The mood going into this week's global climate conference in Cancun, Mexico is decidedly different than that for last year's session in Copenhagen, which had been intended to culminate the process begun two years earlier in Bali. It's not just that expectations for a comprehensive and binding global climate treaty have been dramatically lowered; much of the debate since Copenhagen has moved away from the notion that it's even possible to reduce emissions sufficiently to avert many of the adverse consequences of a warming and less stable climate. It's no coincidence that the cover story of this week's Economist is dedicated to the increased need for adaptation to climate change, while the lead op-ed in the energy pull-out section in today's Wall St. Journal highlights an agenda for making clean energy the cheapest kind--not by subsidizing it even more than we already are, but by driving innovation.
After describing the magnitude of the challenge involved in decarbonizing the global economy by enough, soon enough, to limit the increase in global average temperatures in this century to 2° C, The Economist concludes, "The fight to limit global warming to easily tolerated levels is thus over." That doesn't mean that agreements to bend the trajectory of emissions growth below the status quo trendline aren't worth pursuing, but it suggests that we need to devote much greater attention and resources to adapting to a world that will likely include more droughts, floods, famines, and human migration than we've had to deal with thus far, and for which both the drivers and consequences are being amplified by economic development and population growth. The Economist sees climate adaptation focused on three main areas: infrastructure, migration and food, and their analysis is worth reading.
Another factor I believe the magazine should have highlighted is the difficulty of undertaking any of these efforts at a time when the developed world is hobbled by weak economic growth and related deficit and debt problems that threaten to render even the current level of subsidies for renewable energy sources unsustainable. As the EU grapples with the debts of Greece and Ireland, with Portugal and Spain waiting in the wings, it's no accident that Spain has just cut its feed-in tariff for solar power, which had already been reduced from previously lavish levels. The elephant in the room in Cancun, as it was in Copenhagen, is that binding agreements requiring severe emissions reductions by and large transfer payments from the developed countries might have looked attainable when the economy was booming, but they have become much less feasible in the wake of the worst recession and financial crisis since the Great Depression.
That same fundamental challenge makes the innovation arguments raised by Ted Nordhaus and Michael Shellengerger of the Breakthrough Institute more urgent than they would be otherwise. Because today's renewable energy technologies remain more expensive without subsidies than coal, oil and natural gas--even when the consumption subsidies the latter receive are stripped away--the cost of replacing our existing, high-emitting energy sources with entirely green ones looks unaffordable in today's world. I would add that reliance on experience curve effects--building out a subsidized green energy economy and depending on volume to drive down its cost to the point of competitiveness--is unlikely close that gap, and where it can, there is no guarantee that the country providing the incentives will receive the benefits it is entitled to expect. To cite the most obvious current example, Germany has invested tens of billions of Euros subsidizing solar energy and has indeed created a globally competitive solar industry--mainly in developing Asia.
What makes Nordhaus and Shellenberger's suggestion seem much more practical than global climate treaties and mountains of green subsidies is that the money currently being spent on renewable energy deployment incentives, which constitute a small fraction of the total annual investment in energy infrastructure, would go much farther buying R&D, rather than hardware. The US investment tax credit paid to a single 100 MW wind farm could fund an entire university energy innovation laboratory and graduate degree program.
Of course none of these strategies should be regarded as entirely either/or propositions. Adaptation doesn't let us off the hook for trying to address the causes of climate change, nor does shifting more of government's limited resources into clean energy R&D mean we don't need any of the real-world learnings that only come from deploying technology and seeing how it works under uncontrolled conditions. There's also a parallel role for research into geoengineering to provide a backstop--a potential Hail Mary pass--should all of these other efforts fall short and climate change move beyond a range we can live with. If nothing else, the COP 16 meeting in Cancun might shed more light on the degree to which the UN body is the right umbrella to cover all this work.
Tomorrow at 1:00 PM EST I'll be presenting in a webinar entitled, "Natural Gas: Sustainability Friend or Foe". To sign up follow this link.
Monday, November 29, 2010
Tuesday, November 23, 2010
Chicago's Climate Exchange Shuts Down
I see that the Chicago Climate Exchange (CCX) will be winding down its CO2 trading operations by the end of the year and laying off staff. This is only surprising considering that the parent company of the CCX was acquired just this summer by the Intercontinental Exchange, though mainly for its successful European emissions trading market. In case you were wondering how long the odds against enacting cap & trade legislation in the US have become, the demise of the CCX is a signpost you can't ignore. If the symbolism of a popular Democratic governor using the Waxman-Markey climate bill for target practice during his recent successful bid for the US Senate wasn't clear enough, it looks like his bullet may have also hit the CCX.
I recall a meeting with one of the founders of CCX at Texaco's corporate headquarters in New York prior to my leaving the company at the end of 2001. At that time, Texaco's management was coming around to the idea that sooner or later emissions of CO2 and other greenhouse gases would carry a price, for the first time in human history. Cap & trade offered a proven way to discover that price, based on the pioneering experience of US markets for sulfur dioxide, a cause of acid rain, and nitrogen oxides. The principles of emissions trading had been embedded in the Kyoto Protocol, largely thanks to the efforts of the US delegation, and European countries were setting up the precursors of the EU Emissions Trading System to manage mandatory carbon reductions. Such developments still appeared to be somewhere over the horizon in the US, which never ratified Kyoto, but they seemed likely to find their way here, eventually. One of the main selling points of the CCX, which was based on voluntary emission reduction commitments by member companies, was that it would provide valuable early experience in a formal market for emissions reductions, giving participants a leg up when such trading was required by law. This argument didn't persuade my former employer, but a number of other companies signed up.
If this scenario now seems like a quaint strand of alternate history--a "what if?" that never materialized--that perspective is quite recent. The prospects for CCX and wider emissions trading looked reasonable for a long time. The value of the CCX contract peaked in mid-2008, when it had become apparent that the ultimate presidential nominees of both major US political parties would be candidates who supported cap & trade, with the Republican even having previously co-authored Senate legislation on the subject. After a severe dip during the worst of the financial crisis, the contract recovered to around $2/ton after the new administration took office, but then swooned again as the Waxman-Markey bill, with its heavily skewed version of cap & trade, neared passage. As the likelihood of parallel Senate action on climate legislation receded, it never really recovered.
In its editorial on the termination of the Chicago Climate Exchange, the Wall Street Journal suggested that the market has delivered its verdict and the idea of national-level cap & trade is now dead in the US. Perhaps, but it certainly doesn't signal an end to all CO2 trading here. Aside from the state and regional programs to which the Journal alluded, companies with global operations subject to emissions caps in other countries will still be active participants in non-US emissions markets, and firms that remain committed to voluntary reductions in the US may continue to trade with each other, via brokers, or with over-the-counter market makers.
For that matter, I can't help wondering whether cap & trade is truly as dead as a Monty Python parrot or just resting. I'm reluctant to let go of an idea I've supported for a long time, but I also still see significant advantages for cap & trade over other means of putting a price on greenhouse gas emissions. Although the idea of carbon pricing may have gone out of fashion in the US, major tax reform for the purpose of deficit reduction could make it much more difficult to provide the monetary incentives for renewable energy technologies that we do today. Without those subsidies or a price on CO2, renewables will have a hard time competing with fossil fuels. And if our only other choices for emissions reduction were mandates or the command-and-control approach for which the EPA is now gearing up, then cap & trade and the emissions trading that makes it work might no longer look quite so appalling to their critics. In that case, the companies that participated in the CCX during the last seven years might not have wasted their time, after all.
FYI, I'll be participating in a webinar on the sustainability aspects of natural gas next Monday at The Energy Collective . To sign up follow this link. In the meantime, I wish my US readers a very enjoyable Thanksgiving. New postings will resume next week.
