While reading an article on oil company taxation in the Wall Street Journal, I ran across a quote from Treasury Secretary Geithner that crystallized my growing impression that the administration has misinterpreted its own mantra on energy and is training its "friend or foe" radar on the wrong enemy. I would paraphrase the Obama energy strategy as seeking to reduce US oil imports and greenhouse gas emissions by strongly promoting renewable energy and energy efficiency. Unfortunately, the administration's actions risk putting the domestic oil and gas industry on the wrong side of the divide that creates. Absent the steady output from our oil & gas producers, improved energy security--let alone energy independence--would become simply unattainable no matter how many wind turbines and solar panels we build in the next few years. Domestic oil & gas is not the enemy; it is a natural ally in the administration's quest to wean the US from our harmful over-reliance on foreign oil.
Policy makers must have a clear understanding of the country's energy balance and the relative contributions of our different sources. I looked at these "Big Chunks" in some detail in January. Domestic oil and gas production covers 34% of the nation's energy needs. Imported oil provides another 28%, and that's the chunk we need to focus on, along with the emissions from coal-fired power plants. When Secretary Geithner said, "We don't believe it makes sense to significantly subsidize the production and use of sources of energy that are dramatically going to add to our climate change," he was implicitly lumping oil and gas from all sources together with coal. Although he was correct to the extent that domestic oil and gas--just like the imported varieties--emit CO2 and other greenhouse gases, there is simply no way to keep the US economy running in the near-to-medium term without them, emissions or not.
Consider the latest figures from the Energy Information Agency of the Department of Energy. In 2008 "other renewables", excluding hydropower, generated 3% of the US electricity supply. Wind, solar and geothermal power--the non-hydro renewables that the President has targeted for doubling in the next three years--contributed just over half of that, or 1.6% of the total. That's up from 1.2% last year, for an impressive growth rate of 36%. If the renewable energy sector can maintain that growth for three years, helped by the stimulus package, it should easily double to 3.2% of our electricity supply. That might push the broader "other renewables" category close to 5%, and total renewables including hydropower to 10 or 11%--but all without displacing more than a tiny amount of oil, because oil (including petroleum coke) accounted for just 1.1% of net electricity generation last year, and plug-in vehicles aren't yet a measurable fraction of our vehicle fleet. Oil-burning power plants consumed 165,000 bbl/day, a paltry 0.8% of US petroleum demand. Even if the output of every new wind turbine and solar panel were devoted to backing out oil-fired power--a practical impossibility, given the geographical and time-of-use patterns involved--it wouldn't make a dent in our oil imports.
Increasing the tax burden on the oil and gas industry, by contrast, would most assuredly make a dent in our oil imports--by expanding them. Despite a recent uptick in oil prices, oil companies have seen their cash flows decline significantly in the last nine months. Under pressure to support dividends, those that can still borrow to maintain their capital investment programs are doing so; others have had to defer projects or sell off assets. Increasing their tax burden by revoking long-standing oil & gas tax breaks and singling the industry out for exclusion from a tax benefit offered to all US manufacturers, even with the logic of leveling the playing field for energy sources that emit greenhouse gases relative to those that don't, would be ill-timed, at best.
When the industry argued against higher taxes last year, some suggested that we were entitled to raise taxes on oil companies because political risk was lower in the US than elsewhere, while companies were denied access to key resources overseas. Those comparisons have shifted noticeably, as producing countries have become more receptive to foreign investment in their oil industries, thanks to the rigors of lower oil revenues. At the same time, political risk here has increased, as described in a provocative op-ed by Ian Bremmer of the Eurasia Group. The energy industry has already seen signs of this, in a proposal for an excise tax targeting companies that refuse to renegotiate the royalty relief provisions of certain Gulf of Mexico deepwater lease contracts, which were recently upheld in court. No business leader can watch the current spectacle of "outrage" and fail to wonder when he or she will sit in the hot seat.
This isn't a question of seeking sympathy for companies that have just come off a streak of record-setting profits, most of which were plowed back into the business or returned to shareholders. That would be as fruitless as soliciting aid for AIG's financial products employees. Rather, we need to look to our self-interest, here. When an oil company drills in the US, its production backs out imports directly, barrel for barrel. It pays US salaries--attractive ones--and it pays hefty taxes: income taxes at a 40% effective rate, along with billions of dollars in royalties, rents and bonus bids collected by the government. When a US oil company drills elsewhere, much of the benefit is captured by foreign governments, and when the oil we import comes from a non-US supplier, our trade deficit swells and the federal government only gets to tax the profits on refining & marketing, which are often pretty thin.
In the future, when we've cracked the code for producing liquid fuels cheaply from abundant non-food biomass, covered our hills and shorelines with wind farms and our deserts and roofs with solar arrays, and have sufficient domestic energy supplies--used efficiently--to back out the last of our oil imports, then the time will be ripe to talk about winding down the domestic oil industry, along with the emissions from the remaining petroleum products. Until then, rather than penalizing them on the basis of fractured logic suggesting this will somehow reduce our oil consumption, it is very much in the public interest for the government to treat the domestic oil industry as a partner, not a foe, and refrain from making it less attractive to drill in the US.
Friday, March 27, 2009
Wednesday, March 25, 2009
It's the Economy
Yesterday afternoon I attended a panel discussion in the Capitol building, featuring one Senator, two Members of the House of Representatives, the new CEO of API and two senior journalists from Newsweek, which hosted the event. The discussion covered a wide array of energy topics, including offshore drilling, taxation, renewables, and climate change. Although there weren't many surprises, I was not expecting to hear such uniform skepticism on the prospects for passage this year of a cap & trade bill regulating emissions in the manner proposed by President Obama. With the exception of the Honorable Doc Hastings (R, WA), who questioned the contribution of anthropogenic CO2 to climate change, the common theme appeared to be that the dire state of the economy and the need for sensible energy policy take precedence over stronger action targeting greenhouse gas emissions. In this regard, these elected representatives are attuned to the views reflected in a new national Gallup poll. For the first time since at least the mid-1980s, a majority of Americans place a higher priority on the economy than on protecting the environment. As much as that shift might disappoint environmentalists, a sound economy is the logical precondition for building a sustainable national policy to address climate change.
All three Congressional participants on yesterday's panel were from states or districts with a vested interest in energy. If anything, I would have been more surprised if this group had indicated unwavering support for the immediate imposition of cap & trade. Senator Landrieu (D, LA) represents a state that ranks fourth in US oil production, without counting the contribution from federal waters offshore Louisiana. Representative Rahall (D, WV) chairs the House Natural Resources Committee and hails from a major coal state. And while Washington might not be top of mind as an energy state, Congressman Hastings's 4th District encompasses Columbia River hydroelectric dams, a nuclear power plant, and the DOE's Hanford nuclear site. Still, the concerns expressed by both Democrats suggest that the President cannot count on a party line vote to deliver cap & trade, if it is seen as threatening vital industries and the health of the economy as a whole.
A few weeks ago, I examined the President's proposed budget and the levels of cap & trade permit revenue it included. Since then, the non-partisan Congressional Budget Office has analyzed the budget and concluded that its estimates of the ten-year federal deficit relied on overly-optimistic assumptions of future economic growth and would likely be $2.3 trillion worse than forecast. At the same time, it appears that the original estimate of $646 billion in revenue from cap & trade was highly conservative, with likely proceeds in the range of $1.3-1.9 trillion. Those figures are certainly more in line with the level of carbon prices necessary to stimulate large emissions reduction. $12/ton of CO2 wouldn't cover even the lowest-cost estimate for carbon capture and sequestration, let alone make solar power competitive with natural gas. The roughly $35/ton consistent with $1.9 trillion in permit revenue from 2012-2019 comes much closer to the mark. However, unless the Congress goes along with the President's plan to refund most of the proceeds to taxpayers, that more realistic outcome would result in a much bigger net tax on a weaker economy than the President's staff assumed.
This creates a terrible dilemma. From the perspective of those most concerned about the risks of climate change, we are very late in putting a price on emissions of CO2 and other greenhouse gases, in order to accelerate the transition to greener energy sources and bolster the existing incentives for renewable energy and efficiency investments. Yet it is also apparent from both the Gallup poll and long experience in observing developing countries that unless the economy returns to healthy growth, the wherewithal to pay such a price--and perhaps more importantly the political will to impose it--won't be sufficient. Poor countries, or those that feel poor, are understandably reluctant to pay for environmental protection, particularly when the consequences of not paying are deferred for years or decades. Anyone questioning that logic should spend a moment revisiting Maslow's Hierarchy of Needs.
Any cap & trade bill introduced this year must take into account the dramatic changes since last year's Boxer-Lieberman-Warner bill was debated. It must be structured to minimize the impact on the struggling economy. In practical terms, that means deferring the onset of emissions caps until a recovery is confirmed to be well underway and diverting no more than the President's target of $15 billion per year for energy R&D from the refund of all proceeds to taxpayers, including the businesses that will be burdened with buying trillions of dollars worth of emissions permits. Failure to do so would jeopardize the recovery and doom cap & trade. That's crucial, because mitigating climate change won't be accomplished within the term of one President; it requires commitments that must be sustained for decades. If those commitments are pitted against the public's aspirations for prosperity, they are unlikely to be sustained long enough to do any good.
