Just over two weeks after the earthquake near Sendai in northeastern Japan, which I'm increasingly seeing referred to as the "Great Tohoku Earthquake", the impact of the resulting disruption to various supply chains is being felt around the world. From car factories in Europe that rely on Japanese electronic components to producers of flat-panel displays and solar cells, several industries are feeling the pinch. This appears to be due more to the reduction in Japan's electricity-generation capacity than from actual damage to factories in the zone most affected by the disaster. With more power plants than just the troubled Fukushima Daiichi nuclear complex affected, the scale and potential duration of electricity shortages could result in a significant increase in the demand for smaller-scale generation, both conventional and renewable.
As reported in today's Wall St. Journal, the electricity shortfall resulting from the quake and tsunami is severe and affects both consumers and businesses. The Japanese government is exploring a number of emergency measures to mitigate the problem, including increasing electricity prices, instituting Daylight Savings Time, and calling on customers to conserve power. At the same time, the government appears to understand that Japan's scope for large-scale energy-efficiency improvements is limited. With an energy intensity in BTUs per dollar of GDP already 37% lower than that of the US, only the UK among large developed countries is more efficient. Efficiency and conservation will be helpful, but they can't cover the massive shortfall Japan faces now.
One of the most detailed analyses of the impact of the quake and tsunami on Japan's electricity sector that I've seen so far suggests that as much as 15,000 MW of generating capacity in the Tokyo/Tohoku region is offline and likely to remain so for durations ranging from a few months to several years--or permanently, in the case of most of the reactors at Fukushima Daiichi. This is something like 20% of the pre-quake generating capacity of the two main utilities serving the region, not counting the pumped-hydro storage capacity used for meeting peak demand. As a result, that part of Japan is experiencing an electricity deficit that will likely grow as the summer peak demand months approach, and that could persist even after the least-damaged facilities return to service. Nor can surplus power from southern Japan provide much assistance, because the northern and southern systems are relatively isolated from each other, with limited interconnections, and run on different frequencies--60 cycles for the south and 50 cycles for the north. Back-up and distributed generation appears to be the only real alternative to a protracted economic slowdown caused by insufficient electricity for Japan's businesses and industries.
We've seen this pattern before, if from different and less-catastrophic causes. In the early 1990s the Philippine grid was chronically unreliable, and many businesses bought or leased diesel generators to fill the gap, including barge-mounted units that could be brought in quickly and moved around coastlines and rivers as demand shifted. More recently, diesel demand in China increased substantially in the lead-up to the 2008 Summer Olympics, as the central government idled large, dirty power plants in order to reduce air pollution, and a number of factories chose to generate their own power, rather than shutting down.
For Japanese factories and other businesses facing the same dilemma, cost is unlikely to be the major factor in deciding whether or not to become more energy self-sufficient. Factory managers can often justify paying a lot more for power if their only other option is to slow production or shut down. They have several choices available, including some renewable power options, and I expect to see a surge in solar power installations. However, that's probably a better medium-term rather than short-term option, not just because the entire world didn't install enough solar panels last year to make up for the lost output of the Japanese nuclear plants, but because while solar can help with supply, it can't provide the reliability that is crucial right now. That makes diesel generation the leading contender to backstop Japan's idled power plants in the short term.
I can't speak to the availability of diesel generators, although I can easily envision suppliers and leasing agents scrambling to meet frantic Japanese orders. However, if enough generators are available to cover even 3,000 MW of the shortfall, running just half the time, they would require around 65,000 barrels per day of incremental diesel fuel, or roughly the entire diesel output of a medium-sized refinery. Whether that represented an increase in overall Japanese diesel consumption requiring additional imports would depend on the extent of the other economic consequences of the Tohoku disaster, and on when Japan's refineries return to normal operations.
So the use of diesel generators to make up for damaged or otherwise unavailable generating capacity in Japan could provide another modest boost to global oil demand, which already appears to have exceeded the record level set prior to the recession and financial crisis. And since much of that increased demand is for diesel, rather than gasoline, the impact of Japanese generation needs could affect diesel prices disproportionally. As a result, consumers around the world could see diesel prices rise, as the ripples from the events in Japan spread.
Monday, March 28, 2011
Thursday, March 24, 2011
Renewable Energy: Horses for Courses
It has become nearly impossible to keep track of all the major wind and solar projects underway at any point in time. Considering that I can recall when a month's worth of project announcements could be counted on the fingers of one hand, that's a sign of the tremendous progress in renewable energy over the last decade. Today, the projects that I notice tend to involve either novel technologies, or companies or locations in which I'm interested, such as the new rooftop solar thermal installation on the convention center of St. Paul, Minnesota, not far from where my in-laws live. I probably wouldn't have even paid attention to this one, if the eye-popping price tag hadn't included a cool million in federal stimulus funding. As I read on, it quickly became clear from the figures included in the news story that it requires more imagination than I possess to view this project as a good investment for taxpayers.
In putting the project's $2 million cost into perspective it's important to understand the distinction between solar thermal collectors and solar photovoltaic panels (PV). The former capture and transfer heat, while the latter turn sunlight into electricity, which is much more valuable. A 1 Megawatt (MW) PV installation would cost quite a lot more than $2 million, but that doesn't make this installation's price a bargain. Assessing that depends on the annual energy savings and resulting avoided fuel purchases. From the project description and the emissions reductions cited in the article it was possible to work out the expected annual energy savings involved, which appeared to have been something of a mystery to the facility spokesperson quoted. A MW of solar thermal equates to 3.4 million BTUs per hour, although the River Centre's rooftop clearly wouldn't generate that on a 24/7 basis even in a much sunnier location than the Twin Cities. However, the 900,000 pounds a year of avoided CO2 are unambiguous. At 117 lb. CO2 per million BTUs of pipeline gas, that equates to saving 7.7 billion BTUs of gas a year. And at last year's average commercial natural gas price for the state, that works out to an annual avoided cost of $58,000.
When I convert that stream of future energy savings into its net present value over 25 years, even with fairly generous assumptions on the cost of capital and future natural gas inflation, it is worth about what the convention center alone paid for it, or around $1 million, ignoring the impact of the two years it apparently took to build it. So in the parlance of corporate project evaluation, the federal officials who approved the RiverCentre's solar roof for that stimulus grant destroyed about a million dollars of taxpayer value when they decided to fund a solar thermal project in such a northern location with relatively low annual peak-sun hours. What were they thinking?
Well, the DOE official present at the facility's unveiling offered a clue by means of a hockey quote--always a good call in Minnesota. "We want to be where the puck is going to be, not where it is now." I would translate that as their funding of this project constituting an investment in bringing down the cost of future solar installations. Unfortunately, that would be much more credible if the installation in question involved leading-edge thin film or multi-junction concentrating PV technology, for which performance and cost have been improving steadily, if not quite in Moore's Law fashion. But this is solar hot water. The thermodynamics and heat-transfer considerations for such an application haven't changed since I was in engineering school, even if the packaging has improved. There's only so much heat to be captured and transferred, especially in a place with an average January temperature of 22°F.
When I'm critical of projects such as this one, it's not out of a sense that all renewable energy is impractical or ineffective. Renewables are earning a place in our energy mix, and they will become even more important in the years ahead. However, because they depend on harnessing diffuse energy sources in real time, rather than disgorging geologically stored energy in the manner of fossil fuels, it matters greatly where we put them. That's why I've been relentless in my criticism of Germany's overly-generous feed-in tariffs, and I see rooftop solar thermal in St. Paul in much the same light. Installing renewable energy devices in locations with poor resources, particularly using taxpayer money--or in this case money borrowed on the taxpayers' behalf--reinforces all the worst stereotypes about renewable energy as a boondoggle. The British have an expression that seems apt here, "horses for courses": run the right horse for each racecourse. If someone wants to bet their own money on rooftop solar in Minnesota, they do so with my blessing. But where my tax money is involved--and perhaps I'm especially sensitive about that this time of the year--I insist that it be done someplace that affords the technology a decent chance of earning an economic return, rather than just feel-good, PR value.
In putting the project's $2 million cost into perspective it's important to understand the distinction between solar thermal collectors and solar photovoltaic panels (PV). The former capture and transfer heat, while the latter turn sunlight into electricity, which is much more valuable. A 1 Megawatt (MW) PV installation would cost quite a lot more than $2 million, but that doesn't make this installation's price a bargain. Assessing that depends on the annual energy savings and resulting avoided fuel purchases. From the project description and the emissions reductions cited in the article it was possible to work out the expected annual energy savings involved, which appeared to have been something of a mystery to the facility spokesperson quoted. A MW of solar thermal equates to 3.4 million BTUs per hour, although the River Centre's rooftop clearly wouldn't generate that on a 24/7 basis even in a much sunnier location than the Twin Cities. However, the 900,000 pounds a year of avoided CO2 are unambiguous. At 117 lb. CO2 per million BTUs of pipeline gas, that equates to saving 7.7 billion BTUs of gas a year. And at last year's average commercial natural gas price for the state, that works out to an annual avoided cost of $58,000.
When I convert that stream of future energy savings into its net present value over 25 years, even with fairly generous assumptions on the cost of capital and future natural gas inflation, it is worth about what the convention center alone paid for it, or around $1 million, ignoring the impact of the two years it apparently took to build it. So in the parlance of corporate project evaluation, the federal officials who approved the RiverCentre's solar roof for that stimulus grant destroyed about a million dollars of taxpayer value when they decided to fund a solar thermal project in such a northern location with relatively low annual peak-sun hours. What were they thinking?