I recall a meeting with one of the founders of CCX at Texaco's corporate headquarters in New York prior to my leaving the company at the end of 2001. At that time, Texaco's management was coming around to the idea that sooner or later emissions of CO2 and other greenhouse gases would carry a price, for the first time in human history. Cap & trade offered a proven way to discover that price, based on the pioneering experience of US markets for sulfur dioxide, a cause of acid rain, and nitrogen oxides. The principles of emissions trading had been embedded in the Kyoto Protocol, largely thanks to the efforts of the US delegation, and European countries were setting up the precursors of the EU Emissions Trading System to manage mandatory carbon reductions. Such developments still appeared to be somewhere over the horizon in the US, which never ratified Kyoto, but they seemed likely to find their way here, eventually. One of the main selling points of the CCX, which was based on voluntary emission reduction commitments by member companies, was that it would provide valuable early experience in a formal market for emissions reductions, giving participants a leg up when such trading was required by law. This argument didn't persuade my former employer, but a number of other companies signed up.
If this scenario now seems like a quaint strand of alternate history--a "what if?" that never materialized--that perspective is quite recent. The prospects for CCX and wider emissions trading looked reasonable for a long time. The value of the CCX contract peaked in mid-2008, when it had become apparent that the ultimate presidential nominees of both major US political parties would be candidates who supported cap & trade, with the Republican even having previously co-authored Senate legislation on the subject. After a severe dip during the worst of the financial crisis, the contract recovered to around $2/ton after the new administration took office, but then swooned again as the Waxman-Markey bill, with its heavily skewed version of cap & trade, neared passage. As the likelihood of parallel Senate action on climate legislation receded, it never really recovered.
In its editorial on the termination of the Chicago Climate Exchange, the Wall Street Journal suggested that the market has delivered its verdict and the idea of national-level cap & trade is now dead in the US. Perhaps, but it certainly doesn't signal an end to all CO2 trading here. Aside from the state and regional programs to which the Journal alluded, companies with global operations subject to emissions caps in other countries will still be active participants in non-US emissions markets, and firms that remain committed to voluntary reductions in the US may continue to trade with each other, via brokers, or with over-the-counter market makers.
For that matter, I can't help wondering whether cap & trade is truly as dead as a Monty Python parrot or just resting. I'm reluctant to let go of an idea I've supported for a long time, but I also still see significant advantages for cap & trade over other means of putting a price on greenhouse gas emissions. Although the idea of carbon pricing may have gone out of fashion in the US, major tax reform for the purpose of deficit reduction could make it much more difficult to provide the monetary incentives for renewable energy technologies that we do today. Without those subsidies or a price on CO2, renewables will have a hard time competing with fossil fuels. And if our only other choices for emissions reduction were mandates or the command-and-control approach for which the EPA is now gearing up, then cap & trade and the emissions trading that makes it work might no longer look quite so appalling to their critics. In that case, the companies that participated in the CCX during the last seven years might not have wasted their time, after all.
FYI, I'll be participating in a webinar on the sustainability aspects of natural gas next Monday at The Energy Collective . To sign up follow this link. In the meantime, I wish my US readers a very enjoyable Thanksgiving. New postings will resume next week.
Friday, November 19, 2010
Energy Implications of Tax Reform
I've been thinking about the implications for energy of a major deficit reduction effort along the lines suggested by the co-chairs of the President's fiscal responsibility and reform commission. Our present approach to providing incentives for various energy sources and technologies, new and old, is embedded in a tax code and taxation philosophy that might not survive the upheaval required to bring the US deficit and resulting federal debt back into a manageable range. This goes far beyond the comparatively minor question of extending expiring grants and tax credits that I discussed the other day; under the most stringent of the proposals from Mr. Bowles and Senator Simpson, such things wouldn't even exist. It's not clear how the Administration or Congress would promote favored energy technologies and strategies without these well-established but costly tools.
Start with renewable energy. We currently promote renewable fuels and electricity generation with a combination of mandates--policies such as the federal Renewable Fuels Standard (RFS) and state Renewable Portfolio Standards--and subsidy payments. Until last year's stimulus bill established the Treasury renewable energy grants, for which eligibility is due to expire in a few weeks, most of those subsidy payments have come in the form of reductions in federal taxes, via either an investment tax credit (ITC) based on the cost of a project or a production tax credit (PTC) for actual energy generated. Both of these measures, which have had a checkered history of expirations and extensions, fall into the broad category of "tax expenditures". The Zero Option proposed by Messrs. Bowles and Simpson would permanently eliminate over $1 trillion of such tax expenditures, in exchange for much lower tax rates.
Even if the renewable energy tax credits were reloaded into a streamlined tax code under the "Wyden-Gregg-style" reform presented as Option 2 from the co-chairs, the value of those credits would be reduced--or at least rendered harder to extract--because the corporate tax rate would be reduced from the current 35% to 26%. That means that a higher proportion of companies would likely not pay large enough taxes to take full advantage of the renewable energy tax credits--or have as much appetite for others' credits via "tax equity" swaps. Compounding that, the likelihood of enacting cash grants to get around this restriction would probably be much lower in an environment in which entire herds of sacred cows were being slaughtered in the cause of averting a looming national deficit and debt crisis.
In the absence of such tax credits, renewable energy developers and manufacturers would be forced to rely even more on state-level mandates or a proposed federal renewable electricity standard. The first test of such a mandates-only approach might come in a few weeks, if the ethanol blenders' credit is allowed to expire, while the annual RFS mandate continues to ratchet up. Or companies might simply conclude that without generous tax subsidies for renewable energy deployment here, their best opportunities would be found in markets that are growing much faster than ours, based on actual energy demand, rather than better incentives. Developing Asia comes to mind. That shift might not be the worst outcome, in terms of both the US trade deficit and global emissions reductions.
Conventional energy firms wouldn't escape unscathed, either. They stand to lose significant tax expenditures as well, in the form of oil & gas depletion allowances, the Section 199 manufacturing deduction, and other benefits. However, the oil and gas industry has been paying an effective corporate tax rate above 40% even after all these credits and deductions. A drop to 26% might more than offset the loss of the other benefits, while more importantly bridging the competitive gap between US firms and foreign competitors that operate under lower tax rates and a territorial tax system, rather than being taxed on worldwide earnings, as US companies are today. Bowles/Simpson also proposed increasing the federal gasoline tax by 15¢ per gallon to restore the Highway Trust Fund to solvency. That's a worthy goal, but as I've pointed out previously the Highway fund faces complex challenges as the US car fleet becomes steadily more fuel efficient and increasingly moves away from liquid fuels taxed at the pump. Raising the gas tax is a stop-gap measure, at best, on the way to a different means of collecting road taxes.
With regard to climate policy, tax reform that eliminated tax credits or reduced their value would also tend to nudge the debate back in the direction of putting an explicit price on carbon, either via cap & trade or with an outright tax. Might that prospect suddenly look more attractive as an adjunct to a fairer and simpler income tax system, than it seemed when it would have come as a further complication to an already enormously convoluted tax system that is widely viewed as unfair by both liberals and conservatives? My guess is not, without something else that motivates us to tackle climate change on a much more urgent basis.
Now let's come back to reality. The proposals of the commission's co-chairs have already received a frosty reception or outright hostility from both sides of the aisle, and they haven't yet gotten the buy-in of the rest of their team; the final report requires the consent of 14 of the 18 members. Their ideas must also compete with a growing number of deficit-reduction alternatives, including a widely-reported plan from another bi-partisan group, plus at least one solo proposal from another member of the President's commission. The chances are low for any of these proposals to gain enough traction to be enacted without first being significantly watered down. However, it is starting to look just as risky to assume that the present tax system--and its cornucopia of energy incentives--will continue unchanged indefinitely. A quick glance at the US debt clock ought to make that abundantly clear.
Start with renewable energy. We currently promote renewable fuels and electricity generation with a combination of mandates--policies such as the federal Renewable Fuels Standard (RFS) and state Renewable Portfolio Standards--and subsidy payments. Until last year's stimulus bill established the Treasury renewable energy grants, for which eligibility is due to expire in a few weeks, most of those subsidy payments have come in the form of reductions in federal taxes, via either an investment tax credit (ITC) based on the cost of a project or a production tax credit (PTC) for actual energy generated. Both of these measures, which have had a checkered history of expirations and extensions, fall into the broad category of "tax expenditures". The Zero Option proposed by Messrs. Bowles and Simpson would permanently eliminate over $1 trillion of such tax expenditures, in exchange for much lower tax rates.
