One of many press releases I received this week highlighted the new Clean Energy Export Principles developed by a "multi-industry coalition, which was coordinated by the National Foreign Trade Council, and U.S. government representatives." They recommend a significantly expanded and technology-neutral effort by the US government to promote exports of clean energy gear, including equipment for the smart grid, energy efficiency and energy storage. They also suggest the need to reduce trade barriers affecting such exports globally, not just to help US industry but to increase the effectiveness of efforts to mitigate climate change. I can only hope that the administration embraces these recommendations as enthusiastically as it has other aspects of its green agenda, because these principles are aimed squarely at the biggest opportunities for clean energy technology and emissions reduction, outside our borders.
It doesn't really matter whether these principles reflect the sensible recognition of trends in the global energy marketplace, or merely make a virtue of necessity at a time when government support for domestic clean energy deployment is approaching its statutory and practical limits. However the current debt ceiling crisis is resolved, the capacity for the federal government to continue providing generous incentives for cleantech deployment, either through the Treasury renewable energy cash grants that have totaled nearly $8 billion to date, or the Department of Energy Loan Guarantee program that has backed or directly funded more than $40 billion in loans for clean energy projects is likely to be far more constrained in the future.
Nor is this simply a question of money. The whole notion that we are in some kind of renewable energy deployment race with China or any other country ignores the big differences in our respective levels of economic development. If there were such a race we would be bound to lose, and not because we don't have the right policies or strict enough regulations, but because US electricity demand is growing slowly and is backed by both ample generating capacity and ample supplies of relatively cheap and low-emitting fuel. Meanwhile both electricity demand and capacity in the developing world are growing rapidly, and the indigenous generation fuel in good supply is mainly coal. That, together with the disparities in economic growth coming out of the global recession, is the underlying reason why investment in renewable energy in the developing world apparently surged past that in the developed world last year.
With cleantech supply chains already substantially globalized, the leaders in this industry must be global in scope and focus. US manufacturers of cleantech equipment shouldn't ignore the US market, but they must be realistic about it. Even with growing opportunities in the smart grid and solar power, the US will account for only a small fraction of the global market for such goods and services, as growth shifts away from the mature markets of Europe and North America. The market share that counts, for competitive strength and economies of scale, is global market share. And global sales will provide the volumes needed to drive down costs for both exports and domestic installations. There's a huge, growing market for cleantech, and it is mainly out there.
Friday, July 29, 2011
Wednesday, July 27, 2011
The Anthropocene and Other Topics
For the first four years of this blog I published nearly every weekday, and as time went on occasionally struggled to find suitable topics. Lately, I've been running across more good blog topics than I could conceivably cover. I think more is at work in that than my having scaled back the blog's frequency; energy has become an integral part of so many crucial conversations in the meantime. So instead of my customary single topic, today's post includes three essentially unrelated ones, all of which I thought merited sharing with my readers.
The first item concerns compact fluorescent lighting, those "CFL" bulbs people seem to either love or hate, and upon which many base unrealistic expectations of energy and emissions reductions. According to the tracking of NEMA, the Association of Electrical and Medical Imaging Manufacturers, US demand for CFL bulbs has declined for four straight quarters, while demand for the incandescent bulbs that are being phased out by law has revived to 79% of the market. This shift begs for deeper analysis. Is it the result of consumers stocking up on 100 Watt incandescents before they disappear from store shelves next January 1 and become a new kind of black market commodity, or is it more along the lines of what happened to tire sales after steel belted radials were introduced? Like the latter, CFLs last a lot longer than the traditional product they're replacing, and at some point one would expect sales to plateau at a much lower level than incandescents previously held. Or is it the case, as in my household, that CFLs are simply not viewed as a satisfactory replacement in all the fixtures where they could be placed, because of a combination of lighting quality, cost effectiveness, and concern about potential mercury contamination?
Now let's turn to plastics. Two stories, both involving Dow Chemical, caught my eye. In the first, Dow is investing in a facility to make polyethylene, a very common plastic, from ethanol in Brazil. As the article in Technology Review notes, Brazil is one of the few places that would make sense. The process of producing ethanol from sugar cane is so energy-efficient and cost-competitive that ethanol can sensibly be substituted for the petroleum products from which it might otherwise be produced there. In the other story, Dow recently announced a process for extracting most of the available energy from non-recycled plastic waste. Taken together, these two items challenge our traditional view of the relationship between oil and plastics: not only does oil no longer have a lock on the feedstock market, but it could face competition from waste plastics in end-use energy applications, or possibly even as a potential source of synthetic oil, as I noted a couple of years ago.
Finally, I'd be remiss if I didn't recommend an article from the May 28, 2011 issue of The Economist, which had been in my reading pile for weeks. It suggests that we are living in a new epoch of the earth called the Anthropocene, signifying humanity's having become the equivalent of a force of nature in our effect on the earth and its systems. I'm intrigued by this not just because it dovetails with my view that essentially everything we do on a civilization-wide scale, including energy production and consumption, agriculture, transportation and public works, has consequences for the entire planet, but also because of its implications for what sustainability is likely to mean going forward. If the cited scientists are correct, we influence the earth's systems as much as the climate does, with climate change only one example of our impact.
The corollary to that is that an earth restored to the conditions that prevailed in the Holocene epoch from which we emerged--before we started messing with the nitrogen cycle, the carbon cycle, and other key processes--could not support the population expected by mid-century. There's just no going back to our bucolic roots, but neither is that a justification for the large-scale destruction of the environment needed to sustain humanity. The other interesting twist to this is that it's possible we will need the energy from the large-scale harnessing of solar power to conduct the intentional geoengineering that might be necessary to get the global climate back on an even keel. It's the sort of thing that gives environmentalists nightmares but makes believers in an approaching Technological Singularity nod sagely.
The first item concerns compact fluorescent lighting, those "CFL" bulbs people seem to either love or hate, and upon which many base unrealistic expectations of energy and emissions reductions. According to the tracking of NEMA, the Association of Electrical and Medical Imaging Manufacturers, US demand for CFL bulbs has declined for four straight quarters, while demand for the incandescent bulbs that are being phased out by law has revived to 79% of the market. This shift begs for deeper analysis. Is it the result of consumers stocking up on 100 Watt incandescents before they disappear from store shelves next January 1 and become a new kind of black market commodity, or is it more along the lines of what happened to tire sales after steel belted radials were introduced? Like the latter, CFLs last a lot longer than the traditional product they're replacing, and at some point one would expect sales to plateau at a much lower level than incandescents previously held. Or is it the case, as in my household, that CFLs are simply not viewed as a satisfactory replacement in all the fixtures where they could be placed, because of a combination of lighting quality, cost effectiveness, and concern about potential mercury contamination?
Now let's turn to plastics. Two stories, both involving Dow Chemical, caught my eye. In the first, Dow is investing in a facility to make polyethylene, a very common plastic, from ethanol in Brazil. As the article in Technology Review notes, Brazil is one of the few places that would make sense. The process of producing ethanol from sugar cane is so energy-efficient and cost-competitive that ethanol can sensibly be substituted for the petroleum products from which it might otherwise be produced there. In the other story, Dow recently announced a process for extracting most of the available energy from non-recycled plastic waste. Taken together, these two items challenge our traditional view of the relationship between oil and plastics: not only does oil no longer have a lock on the feedstock market, but it could face competition from waste plastics in end-use energy applications, or possibly even as a potential source of synthetic oil, as I noted a couple of years ago.
Finally, I'd be remiss if I didn't recommend an article from the May 28, 2011 issue of The Economist, which had been in my reading pile for weeks. It suggests that we are living in a new epoch of the earth called the Anthropocene, signifying humanity's having become the equivalent of a force of nature in our effect on the earth and its systems. I'm intrigued by this not just because it dovetails with my view that essentially everything we do on a civilization-wide scale, including energy production and consumption, agriculture, transportation and public works, has consequences for the entire planet, but also because of its implications for what sustainability is likely to mean going forward. If the cited scientists are correct, we influence the earth's systems as much as the climate does, with climate change only one example of our impact.
The corollary to that is that an earth restored to the conditions that prevailed in the Holocene epoch from which we emerged--before we started messing with the nitrogen cycle, the carbon cycle, and other key processes--could not support the population expected by mid-century. There's just no going back to our bucolic roots, but neither is that a justification for the large-scale destruction of the environment needed to sustain humanity. The other interesting twist to this is that it's possible we will need the energy from the large-scale harnessing of solar power to conduct the intentional geoengineering that might be necessary to get the global climate back on an even keel. It's the sort of thing that gives environmentalists nightmares but makes believers in an approaching Technological Singularity nod sagely.
Friday, July 22, 2011
Energy Crisis Prices Persist
Watching oil prices is a hard habit to break, once formed. They're always moving up and down, sometimes for obvious reasons and sometimes not. It has probably escaped most observers' notice that the magnitude of this year's price moves has exceeded the total nominal price of oil that prevailed not many years ago, yet without the sort of apocalyptic events that one might expect such volatility would require. Perhaps that's because we seem to be stuck in the middle of an ongoing, slow-boil oil crisis from which the financial crisis and the demand contraction that accompanied the global recession only provided a brief respite. In fact, when you glance at the oil price trend in real dollars over the last 40 years, it's apparent that prices are back at the level associated with the peak of the oil crisis of the late 1970s and early 1980s:
One reason I've been paying extra attention to oil prices lately is that I've been observing the impact of the coordinated release from the US Strategic Petroleum Reserve (SPR) and strategic reserves of other members of the International Energy Agency. So far, my initial assessment that it would have little lasting effect seems to have been validated, though I'll reserve judgment until the oil is actually delivered during August, when we might see the market respond to the increase in commercial oil inventories that should result. Robert Rapier had an excellent posting yesterday on the folly of this decision. My view is, if anything, less flattering. Not only was this choice unwise, but it also appears to have been ineffective, which in the current economic climate is an even more damning assessment.
The modest response to this move tells us something about the fundamentals of the market. In the past, an SPR release on this scale would have crushed prices--not just for a few days, but for months at least. Consider the release that accompanied the start of the first Gulf War in 1991. Only about half of the nearly 34 million bbls authorized was eventually sold, but the price of oil dropped by 33% overnight and took 13 years to recover to the peak it had reached during the lead-up to Desert Storm. By comparison, the announced release of 30 million bbls from the US SPR--the sale of which was fully-subscribed--and another 30 million bbls from other IEA members managed to depress the price of oil by only around 5% for a week or so. As of this morning Brent crude, the global marker, is $4/bbl higher than it was on June 22nd. And as of this Monday's survey, the average pump price of unleaded regular in the US was also higher than before the President announced the release.
The market's tepid reaction to the SPR release suggests that oil prices have been driven up by more than just speculators. Speculation may be playing a role, but it's more like the head on a glass of beer. Beneath that froth lies the robust demand growth in the developing world, which has pushed global oil consumption to a record level of 89 million bbl/day this year. On the supply side, some point to incipient Peak Oil, but characterizing the crisis we're in doesn't require a grand theory. In addition to the curtailment of production from places like Libya and Yemen, and OPEC's desire to keep a lid on output to preserve their revenues, there's a fundamental mismatch between the companies that have the capital and the desire to invest in new production, and the willingness of some governments to grant access to the resources, whether in the Middle East or the US. All of this is compounded by the inherent time lags in resource development, which can range from 5-10 years, depending on the technology and permits required.
As different as the causes and symptoms of this crisis are from those of the 1970s, the broad outline of solutions remains quite similar: Reduce demand, increase supplies, and diversify our sources of energy. We have more and better options than in 1979, but still no miracle cures.
One reason I've been paying extra attention to oil prices lately is that I've been observing the impact of the coordinated release from the US Strategic Petroleum Reserve (SPR) and strategic reserves of other members of the International Energy Agency. So far, my initial assessment that it would have little lasting effect seems to have been validated, though I'll reserve judgment until the oil is actually delivered during August, when we might see the market respond to the increase in commercial oil inventories that should result. Robert Rapier had an excellent posting yesterday on the folly of this decision. My view is, if anything, less flattering. Not only was this choice unwise, but it also appears to have been ineffective, which in the current economic climate is an even more damning assessment.
The modest response to this move tells us something about the fundamentals of the market. In the past, an SPR release on this scale would have crushed prices--not just for a few days, but for months at least. Consider the release that accompanied the start of the first Gulf War in 1991. Only about half of the nearly 34 million bbls authorized was eventually sold, but the price of oil dropped by 33% overnight and took 13 years to recover to the peak it had reached during the lead-up to Desert Storm. By comparison, the announced release of 30 million bbls from the US SPR--the sale of which was fully-subscribed--and another 30 million bbls from other IEA members managed to depress the price of oil by only around 5% for a week or so. As of this morning Brent crude, the global marker, is $4/bbl higher than it was on June 22nd. And as of this Monday's survey, the average pump price of unleaded regular in the US was also higher than before the President announced the release.