All three Congressional participants on yesterday's panel were from states or districts with a vested interest in energy. If anything, I would have been more surprised if this group had indicated unwavering support for the immediate imposition of cap & trade. Senator Landrieu (D, LA) represents a state that ranks fourth in US oil production, without counting the contribution from federal waters offshore Louisiana. Representative Rahall (D, WV) chairs the House Natural Resources Committee and hails from a major coal state. And while Washington might not be top of mind as an energy state, Congressman Hastings's 4th District encompasses Columbia River hydroelectric dams, a nuclear power plant, and the DOE's Hanford nuclear site. Still, the concerns expressed by both Democrats suggest that the President cannot count on a party line vote to deliver cap & trade, if it is seen as threatening vital industries and the health of the economy as a whole.
A few weeks ago, I examined the President's proposed budget and the levels of cap & trade permit revenue it included. Since then, the non-partisan Congressional Budget Office has analyzed the budget and concluded that its estimates of the ten-year federal deficit relied on overly-optimistic assumptions of future economic growth and would likely be $2.3 trillion worse than forecast. At the same time, it appears that the original estimate of $646 billion in revenue from cap & trade was highly conservative, with likely proceeds in the range of $1.3-1.9 trillion. Those figures are certainly more in line with the level of carbon prices necessary to stimulate large emissions reduction. $12/ton of CO2 wouldn't cover even the lowest-cost estimate for carbon capture and sequestration, let alone make solar power competitive with natural gas. The roughly $35/ton consistent with $1.9 trillion in permit revenue from 2012-2019 comes much closer to the mark. However, unless the Congress goes along with the President's plan to refund most of the proceeds to taxpayers, that more realistic outcome would result in a much bigger net tax on a weaker economy than the President's staff assumed.
This creates a terrible dilemma. From the perspective of those most concerned about the risks of climate change, we are very late in putting a price on emissions of CO2 and other greenhouse gases, in order to accelerate the transition to greener energy sources and bolster the existing incentives for renewable energy and efficiency investments. Yet it is also apparent from both the Gallup poll and long experience in observing developing countries that unless the economy returns to healthy growth, the wherewithal to pay such a price--and perhaps more importantly the political will to impose it--won't be sufficient. Poor countries, or those that feel poor, are understandably reluctant to pay for environmental protection, particularly when the consequences of not paying are deferred for years or decades. Anyone questioning that logic should spend a moment revisiting Maslow's Hierarchy of Needs.
Any cap & trade bill introduced this year must take into account the dramatic changes since last year's Boxer-Lieberman-Warner bill was debated. It must be structured to minimize the impact on the struggling economy. In practical terms, that means deferring the onset of emissions caps until a recovery is confirmed to be well underway and diverting no more than the President's target of $15 billion per year for energy R&D from the refund of all proceeds to taxpayers, including the businesses that will be burdened with buying trillions of dollars worth of emissions permits. Failure to do so would jeopardize the recovery and doom cap & trade. That's crucial, because mitigating climate change won't be accomplished within the term of one President; it requires commitments that must be sustained for decades. If those commitments are pitted against the public's aspirations for prosperity, they are unlikely to be sustained long enough to do any good.
Monday, March 23, 2009
Assessing Trade-Offs
Today's posting serves in lieu of a letter to the editors of the New York Times, in response to the misleading comparisons drawn in today's editorial concerning the "Lessons of the Exxon Valdez." The editorial characterizes oil development as "an inherently risky, dirty business — especially so in the forbidding waters of the Arctic." It goes on to draw a comparison between the $2 billion per year Alaskan fishing business in Bristol Bay and the presumed value of future oil and gas production from this area, concluding that the trade-off is not worth the risk. It suggests that the new Secretary of the Interior focus on promoting wind and tidal energy, instead. Unfortunately, their assessment of the trade-offs involved is undermined by the use of a resource estimate that appears to have been misinterpreted from its original source.
Whether the Times drew its estimate of $8 billion of potential hydrocarbon revenue for Bristol Bay from a 2008 World Wildlife Fund report citing a US Minerals Management Service (MMS) estimate of 230 million barrels of oil and 6.79 trillion cubic feet (TCF) of natural gas, or merely draws on the same ultimate source, I found a rather different estimate in the official report of the MMS to the Congress, as mandated under the Energy Policy Act of 2005 . It reflected a range for the North Aleutian Basin, encompassing Bristol Bay, of 20 million to 2.5 billion barrels of oil and 0.04-23.3 TCF of gas, with a mean estimate of 750 million barrels and 8.62 TCF. At $70/bbl for oil and $6/MCF for natural gas, reflecting current long-dated futures prices, the mean expected value of the "undiscovered, technically recoverable resources" around Bristol Bay would be on the order of $100 billion, rather than $8 billion.
But even that assessment provides a poor basis for comparison, because of the economic criteria that would be applied to any oil or gas discoveries in Bristol Bay. No one can know how much oil and gas is actually under the waters of the North Aleutian Basin, without at least performing a seismic survey and interpreting the results, which would then have to be confirmed with the drill bit. Nor would a positive result from such tests guarantee development, even at the prices cited above. As the Times notes, Alaska is a hostile environment. That raises the costs of exploration and extraction. The minimum resource size required to justify building a production platform would generally be higher than in the Gulf Coast. Oil finds much below that 750 million barrel mean estimate would be unlikely to be pursued, and the outlook is even tougher for gas, for which there is insufficient local demand.
In light of these facts, the balance of risks from allowing lease sales in Bristol Bay looks quite different from the one indicated by the Times, in which we might jeopardize a world-class fishery resource for an inconsequential amount of oil and gas. In reality, whatever risks hydrocarbon development entails would only arise in the eventuality that a world-class oil or gas resource were found there. Otherwise, the government would pocket the bid premiums and rental fees, the local economy would get some welcome revenue during the assessment process, and that would probably be the end of it. It's also high time for the editors of a paper that likes to be thought of as the nation's newspaper of record to recognize that renewable electricity does not function as an oil substitute and won't be in a position to do so until there are millions of electric vehicles on the road. We're going to need billions of barrels of new oil discoveries as we make the long transition to greener energy sources.
Whether the Times drew its estimate of $8 billion of potential hydrocarbon revenue for Bristol Bay from a 2008 World Wildlife Fund report citing a US Minerals Management Service (MMS) estimate of 230 million barrels of oil and 6.79 trillion cubic feet (TCF) of natural gas, or merely draws on the same ultimate source, I found a rather different estimate in the official report of the MMS to the Congress, as mandated under the Energy Policy Act of 2005 . It reflected a range for the North Aleutian Basin, encompassing Bristol Bay, of 20 million to 2.5 billion barrels of oil and 0.04-23.3 TCF of gas, with a mean estimate of 750 million barrels and 8.62 TCF. At $70/bbl for oil and $6/MCF for natural gas, reflecting current long-dated futures prices, the mean expected value of the "undiscovered, technically recoverable resources" around Bristol Bay would be on the order of $100 billion, rather than $8 billion.
But even that assessment provides a poor basis for comparison, because of the economic criteria that would be applied to any oil or gas discoveries in Bristol Bay. No one can know how much oil and gas is actually under the waters of the North Aleutian Basin, without at least performing a seismic survey and interpreting the results, which would then have to be confirmed with the drill bit. Nor would a positive result from such tests guarantee development, even at the prices cited above. As the Times notes, Alaska is a hostile environment. That raises the costs of exploration and extraction. The minimum resource size required to justify building a production platform would generally be higher than in the Gulf Coast. Oil finds much below that 750 million barrel mean estimate would be unlikely to be pursued, and the outlook is even tougher for gas, for which there is insufficient local demand.
In light of these facts, the balance of risks from allowing lease sales in Bristol Bay looks quite different from the one indicated by the Times, in which we might jeopardize a world-class fishery resource for an inconsequential amount of oil and gas. In reality, whatever risks hydrocarbon development entails would only arise in the eventuality that a world-class oil or gas resource were found there. Otherwise, the government would pocket the bid premiums and rental fees, the local economy would get some welcome revenue during the assessment process, and that would probably be the end of it. It's also high time for the editors of a paper that likes to be thought of as the nation's newspaper of record to recognize that renewable electricity does not function as an oil substitute and won't be in a position to do so until there are millions of electric vehicles on the road. We're going to need billions of barrels of new oil discoveries as we make the long transition to greener energy sources.
Friday, March 20, 2009
Rebound or Dead Cat?
US light sweet crude oil closed above $50 per barrel yesterday for the first time since late November. The financial press appears to attribute this mainly to the weakening of the dollar and inflationary expectations triggered by the Federal Reserve's decision to purchase over a trillion dollars of securities, in a bid to reduce longer-term interest rates. Although I don't discount these concerns, a review of oil's fundamentals suggests there are other factors at work, as well. The recovery in oil prices from the mid-$30s has involved more than a one-day rally, nearly a dollar of which had abated as of this morning. It is hardly the kind of rebound we might expect once the recession eases, but if it is sustained it should remind consumers that the current price relief on petroleum products is temporary, while sending producers a positive signal on the need for continued resource development.
Yesterday's weekly statistics from the Energy Information Agency showed that US inventories of crude oil and its two main fuel products, gasoline and distillate (diesel/heating oil), continue to build. But while distillate demand remains very weak, reflecting the decline in goods movement that accompanies a slowdown in economic activity, calculated gasoline demand has returned to within a percent or so of its year-ago level. Gasoline imports are running at a million barrels per day. All of this provides refiners some welcome headroom for their traditional spring-time switch into maximum-gasoline mode, after having optimized on distillate production during the winter. If demand were still as weak as it was a few months ago with gasoline inventories this high, any rally in oil prices would quickly extinguish itself.