Even if the renewable energy tax credits were reloaded into a streamlined tax code under the "Wyden-Gregg-style" reform presented as Option 2 from the co-chairs, the value of those credits would be reduced--or at least rendered harder to extract--because the corporate tax rate would be reduced from the current 35% to 26%. That means that a higher proportion of companies would likely not pay large enough taxes to take full advantage of the renewable energy tax credits--or have as much appetite for others' credits via "tax equity" swaps. Compounding that, the likelihood of enacting cash grants to get around this restriction would probably be much lower in an environment in which entire herds of sacred cows were being slaughtered in the cause of averting a looming national deficit and debt crisis.
In the absence of such tax credits, renewable energy developers and manufacturers would be forced to rely even more on state-level mandates or a proposed federal renewable electricity standard. The first test of such a mandates-only approach might come in a few weeks, if the ethanol blenders' credit is allowed to expire, while the annual RFS mandate continues to ratchet up. Or companies might simply conclude that without generous tax subsidies for renewable energy deployment here, their best opportunities would be found in markets that are growing much faster than ours, based on actual energy demand, rather than better incentives. Developing Asia comes to mind. That shift might not be the worst outcome, in terms of both the US trade deficit and global emissions reductions.
Conventional energy firms wouldn't escape unscathed, either. They stand to lose significant tax expenditures as well, in the form of oil & gas depletion allowances, the Section 199 manufacturing deduction, and other benefits. However, the oil and gas industry has been paying an effective corporate tax rate above 40% even after all these credits and deductions. A drop to 26% might more than offset the loss of the other benefits, while more importantly bridging the competitive gap between US firms and foreign competitors that operate under lower tax rates and a territorial tax system, rather than being taxed on worldwide earnings, as US companies are today. Bowles/Simpson also proposed increasing the federal gasoline tax by 15¢ per gallon to restore the Highway Trust Fund to solvency. That's a worthy goal, but as I've pointed out previously the Highway fund faces complex challenges as the US car fleet becomes steadily more fuel efficient and increasingly moves away from liquid fuels taxed at the pump. Raising the gas tax is a stop-gap measure, at best, on the way to a different means of collecting road taxes.
With regard to climate policy, tax reform that eliminated tax credits or reduced their value would also tend to nudge the debate back in the direction of putting an explicit price on carbon, either via cap & trade or with an outright tax. Might that prospect suddenly look more attractive as an adjunct to a fairer and simpler income tax system, than it seemed when it would have come as a further complication to an already enormously convoluted tax system that is widely viewed as unfair by both liberals and conservatives? My guess is not, without something else that motivates us to tackle climate change on a much more urgent basis.
Now let's come back to reality. The proposals of the commission's co-chairs have already received a frosty reception or outright hostility from both sides of the aisle, and they haven't yet gotten the buy-in of the rest of their team; the final report requires the consent of 14 of the 18 members. Their ideas must also compete with a growing number of deficit-reduction alternatives, including a widely-reported plan from another bi-partisan group, plus at least one solo proposal from another member of the President's commission. The chances are low for any of these proposals to gain enough traction to be enacted without first being significantly watered down. However, it is starting to look just as risky to assume that the present tax system--and its cornucopia of energy incentives--will continue unchanged indefinitely. A quick glance at the US debt clock ought to make that abundantly clear.
Wednesday, November 17, 2010
Closed-Loop Energy
This morning I received an emailed press release announcing that the Altamont landfill gas facility in California had been recognized by the state's governor for its achievement in sustainability. What makes this facility unique is that the methane gas generated by the landfill waste is collected and turned into liquefied natural gas (LNG) in a plant run by a joint venture of Waste Management and the North American subsidiary of the Linde Group and then used to power garbage trucks that haul San Francisco's waste to the landfill. That effectively "closes the loop" by turning trash into fuel to collect the trash. It's a clever concept, but I admit to being initially skeptical about the companies' claim that this approach saves 98% of the greenhouse gas emissions from the diesel fuel it replaces. How can that be, when every pound of methane burned in the trucks' engines yields 2.75 pounds of CO2?
The answer to this conundrum lies in the assumptions behind the analysis of the project done by Argonne National Laboratory, which is generally considered the gold standard for lifecycle, or "well-to-wheels" analysis of this kind. Quoting from their report, "At present most of the biomethane generated at U.S. landfills is flared in conjunction with emissions-abatement practices." Since 1996, landfills above a certain threshold have been required to collect methane and other gases produced by the decomposition of refuse and either flare it or put it through a thermal oxidizer to convert the methane to CO2. That's crucial from an emissions perspective, because it reduces the landfill's greenhouse gas emissions by a factor of 21 times versus simple venting. However, the report also states that over 500 projects around the US recover energy from landfill methane, with most either using it to generate power or steam or compressing it and injecting it into natural gas pipelines, where it becomes indistinguishable from the methane produced from natural gas wells. When Argonne confirms that Altamont's LNG emits practically no greenhouse gases, that result is relative to the option of flaring it, not compared to the other uses to which the recovered gas could be put.
The appropriateness of that assumption goes to the heart of the issue of "additionality" that has made the certification of emissions credits so challenging in many cases around the world. In this case, if the Altamont landfill gas in question weren't turned into LNG to fuel San Francisco garbage trucks, would it really be flared or would it be turned into power, as other gas produced at Altamont apparently is? On one level I can't answer that without knowing a lot more about the facility than is provided either on Waste Management's site or in the Argonne analysis. However, it helps to consider that an assessment of any other use of this gas would face the same question; they can't all be compared to each other. There must be a common reference, and going back to flaring, which is the basic standard required under the Landfill Rule of the Clean Air Act, seems the most consistent choice.
With that assumption in hand, and based on Argonne's analysis of the emissions from the different steps involved in producing the LNG, it's perfectly reasonable to claim that at least compared to burning petroleum diesel in Waste Management's trucks, the Altamont LNG is a nearly zero emission fuel. The more interesting question is whether this disposition, with its obvious green PR benefits, is actually the best use of the energy recovered from the landfill. The same Argonne report indicates that the total energy consumption in the landfill gas-LNG-motor fuel pathway is about 8% higher than in the oil well-refinery-motor fuel pathway for diesel fuel. That hints at the possibility that the total emissions reductions from Altamont might be even greater if the gas were used, not to power garbage trucks, but for another purpose, such as generating power to back out electricity imported into the state from coal-burning sources in places like Four Corners, New Mexico. In any case, lest we make the perfect the enemy of the good, what Waste Management and Linde are doing at Altamont is certainly good compared to the default option of flaring all that gas, and the kudos they have received look well deserved.
The answer to this conundrum lies in the assumptions behind the analysis of the project done by Argonne National Laboratory, which is generally considered the gold standard for lifecycle, or "well-to-wheels" analysis of this kind. Quoting from their report, "At present most of the biomethane generated at U.S. landfills is flared in conjunction with emissions-abatement practices." Since 1996, landfills above a certain threshold have been required to collect methane and other gases produced by the decomposition of refuse and either flare it or put it through a thermal oxidizer to convert the methane to CO2. That's crucial from an emissions perspective, because it reduces the landfill's greenhouse gas emissions by a factor of 21 times versus simple venting. However, the report also states that over 500 projects around the US recover energy from landfill methane, with most either using it to generate power or steam or compressing it and injecting it into natural gas pipelines, where it becomes indistinguishable from the methane produced from natural gas wells. When Argonne confirms that Altamont's LNG emits practically no greenhouse gases, that result is relative to the option of flaring it, not compared to the other uses to which the recovered gas could be put.
The appropriateness of that assumption goes to the heart of the issue of "additionality" that has made the certification of emissions credits so challenging in many cases around the world. In this case, if the Altamont landfill gas in question weren't turned into LNG to fuel San Francisco garbage trucks, would it really be flared or would it be turned into power, as other gas produced at Altamont apparently is? On one level I can't answer that without knowing a lot more about the facility than is provided either on Waste Management's site or in the Argonne analysis. However, it helps to consider that an assessment of any other use of this gas would face the same question; they can't all be compared to each other. There must be a common reference, and going back to flaring, which is the basic standard required under the Landfill Rule of the Clean Air Act, seems the most consistent choice.
