As in most recent years, energy was constantly in the news in 2012. A post attempting to catalog every noteworthy story or event would be quite long. However, a few big trends stand out. For starters, it's a near-certainty that the average US gasoline price will set a new record for the second year running, in both real and nominal terms. Americans are responding by choosing more fuel efficient cars. Meanwhile, fundamental shifts emerged from obscurity into the awareness of policy makers and the public. US energy exports have become a mainstream topic of conversation, and the goal of energy independence--a concept with debatable meanings--has acquired renewed respectability after spending a couple of decades on the fringes of energy policy debate. Perhaps more significantly, our views of climate change and future oil supplies--once aligned--have diverged.
For renewable energy it has been the best and worst of years. Global overcapacity in solar equipment manufacturing drove down the costs of solar panels, at least partly counteracting reductions in government incentives, especially in Europe, and making solar power more competitive. The US is on track to add a record 3,200 MW of solar capacity this year, while China could add 5,000 MW. However, solar manufacturers' rapid expansion depressed their margins and extended last year's string of solar bankruptcies, with firms like Abound Solar, Konarka, Solarwatt, Q-Cells and others forced to restructure or liquidate in 2012. A similar, if less dramatic wave is working through the more mature onshore wind industry, which faces the expiration of a key US incentive, the Production Tax Credit, or PTC on December 31. In anticipation of that loss, wind developers have added 4,728 MW of new capacity in the US through the first three quarters of 2012, the most since 2009.
Energy played a complex and possibly decisive role in the US presidential election. Remarkably, President Obama successfully co opted his opponent's energy platform by embracing an oil and gas revival that his administration had done little to help and much to hinder, even though it appeared to conflict with his emphasis on renewable energy and climate change mitigation. Meanwhile, the shale gas revolution was creating hundreds of thousands of direct and indirect jobs and lowering energy costs across the economy, contributing to US manufacturing competitiveness. The resulting economic growth, while still below the level of other post-war recoveries, apparently helped the President make his case for a second term.
The inherent tension between surging US oil and natural gas production and concerns about climate change--fanned by Hurricane Sandy--reflects a major shift that occurred this year, at least as an influence on future energy policy. Recall that until recently, memories of past energy crises, combined with the influential Peak Oil perspective, shaped our expectations of resource availability and future production. This narrative of hydrocarbon scarcity complemented prescriptions for a rapid transition away from fossil fuels as the only viable solution to climate change, supporting a shared goal of a more sustainable energy economy based on renewable energy, smart grids and electric vehicles. The exploitation of unconventional oil and gas resources in previously inaccessible source rock--shale gas and "tight" or shale oil--poses significant challenges to both strands of that argument.
First, it undermines the notion of energy scarcity for at least the next decade, and probably well beyond. US natural gas production set a new record this year, and US oil production returned to levels not seen since 1997, putting increased pressure on OPEC's control over global oil pricing. Nor does the US have a monopoly on these unconventional resources. Canada looks like the next big shale gas play, with China and South Africa possibly not be far behind. The technologies that enabled the US shale gas revolution and its oil offspring are being transferred around the world.
Yet we also learned that US energy-related CO2 emissions have fallen back to 1992 levels, largely because of a dramatic reduction in the use of coal in power generation. While renewable energy sources like wind and solar power deserve some of the credit, natural gas-fired turbines--driven by cheap shale gas--have added three times as much net generation since 2007 as non-hydro renewables.
Shale gas and oil might not provide a long-term solution to global warming, but they could at least buy us the time to develop the innovations like improved electric vehicle batteries and low-cost grid-storage that will be necessary if renewables are to displace fossil fuels across the entire spectrum of their use--and dominance. They could also provide the time to develop and deploy the next generation of nuclear power, including small modular reactors.
I'd like to thank my readers for your continued interest and encouragement and wish you a happy holiday season.
Thursday, December 20, 2012
Wednesday, December 12, 2012
Should Alaska Export More LNG to Asia?
The Governor of Alaska reportedly met
this week with officials from the South Korean national gas company to
discuss exports of liquefied natural gas (LNG). Ever since crude oil production on Alaska's North Slope ramped
up in the 1980s, industry observers have speculated about the ultimate
disposition of the significant associated natural gas reserves found with the
oil. In a letter filed with the state of Alaska, BP, ConocoPhillips and ExxonMobil, the three main North Slope
producers, together with pipeline company Transcanada, recently confirmed their
plans for a potential liquefied natural gas (LNG) project, instead of the
long-mooted pipeline to deliver the gas to America's lower-48 states. The
contemplated megaproject would validate both the scale of Asia's future LNG
market and the long-term nature of the US shale gas revolution.
Alaska's North Slope has already yielded 15 billion barrels of oil. Production peaked at over 2 million barrels per day in 1988 and subsequently declined to less than 600,000 barrels per day last year. With around 6 billion barrels of remaining reserves, it's still a very significant field but well past its prime. While the public has focused on its oil output, the producers and the state have long had their eyes on how best to harvest the value of the 35 trillion cubic feet (TCF) of gas dissolved in the oil. In fact, the North Slope complex has produced several TCF per year of gas for years, ranking it among the largest gas fields in the world, but almost all of that gas has been reinjected into the formation to aid oil recovery--and for lack of a market in an isolated and sparsely-populated state.
For decades the default assumption was that a pipeline would eventually be built across Alaska and Canada to link this gas to the existing network feeding the contiguous US. That idea gained traction when US marketed gas production stalled around 2000 and then began to decline. The economics of an Alaskan gas pipeline compared poorly with gas produced along the Gulf Coast, but competing with rising LNG imports looked much more feasible. Then along came unconventional gas, starting with coal-bed methane and culminating with the surge of shale production since 2005. The US gas market now has enough domestic supply to shrink coal's contribution to US power generation by 7% since 2008 and revive gas-intensive industries.
If shale gas were only a short-term phenomenon, as some have suggested, it would be of little relevance to the plans of the North Slope producers. All they'd need to do would be to delay their pipeline for a few more years, and the market would come to them. However, estimates put US shale gas resources at between 482 and 686 TCF--a 60-90 year supply at current shale production rates. And the fact that all three of the main North Slope producers have invested in significant acreage positions and production in US shale basins surely gives them insights into the longevity of those resources.
Nor is time on the side of the Alaskan producers. As oil production declines the economics of the North Slope operation will deteriorate, while keeping the Trans Alaska Pipeline full becomes more problematic. Finding an attractive outlet for the North Slope "gas cap" wouldn't just provide a new revenue source; it could keep oil production going for additional decades.
The LNG option offers several advantages, despite its estimated $45-65 billion price tag and technical complexity. For starters, it cuts roughly 1,000 miles of difficult terrain off the distance that the gas must be pipelined, in this case to a site on the southern Alaskan coast. That location is much closer to Asia, the world's largest LNG market, than export projects intended to ship LNG from the US Gulf Coast. The Asian market is also growing, thanks in part to Japan's post-Fukushima reassessment of nuclear power. The Japanese government has backed away, at least for now, from plans for a firm nuclear phase-out, but it seeks to diversify its energy sources. Among other steps taken in the aftermath of the Sendai quake and nuclear disaster, it has instituted the world's most attractive solar power incentives. Yet Japan's solar resources provide just a few hours of peak output per day, on average, requiring substantial fossil fuel generation to fill in the gaps. Power plants burning LNG are well-suited to that task.
China presents a more complex picture, with its own significant shale gas potential and an energy market expected to add as much natural gas demand by 2035 as all the world's developed countries put together. Considering the scale of eventual demand and the infrastructure necessary to bring China's shale gas to market, it seems likely that the growth of the market in the interim must depend heavily on LNG imports.
Assuming that the state of Alaska presents no obstacles and that US export permits would be forthcoming, because Alaskan LNG exports wouldn't impact US natural gas prices, the main questions that will determine the future of this project can't be answered definitively today. Among these are whether the numerous competing LNG projects being planned and built around the Pacific Rim and elsewhere will saturate the global market in the meantime, and whether the market will provide an attractive price for Alaskan LNG, influenced more by crude oil prices than by US shale gas. The North Slope producers are already immersed in these issues via their other activities, including ConocoPhillips' small LNG plant in Kenai, Alaska, which has been shipping LNG to Asia for more than 40 years. The project timeline provided to the state includes at least three go/no-go decisions along the way as the answers to these questions unfold.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Alaska's North Slope has already yielded 15 billion barrels of oil. Production peaked at over 2 million barrels per day in 1988 and subsequently declined to less than 600,000 barrels per day last year. With around 6 billion barrels of remaining reserves, it's still a very significant field but well past its prime. While the public has focused on its oil output, the producers and the state have long had their eyes on how best to harvest the value of the 35 trillion cubic feet (TCF) of gas dissolved in the oil. In fact, the North Slope complex has produced several TCF per year of gas for years, ranking it among the largest gas fields in the world, but almost all of that gas has been reinjected into the formation to aid oil recovery--and for lack of a market in an isolated and sparsely-populated state.
For decades the default assumption was that a pipeline would eventually be built across Alaska and Canada to link this gas to the existing network feeding the contiguous US. That idea gained traction when US marketed gas production stalled around 2000 and then began to decline. The economics of an Alaskan gas pipeline compared poorly with gas produced along the Gulf Coast, but competing with rising LNG imports looked much more feasible. Then along came unconventional gas, starting with coal-bed methane and culminating with the surge of shale production since 2005. The US gas market now has enough domestic supply to shrink coal's contribution to US power generation by 7% since 2008 and revive gas-intensive industries.
If shale gas were only a short-term phenomenon, as some have suggested, it would be of little relevance to the plans of the North Slope producers. All they'd need to do would be to delay their pipeline for a few more years, and the market would come to them. However, estimates put US shale gas resources at between 482 and 686 TCF--a 60-90 year supply at current shale production rates. And the fact that all three of the main North Slope producers have invested in significant acreage positions and production in US shale basins surely gives them insights into the longevity of those resources.
Nor is time on the side of the Alaskan producers. As oil production declines the economics of the North Slope operation will deteriorate, while keeping the Trans Alaska Pipeline full becomes more problematic. Finding an attractive outlet for the North Slope "gas cap" wouldn't just provide a new revenue source; it could keep oil production going for additional decades.
The LNG option offers several advantages, despite its estimated $45-65 billion price tag and technical complexity. For starters, it cuts roughly 1,000 miles of difficult terrain off the distance that the gas must be pipelined, in this case to a site on the southern Alaskan coast. That location is much closer to Asia, the world's largest LNG market, than export projects intended to ship LNG from the US Gulf Coast. The Asian market is also growing, thanks in part to Japan's post-Fukushima reassessment of nuclear power. The Japanese government has backed away, at least for now, from plans for a firm nuclear phase-out, but it seeks to diversify its energy sources. Among other steps taken in the aftermath of the Sendai quake and nuclear disaster, it has instituted the world's most attractive solar power incentives. Yet Japan's solar resources provide just a few hours of peak output per day, on average, requiring substantial fossil fuel generation to fill in the gaps. Power plants burning LNG are well-suited to that task.
China presents a more complex picture, with its own significant shale gas potential and an energy market expected to add as much natural gas demand by 2035 as all the world's developed countries put together. Considering the scale of eventual demand and the infrastructure necessary to bring China's shale gas to market, it seems likely that the growth of the market in the interim must depend heavily on LNG imports.
Assuming that the state of Alaska presents no obstacles and that US export permits would be forthcoming, because Alaskan LNG exports wouldn't impact US natural gas prices, the main questions that will determine the future of this project can't be answered definitively today. Among these are whether the numerous competing LNG projects being planned and built around the Pacific Rim and elsewhere will saturate the global market in the meantime, and whether the market will provide an attractive price for Alaskan LNG, influenced more by crude oil prices than by US shale gas. The North Slope producers are already immersed in these issues via their other activities, including ConocoPhillips' small LNG plant in Kenai, Alaska, which has been shipping LNG to Asia for more than 40 years. The project timeline provided to the state includes at least three go/no-go decisions along the way as the answers to these questions unfold.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Thursday, December 06, 2012
IEA Expects Global Energy Focus to Shift Eastward
Last month the International Energy Agency (IEA) released its annual long-term forecast, the World Energy Outlook (WEO). Its projection that US oil output would exceed that of Saudi Arabia within five years was featured in numerous headlines, although some of the report's other findings look equally consequential. That includes the continued strong growth of energy demand in China, India and other Asian countries, and the linkages between that growth and a dramatic expansion of Iraqi oil production. The agency also set a cautionary tone concerning the increase in global greenhouse gas emissions accompanying all this growth.