Well, the DOE official present at the facility's unveiling offered a clue by means of a hockey quote--always a good call in Minnesota. "We want to be where the puck is going to be, not where it is now." I would translate that as their funding of this project constituting an investment in bringing down the cost of future solar installations. Unfortunately, that would be much more credible if the installation in question involved leading-edge thin film or multi-junction concentrating PV technology, for which performance and cost have been improving steadily, if not quite in Moore's Law fashion. But this is solar hot water. The thermodynamics and heat-transfer considerations for such an application haven't changed since I was in engineering school, even if the packaging has improved. There's only so much heat to be captured and transferred, especially in a place with an average January temperature of 22°F.
When I'm critical of projects such as this one, it's not out of a sense that all renewable energy is impractical or ineffective. Renewables are earning a place in our energy mix, and they will become even more important in the years ahead. However, because they depend on harnessing diffuse energy sources in real time, rather than disgorging geologically stored energy in the manner of fossil fuels, it matters greatly where we put them. That's why I've been relentless in my criticism of Germany's overly-generous feed-in tariffs, and I see rooftop solar thermal in St. Paul in much the same light. Installing renewable energy devices in locations with poor resources, particularly using taxpayer money--or in this case money borrowed on the taxpayers' behalf--reinforces all the worst stereotypes about renewable energy as a boondoggle. The British have an expression that seems apt here, "horses for courses": run the right horse for each racecourse. If someone wants to bet their own money on rooftop solar in Minnesota, they do so with my blessing. But where my tax money is involved--and perhaps I'm especially sensitive about that this time of the year--I insist that it be done someplace that affords the technology a decent chance of earning an economic return, rather than just feel-good, PR value.
Monday, March 21, 2011
Carbon-Neutral Gasoline
I see that Google's venture capital fund is investing in a startup company that would produce hydrocarbon fuels from cellulosic plant matter, with the added twist of sequestering carbon in soil. This is another signpost of the growing interest in non-alcohol biofuels, often referred to as "drop-in" fuels, for both oil replacement and climate mitigation. With cellulosic ethanol developers having mainly disappointed for the last several years, and with so much current policy focus on electric vehicles and their infrastructure, I find it reassuring that there are smart people out there working on alternative fuels that fit today's cars, with today's infrastructure. That's important not just for the obvious reasons, but because the end result of energy policy must create successful business models, not just neat technology.
I haven't delved deeply enough into the technology of CoolPlanetBioFuels to form an opinion about its potential, though I do have some questions about how their front-end "thermal/mechanical processor", which will apparently be produced in 1-million gallon-per-year modules, would mesh with the catalytic fuel production processes needed to turn its output into consumer-ready fuels. Those processes normally operate at scales 100 times larger than CoolPlanet's processor, and when it comes to the efficiency of industrial chemistry, smaller is rarely better. However, if their technology works as advertised, the company's pursuit of the mainstream fuel market looks like a smart business decision.
A few years ago, the main buzz in alternative fuels concerned the production of ethanol from cellulose, and companies large and small were pouring money and resources into different ways to do this, as were governments. That's still happening, despite many of the companies involved missing their early production targets so badly that the Environmental Protection Agency twice had to revise its annual Renewable Fuel Standard (RFS) mandate to compensate for the shortfalls. However, the bigger worry about cellulosic ethanol might not be its production, though that is quite challenging enough, but its ultimate market. That's because corn ethanol has effectively filled up the easiest outlet, consisting of the 10% of a gallon of ordinary gasoline that ethanol can occupy without potentially compromising the fuel systems of cars not designed as flexible fuel vehicles, as well as refueling infrastructure that appears not to be up to handling more ethanol. The EPA has approved a 15% blend, but it faces both litigation and significant practical constraints.
Then there's E85, the 85% ethanol/15% gasoline blend that was expected to provide all the market headroom that ethanol producers would need, when the RFS goals were enacted in 2007. Yet despite generous tax incentives for E85 station conversions and a price that currently averages 53¢ per gallon less than regular unleaded gasoline on a volumetric basis--though still about 50¢/gal. more on an equivalent energy basis-- E85 remains something of a dud, even in the heart of corn country. E85 sales set a record last year in Iowa, but the 9 million gallons sold through 138 outlets there accounted for just 0.7% of the gasoline sold in the state in 2010.
If you want to make money selling motor fuel--or as in the case of CoolPlanet making the hardware for making fuels--then you must come to grips with the commodity nature of its markets. After water, motor fuels are probably the world's largest commodity business. That means that volume, rather than high margins, is the main driver of revenue and profits. The major oil companies struggled with this for decades, pursuing the last penny a gallon of margin by means of additives and advertising. Many of them have left this segment entirely to franchisees, because it's typically not profitable enough to compete with their other investment opportunities. Niche markets can be attractive if they offer unusually high margins, such as those available in the 200 million gallon-per-year aviation gasoline business, which supports just a few players. However, it's not obvious that ethanol and E85 fall into that category. So if you want to develop your business based on its growth potential, and your technology gives you a choice between selling into an at least temporarily saturated ethanol market or the much larger market for fuels that don't require special infrastructure or dedicated fleets, opting for the latter looks like a no-brainer.
The extra angle CoolPlanet offers comes in the form of its sold carbon byproduct called "biochar". This is sometimes referred to as "terra preta", which was a pre-Columbian charcoal-based fertilizer used in South America. The idea is that by returning this product to the soil, rather than allowing the carbon of the biomass to decay into CO2 and enter the atmosphere, the entire process can be made carbon neutral or even carbon negative, sequestering as much or more carbon as the liquid fuels produced will emit when burned. Terra preta is something of a hot topic lately, though the logic of burying solid carbon in one location at the same time that others are mining solid carbon--a.k.a. coal--from the earth elsewhere somewhat escapes me. Nor would the gasoline produced from CoolPlanet's process be any more carbon neutral in effect than conventional gasoline produced by a company that scrupulously bought matching emissions offsets for its products, which could currently be had for a cost of around 9¢ per gal. via an organization like CarbonFund.org.
It's hard to assess the value of the climate-friendly aspects of CoolPlanet's technology in the US, given the uncertainties about pending EPA greenhouse gas regulations and Congressional legislation. However, the attractiveness of a renewable energy technology that unlike wind, solar and geothermal power could actually displace oil on a barrel-for-barrel basis, and that isn't subject to ethanol's limitations and drawbacks, is understandable. All that remains is for CoolPlanet to demonstrate that their device really works and that they can bring it to market at a price that allows the fuels it would produce to compete with commodity fuels from petroleum. That would be big news, indeed.
I haven't delved deeply enough into the technology of CoolPlanetBioFuels to form an opinion about its potential, though I do have some questions about how their front-end "thermal/mechanical processor", which will apparently be produced in 1-million gallon-per-year modules, would mesh with the catalytic fuel production processes needed to turn its output into consumer-ready fuels. Those processes normally operate at scales 100 times larger than CoolPlanet's processor, and when it comes to the efficiency of industrial chemistry, smaller is rarely better. However, if their technology works as advertised, the company's pursuit of the mainstream fuel market looks like a smart business decision.
A few years ago, the main buzz in alternative fuels concerned the production of ethanol from cellulose, and companies large and small were pouring money and resources into different ways to do this, as were governments. That's still happening, despite many of the companies involved missing their early production targets so badly that the Environmental Protection Agency twice had to revise its annual Renewable Fuel Standard (RFS) mandate to compensate for the shortfalls. However, the bigger worry about cellulosic ethanol might not be its production, though that is quite challenging enough, but its ultimate market. That's because corn ethanol has effectively filled up the easiest outlet, consisting of the 10% of a gallon of ordinary gasoline that ethanol can occupy without potentially compromising the fuel systems of cars not designed as flexible fuel vehicles, as well as refueling infrastructure that appears not to be up to handling more ethanol. The EPA has approved a 15% blend, but it faces both litigation and significant practical constraints.
Then there's E85, the 85% ethanol/15% gasoline blend that was expected to provide all the market headroom that ethanol producers would need, when the RFS goals were enacted in 2007. Yet despite generous tax incentives for E85 station conversions and a price that currently averages 53¢ per gallon less than regular unleaded gasoline on a volumetric basis--though still about 50¢/gal. more on an equivalent energy basis-- E85 remains something of a dud, even in the heart of corn country. E85 sales set a record last year in Iowa, but the 9 million gallons sold through 138 outlets there accounted for just 0.7% of the gasoline sold in the state in 2010.
If you want to make money selling motor fuel--or as in the case of CoolPlanet making the hardware for making fuels--then you must come to grips with the commodity nature of its markets. After water, motor fuels are probably the world's largest commodity business. That means that volume, rather than high margins, is the main driver of revenue and profits. The major oil companies struggled with this for decades, pursuing the last penny a gallon of margin by means of additives and advertising. Many of them have left this segment entirely to franchisees, because it's typically not profitable enough to compete with their other investment opportunities. Niche markets can be attractive if they offer unusually high margins, such as those available in the 200 million gallon-per-year aviation gasoline business, which supports just a few players. However, it's not obvious that ethanol and E85 fall into that category. So if you want to develop your business based on its growth potential, and your technology gives you a choice between selling into an at least temporarily saturated ethanol market or the much larger market for fuels that don't require special infrastructure or dedicated fleets, opting for the latter looks like a no-brainer.