With that assumption in hand, and based on Argonne's analysis of the emissions from the different steps involved in producing the LNG, it's perfectly reasonable to claim that at least compared to burning petroleum diesel in Waste Management's trucks, the Altamont LNG is a nearly zero emission fuel. The more interesting question is whether this disposition, with its obvious green PR benefits, is actually the best use of the energy recovered from the landfill. The same Argonne report indicates that the total energy consumption in the landfill gas-LNG-motor fuel pathway is about 8% higher than in the oil well-refinery-motor fuel pathway for diesel fuel. That hints at the possibility that the total emissions reductions from Altamont might be even greater if the gas were used, not to power garbage trucks, but for another purpose, such as generating power to back out electricity imported into the state from coal-burning sources in places like Four Corners, New Mexico. In any case, lest we make the perfect the enemy of the good, what Waste Management and Linde are doing at Altamont is certainly good compared to the default option of flaring all that gas, and the kudos they have received look well deserved.
Monday, November 15, 2010
Extend or Reform?
As the US Congress returns from its election recess to take up its "lame duck" session, one of many crucial pending items it will likely take up is the so-called "extenders" package: key tax provisions that are due to expire at the end of the year, unless extended by legislative action. From an energy perspective, this includes both the expiring ethanol blenders credit and the Treasury renewable energy grants issued in lieu of the investment tax credit (ITC) for renewables. Both incentives face a much more uncertain reception when the new Congress is sworn in next January, so the lame duck might just be their last gasp.
For the ethanol credit, that is as it should be; if 32 years of federal subsidies haven't made corn ethanol competitive with gasoline--particularly when its use is now mandatory--then nothing will. The situation for the renewable energy grants is more complicated. This is a relatively new benefit that, as I've noted in previous postings, was instituted as part of last year's American Recovery and Reinvestment Act--a.k.a. the stimulus--to substitute for a class of market transactions ("tax equity") that renewable energy developers could no longer access as a result of the financial crisis. Bridging that gap became all but essential for smaller companies without enough taxable earnings to take full advantage of the tax credit on their own, or lacking adequate working capital to afford to wait until their next tax filing to recoup the applicable ITC portion of the cost of a project.
If that situation still obtained, justifying the extension of the grants for another year or two would be easy. In the meantime, however, much has changed. Although not yet functioning at the same pace as before the financial crisis, the tax equity market is recovering. Banks and insurance companies have announced a growing number of tax equity deals in the last few months. This market might revive even faster if it weren't competing with essentially free money from the Treasury.
The other aspect of the situation that has changed is the growing dominance of large players in renewable energy project development, particularly for wind. Contrary to the perception that the Treasury grants mainly benefited small companies, more than half of the $5.4 billion in grants awarded to date went to just three companies, all of them large and profitable enough to have waited until tax time to collect their ITC benefits--though I don't doubt that getting cash up front improved the economics of their projects. For example, EDP Renovaveis, through its Horizon Wind Energy subsidiary, collected around $565 million in grants in the first half of 2010, after receiving "in excess of 685 million dollars" in 2009. Meanwhile, between its 3Q2010 earnings presentation and its 2009 full-year presentation Iberdrola Renovables claimed approximately $983 million in US renewable energy grants. NextEra Energy (the renamed parent company of Florida Power & Light) booked $556 million in grants in the first 9 months of 2010, on top of $100 million last year. All of this was entirely appropriate under the provisions of the stimulus, but it doesn't quite fit the picture of an emergency measure intended to help small, struggling firms.
Some have argued that in any case the grants are merely a matter of timing for the government: paying eligible developers cash now, or paying them the same amount later, via reduced taxes. That would only be true if every project that was eligible for a grant could (or should) proceed without one. Sparing wind farms, solar installations and other projects from the discipline of rigorous review by private investors risks allowing weaker projects to proceed, when they should either be rethought or cancelled. That was an unavoidable risk in early 2009, when the renewable energy industry was in peril of imploding, but overlooking it seems less justifiable today.
The Treasury renewable energy grants were instituted as an extreme step at an unprecedented time. It's hard to imagine that anyone intended them to become a permanent entitlement to replace the existing renewable energy tax credits, which were simultaneously extended through the end of 2012 for wind power and 2013 for most other technologies. However, if this program is to be extended for now, it ought to be reformed to exclude beneficiaries for which it constitutes merely a convenience, rather than a necessity. That would mean either capping the maximum payout for any recipient at something less than $100 million, or imposing a corporate income threshold. I'll be watching this issue with great interest between now and the end of the year.
For the ethanol credit, that is as it should be; if 32 years of federal subsidies haven't made corn ethanol competitive with gasoline--particularly when its use is now mandatory--then nothing will. The situation for the renewable energy grants is more complicated. This is a relatively new benefit that, as I've noted in previous postings, was instituted as part of last year's American Recovery and Reinvestment Act--a.k.a. the stimulus--to substitute for a class of market transactions ("tax equity") that renewable energy developers could no longer access as a result of the financial crisis. Bridging that gap became all but essential for smaller companies without enough taxable earnings to take full advantage of the tax credit on their own, or lacking adequate working capital to afford to wait until their next tax filing to recoup the applicable ITC portion of the cost of a project.
If that situation still obtained, justifying the extension of the grants for another year or two would be easy. In the meantime, however, much has changed. Although not yet functioning at the same pace as before the financial crisis, the tax equity market is recovering. Banks and insurance companies have announced a growing number of tax equity deals in the last few months. This market might revive even faster if it weren't competing with essentially free money from the Treasury.
The other aspect of the situation that has changed is the growing dominance of large players in renewable energy project development, particularly for wind. Contrary to the perception that the Treasury grants mainly benefited small companies, more than half of the $5.4 billion in grants awarded to date went to just three companies, all of them large and profitable enough to have waited until tax time to collect their ITC benefits--though I don't doubt that getting cash up front improved the economics of their projects. For example, EDP Renovaveis, through its Horizon Wind Energy subsidiary, collected around $565 million in grants in the first half of 2010, after receiving "in excess of 685 million dollars" in 2009. Meanwhile, between its 3Q2010 earnings presentation and its 2009 full-year presentation Iberdrola Renovables claimed approximately $983 million in US renewable energy grants. NextEra Energy (the renamed parent company of Florida Power & Light) booked $556 million in grants in the first 9 months of 2010, on top of $100 million last year. All of this was entirely appropriate under the provisions of the stimulus, but it doesn't quite fit the picture of an emergency measure intended to help small, struggling firms.
Some have argued that in any case the grants are merely a matter of timing for the government: paying eligible developers cash now, or paying them the same amount later, via reduced taxes. That would only be true if every project that was eligible for a grant could (or should) proceed without one. Sparing wind farms, solar installations and other projects from the discipline of rigorous review by private investors risks allowing weaker projects to proceed, when they should either be rethought or cancelled. That was an unavoidable risk in early 2009, when the renewable energy industry was in peril of imploding, but overlooking it seems less justifiable today.
The Treasury renewable energy grants were instituted as an extreme step at an unprecedented time. It's hard to imagine that anyone intended them to become a permanent entitlement to replace the existing renewable energy tax credits, which were simultaneously extended through the end of 2012 for wind power and 2013 for most other technologies. However, if this program is to be extended for now, it ought to be reformed to exclude beneficiaries for which it constitutes merely a convenience, rather than a necessity. That would mean either capping the maximum payout for any recipient at something less than $100 million, or imposing a corporate income threshold. I'll be watching this issue with great interest between now and the end of the year.
Thursday, November 11, 2010
Those Other Energy Subsidies
Energy subsidies have become a hot-button issue for both renewable and conventional energy, with each side claiming the other receives more than it should. This issue is on the agenda for the meeting of the G-20 group of nations in Seoul, because they committed to the phase-out of subsidies for fossil energy at last year's Pittsburgh summit and will report on progress at this week's session. This coincides with the release of a new forecast from the International Energy Agency highlighting the urgency of phasing out these subsidies for the sake of reducing greenhouse gas emissions. It's worth noting that unlike US incentives for energy production that have attracted so much flak here, the bulk of the subsidies the G-20 and IEA want to eliminate are for the consumption of fossil fuels; most of them are provided in the developing world, often by governments that can ill afford them. Putting an end to these practices is a worthy goal, and not just because of climate change.