Weakness in the dollar relative to other key currencies can also drive crude prices higher. This effect contributed to the extraordinary spike in oil prices from mid-2007 to mid-2008. But many of the factors that fed the resulting "oil-dollar price loop" look too anemic now to create a sustaining pattern of this type, amid the global recession and credit crunch. A slight decline in the Euro or Yen price of oil seems unlikely to stimulate much demand. Unless the dollar continued to weaken progressively, turning its recent 8% slide against the Euro into something more serious, it's hard to see this sustaining higher oil prices against the fundamentals.
The notion of oil as an inflation hedge is another matter. Traders aren't the only ones who get the jitters at the thought of the US government printing money to buy its way out of our current problems. However, inflation worries seem premature when deflation remains a serious risk. The latest report on seasonally-adjusted US consumer prices showed "core inflation"--excluding food and energy--rising at a sub-2% clip, while the three-month and twelve-month averages for the prices of all items are still in negative territory. The whole point of the stimulus bill was to soak up the enormous slack capacity in the economy, and until that begins to bite, the idea of too much money chasing too few goods seems a remote prospect. Nor did oil work out very well as an inflation hedge last summer, when the CPI was growing at more than 5% per year.
And that brings me back to oil's fundamentals. The fact that the market didn't swoon when OPEC met and decided to defer further cuts suggests that they have reduced output sufficiently--and are living up to their lower quotas well enough--to create an environment in which events such as the Fed's move can be seen as bullish. It wasn't long ago that it seemed nothing could drive up oil prices for more than a day or two. At the same time, oil's recent moves haven't flattened out the remarkable degree of "contango" that I observed in December. Oil futures for delivery twelve months from now are $10/bbl higher than the front-month price. That suggests the market is still weighed down by high inventories and tight credit, impeding the obvious arbitrage opportunity such wide spreads create. A more dramatic rebound in oil prices must still wait for the global economy to begin to turn around and draw down that overhang. In the meantime, though, the 50% appreciation of oil from its low on February 12th looks like rather more than the proverbial bounce of a dead cat.
Yesterday's weekly statistics from the Energy Information Agency showed that US inventories of crude oil and its two main fuel products, gasoline and distillate (diesel/heating oil), continue to build. But while distillate demand remains very weak, reflecting the decline in goods movement that accompanies a slowdown in economic activity, calculated gasoline demand has returned to within a percent or so of its year-ago level. Gasoline imports are running at a million barrels per day. All of this provides refiners some welcome headroom for their traditional spring-time switch into maximum-gasoline mode, after having optimized on distillate production during the winter. If demand were still as weak as it was a few months ago with gasoline inventories this high, any rally in oil prices would quickly extinguish itself.
Weakness in the dollar relative to other key currencies can also drive crude prices higher. This effect contributed to the extraordinary spike in oil prices from mid-2007 to mid-2008. But many of the factors that fed the resulting "oil-dollar price loop" look too anemic now to create a sustaining pattern of this type, amid the global recession and credit crunch. A slight decline in the Euro or Yen price of oil seems unlikely to stimulate much demand. Unless the dollar continued to weaken progressively, turning its recent 8% slide against the Euro into something more serious, it's hard to see this sustaining higher oil prices against the fundamentals.
The notion of oil as an inflation hedge is another matter. Traders aren't the only ones who get the jitters at the thought of the US government printing money to buy its way out of our current problems. However, inflation worries seem premature when deflation remains a serious risk. The latest report on seasonally-adjusted US consumer prices showed "core inflation"--excluding food and energy--rising at a sub-2% clip, while the three-month and twelve-month averages for the prices of all items are still in negative territory. The whole point of the stimulus bill was to soak up the enormous slack capacity in the economy, and until that begins to bite, the idea of too much money chasing too few goods seems a remote prospect. Nor did oil work out very well as an inflation hedge last summer, when the CPI was growing at more than 5% per year.
And that brings me back to oil's fundamentals. The fact that the market didn't swoon when OPEC met and decided to defer further cuts suggests that they have reduced output sufficiently--and are living up to their lower quotas well enough--to create an environment in which events such as the Fed's move can be seen as bullish. It wasn't long ago that it seemed nothing could drive up oil prices for more than a day or two. At the same time, oil's recent moves haven't flattened out the remarkable degree of "contango" that I observed in December. Oil futures for delivery twelve months from now are $10/bbl higher than the front-month price. That suggests the market is still weighed down by high inventories and tight credit, impeding the obvious arbitrage opportunity such wide spreads create. A more dramatic rebound in oil prices must still wait for the global economy to begin to turn around and draw down that overhang. In the meantime, though, the 50% appreciation of oil from its low on February 12th looks like rather more than the proverbial bounce of a dead cat.
Wednesday, March 18, 2009
Zero Emissions?
The other day I ran across reports of a curious event, in which the Attorney General of the state of Vermont convinced Entergy, which owns or operates 11 of the nation's 104 active nuclear power plants, to back away from characterizing nuclear power as having zero emissions. Technically, of course, the AG was correct. However, as a reader reminded me, it is equally true that such unambiguously "green" energy sources as wind and solar power also entail emissions greater than zero--a fact that appeared not to trouble Mr. Sorrell. This situation highlights another important gap in the public debate over energy and the environment. The solution lies in better public education and clearer reporting of absolute and relative emissions, based on numerous studies detailing the lifecycle emissions of our various energy sources. We might also apply some common sense to this complex technical issue. Unfortunately, the resolution of the Vermont dispute leaves the public with the mistaken impression that, at least in terms of greenhouse gas emissions, nuclear power is not in the same league as our favored renewables.
The misunderstanding in the Green Mountain State reflects a common inconsistency in the way that we look at the emissions of energy sources. In the last few years it has become pretty routine, at least in the better-informed media, to report the emissions from fuels and the vehicles and stationary facilities that consume them on the basis not just of what comes out of a tailpipe or smoke stack, but by tallying all emissions from extraction and production through to end-use: a technique referred to as "well-to-wheels" analysis, or more generically as "lifecycle" analysis when no actual wheels are involved. Energy sources that don't burn fuels have often escaped this level of rigor and tended to be clumped together as zero-emission sources. That includes nuclear power, wind, solar, geothermal, and hydropower. All of these entail a modest level of "embodied" emissions associated with their construction or manufacture, including the direct and indirect emissions from the conversion of raw materials, machining and assembly of components, and transportation to their operating sites. Nuclear power is different in one respect, in that it also consumes a fuel, the production of which--though not its use--results in some emissions. That hardly justifies lumping nuclear power in with coal, oil and natural gas burners, and drawing a misleading distinction from the embodied emissions of other low-GHG energy.
A web search turned up numerous references that quantify the lifecycle emissions from all these electricity sources. A recent report to the International Energy Agency on electricity in Japan, for example, cited cradle-to-grave GHG emissions from nuclear power at 29 grams of CO2 per generated kWh, equal to those from wind power and roughly double those from geothermal and hydropower, but half the emissions from solar photovoltaic power (PV). By comparison, the lowest fossil fuel emissions in Japan come from combined-cycle gas turbine plants running on imported LNG. Those averaged 519 g/kWh. Then there's the study from the University of Wisconsin, which shows nuclear at 17 g/kWh, beaten only by wind and geothermal, but exceeded by every other renewable source. Finally, I was amused to find the website of the Windham Regional Commission in Vermont hosting a report from the Nuclear Energy Institute bracketing nuclear power between hydro and geothermal and lower than PV and biomass power.
Rather than seeking to highlight the inconsistency of a government official--cue Captain Renault, here--I'd like to propose the common-sense application of a two-tier standard to this problem. All energy and environmental decisions involving comparisons of different energy sources and devices, particularly when they result in money changing hands, should certainly be made on the basis of full and careful lifecycle analysis. For general discussion purposes, however--most likely including the ads that offended the group that appealed to the Attorney General of Vermont--the emissions from wind, solar, geothermal, hydroelectric and nuclear power are all so much lower than those from coal, oil and natural gas that it seems entirely reasonable to treat them as effectively zero. Perhaps Entergy should reconsider its retraction on this basis.
The misunderstanding in the Green Mountain State reflects a common inconsistency in the way that we look at the emissions of energy sources. In the last few years it has become pretty routine, at least in the better-informed media, to report the emissions from fuels and the vehicles and stationary facilities that consume them on the basis not just of what comes out of a tailpipe or smoke stack, but by tallying all emissions from extraction and production through to end-use: a technique referred to as "well-to-wheels" analysis, or more generically as "lifecycle" analysis when no actual wheels are involved. Energy sources that don't burn fuels have often escaped this level of rigor and tended to be clumped together as zero-emission sources. That includes nuclear power, wind, solar, geothermal, and hydropower. All of these entail a modest level of "embodied" emissions associated with their construction or manufacture, including the direct and indirect emissions from the conversion of raw materials, machining and assembly of components, and transportation to their operating sites. Nuclear power is different in one respect, in that it also consumes a fuel, the production of which--though not its use--results in some emissions. That hardly justifies lumping nuclear power in with coal, oil and natural gas burners, and drawing a misleading distinction from the embodied emissions of other low-GHG energy.