The market's tepid reaction to the SPR release suggests that oil prices have been driven up by more than just speculators. Speculation may be playing a role, but it's more like the head on a glass of beer. Beneath that froth lies the robust demand growth in the developing world, which has pushed global oil consumption to a record level of 89 million bbl/day this year. On the supply side, some point to incipient Peak Oil, but characterizing the crisis we're in doesn't require a grand theory. In addition to the curtailment of production from places like Libya and Yemen, and OPEC's desire to keep a lid on output to preserve their revenues, there's a fundamental mismatch between the companies that have the capital and the desire to invest in new production, and the willingness of some governments to grant access to the resources, whether in the Middle East or the US. All of this is compounded by the inherent time lags in resource development, which can range from 5-10 years, depending on the technology and permits required.
As different as the causes and symptoms of this crisis are from those of the 1970s, the broad outline of solutions remains quite similar: Reduce demand, increase supplies, and diversify our sources of energy. We have more and better options than in 1979, but still no miracle cures.
Monday, July 18, 2011
Energy Implications of a Federal Default
Much of the attention concerning a possible failure to increase the US debt ceiling by month-end has focused on the government's ability to borrow, and on how individuals might be affected, whether as recipients of social security, pay or pensions from various branches of the federal government, or as consumers seeking car loans or mortgages. I haven't seen a lot of discussion about the potential impact on energy, other than some speculation about higher oil prices. As I started to consider how different categories of energy might be affected, it occurred to me that a list, or a set of lists was the best way to tackle this. It's not intended to be comprehensive, and I would welcome your input on what I've overlooked.
The first category of energy impacts concerns companies or individuals who are awaiting a check or wire transfer from the government, for which funds might not be available in the absence of a prompt deal to extend the debt ceiling. These include:
The first category of energy impacts concerns companies or individuals who are awaiting a check or wire transfer from the government, for which funds might not be available in the absence of a prompt deal to extend the debt ceiling. These include:
- Projects that have qualified for Treasury renewable energy cash grants, but have not yet received the funds, or that hope to qualify shortly. Since this program started in 2009, the Treasury has disbursed $7.8 billion to project owners and developers.
- Companies that sell energy to the federal government and its various branches. This includes start-ups selling renewable aviation and diesel fuels to the Department of Defense, as well as firms selling the government the large quantities of electricity and conventional fuels it uses. (I will be attending a joint Army/Air Force energy forum tomorrow.
- Companies with contracts related to various energy efficiency programs initiated under the stimulus or previous legislation, including weatherization.
- Individuals who receive federal energy assistance.
- Beneficiaries of the Department of Energy's loan guarantee program that have not yet secured loans are a good example of this category. Note than many of the projects listed on the Loan Program Office's site have only obtained conditional approvals, indicating that their financing has not yet closed. They would be vulnerable either to a protracted default or one that undermined confidence in the government's "full faith and credit" to such an extent that a federal loan guarantee wouldn't aid in lining up lenders.
- Refiners and others blending ethanol into gasoline and collecting the Volumetric Ethanol Excise Tax Credit.
- Producers of biodiesel and cellulosic biofuels and small ethanol producers, all of which receive tax credits for producing renewable fuels.
- Oil and gas companies benefiting from the various tax credits and deductions that have been in the administration's cross-hairs since it took office.
- US manufacturers, including oil and gas companies, power generators, ethanol producers, and a wide array of non-energy recipients of the Sec. 199 deduction for manufacturing their products in the US.
- Purchasers of electric vehicles eligible for the tax credit of up to $7,500 per car for EVs and qualifying plug-in hybrids, or up to $4,000 for natural gas vehicles and other alternative fuels.
- Car manufacturers and dealers depending on these tax credits to help sell their vehicles.
Thursday, July 14, 2011
Carmageddon, Hybrid Cars and Diamond Lanes
The looming "Carmageddon" in Los Angeles made the front page of today's Wall St. Journal, as residents there brace for the two-plus day closure of ten miles of the famed San Diego Freeway (I-405) this weekend. The disruption is apparently required to allow for some demolition necessary for the construction of new high-occupancy vehicle (HOV) lanes on the 405. As locals assess their alternate routes--there are many--they might also want to spend some time thinking about who will be allowed to drive in those new HOV lanes. California recently decided to deny ordinary (non-plug-in) hybrid cars that privilege, in preference to plug-ins and other alternatively fueled vehicles. The new policy and the one it replaces both reflect muddled thinking, but I would argue that abandoning hybrids at this juncture is a mistake, at least if saving gas is still a priority in the Golden State.
I routinely commuted on that stretch of the 405 between the Santa Monica Freeway (I-10) and the Ventura Freeway (US-101) when I lived on the West Side and worked in Mid-Wilshire and later in the San Fernando Valley. I carpooled for part of that time but for most of it, like most other Angelenos, I drove alone. I would have found the option of going solo in the HOV lanes a very appealing way to avoid the frequent stop-and-go traffic, and that's why offering that right to hybrid cars has been a useful non-cash incentive to boost their sales. State officials apparently concluded that normal hybrids are now commonplace, so the incentive should be shifted to the even more efficient cars now becoming available. They have emissions data on their side, because California's electricity mix is dominated by hydropower, nuclear and efficient gas turbines, plus a growing contribution of non-hydro renewables, though it also includes some imported coal-fired power from the Four Corners region. A plug-in should indeed emit less CO2 (directly and indirectly) than a Prius-type hybrid under those conditions.
What I think the state's regulators have missed, however, is that simpler hybrids, which currently enjoy no other incentives, still look like an equally effective way to save gasoline. That's particularly true if most buyers of plug-in cars are choosing them in preference to non-plug-in hybrids, rather than instead of gas-guzzling conventional cars. It comes down to the simple, but often counter-intuitive math of fuel economy the way we calculate it in the US, yielding diminishing gallon savings for increasing miles per gallon (see chart below.) Consider a 50 mpg hybrid that replaces a 25 mpg conventional car. Driven 12,000 miles per year, this choice saves 240 gallons per year. Trading in that hybrid for a plug-in like a Nissan Leaf only saves an additional 240 gallons per year, while a Chevy Volt would save somewhat less than that, unless it were never filled up.
Moreover, plug-ins didn't lack for incentives already. In addition to the federal tax credit of up to $7,500 per car, California offers its own rebate of up to $5,000 for qualifying plug-ins, which also receive discounted rates for electricity. Then there's the money the state is investing in recharging infrastructure. Whether or not the aggregate level of incentives is justified on grounds of economics, environmental and energy security benefits, throwing the HOV benefit on top of them seems like an unnecessary gilding of the lily. The 85,000 hybrids that were given the sticker allowing HOV access for solo drivers still represent a tiny fraction of the state's 39 million registered motor vehicles, and offering 40,000 new stickers for EVs won't make a noticeable dent in California's emissions, or its 40 million gallon-per-day gasoline consumption.
I don't know whether this weekend's Carmageddon will live up to its name, or like L.A.'s 1984 Summer Olympics result in lighter-than-normal traffic because motorists had enough notice to allow them to plan ahead. Yet it does seem that continuing to offer HOV access for non-plug-in hybrids would provide a meaningful incentive for a class of gas-saving vehicles that still represents only around 3% of US car sales, at no cash cost to the state. And if the state is truly concerned that a growing hybrid population could choke the HOV lanes and make them less useful for everyone, an even better option would be to auction the stickers, with only buyers of hybrids, plug-ins and other alternative fuel cars eligible to bid. The proceeds might be sufficient to relieve the state's battered budget of a large portion of the cost of the cash subsidies they're already paying on plug-in cars.
I routinely commuted on that stretch of the 405 between the Santa Monica Freeway (I-10) and the Ventura Freeway (US-101) when I lived on the West Side and worked in Mid-Wilshire and later in the San Fernando Valley. I carpooled for part of that time but for most of it, like most other Angelenos, I drove alone. I would have found the option of going solo in the HOV lanes a very appealing way to avoid the frequent stop-and-go traffic, and that's why offering that right to hybrid cars has been a useful non-cash incentive to boost their sales. State officials apparently concluded that normal hybrids are now commonplace, so the incentive should be shifted to the even more efficient cars now becoming available. They have emissions data on their side, because California's electricity mix is dominated by hydropower, nuclear and efficient gas turbines, plus a growing contribution of non-hydro renewables, though it also includes some imported coal-fired power from the Four Corners region. A plug-in should indeed emit less CO2 (directly and indirectly) than a Prius-type hybrid under those conditions.
What I think the state's regulators have missed, however, is that simpler hybrids, which currently enjoy no other incentives, still look like an equally effective way to save gasoline. That's particularly true if most buyers of plug-in cars are choosing them in preference to non-plug-in hybrids, rather than instead of gas-guzzling conventional cars. It comes down to the simple, but often counter-intuitive math of fuel economy the way we calculate it in the US, yielding diminishing gallon savings for increasing miles per gallon (see chart below.) Consider a 50 mpg hybrid that replaces a 25 mpg conventional car. Driven 12,000 miles per year, this choice saves 240 gallons per year. Trading in that hybrid for a plug-in like a Nissan Leaf only saves an additional 240 gallons per year, while a Chevy Volt would save somewhat less than that, unless it were never filled up.
Moreover, plug-ins didn't lack for incentives already. In addition to the federal tax credit of up to $7,500 per car, California offers its own rebate of up to $5,000 for qualifying plug-ins, which also receive discounted rates for electricity. Then there's the money the state is investing in recharging infrastructure. Whether or not the aggregate level of incentives is justified on grounds of economics, environmental and energy security benefits, throwing the HOV benefit on top of them seems like an unnecessary gilding of the lily. The 85,000 hybrids that were given the sticker allowing HOV access for solo drivers still represent a tiny fraction of the state's 39 million registered motor vehicles, and offering 40,000 new stickers for EVs won't make a noticeable dent in California's emissions, or its 40 million gallon-per-day gasoline consumption.
I don't know whether this weekend's Carmageddon will live up to its name, or like L.A.'s 1984 Summer Olympics result in lighter-than-normal traffic because motorists had enough notice to allow them to plan ahead. Yet it does seem that continuing to offer HOV access for non-plug-in hybrids would provide a meaningful incentive for a class of gas-saving vehicles that still represents only around 3% of US car sales, at no cash cost to the state. And if the state is truly concerned that a growing hybrid population could choke the HOV lanes and make them less useful for everyone, an even better option would be to auction the stickers, with only buyers of hybrids, plug-ins and other alternative fuel cars eligible to bid. The proceeds might be sufficient to relieve the state's battered budget of a large portion of the cost of the cash subsidies they're already paying on plug-in cars.
Tuesday, July 12, 2011
Ethanol's Future Without Subsidies
Given the remarkable longevity of the tax credit for ethanol blended into gasoline, it seems fitting that it would take a problem on the scale of the massive US deficit and $14 trillion federal debt to trigger its demise. Yet despite a widely-publicized Senate vote in June and the announcement of a key compromise among three Senators last week--two from the corn belt and one from the West Coast--it remains unclear just when and how the cancellation of this subsidy will become law. And because the fate of the subsidy is linked to that of the parallel tariff and duty on imported ethanol, the US ethanol industry faces not just the prospect of a more challenging market by year-end, but one that could include competition from foreign suppliers with special advantages under US renewable fuels regulations. Some producers may end up wishing they hadn't expanded output quite so fast.
I've followed the ethanol subsidy for much longer than I've been blogging about it. As I was reading a two-part assessment of the changing ethanol situation in Biofuels Digest it occurred to me to take the dusty report from my long-ago M.B.A. project off the shelf. Its topic was the market for "gasohol", gasoline blended with up to 10% ethanol, on the West Coast in the early 1980s. At the time, blenders received roughly the same tax credit as today's $0.45 per gallon of ethanol blended, thanks to the 1978 Federal Energy Tax Act and the Highway Tax Act of 1983. That benefit was a lot more generous in then-current dollars than now, but much smaller in aggregate. In the intervening decades, gasoline with ethanol has expanded from around 2% of the market to nearly 100%. In much of the country it is now harder to find gasoline without ethanol than it was to find gasohol back then.
That's only one indication of the tremendous success this industry has enjoyed, due almost entirely to government policies like the Volumetric Ethanol Excise Tax Credit and the national Renewable Fuels Standard (RFS) established in 2005. In fact the eventual demise of the ethanol tax credit was virtually guaranteed by the passage of an even more ambitious RFS as part of the federal Energy Independence and Security Act of 2007. Under the RFS, blending ethanol into gasoline in steadily increasing proportions became mandatory, rendering the tax credit paid to refiners and other gasoline blenders redundant. Just as importantly, it expanded the scale of ethanol blending to such an extent that the total annual cost of the so-called blenders credit grew from roughly $1.8 billion in 2005 to a projected $6 billion this year--too big to ignore.
The deal agreed by Senators Feinstein (D-CA), Klobuchar (D-MN) and Thune (R-SD) last week would reportedly result in the early termination of both the ethanol tax credit, which was due to expire at the end of 2011 but could have been renewed, and the corresponding ethanol import tariff. It would devote $1.33 billion of the unspent funds to deficit reduction, while diverting another $668 million to extend tax credits for alternative fuel refueling (or recharging) infrastructure and cellulosic biofuel tax credits. This outcome appears to have pleased at least part of the ethanol industry. However, in order for it to become law, it must still be voted on by both houses of Congress, either by itself or as a provision within another bill, perhaps even the debt ceiling extension package that could emerge from the ongoing deliberations between the House, Senate and White House.
