And while energy efficiency measures, including the substantial improvements in vehicle fuel economy that are possible on a technology-neutral basis--including shifting cars to fuel-efficient diesels--can help to reduce the size of the mountain we must climb, they can't turn it into a valley.
Taking all these considerations into account it's not realistic to imagine that we could break our addiction to oil to any great extent for at least another decade. In the interim, we should certainly pursue all options that could alter the feasibility of such a shift in the years ahead, in a manner consistent with the fiscal constraints we face. I'm also not oblivious to what that implies for greenhouse gas emissions and climate change, though I would point out that our use of oil in transportation is neither the worst emissions offender, nor the easiest high-emitting segment of the US energy economy to tackle in that time frame. In the meantime, we are committed by virtue of scale, infrastructure and fleet requirements to burn many billions of barrels of oil over the next few decades, from wherever they may come. In that light, the administration's decision on the Keystone XL pipeline could prove to be a costly misstep, no matter how much political pressure they were under to withhold approval.
Addendum: Bloomberg has put out an interesting post-decision editorial suggesting that there's no reason for the review of an alternate pipeline route to take as long as the State Dept. has indicated.
Monday, November 07, 2011
Will Energy Determine the 2012 Election?
A year from today Americans will know who will serve as President from 2013 to 2017. Even though $4 gasoline was still fresh in the minds of voters, energy played only a minor role in the outcome of the 2008 election, overshadowed by two wars and a crippling financial crisis. Will that be the case again in 2012, or will energy loom larger, propelled by its close connection with the economy? Several Republican candidates have already raised energy as a campaign issue, and the administration has repeatedly emphasized the linkages between energy, jobs and taxes. Whether any of those arguments gains traction in a race that at this point seems likely to be dominated by unemployment and deficits could depend on how deftly the administration handles decisions such as the Keystone XL Pipeline permit, as well as the degree to which voters become interested in the details of the country's shifting energy balances.
From day one, the Obama administration has taken a calculated risk on energy by focusing most of its non-crisis-response attention on promoting renewables such as biofuels and wind, solar and geothermal power. According to the latest figures from the Energy Information Agency the combined contribution to our total energy diet from these sources increased from 2.2% in 2008 to 3.2% in 2010. Rightly or wrongly, the Solyndra fiasco could leave voters questioning the wisdom of the whole suite of renewables policies that promise large future benefits but have had little tangible impact so far. Nor do the administration's efforts to claim credit for increasing US oil production look very credible when they demonstrably reflected the characteristic time lags of investments made during the Bush years, and occurred largely in spite of policies such as the Gulf of Mexico drilling moratorium and various onshore lease cancellations.
Meanwhile, the single largest energy development of recent years, the harnessing of vast shale gas resources, which last year supplied the equivalent of more than triple the combined output of US wind, solar and geothermal power, has occurred against a background of governmental ambivalence and occasional outright hostility, as in the case of New York's state moratorium on hydraulic fracturing, or "fracking". Unless the Obama administration moves to embrace shale gas, which David Brooks of the New York Times referred to in his column last week as a "wondrous gift", it might not be very hard for the President's challenger next year to portray his policies as being focused on only 3% of the energy that drives the economy, while neglecting the other 97%.
In that context, the Keystone XL decision could prove crucial. The State Department has signaled that the decision, which was anticipated by year-end, might be delayed into next year or beyond. Recent remarks hinted that the President may make the call personally. And in an interview during last Thursday's Washington Post Smart Energy Conference, Energy Secretary Chu backed away from his previous partial endorsement of the project. Taken together, these moves have me questioning the conventional wisdom that expects a grudging approval of Keystone. Turning it down outright, or killing it by attaching a set of uneconomical conditions to a contingent approval, would play well with portions of the President's base, but it might be hard to defend to independent voters later, particularly if higher oil prices or some event moved energy up the list of top election issues. Delaying a decision past the election would probably satisfy no one.
Whoever wins in 2012, the nation will need a renewed energy policy that balances the need to continue funding research and development aimed at delivering renewable energy technologies that can compete with conventional energy with little or no need for further subsidies, while simultaneously and just as vigorously promoting domestic and wider North American production of the conventional energy sources we will still need for at least another several decades, if we don't want to return to our former trend of becoming steadily more dependent on imported energy. Even if today's 3% from new renewable sources grows to 30%, we will still depend on oil, gas, nuclear and coal for the other 70%, nor can we rely on energy efficiency to end our reliance on the latter sources. I look forward to seeing more detailed energy proposals from both sides over the next year.
From day one, the Obama administration has taken a calculated risk on energy by focusing most of its non-crisis-response attention on promoting renewables such as biofuels and wind, solar and geothermal power. According to the latest figures from the Energy Information Agency the combined contribution to our total energy diet from these sources increased from 2.2% in 2008 to 3.2% in 2010. Rightly or wrongly, the Solyndra fiasco could leave voters questioning the wisdom of the whole suite of renewables policies that promise large future benefits but have had little tangible impact so far. Nor do the administration's efforts to claim credit for increasing US oil production look very credible when they demonstrably reflected the characteristic time lags of investments made during the Bush years, and occurred largely in spite of policies such as the Gulf of Mexico drilling moratorium and various onshore lease cancellations.
Meanwhile, the single largest energy development of recent years, the harnessing of vast shale gas resources, which last year supplied the equivalent of more than triple the combined output of US wind, solar and geothermal power, has occurred against a background of governmental ambivalence and occasional outright hostility, as in the case of New York's state moratorium on hydraulic fracturing, or "fracking". Unless the Obama administration moves to embrace shale gas, which David Brooks of the New York Times referred to in his column last week as a "wondrous gift", it might not be very hard for the President's challenger next year to portray his policies as being focused on only 3% of the energy that drives the economy, while neglecting the other 97%.
In that context, the Keystone XL decision could prove crucial. The State Department has signaled that the decision, which was anticipated by year-end, might be delayed into next year or beyond. Recent remarks hinted that the President may make the call personally. And in an interview during last Thursday's Washington Post Smart Energy Conference, Energy Secretary Chu backed away from his previous partial endorsement of the project. Taken together, these moves have me questioning the conventional wisdom that expects a grudging approval of Keystone. Turning it down outright, or killing it by attaching a set of uneconomical conditions to a contingent approval, would play well with portions of the President's base, but it might be hard to defend to independent voters later, particularly if higher oil prices or some event moved energy up the list of top election issues. Delaying a decision past the election would probably satisfy no one.
Whoever wins in 2012, the nation will need a renewed energy policy that balances the need to continue funding research and development aimed at delivering renewable energy technologies that can compete with conventional energy with little or no need for further subsidies, while simultaneously and just as vigorously promoting domestic and wider North American production of the conventional energy sources we will still need for at least another several decades, if we don't want to return to our former trend of becoming steadily more dependent on imported energy. Even if today's 3% from new renewable sources grows to 30%, we will still depend on oil, gas, nuclear and coal for the other 70%, nor can we rely on energy efficiency to end our reliance on the latter sources. I look forward to seeing more detailed energy proposals from both sides over the next year.
Thursday, November 03, 2011
Do LNG Exports Threaten the Shift to Gas?