In addition to promoting stronger government support for renewable energy, the IEA report highlighted $312 billion in counterproductive subsidies for fossil energy last year--the figure was much higher in 2008--compared with $57 billion for all renewables, including biofuels. The subsidies in question are mainly in the form of price controls and market manipulation by governments in developing countries, including both large net energy producers and large net consumers. These governments effectively pay consumers to use more energy by keeping prices lower than free market levels. This is clearly counterproductive with regard to combating climate change, because it leads to higher emissions, but I'd like to focus on another drawback, in terms of how it affects global energy markets. Its effects haven't been as obvious recently, with demand down and spare production capacity ample for the moment, but it contributed significantly to the extreme oil prices we saw in 2007 and especially 2008.
Whether as simple as fuel price caps set by government fiat or as complex as the Philippines' former Oil Price Stabilization Fund that I used to monitor regularly in the 1990s--it acted as a sort of central bank for energy prices, until it ran out of money--these mechanisms insulate consumers from the global price of energy, usually oil. The benefits on which these measures are justified even make a certain amount of sense, in terms of protecting consumers from the effects of market volatility and promoting prosperity. If all they did was to smooth out market fluctuations while still reflecting average market values over time, those benefits might outweigh the damage these policies do to both national treasuries and to the capacity of oil prices to match supply and demand. In practice, these efforts often become politicized and end up entrenching below-market prices for their most vocal constituencies. Unfortunately, this not only boosts consumption but it also muffles or blocks price signals when global demand approaches the limits of supply, as we saw a couple of years ago.
The consequences of this are both local and global. Locally, either oil companies or oil price funds require ever greater cash infusions from governments, as global prices go up but consumers miss receiving the message to conserve. This decoupling, compounded over large segments of global demand, amplifies global price increases and focuses the necessary demand response on those countries without such mechanisms, like the US. This helps explain why oil prices skyrocketed to $145/bbl from the $70s just a year earlier, because that's what it took to force demand in non-subsidized countries down by enough to adjust for the global tightness of supply. In other words, oil consumption subsidies intended to stabilize local markets are paradoxically destabilizing for global oil markets.
It's important to draw a distinction between consumption subsidies like these and the fossil fuel subsidies that have come in for significant criticism in the US, which are focused not on consumption but on production. In fact, if their critics' claims about the unresponsiveness of global oil prices to incremental US production were right, then they would have zero impact in promoting consumption, which is the issue of concern to the G-20 and IEA. I don't believe either side of that thesis is correct. Supporting US domestic production inherently helps stabilize global oil prices by reducing US oil imports, but it likely does increase consumption modestly by nudging prices a bit lower than they'd be otherwise. That gives rise to an awkward trade-off, pitting increased energy security against slightly higher emissions, contrary to the rhetoric of some "energy hawks" who suggest that these two issues are always aligned.
In any case, as long as the G-20's efforts are focused on phasing out subsidies intended to hold down fossil fuel prices, they are on the right track, though consumers in developing countries will be in for a nasty shock when their governments follow through with this initiative. At the same time, the alternative to incentives for energy production is not their unilateral elimination, but the rationalization of tax and regulatory structures so that producers in one country aren't at a disadvantage compared to producers in another country, or to other industries in their own country. Sorting that out would require an entirely different and much more complex effort, and not just by the G-20's membership.
In addition to promoting stronger government support for renewable energy, the IEA report highlighted $312 billion in counterproductive subsidies for fossil energy last year--the figure was much higher in 2008--compared with $57 billion for all renewables, including biofuels. The subsidies in question are mainly in the form of price controls and market manipulation by governments in developing countries, including both large net energy producers and large net consumers. These governments effectively pay consumers to use more energy by keeping prices lower than free market levels. This is clearly counterproductive with regard to combating climate change, because it leads to higher emissions, but I'd like to focus on another drawback, in terms of how it affects global energy markets. Its effects haven't been as obvious recently, with demand down and spare production capacity ample for the moment, but it contributed significantly to the extreme oil prices we saw in 2007 and especially 2008.
Whether as simple as fuel price caps set by government fiat or as complex as the Philippines' former Oil Price Stabilization Fund that I used to monitor regularly in the 1990s--it acted as a sort of central bank for energy prices, until it ran out of money--these mechanisms insulate consumers from the global price of energy, usually oil. The benefits on which these measures are justified even make a certain amount of sense, in terms of protecting consumers from the effects of market volatility and promoting prosperity. If all they did was to smooth out market fluctuations while still reflecting average market values over time, those benefits might outweigh the damage these policies do to both national treasuries and to the capacity of oil prices to match supply and demand. In practice, these efforts often become politicized and end up entrenching below-market prices for their most vocal constituencies. Unfortunately, this not only boosts consumption but it also muffles or blocks price signals when global demand approaches the limits of supply, as we saw a couple of years ago.
The consequences of this are both local and global. Locally, either oil companies or oil price funds require ever greater cash infusions from governments, as global prices go up but consumers miss receiving the message to conserve. This decoupling, compounded over large segments of global demand, amplifies global price increases and focuses the necessary demand response on those countries without such mechanisms, like the US. This helps explain why oil prices skyrocketed to $145/bbl from the $70s just a year earlier, because that's what it took to force demand in non-subsidized countries down by enough to adjust for the global tightness of supply. In other words, oil consumption subsidies intended to stabilize local markets are paradoxically destabilizing for global oil markets.
It's important to draw a distinction between consumption subsidies like these and the fossil fuel subsidies that have come in for significant criticism in the US, which are focused not on consumption but on production. In fact, if their critics' claims about the unresponsiveness of global oil prices to incremental US production were right, then they would have zero impact in promoting consumption, which is the issue of concern to the G-20 and IEA. I don't believe either side of that thesis is correct. Supporting US domestic production inherently helps stabilize global oil prices by reducing US oil imports, but it likely does increase consumption modestly by nudging prices a bit lower than they'd be otherwise. That gives rise to an awkward trade-off, pitting increased energy security against slightly higher emissions, contrary to the rhetoric of some "energy hawks" who suggest that these two issues are always aligned.
In any case, as long as the G-20's efforts are focused on phasing out subsidies intended to hold down fossil fuel prices, they are on the right track, though consumers in developing countries will be in for a nasty shock when their governments follow through with this initiative. At the same time, the alternative to incentives for energy production is not their unilateral elimination, but the rationalization of tax and regulatory structures so that producers in one country aren't at a disadvantage compared to producers in another country, or to other industries in their own country. Sorting that out would require an entirely different and much more complex effort, and not just by the G-20's membership.
Tuesday, November 09, 2010
Hydrocarbons and Geothermal Energy
Geothermal power is probably the lowest-profile renewable energy option we have. It doesn't get nearly the attention that wind and solar power do--even from me--although it has been quietly cranking out about 0.4% of the US electricity supply for many years. That roughly matches the expected output of all the wind turbines likely to be installed here this year. I've commented previously on the striking similarities between geothermal exploration and production and the processes and risk profile of oil and gas E&P, but I don't believe I've ever mentioned a small but potentially important overlap between the two: geothermal heat extracted from the fluids produced from oil and gas wells. The potential contribution of "geothermal hydrocarbon co-production" (GHCP) might not be as large as from conventional hydrothermal reservoirs or engineered geothermal systems (EGS), but this approach has the advantage of capitalizing on additional energy from a source that's already being exploited.
In its report on the US geothermal industry earlier this year, the Geothermal Energy Association listed five projects involving GHCP and related efforts to tap the mechanical energy of high-pressure gas reservoirs, or geopressured fluids. The Department of Energy has recognized this potential and provided partial funding for several of these projects under its stimulus programs. GEA also cited an estimate from Southern Methodist University's Geothermal Energy Program that GHCP from the onshore Gulf Coast region alone could provide up to 5,000 MW of reliable power. That doesn't include the potential for using the large volumes of produced water in new or abandoned wells to tap the energy of higher-temperature rock formations underlying the hydrocarbon reservoirs using engineered geothermal systems (EGS).