The ultimate effect of these changes on the ethanol industry remains somewhat uncertain, though it is hard to see them as a net positive, other than the longer-term benefit of supporting infrastructure investments that could be crucial in resolving a key bottleneck in ethanol distribution. Without much higher sales of gasoline blends containing more than 10% ethanol, the market is already nearly saturated with ethanol, and that's before factoring in the additional imports that the elimination of the tariff is likely to promote. And at least in the case of ethanol derived from sugar cane, those imports will enjoy an important advantage over ethanol derived from corn: most of them are likely to qualify for the stricter designation of "Advanced Biofuel" under the RFS, a category for which the annual quota is just starting to take off, and that cannot be satisfied by corn ethanol but also seems unlikely to be filled by domestic cellulosic ethanol any time soon.
Biofuels Digest suggested that long-dated ethanol futures have already nose-dived in anticipation of the end of the tax credit. It's true that ethanol for delivery in January 2012 is trading for around $0.35/gal. less than the August 2011 ethanol futures contract, reflecting a widening of ethanol's discount to the gasoline futures contract over that interval of around $0.11/gal. However, it also seems highly relevant that corn futures have recently retreated from their early-June peak of nearly $8/bushel to $6.80, with December corn--from which January ethanol might be produced--down at $6.20/bu. That leaves ethanol producers a small but still positive margin on that January futures price. So it is hardly certain that the end of the tax credit will, by itself, stress US corn ethanol producers. If anything, refiners and consumers--who have arguably received most of the benefit of the credit in recent years--stand to lose the most from its disappearance.
Import competition could have much more serious consequences, as the fuel ethanol industry truly begins to globalize. Brazil is the big player internationally, even if the recent rise in sugar prices and a smaller-than-expected cane crop have created the bizarre situation of Brazil actually importing corn ethanol from the US. The historically fragmented Brazilian sugar cane industry is currently both expanding and consolidating, led by companies like Raizen, the new joint venture between Shell and Cosan, which has indicated plans to double its ethanol capacity to 5 billion liters per year (1.3 billion gallons per year.) Nor is Brazil the only tropical country that can grow cane and produce sugar, ethanol and electricity from modern facilities. The Brazilian model could be replicated elsewhere in Latin America, the Caribbean, and West Africa. Not all of that extra ethanol will come here, but enough of it could, helped by the RFS, to put an effective cap on US ethanol prices. I'm not aware of a similar constraint on corn prices.
The US ethanol industry has matured in the last three decades. Today's ethanol plants are much more efficient than the ones supplying the small quantities used for gasohol in the early 1980s, and they now consume around 40% of the US corn crop. The industry has expanded on a scale that would have seemed nearly impossible thirty years ago, though in my view it has in the process fallen into the classic overcapacity trap of commodity manufacturers. Whether that situation is temporary or permanent depends on the success of blends containing more than 10% ethanol--blends that the market has so far treated with indifference. But either way, when the training wheels finally come off with the end of the blenders credit and import tariff, we shouldn't be surprised to see more of the small and higher-cost producers fall by the wayside. That will have local consequences, but the ethanol industry will survive, just as it survived the bankruptcies of some ethanol producers during the financial crisis. Ethanol is here to stay, and it is about to embark on a new career as a more normal commodity.
I've followed the ethanol subsidy for much longer than I've been blogging about it. As I was reading a two-part assessment of the changing ethanol situation in Biofuels Digest it occurred to me to take the dusty report from my long-ago M.B.A. project off the shelf. Its topic was the market for "gasohol", gasoline blended with up to 10% ethanol, on the West Coast in the early 1980s. At the time, blenders received roughly the same tax credit as today's $0.45 per gallon of ethanol blended, thanks to the 1978 Federal Energy Tax Act and the Highway Tax Act of 1983. That benefit was a lot more generous in then-current dollars than now, but much smaller in aggregate. In the intervening decades, gasoline with ethanol has expanded from around 2% of the market to nearly 100%. In much of the country it is now harder to find gasoline without ethanol than it was to find gasohol back then.
That's only one indication of the tremendous success this industry has enjoyed, due almost entirely to government policies like the Volumetric Ethanol Excise Tax Credit and the national Renewable Fuels Standard (RFS) established in 2005. In fact the eventual demise of the ethanol tax credit was virtually guaranteed by the passage of an even more ambitious RFS as part of the federal Energy Independence and Security Act of 2007. Under the RFS, blending ethanol into gasoline in steadily increasing proportions became mandatory, rendering the tax credit paid to refiners and other gasoline blenders redundant. Just as importantly, it expanded the scale of ethanol blending to such an extent that the total annual cost of the so-called blenders credit grew from roughly $1.8 billion in 2005 to a projected $6 billion this year--too big to ignore.
The deal agreed by Senators Feinstein (D-CA), Klobuchar (D-MN) and Thune (R-SD) last week would reportedly result in the early termination of both the ethanol tax credit, which was due to expire at the end of 2011 but could have been renewed, and the corresponding ethanol import tariff. It would devote $1.33 billion of the unspent funds to deficit reduction, while diverting another $668 million to extend tax credits for alternative fuel refueling (or recharging) infrastructure and cellulosic biofuel tax credits. This outcome appears to have pleased at least part of the ethanol industry. However, in order for it to become law, it must still be voted on by both houses of Congress, either by itself or as a provision within another bill, perhaps even the debt ceiling extension package that could emerge from the ongoing deliberations between the House, Senate and White House.
The ultimate effect of these changes on the ethanol industry remains somewhat uncertain, though it is hard to see them as a net positive, other than the longer-term benefit of supporting infrastructure investments that could be crucial in resolving a key bottleneck in ethanol distribution. Without much higher sales of gasoline blends containing more than 10% ethanol, the market is already nearly saturated with ethanol, and that's before factoring in the additional imports that the elimination of the tariff is likely to promote. And at least in the case of ethanol derived from sugar cane, those imports will enjoy an important advantage over ethanol derived from corn: most of them are likely to qualify for the stricter designation of "Advanced Biofuel" under the RFS, a category for which the annual quota is just starting to take off, and that cannot be satisfied by corn ethanol but also seems unlikely to be filled by domestic cellulosic ethanol any time soon.
Biofuels Digest suggested that long-dated ethanol futures have already nose-dived in anticipation of the end of the tax credit. It's true that ethanol for delivery in January 2012 is trading for around $0.35/gal. less than the August 2011 ethanol futures contract, reflecting a widening of ethanol's discount to the gasoline futures contract over that interval of around $0.11/gal. However, it also seems highly relevant that corn futures have recently retreated from their early-June peak of nearly $8/bushel to $6.80, with December corn--from which January ethanol might be produced--down at $6.20/bu. That leaves ethanol producers a small but still positive margin on that January futures price. So it is hardly certain that the end of the tax credit will, by itself, stress US corn ethanol producers. If anything, refiners and consumers--who have arguably received most of the benefit of the credit in recent years--stand to lose the most from its disappearance.
Import competition could have much more serious consequences, as the fuel ethanol industry truly begins to globalize. Brazil is the big player internationally, even if the recent rise in sugar prices and a smaller-than-expected cane crop have created the bizarre situation of Brazil actually importing corn ethanol from the US. The historically fragmented Brazilian sugar cane industry is currently both expanding and consolidating, led by companies like Raizen, the new joint venture between Shell and Cosan, which has indicated plans to double its ethanol capacity to 5 billion liters per year (1.3 billion gallons per year.) Nor is Brazil the only tropical country that can grow cane and produce sugar, ethanol and electricity from modern facilities. The Brazilian model could be replicated elsewhere in Latin America, the Caribbean, and West Africa. Not all of that extra ethanol will come here, but enough of it could, helped by the RFS, to put an effective cap on US ethanol prices. I'm not aware of a similar constraint on corn prices.
The US ethanol industry has matured in the last three decades. Today's ethanol plants are much more efficient than the ones supplying the small quantities used for gasohol in the early 1980s, and they now consume around 40% of the US corn crop. The industry has expanded on a scale that would have seemed nearly impossible thirty years ago, though in my view it has in the process fallen into the classic overcapacity trap of commodity manufacturers. Whether that situation is temporary or permanent depends on the success of blends containing more than 10% ethanol--blends that the market has so far treated with indifference. But either way, when the training wheels finally come off with the end of the blenders credit and import tariff, we shouldn't be surprised to see more of the small and higher-cost producers fall by the wayside. That will have local consequences, but the ethanol industry will survive, just as it survived the bankruptcies of some ethanol producers during the financial crisis. Ethanol is here to stay, and it is about to embark on a new career as a more normal commodity.
Friday, July 08, 2011
A New Era in Space
In the lead-up to the launch of the last space shuttle, "Atlantis", I've been seeing a number of articles on the general theme of an era ending. This week's Economist went so far as to suggest it marks the "End of the Space Age." I sincerely hope they are wrong, and not just because I have followed the US space program avidly since before the first moon landing, but also because of my primary focus on energy. Most of the resources of the solar system, including most of its energy resources, lie outside the earth's atmosphere. To choose a relevant example, space solar power (SSP) might not contribute significantly for decades, but it still looks like an important option for ensuring that energy limits don't constrain our long-term prosperity after the ages of oil and coal wind down.
One presentation that I still recall vividly from the many meetings involved in the economic review of NASA's "Fresh Look" approach to SSP in the 1990s, and from my time on NASA's oversight committee for SSP, dealt with the crucial role of a low-cost, high-frequency launch system in putting the components of solar power satellites into orbit affordably. Even then, it was clear that the current shuttle was not that system. It was equally clear that the traditional alternative of disposable rockets couldn't come close to the $ per pound-on-orbit threshold required. He was proposing a second- or third-generation system using unmanned reusable cargo vehicles that would land like airplanes. This was before the recent advances in drone aircraft.
I wonder what that scientist would recommend today. Perhaps he would build on some of the private spacecraft designs currently under development, such as those of SpaceX, Orbital Sciences and XCOR. However, assembling a solar power system over dozens or hundreds of launches involves very different requirements than taking tourists into space or sending astronauts back to the moon or on to Mars. In any case, without reliable access to space--traveling as passengers on Russian vehicles using a 50-year-old design doesn't count--the benefits of space will be limited to capabilities like the communications and remote sensing of today's satellites. Those are impressive enough and have transformed our world and our view of it, but they can't supply us with the concentrated energy to power cities or industries.
During the space shuttle program's 30-year history, shuttle crews accomplished extraordinary feats at tremendous risk, and sadly some of them paid with their lives. It's interesting to contemplate, as a noted space commentator did this week in Technology Review, whether the right shuttle design was chosen in the early 1970s, though mainly from the perspective of what it might tell us about what our next steps in space should be. I'm as intrigued as anyone by the prospect of resuming manned exploration beyond earth orbit, but it's hard to square the cost of that with the deep cuts that must be made elsewhere to set our financial house in order. A serious examination of the techniques and hardware necessary to deliver space resources for use on earth--now that it wouldn't have to fit an existing shuttle's capabilities--could provide a suitably pragmatic focus for NASA in the current environment.
I have a hunch that a goal of obtaining non-polluting energy from space would go a lot farther towards galvanizing the necessary public support for NASA than the next planetary mission--which incidentally might be easier to construct with the capabilities that a more nuts-and-bolts effort might create. Either way, while it's nice to look back at past achievements, I'd much rather be looking ahead to the accomplishments of the next era in space.
One presentation that I still recall vividly from the many meetings involved in the economic review of NASA's "Fresh Look" approach to SSP in the 1990s, and from my time on NASA's oversight committee for SSP, dealt with the crucial role of a low-cost, high-frequency launch system in putting the components of solar power satellites into orbit affordably. Even then, it was clear that the current shuttle was not that system. It was equally clear that the traditional alternative of disposable rockets couldn't come close to the $ per pound-on-orbit threshold required. He was proposing a second- or third-generation system using unmanned reusable cargo vehicles that would land like airplanes. This was before the recent advances in drone aircraft.
I wonder what that scientist would recommend today. Perhaps he would build on some of the private spacecraft designs currently under development, such as those of SpaceX, Orbital Sciences and XCOR. However, assembling a solar power system over dozens or hundreds of launches involves very different requirements than taking tourists into space or sending astronauts back to the moon or on to Mars. In any case, without reliable access to space--traveling as passengers on Russian vehicles using a 50-year-old design doesn't count--the benefits of space will be limited to capabilities like the communications and remote sensing of today's satellites. Those are impressive enough and have transformed our world and our view of it, but they can't supply us with the concentrated energy to power cities or industries.
During the space shuttle program's 30-year history, shuttle crews accomplished extraordinary feats at tremendous risk, and sadly some of them paid with their lives. It's interesting to contemplate, as a noted space commentator did this week in Technology Review, whether the right shuttle design was chosen in the early 1970s, though mainly from the perspective of what it might tell us about what our next steps in space should be. I'm as intrigued as anyone by the prospect of resuming manned exploration beyond earth orbit, but it's hard to square the cost of that with the deep cuts that must be made elsewhere to set our financial house in order. A serious examination of the techniques and hardware necessary to deliver space resources for use on earth--now that it wouldn't have to fit an existing shuttle's capabilities--could provide a suitably pragmatic focus for NASA in the current environment.