Last week US liquefied natural gas provider Cheniere signed a long-term agreement to sell BG (formerly British Gas) LNG exported from the Gulf Coast. The governor of Alaska was also recently quoted suggesting that his state's surplus natural gas might find a better market in Asia than if sent to the lower-48 via a new pipeline. Both stories indicate just how much the shale gas revolution has altered the US energy balance. They also provide further validation of its likely staying power. Coincidentally, they reminded me that time was running short to respond to my residential gas supplier's offer to lock in an annual fixed price, as I did last year. That's relevant, because even though the risk of a big spike in natural gas prices looks very low now, the prospect of future US gas exports--an unthinkable idea only a few years ago--serves notice that the shale bonanza is also stimulating new segments of demand that compete with existing ones and will tend to drive prices higher.
Cheniere's role in all this looks like a classic lemons-to-lemonade story. Their Sabine Pass LNG terminal and two others in development on the Gulf Coast were designed to import gas and feed it into the domestic pipeline system. They weren't the only ones to pursue this idea, which looked entirely reasonable when they were planned. In the first half of the last decade US gas production was in decline and LNG imports were climbing, facilitated by rising gas prices that made imports at the higher global gas price attractive, at least seasonally. The combination of a surge of shale gas output and the largest US recession in decades turned these plans on their head. Now Cheniere is redeveloping Sabine as an LNG liquefaction and export facility, with construction scheduled to begin next year.
The Wall St. Journal's Heard on the Street column had a good analysis of Cheniere's deal with BG. It closed with the observation that, "...it is natural that excess supply should seek a market." That got me thinking, not just about what I might be paying for natural gas to heat my home in a few years, but about whether exports pose a threat to ambitious notions of displacing large increments of coal-fired electricity with power from gas turbines, shifting large numbers of US cars and long-haul trucks to compressed natural gas (CNG) or LNG, and building new US chemical plants to capitalize on the abundance of shale gas. Most of these plans depend on gas remaining fairly cheap, particularly relative to oil. The current price of natural gas at its key Henry Hub trading point is the equivalent of $22.50 per barrel, a level that we haven't seen for oil since March 2002. Could gas exports drive up domestic prices to the point at which these other uses couldn't compete?
The answer depends both on how much gas would be exported and on the shape of the supply curve for shale gas. If the latter is steep--if not much extra supply can be brought on without requiring big increases in price--then exports could begin to look like a zero-sum-game at the expense of today's consumers and tomorrow's other new uses for gas. However, if large quantities of shale gas are waiting in the wings for only small increases in price, then while all these uses would be in competition with each other, they should be able to coexist at prices that leave gas considerably more attractive than oil, and competitive with both coal and the cheapest renewables. Assessing which view is likelier isn't simple, because it involves multiple shale basins and evolving federal and state regulations, but in general the data I've seen supports the more optimistic view. Many estimates suggest that most US shale plays would produce attractive returns at around $5-6 per million BTUs (MMBTU), compared to current prices around $4, which have left some producers with poor wellhead economics.
If that's correct, then even a big increase in demand from multiple sources, including a stronger economy, additional power generation, new chemical plants and LNG exports, might not boost natural gas prices by more than $1-2/MMTBU before significant additional supply came onstream. (A reality check on that is the sharp drop in the number of gas wells being drilled when prices slid below $6/MMBTU in late 2008, as the recession and financial crisis took hold.) $1/MMBTU sounds like a big jump at the wellhead, but for consumers it would represent an increase of only about 8% after transmission and distribution costs are added. For power generation in efficient combined cycle plants, it would raise costs by less than $0.01/kWh. And for vehicle use, it equates to an extra $5/bbl, or around 12.5 cents per gallon of gasoline-equivalent fuel. Although not trivial, such increases would be smaller than we've seen from market volatility over the last few years.
Putting the Cheniere/BG deal in perspective, the 3.5 million tons of LNG per year involved equate to 0.5 billion cubic feet per day of gas, or 0.8% of 2010 US "dry gas" production (natural gas with the valuable ethane, propane and butane removed.) The facility's total planned capacity of 9 million ton/y works out to 2% of US gas last year. By comparison the Department of Energy has forecasted US gas production growing by about 3.3 BCFD, or 6% in the next five years in their base case, and by up to 14% in their high-shale-resource case. These figures indicate that there's room for several of these demand sectors to expand, including both power generation and LNG exports, without putting intense pressure on prices. This issue is attracting some attention, including from the US Senate, which has scheduled a hearing next week to consider the consequences of gas exports.
Cheniere's role in all this looks like a classic lemons-to-lemonade story. Their Sabine Pass LNG terminal and two others in development on the Gulf Coast were designed to import gas and feed it into the domestic pipeline system. They weren't the only ones to pursue this idea, which looked entirely reasonable when they were planned. In the first half of the last decade US gas production was in decline and LNG imports were climbing, facilitated by rising gas prices that made imports at the higher global gas price attractive, at least seasonally. The combination of a surge of shale gas output and the largest US recession in decades turned these plans on their head. Now Cheniere is redeveloping Sabine as an LNG liquefaction and export facility, with construction scheduled to begin next year.
The Wall St. Journal's Heard on the Street column had a good analysis of Cheniere's deal with BG. It closed with the observation that, "...it is natural that excess supply should seek a market." That got me thinking, not just about what I might be paying for natural gas to heat my home in a few years, but about whether exports pose a threat to ambitious notions of displacing large increments of coal-fired electricity with power from gas turbines, shifting large numbers of US cars and long-haul trucks to compressed natural gas (CNG) or LNG, and building new US chemical plants to capitalize on the abundance of shale gas. Most of these plans depend on gas remaining fairly cheap, particularly relative to oil. The current price of natural gas at its key Henry Hub trading point is the equivalent of $22.50 per barrel, a level that we haven't seen for oil since March 2002. Could gas exports drive up domestic prices to the point at which these other uses couldn't compete?
The answer depends both on how much gas would be exported and on the shape of the supply curve for shale gas. If the latter is steep--if not much extra supply can be brought on without requiring big increases in price--then exports could begin to look like a zero-sum-game at the expense of today's consumers and tomorrow's other new uses for gas. However, if large quantities of shale gas are waiting in the wings for only small increases in price, then while all these uses would be in competition with each other, they should be able to coexist at prices that leave gas considerably more attractive than oil, and competitive with both coal and the cheapest renewables. Assessing which view is likelier isn't simple, because it involves multiple shale basins and evolving federal and state regulations, but in general the data I've seen supports the more optimistic view. Many estimates suggest that most US shale plays would produce attractive returns at around $5-6 per million BTUs (MMBTU), compared to current prices around $4, which have left some producers with poor wellhead economics.
If that's correct, then even a big increase in demand from multiple sources, including a stronger economy, additional power generation, new chemical plants and LNG exports, might not boost natural gas prices by more than $1-2/MMTBU before significant additional supply came onstream. (A reality check on that is the sharp drop in the number of gas wells being drilled when prices slid below $6/MMBTU in late 2008, as the recession and financial crisis took hold.) $1/MMBTU sounds like a big jump at the wellhead, but for consumers it would represent an increase of only about 8% after transmission and distribution costs are added. For power generation in efficient combined cycle plants, it would raise costs by less than $0.01/kWh. And for vehicle use, it equates to an extra $5/bbl, or around 12.5 cents per gallon of gasoline-equivalent fuel. Although not trivial, such increases would be smaller than we've seen from market volatility over the last few years.