In the IEA's primary "New Policies" scenario, the US overtakes Saudi Arabia in oil production by 2017, adding 4 million barrels per day (MBD) of unconventional output, mainly from shale (tight oil) deposits such as the Bakken in North Dakota. US oil imports decline significantly, due in roughly equal measure to higher production and the implementation of strict vehicle fuel economy regulations. As a consequence, the need for imports from the Middle East approaches zero within 10 years. When this change is combined with the growth in oil demand in Asia, where China alone accounts for half the forecasted global growth in oil consumption in this period, the IEA envisions Asia becoming the recipient of 90% of Middle East oil exports by 2035.
The detailed assumptions behind the IEA's conclusions weren't provided in the public release. These include crucial questions such as the assumed status of US rules barring most crude oil exports. As noted in a Reuters op-ed at the time, maximizing the potential of US unconventional resources may depend on allowing higher quality unconventional oil to seek global markets, while continuing to import oil from Latin America and the Middle East into Gulf Coast refineries geared to these heavier, higher-sulfur feedstocks. The op-ed's author also reminded us that the natural gas liquids included in the headline comparison with Saudi production are useful but quite different from crude oil, yielding little gasoline and diesel fuel.
The expected growth of energy demand in China remains extraordinary, even with the country's economic growth slowing from the levels seen a few years ago. To put this in context, when Dr. Fatih Birol, Chief Economist of the IEA, presented the new WEO to the media in London on November 12th, he suggested that China's electricity demand would grow by the equivalent of "one US and one Japan of today" by 2035. Much of that additional electricity generation is projected to come from renewables, nuclear power and domestic gas. Nevertheless, and in spite of significant increases in China's unconventional gas production, the IEA forecasts that import dependence will grow from about 15% for gas and 50% for oil today, to 40% for gas and over 80% for oil by 2035. That increase in imports would equate to additional hundreds of millions of dollars per year of outflows for energy.
In the view of the IEA, much of the extra oil demanded in Asia will be supplied by Iraq, which they project will increase its output from around 3 MBD today to 6.1 MBD in 2020 and 8.3 MBD in 2035, in the process becoming the world's second-largest oil exporter, after Russia. Since the reserves to support that growth have already been identified, with much lower production costs than many other basins, the uncertainties involved are mainly political and structural. Resolution of the current standoff with Iran over its nuclear program would provide even more Middle East oil for Asian markets.
As in its earlier "Golden Age of Gas" scenario, the IEA expects large increases in global natural gas consumption. Unconventional sources, mainly in the US, China and Australia, would contribute around half the additional production required to meet expanded demand. However, at the launch presentation in London Dr. Birol also stressed that unconventional oil and gas are still at an early stage, with significant uncertainties about the eventual magnitude of their resources. This seemed to be a particular issue for the agency's post-2020 forecast of oil production in the US and gas production in China.
Despite the rigorous analysis and level of detail involved in producing the IEA's World Energy Outlook, long-term energy forecasting should always be taken with a grain of salt. Yet whether or not the highlighted trends mature precisely in line with these projections, the shifts that the IEA identified are significant and already becoming evident in current data for energy production, consumption and trade. Even if North America failed to become a net oil exporter--which many equate with energy independence--by 2030, the movement of the center of gravity of global energy trade towards Asia is essentially pre-determined: baked in by differences in economic growth rates and resource opportunities. The economic, geopolitical and environmental consequences of that shift are just starting to take shape.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
In the IEA's primary "New Policies" scenario, the US overtakes Saudi Arabia in oil production by 2017, adding 4 million barrels per day (MBD) of unconventional output, mainly from shale (tight oil) deposits such as the Bakken in North Dakota. US oil imports decline significantly, due in roughly equal measure to higher production and the implementation of strict vehicle fuel economy regulations. As a consequence, the need for imports from the Middle East approaches zero within 10 years. When this change is combined with the growth in oil demand in Asia, where China alone accounts for half the forecasted global growth in oil consumption in this period, the IEA envisions Asia becoming the recipient of 90% of Middle East oil exports by 2035.
The detailed assumptions behind the IEA's conclusions weren't provided in the public release. These include crucial questions such as the assumed status of US rules barring most crude oil exports. As noted in a Reuters op-ed at the time, maximizing the potential of US unconventional resources may depend on allowing higher quality unconventional oil to seek global markets, while continuing to import oil from Latin America and the Middle East into Gulf Coast refineries geared to these heavier, higher-sulfur feedstocks. The op-ed's author also reminded us that the natural gas liquids included in the headline comparison with Saudi production are useful but quite different from crude oil, yielding little gasoline and diesel fuel.
The expected growth of energy demand in China remains extraordinary, even with the country's economic growth slowing from the levels seen a few years ago. To put this in context, when Dr. Fatih Birol, Chief Economist of the IEA, presented the new WEO to the media in London on November 12th, he suggested that China's electricity demand would grow by the equivalent of "one US and one Japan of today" by 2035. Much of that additional electricity generation is projected to come from renewables, nuclear power and domestic gas. Nevertheless, and in spite of significant increases in China's unconventional gas production, the IEA forecasts that import dependence will grow from about 15% for gas and 50% for oil today, to 40% for gas and over 80% for oil by 2035. That increase in imports would equate to additional hundreds of millions of dollars per year of outflows for energy.
In the view of the IEA, much of the extra oil demanded in Asia will be supplied by Iraq, which they project will increase its output from around 3 MBD today to 6.1 MBD in 2020 and 8.3 MBD in 2035, in the process becoming the world's second-largest oil exporter, after Russia. Since the reserves to support that growth have already been identified, with much lower production costs than many other basins, the uncertainties involved are mainly political and structural. Resolution of the current standoff with Iran over its nuclear program would provide even more Middle East oil for Asian markets.
As in its earlier "Golden Age of Gas" scenario, the IEA expects large increases in global natural gas consumption. Unconventional sources, mainly in the US, China and Australia, would contribute around half the additional production required to meet expanded demand. However, at the launch presentation in London Dr. Birol also stressed that unconventional oil and gas are still at an early stage, with significant uncertainties about the eventual magnitude of their resources. This seemed to be a particular issue for the agency's post-2020 forecast of oil production in the US and gas production in China.
Despite the rigorous analysis and level of detail involved in producing the IEA's World Energy Outlook, long-term energy forecasting should always be taken with a grain of salt. Yet whether or not the highlighted trends mature precisely in line with these projections, the shifts that the IEA identified are significant and already becoming evident in current data for energy production, consumption and trade. Even if North America failed to become a net oil exporter--which many equate with energy independence--by 2030, the movement of the center of gravity of global energy trade towards Asia is essentially pre-determined: baked in by differences in economic growth rates and resource opportunities. The economic, geopolitical and environmental consequences of that shift are just starting to take shape.
A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.
Thursday, November 29, 2012
Does the Gas Tax Belong in the Fiscal Cliff Fix?
Recently I've seen several articles along the lines of this one from CNN, suggesting that an increase in the federal gasoline tax might be included in negotiations to avert the impending US "fiscal cliff". While the gap between the gas tax, which was last raised in 1993, and highway repair costs grows each year, that's not just because past Congresses and administrations have been reluctant to hike it again. As I've discussed in previous posts, gas tax revenue is declining for structural reasons related to curtailed driving, rising fuel economy and alternative fuel vehicles. Simply adding another 10-15 ¢ per gallon to the current 18.4 ¢ tax wouldn't solve the long-term problem, although it would raise enough revenue to allow us to continue to ignore these growing challenges for a few years. For that and other reasons, changing the gas tax deserves closer scrutiny than the waning hours of a preoccupied lame-duck Congress can provide.
Yesterday I attended another excellent event held by Resources for the Future in Washington, DC. This one was devoted to "The Future of Fuel." The panel discussion began with a presentation of the current energy forecast of the Energy Information Agency (EIA) highlighting the shifting energy mix the agency expects between now and 2035. Although the slide deck didn't include the chart below, taken from EIA's 2012 Annual Energy Outlook, I couldn't help thinking of it in the context of both yesterday's meeting and the question of future fuel tax revenues.
The EIA forecasts US gasoline demand to decline by about 8% from current levels by 2035 as cars meeting the new federal fuel economy standard enter the fleet, along with small but growing numbers of vehicles running on electricity and other non-petroleum fuels. An 8% drop in gasoline sales--and thus gas tax revenues--doesn't sound large until you realize that the current gas tax system was predicated on consistently rising gasoline sales as a means of expanding revenues. That's crucial, because highway construction and maintenance costs rise each year, too. If gasoline sales were still growing at the 1% annual rate typical when the gas tax was last increased, gas tax revenues would be at least 37% higher by 2035 than the level the EIA would now project.
Stepping back from the details, the government faces a fundamental disconnect between its need to raise sufficient funds from the gas tax to cover the cost of maintaining the nation's road network and explicit federal policies aimed at reducing our consumption of the fuels being taxed. Another one-time bump in the gas tax, whether of 5¢, 10¢ or 15¢ per gallon, will again be overtaken by the combined forces of inflation and declining volumes. Fortunately, this problem is well-understood and a number of solutions are under consideration. Inconveniently, many of them involve basic and controversial changes in how the road tax would be collected, such as shifting to a mileage-based tax assessed via annual inspections or real-time GPS monitoring.
No one should expect or desire the 112th Congress to resolve these issues between now and the end of its term in January, particularly when the money at stake represents such a tiny fraction of either the fiscal cliff's package of tax increases and spending cuts or of the entire federal deficit. I'm also not sure that reforming the gas tax belongs within the larger federal tax reform effort that should be undertaken next year, because the issues involved are so different from those associated with revamping the business, income, and payroll taxes. Even a temporary fuel surtax would likely encounter strong opposition, due to its regressive nature and coincidence with gasoline prices that, despite recent declines, remain at or near seasonal record highs. Unlike the rest of the fiscal cliff, this might just be one can that would benefit from being kicked down the road, at least past the current crisis.
Yesterday I attended another excellent event held by Resources for the Future in Washington, DC. This one was devoted to "The Future of Fuel." The panel discussion began with a presentation of the current energy forecast of the Energy Information Agency (EIA) highlighting the shifting energy mix the agency expects between now and 2035. Although the slide deck didn't include the chart below, taken from EIA's 2012 Annual Energy Outlook, I couldn't help thinking of it in the context of both yesterday's meeting and the question of future fuel tax revenues.
The EIA forecasts US gasoline demand to decline by about 8% from current levels by 2035 as cars meeting the new federal fuel economy standard enter the fleet, along with small but growing numbers of vehicles running on electricity and other non-petroleum fuels. An 8% drop in gasoline sales--and thus gas tax revenues--doesn't sound large until you realize that the current gas tax system was predicated on consistently rising gasoline sales as a means of expanding revenues. That's crucial, because highway construction and maintenance costs rise each year, too. If gasoline sales were still growing at the 1% annual rate typical when the gas tax was last increased, gas tax revenues would be at least 37% higher by 2035 than the level the EIA would now project.
Stepping back from the details, the government faces a fundamental disconnect between its need to raise sufficient funds from the gas tax to cover the cost of maintaining the nation's road network and explicit federal policies aimed at reducing our consumption of the fuels being taxed. Another one-time bump in the gas tax, whether of 5¢, 10¢ or 15¢ per gallon, will again be overtaken by the combined forces of inflation and declining volumes. Fortunately, this problem is well-understood and a number of solutions are under consideration. Inconveniently, many of them involve basic and controversial changes in how the road tax would be collected, such as shifting to a mileage-based tax assessed via annual inspections or real-time GPS monitoring.