The extra angle CoolPlanet offers comes in the form of its sold carbon byproduct called "biochar". This is sometimes referred to as "terra preta", which was a pre-Columbian charcoal-based fertilizer used in South America. The idea is that by returning this product to the soil, rather than allowing the carbon of the biomass to decay into CO2 and enter the atmosphere, the entire process can be made carbon neutral or even carbon negative, sequestering as much or more carbon as the liquid fuels produced will emit when burned. Terra preta is something of a hot topic lately, though the logic of burying solid carbon in one location at the same time that others are mining solid carbon--a.k.a. coal--from the earth elsewhere somewhat escapes me. Nor would the gasoline produced from CoolPlanet's process be any more carbon neutral in effect than conventional gasoline produced by a company that scrupulously bought matching emissions offsets for its products, which could currently be had for a cost of around 9¢ per gal. via an organization like CarbonFund.org.
It's hard to assess the value of the climate-friendly aspects of CoolPlanet's technology in the US, given the uncertainties about pending EPA greenhouse gas regulations and Congressional legislation. However, the attractiveness of a renewable energy technology that unlike wind, solar and geothermal power could actually displace oil on a barrel-for-barrel basis, and that isn't subject to ethanol's limitations and drawbacks, is understandable. All that remains is for CoolPlanet to demonstrate that their device really works and that they can bring it to market at a price that allows the fuels it would produce to compete with commodity fuels from petroleum. That would be big news, indeed.
Thursday, March 17, 2011
Fewer Choices Post-Fukushima?
Even before the resolution of the crisis at the Fukushima Daiichi reactor complex--a crisis that has diverted media attention from the much larger humanitarian crisis caused by last Friday's tsunami--its consequences for nuclear energy policy are rippling across the globe. It is extraordinarily premature to form conclusions about these events, although that didn't stop many from arriving at similarly hasty and under-informed conclusions in the case of last spring's Deepwater Horizon accident. Pervasive instant analysis promotes knee-jerk responses. If the nuclear renaissance that had already been slowed by the recession and financial crisis was struck a fatal blow last week, what could that mean for our energy choices in the years ahead?
Although I want to focus mainly on the potential consequences in the US, what has already transpired in Germany provides a cautionary tale. As reported Tuesday, seven nuclear power plants of similar vintage and/or design to the damaged quartet at Fukushima are being shut down, at least temporarily, as the German government reassesses its decision to extend the operating life of the country's 17 power reactors. Germany hasn't been comfortable with its nukes for some time, though I find it remarkable that 70% of the population is apparently concerned that an accident that required an epic earthquake and a tsunami to trigger could happen there, too. (The next time someone lectures you about German practicality, this would be a fine counter-example to trot out.) However odd that reaction might seem to me and others with an engineering/hard science bent, it's a reminder that nuclear risks are viewed differently than many others, perhaps because radiation is invisible and insidious in its effects. Even if the reactors are finally cooled down with no further incidents and no injuries beyond the plant personnel, who have taken great risks for the public good, we will tend to focus on how much worse the outcome could have been.
Yet shutting down those nuclear plants in Germany is not without consequences, either, as noted by the Breakthrough Institute. Germany's greenhouse gas emissions will inevitably increase, because the country is already adding renewable generation as fast as it can and must make up any shortfall from fossil fuels. After committing an estimated €120 billion ($167 billion) for solar power through 2011, based on the 20 years of feed-in tariff support existing installations will receive, Germany still gets just 2% of its annual generation from solar, compared to around 24% from nuclear. That's mainly because Germany is such an unsuitable location for solar.
What about the US? Nuclear power supplied almost 20% of the electricity generated here in 2010, compared to 45% for coal, nearly 24% for natural gas, 10% for all renewables, and less than 1% from oil. Any notion of replacing the contribution of nuclear power in the longer term would require careful consideration of the energy sources that might fill the gap--based on scale and growth potential--and what it would mean for efforts to cut greenhouse gas emissions by reducing the generation of electricity from coal, which accounted for 81% of the emissions from the electricity sector and 26% of all US emissions in 2009. As for replacing nuclear power in the short run, that's simply out of the question, unless we want to bring on a recession that would make 2009 look like a boom year.
It's not that it's impossible to imagine a US energy mix without nuclear. After all, that's what we had on a much smaller scale prior to the 1960s. We certainly have enough coal and natural gas to take up any slack, although I don't think that would be quite the desired solution of those who would be most eager for an end to nuclear power. For that matter, a combination of geothermal power and concentrated solar power (CSP), the former baseload and the latter at least dispatchable, could also fill the gap, although a geothermal build-out on that scale would provoke concerns about "induced seismicity", while CSP would be largely a regional solution or require lots of very long-distance, high voltage power lines that present massive NIMBY issues of their own. Wind power, which until last year was growing at around 40% annually, could provide 20% or more of the generating mix by 2030, but it can't substitute for nuclear's central role without far more cheap power storage than we can reasonably expect to have available by then. And while solar has great potential, especially as its cost falls, it's no better suited to delivering reliable 24/7 power than is wind, and it is starting from an even smaller level than wind's 2.3% of generation last year.
The likeliest replacement for nuclear power in the US would thus be a combination of sources similar to our current non-nuclear mix, comprised of about 55% coal, 30% gas and 15% renewables, with some help from efficiency. On the basis of the average emissions from these sources, making up for the loss of the 807 billion kilowatt-hours generated by nuclear last year would increase US greenhouse gas emissions by around 580 million tons of CO2-equivalent per year, or 10% of net US emissions in 2009. That would hardly be conducive to meeting our Copenhagen pledge to reduce emissions by 17% by 2020, but then in a non-nuclear world most such pledges would have to be considered null and void.
Barring a worst-case outcome in Japan, I don't expect a groundswell in the US if favor of abandoning nuclear power--not even for the 35 reactors of generally similar design to the ones at Fukushima. Despite that, the emissions figures I calculated above remain relevant. Without a concerted effort to build new power reactors in the next two decades, the US will be on a sure path to de-nuclearization, as 41 of the existing plants would reach the end of their lives and operating licenses--many after a full 60 years of operations--by the mid-2030s. That process could accelerate significantly if the facilities that are awaiting license extensions now face much tougher scrutiny and are turned down in significant numbers. In that case we could lose up to 10,000 MW of nuclear capacity by the end of this decade, generating roughly the same annual output as our entire current wind power capacity. There are some who are already working to make that happen, either openly or more subtly. In that context the story on MSNBC yesterday listing US nuclear reactors in order of earthquake risk was either a public service or fear-mongering, depending on your perspective.
Whether we back away from nuclear power all at once, as Germany seems poised to consider doing, or one plant at a time, the result would be much the same: increased emissions, costlier and less reliable power, at least in the near-to-medium term, and more strain on infrastructure. I still think we'll choose to include nuclear in our evolving future energy mix, particularly given the significant improvements in the technology since the Fukushima reactors were built, along with the development of new, smaller-scale nuclear power options. Yet I have to admit my confidence in that result has been shaken by the reaction to the events in Japan.
Although I want to focus mainly on the potential consequences in the US, what has already transpired in Germany provides a cautionary tale. As reported Tuesday, seven nuclear power plants of similar vintage and/or design to the damaged quartet at Fukushima are being shut down, at least temporarily, as the German government reassesses its decision to extend the operating life of the country's 17 power reactors. Germany hasn't been comfortable with its nukes for some time, though I find it remarkable that 70% of the population is apparently concerned that an accident that required an epic earthquake and a tsunami to trigger could happen there, too. (The next time someone lectures you about German practicality, this would be a fine counter-example to trot out.) However odd that reaction might seem to me and others with an engineering/hard science bent, it's a reminder that nuclear risks are viewed differently than many others, perhaps because radiation is invisible and insidious in its effects. Even if the reactors are finally cooled down with no further incidents and no injuries beyond the plant personnel, who have taken great risks for the public good, we will tend to focus on how much worse the outcome could have been.
Yet shutting down those nuclear plants in Germany is not without consequences, either, as noted by the Breakthrough Institute. Germany's greenhouse gas emissions will inevitably increase, because the country is already adding renewable generation as fast as it can and must make up any shortfall from fossil fuels. After committing an estimated €120 billion ($167 billion) for solar power through 2011, based on the 20 years of feed-in tariff support existing installations will receive, Germany still gets just 2% of its annual generation from solar, compared to around 24% from nuclear. That's mainly because Germany is such an unsuitable location for solar.
What about the US? Nuclear power supplied almost 20% of the electricity generated here in 2010, compared to 45% for coal, nearly 24% for natural gas, 10% for all renewables, and less than 1% from oil. Any notion of replacing the contribution of nuclear power in the longer term would require careful consideration of the energy sources that might fill the gap--based on scale and growth potential--and what it would mean for efforts to cut greenhouse gas emissions by reducing the generation of electricity from coal, which accounted for 81% of the emissions from the electricity sector and 26% of all US emissions in 2009. As for replacing nuclear power in the short run, that's simply out of the question, unless we want to bring on a recession that would make 2009 look like a boom year.
It's not that it's impossible to imagine a US energy mix without nuclear. After all, that's what we had on a much smaller scale prior to the 1960s. We certainly have enough coal and natural gas to take up any slack, although I don't think that would be quite the desired solution of those who would be most eager for an end to nuclear power. For that matter, a combination of geothermal power and concentrated solar power (CSP), the former baseload and the latter at least dispatchable, could also fill the gap, although a geothermal build-out on that scale would provoke concerns about "induced seismicity", while CSP would be largely a regional solution or require lots of very long-distance, high voltage power lines that present massive NIMBY issues of their own. Wind power, which until last year was growing at around 40% annually, could provide 20% or more of the generating mix by 2030, but it can't substitute for nuclear's central role without far more cheap power storage than we can reasonably expect to have available by then. And while solar has great potential, especially as its cost falls, it's no better suited to delivering reliable 24/7 power than is wind, and it is starting from an even smaller level than wind's 2.3% of generation last year.