Putting the Cheniere/BG deal in perspective, the 3.5 million tons of LNG per year involved equate to 0.5 billion cubic feet per day of gas, or 0.8% of 2010 US "dry gas" production (natural gas with the valuable ethane, propane and butane removed.) The facility's total planned capacity of 9 million ton/y works out to 2% of US gas last year. By comparison the Department of Energy has forecasted US gas production growing by about 3.3 BCFD, or 6% in the next five years in their base case, and by up to 14% in their high-shale-resource case. These figures indicate that there's room for several of these demand sectors to expand, including both power generation and LNG exports, without putting intense pressure on prices. This issue is attracting some attention, including from the US Senate, which has scheduled a hearing next week to consider the consequences of gas exports.
Tuesday, November 01, 2011
How Many More Solyndras?
Another firm that received a loan guarantee from the Department of Energy has just filed for bankruptcy. Beacon Power had drawn down $39.1 million of the $43 million authorized by the DOE for the construction of its 20 MW energy storage facility in Stephenstown, NY, but was still operating at a loss and unable to find additional backing. As was the case for Solyndra, the DOE's "loan guarantee" actually took the form of a direct loan from the Federal Financing Bank, an arm of the US Treasury, rather than from a commercial bank or other private-sector lender. If two data points can indicate a pattern, the one here reflects poorly on venture capital decisions made solely by government officials lacking any stake in the eventual outcome of the investment. Real venture capitalists make bad bets, too, but with an entirely different degree of accountability.
The Beacon failure is especially disheartening, because it involves the application of energy storage to grid services, which many believe is crucial for integrating large increments of intermittent renewable energy--mainly wind and solar power--into our electricity supply. In particular, Beacon's use of flywheels, rapidly rotating disks capable of storing and releasing large amounts of energy quickly, looked like a promising alternative to chemical batteries. I've long been intrigued by this technology, which is also being applied to race cars. Beacon's problems appear to be both technical and financial, with two of the company's flywheels having failed catastrophically since startup due to manufacturing defects, and the business model generating insufficient revenue to support the company's obligations.
Unlike Solyndra, the DOE's investment in Beacon Power might not turn out to be a complete loss, though I don't share the confidence of the DOE's spokesman that the "valuable collateral asset" will enable the government to recover the entire sum it lent Beacon. With an operating facility and ongoing revenues, it's possible that the firm's liabilities could be reorganized in such a way than it could emerge from bankruptcy as a viable entity. However, if its reported second-quarter revenue of $525,000 is indicative, it's very hard to see that either the business or the underlying assets could be worth more than a fraction of the $39 million federal loan liability, let alone their $72 million book value. "Haircuts" seem to be in vogue, and I'm guessing that Uncle Sam will take one on Beacon, in order to realize any value at all from the deal.
I'm relieved that the administration has finally ordered an independent review of the entire loan guarantee program, though it's a little late for that to accomplish much more at this stage than bringing additional problems to light. The main 1705 loan guarantee program is out of money and unlikely to receive further appropriations, at least until after the 2012 election. Meanwhile, another energy-related stimulus beneficiary, advanced-battery maker Ener1, was just de-listed from NASDAQ last Friday. The best coda on this whole situation may come from the blog of VC David Gold, who wrote yesterday that the administration's cleantech stimulus is turning out to be "Bad Policy, Bad Politics, and Bad for Cleantech." I'll bet there are many executives at cleantech firms who now wish they had never heard of Treasury grants and DOE loan guarantees.
The Beacon failure is especially disheartening, because it involves the application of energy storage to grid services, which many believe is crucial for integrating large increments of intermittent renewable energy--mainly wind and solar power--into our electricity supply. In particular, Beacon's use of flywheels, rapidly rotating disks capable of storing and releasing large amounts of energy quickly, looked like a promising alternative to chemical batteries. I've long been intrigued by this technology, which is also being applied to race cars. Beacon's problems appear to be both technical and financial, with two of the company's flywheels having failed catastrophically since startup due to manufacturing defects, and the business model generating insufficient revenue to support the company's obligations.
Unlike Solyndra, the DOE's investment in Beacon Power might not turn out to be a complete loss, though I don't share the confidence of the DOE's spokesman that the "valuable collateral asset" will enable the government to recover the entire sum it lent Beacon. With an operating facility and ongoing revenues, it's possible that the firm's liabilities could be reorganized in such a way than it could emerge from bankruptcy as a viable entity. However, if its reported second-quarter revenue of $525,000 is indicative, it's very hard to see that either the business or the underlying assets could be worth more than a fraction of the $39 million federal loan liability, let alone their $72 million book value. "Haircuts" seem to be in vogue, and I'm guessing that Uncle Sam will take one on Beacon, in order to realize any value at all from the deal.
I'm relieved that the administration has finally ordered an independent review of the entire loan guarantee program, though it's a little late for that to accomplish much more at this stage than bringing additional problems to light. The main 1705 loan guarantee program is out of money and unlikely to receive further appropriations, at least until after the 2012 election. Meanwhile, another energy-related stimulus beneficiary, advanced-battery maker Ener1, was just de-listed from NASDAQ last Friday. The best coda on this whole situation may come from the blog of VC David Gold, who wrote yesterday that the administration's cleantech stimulus is turning out to be "Bad Policy, Bad Politics, and Bad for Cleantech." I'll bet there are many executives at cleantech firms who now wish they had never heard of Treasury grants and DOE loan guarantees.
Friday, October 28, 2011
Repaying Greece's Debts with Tomorrow's Sunlight
Some days the economic news seems to emanate from the Twilight Zone. When the official summit document from Wednesday's meeting of EU leaders seeking to avert another financial crisis includes a reference to repaying a portion of Greek debt with the output of a huge PV array that might not be completed for several decades, if it is built at all, I don't know how else to describe it. And that's before considering the perplexing economics behind the Helios scheme, which apparently entails Germany or other EU members investing or lending--after lenders have just agreed to take a 50% haircut on previous Greek debt--up to €20 billion to build a 10 GW PV installation in Greece to generate power that would be sent to central Europe via transmission lines that don't all exist yet. Either I'm missing a key element of the plan, or the EU ministers didn't quite grasp the details involved.
Let's start by stipulating that the idea of generating solar power in a sunny location like Greece and sending it to darker northern countries like Germany probably makes a lot more sense than investing billions of Euros installing additional solar in the latter, where it will be lucky to produce annual output equal to an average of 10% of its nameplate capacity, compared to 25% or more in an ideal location. That's the same logic behind the much larger and better-known Desertec plan, which would accomplish much the same goal from installations in North Africa and the Middle East, if it ever gets built. The problem in the case of Helios, as the Greek project is called, isn't the basic engineering concept but the financial one necessary for it to function in the manner suggested in the EU document.
In order for Helios to generate significant value to offset part of Greece's borrowings from the European Financial Stability Facility (EFSF) and other EU institutions, it would follow that Greece should actually own either the Helios installation or the rights to most of the power it would generate. Yet it's also clear that Helios could only be built with massive non-Greek investment of either equity or debt. If equity, then wouldn't the foreign investors own most of Helios and its output, leaving Greece little from which to repay its debts? And if debt, wouldn't that mean Greece was repaying one debt with the proceeds of another, rendering this scheme just a circuitous form of rollover?