I have a hunch that a goal of obtaining non-polluting energy from space would go a lot farther towards galvanizing the necessary public support for NASA than the next planetary mission--which incidentally might be easier to construct with the capabilities that a more nuts-and-bolts effort might create. Either way, while it's nice to look back at past achievements, I'd much rather be looking ahead to the accomplishments of the next era in space.
Friday, July 01, 2011
A Shale Gas Bubble?
Last weekend the New York Times published a front-page article raising serious questions about the true scale and economics of the production of natural gas from shale, invoking the specter of another asset bubble. To say that this created a buzz would be an understatement. Yet while the article addressed important concerns, it mischaracterized the overall situation by conflating the fortunes and prospects of individual companies with the long-term viability of exploiting the underlying resource. Even if some prominent shale-focused companies were to fail, that wouldn't alter the quantity of shale gas in the ground. It also wouldn't change the fact that shale gas accounted for more than 15% of domestic US natural gas production in 2009 and is expected to supply at least 25% by 2035, even in the most pessimistic shale gas scenario included in the Department of Energy's 2011 Annual Energy Outlook. Comparisons to Enron or the Dot-Com bubble make little sense when the shale gas bonanza has shifted the fundamentals of physical supply and demand, irrespective of its effect on the equity values of companies in this sector.
I understand why the Times' assessment might resonate just now. In the aftermath of a series of asset bubbles and the economic contractions they helped trigger, skepticism about claims such as the game-changing potential of shale gas comes naturally, particularly when it appears that some industry and government insiders don't share the consensus enthusiasm for shale gas. There's nothing wrong with asking some tough questions, particularly given the scale of the opportunity and what it could mean for long-term electricity prices and the displacement of higher-emitting fuels. I have made a career of asking tough questions, myself. However, I also hope that these government officials asked questions at least that tough before issuing billions of dollars in cash grants, loans and loan guarantees to renewable energy developers and electric vehicle start-ups with shorter track records than most shale drillers, and facing greater uncertainties.
That's not as much of a non sequitur as it might seem, because of the prominent placement of the article and its context within the series of probing articles the Times has done on shale gas and its main enabling technology, hydraulic fracturing or "fracking." I wouldn't be surprised to learn that that the paper's editors, like many in environmental circles, find the development of this resource to be an unwelcome diversion on the path to a lower-carbon future. After all, while natural gas emits much less greenhouse gas than coal over its lifecycle, particularly for electricity generation, it certainly emits much more than wind, solar and geothermal power. Many renewable energy projects have struggled to compete with the low cost of gas-fired power generation that shale gas helped bring about. Ultimately, the price of natural gas lies at the heart of both the concerns raised in Sunday's story and the worries of many environmentalists that cheap gas could delay the shift to renewables by many years--although I would remind them that gas-fired power also looks very helpful for enabling the grid to accommodate more renewables.
If I thought that natural gas prices were likely to remain at their current level of roughly $4 per million BTUs indefinitely, I might share some of those concerns. I'd also be even more vocal than I have been in highlighting the opportunity for gas to displace imported oil at an energy equivalent of under $25 per barrel. However, there are good reasons to believe that today's prices aren't just the result of abundant shale gas, but also of a weak US economy. It's no coincidence that they fell precipitously as the recession was starting to bite in the second half of 2008, in tandem with oil prices. Stronger growth is likely to bring more demand from existing users, along with new demand of the type I highlighted in Monday's posting. If the futures market reflects the current consensus on prices in the future, then that consensus expects a fairly steady increase in gas prices in the next few years, reaching $6/MMBTU by late 2015.
By itself that would resolve many of the concerns of environmentalists about competition between gas and renewables, as long as renewables like wind and solar continue on their recent cost-reduction trajectories. It would also negate many of the notions in Sunday's article, because at $6 the project economics of most of the shale plays the Times considered would be cash-positive or at least cash-neutral. That means a driller could finance development without having to bootstrap into it by selling reserves, a practice that appears to have inspired the Times' references to shale gas as a form of Ponzi scheme.
Meanwhile, at an average of $6 per MMBTU the price of natural gas would still be lower--and possibly less volatile--than in the boom years of the last decade, while remaining cheap enough to eventually displace a lot of imported oil. The resulting $35 per oil-equivalent barrel would have looked expensive as recently as 2003, but it would be a bargain in today's world.
In its larger context Sunday's article, by making a case that the future output of shale gas could be much lower than has been assumed, lays the groundwork for opponents of shale development to claim that it is both too risky and not material enough to be worth the risks they attribute to it. After studying this issue carefully, I am convinced that neither aspect of that proposition is correct. Shale can be developed safely, particularly when following guidelines such as the Operating Principles for shale and tight gas that Shell just put out. And shale certainly looks big enough to make a significant difference in the energy balances of entire countries, including both the US and China. Not every company producing shale gas will be financially successful, but that's been true in the oil patch since Col. Drake drilled his first well in 1859. In the unlikely event that shale gas turned out to be a bubble, it wouldn't be the first one in the history of oil and gas exploration. However, if it were a bubble, like previous ones it would leave behind a large number of wells that will be producing vitally important energy for many years to come, whatever the fate of the companies that originally drilled them.
I understand why the Times' assessment might resonate just now. In the aftermath of a series of asset bubbles and the economic contractions they helped trigger, skepticism about claims such as the game-changing potential of shale gas comes naturally, particularly when it appears that some industry and government insiders don't share the consensus enthusiasm for shale gas. There's nothing wrong with asking some tough questions, particularly given the scale of the opportunity and what it could mean for long-term electricity prices and the displacement of higher-emitting fuels. I have made a career of asking tough questions, myself. However, I also hope that these government officials asked questions at least that tough before issuing billions of dollars in cash grants, loans and loan guarantees to renewable energy developers and electric vehicle start-ups with shorter track records than most shale drillers, and facing greater uncertainties.
That's not as much of a non sequitur as it might seem, because of the prominent placement of the article and its context within the series of probing articles the Times has done on shale gas and its main enabling technology, hydraulic fracturing or "fracking." I wouldn't be surprised to learn that that the paper's editors, like many in environmental circles, find the development of this resource to be an unwelcome diversion on the path to a lower-carbon future. After all, while natural gas emits much less greenhouse gas than coal over its lifecycle, particularly for electricity generation, it certainly emits much more than wind, solar and geothermal power. Many renewable energy projects have struggled to compete with the low cost of gas-fired power generation that shale gas helped bring about. Ultimately, the price of natural gas lies at the heart of both the concerns raised in Sunday's story and the worries of many environmentalists that cheap gas could delay the shift to renewables by many years--although I would remind them that gas-fired power also looks very helpful for enabling the grid to accommodate more renewables.
If I thought that natural gas prices were likely to remain at their current level of roughly $4 per million BTUs indefinitely, I might share some of those concerns. I'd also be even more vocal than I have been in highlighting the opportunity for gas to displace imported oil at an energy equivalent of under $25 per barrel. However, there are good reasons to believe that today's prices aren't just the result of abundant shale gas, but also of a weak US economy. It's no coincidence that they fell precipitously as the recession was starting to bite in the second half of 2008, in tandem with oil prices. Stronger growth is likely to bring more demand from existing users, along with new demand of the type I highlighted in Monday's posting. If the futures market reflects the current consensus on prices in the future, then that consensus expects a fairly steady increase in gas prices in the next few years, reaching $6/MMBTU by late 2015.
By itself that would resolve many of the concerns of environmentalists about competition between gas and renewables, as long as renewables like wind and solar continue on their recent cost-reduction trajectories. It would also negate many of the notions in Sunday's article, because at $6 the project economics of most of the shale plays the Times considered would be cash-positive or at least cash-neutral. That means a driller could finance development without having to bootstrap into it by selling reserves, a practice that appears to have inspired the Times' references to shale gas as a form of Ponzi scheme.
Meanwhile, at an average of $6 per MMBTU the price of natural gas would still be lower--and possibly less volatile--than in the boom years of the last decade, while remaining cheap enough to eventually displace a lot of imported oil. The resulting $35 per oil-equivalent barrel would have looked expensive as recently as 2003, but it would be a bargain in today's world.
In its larger context Sunday's article, by making a case that the future output of shale gas could be much lower than has been assumed, lays the groundwork for opponents of shale development to claim that it is both too risky and not material enough to be worth the risks they attribute to it. After studying this issue carefully, I am convinced that neither aspect of that proposition is correct. Shale can be developed safely, particularly when following guidelines such as the Operating Principles for shale and tight gas that Shell just put out. And shale certainly looks big enough to make a significant difference in the energy balances of entire countries, including both the US and China. Not every company producing shale gas will be financially successful, but that's been true in the oil patch since Col. Drake drilled his first well in 1859. In the unlikely event that shale gas turned out to be a bubble, it wouldn't be the first one in the history of oil and gas exploration. However, if it were a bubble, like previous ones it would leave behind a large number of wells that will be producing vitally important energy for many years to come, whatever the fate of the companies that originally drilled them.
Monday, June 27, 2011
What New Ethylene Crackers Tell Us
Sometimes a news item informs us about much more than the event in question. Recent announcements of new petrochemical projects in the US fall into that category. Both Shell and Dow Chemical are planning new ethylene crackers in the US, a market in which established ethylene facilities were being shut down only a few years ago, as part of the demand destruction necessary to balance natural gas demand with shrinking US supplies. Anyone looking for further indications of the game-changing nature of shale gas need look no further than these projects. Yet they also give us intriguing hints about two other situations of great interest: global oil prices and US economic growth.
The Shell project is of particular interest, because of its location. The company is apparently planning to locate it in Appalachia, where it will depend on the byproducts of natural gas produced from the giant Marcellus shale deposit. Considering that most of the other ethylene crackers in the US are located on or near the Gulf Coast, where gas can be supplied from numerous onshore and offshore fields, that's a remarkable endorsement of the potential of the Marcellus. You just wouldn't leave such a facility dependent on one gas field if that field weren't both very large and likely to be producing for a very long time. Anyone suggesting that shale gas is a flash in the pan should look long and hard at this project, as I'm sure Shell has done.
It's also worth pausing to recall the way Shell approaches projects like this. Shell is one of the pioneers of scenario planning, and its business plans are all based on its periodic, carefully developed views of different potential futures. I wouldn't assign some notion of infallibility to this; Shell has made its share of mistakes in the last decade, too. However, it does suggest that the company's decision to invest in this project wasn't just based on a straight-line extrapolation of current conditions. Deciding to build an ethylene cracker, a facility that turns the heavier components of natural gas into one of the basic building blocks of the petrochemical and plastics industry, in such a location is a big vote of confidence. It suggests that Shell has concluded that the current uncertainties facing shale gas development are very likely be resolved without undermining shale's capacity to produce large quantities of gas at relatively low cost, and that shale developers will find ways to resolve concerns about fracking, methane emissions, and other issues both with the affected communities and with state and national regulators.
These projects also suggest at least two other things. First, as the Reuters article noted, they represent sizable wagers on the relationship between the global price of oil and the US price of natural gas. I've commented before on the extraordinary divergence between the two, with oil bouncing around the $100 per barrel mark and US natural gas selling for the energy equivalent of $25 per barrel. A company would be unlikely to make a long-term investment like this if it thought gas and oil were likely to move back into parity any time soon. Even if gas prices eventually recover to around $6 per million BTU, as suggested by current long-dated gas futures, that's still the equivalent of less than $40/bbl--an oil price we haven't seen since the worst stretch of the global recession and financial crisis in early 2009.
And that leads to the last implication I draw from this news: these investments are bets on the health of the US economy. If the economy were headed for a protracted period of slow or no growth, adding petrochemical capacity here would be too risky, rather than putting it in the Middle East, where gas is even cheaper and the growing markets in Asia are much closer. That doesn't' mean that our problems of high unemployment, high indebtedness, and gaping federal, state and local budget deficits aren't extremely challenging, but it provides at least one modestly positive sign among the many ominous ones that are routinely amplified by the basic nature of the news media business.
The Shell project is of particular interest, because of its location. The company is apparently planning to locate it in Appalachia, where it will depend on the byproducts of natural gas produced from the giant Marcellus shale deposit. Considering that most of the other ethylene crackers in the US are located on or near the Gulf Coast, where gas can be supplied from numerous onshore and offshore fields, that's a remarkable endorsement of the potential of the Marcellus. You just wouldn't leave such a facility dependent on one gas field if that field weren't both very large and likely to be producing for a very long time. Anyone suggesting that shale gas is a flash in the pan should look long and hard at this project, as I'm sure Shell has done.
It's also worth pausing to recall the way Shell approaches projects like this. Shell is one of the pioneers of scenario planning, and its business plans are all based on its periodic, carefully developed views of different potential futures. I wouldn't assign some notion of infallibility to this; Shell has made its share of mistakes in the last decade, too. However, it does suggest that the company's decision to invest in this project wasn't just based on a straight-line extrapolation of current conditions. Deciding to build an ethylene cracker, a facility that turns the heavier components of natural gas into one of the basic building blocks of the petrochemical and plastics industry, in such a location is a big vote of confidence. It suggests that Shell has concluded that the current uncertainties facing shale gas development are very likely be resolved without undermining shale's capacity to produce large quantities of gas at relatively low cost, and that shale developers will find ways to resolve concerns about fracking, methane emissions, and other issues both with the affected communities and with state and national regulators.