The likeliest replacement for nuclear power in the US would thus be a combination of sources similar to our current non-nuclear mix, comprised of about 55% coal, 30% gas and 15% renewables, with some help from efficiency. On the basis of the average emissions from these sources, making up for the loss of the 807 billion kilowatt-hours generated by nuclear last year would increase US greenhouse gas emissions by around 580 million tons of CO2-equivalent per year, or 10% of net US emissions in 2009. That would hardly be conducive to meeting our Copenhagen pledge to reduce emissions by 17% by 2020, but then in a non-nuclear world most such pledges would have to be considered null and void.
Barring a worst-case outcome in Japan, I don't expect a groundswell in the US if favor of abandoning nuclear power--not even for the 35 reactors of generally similar design to the ones at Fukushima. Despite that, the emissions figures I calculated above remain relevant. Without a concerted effort to build new power reactors in the next two decades, the US will be on a sure path to de-nuclearization, as 41 of the existing plants would reach the end of their lives and operating licenses--many after a full 60 years of operations--by the mid-2030s. That process could accelerate significantly if the facilities that are awaiting license extensions now face much tougher scrutiny and are turned down in significant numbers. In that case we could lose up to 10,000 MW of nuclear capacity by the end of this decade, generating roughly the same annual output as our entire current wind power capacity. There are some who are already working to make that happen, either openly or more subtly. In that context the story on MSNBC yesterday listing US nuclear reactors in order of earthquake risk was either a public service or fear-mongering, depending on your perspective.
Whether we back away from nuclear power all at once, as Germany seems poised to consider doing, or one plant at a time, the result would be much the same: increased emissions, costlier and less reliable power, at least in the near-to-medium term, and more strain on infrastructure. I still think we'll choose to include nuclear in our evolving future energy mix, particularly given the significant improvements in the technology since the Fukushima reactors were built, along with the development of new, smaller-scale nuclear power options. Yet I have to admit my confidence in that result has been shaken by the reaction to the events in Japan.
Tuesday, March 15, 2011
Energy in the Aftermath of the Sendai Quake
Investors and companies around the world are scrambling to assess the impact of the Sendai earthquake and tsunami on supply chains and markets, both within Japan and globally, between the direct damage from the event and the disruption to critical infrastructure in its aftermath. An item I spotted in this morning's Wall St. Journal provided an early clue concerning the potential ripple effects in global energy markets, as Chevron sold a cargo of Indonesian crude to a power customer south of Tokyo. However, it remains to be seen whether demand destruction or the impairment of supply capabilities will dominate over the short, medium and longer-term recovery periods.
The impact on the Japanese power grid extends beyond the shutdown of 9,702 MW of nuclear power capacity, including 2,812 MW at Fukushima Daiichi that will not resume operations for many years, if ever. Some fossil fuel power plants have also shut down, and more than a fourth of the country's refining capacity is down, cutting off a significant supply of power plant fuel oil, along with a wide range of other petroleum products. That helps explain the interest in light, sweet Indonesian crude that can be burned directly in power plants as a replacement for low-sulfur fuel oil. Significant quantities of Indonesian Minas crude formerly came to the US west coast for a similar purpose, when we still had a lot of oil-fired power generation, although the crude was normally processed to remove the valuable light products from the fuel oil before sale to utilities. (My first job in the industry was at a refinery that did just that as part of a contract Texaco had with a southern California utility.)
Burning crude oil for power is a practical stop-gap, and as long as so many of Japan's refineries remain shut for damage assessment and repair, it shouldn't have much impact on the global crude market, since the crude those refineries would have otherwise run is now surplus. That explains the $5 per barrel drop in crude prices this week. However, if demand recovers faster than Japanese refinery capacity returns to operation, much of that extra crude oil will need to be processed in refineries elsewhere around the Asia-Pacific region, to provide the refined product imports that Japan will need.
It's much harder to assess the medium-term situation, because it will be some time before the full extent of the damage to industry, power generation and transportation is known. If more demand was destroyed than the capacity to supply it, then Japan could actually end up with surplus energy capacity until demand recovers, and that would be a bearish factor in global energy markets. If more energy supply than demand was destroyed, as seems possible given the largely agrarian nature of the part of Japan that suffered the worst consequences of the quake and tsunami, then Japan could be importing additional supplies of energy from regional sources for a long time.
I've had several people ask me about the potential of these events to increase Japan's demand for renewable energy, and I think that's a likely outcome. As of the end of 2009 Japan already had the world's third-largest installed solar power capacity at 2,600 MW, to which another 1,000 MW or so was apparently added last year. For Japanese businesses suffering from rolling brownouts, solar power is one of their few options other than diesel generators for becoming more self-sufficient fairly quickly. However, at the scale of the grid, intermittent solar isn't a great substitute for 24/7 nuclear power. With Japan's average solar insolation, it would take about 5,000 MW of solar panels to replace the annual output of a just one of the Fukushima Daiichi reactors (#2, 3 or 4) at an installed cost in the neighborhood of more than $20 billion. That might give a welcome shot in the arm to photovoltaic manufacturers that are still expanding rapidly but have been overly-dependent on faltering European solar incentives. I don't know enough about the Japanese grid to know how easily they could adjust to such a shift from centralized, baseload power to distributed, cyclical generation.
The long-term outcome seems impossible to gauge at this point, and I hesitate to even speculate while the engineers are still working to cool down the damaged nuclear plants. (The American Nuclear Society has a useful site with updates and background on the Japanese reactors.) Much depends on how well Japan's nuclear industry will be seen to have responded to these incidents. Unless these facilities are either rebuilt or replaced with new, next-generation nuclear plants, then Japan's imports of LNG, coal and other fuels could increase significantly, until and unless renewables ramped up enough to make up the difference. Japan is already the world's largest importer of LNG, and it is perfectly situated to absorb the output of the new LNG plants planned for Australia. That could boost global LNG prices for years to come.
Disclosure: My portfolio includes investment in Chevron, which is mentioned above and owns projects and facilities that could be affected by these events.
The impact on the Japanese power grid extends beyond the shutdown of 9,702 MW of nuclear power capacity, including 2,812 MW at Fukushima Daiichi that will not resume operations for many years, if ever. Some fossil fuel power plants have also shut down, and more than a fourth of the country's refining capacity is down, cutting off a significant supply of power plant fuel oil, along with a wide range of other petroleum products. That helps explain the interest in light, sweet Indonesian crude that can be burned directly in power plants as a replacement for low-sulfur fuel oil. Significant quantities of Indonesian Minas crude formerly came to the US west coast for a similar purpose, when we still had a lot of oil-fired power generation, although the crude was normally processed to remove the valuable light products from the fuel oil before sale to utilities. (My first job in the industry was at a refinery that did just that as part of a contract Texaco had with a southern California utility.)
Burning crude oil for power is a practical stop-gap, and as long as so many of Japan's refineries remain shut for damage assessment and repair, it shouldn't have much impact on the global crude market, since the crude those refineries would have otherwise run is now surplus. That explains the $5 per barrel drop in crude prices this week. However, if demand recovers faster than Japanese refinery capacity returns to operation, much of that extra crude oil will need to be processed in refineries elsewhere around the Asia-Pacific region, to provide the refined product imports that Japan will need.
It's much harder to assess the medium-term situation, because it will be some time before the full extent of the damage to industry, power generation and transportation is known. If more demand was destroyed than the capacity to supply it, then Japan could actually end up with surplus energy capacity until demand recovers, and that would be a bearish factor in global energy markets. If more energy supply than demand was destroyed, as seems possible given the largely agrarian nature of the part of Japan that suffered the worst consequences of the quake and tsunami, then Japan could be importing additional supplies of energy from regional sources for a long time.
I've had several people ask me about the potential of these events to increase Japan's demand for renewable energy, and I think that's a likely outcome. As of the end of 2009 Japan already had the world's third-largest installed solar power capacity at 2,600 MW, to which another 1,000 MW or so was apparently added last year. For Japanese businesses suffering from rolling brownouts, solar power is one of their few options other than diesel generators for becoming more self-sufficient fairly quickly. However, at the scale of the grid, intermittent solar isn't a great substitute for 24/7 nuclear power. With Japan's average solar insolation, it would take about 5,000 MW of solar panels to replace the annual output of a just one of the Fukushima Daiichi reactors (#2, 3 or 4) at an installed cost in the neighborhood of more than $20 billion. That might give a welcome shot in the arm to photovoltaic manufacturers that are still expanding rapidly but have been overly-dependent on faltering European solar incentives. I don't know enough about the Japanese grid to know how easily they could adjust to such a shift from centralized, baseload power to distributed, cyclical generation.
The long-term outcome seems impossible to gauge at this point, and I hesitate to even speculate while the engineers are still working to cool down the damaged nuclear plants. (The American Nuclear Society has a useful site with updates and background on the Japanese reactors.) Much depends on how well Japan's nuclear industry will be seen to have responded to these incidents. Unless these facilities are either rebuilt or replaced with new, next-generation nuclear plants, then Japan's imports of LNG, coal and other fuels could increase significantly, until and unless renewables ramped up enough to make up the difference. Japan is already the world's largest importer of LNG, and it is perfectly situated to absorb the output of the new LNG plants planned for Australia. That could boost global LNG prices for years to come.
Disclosure: My portfolio includes investment in Chevron, which is mentioned above and owns projects and facilities that could be affected by these events.