Perhaps the Greek government assumes it will end up with a large carried interest in the project merely from contributing the land upon which it would sit, and for streamlining the permitting process for building it. But what proportion of most PV projects is attributable to land, especially in competing, high-sun regions such as those involved in Desertec? I'd think it was pretty low compared to the value of all the solar and electrical hardware, which Greece can't afford to buy on its own. And once we determine how much of the project Greece would actually own, then we would need to calculate the revenue out of which debt repayment could be remitted. If they're counting on power prices close to today's German feed-in tariffs, which were just slashed again, I think they're going to be very disappointed at the end of the day. My guess is the power would be worth no more than around 10 €-cents per kWh at the source, to allow it to compete in the German wholesale market after accounting for transmission costs. At that rate a 100% share of twenty years of 10 GW of PV under Greece's average temperature-adjusted insolation might generate an undiscounted €25 billion, but that's before repaying the project's up-front investment and all other expenses.
Not so long ago the prospects for projects like Helios were mainly determined by the interaction of oil prices and climate policy, with strong global economic growth essentially a given. That proposition has recently been inverted, with oil prices, climate policy and energy development all being driven or constrained largely by economic factors. In this context Helios looks potentially useful as a development project that could provide some construction jobs and eventually generate some corporate tax revenue for Greece on the profits from exporting green electricity to the project's effective owners in central Europe. That could give the Greek economy a bit of a boost. However, the line in the EU communique in which , "Greece commits future cash flows from project Helios...to further reduce indebtedness of the Hellenic Republic by up to €15 billion with the aim of restoring the lending capacity of the EFSF," seems to reflect the same sort of thinking that brought Greece to its current situation.
Let's start by stipulating that the idea of generating solar power in a sunny location like Greece and sending it to darker northern countries like Germany probably makes a lot more sense than investing billions of Euros installing additional solar in the latter, where it will be lucky to produce annual output equal to an average of 10% of its nameplate capacity, compared to 25% or more in an ideal location. That's the same logic behind the much larger and better-known Desertec plan, which would accomplish much the same goal from installations in North Africa and the Middle East, if it ever gets built. The problem in the case of Helios, as the Greek project is called, isn't the basic engineering concept but the financial one necessary for it to function in the manner suggested in the EU document.
In order for Helios to generate significant value to offset part of Greece's borrowings from the European Financial Stability Facility (EFSF) and other EU institutions, it would follow that Greece should actually own either the Helios installation or the rights to most of the power it would generate. Yet it's also clear that Helios could only be built with massive non-Greek investment of either equity or debt. If equity, then wouldn't the foreign investors own most of Helios and its output, leaving Greece little from which to repay its debts? And if debt, wouldn't that mean Greece was repaying one debt with the proceeds of another, rendering this scheme just a circuitous form of rollover?
Perhaps the Greek government assumes it will end up with a large carried interest in the project merely from contributing the land upon which it would sit, and for streamlining the permitting process for building it. But what proportion of most PV projects is attributable to land, especially in competing, high-sun regions such as those involved in Desertec? I'd think it was pretty low compared to the value of all the solar and electrical hardware, which Greece can't afford to buy on its own. And once we determine how much of the project Greece would actually own, then we would need to calculate the revenue out of which debt repayment could be remitted. If they're counting on power prices close to today's German feed-in tariffs, which were just slashed again, I think they're going to be very disappointed at the end of the day. My guess is the power would be worth no more than around 10 €-cents per kWh at the source, to allow it to compete in the German wholesale market after accounting for transmission costs. At that rate a 100% share of twenty years of 10 GW of PV under Greece's average temperature-adjusted insolation might generate an undiscounted €25 billion, but that's before repaying the project's up-front investment and all other expenses.
Not so long ago the prospects for projects like Helios were mainly determined by the interaction of oil prices and climate policy, with strong global economic growth essentially a given. That proposition has recently been inverted, with oil prices, climate policy and energy development all being driven or constrained largely by economic factors. In this context Helios looks potentially useful as a development project that could provide some construction jobs and eventually generate some corporate tax revenue for Greece on the profits from exporting green electricity to the project's effective owners in central Europe. That could give the Greek economy a bit of a boost. However, the line in the EU communique in which , "Greece commits future cash flows from project Helios...to further reduce indebtedness of the Hellenic Republic by up to €15 billion with the aim of restoring the lending capacity of the EFSF," seems to reflect the same sort of thinking that brought Greece to its current situation.
Tuesday, October 25, 2011
Key Renewable Energy Subsidies About to Expire
The US renewable energy industry faces a greatly altered incentive environment next year, as eligibility for two of its largest current subsidies comes to an end at the close of 2011. The corn ethanol sector will likely see the complete withdrawal of the blenders' credit that has fueled its growth for more than 30 years, while new projects generating electricity from renewable energy sources must shortly attract investment without the Treasury grants that provided up-front cash in place of federal investment tax credits against taxable income--a commodity sometimes in even shorter supply among recipients than the energy they seek to generate. With these expirations taking place against the backdrop of a US presidential election campaign and record levels of deficit and federal debt, the prospects for another round of one-year subsidy extensions look slim. Yet renewable energy development in the US won't grind to a halt without them, because these two programs represent merely the most generous layer of the complex web supporting renewables.
Consider the venerable ethanol tax credit, which was made mostly redundant by the passage of the Energy Independence and Security Act of 2007, with its Renewable Fuels Standard mandating the use of increasing quantities of ethanol in gasoline. In fact, ethanol producers were never more than indirect beneficiaries of the $0.45 per gallon credit, which was paid to refiners and other gasoline blenders in order to help create a market for ethanol. Mission accomplished. Moreover, with US gasoline sales having stalled at a level that can barely absorb all the ethanol that existing US ethanol plants can produce, unless gasoline blends containing more than 10% ethanol become popular, there is simply no need for corn ethanol output to expand further. In fact, the market will be more than sufficiently challenged providing outlets for the limited quantities of cellulosic and other advanced ethanol likely to be produced in the next few years. As I've noted previously, forward-looking members of the industry are now seeking help in expanding the market for high-ethanol blends, rather than perpetuating an outdated support for existing sales.
The situation for renewable electricity sources like wind, solar and geothermal energy is more complicated. The expiring Treasury grants were introduced as part of the 2009 stimulus to stand in for the "tax equity swap" market, a category of financial transactions that froze up during the financial crisis. These swaps provided a private-sector cash-flow bridge between project expenditures and tax credits that only paid off after start-up as income was earned or energy produced. That was particularly helpful for smaller, less profitable developers, but it also provided an additional check on marginal projects. Even after credit markets eased, most developers understandably preferred the cash grants, which reduced their financing costs and avoided the fees that bankers charged on tax equity deals. However, that preference doesn't justify continuing the cash grant program--particularly for the large, profitable corporations that increasing dominate this space. The industry should focus more effort on fostering the revival of a liquid and competitive tax equity market and less on lobbying for an extension of a temporary stimulus measure.
Either way, the tax credits behind these grants and swaps won't last forever. Under current law, the principal federal tax credit for wind will be in place only through 2012, for biomass and geothermal through 2013, and for solar through 2016. Instead of a scenario of perpetual last-minute extensions such as we've seen in the past, the industry and its investors should be thinking about a scenario in which all these tax credits end, either as part of comprehensive tax reform that eliminates most such "tax expenditures"--including the ones for the oil and gas industry that have become so contentious in the last few years--or a transition to providing renewables with similar sorts of incentives as oil and gas, which essentially amount to forms of accelerated depreciation and modest tax breaks for manufacturing in the US, rather than in other countries.