A web search turned up numerous references that quantify the lifecycle emissions from all these electricity sources. A recent report to the International Energy Agency on electricity in Japan, for example, cited cradle-to-grave GHG emissions from nuclear power at 29 grams of CO2 per generated kWh, equal to those from wind power and roughly double those from geothermal and hydropower, but half the emissions from solar photovoltaic power (PV). By comparison, the lowest fossil fuel emissions in Japan come from combined-cycle gas turbine plants running on imported LNG. Those averaged 519 g/kWh. Then there's the study from the University of Wisconsin, which shows nuclear at 17 g/kWh, beaten only by wind and geothermal, but exceeded by every other renewable source. Finally, I was amused to find the website of the Windham Regional Commission in Vermont hosting a report from the Nuclear Energy Institute bracketing nuclear power between hydro and geothermal and lower than PV and biomass power.
Rather than seeking to highlight the inconsistency of a government official--cue Captain Renault, here--I'd like to propose the common-sense application of a two-tier standard to this problem. All energy and environmental decisions involving comparisons of different energy sources and devices, particularly when they result in money changing hands, should certainly be made on the basis of full and careful lifecycle analysis. For general discussion purposes, however--most likely including the ads that offended the group that appealed to the Attorney General of Vermont--the emissions from wind, solar, geothermal, hydroelectric and nuclear power are all so much lower than those from coal, oil and natural gas that it seems entirely reasonable to treat them as effectively zero. Perhaps Entergy should reconsider its retraction on this basis.
Monday, March 16, 2009
Building the Low-Emissions Future
Last week The Economist published a detailed assessment of the state of play for capturing and storing the carbon dioxide emitted by power plants and factories. Although it skirted the assertion of many environmentalists that "clean coal" is inherently an oxymoron, the article's tone was generally skeptical concerning the cost and ultimate efficacy of the technology. Coincidentally, Greenpeace released a study featuring an ultra-low-carbon scenario created in conjunction with the European Renewable Energy Council. It proposes that by 2050 the US could shed all coal-fired power generation, as well as all nuclear power and most natural gas-fired power, along with nearly 80% of the petroleum used in transportation--all replaced by renewable electricity and biofuels. If the Economist regards carbon capture and sequestration (CCS) as "expensive and unproven", I can only imagine the terms it might use to describe the extraordinary transformation required to achieve the outcome Greenpeace envisions. The necessity of reducing greenhouse gas emissions dramatically by mid-century and the serious obstacles to replacing our entire energy economy with renewable energy sources in that time frame reinforce the importance of continuing to pursue CCS, in spite of its uncertainties.
I've been following CCS for a long time, and I've written about it many times on this blog. Without diminishing the technical challenges involved, I see them as being manageable with existing and foreseeable engineering know-how, without a scientific breakthrough. I attribute the prolonged absence of a large-scale demonstration of fully-integrated CCS on energy sources more carbon-intensive than natural gas to the mismatch between its costs and current monetary benefits. Whether the cost proves to be closer to the low or high end of the range of estimates included in the article, from roughly $40-115 per ton of captured CO2, it's hard to imagine a utility or oil company taking on the investment and operating expenses involved without the incentive of a transparent and fairly predictable price on carbon emissions. Whatever the cost of CCS might be, it can't be considered in a vacuum, and that is the biggest shortcoming of the Economist's otherwise thorough analysis.
As the US Congress prepares to embark on its latest effort to enact a greenhouse gas cap and trade bill, it's important to think about where its enormous pool of emissions savings will be found, and at what cost. CCS is only one option among many. Happily, a fair amount of work has been done in this regard, including a study by McKinsey & Co. for the Conference Board a little more than a year ago. A key chart from their report portrays a potential medium-term supply curve for emissions reductions. It indicates that while there might be a number of ways to cut CO2 at low or even negative cost--changes that would pay for themselves--achieving deeper cuts would require the contribution of costlier solutions, including CCS.
It's also worth noting that the current cost per ton of CO2 reductions from some of our current climate change strategies exceeds most estimates for CCS. In my recent posting on the application of energy storage to solar power, I calculated an effective cost of power for a couple of utility-scale solar projects in Florida at around $0.25/kWh. That's a premium of at least $0.20/kWh compared to a coal-fired power plant (without sequestration.) Based on typical emissions of 2.1 lb. of CO2 per kWh generated from coal, that implies an abatement cost of $190/ton of avoided CO2. In the likelier event that the power backed out by solar was generated from natural gas, the effective abatement cost could be even higher, because of the smaller emissions savings involved, despite the higher cost of gas-fired power compared to coal.
That comparison doesn't imply that solar power will always be a high-cost source of emissions reductions, or that CCS represents some kind of silver bullet for climate change. At the same time, coal now accounts for 23% of US primary energy consumption, 49% of our electricity generation, and nearly two-thirds of our baseload-capable generation. The difficulty of replacing baseload power with cyclical or intermittent sources makes me very skeptical of any low-emissions scenario that ignores CCS or assumes we can jettison coal entirely, not to mention forgoing nuclear power, the second-largest baseload power source in the US and by far our largest source of low-CO2 power. My specific comments on the Greenpeace scenario are posted elsewhere. At a minimum, any claims that it proves we can achieve the administration's 2050 emissions goals with only "green" energy options and efficiency gains are unwarranted. As useful as they are, scenarios can only point the way to possible futures. They can't provide firm proof of anything.
That leaves us with the hard work of cobbling together a broad set of climate solutions, in response to a price signal on emissions. In my assessment, that mix is very likely to include awkward elements such as CCS, along with deeply unglamorous things like improved farming and ranching practices. Contrary to the conclusions of the editorial accompanying the article on CCS, the technology is worth pursuing for reasons that have nothing to do with "placating the coal lobby." Nor does the cost of proving its feasibility look so high as to "deprive potentially cheaper methods of cutting emissions of cash and attention," particularly when the administration expects to carve out $120 billion for energy R&D from the proceeds of cap & trade over the next ten years. And even if it did, it's one of the few options that could be applied to reduce directly the emissions from the fossil fuels that still account for 85% of the energy we consume. That could make the difference between a manageable transition to a low-emissions world and an upheaval as bad as the current financial crisis.
I've been following CCS for a long time, and I've written about it many times on this blog. Without diminishing the technical challenges involved, I see them as being manageable with existing and foreseeable engineering know-how, without a scientific breakthrough. I attribute the prolonged absence of a large-scale demonstration of fully-integrated CCS on energy sources more carbon-intensive than natural gas to the mismatch between its costs and current monetary benefits. Whether the cost proves to be closer to the low or high end of the range of estimates included in the article, from roughly $40-115 per ton of captured CO2, it's hard to imagine a utility or oil company taking on the investment and operating expenses involved without the incentive of a transparent and fairly predictable price on carbon emissions. Whatever the cost of CCS might be, it can't be considered in a vacuum, and that is the biggest shortcoming of the Economist's otherwise thorough analysis.
As the US Congress prepares to embark on its latest effort to enact a greenhouse gas cap and trade bill, it's important to think about where its enormous pool of emissions savings will be found, and at what cost. CCS is only one option among many. Happily, a fair amount of work has been done in this regard, including a study by McKinsey & Co. for the Conference Board a little more than a year ago. A key chart from their report portrays a potential medium-term supply curve for emissions reductions. It indicates that while there might be a number of ways to cut CO2 at low or even negative cost--changes that would pay for themselves--achieving deeper cuts would require the contribution of costlier solutions, including CCS.
It's also worth noting that the current cost per ton of CO2 reductions from some of our current climate change strategies exceeds most estimates for CCS. In my recent posting on the application of energy storage to solar power, I calculated an effective cost of power for a couple of utility-scale solar projects in Florida at around $0.25/kWh. That's a premium of at least $0.20/kWh compared to a coal-fired power plant (without sequestration.) Based on typical emissions of 2.1 lb. of CO2 per kWh generated from coal, that implies an abatement cost of $190/ton of avoided CO2. In the likelier event that the power backed out by solar was generated from natural gas, the effective abatement cost could be even higher, because of the smaller emissions savings involved, despite the higher cost of gas-fired power compared to coal.
That comparison doesn't imply that solar power will always be a high-cost source of emissions reductions, or that CCS represents some kind of silver bullet for climate change. At the same time, coal now accounts for 23% of US primary energy consumption, 49% of our electricity generation, and nearly two-thirds of our baseload-capable generation. The difficulty of replacing baseload power with cyclical or intermittent sources makes me very skeptical of any low-emissions scenario that ignores CCS or assumes we can jettison coal entirely, not to mention forgoing nuclear power, the second-largest baseload power source in the US and by far our largest source of low-CO2 power. My specific comments on the Greenpeace scenario are posted elsewhere. At a minimum, any claims that it proves we can achieve the administration's 2050 emissions goals with only "green" energy options and efficiency gains are unwarranted. As useful as they are, scenarios can only point the way to possible futures. They can't provide firm proof of anything.