Monday, March 14, 2011
Press Conference Confusion
After listening to the energy portions of the presidential press conference last Friday, I found myself confused about the administration's approach to energy. Although I heard the President defending certain US energy policies, they weren't mainly those of his administration, nor were many of the outcomes he highlighted the result of actions he has taken. What's odd about that is that this administration has pursued as clear a set of energy policies, explicit and implicit, as any administration in recent memory; they just happen to be focused on a very different set of goals than attempting "to boost domestic production of oil and gas". And while I haven't agreed with all of them, his administration's actual policies concerning energy are certainly defensible in the context of putting the highest national priority on concerns about climate change. Before looking at this in more detail, I want to share a few thoughts on the aftermath of the quake and tsunami in Japan.
Having spent many years in earthquake country, I have deep sympathy for what the people of northeastern Japan are experiencing. The cleanup and recovery will take years, and the tectonic and emotional aftershocks will persist for a long time. The aftershocks for energy are more difficult to assess. It seems premature to draw conclusions about the impact on Japan's nuclear reactor fleet and the future of the global nuclear power industry. However, if the damage to several reactors is as bad as reports suggest, then the Japanese power grid must make up for the lost generation using either spare capacity at fossil fuel plants or with new technology. That could affect global fuel markets and the global demand for quickly-deployed generation, including both photovoltaic power and conventional small generators. At the same time, the extent of disruption the quake has caused to the global supply chains for such technologies is not yet clear. I'll be watching for discernible trends on these concerns in the weeks and months ahead.
Now back to the press conference. Two years into this administration, it has a track record on energy. The President campaigned on a platform of refocusing the government's energy efforts on renewables and energy efficiency, and he has followed through on that. The stimulus bill enacted in February 2009 included nearly $17 billion for those areas and not a penny for oil and gas. The administration's latest budget proposes slashing funding for R&D on fossil energy technology and ending tax incentives for domestic oil and gas production, using the savings to increase support for renewables and efficiency, consistent with his State of the Union remarks about investing in tomorrow's energy instead of "yesterday's". The President also supported comprehensive energy legislation, the explicit purpose of which was to make energy derived from fossil fuels--especially oil--more expensive. Although I have disagreed with many of these measures because I thought they took too little cognizance of the realities of the energy sector that supports our economy and the length of time a transition to cleaner energy entails, there was at least an admirable--and defensible--consistency to them. I would not have expected the President to tack away from defending these policies the first time oil and gasoline prices seriously spiked since his inauguration.
Then there's the matter of appearing to take credit for the recent recovery in US oil production by citing it twice in his remarks. The increase is real enough, though most experts, including the administration's own Department of Energy expect it to be short-lived, as the lagged effects of the post-Deepwater Horizon deepwater drilling moratorium work their way through the system. In fact, lags are the key to the whole question. If you have had experience with large projects, and particularly oil projects, then you realize that it typically takes a lot longer than two years for them to go through all the stages from inception to first production, including leasing, exploration, permitting, procurement and construction. The last time I looked at this in detail for oil the average time lag involved was around 7 years.
What was happening seven or eight years ago? Well, oil prices were in the early stages of the long climb that peaked in July 2008 at $144. It's no coincidence that a wave of new projects should have been coming onstream over the last couple of years, because the attractiveness of investing in them increased tremendously when prices broke out of their long-standing $20-30 per barrel price range. Yet it can be no more than a coincidence that the resulting increase in production should appear during an administration that has put in place policies restricting access to oil & gas development, delaying permits, and in some cases rescinding previously awarded leases.
The President's statement about undeveloped oil leases is a further reflection of how short his administration is on staff with industry experience. Companies don't lease these tracts with the intention of letting them sit idle. Instead, they continually prioritize their drilling prospects and pursue the best ones first, adding new leases to their inventory when they appear to have higher potential than those in their backlog. This process benefits taxpayers as well as the companies involved by helping to maximize the production on which royalties are paid and displacing more imports. And in the meantime, the Department of Interior continues to collect rental payments on any undeveloped leases, having already pocketed the bid bonuses on the basis of which they were awarded in the first place.
President Obama isn't the first politician to take credit for the results of actions taken in another administration. Considering the blame presidents often receive for events over which they likewise had little control or responsibility, it might even be understandable. Still, I can't help being surprised when the leader of an administration that has focused 90% of its energy efforts on resources and technologies that account for about 5% of our energy consumption and treated oil and gas as a legacy of a previous, less enlightened era suddenly embraces rising oil output. Whatever the reason, the change is welcome. And he has certainly learned the lesson of not being overly specific in explaining the circumstances under which the Strategic Petroleum Reserve would be tapped. All that's needed now is a shift of emphasis to recognize both the large potential of the renewable energy technologies in which we are investing and the enormous contribution of the domestic oil and gas that supply 37% of our energy needs and can do even more in the medium term, under the right policies.
Having spent many years in earthquake country, I have deep sympathy for what the people of northeastern Japan are experiencing. The cleanup and recovery will take years, and the tectonic and emotional aftershocks will persist for a long time. The aftershocks for energy are more difficult to assess. It seems premature to draw conclusions about the impact on Japan's nuclear reactor fleet and the future of the global nuclear power industry. However, if the damage to several reactors is as bad as reports suggest, then the Japanese power grid must make up for the lost generation using either spare capacity at fossil fuel plants or with new technology. That could affect global fuel markets and the global demand for quickly-deployed generation, including both photovoltaic power and conventional small generators. At the same time, the extent of disruption the quake has caused to the global supply chains for such technologies is not yet clear. I'll be watching for discernible trends on these concerns in the weeks and months ahead.
Now back to the press conference. Two years into this administration, it has a track record on energy. The President campaigned on a platform of refocusing the government's energy efforts on renewables and energy efficiency, and he has followed through on that. The stimulus bill enacted in February 2009 included nearly $17 billion for those areas and not a penny for oil and gas. The administration's latest budget proposes slashing funding for R&D on fossil energy technology and ending tax incentives for domestic oil and gas production, using the savings to increase support for renewables and efficiency, consistent with his State of the Union remarks about investing in tomorrow's energy instead of "yesterday's". The President also supported comprehensive energy legislation, the explicit purpose of which was to make energy derived from fossil fuels--especially oil--more expensive. Although I have disagreed with many of these measures because I thought they took too little cognizance of the realities of the energy sector that supports our economy and the length of time a transition to cleaner energy entails, there was at least an admirable--and defensible--consistency to them. I would not have expected the President to tack away from defending these policies the first time oil and gasoline prices seriously spiked since his inauguration.
Then there's the matter of appearing to take credit for the recent recovery in US oil production by citing it twice in his remarks. The increase is real enough, though most experts, including the administration's own Department of Energy expect it to be short-lived, as the lagged effects of the post-Deepwater Horizon deepwater drilling moratorium work their way through the system. In fact, lags are the key to the whole question. If you have had experience with large projects, and particularly oil projects, then you realize that it typically takes a lot longer than two years for them to go through all the stages from inception to first production, including leasing, exploration, permitting, procurement and construction. The last time I looked at this in detail for oil the average time lag involved was around 7 years.
What was happening seven or eight years ago? Well, oil prices were in the early stages of the long climb that peaked in July 2008 at $144. It's no coincidence that a wave of new projects should have been coming onstream over the last couple of years, because the attractiveness of investing in them increased tremendously when prices broke out of their long-standing $20-30 per barrel price range. Yet it can be no more than a coincidence that the resulting increase in production should appear during an administration that has put in place policies restricting access to oil & gas development, delaying permits, and in some cases rescinding previously awarded leases.
The President's statement about undeveloped oil leases is a further reflection of how short his administration is on staff with industry experience. Companies don't lease these tracts with the intention of letting them sit idle. Instead, they continually prioritize their drilling prospects and pursue the best ones first, adding new leases to their inventory when they appear to have higher potential than those in their backlog. This process benefits taxpayers as well as the companies involved by helping to maximize the production on which royalties are paid and displacing more imports. And in the meantime, the Department of Interior continues to collect rental payments on any undeveloped leases, having already pocketed the bid bonuses on the basis of which they were awarded in the first place.
President Obama isn't the first politician to take credit for the results of actions taken in another administration. Considering the blame presidents often receive for events over which they likewise had little control or responsibility, it might even be understandable. Still, I can't help being surprised when the leader of an administration that has focused 90% of its energy efforts on resources and technologies that account for about 5% of our energy consumption and treated oil and gas as a legacy of a previous, less enlightened era suddenly embraces rising oil output. Whatever the reason, the change is welcome. And he has certainly learned the lesson of not being overly specific in explaining the circumstances under which the Strategic Petroleum Reserve would be tapped. All that's needed now is a shift of emphasis to recognize both the large potential of the renewable energy technologies in which we are investing and the enormous contribution of the domestic oil and gas that supply 37% of our energy needs and can do even more in the medium term, under the right policies.
Friday, March 11, 2011
Early Daylight Savings, Again
This is by way of a pet peeve, but for the benefit of any of my readers who are as annoyed as I am to be starting Daylight Savings Time three weeks early again this year I'm reprinting a portion of my posting from 2007, when the practice was introduced. It's also interesting to see that the US is very much an outlier in this regard, with most countries that change their clocks doing so on March 27 this year. For me, early DST highlights the fecklessness of much of our current energy policy, devoted more to appearances than outcomes. Here's what I said in '07, with some minor updates:
It was interesting to hear the Congressional sponsor of this change suggest a few days ago that, aside from the other expected results of DST, it "brings a smile to everybody's faces." I wonder how many of us will be smiling when we learn that the energy savings that prompted this measure are likely to be illusory--if not actually negative--based on a study of the time change's effects in Australia. (Other studies reflect mixed results.) As much as anything else, this exercise serves as a useful reminder of the questionable benefits of adopting 1970s-style energy policies in the 21st century.