It's also important to realize that even without these tax credits and in the absence of comprehensive federal energy legislation that looks unlikely any time soon, the industry would still retain numerous state-level benefits, starting with the renewable portfolio standards (RPS) for electricity currently in place in 29 states and the District of Columbia, a tally that encompasses most of the states with the best wind and solar resources. These RPS's are similar to the Renewable Fuel Standard for biofuels in requiring utilities to include increasing proportions of renewable energy in their supply portfolios, whether owned or purchased. Such standards, including California's aggressive RPS targeting 33% renewable electricity by 2020, stand outside the polarizing political debate over taxation and government expenditures. They function as an implicit tax on ratepayers, rather than taxpayers, because they show up within customers' utility bills rather than on their 1040 forms. That distinction could be particularly important if the congressional supercommittee fails to reach a consensus, and the default spending cuts built into the Budget Control Act that resolved this summer's debt ceiling crisis kick in.
So while it might appear that the US renewable energy industry is about it be cut loose from the key incentives that enabled it to grow to its present dimensions, it will continue to benefit from supports not enjoyed by other industrial sectors. Even when the current tax credits expire, renewables will have a mandated market providing a floor beneath them. Ethanol output won't revert to 2005 levels, nor will renewables vanish from the landscape, even if their growth slows a bit while the rest of the economy struggles to emerge from the aftermath of the Great Recession and financial crisis, and to avoid a double-dip. Meanwhile, global overcapacity in wind turbine and solar module manufacturing will keep their prices trending lower--and installations stronger--pending industry consolidations that will position both for healthier, more sustainable growth in the long run. All of this falls well short of the level of help for the industry that most renewable energy supporters would like to see, but it's far more than the level playing field (ignoring externalities) that would see cheap and abundant natural gas sweep away all competition for new power generation.
Consider the venerable ethanol tax credit, which was made mostly redundant by the passage of the Energy Independence and Security Act of 2007, with its Renewable Fuels Standard mandating the use of increasing quantities of ethanol in gasoline. In fact, ethanol producers were never more than indirect beneficiaries of the $0.45 per gallon credit, which was paid to refiners and other gasoline blenders in order to help create a market for ethanol. Mission accomplished. Moreover, with US gasoline sales having stalled at a level that can barely absorb all the ethanol that existing US ethanol plants can produce, unless gasoline blends containing more than 10% ethanol become popular, there is simply no need for corn ethanol output to expand further. In fact, the market will be more than sufficiently challenged providing outlets for the limited quantities of cellulosic and other advanced ethanol likely to be produced in the next few years. As I've noted previously, forward-looking members of the industry are now seeking help in expanding the market for high-ethanol blends, rather than perpetuating an outdated support for existing sales.
The situation for renewable electricity sources like wind, solar and geothermal energy is more complicated. The expiring Treasury grants were introduced as part of the 2009 stimulus to stand in for the "tax equity swap" market, a category of financial transactions that froze up during the financial crisis. These swaps provided a private-sector cash-flow bridge between project expenditures and tax credits that only paid off after start-up as income was earned or energy produced. That was particularly helpful for smaller, less profitable developers, but it also provided an additional check on marginal projects. Even after credit markets eased, most developers understandably preferred the cash grants, which reduced their financing costs and avoided the fees that bankers charged on tax equity deals. However, that preference doesn't justify continuing the cash grant program--particularly for the large, profitable corporations that increasing dominate this space. The industry should focus more effort on fostering the revival of a liquid and competitive tax equity market and less on lobbying for an extension of a temporary stimulus measure.
Either way, the tax credits behind these grants and swaps won't last forever. Under current law, the principal federal tax credit for wind will be in place only through 2012, for biomass and geothermal through 2013, and for solar through 2016. Instead of a scenario of perpetual last-minute extensions such as we've seen in the past, the industry and its investors should be thinking about a scenario in which all these tax credits end, either as part of comprehensive tax reform that eliminates most such "tax expenditures"--including the ones for the oil and gas industry that have become so contentious in the last few years--or a transition to providing renewables with similar sorts of incentives as oil and gas, which essentially amount to forms of accelerated depreciation and modest tax breaks for manufacturing in the US, rather than in other countries.
It's also important to realize that even without these tax credits and in the absence of comprehensive federal energy legislation that looks unlikely any time soon, the industry would still retain numerous state-level benefits, starting with the renewable portfolio standards (RPS) for electricity currently in place in 29 states and the District of Columbia, a tally that encompasses most of the states with the best wind and solar resources. These RPS's are similar to the Renewable Fuel Standard for biofuels in requiring utilities to include increasing proportions of renewable energy in their supply portfolios, whether owned or purchased. Such standards, including California's aggressive RPS targeting 33% renewable electricity by 2020, stand outside the polarizing political debate over taxation and government expenditures. They function as an implicit tax on ratepayers, rather than taxpayers, because they show up within customers' utility bills rather than on their 1040 forms. That distinction could be particularly important if the congressional supercommittee fails to reach a consensus, and the default spending cuts built into the Budget Control Act that resolved this summer's debt ceiling crisis kick in.
So while it might appear that the US renewable energy industry is about it be cut loose from the key incentives that enabled it to grow to its present dimensions, it will continue to benefit from supports not enjoyed by other industrial sectors. Even when the current tax credits expire, renewables will have a mandated market providing a floor beneath them. Ethanol output won't revert to 2005 levels, nor will renewables vanish from the landscape, even if their growth slows a bit while the rest of the economy struggles to emerge from the aftermath of the Great Recession and financial crisis, and to avoid a double-dip. Meanwhile, global overcapacity in wind turbine and solar module manufacturing will keep their prices trending lower--and installations stronger--pending industry consolidations that will position both for healthier, more sustainable growth in the long run. All of this falls well short of the level of help for the industry that most renewable energy supporters would like to see, but it's far more than the level playing field (ignoring externalities) that would see cheap and abundant natural gas sweep away all competition for new power generation.
Thursday, October 20, 2011
US Energy Poll Reveals Contradictions
Yesterday I received a press release announcing the results of a new poll on US consumer attitudes towards energy conducted by the McCombs School of Business at the University of Texas in Austin. I wasn't surprised to see that a plurality of the poll's respondents thinks the country is headed in the wrong direction on energy--triple the proportion that think we're on the right track--and many expect the situation to get worse in the next 25 years. That meshes with numerous readings on Americans' views of the overall economy. The poll also showed consumers broadly dissatisfied with the job that government and industry are doing in this regard, though the renewable energy sector, along with engineers, scientists and academia received somewhat better marks. At the same time, the results on several questions either contradict current consumer trends or reveal a poor understanding of energy market influences. Perhaps the most reassuring finding was that less than a quarter of consumers consider themselves knowledgeable on energy, while a large majority is interested in learning more.
The main question that grabbed my attention concerned consumers' "expectations for adopting new technology." 38% reported they were likely to use smart meter technology within the next five years, 30% said they were likely to own a hybrid car, and 21% were likely to install solar panels on their homes. On the face of it, these should be very encouraging results for the renewable energy and advanced vehicle sectors and those who invest in them. At the same time, it's hard to square these figures with the actual adoption rates for such technologies in the marketplace.
