Last Friday I was in Washington, DC for the presentation of the International Energy Agency's latest report on natural gas, "Golden Rules for A Golden Age of Gas." It is a follow-up to last year's IEA scenario describing the enormous gas potential now being unlocked by new combinations of technology. According to IEA's chief economist, Fatih Birol, who was the lead speaker at the event at the Carnegie Endowment for International Peace, the new report addresses the key uncertainty in delivering on that potential, including the potential of new gas supplies to "fracture established balances in the world energy system." In IEA's view the resources and technologies are in place, but environmental and social challenges represent serious potential roadblocks; overcoming those obstacles calls for a new set of principles along the lines of the ones included in the report. Fundamentally, as Dr. Birol put it, the industry must focus on its "social license to operate", if it is to develop the massive global resources of shale and other unconventional gas to the extent now being envisioned. I believe many in the industry would agree that that license can't be taken for granted.
The report spells out seven principles that IEA sees as prerequisites for securing the necessary concurrence from governments and publics. While several of them merely enunciate common sense, others will likely be controversial on one side or the other--if not in theory then in their implementation. IEA's description of these principles can be found in the report's executive summary. I would paraphrase them as:
1. Operate with transparency
2. Choose appropriate sites
3. Contain potential contaminants
4. Be vigilant with water!
5. Control emissions
6. Recognize scale
7. Regulate carefully
None of these is likely to startle my regular readers, since I've been writing about shale gas extraction and its potential economic, environmental and geopolitical consequences for several years. The aspect of these principles that got my attention during Friday's presentation concerned IEA's admonition to "Be ready to think big." Dr. Birol cited statistics indicating that there are currently around 100,000 unconventional wells in the US today--a figure that might include unconventional oil wells. Supplying the levels of shale gas forecasted by IEA and other agencies would require on the order of one million wells. That compares to a total US well population of roughly a half-million. Drilling on that scale requires that we get it right, because if we don't, even small consequences could compound. However, Dr. Birol also made it very clear that in the view of the IEA, the industry is entirely capable of getting it right.
The findings of this report--at least the high-level findings--have been widely embraced across the environmental and business spectrum. Among groups embracing the report are the American Petroleum Institute and the Investor Environmental Health Network, while EPA Assistant Administrator Gina McCarthy, who was also on Friday's panel, seemed to place her agency's regulatory approach to shale gas in the context of IEA's principles. The harshest criticism I've seen so far is that while it acknowledges the industry's work on best practices, it fails to recognize that much of this is already standard practice, at least in the US. Along those lines, API and the American Natural Gas Alliance (ANGA) are jointly issuing a new report on methane emissions from hydraulically fractured ("fracked") gas wells today.
IEA's report and the early reactions to it clearly illustrate that despite the many thousands of unconventional gas wells that have already been drilled, and the dramatic impact of shale gas on both natural prices and gas-dependent industries, we are still in the early days of a possible global energy revolution. The extent of that revolution hasn't yet been determined, and it will be shaped as much by the reactions of numerous stakeholders as by the investment plans of producers. Whether you see that as a good or bad thing, it's an indisputable feature of the world in which we now live. However, I don't think it's appropriate to view IEA's seven principles exclusively as a set of rules to be imposed on a reluctant industry; they're as much about getting the rest of society comfortable with an energy resource that could provide enormous economic and environmental benefits, globally, particularly with regard to greenhouse gas emissions. Although Dr. Birol emphasized that unleashing all this shale gas won't be sufficient to solve the climate problem, he also demonstrated that without it, our chances of reining in emissions look even worse, because the main trade-off globally is not gas vs. renewables, but gas vs. coal. Getting this right is crucial for many reasons, and the IEA's report looks like a helpful contribution to the dialogue that must take place.
Monday, June 04, 2012
Wednesday, May 23, 2012
Can the US Military Afford More Biofuels?
Last week the US House of Representatives passed the fiscal 2013 National Defense Authorization Act by a wide, bi-partisan margin. It included two controversial provisions relating to energy that will presumably be debated when the Senate Armed Services Committee takes up the bill this week. Sections 313 and 314 would exempt the Department of Defense from a provision of the Energy Independence and Security Act of 2007 (EISA) barring the government from purchasing alternative fuels with higher emissions than conventional fossil fuels, while prohibiting the purchase of any alternative fuel that costs more than the conventional fuel it would replace, except for testing and certification purposes. If enacted, the bill would require drastic revisions to the current alternative energy strategies of the US military branches.
It would be easier to attribute these provisions to partisan maneuvering, if our economic and fiscal circumstances hadn't changed so dramatically subsequent to the passage of EISA in 2007. Although I don't dismiss the influence of election-year politics in such matters, we are now in the third full year of a recovery so weak that many Americans still think we're in a recession, and we face deficits and a ticking debt bomb that forced a reluctant Congress to agree to deep spending cuts starting next January. Nearly $500 billion of those cuts are targeted at military spending. Moreover, our perspective on US energy security has been altered by the emergence of shale gas and so-called "tight oil", and by our recent shift from net importer to net exporter of petroleum products--though certainly not of crude oil. While it remains desirable for the US military to diversify its energy sources, the value of that diversification has arguably fallen. Meanwhile, the biofuels industry, despite tremendous growth and advances, has been unable thus far to compete with petroleum-based fuels without either large subsidies or strict mandates, even with a global price of oil that has remained consistently above $100 per barrel since January 2011.