I am sure that when the extended DST was imposed during the first energy crisis of 1973-74, it saved significant quantities of energy. But it's worth recalling just how different this country was, back then. In 1970, the US population was one-third smaller, and nearly 1 in 10 Americans worked in manufacturing, compared to about 1 in 27 now. Only 40% of women were employed outside the home, compared to 58% in 2011. Today, large numbers of Americans of both sexes work "24/7" jobs that start earlier and end later, and our leisure activities are likely to be at least as energy-intensive as anything we do at the office. It's not intuitively obvious that adding an extra hour of sunlight for a few more weeks in March and October will materially change our consumption of oil, gas, or electricity.
In the near term--barring enormous public outcry--there's probably no going back to a shorter DST, even if it becomes clear that its extension was a mistake. Reverting to the earlier schedule would require yet another round of computer system patches to replace the timetable that was just updated, and result in further confusion. In the long run, however, we need energy policies tailored to how Americans live and work now, rather than to the way our parents did. And for the future, it's possible to imagine a different, more flexible kind of DST, designed not to reduce consumption, but to align the daily peak in electricity demand with the output of solar power generation.
It was interesting to hear the Congressional sponsor of this change suggest a few days ago that, aside from the other expected results of DST, it "brings a smile to everybody's faces." I wonder how many of us will be smiling when we learn that the energy savings that prompted this measure are likely to be illusory--if not actually negative--based on a study of the time change's effects in Australia. (Other studies reflect mixed results.) As much as anything else, this exercise serves as a useful reminder of the questionable benefits of adopting 1970s-style energy policies in the 21st century.
I am sure that when the extended DST was imposed during the first energy crisis of 1973-74, it saved significant quantities of energy. But it's worth recalling just how different this country was, back then. In 1970, the US population was one-third smaller, and nearly 1 in 10 Americans worked in manufacturing, compared to about 1 in 27 now. Only 40% of women were employed outside the home, compared to 58% in 2011. Today, large numbers of Americans of both sexes work "24/7" jobs that start earlier and end later, and our leisure activities are likely to be at least as energy-intensive as anything we do at the office. It's not intuitively obvious that adding an extra hour of sunlight for a few more weeks in March and October will materially change our consumption of oil, gas, or electricity.
In the near term--barring enormous public outcry--there's probably no going back to a shorter DST, even if it becomes clear that its extension was a mistake. Reverting to the earlier schedule would require yet another round of computer system patches to replace the timetable that was just updated, and result in further confusion. In the long run, however, we need energy policies tailored to how Americans live and work now, rather than to the way our parents did. And for the future, it's possible to imagine a different, more flexible kind of DST, designed not to reduce consumption, but to align the daily peak in electricity demand with the output of solar power generation.
Thursday, March 10, 2011
A Nuclear/Gas Alliance?
As I was scanning the news of the last few days I was intrigued by a headline featuring the CEO of the largest owner/operator of nuclear power plants in the US, Exelon Corp., extolling the virtues of natural gas and advocating an increase in its output. That might not sound earth-shattering, especially considering that Exelon also owns a fleet of natural gas-fired power plants with combined output equivalent to several nuclear reactors, unless you are convinced that nuclear and gas are engaged in a tooth-and-nail competition to supply America's future electricity needs. However, it's certainly attention-getting for Mr. Rowe, whose company recently acquired the substantial wind-generation business of John Deere, to go on record opposing clean-energy subsidies for a range of low-emission technologies.
The main message of Mr. Rowe's address at the American Enterprise Institute was apparently that Congress shouldn't interfere further with markets, regulations and technologies that he sees already being sufficient to reduce carbon emissions and clean up the air. Yet while I'm usually reluctant to read too much into remarks I wasn't present to hear, I do think it's possible to infer an alternative strategic dynamic to the nuclear vs. gas narrative that I have encountered in a number of blog postings in the last few years, particularly since shale gas production took off and the anticipated nuclear renaissance in the US encountered resistance. Because it's uncommon to hear CEOs touting their competition, I think it's safe to conclude that Exelon views nuclear and gas as complementary--a view I share--rather than competing for the same segment of the market.
It also sounds like Mr. Rowe sees gas and nuclear competing with coal, which makes eminent sense in the context of environmental policy and typical grid power-dispatch curves. Competition between nuclear and coal was especially obvious when both were viewed as enhancing energy security and before concerns about greenhouse gas emissions had become mainstream. And as recently as a few years ago, when most forecasts anticipated declining US gas production and rapidly increasing imports of LNG, yielding even more volatile natural gas prices, coal-fired power plants were the principal large-scale alternative to both new nuclear and gas-fired capacity. Today's emphasis on emissions, combined with next-generation reactor technology, gives nuclear an edge over coal in baseload for locations where communities are comfortable with the technology, while gas has a more than a 2:1 lead over coal in planned new generating capacity and seems likely to do even better in terms of capacity actually built, due to its substantial lifecycle environmental advantages.
It's also possible to envision a future grid relying mainly on nuclear for baseload power and natural gas for flexible power, without the need for any coal generation at all. Moreover, with the addition of smart grid technology and new long-distance transmission, that combination should provide a very hospitable environment for much larger increments of renewable energy. Gas-fired backup power remains the best enabler for incorporating intermittent generation from wind and solar power, particularly when these technologies are combined in installations such as Florida Power & Light's new hybrid solar/gas power plant in southeast Florida. That seems like a much more realistic approach than the notion of an all-renewable grid based on energy storage, even if storage technology were to become more effective and much cheaper. (Storage has a key role to play in the future grid, but I believe it will be used mainly for short-term buffering and for storing the cheapest off-peak power from any source, rather than as dedicated storage for renewable power.)
The biggest potential obstacle to this scenario is growth, or the lack of it. In a US electricity market that is barely growing at all, in contrast to the steady 2% or so per year expansion in demand from 1997-2007, and with renewables given the first shot at satisfying any growth in a majority of states, the only opportunity that looks big enough for both nuclear and gas-fired power to cooperate on is coal displacement. Yet if you agree with Mr. Rowe that "carbon legislation is dead", it's a lot less certain that coal would go away fast enough for the combination of gas and nuclear he is promoting to become the de facto future. It remains to be seen whether the market, together with an increased emphasis on local pollutants--excluding CO2--under the Clean Air Act will be sufficient to squeeze out a coal industry that, along with its numerous stakeholders, will not depart without a fight.
The main message of Mr. Rowe's address at the American Enterprise Institute was apparently that Congress shouldn't interfere further with markets, regulations and technologies that he sees already being sufficient to reduce carbon emissions and clean up the air. Yet while I'm usually reluctant to read too much into remarks I wasn't present to hear, I do think it's possible to infer an alternative strategic dynamic to the nuclear vs. gas narrative that I have encountered in a number of blog postings in the last few years, particularly since shale gas production took off and the anticipated nuclear renaissance in the US encountered resistance. Because it's uncommon to hear CEOs touting their competition, I think it's safe to conclude that Exelon views nuclear and gas as complementary--a view I share--rather than competing for the same segment of the market.
It also sounds like Mr. Rowe sees gas and nuclear competing with coal, which makes eminent sense in the context of environmental policy and typical grid power-dispatch curves. Competition between nuclear and coal was especially obvious when both were viewed as enhancing energy security and before concerns about greenhouse gas emissions had become mainstream. And as recently as a few years ago, when most forecasts anticipated declining US gas production and rapidly increasing imports of LNG, yielding even more volatile natural gas prices, coal-fired power plants were the principal large-scale alternative to both new nuclear and gas-fired capacity. Today's emphasis on emissions, combined with next-generation reactor technology, gives nuclear an edge over coal in baseload for locations where communities are comfortable with the technology, while gas has a more than a 2:1 lead over coal in planned new generating capacity and seems likely to do even better in terms of capacity actually built, due to its substantial lifecycle environmental advantages.
It's also possible to envision a future grid relying mainly on nuclear for baseload power and natural gas for flexible power, without the need for any coal generation at all. Moreover, with the addition of smart grid technology and new long-distance transmission, that combination should provide a very hospitable environment for much larger increments of renewable energy. Gas-fired backup power remains the best enabler for incorporating intermittent generation from wind and solar power, particularly when these technologies are combined in installations such as Florida Power & Light's new hybrid solar/gas power plant in southeast Florida. That seems like a much more realistic approach than the notion of an all-renewable grid based on energy storage, even if storage technology were to become more effective and much cheaper. (Storage has a key role to play in the future grid, but I believe it will be used mainly for short-term buffering and for storing the cheapest off-peak power from any source, rather than as dedicated storage for renewable power.)
The biggest potential obstacle to this scenario is growth, or the lack of it. In a US electricity market that is barely growing at all, in contrast to the steady 2% or so per year expansion in demand from 1997-2007, and with renewables given the first shot at satisfying any growth in a majority of states, the only opportunity that looks big enough for both nuclear and gas-fired power to cooperate on is coal displacement. Yet if you agree with Mr. Rowe that "carbon legislation is dead", it's a lot less certain that coal would go away fast enough for the combination of gas and nuclear he is promoting to become the de facto future. It remains to be seen whether the market, together with an increased emphasis on local pollutants--excluding CO2--under the Clean Air Act will be sufficient to squeeze out a coal industry that, along with its numerous stakeholders, will not depart without a fight.