Consider hybrids, which have lost most of their novelty in the last decade, with cumulative US hybrid car sales standing at just over 2 million at this point. That's less than 1% of total US light-duty vehicles (cars, SUVs and light trucks), but it's still impressive, considering they started at essentially zero in the late 1990s. The problem is that even now, with practically every major carmaker offering at least one hybrid model, and several fielding an entire range of hybrids, 2011 sales have averaged just 2% of total US car sales of 9.5 million through September, based on figures compiled by hybridcars.com. Add plug-in electric cars like the Chevrolet Volt and Nissan Leaf and you get to 2.1%. Even before hybrid supplies were constrained in the aftermath of the earthquake in Japan, advanced vehicle sales never topped 3% in any month of this year.
The poll provides few insights into why the actual "take rate"would amount to less than a tenth of those with favorable attitudes towards buying a hybrid. However, it does suggest that the standard explanation that gas prices just aren't high enough yet is out of step with how consumers view those prices. Fully 95% of respondents described gas prices as either "very high" or "somewhat high", and 78% expected them to be somewhat or significantly higher in six months. One possible conclusion is that despite coming in compact, SUV, truck and luxury flavors, hybrid technology still doesn't deliver the value and/or performance most consumers are seeking, even if they're receptive to it in the abstract.
Then there's the even more dramatic disconnect on solar power. If 21% of single-family dwellings in the US were to install rooftop solar panels of 3 kW or more in the next five years, that would equate to at least 228 GW of solar power--about 90 times current US installed capacity--for average installations of 46 GW per year, or nearly three times the amount installed globally last year, mostly in Europe. As of the end of 2010, there were 153,000 grid-connected PV systems in the US, including commercial and utility installations. Even if all of them were on the rooftops of homes, that would still amount to just a 0.2% market penetration. Although PV prices are coming down rapidly and sales could approach 2 GW in 2011, this divergence between sentiment and sales suggests that a lot more Americans like the idea of rooftop solar than are actually willing to invest in buying (or leasing) it at this point.
Whatever the UT poll results indicate about the potential medium-term market share of new energy technologies, they provide a data point that Americans view energy as another important issue they believe government is getting wrong. They also highlight the need and opportunity for more education on how energy markets really work, with supply constraints and growing demand actually having a much bigger impact on energy prices than the limited pricing power most energy companies enjoy.
The main question that grabbed my attention concerned consumers' "expectations for adopting new technology." 38% reported they were likely to use smart meter technology within the next five years, 30% said they were likely to own a hybrid car, and 21% were likely to install solar panels on their homes. On the face of it, these should be very encouraging results for the renewable energy and advanced vehicle sectors and those who invest in them. At the same time, it's hard to square these figures with the actual adoption rates for such technologies in the marketplace.
Consider hybrids, which have lost most of their novelty in the last decade, with cumulative US hybrid car sales standing at just over 2 million at this point. That's less than 1% of total US light-duty vehicles (cars, SUVs and light trucks), but it's still impressive, considering they started at essentially zero in the late 1990s. The problem is that even now, with practically every major carmaker offering at least one hybrid model, and several fielding an entire range of hybrids, 2011 sales have averaged just 2% of total US car sales of 9.5 million through September, based on figures compiled by hybridcars.com. Add plug-in electric cars like the Chevrolet Volt and Nissan Leaf and you get to 2.1%. Even before hybrid supplies were constrained in the aftermath of the earthquake in Japan, advanced vehicle sales never topped 3% in any month of this year.
The poll provides few insights into why the actual "take rate"would amount to less than a tenth of those with favorable attitudes towards buying a hybrid. However, it does suggest that the standard explanation that gas prices just aren't high enough yet is out of step with how consumers view those prices. Fully 95% of respondents described gas prices as either "very high" or "somewhat high", and 78% expected them to be somewhat or significantly higher in six months. One possible conclusion is that despite coming in compact, SUV, truck and luxury flavors, hybrid technology still doesn't deliver the value and/or performance most consumers are seeking, even if they're receptive to it in the abstract.
Then there's the even more dramatic disconnect on solar power. If 21% of single-family dwellings in the US were to install rooftop solar panels of 3 kW or more in the next five years, that would equate to at least 228 GW of solar power--about 90 times current US installed capacity--for average installations of 46 GW per year, or nearly three times the amount installed globally last year, mostly in Europe. As of the end of 2010, there were 153,000 grid-connected PV systems in the US, including commercial and utility installations. Even if all of them were on the rooftops of homes, that would still amount to just a 0.2% market penetration. Although PV prices are coming down rapidly and sales could approach 2 GW in 2011, this divergence between sentiment and sales suggests that a lot more Americans like the idea of rooftop solar than are actually willing to invest in buying (or leasing) it at this point.
Whatever the UT poll results indicate about the potential medium-term market share of new energy technologies, they provide a data point that Americans view energy as another important issue they believe government is getting wrong. They also highlight the need and opportunity for more education on how energy markets really work, with supply constraints and growing demand actually having a much bigger impact on energy prices than the limited pricing power most energy companies enjoy.
Tuesday, October 18, 2011
Pipelines in the Spotlight
There aren't many parts of the energy value chain that normally receive less attention than pipelines. Energy production, whether from oil and gas fields, nuclear power plants, or rapidly growing renewable sources usually garners far more attention for the impressive technology and capital involved. By contrast pipelines are long-lived, relatively low-tech and low-return assets that often seem invisible to those outside the industry. Sunday's announcement of Kinder Morgan's bid for El Paso Corp., uniting two pipeline giants into a $94 billion enterprise, reminds us just how big this low-key infrastructure can be. This deal also signals important shifts underway within the fossil fuel industry. Just as the rise of wind and solar power requires an upgraded electricity grid, changes in the sources of our oil and gas have big implications for the networks required to bring these fuels to market.
As an article in today's Wall St. Journal states in its title, the Kinder Morgan-El Paso deal heralds the arrival of the Age of Shale. It simultaneously validates the potential of US shale gas resources and points to a new set of growth opportunities created by unconventional oil and gas resources that couldn't have been produced a decade ago, either economically or technically. This couldn't have come at a better time for the pipeline industry, when its bread-and-butter business of transporting refined products to distribution terminals is reaching a plateau, as developed-country markets exhibit Peak Demand and biofuels output grows. That's a big change from when I worked in the "mid-stream", which includes pipelines, distribution terminals and trading. Then, the challenge was keeping conventional crude pipelines full as domestic onshore oil fields depleted, while expanding capacity to transport gasoline, diesel and jet fuel to meet steadily rising demand. Today the advent of shale gas, shale oil and oil sands crude coincides with the development of a much more diverse energy market.
Recent changes in the economy also make pipelines, which used to be considered dull, more interesting as an investment. With interest rates historically low and equity markets weak and volatile, the modest but stable returns that midstream oil and gas assets offer must seem a lot more attractive than they did prior to the financial crisis, particularly when managed in tax-efficient structures such as the master limited partnerships that Mr. Kinder helped pioneer. And those same low interest rates make the capital required for new private-sector infrastructure projects more affordable. Such projects also look doubly beneficial in the current environment of high unemployment, providing both large numbers of jobs in the short term, during construction, and ensuring the reliable energy supplies needed for sustainable job growth once the economy hits its stride again.