No one should expect or desire the 112th Congress to resolve these issues between now and the end of its term in January, particularly when the money at stake represents such a tiny fraction of either the fiscal cliff's package of tax increases and spending cuts or of the entire federal deficit. I'm also not sure that reforming the gas tax belongs within the larger federal tax reform effort that should be undertaken next year, because the issues involved are so different from those associated with revamping the business, income, and payroll taxes. Even a temporary fuel surtax would likely encounter strong opposition, due to its regressive nature and coincidence with gasoline prices that, despite recent declines, remain at or near seasonal record highs. Unlike the rest of the fiscal cliff, this might just be one can that would benefit from being kicked down the road, at least past the current crisis.
Tuesday, November 20, 2012
EPA Unwavering in Support for Ethanol, Despite Drought
Last Friday the US Environmental Protection Agency (EPA) rejected the petitions of a bi-partisan group of state governors for a waiver of the federal ethanol mandate, resolving one of several energy-related issues that had been deferred beyond the presidential election. The waiver requests filed in August cited the harm that the Renewable Fuel Standard (RFS) is causing to the poultry, dairy and livestock sectors and related businesses--and by extension to consumers--by increasing competition for corn during a severe drought that has sharply constrained supply. The EPA's detailed response made frequent references to the "high statutory threshold of severe harm to the economy" required for a waiver of the RFS, and to the output of a model simulating the market for corn and ethanol. It also included the extraordinary assertion that, "the RFS volume requirements will have no impact on ethanol production volumes in the relevant time frame, and therefore will have no impact on corn, food, or fuel prices." If that were true, then it's not obvious why the mandate should exist at all.
In rejecting pleas for relaxation of the ethanol standard, the EPA appears to be relying on two key facts. First, wholesale ethanol prices remain lower than wholesale gasoline prices, despite corn prices that are high enough to force many ethanol producers to cut back output. I'd attribute that mainly to weak US gasoline demand and the much-discussed impact of the "blend wall" in limiting ethanol to 10% of the gasoline pool, rather than as a sign of an unaffected market. The agency is also relying on the availability of "paper ethanol" in the form of Renewable Identification Number (RIN) credits from past over-blending of ethanol by refiners and other gasoline blenders. The EPA's estimate puts the number of available RINs at the equivalent of 2-3 billion gallons, or around 20% of this year's 13.2 billion gallon conventional ethanol requirement. As a result of these factors, EPA can claim with some justification that ethanol prices are not harming motorists at the gas pump at this time. That's small consolation to the petitioners.
EPA's assurances to those in the poultry, dairy and livestock value chains are based on much thinner evidence--in fact, on none at all, unless you count as evidence a model that predicts corn prices would only fall by $0.58 per bushel if the ethanol mandate were eliminated entirely. Simulations are useful but still aren't reality. The output of a model is only as good as its assumptions and algorithms, and when that output defies logic, it calls for the application of good judgment, particularly when the result happens to align so neatly with the internal concerns about the long-term implications of a waiver that are evident in the agency's response. I can't help concluding that an agency whose management possessed greater depth and breadth of experience outside of government--especially in the business sector--would have given more weight to the struggles of the dairies, ranchers, meat-packers and others who are being squeezed by a mandate that is projected to consume 42% of this year's corn crop and is very likely inflating the cost of the Thanksgiving meal that many of my US readers will eat on Thursday. This administration's lack of outside experience has been a glaring shortcoming that the President could easily remedy as turnover creates openings at the start of his second term.
I can't say that I'm surprised by the EPA's ruling on the waiver requests. I also can't help wondering whether it provides any indication of how the administration is likely to deal with the other issues that were deferred until after the election. Yet even if we can't read anything else into this decision, it's clear that the Renewable Fuel Standard enacted in 2007--before the financial crisis and recession--is in serious need of reform. If its language doesn't require the EPA to adjust the ethanol mandate in light of a drought that will result in the smallest corn crop since 2006, when US ethanol production was 65% lower than last year, then the law simply didn't incorporate sufficient foresight about possible future events. Together with its unrealistically ambitious cellulosic biofuel standard, the provisions of the RFS increasingly seem to relate to some other, parallel universe, rather than the one in which we live.
In rejecting pleas for relaxation of the ethanol standard, the EPA appears to be relying on two key facts. First, wholesale ethanol prices remain lower than wholesale gasoline prices, despite corn prices that are high enough to force many ethanol producers to cut back output. I'd attribute that mainly to weak US gasoline demand and the much-discussed impact of the "blend wall" in limiting ethanol to 10% of the gasoline pool, rather than as a sign of an unaffected market. The agency is also relying on the availability of "paper ethanol" in the form of Renewable Identification Number (RIN) credits from past over-blending of ethanol by refiners and other gasoline blenders. The EPA's estimate puts the number of available RINs at the equivalent of 2-3 billion gallons, or around 20% of this year's 13.2 billion gallon conventional ethanol requirement. As a result of these factors, EPA can claim with some justification that ethanol prices are not harming motorists at the gas pump at this time. That's small consolation to the petitioners.
EPA's assurances to those in the poultry, dairy and livestock value chains are based on much thinner evidence--in fact, on none at all, unless you count as evidence a model that predicts corn prices would only fall by $0.58 per bushel if the ethanol mandate were eliminated entirely. Simulations are useful but still aren't reality. The output of a model is only as good as its assumptions and algorithms, and when that output defies logic, it calls for the application of good judgment, particularly when the result happens to align so neatly with the internal concerns about the long-term implications of a waiver that are evident in the agency's response. I can't help concluding that an agency whose management possessed greater depth and breadth of experience outside of government--especially in the business sector--would have given more weight to the struggles of the dairies, ranchers, meat-packers and others who are being squeezed by a mandate that is projected to consume 42% of this year's corn crop and is very likely inflating the cost of the Thanksgiving meal that many of my US readers will eat on Thursday. This administration's lack of outside experience has been a glaring shortcoming that the President could easily remedy as turnover creates openings at the start of his second term.
I can't say that I'm surprised by the EPA's ruling on the waiver requests. I also can't help wondering whether it provides any indication of how the administration is likely to deal with the other issues that were deferred until after the election. Yet even if we can't read anything else into this decision, it's clear that the Renewable Fuel Standard enacted in 2007--before the financial crisis and recession--is in serious need of reform. If its language doesn't require the EPA to adjust the ethanol mandate in light of a drought that will result in the smallest corn crop since 2006, when US ethanol production was 65% lower than last year, then the law simply didn't incorporate sufficient foresight about possible future events. Together with its unrealistically ambitious cellulosic biofuel standard, the provisions of the RFS increasingly seem to relate to some other, parallel universe, rather than the one in which we live.
Monday, November 12, 2012
Is Gas Rationing Superior to Raising Prices for Consumers?
With New Jersey about to end the odd-even gasoline rationing imposed in the aftermath of Hurricane Sandy, we have an opportunity to consider whether this kind of response actually produces better outcomes than the price increases by which the market would normally balance supply and demand. Most of the defenses of "price gouging" that I've seen, including Matthew Yglesias's recent posting in Slate, tend to focus mainly on its supply-side aspects. Yet such arguments, however well-reasoned, are unlikely to sway Americans from their innate sense of fairness, on which most anti-gouging regulations are premised. That's inherent in the judgmental term itself. However, having spent my share of time in gas lines during the energy crises of the 1970s, I believe that supporters of these rules are ignoring some even more pragmatic, consumer-based arguments for allowing prices to rise after a disaster.
In addition to the tragic loss of life and property inflicted by Sandy, the storm left the petroleum products infrastructure on which New Jersey depends paralyzed for days. Refineries were shut down, distribution terminals full of gasoline were unable to deliver product, and gas stations without power had no way to sell the fuel stored in the tanks under their forecourts. This combination represented a huge supply shock to the region, and it wasn't long before gas lines formed at those stations that had both product and electricity. New Jersey has strict and specific anti-gouging rules and is already charging merchants with violations following Sandy. Within a few days, in an effort to alleviate the queuing that resulted from the supply shortfall and the inability of retailers to raise prices, Governor Christie resorted to rationing by license plate number.
Although restricting prices might superficially appear more equitable--particularly for lower-income consumers--than allowing them to climb to the levels necessary to clear the market without long lines, it also imposes significant costs on all consumers. For starters, anti-gouging rules effectively confine motorists to their vehicles precisely when they have many other urgent priorities, including attending to their families and homes. They also implicitly put a very low monetary value on consumers' time. Waiting on line for four hours to obtain 10 gallons of gas at a pre-disaster price of $3.50/gal., instead of experiencing a much shorter wait to purchase fuel for $5.00/gal., is equivalent to being paid $3.75 per hour--around half the state's official minimum wage. This situation also increases the chances that an individual will wait for hours only to see the station run out of fuel before his or her turn comes, because demand is unchanged or temporarily higher than before the crisis. Adding odd/even rationing might reduce gas lines by limiting demand and breaking the psychology contributing to the lines, but it also compounds the harm to consumers, some of whom are left with no legal means of acquiring fuel when they need it most.
I don't expect politicians and regulators suddenly to embrace a purely market-based approach towards post-disaster pricing of necessities like fuel. However, we ought to expect them to look at the real-world results of their policies and apply some common sense and creativity to improve how they function. Anti-gouging rules clearly benefit some at the expense of others. How could we simultaneously preserve the benefits for the first group, while allowing those willing to pay a premium for emergency supplies to do so, in the process sending the appropriate price signal to reduce overall demand? One solution might be to allow gas stations with multiple pump islands to raise prices as long as they have at least one set of pumps offering the pre-disaster price. Technology should provide even more innovative and effective options.
Given the magnitude of the supply disruption post-Sandy, there was no way to avoid a serious shortage of motor fuel in the affected region. However, the appearance of long gas lines and the resort to a 1970's expedient of odd-even rationing shouldn't satisfy anyone concerning the effectiveness of the pre-existing emergency energy policies that were called into play following the storm. I can't imagine New Jerseyans being content with the outcome they experienced.
In addition to the tragic loss of life and property inflicted by Sandy, the storm left the petroleum products infrastructure on which New Jersey depends paralyzed for days. Refineries were shut down, distribution terminals full of gasoline were unable to deliver product, and gas stations without power had no way to sell the fuel stored in the tanks under their forecourts. This combination represented a huge supply shock to the region, and it wasn't long before gas lines formed at those stations that had both product and electricity. New Jersey has strict and specific anti-gouging rules and is already charging merchants with violations following Sandy. Within a few days, in an effort to alleviate the queuing that resulted from the supply shortfall and the inability of retailers to raise prices, Governor Christie resorted to rationing by license plate number.
Although restricting prices might superficially appear more equitable--particularly for lower-income consumers--than allowing them to climb to the levels necessary to clear the market without long lines, it also imposes significant costs on all consumers. For starters, anti-gouging rules effectively confine motorists to their vehicles precisely when they have many other urgent priorities, including attending to their families and homes. They also implicitly put a very low monetary value on consumers' time. Waiting on line for four hours to obtain 10 gallons of gas at a pre-disaster price of $3.50/gal., instead of experiencing a much shorter wait to purchase fuel for $5.00/gal., is equivalent to being paid $3.75 per hour--around half the state's official minimum wage. This situation also increases the chances that an individual will wait for hours only to see the station run out of fuel before his or her turn comes, because demand is unchanged or temporarily higher than before the crisis. Adding odd/even rationing might reduce gas lines by limiting demand and breaking the psychology contributing to the lines, but it also compounds the harm to consumers, some of whom are left with no legal means of acquiring fuel when they need it most.
I don't expect politicians and regulators suddenly to embrace a purely market-based approach towards post-disaster pricing of necessities like fuel. However, we ought to expect them to look at the real-world results of their policies and apply some common sense and creativity to improve how they function. Anti-gouging rules clearly benefit some at the expense of others. How could we simultaneously preserve the benefits for the first group, while allowing those willing to pay a premium for emergency supplies to do so, in the process sending the appropriate price signal to reduce overall demand? One solution might be to allow gas stations with multiple pump islands to raise prices as long as they have at least one set of pumps offering the pre-disaster price. Technology should provide even more innovative and effective options.