These projects also suggest at least two other things. First, as the Reuters article noted, they represent sizable wagers on the relationship between the global price of oil and the US price of natural gas. I've commented before on the extraordinary divergence between the two, with oil bouncing around the $100 per barrel mark and US natural gas selling for the energy equivalent of $25 per barrel. A company would be unlikely to make a long-term investment like this if it thought gas and oil were likely to move back into parity any time soon. Even if gas prices eventually recover to around $6 per million BTU, as suggested by current long-dated gas futures, that's still the equivalent of less than $40/bbl--an oil price we haven't seen since the worst stretch of the global recession and financial crisis in early 2009.
And that leads to the last implication I draw from this news: these investments are bets on the health of the US economy. If the economy were headed for a protracted period of slow or no growth, adding petrochemical capacity here would be too risky, rather than putting it in the Middle East, where gas is even cheaper and the growing markets in Asia are much closer. That doesn't' mean that our problems of high unemployment, high indebtedness, and gaping federal, state and local budget deficits aren't extremely challenging, but it provides at least one modestly positive sign among the many ominous ones that are routinely amplified by the basic nature of the news media business.
Thursday, June 23, 2011
SPR Release Catches Market Napping
I see that the administration has decided to release 30 million barrels of oil from the US Strategic Petroleum Reserve, in coordination with a matched release from the strategic stocks of other OECD member countries of the International Energy Agency (IEA.) The release will be spaced over the next month, though it's not clear how soon it can begin, since it should take at least a few days to line up the requisite buyers, sign contracts, and schedule pipeline space. Politicians who have been calling for such a release to punish speculation in oil futures and alleviate pressure on consumers are crowing, and the oil markets have responded by dropping $5-6 dollars per barrel. As welcome as this will be for consumers, it is simultaneously a drop in the bucket and an unwelcome precedent for the future stewardship of these emergency reserves.
As I noted when I assessed the outcome of the recent OPEC meeting, oil inventories aren't unusually low, and the current shortfall in global production compared to demand will take a while to develop into a problem. I suspect the main concern behind the IEA's decision to release stocks now, rather than waiting for a true physical shortfall to materialize, is the mismatch between the quality of the Libyan and Middle Eastern oil that has been taken off the market as a result of the ongoing turmoil of the "Arab Spring" and that of the OPEC spare capacity available to fill in for it, mainly in Saudi Arabia. In this context, the US SPR release looks more like an expression of solidarity with its EU partners, for whom the Libyan shortfall is much more significant, than a direct assault on the market.
Nevertheless, the concerns I expressed in my posting of June 2nd regarding a smaller "operational" release from the SPR apply to this release, as well. The SPR doesn't exist to game the market, especially not for political purposes. It's there in case of a serious interruption in supply, the scenarios for which are numerous and unfortunately not very hard to imagine for either us or the potential perpetrators.
Perhaps an extra 2 million barrels per day will alter the psychology of the futures markets and catalyze a larger price drop than we've seen today. By itself, that seems unlikely. Because it's a temporary measure, the market will want to know what comes next, and that's the real problem. Unless the designers of this program have made a lucky choice and timed their release to coincide with a further easing of prices due to weakening demand, the calls for another release will start in a month, if prices remain at a level deemed high enough to threaten the economic recovery. Selling off 4% of the SPR in the absence of a real emergency--and with no clear plan for replacing it--might not be a big problem, but additional releases that added up to a substantial portion of the reserve would be. Let's hope we don't have cause to regret this.
As I noted when I assessed the outcome of the recent OPEC meeting, oil inventories aren't unusually low, and the current shortfall in global production compared to demand will take a while to develop into a problem. I suspect the main concern behind the IEA's decision to release stocks now, rather than waiting for a true physical shortfall to materialize, is the mismatch between the quality of the Libyan and Middle Eastern oil that has been taken off the market as a result of the ongoing turmoil of the "Arab Spring" and that of the OPEC spare capacity available to fill in for it, mainly in Saudi Arabia. In this context, the US SPR release looks more like an expression of solidarity with its EU partners, for whom the Libyan shortfall is much more significant, than a direct assault on the market.
Nevertheless, the concerns I expressed in my posting of June 2nd regarding a smaller "operational" release from the SPR apply to this release, as well. The SPR doesn't exist to game the market, especially not for political purposes. It's there in case of a serious interruption in supply, the scenarios for which are numerous and unfortunately not very hard to imagine for either us or the potential perpetrators.
Perhaps an extra 2 million barrels per day will alter the psychology of the futures markets and catalyze a larger price drop than we've seen today. By itself, that seems unlikely. Because it's a temporary measure, the market will want to know what comes next, and that's the real problem. Unless the designers of this program have made a lucky choice and timed their release to coincide with a further easing of prices due to weakening demand, the calls for another release will start in a month, if prices remain at a level deemed high enough to threaten the economic recovery. Selling off 4% of the SPR in the absence of a real emergency--and with no clear plan for replacing it--might not be a big problem, but additional releases that added up to a substantial portion of the reserve would be. Let's hope we don't have cause to regret this.
Tuesday, June 21, 2011
How Do Renewables and Oil Sands Affect Energy Security?
Despite its frequent use in policy and other discussions, "energy security" lacks a single, fixed meaning, and the consensus on its definition seems to be in flux. As an outgrowth of the oil crises of the 1970s, it has usually been associated with the economic, defense and geopolitical implications of imported oil and petroleum products, focused mainly on security of supply. It was often seen as a more nuanced term than energy independence. Over time, it has taken on other connotations, including the financial impact of imported energy. However, an even more recent trend to incorporate climate change and other sustainability concerns into energy security bears careful consideration, because it can sometimes lead to a direct conflict with energy security's most basic aspects. When I see advocates of a renewable electricity technology like solar power touting its energy security benefits, I can't help wondering how carefully they've thought through that claim, especially in light of the significant energy changes arising from the shale gas revolution.
A blogger conference call hosted by the American Petroleum Institute last week got me thinking about this topic again. Based on API's analysis, increased access to US oil resources that are currently off limits for exploration and development, together with approval of the Keystone XL pipeline to bring in more Canadian crude--including synthetic crude from new oil-sands projects--could dramatically reduce US oil imports. Imports from countries other than Canada could fall from 38% of our supply in 2010 to just 8% by 2030. Their assessment builds on a US Department of Energy forecast that already incorporates improvements in vehicle fuel economy and the expected contribution of oil shale resources such as the Bakken Shale in North Dakota and Montana. In API's resulting scenario, US oil production would increase by 4.8 million barrels per day (bpd) and domestic biofuels output would grow by 1.9 million bpd, along with an extra million bpd of imports from Canada. That combination would shrink our net non-Canadian imports of crude and petroleum products from 7.2 million bpd last year to just 1.8 million bpd in under 20 years.
However one views the potential environmental consequences of the steps necessary to achieve such an outcome, that would be a stellar result under the most commonly used definition of energy security. That's because these actions would directly replace imported oil and products, barrel for barrel, with supplies from more stable and dependable countries--including our own--as an extension of one of the main energy security strategies we've employed since the 1970s. Assessing the energy security benefits of some of our other options is less clear-cut, particularly when it comes to the generation of electricity from renewable sources.
Consider today's most familiar renewable energy projects, wind farms and rooftop solar installations. Both reduce greenhouse gas emissions, but do they also enhance energy security? The answer depends on where they are installed and how their output is used. If the venue is Europe, which imports large quantities of natural gas, or Japan, where the post-Fukushima electricity shortage is leading to significant increases in imports of fuel oil and liquefied natural gas (LNG), it's clear that they do. But the answer isn't as obvious in the US, where the generation they displace is mainly fueled by coal--a domestic resource--or natural gas. Prior to the explosion of domestic gas production from shale resources, it was much easier to argue that displacement of gas from a peaking gas turbine power plant backed out imported LNG somewhere and thus bolstered energy security. Today, with most gas coming from domestic wells and with most renewables relying on gas-fired backup power, that assertion is becoming a stretch.
Making the case for energy security benefits from wind and solar on the basis that they can back out oil imports by powering electric vehicles looks like even more of a stretch. This notion might be true in the 2030 time frame of the API scenario described above, by which time I'd expect to see many more EVs on the road, along with a smarter power grid capable of channeling the output of renewable power generation into EV recharging. In the nearer term, however, there simply won't be enough EVs on the road to substantiate such a claim. In fact, it would take more than 23 million EVs like the Nissan Leaf to consume the output of the wind and solar installations already in place last year. And in most locations, the EVs coming to market will be recharged mainly with average grid electricity, which includes a significant contribution from coal, even in California, thanks to that state's sizable electricity imports from neighboring states.
Resorting to such contingent and indirect claims of enhanced energy security sets up a debate that only liquid biofuels are currently positioned to win. However, it seems equally unrealistic to adhere to a definition of energy security that ignores the many ways in which our perspective on the world has changed in the last decade. I wasn't surprised to find a definition of energy security from within the US military incorporating sustainability along with sufficiency and surety. In effect, sustainability represents a new, albeit self-imposed, risk on the security of supply for conventional fuels that we're less accustomed to considering. It can also cut both ways, leaving some renewables, such as food-based biofuels, vulnerable under a definition of energy security that includes this metric.
Our notions of energy security are moving into a 21st century context, as they begin to recognize factors beyond supply and demand. That seems appropriate. At the same time, the term should still convey the pragmatism that gave rise to this concept in the first place. The traditional view of energy security never constituted a trumping argument in US energy policy, or else we wouldn't be sitting here with so many billions of barrels of technically recoverable resources off-limits to exploitation because of worries about the possible effect on beaches, tourism, wildlife and a myriad other concerns, broad and narrow. Similarly, a greater inclusion of sustainability aspects into our view of energy security should not be expected to disqualify efforts like the Keystone XL pipeline or expanded access to hydrocarbon resources. Even if such endeavors must also demonstrate their soundness on other criteria, they would unquestionably leave the US more secure in its energy sources. Instead of pitting one view of energy security against another, I'd prefer to see a scenario for 2030 that incorporates more access to North America's liquid fuel resources, together with expanded efforts on energy efficiency, transportation energy diversification, and creative capitalization on our new-found natural gas wealth--all of which would enhance US energy security.
A blogger conference call hosted by the American Petroleum Institute last week got me thinking about this topic again. Based on API's analysis, increased access to US oil resources that are currently off limits for exploration and development, together with approval of the Keystone XL pipeline to bring in more Canadian crude--including synthetic crude from new oil-sands projects--could dramatically reduce US oil imports. Imports from countries other than Canada could fall from 38% of our supply in 2010 to just 8% by 2030. Their assessment builds on a US Department of Energy forecast that already incorporates improvements in vehicle fuel economy and the expected contribution of oil shale resources such as the Bakken Shale in North Dakota and Montana. In API's resulting scenario, US oil production would increase by 4.8 million barrels per day (bpd) and domestic biofuels output would grow by 1.9 million bpd, along with an extra million bpd of imports from Canada. That combination would shrink our net non-Canadian imports of crude and petroleum products from 7.2 million bpd last year to just 1.8 million bpd in under 20 years.
However one views the potential environmental consequences of the steps necessary to achieve such an outcome, that would be a stellar result under the most commonly used definition of energy security. That's because these actions would directly replace imported oil and products, barrel for barrel, with supplies from more stable and dependable countries--including our own--as an extension of one of the main energy security strategies we've employed since the 1970s. Assessing the energy security benefits of some of our other options is less clear-cut, particularly when it comes to the generation of electricity from renewable sources.
Consider today's most familiar renewable energy projects, wind farms and rooftop solar installations. Both reduce greenhouse gas emissions, but do they also enhance energy security? The answer depends on where they are installed and how their output is used. If the venue is Europe, which imports large quantities of natural gas, or Japan, where the post-Fukushima electricity shortage is leading to significant increases in imports of fuel oil and liquefied natural gas (LNG), it's clear that they do. But the answer isn't as obvious in the US, where the generation they displace is mainly fueled by coal--a domestic resource--or natural gas. Prior to the explosion of domestic gas production from shale resources, it was much easier to argue that displacement of gas from a peaking gas turbine power plant backed out imported LNG somewhere and thus bolstered energy security. Today, with most gas coming from domestic wells and with most renewables relying on gas-fired backup power, that assertion is becoming a stretch.
Making the case for energy security benefits from wind and solar on the basis that they can back out oil imports by powering electric vehicles looks like even more of a stretch. This notion might be true in the 2030 time frame of the API scenario described above, by which time I'd expect to see many more EVs on the road, along with a smarter power grid capable of channeling the output of renewable power generation into EV recharging. In the nearer term, however, there simply won't be enough EVs on the road to substantiate such a claim. In fact, it would take more than 23 million EVs like the Nissan Leaf to consume the output of the wind and solar installations already in place last year. And in most locations, the EVs coming to market will be recharged mainly with average grid electricity, which includes a significant contribution from coal, even in California, thanks to that state's sizable electricity imports from neighboring states.
Resorting to such contingent and indirect claims of enhanced energy security sets up a debate that only liquid biofuels are currently positioned to win. However, it seems equally unrealistic to adhere to a definition of energy security that ignores the many ways in which our perspective on the world has changed in the last decade. I wasn't surprised to find a definition of energy security from within the US military incorporating sustainability along with sufficiency and surety. In effect, sustainability represents a new, albeit self-imposed, risk on the security of supply for conventional fuels that we're less accustomed to considering. It can also cut both ways, leaving some renewables, such as food-based biofuels, vulnerable under a definition of energy security that includes this metric.