Tuesday, March 08, 2011
Arguing With the Numbers
Over the weekend I read a remark in one of the Wall St. Journal's political columns that resonated with an implicit theme of this blog since its inception in early 2004. In her discussion of the budget crises facing various states and the debates concerning how to resolve them, Peggy Noonan highlighted the benefits of focusing on the numbers involved. "It doesn't matter if you're a liberal or a conservative, it's all about the numbers, and numbers are sobering things." Our national debate on energy would be much more productive if that same rationale were applied to it. That's happening more than it used to, perhaps because blogs are making some of the numbers more accessible, but an example in Monday's Journal reminded me just how far we still have to go in this regard.
In a supplement providing highlights from the Journal's annual "ECO-nomics" session in Santa Barbara, I saw a reference to a discussion of Brazil's sugarcane ethanol model and the merits of trying to apply something like that here, either on a domestic basis or by importing more cane ethanol. Brazil is widely credited for its vision of fueling its cars from domestic renewable sources, largely in response to the oil shocks of the 1970s. As hard as those were on the developed world, they were even more disruptive for developing economies. Today, Brazil consumes more ethanol than gasoline, because so many cars in Brazil run on either pure ethanol or a blend with a much higher proportion of alcohol than the standard US 10% blend. Who could fail to find this attractive, conceptually?
When we look at the actual numbers involved, however, we see Brazil's cane ethanol and its flexible fuel vehicle fleet in a somewhat different light, in terms of providing a model for the US. Start with the number of cars in the country, comprising around 26 million in a nation of 194 million, or 2/3rds the population of the US. By contrast, the US has more cars and light trucks than there are Brazilians. Next compare Brazil's total ethanol output to US gasoline consumption. With Brazil's annual ethanol yield approaching 7 billion gallons, and factoring in ethanol's lower energy content, the US would need roughly 27 Brazils worth of cane ethanol to fuel our car fleet, after subtracting the 13 billion gallons of corn ethanol we produce domestically, and ignoring logistical and fleet modification issues.
So without trivializing the important question of whether to continue to impose a tariff on Brazilian ethanol imported into the US, or taking anything away from the tremendous biomass conversion inherent in sugar cane grown in the tropics and processed in efficient facilities that make use of essentially every part of the cane plant to produce ethanol, sugar and a modest surplus of electric power, it's hard to see that we could encourage Brazil to ramp up its output enough to displace all the gasoline attributable to imported oil, or gear up US cropland in Florida and Louisiana to produce the equivalent. That conclusion couldn't be gleaned from purely conceptual arguments without the numbers.
This isn't intended as a slam on the Journal's conference or other high-concept confabs--I have attended many, myself, and found them very stimulating--or on Brazil's sugar/ethanol industry. It just seems that if our fiscal problems have finally reached the level of concern at which serious conversations must be grounded in the numbers, then energy deserves no less. And while I recognize that many of the numbers involved are daunting, there are many resources available to make them more accessible. That includes the recently revamped public website of the Energy Information Agency of the US Department of Energy. Although the update to EIA.gov has unfortunately blown up numerous embedded links in my past postings, the result seems to be more user-friendly.
Tomorrow I'll be participating in a webinar examining the energy implications of the unfolding revolutions in North Africa and the Middle East at The Energy Collective. Click here for more information and to register.
In a supplement providing highlights from the Journal's annual "ECO-nomics" session in Santa Barbara, I saw a reference to a discussion of Brazil's sugarcane ethanol model and the merits of trying to apply something like that here, either on a domestic basis or by importing more cane ethanol. Brazil is widely credited for its vision of fueling its cars from domestic renewable sources, largely in response to the oil shocks of the 1970s. As hard as those were on the developed world, they were even more disruptive for developing economies. Today, Brazil consumes more ethanol than gasoline, because so many cars in Brazil run on either pure ethanol or a blend with a much higher proportion of alcohol than the standard US 10% blend. Who could fail to find this attractive, conceptually?
When we look at the actual numbers involved, however, we see Brazil's cane ethanol and its flexible fuel vehicle fleet in a somewhat different light, in terms of providing a model for the US. Start with the number of cars in the country, comprising around 26 million in a nation of 194 million, or 2/3rds the population of the US. By contrast, the US has more cars and light trucks than there are Brazilians. Next compare Brazil's total ethanol output to US gasoline consumption. With Brazil's annual ethanol yield approaching 7 billion gallons, and factoring in ethanol's lower energy content, the US would need roughly 27 Brazils worth of cane ethanol to fuel our car fleet, after subtracting the 13 billion gallons of corn ethanol we produce domestically, and ignoring logistical and fleet modification issues.
So without trivializing the important question of whether to continue to impose a tariff on Brazilian ethanol imported into the US, or taking anything away from the tremendous biomass conversion inherent in sugar cane grown in the tropics and processed in efficient facilities that make use of essentially every part of the cane plant to produce ethanol, sugar and a modest surplus of electric power, it's hard to see that we could encourage Brazil to ramp up its output enough to displace all the gasoline attributable to imported oil, or gear up US cropland in Florida and Louisiana to produce the equivalent. That conclusion couldn't be gleaned from purely conceptual arguments without the numbers.
This isn't intended as a slam on the Journal's conference or other high-concept confabs--I have attended many, myself, and found them very stimulating--or on Brazil's sugar/ethanol industry. It just seems that if our fiscal problems have finally reached the level of concern at which serious conversations must be grounded in the numbers, then energy deserves no less. And while I recognize that many of the numbers involved are daunting, there are many resources available to make them more accessible. That includes the recently revamped public website of the Energy Information Agency of the US Department of Energy. Although the update to EIA.gov has unfortunately blown up numerous embedded links in my past postings, the result seems to be more user-friendly.
Tomorrow I'll be participating in a webinar examining the energy implications of the unfolding revolutions in North Africa and the Middle East at The Energy Collective. Click here for more information and to register.
Thursday, March 03, 2011
Could Competition and Low Demand Stall Wind Power's Growth?
In the last week I've seen reports that two of the biggest wind power developers in the world, Spain's Iberdrola Renovables and Portugal's EDP Renovaveis, plan to reduce their wind power investments in the US for at least the next couple of years. That's significant because these two firms together accounted for just under a third of the 5,115 MW of new wind turbines installed in the US last year. This isn't for lack of opportunities or incentives, but for some very old-fashioned reasons: low demand and competition from other energy sources. It's an important reminder that renewable energy can't just be viewed as a set of technologies; they are also businesses, and as such are subject to the normal ups and downs of the market. It also highlights the limitations of government incentives.
Wind power had been on a tear in the US as recently as 2009, when a record 10,010 MW of turbines were installed, extending an enviable 5-year run of 40% average annual growth in wind capacity. Last year that growth slowed to 15% as new installations fell by half. That occurred in spite of the federal stimulus program that converted tax credits for renewable energy projects into up-front cash grants, paying $ 3.5 billion to wind developers out of a total of $4.2 billion expended in 2010. Although eligibility for that benefit was due to expire on 12/31/10, it was subsequently extended through 2011 under December's "lame duck" tax legislation, largely on the strength of arguments that it would keep wind and other renewables growing at a brisk pace. What happened?
At least two major factors related to the business environment are weighing on wind development, as well as another factor unique to renewables. First, electricity demand that was depressed by the recession is apparently still at least 1% below pre-crisis levels. That doesn't sound like much, but the difference is roughly equivalent to the entire amount of electricity generated from wind power in 2008. As a result, utilities have become less keen to sign long-term offtake agreements, or "power purchase agreements" (PPAs), with new wind farms. Both EDP and Iberdrola cited this problem in reference to their 2011 plans.
Wind power also faces strong competition from cheap natural gas, as you've probably heard many times by now. Despite some resistance to shale drilling in states like New York, there's every indication that US gas output will continue to expand. Last year the US produced more natural gas than in any year since 1973, and the end of this boom is not in sight. Although advocates may claim that wind is now cost-competitive with gas, that remains a best-case analysis for locations with excellent wind resources and good access to transmission. Natural gas at $5 per million BTUs yields electricity at 5¢/kWh from a combined-cycle gas turbine. That sets a pretty tough bar for wind, especially when gas turbines can produce power on-demand, 24/7, while wind turbines generate power an average of 30% of the time, intermittently.
Unexpectedly, wind power may also be facing competition from solar power. In a recent interview the CEO of NRG Energy Inc., a large power generator, pointed to the greater opportunities for innovation in solar, compared to wind. The cost of installed photovoltaic modules, particularly in utility-scale applications, has fallen much faster in recent years than the cost of wind turbines. That's not to say that power from solar is cheaper than from wind, but solar is starting to look like a better investment for utilities, which have been signing PPAs with solar project developers in droves. It's also noteworthy that for the first time last year more solar power was installed in Europe than new wind power, by a healthy margin.
It's probably premature to conclude that the US wind boom has ended, and that wind capacity is now likely to grow at lower, more normal rates in the future, compared to its extraordinary past performance. This could just be a lull, as the enormous additions of the last few years are absorbed into a power grid that is still modernizing and remains a long way from the smart grid that will be needed to accommodate much larger contributions from intermittent renewables of all types. At the same time, it's worth noting that government incentives can't eliminate every obstacle that renewables face, and that arguments that the Treasury cash grants in lieu of tax credits should be extended beyond 2011 should be assessed with much more critical judgment than was possible in the scramble of a lame duck Congressional session.