Given the magnitude of the supply disruption post-Sandy, there was no way to avoid a serious shortage of motor fuel in the affected region. However, the appearance of long gas lines and the resort to a 1970's expedient of odd-even rationing shouldn't satisfy anyone concerning the effectiveness of the pre-existing emergency energy policies that were called into play following the storm. I can't imagine New Jerseyans being content with the outcome they experienced.
Thursday, November 08, 2012
Push-me/Pull-you: Post-election Energy Policies
I've seen numerous commentaries on the energy implications of President Obama's narrow, 51%/49% victory. One of the most intriguing of these, from Reuters, concerned the prospects for exporting a portion of the growing output of natural gas produced from US shale deposits. This issue doesn't only affect gas drillers and their residential and industrial customers, but also developers of renewable energy projects, because of the way that gas and renewables compete in electricity markets. As much as the President's reelection, the failure of Republicans to capture control of the US Senate might turn out to be a key factor in determining the fate of potential gas exports, and by extension the environment within which renewables like wind and solar power must compete.
A variety of energy issues has been in limbo for months, pending the outcome of Tuesday's election. That includes approval of the Keystone XL crude oil pipeline from Canada, which might have gotten a favorable nudge as a result of Senate wins by pro-pipeline Democrats in North Dakota and Montana. Environmentalists are committed to blocking the pipeline, so the President must soon choose which part of his winning coalition he will disappoint. By comparison, the question of natural gas exports has received much less attention in the media, although it's been discussed extensively within energy and manufacturing circles. The likely incoming chairman of the Senate Energy and Natural Resources Committee, Ron Wyden (D-OR), appears to have strong views on the subject.
If Senator Wyden does replace the outgoing chairman, Senator Bingaman (D-NM), as expected, this would represent a shift in constituencies from a state with significant oil and gas production to one with essentially none. Senator Wyden thus brings mainly an end-user perspective to his Energy and Natural Resources role, and from that standpoint his concern about the potential price impact of gas exports, whether in the form of LNG or otherwise, is understandable, although I would argue it is also short-sighted and potentially detrimental to renewable energy, which he strongly supports.
On the surface, restrictions on the export of US gas should result in lower domestic natural gas prices than if large quantities of gas were shipped offshore. After all, low US natural gas prices, compared to those in Europe and Asia, are the main driver behind the desire to build export facilities, such as the Sabine Pass project of Cheniere Energy. Natural gas is cheaper in the US than elsewhere for several reasons, including the high and growing output from shale gas resources, as well as the epic disconnect between the natural gas price and crude oil prices, which are the basis for most international LNG contracts. US gas at the wellhead is currently trading for the oil equivalent of $21 per barrel, compared to UK Brent Crude at $107 per barrel. The extent to which exports might increase domestic prices is a matter of much speculation and study, and I wouldn't venture a guess. However, we can't just look at demand in gauging the impact of export restrictions.
The efficacy of holding down US prices by keeping more gas here also depends on the response of producers. If legislators or regulators turn the US gas market into a capped bottle, why would producers be content to supply steadily increasing quantities of gas at prices that don't provide them an attractive return? To some degree the low prices we've seen this year were the result of the combination of a weak economy and a supply glut created by contractual commitments on the part of drillers to develop gas leases at a specified pace. My understanding is that most such commitments have lapsed, and that a significant proportion of current gas supply is coming from wells that depend on the economics of their liquids output (crude oil and gas liquids), with the associated natural gas effectively a byproduct. It's not clear how rapidly gas production can continue to grow without natural gas prices that make gas-only wells economically attractive. So a US gas market with no export outlets would likely produce less gas in the long run, and that would constrain opportunities to use our abundant gas resources to support new industries, displace oil from transportation, and further reduce the use of coal in power generation.
Moreover, keeping a lid on the US gas market would compound the obstacles for renewable sources of electricity. Wind power developers and turbine manufacturers now face the expiration of the Wind Production Tax Credit (PTC). Even if it is extended, the output of wind farms competes with the output of gas turbines, while the grid relies on gas-fired power to provide a back-up for the intermittent output of wind and solar power. The cheaper the gas, the tougher it will be for renewables to make a profit. Market competition with gas will become an even bigger issue for renewables as they expand beyond the capacity of a cash-strapped federal government to continue to subsidize them. The one-year extension of the PTC under consideration could cost as much as $12 billion, an annual price tag that would only grow as renewables scale up--as they must if they are going to matter.
Navigating the complexities of allowing or restricting natural gas exports, and balancing the various constituencies involved, could provide an early test of the administration's commitment to an all-of-the-above energy strategy. That's because "all of the above"--if not merely a slogan--implies more than just producing energy from a variety of sources. It also entails competition among all these sources within a market in which some sectors of demand are declining, others growing, and new ones--including exports--are appearing all the time. Pushing back on one part of this market will have large consequences in other parts, and regulators could soon be overwhelmed by unintended consequences.
A variety of energy issues has been in limbo for months, pending the outcome of Tuesday's election. That includes approval of the Keystone XL crude oil pipeline from Canada, which might have gotten a favorable nudge as a result of Senate wins by pro-pipeline Democrats in North Dakota and Montana. Environmentalists are committed to blocking the pipeline, so the President must soon choose which part of his winning coalition he will disappoint. By comparison, the question of natural gas exports has received much less attention in the media, although it's been discussed extensively within energy and manufacturing circles. The likely incoming chairman of the Senate Energy and Natural Resources Committee, Ron Wyden (D-OR), appears to have strong views on the subject.
If Senator Wyden does replace the outgoing chairman, Senator Bingaman (D-NM), as expected, this would represent a shift in constituencies from a state with significant oil and gas production to one with essentially none. Senator Wyden thus brings mainly an end-user perspective to his Energy and Natural Resources role, and from that standpoint his concern about the potential price impact of gas exports, whether in the form of LNG or otherwise, is understandable, although I would argue it is also short-sighted and potentially detrimental to renewable energy, which he strongly supports.
On the surface, restrictions on the export of US gas should result in lower domestic natural gas prices than if large quantities of gas were shipped offshore. After all, low US natural gas prices, compared to those in Europe and Asia, are the main driver behind the desire to build export facilities, such as the Sabine Pass project of Cheniere Energy. Natural gas is cheaper in the US than elsewhere for several reasons, including the high and growing output from shale gas resources, as well as the epic disconnect between the natural gas price and crude oil prices, which are the basis for most international LNG contracts. US gas at the wellhead is currently trading for the oil equivalent of $21 per barrel, compared to UK Brent Crude at $107 per barrel. The extent to which exports might increase domestic prices is a matter of much speculation and study, and I wouldn't venture a guess. However, we can't just look at demand in gauging the impact of export restrictions.
The efficacy of holding down US prices by keeping more gas here also depends on the response of producers. If legislators or regulators turn the US gas market into a capped bottle, why would producers be content to supply steadily increasing quantities of gas at prices that don't provide them an attractive return? To some degree the low prices we've seen this year were the result of the combination of a weak economy and a supply glut created by contractual commitments on the part of drillers to develop gas leases at a specified pace. My understanding is that most such commitments have lapsed, and that a significant proportion of current gas supply is coming from wells that depend on the economics of their liquids output (crude oil and gas liquids), with the associated natural gas effectively a byproduct. It's not clear how rapidly gas production can continue to grow without natural gas prices that make gas-only wells economically attractive. So a US gas market with no export outlets would likely produce less gas in the long run, and that would constrain opportunities to use our abundant gas resources to support new industries, displace oil from transportation, and further reduce the use of coal in power generation.
Moreover, keeping a lid on the US gas market would compound the obstacles for renewable sources of electricity. Wind power developers and turbine manufacturers now face the expiration of the Wind Production Tax Credit (PTC). Even if it is extended, the output of wind farms competes with the output of gas turbines, while the grid relies on gas-fired power to provide a back-up for the intermittent output of wind and solar power. The cheaper the gas, the tougher it will be for renewables to make a profit. Market competition with gas will become an even bigger issue for renewables as they expand beyond the capacity of a cash-strapped federal government to continue to subsidize them. The one-year extension of the PTC under consideration could cost as much as $12 billion, an annual price tag that would only grow as renewables scale up--as they must if they are going to matter.
Navigating the complexities of allowing or restricting natural gas exports, and balancing the various constituencies involved, could provide an early test of the administration's commitment to an all-of-the-above energy strategy. That's because "all of the above"--if not merely a slogan--implies more than just producing energy from a variety of sources. It also entails competition among all these sources within a market in which some sectors of demand are declining, others growing, and new ones--including exports--are appearing all the time. Pushing back on one part of this market will have large consequences in other parts, and regulators could soon be overwhelmed by unintended consequences.
Wednesday, October 31, 2012
US Natural Gas Prices and the Election
Every fall my natural gas utility asks if I'd like to lock in my gas price for the next 12 months. In some respects the timing for this looks ideal. Commodity natural gas prices haven't been lower than this year's average since 1999. Gas is also historically cheap relative to other fuels. Heating oil recently averaged above $4 per gallon, while the fixed price my natural gas provider is offering equates to $1.36 per gallon, including distribution charges. However, overhanging this relatively simple choice are big uncertainties related to the economy and the potential impact of regulations on shale gas production. To complicate matters further, both of these uncertainties are entangled with the outcome of the US presidential election, and my gas provider wants my answer by next Monday.
When I last looked at this question in detail, in 2010, I concluded that the utility's offer was attractive, after scrutinizing then-current gas futures prices and the historical relationship between the futures market and "city gate" prices for Virginia, where I live. Using the same methodology, this year's offer of $0.62/therm ($6.20/MMBTU) looks reasonable. Much has changed in the interim, though, in ways that undermine the rationale for locking in consumer gas prices. The biggest benefit of a fixed price is avoiding nasty surprises during winter heating season. More than four-fifths of my household's gas consumption occurs from November through March, a period when gas prices used to be alarmingly volatile.
That's less of a concern, now, with US gas inventories high and supply ample. The same shale gas revolution that has increased domestic supply and backed out imports has also reduced volatility and promoted big shifts in demand. Since 2009 residential gas demand has been essentially flat, while demand from commercial and industrial users has grown by 6.5% and consumption in power generation is up by more than 10%, despite a lackluster economy. (Gas for use in transportation grew even faster but still constitutes less than 0.2% of total gas demand.) As a result of these shifts, peak monthly average natural gas prices since the winter of 2009-10 have occurred in summer, coinciding with air conditioning demand. With less winter price volatility, the decision to lock in prices now is mainly a bet on gas prices for the next 12 months. The outcome of that bet hinges on future supply and demand.
On the supply side, will the surge of US shale gas production continue? New regulations are among the biggest potential constraints on output. The EPA has set new rules on emissions during well completion and production, with the most expensive aspect phasing in by 2015. EPA will also issue new rules on wastewater disposal from fracking by 2014. There is growing pressure on the administration to impose federal regulation of most aspects of shale development, superseding management by the states. Thus far, the White House has avoided a sweeping crackdown that would disrupt gas markets, and the EPA administrator is on record opposing comprehensive federal regulation of all wells. However, it's not obvious whether such reticence stems from a basic belief in the national importance of this resource or the simple expedient of not killing the golden goose before the election. Governor Romney has proposed streamlining regulations affecting gas production. Next Tuesday's outcome should resolve this uncertainty.
The other big uncertainty surrounding gas prices concerns demand. High shale gas output isn't the only reason gas is cheap today. Anemic GDP growth such as the 2% rate for the third quarter reported last Friday has helped keep gas prices low. A stronger economy with higher full-time employment would put upward pressure on prices by soaking up much of the surplus production that has depressed them. However, the consequences of failing to mitigate January's "fiscal cliff"--federal budget "sequestration" and the expiration of many tax cuts--would likely drive natural gas back toward the lows we saw this spring. With the economy still the number one issue for most voters, its likely future impact on gas demand is linked with our perceptions of the candidates' economic programs and promises.