Our notions of energy security are moving into a 21st century context, as they begin to recognize factors beyond supply and demand. That seems appropriate. At the same time, the term should still convey the pragmatism that gave rise to this concept in the first place. The traditional view of energy security never constituted a trumping argument in US energy policy, or else we wouldn't be sitting here with so many billions of barrels of technically recoverable resources off-limits to exploitation because of worries about the possible effect on beaches, tourism, wildlife and a myriad other concerns, broad and narrow. Similarly, a greater inclusion of sustainability aspects into our view of energy security should not be expected to disqualify efforts like the Keystone XL pipeline or expanded access to hydrocarbon resources. Even if such endeavors must also demonstrate their soundness on other criteria, they would unquestionably leave the US more secure in its energy sources. Instead of pitting one view of energy security against another, I'd prefer to see a scenario for 2030 that incorporates more access to North America's liquid fuel resources, together with expanded efforts on energy efficiency, transportation energy diversification, and creative capitalization on our new-found natural gas wealth--all of which would enhance US energy security.
Thursday, June 16, 2011
Gasoline Could Cost Consumers an Extra $150 Billion in 2011
A poll reported in this morning's Wall St. Journal (subscription) indicated that more Americans are significantly affected by high gas prices than by rising food prices, falling home values, unemployment or foreclosures. That's a surprising result, considering that transportation fuel only accounts for about 5% of average household expenses. However, gasoline has one of the most visible prices in our society, and the scale of our fuel use is such that price increases of the recent magnitude aggregate to a very large total. Based on year-to-date prices and compared to a more typical year like 2006, the drag on the US economy is running between $100 and $150 billion for 2011, reversing any "gasoline stimulus" we received in 2009.
As of the latest price report from the Department of Energy's Energy Information Agency, the national average price for unleaded regular gasoline has dropped back to $3.71 per gallon from its May peak of just under $4. Despite that, it's still more than a buck higher than this time last year. In fact, until a couple of weeks ago gas prices were trending well above their path in 2008, when prices reached an all-time high of $4.11/gal. that July. (See above chart.) When I compared this year's prices to those in 2006, which averaged only about 20 cents per gallon lower than last year's but exhibited more normal seasonality, and then multiplied by the more than 137 billion gallons of gasoline the US is likely to consume this year, the total drag on the economy worked out to between $100 and $150 billion on a full-year basis. (See chart below.) If these prices persisted, that would be enough to negate the effect of the entire 2% cut in Social Security taxes for 2011.
Fortunately, barring an escalation of the current supply disruptions in the Middle East, a major hurricane affecting Gulf Coast refinery operations, or an unexpected surge in economic growth, we've probably either already seen the peak gasoline price for the year or are within a few weeks of it. The outcome of last week's OPEC meeting, while not as bearish for prices as an agreement to increase quotas and output would have been, has had little lasting effect on oil prices, which are running at a level consistent with this week's US average pump price or a bit less. However, no one should confuse a seasonal easing in prices with a permanent return to cheaper gas. Short of another global economic crisis, global oil supply and demand remain closely enough matched that any hiccup will quickly translate into higher prices at the pump. I feel safe in predicting that we'll be flirting with $4 again before long, and the consequences of that should be factored into any forecasts of future economic growth.
As of the latest price report from the Department of Energy's Energy Information Agency, the national average price for unleaded regular gasoline has dropped back to $3.71 per gallon from its May peak of just under $4. Despite that, it's still more than a buck higher than this time last year. In fact, until a couple of weeks ago gas prices were trending well above their path in 2008, when prices reached an all-time high of $4.11/gal. that July. (See above chart.) When I compared this year's prices to those in 2006, which averaged only about 20 cents per gallon lower than last year's but exhibited more normal seasonality, and then multiplied by the more than 137 billion gallons of gasoline the US is likely to consume this year, the total drag on the economy worked out to between $100 and $150 billion on a full-year basis. (See chart below.) If these prices persisted, that would be enough to negate the effect of the entire 2% cut in Social Security taxes for 2011.Fortunately, barring an escalation of the current supply disruptions in the Middle East, a major hurricane affecting Gulf Coast refinery operations, or an unexpected surge in economic growth, we've probably either already seen the peak gasoline price for the year or are within a few weeks of it. The outcome of last week's OPEC meeting, while not as bearish for prices as an agreement to increase quotas and output would have been, has had little lasting effect on oil prices, which are running at a level consistent with this week's US average pump price or a bit less. However, no one should confuse a seasonal easing in prices with a permanent return to cheaper gas. Short of another global economic crisis, global oil supply and demand remain closely enough matched that any hiccup will quickly translate into higher prices at the pump. I feel safe in predicting that we'll be flirting with $4 again before long, and the consequences of that should be factored into any forecasts of future economic growth.
Tuesday, June 14, 2011
Marrying Gas and Renewables
A Turkish developer recently announced that it would build a new power plant using technology from GE that matches wind and solar generation to the output of a highly responsive natural gas turbine, all integrated in one package with the hardware and software to mesh its output with the grid. GE is apparently calling this scheme IRCC, for "integrated renewables combined cycle", adding yet another acronym to our growing list of energy choices. This development looks interesting from a technical perspective, but also for what it suggests about GE's view of the future market for generating equipment and power delivery.
The International Energy Agency's "Golden Age of Natural Gas" scenario remains a question mark, rather than a certainty, but if gas is to serve as the key fuel for bridging between our high-emission present and the low-emission future, then we're likely to see more installations like the one in Turkey emphasizing the synergies between gas and renewables, rather than the tough competition gas is giving renewables in some markets. The IRCC--not to be confused with an IGCC or the IPCC--is interesting because it goes well beyond the idea of using gas-fired power plants to back up the naturally variable output of wind farms and utility-scale solar arrays.
The IRCC concept is built around a new combined cycle gas turbine, the Flex-Efficiency 50, with an impressive capability to ramp up and down, as needed, with minimal loss of either efficiency or emissions performance. And thanks to the energy technology portfolio the company has built up over the last decade, GE is able to offer one-stop shopping with GE wind turbines and a solar thermal generating module from eSolar, in which GE has recently invested. The gas turbine/solar thermal hybridization looks especially useful in maximizing plant efficiency and incorporating solar thermal power into the grid at the lowest possible cost, by avoiding the expense of an extra steam turbine and generator. If all this works as advertised, the grid operator shouldn't know or care whether the power being dispatched was generated using wind, sun, or gas.
Before you confuse this posting for a GE ad, I should note that at least in the configuration chosen for the Turkish site most of the power from this integrated plant would still be generated by the gas turbine, which has 10 times the peak output of the concentrated solar power module and more than 20 times the rated power of the small wind farm tied into it. By the time you account for the capability of the gas turbine to run 24/7 when necessary, compared to typical capacity factors of 25-40% for wind and up to 25% for solar, the proportion of the IRCC's annual megawatt-hours generated from gas could exceed 95%. Nor is GE the only firm bringing turbines like this to market. So it's an impressive step, though more of an incremental than revolutionary one. However, with its inherent flexibility, I wouldn't be surprised if this type of gas turbine could effectively integrate a much larger quantity of renewable generation on the grid outside the IRCC's fence, particularly after the operating experience of the first few installations has been absorbed.
GE's timing in introducing its IRCC concept could prove especially apt. Not only does the Flex-Efficiency turbine look useful for helping to meet California's aggressive new 33% renewable electricity target, but the 50-cycle version featured in GE's marketing materials--likely minus the solar thermal module--could be just what Germany needs, now that its government has begun to come to grips with the quantity of new fossil generation that's going to be required to make up for the post-Fukushima accelerated retirement of its nuclear power plants.
The International Energy Agency's "Golden Age of Natural Gas" scenario remains a question mark, rather than a certainty, but if gas is to serve as the key fuel for bridging between our high-emission present and the low-emission future, then we're likely to see more installations like the one in Turkey emphasizing the synergies between gas and renewables, rather than the tough competition gas is giving renewables in some markets. The IRCC--not to be confused with an IGCC or the IPCC--is interesting because it goes well beyond the idea of using gas-fired power plants to back up the naturally variable output of wind farms and utility-scale solar arrays.
The IRCC concept is built around a new combined cycle gas turbine, the Flex-Efficiency 50, with an impressive capability to ramp up and down, as needed, with minimal loss of either efficiency or emissions performance. And thanks to the energy technology portfolio the company has built up over the last decade, GE is able to offer one-stop shopping with GE wind turbines and a solar thermal generating module from eSolar, in which GE has recently invested. The gas turbine/solar thermal hybridization looks especially useful in maximizing plant efficiency and incorporating solar thermal power into the grid at the lowest possible cost, by avoiding the expense of an extra steam turbine and generator. If all this works as advertised, the grid operator shouldn't know or care whether the power being dispatched was generated using wind, sun, or gas.
Before you confuse this posting for a GE ad, I should note that at least in the configuration chosen for the Turkish site most of the power from this integrated plant would still be generated by the gas turbine, which has 10 times the peak output of the concentrated solar power module and more than 20 times the rated power of the small wind farm tied into it. By the time you account for the capability of the gas turbine to run 24/7 when necessary, compared to typical capacity factors of 25-40% for wind and up to 25% for solar, the proportion of the IRCC's annual megawatt-hours generated from gas could exceed 95%. Nor is GE the only firm bringing turbines like this to market. So it's an impressive step, though more of an incremental than revolutionary one. However, with its inherent flexibility, I wouldn't be surprised if this type of gas turbine could effectively integrate a much larger quantity of renewable generation on the grid outside the IRCC's fence, particularly after the operating experience of the first few installations has been absorbed.
GE's timing in introducing its IRCC concept could prove especially apt. Not only does the Flex-Efficiency turbine look useful for helping to meet California's aggressive new 33% renewable electricity target, but the 50-cycle version featured in GE's marketing materials--likely minus the solar thermal module--could be just what Germany needs, now that its government has begun to come to grips with the quantity of new fossil generation that's going to be required to make up for the post-Fukushima accelerated retirement of its nuclear power plants.
Thursday, June 09, 2011
Do OPEC Meetings Matter?
Yesterday's meeting of OPEC in Vienna attracted extra attention because of disagreements between Saudi Arabia and Iran that extend well beyond the oil fields. The resulting impasse over increasing production to stem high oil prices and support a weakening global economy produced a much-quoted assessment from the Saudi Oil minister, Ali Naimi, who described it as "one of the worst meetings we ever had in OPEC." Yet while the events in the Middle East were at the forefront for most commentators, the outcome of the meeting seems understandable purely in the context of OPEC's own history and the current fundamentals of the market. I'm not sure why so many people appeared to expect OPEC to boost output in anticipation of demand that might not materialize.
I have followed OPEC meetings for nearly 30 years, though not always as closely as when I was trading oil and its products, the prices of which stood to rise or fall depending on what was decided in Vienna. My interest in this meeting went up significantly when I received a call inviting me to participate in a panel discussion about it on the Voice of Russia radio network yesterday afternoon. An hour or two of research revealed a global oil market that is currently well-supplied, with inventories in most developed countries running at fairly typical levels and inventories in the US actually on the high side of normal for this time of the year. That's pretty much the argument that OPEC's price hawks took into yesterday's session.
However, the Saudis and others arguing for higher quotas were looking ahead to the effects of summer demand, especially in rapidly growing Asia, and the buildup of inventories for the fall and winter heating fuel season. They--along with the IEA--anticipated demand growing faster than supply, particularly when the impact of the curtailments from Libya and Yemen are factored in. Such events are important because of the quality difference between the oil that's been shut in in those countries and the spare capacity elsewhere that's available to make up for it.
OPEC's main problem is that the outlook for the global economy has weakened in the last few weeks, and not just because oil has risen to above $115 per barrel, compared to its average of $80 or so last year. The stakes for them look even higher when you factor in a history that includes boosting production in the late 1990s to meet roaring demand in Asia-Pacific, only to see the Asian Economic Crisis slam demand growth in the region into reverse, sending crude prices tumbling from the $20s to single digits by the end of 1998. The doves within OPEC were focused on keeping prices below the level at which large chunks of demand were destroyed in 2008, while the hawks seemed willing to risk that outcome to avert a future price collapse and preserve the revenue they need to fund their national agendas.
The potential consequences for individual OPEC members are substantial. Consider Algeria, which exports about 1.8 million barrels per day. The difference between the current price and what they realized last year equates to more than $20 billion annually. That might sound small in the context of the current debate over trillion-dollar US deficits, but it's nearly 15% of Algeria's GDP. It's no wonder that smaller producers and others with limited capacity to increase output--and thus revenue--would drag their feet on agreeing to raise quotas for countries with spare capacity.
If it sounds like I'm rationalizing cartel behavior that would be illegal in the US, that's not my intent. It's clear to me that oil prices are significantly higher than they would be, because OPEC has chosen to produce around 2 million barrels per day less than it did in 2008. In part they've had to do that to accommodate higher non-OPEC production--think Brazil and Russia--along with rising biofuel production, without weakening prices. The consequences for US consumers are equally clear: Gasoline prices are still more than $1 per gallon higher than a year ago, and even ignoring the impact on diesel or jet fuel that translates into an additional drain of $100-150 billion per year that can't be spent on other goods and services that would contribute more to the recovery.