Wind power had been on a tear in the US as recently as 2009, when a record 10,010 MW of turbines were installed, extending an enviable 5-year run of 40% average annual growth in wind capacity. Last year that growth slowed to 15% as new installations fell by half. That occurred in spite of the federal stimulus program that converted tax credits for renewable energy projects into up-front cash grants, paying $ 3.5 billion to wind developers out of a total of $4.2 billion expended in 2010. Although eligibility for that benefit was due to expire on 12/31/10, it was subsequently extended through 2011 under December's "lame duck" tax legislation, largely on the strength of arguments that it would keep wind and other renewables growing at a brisk pace. What happened?
At least two major factors related to the business environment are weighing on wind development, as well as another factor unique to renewables. First, electricity demand that was depressed by the recession is apparently still at least 1% below pre-crisis levels. That doesn't sound like much, but the difference is roughly equivalent to the entire amount of electricity generated from wind power in 2008. As a result, utilities have become less keen to sign long-term offtake agreements, or "power purchase agreements" (PPAs), with new wind farms. Both EDP and Iberdrola cited this problem in reference to their 2011 plans.
Wind power also faces strong competition from cheap natural gas, as you've probably heard many times by now. Despite some resistance to shale drilling in states like New York, there's every indication that US gas output will continue to expand. Last year the US produced more natural gas than in any year since 1973, and the end of this boom is not in sight. Although advocates may claim that wind is now cost-competitive with gas, that remains a best-case analysis for locations with excellent wind resources and good access to transmission. Natural gas at $5 per million BTUs yields electricity at 5¢/kWh from a combined-cycle gas turbine. That sets a pretty tough bar for wind, especially when gas turbines can produce power on-demand, 24/7, while wind turbines generate power an average of 30% of the time, intermittently.
Unexpectedly, wind power may also be facing competition from solar power. In a recent interview the CEO of NRG Energy Inc., a large power generator, pointed to the greater opportunities for innovation in solar, compared to wind. The cost of installed photovoltaic modules, particularly in utility-scale applications, has fallen much faster in recent years than the cost of wind turbines. That's not to say that power from solar is cheaper than from wind, but solar is starting to look like a better investment for utilities, which have been signing PPAs with solar project developers in droves. It's also noteworthy that for the first time last year more solar power was installed in Europe than new wind power, by a healthy margin.
It's probably premature to conclude that the US wind boom has ended, and that wind capacity is now likely to grow at lower, more normal rates in the future, compared to its extraordinary past performance. This could just be a lull, as the enormous additions of the last few years are absorbed into a power grid that is still modernizing and remains a long way from the smart grid that will be needed to accommodate much larger contributions from intermittent renewables of all types. At the same time, it's worth noting that government incentives can't eliminate every obstacle that renewables face, and that arguments that the Treasury cash grants in lieu of tax credits should be extended beyond 2011 should be assessed with much more critical judgment than was possible in the scramble of a lame duck Congressional session.
Tuesday, March 01, 2011
Will $100 Oil Help Renewables?
Last week I read a blog posting discussing the prospects for First Solar, a leading US-based producer of photovoltaic modules. Among other rationales for the firm's continued growth the author mentioned $100 oil. I can't find the link, and I don't mean to pick on that particular blog, because the view it expressed merely reflects the conventional wisdom that low oil prices held back the growth of renewables in the past, so high oil prices must be good for them. However, the underlying logic of this argument has been eroded by the changes of the last several decades, with the important exception of its lingering influence on government policy and public perception.
The problem starts with the notion of renewable energy as a replacement for oil. Other than biofuels like ethanol, most renewable energy technologies including wind, solar, and geothermal power generate electricity. In the US and most other developed countries, oil is no longer a major source of electricity. Between 1973, the year of the first oil crisis, and 2009 the share of petroleum and its products in electricity generation in the US declined from 17% to less than 1%, with much of the current remainder consisting of back-up power and generation at remote sites. That change happened pretty quietly, as oil was replaced by nuclear, coal and especially natural gas. The latter is important because the prices of oil and natural gas were historically linked, both by the ability of some customers to switch from one fuel to the other as prices shifted, and by the production of much US gas from oil fields. So when oil prices went up, gas followed and so did electricity prices.
One of the most remarkable developments in energy markets in the last few years has been the disconnection of US natural gas prices from oil prices, due in large part to rising shale gas production. From 1995-2005 the front-month natural gas contract on the New York Mercantile Exchange traded at an average of 80% of the futures price of West Texas Intermediate crude oil, on an energy-equivalent basis. But from 2006-2010 natural gas averaged just 49% of the oil price, while the average so far this year is a mere 28%. So when oil prices go up today, gas prices don't follow, nor should electricity prices. That means that higher oil prices no longer make electricity from renewable sources more competitive, in the way they formerly did.
Nor does much substitution between oil and electricity happen from the other direction, despite our renewed enthusiasm about electric cars. As of 2009, transportation accounted for 29% of total US energy consumption, yet only 0.3% of the energy used in transportation was in the form of electricity, including transmission and other losses, compared to 94% for petroleum products. So increasing the quantity of electricity generated from renewable sources won't mean noticeably less oil consumption, at least until there are many millions of electric vehicles on the road.
Then there's the phenomenon of "receding horizons" that became apparent as oil prices ran up from 2004-8. As the basic technology cost of renewable electricity generation from wind turbines and solar modules fell with wider deployment and continued R&D, the proportion of their installed cost attributable to raw materials, energy inputs, and construction costs rose. As oil prices went up, the cost of many of those inputs increased--just as we saw for the inputs to biofuels production--and construction costs went up due to competition with construction in other sectors, including mining and oil & gas exploration and production. That dynamic helps explain why renewables didn't instantly become cost-competitive when oil hit $145/bbl in 2008.
Even if the basis of the old conventional wisdom about high oil prices being good for renewables has faded, it's not entirely bad news for renewables, because energy policy has also become disconnected from oil prices. Energy policy is now driven more by concerns about climate change, green jobs and notions of energy independence than by any actual linkage between renewables and the uses of oil in our economy. High oil prices may ratchet up the political rhetoric in support of these policies, but they don't seem to result in the kind of practical actions that could directly address our most serious energy security concerns, which stem from our ongoing reliance on oil imports and have little or nothing to do with renewable electricity.
Wind and solar are also becoming more competitive in their own right, and manufacturers like First Solar see the necessity of being able to compete not just with conventional energy sources, but also without subsidies that look increasingly unsustainable in the fiscal environment that is likely to prevail for the foreseeable future. So even as sustained high oil prices would likely increase support for expanding renewables, they could also hasten the day when they must stand on their own.
The problem starts with the notion of renewable energy as a replacement for oil. Other than biofuels like ethanol, most renewable energy technologies including wind, solar, and geothermal power generate electricity. In the US and most other developed countries, oil is no longer a major source of electricity. Between 1973, the year of the first oil crisis, and 2009 the share of petroleum and its products in electricity generation in the US declined from 17% to less than 1%, with much of the current remainder consisting of back-up power and generation at remote sites. That change happened pretty quietly, as oil was replaced by nuclear, coal and especially natural gas. The latter is important because the prices of oil and natural gas were historically linked, both by the ability of some customers to switch from one fuel to the other as prices shifted, and by the production of much US gas from oil fields. So when oil prices went up, gas followed and so did electricity prices.
One of the most remarkable developments in energy markets in the last few years has been the disconnection of US natural gas prices from oil prices, due in large part to rising shale gas production. From 1995-2005 the front-month natural gas contract on the New York Mercantile Exchange traded at an average of 80% of the futures price of West Texas Intermediate crude oil, on an energy-equivalent basis. But from 2006-2010 natural gas averaged just 49% of the oil price, while the average so far this year is a mere 28%. So when oil prices go up today, gas prices don't follow, nor should electricity prices. That means that higher oil prices no longer make electricity from renewable sources more competitive, in the way they formerly did.
Nor does much substitution between oil and electricity happen from the other direction, despite our renewed enthusiasm about electric cars. As of 2009, transportation accounted for 29% of total US energy consumption, yet only 0.3% of the energy used in transportation was in the form of electricity, including transmission and other losses, compared to 94% for petroleum products. So increasing the quantity of electricity generated from renewable sources won't mean noticeably less oil consumption, at least until there are many millions of electric vehicles on the road.
Then there's the phenomenon of "receding horizons" that became apparent as oil prices ran up from 2004-8. As the basic technology cost of renewable electricity generation from wind turbines and solar modules fell with wider deployment and continued R&D, the proportion of their installed cost attributable to raw materials, energy inputs, and construction costs rose. As oil prices went up, the cost of many of those inputs increased--just as we saw for the inputs to biofuels production--and construction costs went up due to competition with construction in other sectors, including mining and oil & gas exploration and production. That dynamic helps explain why renewables didn't instantly become cost-competitive when oil hit $145/bbl in 2008.
Even if the basis of the old conventional wisdom about high oil prices being good for renewables has faded, it's not entirely bad news for renewables, because energy policy has also become disconnected from oil prices. Energy policy is now driven more by concerns about climate change, green jobs and notions of energy independence than by any actual linkage between renewables and the uses of oil in our economy. High oil prices may ratchet up the political rhetoric in support of these policies, but they don't seem to result in the kind of practical actions that could directly address our most serious energy security concerns, which stem from our ongoing reliance on oil imports and have little or nothing to do with renewable electricity.
Wind and solar are also becoming more competitive in their own right, and manufacturers like First Solar see the necessity of being able to compete not just with conventional energy sources, but also without subsidies that look increasingly unsustainable in the fiscal environment that is likely to prevail for the foreseeable future. So even as sustained high oil prices would likely increase support for expanding renewables, they could also hasten the day when they must stand on their own.
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