That leaves us with the hard work of cobbling together a broad set of climate solutions, in response to a price signal on emissions. In my assessment, that mix is very likely to include awkward elements such as CCS, along with deeply unglamorous things like improved farming and ranching practices. Contrary to the conclusions of the editorial accompanying the article on CCS, the technology is worth pursuing for reasons that have nothing to do with "placating the coal lobby." Nor does the cost of proving its feasibility look so high as to "deprive potentially cheaper methods of cutting emissions of cash and attention," particularly when the administration expects to carve out $120 billion for energy R&D from the proceeds of cap & trade over the next ten years. And even if it did, it's one of the few options that could be applied to reduce directly the emissions from the fossil fuels that still account for 85% of the energy we consume. That could make the difference between a manageable transition to a low-emissions world and an upheaval as bad as the current financial crisis.
Friday, March 13, 2009
Mark to Market
The practice of requiring banks and other businesses to mark their investments to market has drawn increasing criticism in the last several weeks from pundits and high-profile investors who would like to see it at least relaxed, if not rescinded. When I traded commodities in Texaco's international oil trading operation in London in the early 1990s I acquired some first-hand experience with "mark to market." Although I wasn't dealing with multi-billion dollar investments in exotic credit derivatives, the principles are sufficiently similar for me to offer some thoughts on the benefits and risks of this methodology, which appears to be feeding a vicious cycle of asset deflation in the financial sector.
The other night while watching our favorite TV cop show, "Life", my wife and I got a laugh out of the bumbled attempts of several of the characters to explain a derivative, and the confusion that greeted the accurate definition when it was finally given. I suspect the writers were reminding us how few people truly understand some of the financial instruments and regulations at the heart of the current crisis. Mark-to-market accounting likely falls into this category.
In the case of the futures market and physical oil market deals in which I was involved in London, the mark to market (MTM) provided a way to issue a daily report card on each of the trading positions we had taken on behalf of the company. This removed much of the element of surprise, if the value of something we had bought or sold changed significantly before the deal was ultimately completed. It entailed assigning a market-based price to each component of the deal at the end of every trading day, as if the product had been delivered or the position unwound that day, even though that might not actually happen for weeks. When the commodities in which we were dealing were ones for which there was an active, liquid market at all times, this accounting was relatively easy to perform. For some of the more unusual things we dealt in, for which there was no futures market and only occasional, sometimes unreliable reports of recent transactions, it generated uncertainty and anxiety.
The purpose of undertaking this effort, which consumed valuable time and was not exactly popular with the trading team, was to promote accountability and action. If the MTM on a particular trade showed a steady negative trend--particularly if it had moved from an expected profit to a loss--this triggered a discussion with management about why it was happening and what should be done. When handled well, this sometimes led to new insights about the market that we had failed to recognize. It normally resulted in a decision on whether to hang in there a bit longer, because we could justify our view that things would turn our way, or to modify or unravel the position--even at a loss--and regroup. Of course, that wasn't always possible; sometimes the cargo was on the water, bought and paid for, and there was nothing we could do but watch the red ink swell. That gets at the essence of my concern with the application of MTM to the big banks and institutions that the government has been forced to assist, for fear of "systemic risk"--the chance of the whole financial system crashing like the Blue Screen of Death on your PC.
Crucially, the reliability of mark to market depends on the ability to obtain an accurate reading of the value of what you are holding. That requires credible reporting of current transactions--preferably many of them--in something that, if not identical, at least looks enough like your asset to serve as a good proxy. If the only deals reported are distressed sales by desperate firms, you must write down your position to that level, even if you would never willingly sell it for so little. In the worst case a series of such write-downs causes a large enough deterioration in the balance sheet of the firm that it is compelled to sell some of these assets, driving their market value even lower and triggering a cascade of further sales by depressing the MTMs of other institutions.
Throughout the financial crisis, the practice of MTM has been defended as an unpleasant but necessary discipline to prevent an outcome such as was seen in Japan after its property bubble collapsed, with numerous "zombie banks" that were effectively insolvent but kept alive by the fictitious value of assets that were worth only a fraction of the level at which they were carried on the books. That argument still has some merit. However, it seems equally possible to destroy investor (and ultimately depositor) confidence in otherwise profitable, solvent institutions through the steady mechanical deflation of their illiquid assets, the potential buyers for which understand clearly that time is on their side.
Having run this experiment in its pure form until now, I'd like to see the administration test the opposite hypothesis for a few months: suspend MTM for bank capital purposes and restore the "uptick rule" on short-selling, while they're at it. We'd quickly find out whether these steps helped to stabilize the system. If they made things worse, they could quickly be reversed. It wouldn't be the first course correction we've seen during this crisis.
The other night while watching our favorite TV cop show, "Life", my wife and I got a laugh out of the bumbled attempts of several of the characters to explain a derivative, and the confusion that greeted the accurate definition when it was finally given. I suspect the writers were reminding us how few people truly understand some of the financial instruments and regulations at the heart of the current crisis. Mark-to-market accounting likely falls into this category.
In the case of the futures market and physical oil market deals in which I was involved in London, the mark to market (MTM) provided a way to issue a daily report card on each of the trading positions we had taken on behalf of the company. This removed much of the element of surprise, if the value of something we had bought or sold changed significantly before the deal was ultimately completed. It entailed assigning a market-based price to each component of the deal at the end of every trading day, as if the product had been delivered or the position unwound that day, even though that might not actually happen for weeks. When the commodities in which we were dealing were ones for which there was an active, liquid market at all times, this accounting was relatively easy to perform. For some of the more unusual things we dealt in, for which there was no futures market and only occasional, sometimes unreliable reports of recent transactions, it generated uncertainty and anxiety.
The purpose of undertaking this effort, which consumed valuable time and was not exactly popular with the trading team, was to promote accountability and action. If the MTM on a particular trade showed a steady negative trend--particularly if it had moved from an expected profit to a loss--this triggered a discussion with management about why it was happening and what should be done. When handled well, this sometimes led to new insights about the market that we had failed to recognize. It normally resulted in a decision on whether to hang in there a bit longer, because we could justify our view that things would turn our way, or to modify or unravel the position--even at a loss--and regroup. Of course, that wasn't always possible; sometimes the cargo was on the water, bought and paid for, and there was nothing we could do but watch the red ink swell. That gets at the essence of my concern with the application of MTM to the big banks and institutions that the government has been forced to assist, for fear of "systemic risk"--the chance of the whole financial system crashing like the Blue Screen of Death on your PC.
Crucially, the reliability of mark to market depends on the ability to obtain an accurate reading of the value of what you are holding. That requires credible reporting of current transactions--preferably many of them--in something that, if not identical, at least looks enough like your asset to serve as a good proxy. If the only deals reported are distressed sales by desperate firms, you must write down your position to that level, even if you would never willingly sell it for so little. In the worst case a series of such write-downs causes a large enough deterioration in the balance sheet of the firm that it is compelled to sell some of these assets, driving their market value even lower and triggering a cascade of further sales by depressing the MTMs of other institutions.
Throughout the financial crisis, the practice of MTM has been defended as an unpleasant but necessary discipline to prevent an outcome such as was seen in Japan after its property bubble collapsed, with numerous "zombie banks" that were effectively insolvent but kept alive by the fictitious value of assets that were worth only a fraction of the level at which they were carried on the books. That argument still has some merit. However, it seems equally possible to destroy investor (and ultimately depositor) confidence in otherwise profitable, solvent institutions through the steady mechanical deflation of their illiquid assets, the potential buyers for which understand clearly that time is on their side.
Having run this experiment in its pure form until now, I'd like to see the administration test the opposite hypothesis for a few months: suspend MTM for bank capital purposes and restore the "uptick rule" on short-selling, while they're at it. We'd quickly find out whether these steps helped to stabilize the system. If they made things worse, they could quickly be reversed. It wouldn't be the first course correction we've seen during this crisis.
Wednesday, March 11, 2009
Storing Sunlight
An article in MIT's Technology Review on a new liquid battery technology got me rethinking an assumption I've been making for some time concerning the synergy between renewable energy and better batteries. The article's author makes a similar assumption, suggesting that with bigger, cheaper batteries, electricity from solar power might be supplied around the clock. But while this new battery, consisting of a combination of molten metals and molten salts, looks clever, I'm not sure it would make sense to use it to store solar electricity in the way the author envisions. The main impediment to the large-scale application of solar power today is not so much its cyclical nature--which storage can address--but its high cost per generated kilowatt-hour, compared to other technologies. The power likeliest to be stored for later delivery won't be the most expensive, but the cheapest.
My focus here is not on the rooftop solar panels being installed on homes. Storage isn't an issue in most such cases, unless you're in a remote location or insist on grid independence. Net metering--the ability to sell excess electricity back to the grid and buy power from it when the sun isn't shining--typically offers a much better deal for homeowners than batteries, by effectively using the grid as free storage. Since rooftop solar has the inherent advantage of competing with retail, rather than wholesale electricity prices, I'm more interested in the utility-scale solar installations springing up all over. These compete directly with the output of gas-fired simple-cycle turbines, the standard "peaking" power plant technology. Utility solar projects currently cost around $6,000 per installed kilowatt (kW) based on several recent project announcements turned up by a quick web search. Even with the 30% solar investment tax credit and a site in a sunny location, such as Florida, that results in an amortized cost of generation of roughly $0.25 per kilowatt-hour (kWh), based on a 20-year life and 6% interest rate. That might be acceptable for peak demand periods, such as hot, sunny afternoons, but it doesn't compare very well to off-peak wholesale power costs from other technologies, including wind and gas turbines, let alone coal or nuclear power.