Of course pipelines aren't always dull, particularly when they are the focus of controversies such as the current one concerning the proposed Keystone XL Pipeline. But what many of that project's critics, including celebrities who appear to know less about such facilities than most of my readers, have missed is that despite rare, unfortunate accidents, pipelines remain the best and most efficient means of transporting large volumes of fuel over long distances. Unless you honestly think we can do without these fuels entirely--a scenario that I am convinced will not be realistic for at least another few decades--then it makes little sense to shun pipelines and thus proportionally increase the quantity of fuel that will be carried by truck, rail and ocean-going tankers, all of which are also subject to accidents. Like all infrastructure pipelines require proper maintenance, but they are not inherently risky.
No bet on the scale of the one Kinder Morgan is making can ever be a sure thing, and I can think of several things that might go wrong, topped by a double-dip global recession that lasted for years and sapped both energy demand and gas drilling economics. However, this deal taps into a number of converging trends supporting a US natural gas boom that is part and parcel of the potential global Golden Age of Gas that the International Energy Agency recently described. I wouldn't be surprised to see more transactions along these lines.
As an article in today's Wall St. Journal states in its title, the Kinder Morgan-El Paso deal heralds the arrival of the Age of Shale. It simultaneously validates the potential of US shale gas resources and points to a new set of growth opportunities created by unconventional oil and gas resources that couldn't have been produced a decade ago, either economically or technically. This couldn't have come at a better time for the pipeline industry, when its bread-and-butter business of transporting refined products to distribution terminals is reaching a plateau, as developed-country markets exhibit Peak Demand and biofuels output grows. That's a big change from when I worked in the "mid-stream", which includes pipelines, distribution terminals and trading. Then, the challenge was keeping conventional crude pipelines full as domestic onshore oil fields depleted, while expanding capacity to transport gasoline, diesel and jet fuel to meet steadily rising demand. Today the advent of shale gas, shale oil and oil sands crude coincides with the development of a much more diverse energy market.
Recent changes in the economy also make pipelines, which used to be considered dull, more interesting as an investment. With interest rates historically low and equity markets weak and volatile, the modest but stable returns that midstream oil and gas assets offer must seem a lot more attractive than they did prior to the financial crisis, particularly when managed in tax-efficient structures such as the master limited partnerships that Mr. Kinder helped pioneer. And those same low interest rates make the capital required for new private-sector infrastructure projects more affordable. Such projects also look doubly beneficial in the current environment of high unemployment, providing both large numbers of jobs in the short term, during construction, and ensuring the reliable energy supplies needed for sustainable job growth once the economy hits its stride again.
Of course pipelines aren't always dull, particularly when they are the focus of controversies such as the current one concerning the proposed Keystone XL Pipeline. But what many of that project's critics, including celebrities who appear to know less about such facilities than most of my readers, have missed is that despite rare, unfortunate accidents, pipelines remain the best and most efficient means of transporting large volumes of fuel over long distances. Unless you honestly think we can do without these fuels entirely--a scenario that I am convinced will not be realistic for at least another few decades--then it makes little sense to shun pipelines and thus proportionally increase the quantity of fuel that will be carried by truck, rail and ocean-going tankers, all of which are also subject to accidents. Like all infrastructure pipelines require proper maintenance, but they are not inherently risky.
No bet on the scale of the one Kinder Morgan is making can ever be a sure thing, and I can think of several things that might go wrong, topped by a double-dip global recession that lasted for years and sapped both energy demand and gas drilling economics. However, this deal taps into a number of converging trends supporting a US natural gas boom that is part and parcel of the potential global Golden Age of Gas that the International Energy Agency recently described. I wouldn't be surprised to see more transactions along these lines.
Friday, October 14, 2011
More Lessons from Solyndra
I'll bet that those working and investing in renewable energy are even more tired of the steady stream of headlines from the unraveling Solyndra mess than the rest of us are. Today's crop includes more evidence of the political linkages to the overall process for determining the company's suitability for federal backing and the revelation that an investor in Solyndra was advising the US Navy to sign a contract with them, even as the firm was on the verge of collapse. None of this has done either the industry or the administration any good, and there is much to be learned from this episode. That includes lessons concerning direct government support for the full-scale deployment of renewable energy and other technologies.
Start with the ethics issues. No one should be surprised that investors in Solyndra were lobbying the DOE and White House in support of the company's application for a federal loan guarantee. That was hardly unique to Solyndra or renewable energy. And I'm perfectly willing to accept, unless proven otherwise, that both the DOE advisor whose wife works for a law firm representing Solyndra, and the venture capitalist who apparently advised the Navy to buy Solyndra's technology in his capacity with the Pentagon's Defense Venture Catalyst Initiative, thought they had done everything necessary to resolve any potential conflicts of interest in this matter. Yet in both cases it seems clear that even if nothing improper was done, the appearance of impropriety is very hard to dispel after what seemed like a routine transaction turns into a front-page scandal.
Whenever I see this sort of thing I can't help recalling the early training I received as a petroleum products trader for Texaco, which took anti-trust compliance very seriously. The lawyer who advised our Supply & Distribution department on such matters always reminded us to think about how our dealings with other companies might look if we had to explain them from the witness stand in a court of law. He invariably advised going beyond mere compliance; his mantra was, "Avoid the appearance of evil." That's a lesson that it seems many of the officials involved in the Solyndra debacle either forgot or never received, even if they believed they were in full compliance with existing ethics policies.
When you step back from such details it becomes apparent that these are precisely the sorts of conflicts that result, when the government involves itself so deeply in transactions of a magnitude that would normally be handled in the commercial sector--which even when it makes mistakes does so with shareholder dollars, rather than tax dollars. And make no mistake, if Solyndra had gone broke after receiving $500,000 from Uncle Sam, rather than $535 million, none of these other issues would matter or have seen the light of day.
It's perfectly appropriate--even necessary--for the government to make modest-sized bets on new technology in key areas, particularly when they require greater patience than most corporations are capable of. And it's to be expected that many or even most such bets will turn out to be dead ends, as Solyndra did. The problem is that while a few million dollars will buy a lot of renewable energy R&D, they will buy only a negligible amount of deployment. While the government can afford to make numerous small bets that don't turn out well but advance our knowledge in the process, it can only afford to make a small number of bets on the scale of the Solyndra loan. That ought to be especially true when the deficit and debt loom as large as they do, unless you're a firm believer in the "broken windows" theory of stimulus, or Lord Keynes's suggestion that the government could productively bury bottles of money and let people dig them up.
The easy question is whether the Department of Energy should have backed Solyndra. I have concluded the answer is no, and not just based on after-the-fact information. The much harder question is whether the US government should be in the business of providing this level of support for large-scale manufacturing or deployment, rather than just R&D. And even if it should, can it develop the necessary expertise and processes, not only to make such decisions at least as well as its commercial counterparts would, but also to insulate the decision-makers from the political influence that such high stakes are bound to attract. Answering that depends on a lot more than just one's political or economic philosophy.
Start with the ethics issues. No one should be surprised that investors in Solyndra were lobbying the DOE and White House in support of the company's application for a federal loan guarantee. That was hardly unique to Solyndra or renewable energy. And I'm perfectly willing to accept, unless proven otherwise, that both the DOE advisor whose wife works for a law firm representing Solyndra, and the venture capitalist who apparently advised the Navy to buy Solyndra's technology in his capacity with the Pentagon's Defense Venture Catalyst Initiative, thought they had done everything necessary to resolve any potential conflicts of interest in this matter. Yet in both cases it seems clear that even if nothing improper was done, the appearance of impropriety is very hard to dispel after what seemed like a routine transaction turns into a front-page scandal.