The benefits of these approaches for low-emission power generation seem obvious, but it's worth considering why they might be attractive for oil and gas companies that are mainly focused on producing hydrocarbons for processing and sale, not electricity. GHCP addresses two key, related problems of many mature US oil fields. The first is water, which in many cases is injected underground as part of "secondary recovery", in order to increase the total fraction of hydrocarbons recovered from an oil field during its life. Together with water already present in these reservoirs (as distinct from the shallower aquifers used for drinking water and irrigation) this contributes to high "water cuts"--large volumes of water produced with the oil and gas that sometimes exceed oil volumes by a factor of 20:1. If this water is in contact with hot rock, it will bring some of that heat to the surface, where it can be recovered using binary geothermal technology. SMU estimated total produced water from US oil production at 50 billion barrels per year.
That's an enormous volume of water for the industry to handle and dispose of in an appropriate manner, and it gives rise to another problem that GHCP can help tackle. It takes a lot of electricity to pump all that water out of the ground, process it, and pump it back down. That power must either be purchased or generated onsite. If GHCP can just provide enough power to cover an oil field's operating power requirements, it represents a significant savings in the cost per barrel of oil produced. The SMU study suggests that there is also an opportunity for net electricity production, representing another potential revenue source for an oil project. Depending on the investment required, that could improve overall project economics.
I see another, less obvious benefit for geothermal hydrocarbon co-production. The US geothermal industry hasn't attracted anything like the investment that's gone into wind and solar power; it is starved for capital. As a result, it can only tap a small fraction of the potential power from US hydrothermal reservoirs, let alone the orders-of-magnitude larger potential of EGS. If these projects don't offer quite the economic payoff of oil and gas production, they at least closely resemble what the oil industry does day in and day out, while being almost completely unlike what firms involved in wind, solar or even biomass power do. GHCP could be a natural bridge for more of the oil and gas industry, which its much larger capital, skills and technology base, to expand into geothermal energy that doesn't involve any hydrocarbons.
In its report on the US geothermal industry earlier this year, the Geothermal Energy Association listed five projects involving GHCP and related efforts to tap the mechanical energy of high-pressure gas reservoirs, or geopressured fluids. The Department of Energy has recognized this potential and provided partial funding for several of these projects under its stimulus programs. GEA also cited an estimate from Southern Methodist University's Geothermal Energy Program that GHCP from the onshore Gulf Coast region alone could provide up to 5,000 MW of reliable power. That doesn't include the potential for using the large volumes of produced water in new or abandoned wells to tap the energy of higher-temperature rock formations underlying the hydrocarbon reservoirs using engineered geothermal systems (EGS).
The benefits of these approaches for low-emission power generation seem obvious, but it's worth considering why they might be attractive for oil and gas companies that are mainly focused on producing hydrocarbons for processing and sale, not electricity. GHCP addresses two key, related problems of many mature US oil fields. The first is water, which in many cases is injected underground as part of "secondary recovery", in order to increase the total fraction of hydrocarbons recovered from an oil field during its life. Together with water already present in these reservoirs (as distinct from the shallower aquifers used for drinking water and irrigation) this contributes to high "water cuts"--large volumes of water produced with the oil and gas that sometimes exceed oil volumes by a factor of 20:1. If this water is in contact with hot rock, it will bring some of that heat to the surface, where it can be recovered using binary geothermal technology. SMU estimated total produced water from US oil production at 50 billion barrels per year.
That's an enormous volume of water for the industry to handle and dispose of in an appropriate manner, and it gives rise to another problem that GHCP can help tackle. It takes a lot of electricity to pump all that water out of the ground, process it, and pump it back down. That power must either be purchased or generated onsite. If GHCP can just provide enough power to cover an oil field's operating power requirements, it represents a significant savings in the cost per barrel of oil produced. The SMU study suggests that there is also an opportunity for net electricity production, representing another potential revenue source for an oil project. Depending on the investment required, that could improve overall project economics.
I see another, less obvious benefit for geothermal hydrocarbon co-production. The US geothermal industry hasn't attracted anything like the investment that's gone into wind and solar power; it is starved for capital. As a result, it can only tap a small fraction of the potential power from US hydrothermal reservoirs, let alone the orders-of-magnitude larger potential of EGS. If these projects don't offer quite the economic payoff of oil and gas production, they at least closely resemble what the oil industry does day in and day out, while being almost completely unlike what firms involved in wind, solar or even biomass power do. GHCP could be a natural bridge for more of the oil and gas industry, which its much larger capital, skills and technology base, to expand into geothermal energy that doesn't involve any hydrocarbons.
Friday, November 05, 2010
A Wind Bubble?
New US wind turbine installations have slowed significantly this year, compared to 2009, and the decline is having consequences. Among other fallout, Suzlon is mothballing a four-year-old wind turbine factory in Minnesota and laying off the remaining 110 workers, due to a lack of new orders. While the industry pins most of the blame for the slowdown on insufficiently aggressive federal energy policies, it suddenly occurred to me to wonder whether wind power, like housing, might have been caught up in an investment bubble that has finally popped, somewhat belatedly.
The idea of a wind bubble goes against all conventional wisdom, including the importance of expanding electricity generation from low-emission sources in order to mitigate climate change; the desire to build a vibrant "new energy" economy in the US for energy security and competitive reasons; and the persistent mantra of the green jobs that are supposed to turn the economy around. Yet every bubble must have a compelling, plausible narrative, or it would never take off.
When you examine the charts of annual and quarterly US wind turbine installations on pages 2 and 3 of the "Third Quarter 2010 Market Report" from the American Wind Energy Association, there are at least two ways to look at them. The customary perspective would attribute the dramatic increase in wind installations beginning in 2006, which set records in each of the next three years, to the rapid scaling up of an industry that many envision supplying 20% of US electricity generation within two decades, up from its current level of around 2%. This growth has been supported by a variety of incentives and mandates, including the federal renewable production tax credit (PTC), the stimulus grants, and state renewable portfolio standards. But in this scenario it's hard to explain why installations would have fallen off so much this year, when all of these benefits are still in place, other than the imminent expiration of eligibility for the stimulus grants--which in another year might have been expected to trigger a mad rush for projects to get in under the wire, as we saw in 2008 when the PTC was due to expire at year end. How can we attribute this year's drop in installations to the absence of a policy--either a national renewable electricity standard or a comprehensive climate bill--that we've never had?
So turn this picture around and ask why wind might have been in a bubble, and why that bubble might have only popped now, roughly two years after the other bubbles for stocks, housing and possibly oil prices. Aside from the policies promoting wind and other renewables, which have not changed, wind power developers would have looked at two other indicators: credit and demand. Wind projects are capital intensive, and in the run-up to the financial crisis they benefited from the same kind of cheap and readily available credit as other businesses and homeowners did. At the same time, between 2000 and 2007 US demand for electricity was growing at about 1.3% per year. That might not seem like much, but at the scale of the US power sector, that translated into the need to add around 7,000 MW of new generating capacity each year. If all of that was from wind turbines, the required nameplate capacity would approach 20,000 MW, because of wind's lower average output per MW. Wind was also becoming a preferred technology, despite its intermittency, because coal was falling out of favor for environmental reasons and the price of natural gas, the fuel for the dominant incremental generation technology for the last 20 years, had spiked and become very volatile.
If wind was indeed being carried along either by its own bubble or by the froth from the other bubbles fueling the economy in the middle of the decade, why has it only now run out of steam, rather than popping in 2008 or 2009? After all, electricity demand growth evaporated when the financial crisis and recession hit, and demand has not yet recovered to its 2007 peak. For 2008, perhaps the dash to complete projects before the expected expiration of the PTC--it wasn't extended until October of that year--provides sufficient explanation. As for 2009, the charts show that installations did fall dramatically until the implementation of the Treasury stimulus grant program, which injected $1.7 B into wind projects last year and another $2.9 B this year. Moreover, the stimulus grants were more valuable to wind developers than the PTC they formerly received. That isn't just because developers got the money up front, rather than having to wait until a project started up and produced electricity, but also because the grants were based on the 30% investment tax credit (ITC). Using NREL's simplified calculator for the levelized cost of electricity, at a typical cost of around $2,200/kW of capacity the ITC could be worth at least 20% more than the 2.2¢/kWh PTC. In other words, just as the wind market was collapsing last year, the government increased its incentives and accelerated them into up-front cash. That might have been enough to keep a bubble going for a while longer.