OPEC meetings do matter, because as long as OPEC possesses both spare production capacity and the discipline to withhold it from the market, it retains the power to control oil prices. If we want to understand the decision process of this group of countries that is always struggling to reconcile its own often-competing, but still broadly aligned self-interests, our assessment should focus on their issues more than ours, however much we are affected by the outcome. Yesterday we saw the price hawks stymie the efforts of those producers who are worried that if they squeeze consumers too hard, demand will fall back to the lows of 2009, costing them hundreds of billions of dollars per year in revenue. But if demand continues to grow, that was surely not the last word, and this debate must be revisited within a few months.
I have followed OPEC meetings for nearly 30 years, though not always as closely as when I was trading oil and its products, the prices of which stood to rise or fall depending on what was decided in Vienna. My interest in this meeting went up significantly when I received a call inviting me to participate in a panel discussion about it on the Voice of Russia radio network yesterday afternoon. An hour or two of research revealed a global oil market that is currently well-supplied, with inventories in most developed countries running at fairly typical levels and inventories in the US actually on the high side of normal for this time of the year. That's pretty much the argument that OPEC's price hawks took into yesterday's session.
However, the Saudis and others arguing for higher quotas were looking ahead to the effects of summer demand, especially in rapidly growing Asia, and the buildup of inventories for the fall and winter heating fuel season. They--along with the IEA--anticipated demand growing faster than supply, particularly when the impact of the curtailments from Libya and Yemen are factored in. Such events are important because of the quality difference between the oil that's been shut in in those countries and the spare capacity elsewhere that's available to make up for it.
OPEC's main problem is that the outlook for the global economy has weakened in the last few weeks, and not just because oil has risen to above $115 per barrel, compared to its average of $80 or so last year. The stakes for them look even higher when you factor in a history that includes boosting production in the late 1990s to meet roaring demand in Asia-Pacific, only to see the Asian Economic Crisis slam demand growth in the region into reverse, sending crude prices tumbling from the $20s to single digits by the end of 1998. The doves within OPEC were focused on keeping prices below the level at which large chunks of demand were destroyed in 2008, while the hawks seemed willing to risk that outcome to avert a future price collapse and preserve the revenue they need to fund their national agendas.
The potential consequences for individual OPEC members are substantial. Consider Algeria, which exports about 1.8 million barrels per day. The difference between the current price and what they realized last year equates to more than $20 billion annually. That might sound small in the context of the current debate over trillion-dollar US deficits, but it's nearly 15% of Algeria's GDP. It's no wonder that smaller producers and others with limited capacity to increase output--and thus revenue--would drag their feet on agreeing to raise quotas for countries with spare capacity.
If it sounds like I'm rationalizing cartel behavior that would be illegal in the US, that's not my intent. It's clear to me that oil prices are significantly higher than they would be, because OPEC has chosen to produce around 2 million barrels per day less than it did in 2008. In part they've had to do that to accommodate higher non-OPEC production--think Brazil and Russia--along with rising biofuel production, without weakening prices. The consequences for US consumers are equally clear: Gasoline prices are still more than $1 per gallon higher than a year ago, and even ignoring the impact on diesel or jet fuel that translates into an additional drain of $100-150 billion per year that can't be spent on other goods and services that would contribute more to the recovery.
OPEC meetings do matter, because as long as OPEC possesses both spare production capacity and the discipline to withhold it from the market, it retains the power to control oil prices. If we want to understand the decision process of this group of countries that is always struggling to reconcile its own often-competing, but still broadly aligned self-interests, our assessment should focus on their issues more than ours, however much we are affected by the outcome. Yesterday we saw the price hawks stymie the efforts of those producers who are worried that if they squeeze consumers too hard, demand will fall back to the lows of 2009, costing them hundreds of billions of dollars per year in revenue. But if demand continues to grow, that was surely not the last word, and this debate must be revisited within a few months.
Tuesday, June 07, 2011
The Golden Age of Natural Gas
A regular reader of this blog kindly sent me a link to the International Energy Agency's new study on global natural gas, to which he contributed. The report, entitled, "Are We Entering A Golden Age for Gas?" was launched with a press conference yesterday in London. It presents a scenario in which gas use grows rapidly due to faster demand growth, particularly in the developing world, increased supply from unconventional sources such as shale gas, and a slower expansion of nuclear power in the aftermath of the Fukushima Daichi accident. Its key findings envision gas providing 25% of world energy by 2035, up from 21% today, and eclipsing the share of coal before 2030, with corresponding benefits for global greenhouse gas emissions.
The IEA's presenters were careful to point out that they are not proposing this view as the likeliest scenario, but as an offshoot of their primary World Energy Outlook scenario published last fall, which incorporated the commitments at the Copenhagen climate conference. The new gas scenario depends on a number of uncertainties, including the resolution of some of the concerns about the environmental impacts of unconventional gas production, along with the realization of carbon-intensity and gas-development targets in places like China. However, it doesn't depend on new technology or dramatic changes such as a massive move to natural gas for vehicle use. (The latter is presented as a "High Impact Low Probability" sensitivity.) Its big shifts occur in the big existing gas market segments, for power generation globally and for industry and buildings in the developing world.
I was struck by several elements of the scenario. First, although much of the focus on unconventional gas has been on North America, where many of the techniques were pioneered, this is very much a global story. The IEA shows estimated unconventional gas resources from shale, "tight gas" and coal-bed methane that exceed conventional gas resources in Asia and Africa and rival them even in Eastern Europe/Eurasia. On the strength of its unconventional resources China could become the world's third-largest gas producer by 2035, behind Russia and the US. So even if the US plaintiffs bar attempts to turn "fracking" into the next tobacco or asbestos, unconventional gas exploitation will likely progress elsewhere. At the same time, increases in conventional gas production are expected to exceed those from unconventional sources, by 60/40 over the period studied. That requires big increases in LNG production in Australia and a substantial increase in pipeline capacity linking Russian and Central Asian gas to markets in Europe and Asia. It's also worth noting that despite the shale gas bonanza, the IEA doesn't envision the US becoming a net gas exporter.
As one of my mentors frequently reminded me, natural gas doesn't get developed without a market, and in this scenario the biggest source of new demand is in power generation, where the combination of lower gas prices and the 60% thermal efficiency of combined cycle gas turbines makes gas highly competitive, even with coal. It's less clear whether gas is taking market share from new nuclear based on price, or mainly filling the gap that the response to Fukushima is leaving in some markets. From what I heard on a power industry webinar yesterday, the former is a significant factor, at least in the US. The strong connection between gas and power is another reason why so much of the growth in gas demand--80% by the IEA's estimate--is expected to occur in developing countries including China and India, where electricity demand is expanding at rates that the US and Europe haven't experienced for years or decades. Perhaps the most startling forecast in the report is that China's gas demand could grow from roughly matching Germany's today to about the level of the entire EU in 25 years. That would be supported as much by additional imports as from domestic unconventional gas output.
As I'd have expected, the IEA provided a sober assessment of the environmental implications of their scenario. Increasing the share of gas in global energy demand reduces global GHG emissions by 160 million tons of CO2 equivalent by 2035--less than 1% of total emissions--by substituting for coal and some oil. That's a lot less than if the extra gas didn't also contribute to higher energy demand by keeping electricity prices lower, while outcompeting some lower-emission renewables and nuclear projects. The IEA states plainly that relying on more gas is not a silver bullet for climate change, although it is a positive step.
In addition to pointing out the need for safe handling of the fluids involved in hydraulic fracturing, the report also specifically addresses the critique of Howarth and others concerning the direct emissions from shale gas production. The IEA found that CO2-equivalent emissions for shale gas from well to burner exceed those for conventional gas by 3.5%-12%, depending on whether the methane liberated during well completion is captured, flared or vented to the atmosphere. Even at the high end, that does not negate gas's emissions advantage over other fossil fuels, especially when power generation efficiencies are factored in. The report's authors apparently see most of the excess emissions compared to conventional gas production as representing an opportunity that can be captured with current technology and best practices.
The IEA put a price tag on this shift to gas: a cumulative $8 trillion through 2035 , nearly $1 trillion higher than the gas infrastructure investment in their global energy scenario of last fall. Those figures aren't as hard to fathom in the context of developed-country budget deficits and debt as they might seem, because they mainly reflect unsubsidized, economically attractive investments by publicly-traded and state-owned energy companies that are making healthy profits and have substantial cash flow on which to draw. Surprisingly, the IEA sees most of the incremental investment in gas coming at the expense of oil. Although they deliberately framed the title of their scenario as a question that hinges on a number of variables, the report comes across as a plausible and credible glimpse of our possible energy future.
The IEA's presenters were careful to point out that they are not proposing this view as the likeliest scenario, but as an offshoot of their primary World Energy Outlook scenario published last fall, which incorporated the commitments at the Copenhagen climate conference. The new gas scenario depends on a number of uncertainties, including the resolution of some of the concerns about the environmental impacts of unconventional gas production, along with the realization of carbon-intensity and gas-development targets in places like China. However, it doesn't depend on new technology or dramatic changes such as a massive move to natural gas for vehicle use. (The latter is presented as a "High Impact Low Probability" sensitivity.) Its big shifts occur in the big existing gas market segments, for power generation globally and for industry and buildings in the developing world.
I was struck by several elements of the scenario. First, although much of the focus on unconventional gas has been on North America, where many of the techniques were pioneered, this is very much a global story. The IEA shows estimated unconventional gas resources from shale, "tight gas" and coal-bed methane that exceed conventional gas resources in Asia and Africa and rival them even in Eastern Europe/Eurasia. On the strength of its unconventional resources China could become the world's third-largest gas producer by 2035, behind Russia and the US. So even if the US plaintiffs bar attempts to turn "fracking" into the next tobacco or asbestos, unconventional gas exploitation will likely progress elsewhere. At the same time, increases in conventional gas production are expected to exceed those from unconventional sources, by 60/40 over the period studied. That requires big increases in LNG production in Australia and a substantial increase in pipeline capacity linking Russian and Central Asian gas to markets in Europe and Asia. It's also worth noting that despite the shale gas bonanza, the IEA doesn't envision the US becoming a net gas exporter.
As one of my mentors frequently reminded me, natural gas doesn't get developed without a market, and in this scenario the biggest source of new demand is in power generation, where the combination of lower gas prices and the 60% thermal efficiency of combined cycle gas turbines makes gas highly competitive, even with coal. It's less clear whether gas is taking market share from new nuclear based on price, or mainly filling the gap that the response to Fukushima is leaving in some markets. From what I heard on a power industry webinar yesterday, the former is a significant factor, at least in the US. The strong connection between gas and power is another reason why so much of the growth in gas demand--80% by the IEA's estimate--is expected to occur in developing countries including China and India, where electricity demand is expanding at rates that the US and Europe haven't experienced for years or decades. Perhaps the most startling forecast in the report is that China's gas demand could grow from roughly matching Germany's today to about the level of the entire EU in 25 years. That would be supported as much by additional imports as from domestic unconventional gas output.
As I'd have expected, the IEA provided a sober assessment of the environmental implications of their scenario. Increasing the share of gas in global energy demand reduces global GHG emissions by 160 million tons of CO2 equivalent by 2035--less than 1% of total emissions--by substituting for coal and some oil. That's a lot less than if the extra gas didn't also contribute to higher energy demand by keeping electricity prices lower, while outcompeting some lower-emission renewables and nuclear projects. The IEA states plainly that relying on more gas is not a silver bullet for climate change, although it is a positive step.
In addition to pointing out the need for safe handling of the fluids involved in hydraulic fracturing, the report also specifically addresses the critique of Howarth and others concerning the direct emissions from shale gas production. The IEA found that CO2-equivalent emissions for shale gas from well to burner exceed those for conventional gas by 3.5%-12%, depending on whether the methane liberated during well completion is captured, flared or vented to the atmosphere. Even at the high end, that does not negate gas's emissions advantage over other fossil fuels, especially when power generation efficiencies are factored in. The report's authors apparently see most of the excess emissions compared to conventional gas production as representing an opportunity that can be captured with current technology and best practices.
The IEA put a price tag on this shift to gas: a cumulative $8 trillion through 2035 , nearly $1 trillion higher than the gas infrastructure investment in their global energy scenario of last fall. Those figures aren't as hard to fathom in the context of developed-country budget deficits and debt as they might seem, because they mainly reflect unsubsidized, economically attractive investments by publicly-traded and state-owned energy companies that are making healthy profits and have substantial cash flow on which to draw. Surprisingly, the IEA sees most of the incremental investment in gas coming at the expense of oil. Although they deliberately framed the title of their scenario as a question that hinges on a number of variables, the report comes across as a plausible and credible glimpse of our possible energy future.
Thursday, June 02, 2011
Hedging the Risks of Selling Oil from the Strategic Petroleum Reserve
I see that the administration has asked Congress to approve a non-emergency sale of oil from the US Strategic Petroleum Reserve (SPR), in order to allow a storage cavern to be repaired before it starts to leak. That's fine, as far as it goes, though the article I read suggested this would be done as a net sale into the market, rather than an exchange for future oil, as has been done for many previous SPR releases. The distinction means that the government will either be exposed to buying the oil back at higher prices later, or would simply forgo refilling that portion of the reserve. The current shape of the oil futures market provides another alternative, though without the presumed political benefits of being seen to sell SPR oil when gasoline prices are high.