Whenever I see this sort of thing I can't help recalling the early training I received as a petroleum products trader for Texaco, which took anti-trust compliance very seriously. The lawyer who advised our Supply & Distribution department on such matters always reminded us to think about how our dealings with other companies might look if we had to explain them from the witness stand in a court of law. He invariably advised going beyond mere compliance; his mantra was, "Avoid the appearance of evil." That's a lesson that it seems many of the officials involved in the Solyndra debacle either forgot or never received, even if they believed they were in full compliance with existing ethics policies.
When you step back from such details it becomes apparent that these are precisely the sorts of conflicts that result, when the government involves itself so deeply in transactions of a magnitude that would normally be handled in the commercial sector--which even when it makes mistakes does so with shareholder dollars, rather than tax dollars. And make no mistake, if Solyndra had gone broke after receiving $500,000 from Uncle Sam, rather than $535 million, none of these other issues would matter or have seen the light of day.
It's perfectly appropriate--even necessary--for the government to make modest-sized bets on new technology in key areas, particularly when they require greater patience than most corporations are capable of. And it's to be expected that many or even most such bets will turn out to be dead ends, as Solyndra did. The problem is that while a few million dollars will buy a lot of renewable energy R&D, they will buy only a negligible amount of deployment. While the government can afford to make numerous small bets that don't turn out well but advance our knowledge in the process, it can only afford to make a small number of bets on the scale of the Solyndra loan. That ought to be especially true when the deficit and debt loom as large as they do, unless you're a firm believer in the "broken windows" theory of stimulus, or Lord Keynes's suggestion that the government could productively bury bottles of money and let people dig them up.
The easy question is whether the Department of Energy should have backed Solyndra. I have concluded the answer is no, and not just based on after-the-fact information. The much harder question is whether the US government should be in the business of providing this level of support for large-scale manufacturing or deployment, rather than just R&D. And even if it should, can it develop the necessary expertise and processes, not only to make such decisions at least as well as its commercial counterparts would, but also to insulate the decision-makers from the political influence that such high stakes are bound to attract. Answering that depends on a lot more than just one's political or economic philosophy.
Wednesday, October 12, 2011
Is Mount Everest the Best Place for Solar Power?
A new study on the impact of regional temperature differences on solar generating potential arrives at some surprising conclusions about the world's best locations for solar power. While the US desert southwest still ranks high, as you'd expect, it turns out that some of the best sites may be in places most of us would never suspect, including the Himalayas and Antarctica. That's because the crystalline silicon-based photovoltaic (PV) cells that dominate the market today are sensitive to ambient temperature and perform best at low temperatures, such as those found in the polar regions and high altitudes. These results could have interesting implications for future energy supply and greenhouse gas emissions in India and China, and for regional cooperation in what has historically been a tense neighborhood.
The paper by researchers from Japan's National Institute for Advanced Industrial Science and Technology was published in Environmental Science & Technology. Their approach involved superimposing mapped global average temperatures onto the map of average solar radiation, or "insolation", that has been the standard guide for assessing solar power potential. This produces some interesting shifts in the world's best solar locations, particularly by reducing the PV potential of the tropics and increasing that of colder regions. (Note that this comparison isn't applicable to solar thermal installations.) High-altitude locations look especially attractive for PV for two reasons: Not only are they colder, with average temperatures falling by 4-10ºC for each kilometer of altitude (12-28ºF/mile), but they also receive more sunlight, due to the thinner atmosphere at these heights.
The resulting differences in output are significant. The same PV module that generates 600-800 kWh/year per Watt of nameplate capacity in the UK or Germany and 1,400-1,600 kWh/W in Arizona would top 2,000 kWh/W in the Himalayas and parts of the Andes, as well as near the South Pole. The authors recognize that the latter might not be very useful without low-cost, high-volume energy storage, perhaps in the form of hydrogen, due to extended periods of darkness in the antipodal winter. I would note that the enormous distances to the nearest market might also be overcome by borrowing some ideas from the plans for space solar power (SSP). Either way, it doesn't take high storage or logistical costs to render large-scale Antarctican PV impractical, and the installation, maintenance and transmission challenges in the Andes and Himalayas aren't trivial, either. Whether the paper's conclusions turn out to be more than just scientifically interesting will depend on the detailed economics of the projects necessary to implement them.
The economics of PV entail a lot more than just the solar generating potential in a given location. Proximity to markets, or at least access to transmission, is a big factor, as is price, including both the market price for power and any relevant government or utility incentives or carbon pricing. However, it's also true that it takes either very high local prices or very high subsidies, such as Germany's solar Feed-in Tariffs, to make PV competitive in regions with low temperature-adjusted solar output. Such subsidies are a rich-country game on any scale large enough to matter, and even European countries are finding it hard to sustain these added costs as their economies teeter on the brink of another financial crisis and recession. The advantages to developing countries like China and India of pursuing high-altitude solar--even if it requires long transmission lines--could be compelling in the long run.
The paper by researchers from Japan's National Institute for Advanced Industrial Science and Technology was published in Environmental Science & Technology. Their approach involved superimposing mapped global average temperatures onto the map of average solar radiation, or "insolation", that has been the standard guide for assessing solar power potential. This produces some interesting shifts in the world's best solar locations, particularly by reducing the PV potential of the tropics and increasing that of colder regions. (Note that this comparison isn't applicable to solar thermal installations.) High-altitude locations look especially attractive for PV for two reasons: Not only are they colder, with average temperatures falling by 4-10ºC for each kilometer of altitude (12-28ºF/mile), but they also receive more sunlight, due to the thinner atmosphere at these heights.
The resulting differences in output are significant. The same PV module that generates 600-800 kWh/year per Watt of nameplate capacity in the UK or Germany and 1,400-1,600 kWh/W in Arizona would top 2,000 kWh/W in the Himalayas and parts of the Andes, as well as near the South Pole. The authors recognize that the latter might not be very useful without low-cost, high-volume energy storage, perhaps in the form of hydrogen, due to extended periods of darkness in the antipodal winter. I would note that the enormous distances to the nearest market might also be overcome by borrowing some ideas from the plans for space solar power (SSP). Either way, it doesn't take high storage or logistical costs to render large-scale Antarctican PV impractical, and the installation, maintenance and transmission challenges in the Andes and Himalayas aren't trivial, either. Whether the paper's conclusions turn out to be more than just scientifically interesting will depend on the detailed economics of the projects necessary to implement them.
The economics of PV entail a lot more than just the solar generating potential in a given location. Proximity to markets, or at least access to transmission, is a big factor, as is price, including both the market price for power and any relevant government or utility incentives or carbon pricing. However, it's also true that it takes either very high local prices or very high subsidies, such as Germany's solar Feed-in Tariffs, to make PV competitive in regions with low temperature-adjusted solar output. Such subsidies are a rich-country game on any scale large enough to matter, and even European countries are finding it hard to sustain these added costs as their economies teeter on the brink of another financial crisis and recession. The advantages to developing countries like China and India of pursuing high-altitude solar--even if it requires long transmission lines--could be compelling in the long run.
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