Nor is the cost per kWh the only barrier solar power must overcome, in order to be competitive around the clock, even if the cost of storing it were negligible--which is certainly not the case today. The capital involved in amassing enough capacity to serve a given market 24/7 is much higher for utility-scale solar power than for other technologies because solar's capacity factors, reflecting the fraction of time when these facilities are available and generating peak power, often average below 20%. In the Florida example above, a solar array would receive an average amount of sunlight equivalent to 4-4.5 hours of peak sun per day. That equates to a capacity factor between 17-19%. Replacing the baseload power from a 500 MW coal-fired power plant operating at an average capacity factor of 80% would require 2,200 MW of solar power plus a commensurate amount of storage. So at $6,000/kW, a solar power plant capable of generating as many kWhs as a $1.5 B coal-fired plant would cost $13.2 B, excluding the cost of delivering power when needed, instead of when the sun happens to be shining. (It also implies a very high cost per ton for the avoided CO2 emissions.)
With current solar technology, the entire proposition of storing lots of solar power looks impractical and unnecessary. Using large-scale, cheap storage--of whatever technology, whether batteries, compressed air, or pumped water--to time-shift renewable power makes much more sense when applied to lower-cost generation from wind power, the normal output of which also has a much poorer overlap with typical daily and seasonal power demand curves than solar power. In most markets, solar power should be going after the premium associated with the afternoon demand peak. Solar needs little or no storage for that, other than to buffer the effects of cloudiness or extend its output by an hour or two on either side of its natural output peaks. That looks easiest with solar thermal technology, which stores energy as heat, rather than electricity. As a result, developers of new batteries should not pin their hopes on the growth of a market for storing solar power.
My focus here is not on the rooftop solar panels being installed on homes. Storage isn't an issue in most such cases, unless you're in a remote location or insist on grid independence. Net metering--the ability to sell excess electricity back to the grid and buy power from it when the sun isn't shining--typically offers a much better deal for homeowners than batteries, by effectively using the grid as free storage. Since rooftop solar has the inherent advantage of competing with retail, rather than wholesale electricity prices, I'm more interested in the utility-scale solar installations springing up all over. These compete directly with the output of gas-fired simple-cycle turbines, the standard "peaking" power plant technology. Utility solar projects currently cost around $6,000 per installed kilowatt (kW) based on several recent project announcements turned up by a quick web search. Even with the 30% solar investment tax credit and a site in a sunny location, such as Florida, that results in an amortized cost of generation of roughly $0.25 per kilowatt-hour (kWh), based on a 20-year life and 6% interest rate. That might be acceptable for peak demand periods, such as hot, sunny afternoons, but it doesn't compare very well to off-peak wholesale power costs from other technologies, including wind and gas turbines, let alone coal or nuclear power.
Nor is the cost per kWh the only barrier solar power must overcome, in order to be competitive around the clock, even if the cost of storing it were negligible--which is certainly not the case today. The capital involved in amassing enough capacity to serve a given market 24/7 is much higher for utility-scale solar power than for other technologies because solar's capacity factors, reflecting the fraction of time when these facilities are available and generating peak power, often average below 20%. In the Florida example above, a solar array would receive an average amount of sunlight equivalent to 4-4.5 hours of peak sun per day. That equates to a capacity factor between 17-19%. Replacing the baseload power from a 500 MW coal-fired power plant operating at an average capacity factor of 80% would require 2,200 MW of solar power plus a commensurate amount of storage. So at $6,000/kW, a solar power plant capable of generating as many kWhs as a $1.5 B coal-fired plant would cost $13.2 B, excluding the cost of delivering power when needed, instead of when the sun happens to be shining. (It also implies a very high cost per ton for the avoided CO2 emissions.)
With current solar technology, the entire proposition of storing lots of solar power looks impractical and unnecessary. Using large-scale, cheap storage--of whatever technology, whether batteries, compressed air, or pumped water--to time-shift renewable power makes much more sense when applied to lower-cost generation from wind power, the normal output of which also has a much poorer overlap with typical daily and seasonal power demand curves than solar power. In most markets, solar power should be going after the premium associated with the afternoon demand peak. Solar needs little or no storage for that, other than to buffer the effects of cloudiness or extend its output by an hour or two on either side of its natural output peaks. That looks easiest with solar thermal technology, which stores energy as heat, rather than electricity. As a result, developers of new batteries should not pin their hopes on the growth of a market for storing solar power.
Monday, March 09, 2009
The End of the World As We Know It?
The opinion section of the Sunday New York Times made for sobering reading this weekend. While the Times has hardly been a bastion of economic optimism of late, three op-eds stood out for their shared sense that we might be on the brink of truly wrenching change. Tom Friedman invoked an enviro-economic tipping point, citing one expert's prognosis of a "Great Disruption;" a best-selling author saw the risk of "economic cataclysm" in the bursting of Eastern Europe's foreign debt bubble; and another found parallels to the Austria-Hungary of 1913, one year before the war that ended at least three empires and mortally wounded a couple of others. But while the systemic unraveling of the past six months or so makes such possibilities likelier than they would have been just a few years ago, the odds still favor a much less drastic result than revolution or apocalypse. The enormous recent increase in the range of uncertainties we face lends added credibility to the direst scenarios. However, it's important to realize that these predictions are not certainties, unless our responses make them so. That applies to energy, as well.
When I think about the possible paths of energy supply and demand over the next few years, they depend much less on specific energy or environmental trends than on the future state of the economy. Forecasting oil prices has become meaningless without a clear view of growth, particularly in the US and China. Demand may have rebounded recently in the US, but the combination of a crippling financial crisis with a deep cyclical downturn has Americans questioning the future in ways that I haven't seen in decades, other than the immediate aftermath of 9/11. The tangible effects of what noted historian Niall Ferguson has dubbed the "Great Recession" serve to reinforce the hangover of millennial angst from the turn of the century, which manifested in the more extreme views of Y2K and more recently Peak Oil. Layer in the propensity of my own Baby Boom generation to see itself at the epicenter of great events, and the stage is set for receptiveness to the view that we stand on the brink of unprecedented, permanently life-altering change.
When I was involved in my first scenario planning project at Texaco, we came up with three remarkably insightful views of the future of the energy industry, at least two of which have remained relevant far longer than any of us could have guessed. They received wide distribution throughout the company and had the general support of many in upper management. However, that project also came up with the seeds of another scenario, a much darker view involving the rejection of globalization and a growing wave of anti-Americanism around the world. Although in some respects it was no less prescient--or challenging--than the other three scenarios, it went nowhere, because the context for exploring it didn't exist in 1997. The external consultants who guided us through the process advised us not to pursue it, or risk destroying the credibility of the entire effort. That was good advice, even in retrospect, and it served as a useful lesson about the way that assessments of the future interact with our views of the present and our experience of the past. They must also be grounded in reality.
That's certainly true for energy, today. However much we might consider our energy future to be in flux, our views of it must take into account the embedded dominance of fossil fuels in our energy systems. Given the scale of these systems, that dominance will still exist next year and the following year, no matter what policies are enacted in the US or elsewhere. This might all seem to be up for grabs, but that's really only true in the long term. I've believed for a long time that we are on the threshold of a revolution in the ways that we produce and use energy, and it has arguably already begun. But no matter what happens in the economy, short of a massive global collapse, this revolution cannot be completed overnight. It will take decades, and that is equally true of our response to man-made climate change, which took a century to create.
Whenever I watch the news or read the latest statistics about the economy, I worry about what next year might look like. The uncertainties are huge and daunting. But I also know that while the chances of a Great Depression-style collapse or a radical socio-enviro-political transformation have risen, the economic future is likelier to resemble the last few decades, minus the unsustainable levels of personal and institutional debt. In the same way, the energy transformation is likely to play out as a set of big, gradual shifts: away from coal and other carbon-intensive fuels and toward renewable energy and nuclear power, and away from liquid transportation fuels and towards the eventual electrification of most ground vehicles. These transitions will take time, and that means that, whatever their price, a decade from now there will still be electricity and natural gas for the appliances and devices you buy today, and there will still be fuel for the car you buy today. That's one set of uncertainties over which we shouldn't lose sleep.
When I think about the possible paths of energy supply and demand over the next few years, they depend much less on specific energy or environmental trends than on the future state of the economy. Forecasting oil prices has become meaningless without a clear view of growth, particularly in the US and China. Demand may have rebounded recently in the US, but the combination of a crippling financial crisis with a deep cyclical downturn has Americans questioning the future in ways that I haven't seen in decades, other than the immediate aftermath of 9/11. The tangible effects of what noted historian Niall Ferguson has dubbed the "Great Recession" serve to reinforce the hangover of millennial angst from the turn of the century, which manifested in the more extreme views of Y2K and more recently Peak Oil. Layer in the propensity of my own Baby Boom generation to see itself at the epicenter of great events, and the stage is set for receptiveness to the view that we stand on the brink of unprecedented, permanently life-altering change.
When I was involved in my first scenario planning project at Texaco, we came up with three remarkably insightful views of the future of the energy industry, at least two of which have remained relevant far longer than any of us could have guessed. They received wide distribution throughout the company and had the general support of many in upper management. However, that project also came up with the seeds of another scenario, a much darker view involving the rejection of globalization and a growing wave of anti-Americanism around the world. Although in some respects it was no less prescient--or challenging--than the other three scenarios, it went nowhere, because the context for exploring it didn't exist in 1997. The external consultants who guided us through the process advised us not to pursue it, or risk destroying the credibility of the entire effort. That was good advice, even in retrospect, and it served as a useful lesson about the way that assessments of the future interact with our views of the present and our experience of the past. They must also be grounded in reality.