The sale in question was included in the administration's annual budget request and identified 6 million barrels to be sold "for operational purposes." That amounts to less than 1% of the 727 million barrels of oil currently in the SPR, equating to a little more than one day of import disruption insurance at the SPR's maximum output of 4.4 million barrels per day. Of course at current oil prices it would be worth over a half-billion bucks, so I can understand the appeal of doing this when federal finances are tight. However, the purpose of the reserve was never to speculate on the price of oil and harvest those gains when we came up short elsewhere; the oil is there to mitigate a serious disruption in the roughly 9 million barrels per day of oil imports on which our economy depends. Unless the administration now wants to undertake a comprehensive review of our SPR strategy--something I've advocated for several years--it is more or less obligated to replace the oil once the cavern has been fixed.
In that case, selling the oil, rather than offering it to refiners on a time-trade, will expose the government to a substantial amount of price risk while repairs are completed. For example, if they had sold this oil last fall and needed to buy it back now, the Department of Energy would have incurred a loss of up to $180 million, based on the increase in oil prices in general and the divergence of physical markets, which tend to track UK Brent Crude, from the futures market in West Texas Intermediate. Prices might fall in the meantime, but it is not the role of the DOE to bet on that prospect. The futures market offers a uniquely better alternative today.
Most of the time, the oil futures price curve is bent either up or down, in "contango" or "backwardation" in trader's terms, with oil for delivery several months or more from now selling for considerably more or less than for prompt delivery. That's usually an indication of expectations that the balance between supply and demand will be either tighter or looser in the months ahead, compared to today. The contango that prevailed until recently has flattened dramatically, so that if it acted quickly, the DOE could sell the oil from the caverns to refiners and lock in its future repurchase price on the futures market at only a dollar or two per barrel more than the sales price. Of course this would involve having the government participate in the dreaded futures market, even though it wouldn't be for the purpose of manipulation or stabilization, but for simple hedging of the kind that producers and refiners do every day of the week. (Backwardation would offer an even better deal, and the Brent market is currently mildly backwardated, but I can only imagine the hullabaloo if the US government hedged SPR oil on a European exchange.)
We would argue all day about which approach is riskier: hedging the oil sold from the SPR with futures contracts or waiting to buy back at whatever price prevailed later. In the larger scheme of things, neither looks as risky as emptying the cavern and not refilling it at all. Based on my experience and at least in this special case, hedging seems like a good way to ensure that the SPR cavern repair doesn't end up costing a lot more than the DOE expects, if its managers ignored oil-price risk.
The sale in question was included in the administration's annual budget request and identified 6 million barrels to be sold "for operational purposes." That amounts to less than 1% of the 727 million barrels of oil currently in the SPR, equating to a little more than one day of import disruption insurance at the SPR's maximum output of 4.4 million barrels per day. Of course at current oil prices it would be worth over a half-billion bucks, so I can understand the appeal of doing this when federal finances are tight. However, the purpose of the reserve was never to speculate on the price of oil and harvest those gains when we came up short elsewhere; the oil is there to mitigate a serious disruption in the roughly 9 million barrels per day of oil imports on which our economy depends. Unless the administration now wants to undertake a comprehensive review of our SPR strategy--something I've advocated for several years--it is more or less obligated to replace the oil once the cavern has been fixed.
In that case, selling the oil, rather than offering it to refiners on a time-trade, will expose the government to a substantial amount of price risk while repairs are completed. For example, if they had sold this oil last fall and needed to buy it back now, the Department of Energy would have incurred a loss of up to $180 million, based on the increase in oil prices in general and the divergence of physical markets, which tend to track UK Brent Crude, from the futures market in West Texas Intermediate. Prices might fall in the meantime, but it is not the role of the DOE to bet on that prospect. The futures market offers a uniquely better alternative today.
Most of the time, the oil futures price curve is bent either up or down, in "contango" or "backwardation" in trader's terms, with oil for delivery several months or more from now selling for considerably more or less than for prompt delivery. That's usually an indication of expectations that the balance between supply and demand will be either tighter or looser in the months ahead, compared to today. The contango that prevailed until recently has flattened dramatically, so that if it acted quickly, the DOE could sell the oil from the caverns to refiners and lock in its future repurchase price on the futures market at only a dollar or two per barrel more than the sales price. Of course this would involve having the government participate in the dreaded futures market, even though it wouldn't be for the purpose of manipulation or stabilization, but for simple hedging of the kind that producers and refiners do every day of the week. (Backwardation would offer an even better deal, and the Brent market is currently mildly backwardated, but I can only imagine the hullabaloo if the US government hedged SPR oil on a European exchange.)
We would argue all day about which approach is riskier: hedging the oil sold from the SPR with futures contracts or waiting to buy back at whatever price prevailed later. In the larger scheme of things, neither looks as risky as emptying the cavern and not refilling it at all. Based on my experience and at least in this special case, hedging seems like a good way to ensure that the SPR cavern repair doesn't end up costing a lot more than the DOE expects, if its managers ignored oil-price risk.
Tuesday, May 31, 2011
The Cost of A Tougher Iranian Oil Boycott
Today's Wall St. Journal (subscription required) includes an op-ed calling for a stricter US boycott of Iran than the current one that prohibits importing Iranian oil. The proposal from Reuel Marc Gerecht and Mark Dubowitz of the Foundation for the Defense of Democracies would go a step farther, barring the importation of petroleum products that contain any components processed from Iranian crude elsewhere. Before any fuels or petrochemical products could be brought to the US, exporters "would have to certify that no Iranian oil was involved in its manufacture." Yet while the authors have clearly thought about how to maximize the impact of such a rule on the government of Iran, I'm not sure they've examined the potential impact on the US carefully enough. If their arguments about how European refiners would react to such a boycott are correct, then U.S. gasoline prices would likely rise as a result of these restrictions.
The logic of the proposal is grounded in fact. The US imports significant quantities of gasoline from Europe, though lately most of it is in the form of gasoline blending components, rather than finished gasoline that is ready to be put into a pipeline or sold over a refinery's or blending facility's truck rack. Last year total US gasoline imports averaged almost 900,000 barrels per day, with 39% coming from EU countries led by the UK, Netherlands, Spain and France. It's also true that many European refineries process some Iranian crude. In 2010, the EU imported 471,000 bbl/day of crude oil from Iran, comprising just over 4% of total EU oil imports of 11.1 million barrels per day. (Compare that to US oil imports in 2010 of 9.2 million bbl/day.) This amounts to roughly a fifth of total Iranian crude oil exports. At least on the surface, it looks like it shouldn't be too hard for European refiners to forgo this small input, in order to be able to continue exporting gasoline and other oil-derived products to the USA.
In practice, I think it would be more difficult for European refiners to make that adjustment than the authors imagine. For starters, those refineries capable of exporting gasoline to the US must generally be located near ports, rather than inland, and likely run more Iranian crude than the EU average, since this oil is delivered by large tankers. Then there's the question of how much Iranian crude a refinery could run and still be able to certify its products to be Iran-free. If the standard were simply that you couldn't export a larger proportion of your products than the proportion of non-Iranian oil in your crude slate, that probably wouldn't change what any refiner is currently doing, since most of their output goes into the local market. Certifying that there were no molecules of Iranian origin in any products destined for the US would essentially require running no Iranian crude at all, because of the way that most refineries operate and manage their inventories of crude oil and unfinished products.
I presume that's what the authors have in mind, because it would certainly exert the greatest market pressure on the price of Iranian crude. However, substituting one crude oil for another in a refinery isn't like substituting one brand of cola for another in a fast-food restaurant. We've seen a prime example of that recently with the disproportionately large disruption caused by the curtailment of exports of high-quality oil from Libya. Refineries tend to be optimized around certain proportions of well-known crudes, with shifts in those proportions mainly driven by changes in the value of the products they yield, within a range set by the capabilities of the specific hardware. In other words, if your refinery model is telling you to run x% of Iranian Light, then choosing something else in order to be able to sell into the US market comes at a cost.
That cost would be passed on to companies importing European gasoline into the US in two ways. First, it would require a higher price to make it worthwhile for the exporting refinery to produce a cargo to US specifications. Less directly but just as significantly, it would reduce the number of refineries competing for the export opportunity, because some would simply find the changes too onerous, unless the premium they collected was really large. That would create a smaller pool of suppliers with higher costs. That's not what you want to face as a buyer.
Market dynamics might also amplify this effect. A portion of the gasoline exported from Europe to the US flows not under long-term contracts, but as "spot" cargoes shipped in response to occasional wide price differences between there and here. That's exactly the kind of trading I was involved in when I worked in London in the early '90s. Such "arbitrage opportunities" often result from supply problems such as refinery accidents and other unanticipated shutdowns, large weather events, or other situations leading to a local or regional price spike. As a result, much of the impact on the US from the authors' proposal could be delivered when gas prices here would already be rising, thus adding to the economic impact of a price spike.
Perhaps paying more at the pump to drive down the value of Iranian crude in the global market is a price most Americans would be willing to accept. I'd gladly kick in a few cents per gallon for that purpose, since I remain extremely skeptical of Iranian assurances that their nuclear program is entirely for peaceful purposes. Nothing has materially changed my view of that since my detailed analysis in 2005. However, I suspect that the strong likelihood that such a boycott would entail a certain amount of "blowback" at home would complicate the politics of passing the necessary legislation, particularly when gas prices are already quite high by US standards.
The logic of the proposal is grounded in fact. The US imports significant quantities of gasoline from Europe, though lately most of it is in the form of gasoline blending components, rather than finished gasoline that is ready to be put into a pipeline or sold over a refinery's or blending facility's truck rack. Last year total US gasoline imports averaged almost 900,000 barrels per day, with 39% coming from EU countries led by the UK, Netherlands, Spain and France. It's also true that many European refineries process some Iranian crude. In 2010, the EU imported 471,000 bbl/day of crude oil from Iran, comprising just over 4% of total EU oil imports of 11.1 million barrels per day. (Compare that to US oil imports in 2010 of 9.2 million bbl/day.) This amounts to roughly a fifth of total Iranian crude oil exports. At least on the surface, it looks like it shouldn't be too hard for European refiners to forgo this small input, in order to be able to continue exporting gasoline and other oil-derived products to the USA.
In practice, I think it would be more difficult for European refiners to make that adjustment than the authors imagine. For starters, those refineries capable of exporting gasoline to the US must generally be located near ports, rather than inland, and likely run more Iranian crude than the EU average, since this oil is delivered by large tankers. Then there's the question of how much Iranian crude a refinery could run and still be able to certify its products to be Iran-free. If the standard were simply that you couldn't export a larger proportion of your products than the proportion of non-Iranian oil in your crude slate, that probably wouldn't change what any refiner is currently doing, since most of their output goes into the local market. Certifying that there were no molecules of Iranian origin in any products destined for the US would essentially require running no Iranian crude at all, because of the way that most refineries operate and manage their inventories of crude oil and unfinished products.
I presume that's what the authors have in mind, because it would certainly exert the greatest market pressure on the price of Iranian crude. However, substituting one crude oil for another in a refinery isn't like substituting one brand of cola for another in a fast-food restaurant. We've seen a prime example of that recently with the disproportionately large disruption caused by the curtailment of exports of high-quality oil from Libya. Refineries tend to be optimized around certain proportions of well-known crudes, with shifts in those proportions mainly driven by changes in the value of the products they yield, within a range set by the capabilities of the specific hardware. In other words, if your refinery model is telling you to run x% of Iranian Light, then choosing something else in order to be able to sell into the US market comes at a cost.
That cost would be passed on to companies importing European gasoline into the US in two ways. First, it would require a higher price to make it worthwhile for the exporting refinery to produce a cargo to US specifications. Less directly but just as significantly, it would reduce the number of refineries competing for the export opportunity, because some would simply find the changes too onerous, unless the premium they collected was really large. That would create a smaller pool of suppliers with higher costs. That's not what you want to face as a buyer.
Market dynamics might also amplify this effect. A portion of the gasoline exported from Europe to the US flows not under long-term contracts, but as "spot" cargoes shipped in response to occasional wide price differences between there and here. That's exactly the kind of trading I was involved in when I worked in London in the early '90s. Such "arbitrage opportunities" often result from supply problems such as refinery accidents and other unanticipated shutdowns, large weather events, or other situations leading to a local or regional price spike. As a result, much of the impact on the US from the authors' proposal could be delivered when gas prices here would already be rising, thus adding to the economic impact of a price spike.
Perhaps paying more at the pump to drive down the value of Iranian crude in the global market is a price most Americans would be willing to accept. I'd gladly kick in a few cents per gallon for that purpose, since I remain extremely skeptical of Iranian assurances that their nuclear program is entirely for peaceful purposes. Nothing has materially changed my view of that since my detailed analysis in 2005. However, I suspect that the strong likelihood that such a boycott would entail a certain amount of "blowback" at home would complicate the politics of passing the necessary legislation, particularly when gas prices are already quite high by US standards.
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