My best bet is to convince my supplier to let me wait until after the election to reply. There's nothing like additional information to improve the value of a decision. Failing that, I'm inclined to pass on this opportunity. The possibility of cheaper natural gas next year acts as a modest hedge against the risk of another recession, while the benefits of a stronger economy would more than outweigh any natural gas price increases I might experience on the upside.
When I last looked at this question in detail, in 2010, I concluded that the utility's offer was attractive, after scrutinizing then-current gas futures prices and the historical relationship between the futures market and "city gate" prices for Virginia, where I live. Using the same methodology, this year's offer of $0.62/therm ($6.20/MMBTU) looks reasonable. Much has changed in the interim, though, in ways that undermine the rationale for locking in consumer gas prices. The biggest benefit of a fixed price is avoiding nasty surprises during winter heating season. More than four-fifths of my household's gas consumption occurs from November through March, a period when gas prices used to be alarmingly volatile.
That's less of a concern, now, with US gas inventories high and supply ample. The same shale gas revolution that has increased domestic supply and backed out imports has also reduced volatility and promoted big shifts in demand. Since 2009 residential gas demand has been essentially flat, while demand from commercial and industrial users has grown by 6.5% and consumption in power generation is up by more than 10%, despite a lackluster economy. (Gas for use in transportation grew even faster but still constitutes less than 0.2% of total gas demand.) As a result of these shifts, peak monthly average natural gas prices since the winter of 2009-10 have occurred in summer, coinciding with air conditioning demand. With less winter price volatility, the decision to lock in prices now is mainly a bet on gas prices for the next 12 months. The outcome of that bet hinges on future supply and demand.
On the supply side, will the surge of US shale gas production continue? New regulations are among the biggest potential constraints on output. The EPA has set new rules on emissions during well completion and production, with the most expensive aspect phasing in by 2015. EPA will also issue new rules on wastewater disposal from fracking by 2014. There is growing pressure on the administration to impose federal regulation of most aspects of shale development, superseding management by the states. Thus far, the White House has avoided a sweeping crackdown that would disrupt gas markets, and the EPA administrator is on record opposing comprehensive federal regulation of all wells. However, it's not obvious whether such reticence stems from a basic belief in the national importance of this resource or the simple expedient of not killing the golden goose before the election. Governor Romney has proposed streamlining regulations affecting gas production. Next Tuesday's outcome should resolve this uncertainty.
The other big uncertainty surrounding gas prices concerns demand. High shale gas output isn't the only reason gas is cheap today. Anemic GDP growth such as the 2% rate for the third quarter reported last Friday has helped keep gas prices low. A stronger economy with higher full-time employment would put upward pressure on prices by soaking up much of the surplus production that has depressed them. However, the consequences of failing to mitigate January's "fiscal cliff"--federal budget "sequestration" and the expiration of many tax cuts--would likely drive natural gas back toward the lows we saw this spring. With the economy still the number one issue for most voters, its likely future impact on gas demand is linked with our perceptions of the candidates' economic programs and promises.
My best bet is to convince my supplier to let me wait until after the election to reply. There's nothing like additional information to improve the value of a decision. Failing that, I'm inclined to pass on this opportunity. The possibility of cheaper natural gas next year acts as a modest hedge against the risk of another recession, while the benefits of a stronger economy would more than outweigh any natural gas price increases I might experience on the upside.
Thursday, October 25, 2012
Solyndra's Second Chapter
The details of the reorganization plan approved Monday by the judge hearing the Solyndra bankruptcy case reminded me of the admonition of one of my mentors always to beware of unintended consequences. I'm sure the Department of Energy officials who recommended the federal loan guarantee for Solyndra in March of 2009 envisioned that the solar start-up would succeed. As a worst-case outcome, they probably anticipated the loss of the entire $535 million direct federal loan ultimately provided by the Treasury. However, in a remarkable turn of events, the actual extent of the downside for taxpayers has now expanded to nearly $900 million, due to a quirk in the tax code and a subsequent DOE decision in 2011.
This odd sequence of events starts in early 2011 when two venture investors agreed to infuse another $75 million into the already failing Solyndra. In order to facilitate this injection--presumably in hopes of protecting the government's substantial investment in the firm--the DOE agreed to allow the investors' loan to take precedence over the government's if Solyndra went bankrupt. Perhaps they thought that even in that case, they'd still recover most of the government's investment, because Solyndra had a sexy technology and a big new factory in Fremont, CA that could be sold to a competitor for close to full value. They apparently didn't appreciate that Solyndra's high-cost technology had already been bypassed by falling polysilicon prices, and that the factory and its custom equipment wouldn't be of much interest to other solar producers, who were in the process of creating a huge global overhang of solar manufacturing capacity. The Solyndra plant will now apparently be sold to a hard-drive maker for just $90 million.
In the meantime, Solyndra was piling up substantial losses running its plant and selling solar modules below cost, in order to compete with conventional solar panels that had become much cheaper. By the time Solyndra entered Chapter 11 bankruptcy, its cumulative losses apparently totaled $975 million. To put that in perspective, the combined after tax profits of First Solar, the largest US solar producer, for the three years in which the DOE's loan to Solyndra was outstanding, were $1,265 million.
What makes Solyndra's losses relevant is that, contrary to intuition, they didn't disappear in bankruptcy. Instead, via the investors' plan for emerging from bankruptcy, they became an asset. And because the DOE ceded the first place in line to private investors, it is those investors who will control those "net operating losses" retained by Solyndra's reorganized parent company, 360 Degree Solar Holdings, Inc. That company apparently kept none of Solyndra's hardware, but when it acquires other companies--in any line of business--it will be able to offset future federal tax liabilities estimated by Bloomberg at $341 million. Meanwhile, the federal government is likely to recover just 5 cents on the dollar on its "secured loan." The Solyndra loan is a gift that keeps on giving.
Hindsight is 20/20, but it seems pretty clear that the folks at DOE were outsmarted by private investors who had a much clearer picture of the stakes for which they were negotiating. As we were reminded last week, Solyndra wasn't the only investment they made that went bad. Let's hope that the others don't include similarly unpleasant surprises. Meanwhile, I wish the IRS and Alameda County the best of luck in appealing the bankruptcy judge's ruling.
This odd sequence of events starts in early 2011 when two venture investors agreed to infuse another $75 million into the already failing Solyndra. In order to facilitate this injection--presumably in hopes of protecting the government's substantial investment in the firm--the DOE agreed to allow the investors' loan to take precedence over the government's if Solyndra went bankrupt. Perhaps they thought that even in that case, they'd still recover most of the government's investment, because Solyndra had a sexy technology and a big new factory in Fremont, CA that could be sold to a competitor for close to full value. They apparently didn't appreciate that Solyndra's high-cost technology had already been bypassed by falling polysilicon prices, and that the factory and its custom equipment wouldn't be of much interest to other solar producers, who were in the process of creating a huge global overhang of solar manufacturing capacity. The Solyndra plant will now apparently be sold to a hard-drive maker for just $90 million.
In the meantime, Solyndra was piling up substantial losses running its plant and selling solar modules below cost, in order to compete with conventional solar panels that had become much cheaper. By the time Solyndra entered Chapter 11 bankruptcy, its cumulative losses apparently totaled $975 million. To put that in perspective, the combined after tax profits of First Solar, the largest US solar producer, for the three years in which the DOE's loan to Solyndra was outstanding, were $1,265 million.
What makes Solyndra's losses relevant is that, contrary to intuition, they didn't disappear in bankruptcy. Instead, via the investors' plan for emerging from bankruptcy, they became an asset. And because the DOE ceded the first place in line to private investors, it is those investors who will control those "net operating losses" retained by Solyndra's reorganized parent company, 360 Degree Solar Holdings, Inc. That company apparently kept none of Solyndra's hardware, but when it acquires other companies--in any line of business--it will be able to offset future federal tax liabilities estimated by Bloomberg at $341 million. Meanwhile, the federal government is likely to recover just 5 cents on the dollar on its "secured loan." The Solyndra loan is a gift that keeps on giving.
Hindsight is 20/20, but it seems pretty clear that the folks at DOE were outsmarted by private investors who had a much clearer picture of the stakes for which they were negotiating. As we were reminded last week, Solyndra wasn't the only investment they made that went bad. Let's hope that the others don't include similarly unpleasant surprises. Meanwhile, I wish the IRS and Alameda County the best of luck in appealing the bankruptcy judge's ruling.
Wednesday, October 17, 2012
A123 Bankruptcy Casts Doubts on EV Goals
The theory was that the federal government could guide an entire US electric vehicle (EV) industry into existence by orchestrating a constellation of grants, loans and loan guarantees to manufacturers and infrastructure developers, along with generous tax credits for purchasers. That vision was attractive, because EVs have the potential to be an important element of a long-term strategy to counter climate change and bolster energy security. However, yesterday's bankruptcy of battery-maker A123 Systems, Inc. provides a costly reality check. Along with the earlier bankruptcy of another advanced battery firm, Ener1, and disappointing battery-EV sales, it raises new doubts concerning both the government's model of industrial development and the achievability of President Obama's goal of putting one million EVs on the road by 2015.
A123 was built around a novel lithium-ion battery technology developed at MIT. For a time they were the darling of the advanced battery sector, with a market capitalization above $2 billion following its 2009 initial public offering. That IPO came on the heels of A123's receipt of a $249 million stimulus grant from the Department of Energy and $100 million of refundable tax credits from the state of Michigan. Subsequently, though, they experienced low sales and a costly battery recall that contributed to their signing a memorandum of understanding with China's Wanxiang Group to sell an 80% interest in the company for around $450 million. Instead, it now appears that Johnson Controls, a diversified company that was the recipient of a $299 million DOE advanced battery grant of its own, will end up acquiring A123's assets for around $125 million. Johnson is apparently providing "debtor-in-possession" financing for A123's Chapter 11 process. It's not clear whether Johnson would be able to draw down the unused portion of A123's federal grant.
Because of the government's close involvement with A123, and in particular its structuring of aid to A123 in a manner that left taxpayers without any call on the firm's assets ahead of suitors like Johnson Controls or Wanxiang, this event is inherently political. I was a little surprised it didn't come up in last night's presidential debate. If it does become a "talking point" in the next two weeks, however, I'd prefer to see the conversation focus on the real issues it raises. The reasons for A123's failure appear very different from those behind the much-discussed failure of loan-guarantee recipient Solyndra. While the latter ultimately called into question the judgment of officials who loaned money to Solyndra when that company's business model was already doomed, A123 highlights the much deeper challenges involved in attempting to conjure an entire industry out of thin air.
The earlier failure of GM's electric vehicle effort in the 1990s, the EV-1, demonstrated the chicken-and-egg nature of EV sales: Vehicle sales depended on recharging infrastructure that in turn depended on robust vehicle sales to justify infrastructure investment. But at least GM could begin then by relying on a mature lead-acid battery industry. Those batteries turned out to be inadequate to meet consumers' expectations of range and recharging convenience, which led to the creation of another chicken-and-egg dependence for the new EV industry: carmakers needed a reliable supply of advanced batteries from producers who couldn't invest in the capacity to make them, without knowing that vehicle sales would consume enough batteries to turn a profit. So in 2009 the administration set out to short-circuit all those inter-dependencies by simultaneously funding the key elements of these loops, including advanced battery makers. It makes me wonder if anyone involved had any direct manufacturing experience--a natural doubt considering that the entire US auto industry was restructured in 2009 by a task force without a single member who had worked in any manufacturing business, let alone the auto industry.
The main causes of A123's failure appear to have involved basic manufacturing issues of capacity utilization and quality control. The company wasn't selling enough batteries to cover its costs, and too many of the batteries it sold came back in an expensive recall. They weren't the first business to experience such growing pains, but their challenges were compounded by the burden of a manufacturing line that had been sized to meet the demand of an EV market that hasn't yet materialized. US EV sales through September amounted to just 31,000 vehicles, or less than 0.3% of total US car sales. The picture looks even worse if you subtract out sales of GM's Volt and Toyota's plug-in version of its Prius, the gasoline engines of which provide essentially unlimited range, circumventing the limitations of today's batteries. I think there's a strong argument that the government's assistance to A123 was actually a key factor in leading them to bankruptcy, by prompting A123 to grow much faster than could have been justified to its bankers or private investors.