That's certainly true for energy, today. However much we might consider our energy future to be in flux, our views of it must take into account the embedded dominance of fossil fuels in our energy systems. Given the scale of these systems, that dominance will still exist next year and the following year, no matter what policies are enacted in the US or elsewhere. This might all seem to be up for grabs, but that's really only true in the long term. I've believed for a long time that we are on the threshold of a revolution in the ways that we produce and use energy, and it has arguably already begun. But no matter what happens in the economy, short of a massive global collapse, this revolution cannot be completed overnight. It will take decades, and that is equally true of our response to man-made climate change, which took a century to create.
Whenever I watch the news or read the latest statistics about the economy, I worry about what next year might look like. The uncertainties are huge and daunting. But I also know that while the chances of a Great Depression-style collapse or a radical socio-enviro-political transformation have risen, the economic future is likelier to resemble the last few decades, minus the unsustainable levels of personal and institutional debt. In the same way, the energy transformation is likely to play out as a set of big, gradual shifts: away from coal and other carbon-intensive fuels and toward renewable energy and nuclear power, and away from liquid transportation fuels and towards the eventual electrification of most ground vehicles. These transitions will take time, and that means that, whatever their price, a decade from now there will still be electricity and natural gas for the appliances and devices you buy today, and there will still be fuel for the car you buy today. That's one set of uncertainties over which we shouldn't lose sleep.
Friday, March 06, 2009
Raising A Hidden Tax
Since the administration has apparently ruled out an increase in the gasoline tax to cover declining Highway Trust Fund revenues, it's surprising that it appears to be giving serious consideration to a proposal that would raise a hidden tax on gasoline. This is even more perplexing, when you realize that this increase would actually reduce the government's net take on every gallon of gasoline sold, while simultaneously diminishing the value of the product for consumers. As reported in today's Washington Post, the US ethanol industry is petitioning the government to increase the percentage of ethanol allowable for inclusion in gasoline from 10% to 15%. At the current average gasoline pump price of $1.93 per gallon, this would effectively raise the price by 3.4 cents per gallon, while reducing federal tax revenue by 2.2 cents.
It's entirely understandable that the ethanol industry would seek such a change. Having overbuilt capacity just as demand for the fuel into which their product was blended collapsed and the easy credit that enabled their expansion tightened drastically, ethanol producers aren't in much better shape than Detroit. Several are already in bankruptcy, and others are idling capacity because of poor margins and tight cash flow. And if that weren't bad enough, the primary market for their product--"E10" gasoline, a blend containing 10% ethanol--is approaching saturation at current production levels. Nor have E85 sales grown sufficiently to relieve the pressure created by the combination of a steadily-escalating federal Renewable Fuel Standard and weak motor gasoline sales. However, even if there were no risk of higher ethanol blends damaging the engines and fuel systems of cars not designed as Flexible Fuel Vehicles, increasing the ethanol limit in gasoline would cost us all at the pump.
A gallon of ethanol contains one-third less useful energy than a gallon of petroleum gasoline. This dilution effect is already at work in the standard E10 blend, which contains 3.4% fewer BTUs than "E0". E15 would increase this gap to 5.1%. The Oak Ridge National Laboratory of the Department of Energy recently tested a representative group of cars on fuel blends containing up to 20% ethanol and confirmed a fuel economy loss proportional to the energy dilution effect. An average car driving 10,000 miles per year would require an extra 7 gallons of fuel, compared to one using E10. The extra cost at current pump prices works out to the $0.034/gal cited above. The loss of tax revenue is even more straightforward. Every gallon of ethanol blended into gasoline confers a $0.45/gal excise tax credit on the blender. Blend 10% ethanol and get $0.045 for every gallon of gasoline; blend 15% and receive $0.067.
The long-term success of the government's ethanol policy hinges on increasing the sales of E85 into Flexible Fuel Vehicles, not on foisting inferior mid-level blends of fuel on the public in the guise of "gasoline" without a price discount to reflect its poorer fuel economy, such as has evolved for E85 in most markets. If a soft-drink bottler or beer brewery were watering down its product, while charging the same price, the outcry would be deafening. Yet that's precisely what the government would be encouraging fuel marketers to do, by raising the blend limit. As consumers and taxpayers, we have more than a nickel per gallon at stake in this decision.
It's entirely understandable that the ethanol industry would seek such a change. Having overbuilt capacity just as demand for the fuel into which their product was blended collapsed and the easy credit that enabled their expansion tightened drastically, ethanol producers aren't in much better shape than Detroit. Several are already in bankruptcy, and others are idling capacity because of poor margins and tight cash flow. And if that weren't bad enough, the primary market for their product--"E10" gasoline, a blend containing 10% ethanol--is approaching saturation at current production levels. Nor have E85 sales grown sufficiently to relieve the pressure created by the combination of a steadily-escalating federal Renewable Fuel Standard and weak motor gasoline sales. However, even if there were no risk of higher ethanol blends damaging the engines and fuel systems of cars not designed as Flexible Fuel Vehicles, increasing the ethanol limit in gasoline would cost us all at the pump.
A gallon of ethanol contains one-third less useful energy than a gallon of petroleum gasoline. This dilution effect is already at work in the standard E10 blend, which contains 3.4% fewer BTUs than "E0". E15 would increase this gap to 5.1%. The Oak Ridge National Laboratory of the Department of Energy recently tested a representative group of cars on fuel blends containing up to 20% ethanol and confirmed a fuel economy loss proportional to the energy dilution effect. An average car driving 10,000 miles per year would require an extra 7 gallons of fuel, compared to one using E10. The extra cost at current pump prices works out to the $0.034/gal cited above. The loss of tax revenue is even more straightforward. Every gallon of ethanol blended into gasoline confers a $0.45/gal excise tax credit on the blender. Blend 10% ethanol and get $0.045 for every gallon of gasoline; blend 15% and receive $0.067.
The long-term success of the government's ethanol policy hinges on increasing the sales of E85 into Flexible Fuel Vehicles, not on foisting inferior mid-level blends of fuel on the public in the guise of "gasoline" without a price discount to reflect its poorer fuel economy, such as has evolved for E85 in most markets. If a soft-drink bottler or beer brewery were watering down its product, while charging the same price, the outcry would be deafening. Yet that's precisely what the government would be encouraging fuel marketers to do, by raising the blend limit. As consumers and taxpayers, we have more than a nickel per gallon at stake in this decision.
Thursday, March 05, 2009
Altered Terms
While I've devoted my last two postings to the climate change aspects of the administration's first budget, some of its other provisions could also have a significant effect on our energy economy--perhaps more, considering their potential impact on a source that still contributes one-third of our total energy diet: domestic oil and gas production. The President's budget seeks to alter many of the financial parameters under which this energy is produced and processed, ultimately affecting the energy prices consumers pay. It's not even clear that these changes would result in a net revenue gain for the federal government, after all their offsetting consequences are tallied.
Let me start by stipulating that the proposed modifications, to the extent they don't breach contractual obligations, are the government's prerogative as the custodian of the public's interest in the resources and activities involved. That's certainly true in the case of oil and gas produced from public lands and the Outer Continental Shelf (OCS). All governments change tax rates and tax benefits periodically, as circumstances change, and businesses shouldn't be surprised or offended by this. (Altering the terms of existing contracts, or enacting punitive taxes to achieve the same result after the courts have upheld companies' legal rights, is a different matter.) What's at issue here is not the government's authority to make these changes, but the wisdom of its doing so, and the ultimate consequences for a nation that still relies on petroleum for 95% of the energy we use in transportation. When it proposes singling this industry out to bar it from taking the manufacturing tax deduction, or ending the expensing of intangible drilling costs, these issues can't just be viewed as isolated line items, without examining their broader implications. In several cases, the changes likely wouldn't even raise overall government revenues.
Consider a provision in the budget to impose a new annual fee on Gulf of Mexico leases not currently producing oil or gas. This is clearly an outgrowth of last summer's spurious "idle leases" debate, which arose from a fundamental misunderstanding of the mechanics of oil and gas leasing and the way that companies determine which prospects to drill first. In any case, the $115 million per year the government hopes to raise with this fee only reflects its direct revenue, without considering the lower bid premiums on new leases that would ensue.
With the exception of the enormously controversial late-1990s leases subject to royalty relief, companies have bid for OCS leases under rules that specify that after paying the bid premium, they must pay rental fees until a property is developed, after which they would owe a 1/6th royalty on any production. (Note that both parties to these contracts have significant incentives for the deals to yield substantial production, and both are harmed when they don't.) The new fee would increase costs for leases that turn out not to have sufficient quantities of hydrocarbons to merit commercial development--over and above the cost of learning that bad news--or that simply never rise to the top of a company's constantly-evolving project list before they expire. Since neither of these outcomes is unusual, the "non-producing lease" fee would become an important consideration in calculating how much to bid in the first place. Net result: decreases in new lease bids would offset the revenue from the new fee, and in the worst case we'd see a significant drop in overall oil & gas "bonus bid", rent and royalty revenue that contributed $23 billion to the federal budget last year. Most of the budget's other energy provisions entail similar risks.