Of course there's no way to know whether this scenario is more accurate than the standard explanation for what has happened to the US wind market this year. Nor does it doom wind power to the doldrums even after the economy resumes growing and creating jobs at a healthier rate, and electricity demand picks up. However, if there is a grain of truth in this view, then it might alter our perspective on providing more aggressive support for the wind industry based on the notion that installations should still be running at 10,000 MW per year or more, as they were in 2009, rather than at the lower rate of around 5,000 MW we see today.
The idea of a wind bubble goes against all conventional wisdom, including the importance of expanding electricity generation from low-emission sources in order to mitigate climate change; the desire to build a vibrant "new energy" economy in the US for energy security and competitive reasons; and the persistent mantra of the green jobs that are supposed to turn the economy around. Yet every bubble must have a compelling, plausible narrative, or it would never take off.
When you examine the charts of annual and quarterly US wind turbine installations on pages 2 and 3 of the "Third Quarter 2010 Market Report" from the American Wind Energy Association, there are at least two ways to look at them. The customary perspective would attribute the dramatic increase in wind installations beginning in 2006, which set records in each of the next three years, to the rapid scaling up of an industry that many envision supplying 20% of US electricity generation within two decades, up from its current level of around 2%. This growth has been supported by a variety of incentives and mandates, including the federal renewable production tax credit (PTC), the stimulus grants, and state renewable portfolio standards. But in this scenario it's hard to explain why installations would have fallen off so much this year, when all of these benefits are still in place, other than the imminent expiration of eligibility for the stimulus grants--which in another year might have been expected to trigger a mad rush for projects to get in under the wire, as we saw in 2008 when the PTC was due to expire at year end. How can we attribute this year's drop in installations to the absence of a policy--either a national renewable electricity standard or a comprehensive climate bill--that we've never had?
So turn this picture around and ask why wind might have been in a bubble, and why that bubble might have only popped now, roughly two years after the other bubbles for stocks, housing and possibly oil prices. Aside from the policies promoting wind and other renewables, which have not changed, wind power developers would have looked at two other indicators: credit and demand. Wind projects are capital intensive, and in the run-up to the financial crisis they benefited from the same kind of cheap and readily available credit as other businesses and homeowners did. At the same time, between 2000 and 2007 US demand for electricity was growing at about 1.3% per year. That might not seem like much, but at the scale of the US power sector, that translated into the need to add around 7,000 MW of new generating capacity each year. If all of that was from wind turbines, the required nameplate capacity would approach 20,000 MW, because of wind's lower average output per MW. Wind was also becoming a preferred technology, despite its intermittency, because coal was falling out of favor for environmental reasons and the price of natural gas, the fuel for the dominant incremental generation technology for the last 20 years, had spiked and become very volatile.
If wind was indeed being carried along either by its own bubble or by the froth from the other bubbles fueling the economy in the middle of the decade, why has it only now run out of steam, rather than popping in 2008 or 2009? After all, electricity demand growth evaporated when the financial crisis and recession hit, and demand has not yet recovered to its 2007 peak. For 2008, perhaps the dash to complete projects before the expected expiration of the PTC--it wasn't extended until October of that year--provides sufficient explanation. As for 2009, the charts show that installations did fall dramatically until the implementation of the Treasury stimulus grant program, which injected $1.7 B into wind projects last year and another $2.9 B this year. Moreover, the stimulus grants were more valuable to wind developers than the PTC they formerly received. That isn't just because developers got the money up front, rather than having to wait until a project started up and produced electricity, but also because the grants were based on the 30% investment tax credit (ITC). Using NREL's simplified calculator for the levelized cost of electricity, at a typical cost of around $2,200/kW of capacity the ITC could be worth at least 20% more than the 2.2¢/kWh PTC. In other words, just as the wind market was collapsing last year, the government increased its incentives and accelerated them into up-front cash. That might have been enough to keep a bubble going for a while longer.
Of course there's no way to know whether this scenario is more accurate than the standard explanation for what has happened to the US wind market this year. Nor does it doom wind power to the doldrums even after the economy resumes growing and creating jobs at a healthier rate, and electricity demand picks up. However, if there is a grain of truth in this view, then it might alter our perspective on providing more aggressive support for the wind industry based on the notion that installations should still be running at 10,000 MW per year or more, as they were in 2009, rather than at the lower rate of around 5,000 MW we see today.
Wednesday, November 03, 2010
Interpreting the Election Results
The results of yesterday's election will be interpreted and spun in many ways in the days and weeks ahead. Republicans gained control of the House of Representatives and several key governorships but fell short of capturing control of the Senate. In the process they picked up enough seats--along with at least one like-minded Democratic Senator-elect--to put cap & trade or a national carbon tax out of reach for at least the next two years. Meanwhile, voters resoundingly defeated a ballot initiative in California that would have forestalled implementation of the state's tough greenhouse gas policies. But even if comprehensive federal energy legislation is off the table, divided government doesn't rule out the possibility of a national renewable energy standard or other energy measures, provided they don't involve significant additional expenditures.
On the surface, the election outcome appears to set up a return to the pre-2009 situation, when California and other states were pushing aggressively for action on climate change while the federal government remained deadlocked on the issue. Too much has changed since then for that picture to be accurate. In the absence of Congressional action on greenhouse gas emissions the EPA is forging ahead with its own regulations under the Clean Air Act, and that could provide an early test of the willingness of the new Congress to try to modify the administration's regulatory approach. Meanwhile, although the proposition that would have suspended California's A.B. 32 climate rules was swamped after being portrayed--unfairly, in my view--as mainly benefiting out-of-state oil companies at the expense of the state's new Cleantech industry, California voters passed another initiative, Proposition 26, that will make it harder to impose a variety of new fees on businesses and consumers, including fees related to the environment. Further complicating the outlook, the results of several key governor's races, including in New Mexico and possibly Oregon, could limit the number of other states that might "opt in" to A.B. 32, as well as raising the possibility of more defections from the Western Climate Initiative.
Although as I noted on Monday our fundamental energy situation is largely pre-determined for at least the next few years, last night's results could affect energy policy in a number of other ways, aside from climate change. One example is the President's desire to eliminate subsidies for conventional energy, as part of an initiative of the G-20 group of nations. The main subsidies targeted by this international effort are those that increase demand by limiting the price of fossil fuels for consumers, particularly in developing countries, yet President Obama has linked this to his goal of eliminating a variety of tax breaks benefiting domestic energy production, including the Section 199 tax deduction that all US manufacturers enjoy. Unless this measure is somehow passed in the lame duck session when Congress returns from its election break, it looks dead on arrival come January. From an energy security perspective we should be glad of that.
The change in control of the House also puts the extension of the expiring ethanol blending credit in doubt, along with the prospect of extending eligibility for Treasury renewable energy stimulus grants beyond the end of this year. Even though the latter appears deficit-neutral, and might thus attract bi-partisan support, it accelerates benefits that project developers would otherwise have to wait until their next tax filing to receive, and it probably lets some marginal projects that might not otherwise find private funding escape winnowing. If the lame duck doesn't pass this, the odds of the 112th Congress extending it or anything else connected to the stimulus look poor.
Ultimately the likelihood of meaningful energy legislation of any kind will hinge on the willingness of the President and the new Congress to meet somewhere in the middle to get things done. Otherwise, the scope is limited to a few lowest-common-denominator efforts, which might include a modest national renewable electricity standard, with everything else effectively blocked by the other chamber of Congress or the President's veto pen. I don't expect to lack for topics on which to blog in the next two years.