Perhaps it's some consolation that A123's technology has apparently been snapped up by a competitor, rather than going the way of Solyndra's odd solar modules. Yet that outcome hardly justifies the casual dismissal of A123's fate by a DOE spokesman as a common occurrence in an emerging industry. That sort of talk merely perpetuates the perception of cluelessness fostered by Energy Secretary Chu's failure to hold anyone accountable for the Solyndra debacle. Yes, companies in emerging industries fall by the wayside, but the preferred response would be to examine what happened and apply the lessons learned to the rest of the "venture capital portfolio" with which the administration's industrial policy has saddled the DOE. With EV sales still low and several key EV makers experiencing delays and production problems, a thorough public review of the entire EV strategy is in order.
A123 was built around a novel lithium-ion battery technology developed at MIT. For a time they were the darling of the advanced battery sector, with a market capitalization above $2 billion following its 2009 initial public offering. That IPO came on the heels of A123's receipt of a $249 million stimulus grant from the Department of Energy and $100 million of refundable tax credits from the state of Michigan. Subsequently, though, they experienced low sales and a costly battery recall that contributed to their signing a memorandum of understanding with China's Wanxiang Group to sell an 80% interest in the company for around $450 million. Instead, it now appears that Johnson Controls, a diversified company that was the recipient of a $299 million DOE advanced battery grant of its own, will end up acquiring A123's assets for around $125 million. Johnson is apparently providing "debtor-in-possession" financing for A123's Chapter 11 process. It's not clear whether Johnson would be able to draw down the unused portion of A123's federal grant.
Because of the government's close involvement with A123, and in particular its structuring of aid to A123 in a manner that left taxpayers without any call on the firm's assets ahead of suitors like Johnson Controls or Wanxiang, this event is inherently political. I was a little surprised it didn't come up in last night's presidential debate. If it does become a "talking point" in the next two weeks, however, I'd prefer to see the conversation focus on the real issues it raises. The reasons for A123's failure appear very different from those behind the much-discussed failure of loan-guarantee recipient Solyndra. While the latter ultimately called into question the judgment of officials who loaned money to Solyndra when that company's business model was already doomed, A123 highlights the much deeper challenges involved in attempting to conjure an entire industry out of thin air.
The earlier failure of GM's electric vehicle effort in the 1990s, the EV-1, demonstrated the chicken-and-egg nature of EV sales: Vehicle sales depended on recharging infrastructure that in turn depended on robust vehicle sales to justify infrastructure investment. But at least GM could begin then by relying on a mature lead-acid battery industry. Those batteries turned out to be inadequate to meet consumers' expectations of range and recharging convenience, which led to the creation of another chicken-and-egg dependence for the new EV industry: carmakers needed a reliable supply of advanced batteries from producers who couldn't invest in the capacity to make them, without knowing that vehicle sales would consume enough batteries to turn a profit. So in 2009 the administration set out to short-circuit all those inter-dependencies by simultaneously funding the key elements of these loops, including advanced battery makers. It makes me wonder if anyone involved had any direct manufacturing experience--a natural doubt considering that the entire US auto industry was restructured in 2009 by a task force without a single member who had worked in any manufacturing business, let alone the auto industry.
The main causes of A123's failure appear to have involved basic manufacturing issues of capacity utilization and quality control. The company wasn't selling enough batteries to cover its costs, and too many of the batteries it sold came back in an expensive recall. They weren't the first business to experience such growing pains, but their challenges were compounded by the burden of a manufacturing line that had been sized to meet the demand of an EV market that hasn't yet materialized. US EV sales through September amounted to just 31,000 vehicles, or less than 0.3% of total US car sales. The picture looks even worse if you subtract out sales of GM's Volt and Toyota's plug-in version of its Prius, the gasoline engines of which provide essentially unlimited range, circumventing the limitations of today's batteries. I think there's a strong argument that the government's assistance to A123 was actually a key factor in leading them to bankruptcy, by prompting A123 to grow much faster than could have been justified to its bankers or private investors.
Perhaps it's some consolation that A123's technology has apparently been snapped up by a competitor, rather than going the way of Solyndra's odd solar modules. Yet that outcome hardly justifies the casual dismissal of A123's fate by a DOE spokesman as a common occurrence in an emerging industry. That sort of talk merely perpetuates the perception of cluelessness fostered by Energy Secretary Chu's failure to hold anyone accountable for the Solyndra debacle. Yes, companies in emerging industries fall by the wayside, but the preferred response would be to examine what happened and apply the lessons learned to the rest of the "venture capital portfolio" with which the administration's industrial policy has saddled the DOE. With EV sales still low and several key EV makers experiencing delays and production problems, a thorough public review of the entire EV strategy is in order.
Thursday, October 11, 2012
Sacramento's Role in California's Gasoline Price Spike
How much higher were gasoline prices in California last week than elsewhere? Enough to raise the national average price for unleaded regular by about $0.10 per gallon. So while the rest of us were paying an average of $3.75/gal., down slightly from the previous week, gas prices in the Golden State went up by 48 cents, leaving Californians paying nearly a dollar a gallon more than other Americans. In general the media have done a good job of explaining the direct causes for this spike: a pair of unexpected outages at large refineries in the Bay Area and L.A., combined with the difficulties of supplying the state's unique gasoline blend when local refiners fall short. Robert Rapier does an even better job of explaining the intricacies of that blend. But what's missing from all this commentary is an explanation for why the supply for the nation's largest gasoline market, with more than 11% of US sales, should be so tightly balanced that such disruptions would lead to economic hardship for consumers.
As I've indicated before, California is effectively a gasoline island. The product pipelines connecting it with neighboring Arizona and Nevada run out, not in, and the only routes between California and the other West Coast refining center north of Seattle travel over water. So the principal refineries serving the California market are in California, and obtaining supply from elsewhere that hasn't been prearranged takes time for special batches of fuel to be blended up, tankers to be chartered, and for those vessels to complete their voyages from ports as far away as the Gulf Coast or Singapore. That entails at least a couple of weeks.
In a posting I wrote in 2007 during a similar price spike in California, I referred to a 2003 study by the Energy Information Agency of the US Department of Energy, looking at an earlier California gasoline spike. (This is a recurring problem.) Among the major factors explaining the higher prices and volatility of the California gasoline market, they found,
So much for the diagnosis, but what about the cause? Tackling the local pollution from large, stationary sources like oil refineries, and from the tailpipes of the state's 31million cars and other vehicles has been a top priority for the state's Air Resources Board (CARB) since the 1970s, for good reason. However, over the years, CARB's increasingly strict regulations made it harder and less attractive to operate refineries in the state, and more difficult to blend the fuel it allowed to be sold there. As it happens, I saw much of this first-hand when I worked as an engineer in Texaco's Los Angeles refinery and later when I traded refined products, crude and feedstocks for the company's West Coast operations in the 1980s and early '90s. I watched one small refinery after another go out of business, and the magnitude of periodic price spikes grow, as the market became more constrained and isolated. I also saw refining margins for the survivors improve relative to those on the Gulf Coast and other parts of the country. These trends seemed related, since the state, by its actions, was turning California gasoline into a boutique product and effectively blocking competition from outside the state.
The normal response of companies operating in a market such as that, with growing demand and healthy margins, would have been to invest in more capacity--new refineries or major refinery expansions--and collectively to overshoot somewhat. But by then the prospect of obtaining the permits necessary to build a new refinery in California had gone from difficult to impossible, and most refining investment was focused on the substantial upgrades required to keep up with the state's periodic tightening of product specifications. And since those investments generally did little to increase output or improve product quality in ways a consumer might notice and pay a premium for, they had awful returns and dragged down the total return on investment for the entire facility. This contributed to refineries shutting down or being sold to independents with less capacity to make further such investments in the future.
The net result of all these factors is a California refining system that today is 21% smaller than in 1982, at least in terms of crude processing capacity, but must meet gasoline demand that has grown by a third in the meantime, even after shrinking from its 2006 peak. Now, when an unplanned refinery outage occurs, the result provides as classic and dramatic a demonstration as you'll ever see of the price response to a shift in the supply curve for a good with inelastic demand.
As an ex-Californian and ex-Angeleno there's no doubt in my mind that air quality, especially in Southern California, has improved as a result of many of the regulations imposed on industry and on fuels. However, you'd have to ask the state's current residents whether that result is worth the high price they periodically pay at the gas pump, or whether some degree of compromise that would have allowed refineries to expand to keep pace with demand, while cleaning up the air almost as much, would have been preferable.
As I've indicated before, California is effectively a gasoline island. The product pipelines connecting it with neighboring Arizona and Nevada run out, not in, and the only routes between California and the other West Coast refining center north of Seattle travel over water. So the principal refineries serving the California market are in California, and obtaining supply from elsewhere that hasn't been prearranged takes time for special batches of fuel to be blended up, tankers to be chartered, and for those vessels to complete their voyages from ports as far away as the Gulf Coast or Singapore. That entails at least a couple of weeks.
In a posting I wrote in 2007 during a similar price spike in California, I referred to a 2003 study by the Energy Information Agency of the US Department of Energy, looking at an earlier California gasoline spike. (This is a recurring problem.) Among the major factors explaining the higher prices and volatility of the California gasoline market, they found,
"The California refinery system runs near its capacity limits, which means there is little excess capability in the region to respond to unexpected shortfalls."
So much for the diagnosis, but what about the cause? Tackling the local pollution from large, stationary sources like oil refineries, and from the tailpipes of the state's 31million cars and other vehicles has been a top priority for the state's Air Resources Board (CARB) since the 1970s, for good reason. However, over the years, CARB's increasingly strict regulations made it harder and less attractive to operate refineries in the state, and more difficult to blend the fuel it allowed to be sold there. As it happens, I saw much of this first-hand when I worked as an engineer in Texaco's Los Angeles refinery and later when I traded refined products, crude and feedstocks for the company's West Coast operations in the 1980s and early '90s. I watched one small refinery after another go out of business, and the magnitude of periodic price spikes grow, as the market became more constrained and isolated. I also saw refining margins for the survivors improve relative to those on the Gulf Coast and other parts of the country. These trends seemed related, since the state, by its actions, was turning California gasoline into a boutique product and effectively blocking competition from outside the state.
The normal response of companies operating in a market such as that, with growing demand and healthy margins, would have been to invest in more capacity--new refineries or major refinery expansions--and collectively to overshoot somewhat. But by then the prospect of obtaining the permits necessary to build a new refinery in California had gone from difficult to impossible, and most refining investment was focused on the substantial upgrades required to keep up with the state's periodic tightening of product specifications. And since those investments generally did little to increase output or improve product quality in ways a consumer might notice and pay a premium for, they had awful returns and dragged down the total return on investment for the entire facility. This contributed to refineries shutting down or being sold to independents with less capacity to make further such investments in the future.
The net result of all these factors is a California refining system that today is 21% smaller than in 1982, at least in terms of crude processing capacity, but must meet gasoline demand that has grown by a third in the meantime, even after shrinking from its 2006 peak. Now, when an unplanned refinery outage occurs, the result provides as classic and dramatic a demonstration as you'll ever see of the price response to a shift in the supply curve for a good with inelastic demand.
As an ex-Californian and ex-Angeleno there's no doubt in my mind that air quality, especially in Southern California, has improved as a result of many of the regulations imposed on industry and on fuels. However, you'd have to ask the state's current residents whether that result is worth the high price they periodically pay at the gas pump, or whether some degree of compromise that would have allowed refineries to expand to keep pace with demand, while cleaning up the air almost as much, would have been preferable.
Thursday, October 04, 2012
Election 2012: Romney on Energy
After last week's review of President Obama's energy record and campaign materials on energy, Governor Romney's energy plans present a sharp contrast. They are based on a fundamentally different view of energy and the economy, relying on markets to allocate capital to the most productive opportunities, rather than on government to guide a mix of public and private investments along specific paths towards designated ends. They also emphasize technologies that are already deployed at scale today, not those still under development or striving to attain scale. Implicitly, the Romney plan prioritizes supplying the energy for a robust economic recovery over programs designed to address long-term environmental challenges like climate change. These positions present voters with a serious and consequential choice on November 6th.