It's not my intention to be naive, here. Other than their employees and stockholders, most people consider oil companies as at best a necessary evil. After another year in which many of these firms turned in more record profits--probably their last for a while--and with few other sectors looking as healthy, they make an inviting target for new taxes and fees. But whether the intention is merely to help stanch the red ink in the budget or to punish these companies for their success when everyone else was hurting, the outcome could be doubly counterproductive, reducing tax revenues by shrinking an activity we already tax pretty thoroughly. It's hard enough for companies to justify maintaining their drilling programs in a period of low energy prices, without making the fiscal terms under which they operate less attractive. How does that align with the administration's goals for energy independence, to which doubling the output of wind, solar and geothermal energy, from 1% to 2% of consumption, can only provide a partial answer?
Let me start by stipulating that the proposed modifications, to the extent they don't breach contractual obligations, are the government's prerogative as the custodian of the public's interest in the resources and activities involved. That's certainly true in the case of oil and gas produced from public lands and the Outer Continental Shelf (OCS). All governments change tax rates and tax benefits periodically, as circumstances change, and businesses shouldn't be surprised or offended by this. (Altering the terms of existing contracts, or enacting punitive taxes to achieve the same result after the courts have upheld companies' legal rights, is a different matter.) What's at issue here is not the government's authority to make these changes, but the wisdom of its doing so, and the ultimate consequences for a nation that still relies on petroleum for 95% of the energy we use in transportation. When it proposes singling this industry out to bar it from taking the manufacturing tax deduction, or ending the expensing of intangible drilling costs, these issues can't just be viewed as isolated line items, without examining their broader implications. In several cases, the changes likely wouldn't even raise overall government revenues.
Consider a provision in the budget to impose a new annual fee on Gulf of Mexico leases not currently producing oil or gas. This is clearly an outgrowth of last summer's spurious "idle leases" debate, which arose from a fundamental misunderstanding of the mechanics of oil and gas leasing and the way that companies determine which prospects to drill first. In any case, the $115 million per year the government hopes to raise with this fee only reflects its direct revenue, without considering the lower bid premiums on new leases that would ensue.
With the exception of the enormously controversial late-1990s leases subject to royalty relief, companies have bid for OCS leases under rules that specify that after paying the bid premium, they must pay rental fees until a property is developed, after which they would owe a 1/6th royalty on any production. (Note that both parties to these contracts have significant incentives for the deals to yield substantial production, and both are harmed when they don't.) The new fee would increase costs for leases that turn out not to have sufficient quantities of hydrocarbons to merit commercial development--over and above the cost of learning that bad news--or that simply never rise to the top of a company's constantly-evolving project list before they expire. Since neither of these outcomes is unusual, the "non-producing lease" fee would become an important consideration in calculating how much to bid in the first place. Net result: decreases in new lease bids would offset the revenue from the new fee, and in the worst case we'd see a significant drop in overall oil & gas "bonus bid", rent and royalty revenue that contributed $23 billion to the federal budget last year. Most of the budget's other energy provisions entail similar risks.
It's not my intention to be naive, here. Other than their employees and stockholders, most people consider oil companies as at best a necessary evil. After another year in which many of these firms turned in more record profits--probably their last for a while--and with few other sectors looking as healthy, they make an inviting target for new taxes and fees. But whether the intention is merely to help stanch the red ink in the budget or to punish these companies for their success when everyone else was hurting, the outcome could be doubly counterproductive, reducing tax revenues by shrinking an activity we already tax pretty thoroughly. It's hard enough for companies to justify maintaining their drilling programs in a period of low energy prices, without making the fiscal terms under which they operate less attractive. How does that align with the administration's goals for energy independence, to which doubling the output of wind, solar and geothermal energy, from 1% to 2% of consumption, can only provide a partial answer?
Tuesday, March 03, 2009
Implicit Carbon Price
My posting last Friday on greenhouse gas cap & trade prompted some interesting reader comments and questions, one of which got me thinking about the price of carbon implied by the revenues included in the budget submitted to Congress. Estimating this required an examination of our recent greenhouse gas track record, along with some assumptions about how rapidly emissions would be reduced. The result appears to suggest that surprisingly modest CO2 permit prices in the initial period would be sufficient to generate the revenues shown in the budget.
President Obama campaigned on a pair of high-level greenhouse gas targets, to reduce emissions to 1990 levels by 2020, and to 80% below 1990 by 2050. That would entail a somewhat easier transition than the previous cap & trade legislation submitted to Congress, last year's Boxer-Lieberman-Warner bill, but a stricter long-term cap. Expressed in terms of tons of CO2-equivalent emissions per year, as of the most recent US greenhouse gas estimates from the Department of Energy, the President's goals would require a net reduction of slightly more than one billion tons per year (tpy) from 2007 levels by 2020, and a further 5 billion tpy in the subsequent 30 years. If emissions were flat between now and 2012, when the budget suggests reductions would begin, and the cuts proceeded in a linear fashion, cumulative emissions from 2012-2019 would be 54.1 billion tons, down from a baseline of 58.3 billion tons. Based on the $645.7 B in expected revenue from auctioning cap & trade permits over that period, the implied price per ton emitted works out to a surprisingly low $12/ton. Since this is well below the $20/ton that many experts expect to see initially, I took a look at my math and then my assumptions.
The biggest assumptions concern how much emissions might grow between 2007 and the start of cap & trade in 2012, and how rapidly they would be reduced subsequently. I initially assumed no growth to 2012, considering that emissions have increased at an average rate of 0.4% per year since 2000, spanning both the previous recession and the asset booms of the last few years. More realistically, I would expect 2008 emissions to reflect a drop from 2007, based on high energy prices in the first half and the effects of the recession in the second half, with 2009 emissions likely even lower. If we factored in a 5% cumulative drop through 2012, that would reduce the severity of cuts required to achieve 1990 levels by 2020, while also reducing the cumulative emissions over the 2012-2019 period, slightly increasing the effective cost per ton CO2e required to deliver the same revenue. Phasing in reductions more slowly would increase cumulative emissions and drive down the effective dollars per ton, perhaps to $11/ton. In other words, within reasonable bands of uncertainty about how emissions might change from 2007 levels before cap & trade started, and how rapidly the annual caps tightened toward achieving 1990 levels by 2020, the implied cost per ton of CO2 equivalent looks pretty modest in this period--the equivalent of roughly 1 cent per kWh for coal-generated electricity or 11 cents per gallon of gasoline.
Cap & trade still faces many hurdles, including the chance of a significantly different concept emerging from Congressional debate or a postponement due to the weak economy. However, at least in terms of the assumptions built into the budget, my back-of-the-envelope estimate indicates that it might not cause dramatic increases in energy prices in the first few years of the program, although the sums collected across the entire economy would still be material.
President Obama campaigned on a pair of high-level greenhouse gas targets, to reduce emissions to 1990 levels by 2020, and to 80% below 1990 by 2050. That would entail a somewhat easier transition than the previous cap & trade legislation submitted to Congress, last year's Boxer-Lieberman-Warner bill, but a stricter long-term cap. Expressed in terms of tons of CO2-equivalent emissions per year, as of the most recent US greenhouse gas estimates from the Department of Energy, the President's goals would require a net reduction of slightly more than one billion tons per year (tpy) from 2007 levels by 2020, and a further 5 billion tpy in the subsequent 30 years. If emissions were flat between now and 2012, when the budget suggests reductions would begin, and the cuts proceeded in a linear fashion, cumulative emissions from 2012-2019 would be 54.1 billion tons, down from a baseline of 58.3 billion tons. Based on the $645.7 B in expected revenue from auctioning cap & trade permits over that period, the implied price per ton emitted works out to a surprisingly low $12/ton. Since this is well below the $20/ton that many experts expect to see initially, I took a look at my math and then my assumptions.
The biggest assumptions concern how much emissions might grow between 2007 and the start of cap & trade in 2012, and how rapidly they would be reduced subsequently. I initially assumed no growth to 2012, considering that emissions have increased at an average rate of 0.4% per year since 2000, spanning both the previous recession and the asset booms of the last few years. More realistically, I would expect 2008 emissions to reflect a drop from 2007, based on high energy prices in the first half and the effects of the recession in the second half, with 2009 emissions likely even lower. If we factored in a 5% cumulative drop through 2012, that would reduce the severity of cuts required to achieve 1990 levels by 2020, while also reducing the cumulative emissions over the 2012-2019 period, slightly increasing the effective cost per ton CO2e required to deliver the same revenue. Phasing in reductions more slowly would increase cumulative emissions and drive down the effective dollars per ton, perhaps to $11/ton. In other words, within reasonable bands of uncertainty about how emissions might change from 2007 levels before cap & trade started, and how rapidly the annual caps tightened toward achieving 1990 levels by 2020, the implied cost per ton of CO2 equivalent looks pretty modest in this period--the equivalent of roughly 1 cent per kWh for coal-generated electricity or 11 cents per gallon of gasoline.
Cap & trade still faces many hurdles, including the chance of a significantly different concept emerging from Congressional debate or a postponement due to the weak economy. However, at least in terms of the assumptions built into the budget, my back-of-the-envelope estimate indicates that it might not cause dramatic increases in energy prices in the first few years of the program, although the sums collected across the entire economy would still be material.
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