On the surface, the election outcome appears to set up a return to the pre-2009 situation, when California and other states were pushing aggressively for action on climate change while the federal government remained deadlocked on the issue. Too much has changed since then for that picture to be accurate. In the absence of Congressional action on greenhouse gas emissions the EPA is forging ahead with its own regulations under the Clean Air Act, and that could provide an early test of the willingness of the new Congress to try to modify the administration's regulatory approach. Meanwhile, although the proposition that would have suspended California's A.B. 32 climate rules was swamped after being portrayed--unfairly, in my view--as mainly benefiting out-of-state oil companies at the expense of the state's new Cleantech industry, California voters passed another initiative, Proposition 26, that will make it harder to impose a variety of new fees on businesses and consumers, including fees related to the environment. Further complicating the outlook, the results of several key governor's races, including in New Mexico and possibly Oregon, could limit the number of other states that might "opt in" to A.B. 32, as well as raising the possibility of more defections from the Western Climate Initiative.
Although as I noted on Monday our fundamental energy situation is largely pre-determined for at least the next few years, last night's results could affect energy policy in a number of other ways, aside from climate change. One example is the President's desire to eliminate subsidies for conventional energy, as part of an initiative of the G-20 group of nations. The main subsidies targeted by this international effort are those that increase demand by limiting the price of fossil fuels for consumers, particularly in developing countries, yet President Obama has linked this to his goal of eliminating a variety of tax breaks benefiting domestic energy production, including the Section 199 tax deduction that all US manufacturers enjoy. Unless this measure is somehow passed in the lame duck session when Congress returns from its election break, it looks dead on arrival come January. From an energy security perspective we should be glad of that.
The change in control of the House also puts the extension of the expiring ethanol blending credit in doubt, along with the prospect of extending eligibility for Treasury renewable energy stimulus grants beyond the end of this year. Even though the latter appears deficit-neutral, and might thus attract bi-partisan support, it accelerates benefits that project developers would otherwise have to wait until their next tax filing to receive, and it probably lets some marginal projects that might not otherwise find private funding escape winnowing. If the lame duck doesn't pass this, the odds of the 112th Congress extending it or anything else connected to the stimulus look poor.
Ultimately the likelihood of meaningful energy legislation of any kind will hinge on the willingness of the President and the new Congress to meet somewhere in the middle to get things done. Otherwise, the scope is limited to a few lowest-common-denominator efforts, which might include a modest national renewable electricity standard, with everything else effectively blocked by the other chamber of Congress or the President's veto pen. I don't expect to lack for topics on which to blog in the next two years.
Monday, November 01, 2010
What Won't Change After the Election?
Tomorrow's US mid-term election dominates today's headlines, with most analysts expecting a dramatic shift in control, at least in the House of Representatives. However, from an energy perspective, many aspects of the situation in which we will find ourselves after the ballots are counted will remain largely predetermined for the next two years, going into the 2012 election. As candidates debate differing perspectives on energy it's worth recalling the tremendous inertia of our energy systems. The seeds of significant change have already been planted and are promoting a gradual transformation, but the results will be more evident when we look back at the end of the decade than while it is underway.
One given is that for at least the next two years, fossil fuels will continue to supply well over 90% of US transportation energy and more than 2/3rds of US electricity generation, with nuclear and conventional hydropower accounting for more than 80% of the low-emitting remainder. Even though wind and solar power are still growing rapidly, though the former has slowed down appreciably compared to last year, they are still too small to make a significant difference in our consumption or emissions, and that will remain the case in 2012. Advocates of wind power and other renewables lament the lack of comprehensive energy legislation or a more focused national renewable electricity standard, but weak fundamentals have at least as much to do with the slowing rate of wind installations. US electricity demand has recovered somewhat from its low point last year, but it remains around 2% below its high of 2007. That has made utilities more reluctant to add generation of any kind, particularly in light of the strong emphasis on efficiency measures in the policies enacted in the last several years, starting with the Energy Independence and Security Act of 2007 and reinforced by last year's stimulus.
Another given is that oil will continue to dominate our concerns about energy security. The economic slowdown reduced net US imports of crude oil and petroleum products by 20%, compared to 2007, but even at this level imports are still a third larger than domestic production of crude oil and natural gas liquids--a disparity that is set to grow for two reasons. First, the greatly reduced rate of drilling in the Gulf of Mexico following the Deepwater Horizon disaster and the moratorium that was imposed in response is already starting to reverse the gains in US oil output that we saw in the last several years. Mature offshore fields are declining, while new projects will be slower to come online. Not even the remarkable success of onshore drilling in the Bakken formation of the Dakotas and Montana, which has moved North Dakota up to number four among oil producing states--past perennial heavyweights like Louisiana and Oklahoma--is likely to compensate for slower growth from the Gulf.
Nor are biofuels likely to add enough production in the next two years to avoid an increase in our oil imports, as ethanol approaches the limits of corn ethanol output and faces the expiration of the tax credit it has enjoyed since 1978. And while the proliferation of hybrids, electric vehicles and other efficient car models is a step in the right direction, their numbers are too small for now to counteract any increase in miles traveled. Even a modest amount of demand growth from a recovering economy will set US oil and refined product imports climbing again, with a corresponding impact on world oil prices and our trade deficit.
There's little doubt that the incoming 112th Congress will have a different approach to energy and its related environmental issues than the outgoing 111th has had. That could prove significant for many aspects of US energy policy, including climate policy. At the same time, the new members of the House and Senate are likely to find, as past Congresses have, that our energy challenges are less responsive to intervention than they assumed. I wouldn't be surprised if the biggest impact on energy in the next two years comes not from energy legislation, but from the indirect effect of whatever steps are taken to address our larger economic problems.
One given is that for at least the next two years, fossil fuels will continue to supply well over 90% of US transportation energy and more than 2/3rds of US electricity generation, with nuclear and conventional hydropower accounting for more than 80% of the low-emitting remainder. Even though wind and solar power are still growing rapidly, though the former has slowed down appreciably compared to last year, they are still too small to make a significant difference in our consumption or emissions, and that will remain the case in 2012. Advocates of wind power and other renewables lament the lack of comprehensive energy legislation or a more focused national renewable electricity standard, but weak fundamentals have at least as much to do with the slowing rate of wind installations. US electricity demand has recovered somewhat from its low point last year, but it remains around 2% below its high of 2007. That has made utilities more reluctant to add generation of any kind, particularly in light of the strong emphasis on efficiency measures in the policies enacted in the last several years, starting with the Energy Independence and Security Act of 2007 and reinforced by last year's stimulus.
Another given is that oil will continue to dominate our concerns about energy security. The economic slowdown reduced net US imports of crude oil and petroleum products by 20%, compared to 2007, but even at this level imports are still a third larger than domestic production of crude oil and natural gas liquids--a disparity that is set to grow for two reasons. First, the greatly reduced rate of drilling in the Gulf of Mexico following the Deepwater Horizon disaster and the moratorium that was imposed in response is already starting to reverse the gains in US oil output that we saw in the last several years. Mature offshore fields are declining, while new projects will be slower to come online. Not even the remarkable success of onshore drilling in the Bakken formation of the Dakotas and Montana, which has moved North Dakota up to number four among oil producing states--past perennial heavyweights like Louisiana and Oklahoma--is likely to compensate for slower growth from the Gulf.
Nor are biofuels likely to add enough production in the next two years to avoid an increase in our oil imports, as ethanol approaches the limits of corn ethanol output and faces the expiration of the tax credit it has enjoyed since 1978. And while the proliferation of hybrids, electric vehicles and other efficient car models is a step in the right direction, their numbers are too small for now to counteract any increase in miles traveled. Even a modest amount of demand growth from a recovering economy will set US oil and refined product imports climbing again, with a corresponding impact on world oil prices and our trade deficit.
There's little doubt that the incoming 112th Congress will have a different approach to energy and its related environmental issues than the outgoing 111th has had. That could prove significant for many aspects of US energy policy, including climate policy. At the same time, the new members of the House and Senate are likely to find, as past Congresses have, that our energy challenges are less responsive to intervention than they assumed. I wouldn't be surprised if the biggest impact on energy in the next two years comes not from energy legislation, but from the indirect effect of whatever steps are taken to address our larger economic problems.
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