The Romney campaign's website on energy arrays the candidate's ideas mainly in words, rather than with the kind of images and interactive features that dominate the Obama campaign's sites. Energy is the first plank of Governor Romney's five-point "Plan for a Stronger Middle Class", though it requires a little work to explore the details of his energy program. A list of bullet points is backed up by a lengthy policy paper with numerous references to external sources, but you have to look for it.
The Romney energy plan focuses mainly on oil, gas, coal and nuclear energy, which together meet 91% of current US primary energy demand and which the Department of Energy projects will still provide nearly 90% in 2020 under the policies in place today. You won't find much on his campaign's website about the new renewables that generated electricity equivalent to 2% of our energy use last year, beyond a critique of the administration's investment in Solyndra and a commitment to R&D on new energy technologies.
Among the details of his plan are support for expanded offshore drilling, including areas such as offshore Virginia that were originally in the Obama administration's early-2010 offshore development blueprint, along with a comprehensive assessment of US resources using current technology, rather than further extrapolations based on 1980s technology. Governor Romney proposes expanding energy cooperation with both Canada and Mexico and would approve the entire Keystone XL pipeline. His goal of attaining North American energy independence is aggressive, yet recent analysis by Citigroup puts it within the realm of possibility. It appears to be based on an assessment by Wood Mackenzie, a top-notch energy consultancy, indicating that US oil and natural gas liquids output could expand by 7.6 million barrels per day, with 6.7 million of that coming from federal lands and waters currently off-limits to development. That compares to US net petroleum imports of 8.5 million barrels per day in 2011.
Another aspect of the plan aimed at streamlining the permitting of energy projects could be just as useful for utility-scale renewable energy projects as for oil and gas exploration and production. Regulatory and permitting delays are among the key reasons it takes longer and costs more to develop crucial energy and infrastructure projects here than in many of the countries against which our competitive standing has been slipping. Governor Romney also proposes giving states greater control of permitting on their non-park federal lands. That could substantially increase energy access and output, especially in the west, where the federal government owns over 280 hundred million acres, or 37% of those 11 states, net of tribal lands.
There are also some missing elements. I would have liked to see more about how renewables fit into Governor Romney's vision. He apparently supports the Renewable Fuels Standard but is silent about the increasingly urgent need to reform it. He is on record against the extension of the wind Production Tax Credit (PTC), a 20-year old subsidy roughly equivalent to the current price of natural gas, yet misses the opportunity to explain how all types of energy would be treated under his proposal to reduce corporate income tax rates while broadening the tax base--policy-speak for closing loopholes and eliminating incentives. In last night's debate he said, referring to the $2.8 billion in annual tax incentives for oil and gas identified by the Department of Energy, "... if we get that tax rate from 35 percent down to 25 percent, why that $2.8 billion is on the table. Of course it's on the table. That's probably not going to survive (if) you get that rate down to 25 percent." I'd also like to hear more about how Governor Romney would address greenhouse gas emissions once the economy returns to stronger growth.
Superficially, much of the Romney energy agenda evokes a return to the pre-2008 status quo: heavy on oil, gas and coal, light on renewables, and largely ignoring climate change. I see it from a different perspective: When Barack Obama began running for President in 2007, the US was considered by many to be tapped out on conventional energy, with domestic oil and natural gas production exhibiting signs of deep and permanent decline. In that context it made sense to look beyond those resources to the potential of renewable energy and vehicle electrification, even if the transition involved would be lengthy. That approach also appeared synergistic with reducing greenhouse gas emissions, and a strategy was born. In the meantime, however, it turned out that US oil and gas were far from exhausted, and the most productive new energy technology of this decade wasn't wind, solar or biofuels, but the combination of hydraulic fracturing ("fracking") and horizontal drilling that has unlocked hundreds of trillions of cubic feet of shale gas and tens of billions of barrels of shale oil or "tight oil" resources. Since 2008 the expansion of shale gas drilling has added as much new US energy production as over 250,000 MW of wind turbines or solar panels--8x the wind and solar power added in the same interval. To the surprise of many, the big global energy opportunity of the 20-teens is US hydrocarbons. The Romney plan reflects the unexpected energy transformation we're experiencing.
As in 2008, this blog isn't in the business of endorsing candidates. Energy remains an issue that, like the Cold War, demands bi-partisan cooperation and some level of consistency from one administration or Congress to the next. However, that doesn't prevent me from observing that the energy agendas of the two campaigns are not equally well-suited for a period of serious US fiscal constraints and shrinking federal discretionary expenditures, in which our energy security and economic growth will still depend largely on fossil fuels. In that context, it's highly relevant that the "all of the above" credentials of one candidate depend on oil and gas outcomes that his policies did little to support. Of course, energy isn't the only issue that matters, but then you wouldn't be reading this if you didn't think it was important.
The Romney campaign's website on energy arrays the candidate's ideas mainly in words, rather than with the kind of images and interactive features that dominate the Obama campaign's sites. Energy is the first plank of Governor Romney's five-point "Plan for a Stronger Middle Class", though it requires a little work to explore the details of his energy program. A list of bullet points is backed up by a lengthy policy paper with numerous references to external sources, but you have to look for it.
The Romney energy plan focuses mainly on oil, gas, coal and nuclear energy, which together meet 91% of current US primary energy demand and which the Department of Energy projects will still provide nearly 90% in 2020 under the policies in place today. You won't find much on his campaign's website about the new renewables that generated electricity equivalent to 2% of our energy use last year, beyond a critique of the administration's investment in Solyndra and a commitment to R&D on new energy technologies.
Among the details of his plan are support for expanded offshore drilling, including areas such as offshore Virginia that were originally in the Obama administration's early-2010 offshore development blueprint, along with a comprehensive assessment of US resources using current technology, rather than further extrapolations based on 1980s technology. Governor Romney proposes expanding energy cooperation with both Canada and Mexico and would approve the entire Keystone XL pipeline. His goal of attaining North American energy independence is aggressive, yet recent analysis by Citigroup puts it within the realm of possibility. It appears to be based on an assessment by Wood Mackenzie, a top-notch energy consultancy, indicating that US oil and natural gas liquids output could expand by 7.6 million barrels per day, with 6.7 million of that coming from federal lands and waters currently off-limits to development. That compares to US net petroleum imports of 8.5 million barrels per day in 2011.
Another aspect of the plan aimed at streamlining the permitting of energy projects could be just as useful for utility-scale renewable energy projects as for oil and gas exploration and production. Regulatory and permitting delays are among the key reasons it takes longer and costs more to develop crucial energy and infrastructure projects here than in many of the countries against which our competitive standing has been slipping. Governor Romney also proposes giving states greater control of permitting on their non-park federal lands. That could substantially increase energy access and output, especially in the west, where the federal government owns over 280 hundred million acres, or 37% of those 11 states, net of tribal lands.
There are also some missing elements. I would have liked to see more about how renewables fit into Governor Romney's vision. He apparently supports the Renewable Fuels Standard but is silent about the increasingly urgent need to reform it. He is on record against the extension of the wind Production Tax Credit (PTC), a 20-year old subsidy roughly equivalent to the current price of natural gas, yet misses the opportunity to explain how all types of energy would be treated under his proposal to reduce corporate income tax rates while broadening the tax base--policy-speak for closing loopholes and eliminating incentives. In last night's debate he said, referring to the $2.8 billion in annual tax incentives for oil and gas identified by the Department of Energy, "... if we get that tax rate from 35 percent down to 25 percent, why that $2.8 billion is on the table. Of course it's on the table. That's probably not going to survive (if) you get that rate down to 25 percent." I'd also like to hear more about how Governor Romney would address greenhouse gas emissions once the economy returns to stronger growth.
Superficially, much of the Romney energy agenda evokes a return to the pre-2008 status quo: heavy on oil, gas and coal, light on renewables, and largely ignoring climate change. I see it from a different perspective: When Barack Obama began running for President in 2007, the US was considered by many to be tapped out on conventional energy, with domestic oil and natural gas production exhibiting signs of deep and permanent decline. In that context it made sense to look beyond those resources to the potential of renewable energy and vehicle electrification, even if the transition involved would be lengthy. That approach also appeared synergistic with reducing greenhouse gas emissions, and a strategy was born. In the meantime, however, it turned out that US oil and gas were far from exhausted, and the most productive new energy technology of this decade wasn't wind, solar or biofuels, but the combination of hydraulic fracturing ("fracking") and horizontal drilling that has unlocked hundreds of trillions of cubic feet of shale gas and tens of billions of barrels of shale oil or "tight oil" resources. Since 2008 the expansion of shale gas drilling has added as much new US energy production as over 250,000 MW of wind turbines or solar panels--8x the wind and solar power added in the same interval. To the surprise of many, the big global energy opportunity of the 20-teens is US hydrocarbons. The Romney plan reflects the unexpected energy transformation we're experiencing.
As in 2008, this blog isn't in the business of endorsing candidates. Energy remains an issue that, like the Cold War, demands bi-partisan cooperation and some level of consistency from one administration or Congress to the next. However, that doesn't prevent me from observing that the energy agendas of the two campaigns are not equally well-suited for a period of serious US fiscal constraints and shrinking federal discretionary expenditures, in which our energy security and economic growth will still depend largely on fossil fuels. In that context, it's highly relevant that the "all of the above" credentials of one candidate depend on oil and gas outcomes that his policies did little to support. Of course, energy isn't the only issue that matters, but then you wouldn't be reading this if you didn't think it was important.
Thursday, September 27, 2012
Candidates & Energy 2012: Obama
It's curious that energy hasn't been as big an issue in this year's presidential campaign as it was in 2008, the year of "Drill, baby, drill." The price of unleaded regular gasoline has averaged roughly a dime per gallon higher through September than either last year or the same period in 2008, when prices peaked at $4.11 per gallon in July. Gas prices are higher this year because global oil prices are also higher, with UK Brent crude averaging $15 per barrel over its 2008 full-year average, though without a similar spike. One explanation for the reduced focus on energy is that President Obama co-opted his opponents' "all of the above" prescription, while indicators such as US crude oil production and natural gas output and prices have been moving in favorable directions. The Obama campaign and key administration officials routinely draw a strong causal connection between those two facts, forming the basis of their campaign on energy. But is that claim true? Like the Washington Post fact checker's assessment of another frequent presidential assertion about energy, a finding of "true but false" seems appropriate.
Although I had intended to provide a side-by-side comparison of President Obama's and Governor Romney's energy agendas, it quickly became obvious that that was impractical, due to length and complexity. I'll take a look at the challenger's ideas next week. Since any re-election bid is fundamentally a referendum on the incumbent, it made sense to start with the record of an administration that came into office with an unusually clear and clearly articulated vision on energy, experienced some notable victories and defeats along the way, and ended up embracing a pair of big, emerging trends that it had done virtually nothing to foster.
That is readily apparent when it comes to oil production, which must be a core element of any "all of the above" approach, since that "all" implicitly includes fossil fuels along with renewables and efficiency. Go to the Obama campaign web page on energy and you'll see this chart:
Aside from the fact that changing the axis scale makes the trend look much more dramatic, what's entirely missing from both these charts and the websites where they appear is any cogent explanation of why oil production is rising. That requires some context about the industry and oil markets that I've overlaid in the following graphs:
Most oil projects big enough to matter aren't accomplished overnight. The process typically involves acquiring onshore or offshore leases, obtaining the necessary permits, conducting exploration activities that only proceed to the next step based on success, planning the required production wells and processing facilities, competing for internal funding against other company projects, obtaining additional permits, constructing facilities and drilling the production wells. Every step takes time. Depending on the complexity of the project, the overall timeline can span from three to seven years, and that's if no one sues to block the project. To see why oil production has been rising since 2009, we need to ask what was happening in 2003-6. The answer is that after many years of being stuck in a range of $20-30 per barrel--with an excursion down to single digits in the late 1990s--oil prices tripled during that period, mainly due to the combination of global economic growth, especially in Asia, and the lagged effect on oil project investments from that late-'90s price crash. In other words, production went up mainly because five or six years earlier the financial rewards for drilling suddenly got much bigger.
So at a minimum it's a stretch--mere spin--to claim credit for higher production that is attributable to events and perhaps policies on your predecessor's watch. However, the picture looks worse when we factor in the policies and attitudes that went into effect when this administration took office in early 2009. Recall that one of the first energy decisions of the new administration was Interior Secretary Salazar's cancellation of previously awarded oil leases in Utah. Later that year a senior Treasury official--currently chairman of the President's Council of Economic Advisers--testified before Congress that US policies were promoting the "overproduction of US oil and gas", just as the now-touted production surge was starting. For at least its first several years, the rhetoric and actions of the Obama White House were generally consistent with that view and with Mr. Obama's portrayal of oil and gas as "yesterday's energy" in his 2011 State of the Union address. The brief offshore drilling opening signaled in spring 2010 was quickly retracted following the Deepwater Horizon accident, with the imposition of a six-month offshore drilling moratorium and subsequent "permitorium". Those responses--justified or not--resulted in Gulf of Mexico production falling by 22% since mid-2010, a decline that has been masked by the tremendous success of "tight oil" exploration and production in Texas and North Dakota. (The time lag for the moratorium's effects was negligible, because the deepwater projects that were halted had already been planned and permitted.)
In fact, the President's adoption of "all of the above" is fairly recent, making headlines following his 2012 State of the Union. It represents quite an evolution from Senator Obama's 2008 emphasis on renewable energy and climate change mitigation. President Obama certainly pursued those agendas with vigor, incorporating billions of dollars of federal grants and loan guarantees for renewables in the 2009 stimulus, backing the Waxman-Markey cap-and-trade bill, and at both the Copenhagen and Cancun UN climate conferences committing the US to significant greenhouse gas reduction targets and further negotiations.
It hasn't all worked out as planned, though. Notwithstanding the high-profile bankruptcies of Solyndra--a colossal failure of due diligence by the administration--and other loan guarantee and grant beneficiaries, the output of wind, solar and other non-hydro renewable energy generation has indeed grown by 55% since 2008, increasing from 3.1% to 4.7% of total US electricity generation, equivalent to 1.9% of total energy consumption. Yet sadly the wind and solar manufacturing sectors that were to have produced so many "green jobs" are caught up in parallel waves of excess global production capacity that could take years--or wrenching consolidation--to work off. The overcapacity that has blighted the prospects of many of these companies is largely attributable to the generous incentives provided by the US and other governments from Europe to Asia. Direct wind and solar jobs accounted for just 54,000 of the US "clean economy jobs" tallied by Brookings and Battelle in their study last year, and they look no more secure than non-green jobs.
Climate policy is another area featuring a big disconnect between effort and results. With control of both Houses of Congress, the President backed a climate bill that exhibited all the worst tendencies of that body: 1,092 pages of bloated regulations and carve-outs for favored constituencies. Even to someone who had supported the idea of cap and trade for a decade, it was a dog's breakfast, configured mainly as a production-inhibiting tax on the US petroleum sector. Waxman-Markey failed to pass the Senate, and a more bi-partisan bill died in the aftermath of Deepwater Horizon and the recession. Whatever one's views on the science of climate change, costly climate legislation looked like a bad bet in a weak economy. Actual emissions have fallen, however, as a result not of policy but of another trend that wasn't on the administration's radar screen until it grew too large to ignore: shale gas. Emissions are at a 20-year low, mainly due to fuel switching from coal to cheap natural gas in the utility sector.
Another key trend cited as evidence of the effectiveness of the administration's energy policies is the reduction of oil imports that has occurred since 2008. Yet like the facts on oil production, the causes are only tenuously connected to those policies. From 2008-11, US net petroleum imports fell by 2.6 million bbl/day (MBD), including refined products. That goes a long way toward achieving then-candidate Obama's goal of reducing imports by an amount equivalent to what the US imported from the Middle East and Venezuela. However, the biggest contributor to this reduction was the 1.1 MBD increase in total US petroleum production (including natural gas liquids), followed by a 0.6 MBD drop in demand that had more to do with reduced driving and the weak economy than the early gains from tougher fuel economy rules. Increasing biofuel production associated with the 2007 Renewable Fuel Standard contributed another 0.3 MBD, although that policy now stands in urgent need of reform.
I have watched many elections in my life, and I can't honestly say I'm surprised to see an administration running on something other than its actual energy record, which in this case includes positives such as funding ARPA-E's potentially transformational energy R&D and having enough sense to keep largely out of the way of the shale gas revolution--at least for now. Yet having focused 90% of its efforts on a set of technologies that look important for the future but will still meet less than 10% of our energy needs for some time to come, they have now hitched their electoral wagon to an oil production surge that they didn't help and partly hindered. I can only imagine that this would be deeply disappointing to those who supported Mr. Obama in 2008 because of his vision for alternative energy and the environment. Nor does it provide much comfort to those who found large portions of that agenda ill-considered or premature. The President's 11th-hour conversion to "all of the above" creates great uncertainty about the course he would pursue with regard to energy for the next four years, if reelected.
Although I had intended to provide a side-by-side comparison of President Obama's and Governor Romney's energy agendas, it quickly became obvious that that was impractical, due to length and complexity. I'll take a look at the challenger's ideas next week. Since any re-election bid is fundamentally a referendum on the incumbent, it made sense to start with the record of an administration that came into office with an unusually clear and clearly articulated vision on energy, experienced some notable victories and defeats along the way, and ended up embracing a pair of big, emerging trends that it had done virtually nothing to foster.
That is readily apparent when it comes to oil production, which must be a core element of any "all of the above" approach, since that "all" implicitly includes fossil fuels along with renewables and efficiency. Go to the Obama campaign web page on energy and you'll see this chart:
It's a rescaled version of the chart below, which appears on the WhiteHouse.gov site on gas prices:
Aside from the fact that changing the axis scale makes the trend look much more dramatic, what's entirely missing from both these charts and the websites where they appear is any cogent explanation of why oil production is rising. That requires some context about the industry and oil markets that I've overlaid in the following graphs:
Most oil projects big enough to matter aren't accomplished overnight. The process typically involves acquiring onshore or offshore leases, obtaining the necessary permits, conducting exploration activities that only proceed to the next step based on success, planning the required production wells and processing facilities, competing for internal funding against other company projects, obtaining additional permits, constructing facilities and drilling the production wells. Every step takes time. Depending on the complexity of the project, the overall timeline can span from three to seven years, and that's if no one sues to block the project. To see why oil production has been rising since 2009, we need to ask what was happening in 2003-6. The answer is that after many years of being stuck in a range of $20-30 per barrel--with an excursion down to single digits in the late 1990s--oil prices tripled during that period, mainly due to the combination of global economic growth, especially in Asia, and the lagged effect on oil project investments from that late-'90s price crash. In other words, production went up mainly because five or six years earlier the financial rewards for drilling suddenly got much bigger.
So at a minimum it's a stretch--mere spin--to claim credit for higher production that is attributable to events and perhaps policies on your predecessor's watch. However, the picture looks worse when we factor in the policies and attitudes that went into effect when this administration took office in early 2009. Recall that one of the first energy decisions of the new administration was Interior Secretary Salazar's cancellation of previously awarded oil leases in Utah. Later that year a senior Treasury official--currently chairman of the President's Council of Economic Advisers--testified before Congress that US policies were promoting the "overproduction of US oil and gas", just as the now-touted production surge was starting. For at least its first several years, the rhetoric and actions of the Obama White House were generally consistent with that view and with Mr. Obama's portrayal of oil and gas as "yesterday's energy" in his 2011 State of the Union address. The brief offshore drilling opening signaled in spring 2010 was quickly retracted following the Deepwater Horizon accident, with the imposition of a six-month offshore drilling moratorium and subsequent "permitorium". Those responses--justified or not--resulted in Gulf of Mexico production falling by 22% since mid-2010, a decline that has been masked by the tremendous success of "tight oil" exploration and production in Texas and North Dakota. (The time lag for the moratorium's effects was negligible, because the deepwater projects that were halted had already been planned and permitted.)
In fact, the President's adoption of "all of the above" is fairly recent, making headlines following his 2012 State of the Union. It represents quite an evolution from Senator Obama's 2008 emphasis on renewable energy and climate change mitigation. President Obama certainly pursued those agendas with vigor, incorporating billions of dollars of federal grants and loan guarantees for renewables in the 2009 stimulus, backing the Waxman-Markey cap-and-trade bill, and at both the Copenhagen and Cancun UN climate conferences committing the US to significant greenhouse gas reduction targets and further negotiations.
It hasn't all worked out as planned, though. Notwithstanding the high-profile bankruptcies of Solyndra--a colossal failure of due diligence by the administration--and other loan guarantee and grant beneficiaries, the output of wind, solar and other non-hydro renewable energy generation has indeed grown by 55% since 2008, increasing from 3.1% to 4.7% of total US electricity generation, equivalent to 1.9% of total energy consumption. Yet sadly the wind and solar manufacturing sectors that were to have produced so many "green jobs" are caught up in parallel waves of excess global production capacity that could take years--or wrenching consolidation--to work off. The overcapacity that has blighted the prospects of many of these companies is largely attributable to the generous incentives provided by the US and other governments from Europe to Asia. Direct wind and solar jobs accounted for just 54,000 of the US "clean economy jobs" tallied by Brookings and Battelle in their study last year, and they look no more secure than non-green jobs.
Climate policy is another area featuring a big disconnect between effort and results. With control of both Houses of Congress, the President backed a climate bill that exhibited all the worst tendencies of that body: 1,092 pages of bloated regulations and carve-outs for favored constituencies. Even to someone who had supported the idea of cap and trade for a decade, it was a dog's breakfast, configured mainly as a production-inhibiting tax on the US petroleum sector. Waxman-Markey failed to pass the Senate, and a more bi-partisan bill died in the aftermath of Deepwater Horizon and the recession. Whatever one's views on the science of climate change, costly climate legislation looked like a bad bet in a weak economy. Actual emissions have fallen, however, as a result not of policy but of another trend that wasn't on the administration's radar screen until it grew too large to ignore: shale gas. Emissions are at a 20-year low, mainly due to fuel switching from coal to cheap natural gas in the utility sector.
Another key trend cited as evidence of the effectiveness of the administration's energy policies is the reduction of oil imports that has occurred since 2008. Yet like the facts on oil production, the causes are only tenuously connected to those policies. From 2008-11, US net petroleum imports fell by 2.6 million bbl/day (MBD), including refined products. That goes a long way toward achieving then-candidate Obama's goal of reducing imports by an amount equivalent to what the US imported from the Middle East and Venezuela. However, the biggest contributor to this reduction was the 1.1 MBD increase in total US petroleum production (including natural gas liquids), followed by a 0.6 MBD drop in demand that had more to do with reduced driving and the weak economy than the early gains from tougher fuel economy rules. Increasing biofuel production associated with the 2007 Renewable Fuel Standard contributed another 0.3 MBD, although that policy now stands in urgent need of reform.
I have watched many elections in my life, and I can't honestly say I'm surprised to see an administration running on something other than its actual energy record, which in this case includes positives such as funding ARPA-E's potentially transformational energy R&D and having enough sense to keep largely out of the way of the shale gas revolution--at least for now. Yet having focused 90% of its efforts on a set of technologies that look important for the future but will still meet less than 10% of our energy needs for some time to come, they have now hitched their electoral wagon to an oil production surge that they didn't help and partly hindered. I can only imagine that this would be deeply disappointing to those who supported Mr. Obama in 2008 because of his vision for alternative energy and the environment. Nor does it provide much comfort to those who found large portions of that agenda ill-considered or premature. The President's 11th-hour conversion to "all of the above" creates great uncertainty about the course he would pursue with regard to energy for the next four years, if reelected.