Last year I had a couple of opportunities to question Defense Department officials about their alternative energy strategies, as part of an Army/Air Force energy forum and a subsequent Air Force media briefing at the Pentagon. Although I was impressed by the changing military culture concerning energy and the methodical way they were approaching the introduction of new fuels, I was concerned that at some point the services' procurement of higher-cost renewable fuels would conflict with their other priorities, including the need to replace equipment worn out in Iraq and Afghanistan and to field the next generation of aircraft and naval vessels. What I thought I heard very clearly from the Air Force Deputy Assistant Secretary for energy was that his service was not going into the fuel-production business, and would only buy renewable fuels--other than for certification with their fleet--if they were competitive with conventional fuels. That approach seems very different than the one embodied in the Navy's "Great Green Fleet" initiative.
The rationale behind the military's adoption of alternative fuels rests on many complex issues, including the vulnerability of military supply chains and budgets to potential disruptions in oil supplies and price spikes, consistency with the government's imposition of renewable energy mandates on the private sector, and the desirability of reducing the environmental footprint of the military's global activities. There's also the human dimension of personnel put at risk delivering fuel to front-line units, although it's not clear how biofuels would alleviate that risk unless they were produced in forward locations. In any case, however, all these concerns must be reconciled with a realistic response to budget constraints. That looks extremely challenging, and it shouldn't be divorced from deeper questions about the evolving drivers for biofuels or other alternative fuels for the US military.
Consider the question of supply disruptions, for example. US oil production looks set to continue increasing and oil imports to keep falling, while we now enjoy a refining surplus that is supporting new product exports. We also have a Strategic Petroleum Reserve that could replace up to half of our net crude oil imports for up to 5 months, or a smaller disruption for much longer. As a result of these factors, it's become more difficult to envision a scenario in which an oil market event affected the military's access to fuels in a manner that the present renewable energy industry could alleviate. And with the cost of most alternatives still above even today's elevated prices for oil and its products, the investment required to develop an alternative fuel industry capable of making a meaningful dent in the military's needs under such a scenario would be very substantial. Should the military make that investment, should someone else, or should it be left to the market? And that doesn't begin to address the issues related to the non-renewable alternative fuels that would be enabled by Section 313, including synthetic fuels derived from natural gas or coal, though these would still be subject to the restriction that they must be price-competitive with conventional fuels.
I suspect that the House bill will not be the last word on this subject, though I also imagine that in the new world of "sequestered" budgets and the fiscal challenges that lie ahead, the US military may need to rethink what can be achieved in this area without sacrificing readiness and combat capabilities. It's also important to note that the 2013 Defense Authorization Act's provisions on alternative fuels shouldn't affect the services' efforts to integrate renewable electricity generation, which looks like a real boon for some forward-deployed applications.
It would be easier to attribute these provisions to partisan maneuvering, if our economic and fiscal circumstances hadn't changed so dramatically subsequent to the passage of EISA in 2007. Although I don't dismiss the influence of election-year politics in such matters, we are now in the third full year of a recovery so weak that many Americans still think we're in a recession, and we face deficits and a ticking debt bomb that forced a reluctant Congress to agree to deep spending cuts starting next January. Nearly $500 billion of those cuts are targeted at military spending. Moreover, our perspective on US energy security has been altered by the emergence of shale gas and so-called "tight oil", and by our recent shift from net importer to net exporter of petroleum products--though certainly not of crude oil. While it remains desirable for the US military to diversify its energy sources, the value of that diversification has arguably fallen. Meanwhile, the biofuels industry, despite tremendous growth and advances, has been unable thus far to compete with petroleum-based fuels without either large subsidies or strict mandates, even with a global price of oil that has remained consistently above $100 per barrel since January 2011.
Last year I had a couple of opportunities to question Defense Department officials about their alternative energy strategies, as part of an Army/Air Force energy forum and a subsequent Air Force media briefing at the Pentagon. Although I was impressed by the changing military culture concerning energy and the methodical way they were approaching the introduction of new fuels, I was concerned that at some point the services' procurement of higher-cost renewable fuels would conflict with their other priorities, including the need to replace equipment worn out in Iraq and Afghanistan and to field the next generation of aircraft and naval vessels. What I thought I heard very clearly from the Air Force Deputy Assistant Secretary for energy was that his service was not going into the fuel-production business, and would only buy renewable fuels--other than for certification with their fleet--if they were competitive with conventional fuels. That approach seems very different than the one embodied in the Navy's "Great Green Fleet" initiative.
The rationale behind the military's adoption of alternative fuels rests on many complex issues, including the vulnerability of military supply chains and budgets to potential disruptions in oil supplies and price spikes, consistency with the government's imposition of renewable energy mandates on the private sector, and the desirability of reducing the environmental footprint of the military's global activities. There's also the human dimension of personnel put at risk delivering fuel to front-line units, although it's not clear how biofuels would alleviate that risk unless they were produced in forward locations. In any case, however, all these concerns must be reconciled with a realistic response to budget constraints. That looks extremely challenging, and it shouldn't be divorced from deeper questions about the evolving drivers for biofuels or other alternative fuels for the US military.
Consider the question of supply disruptions, for example. US oil production looks set to continue increasing and oil imports to keep falling, while we now enjoy a refining surplus that is supporting new product exports. We also have a Strategic Petroleum Reserve that could replace up to half of our net crude oil imports for up to 5 months, or a smaller disruption for much longer. As a result of these factors, it's become more difficult to envision a scenario in which an oil market event affected the military's access to fuels in a manner that the present renewable energy industry could alleviate. And with the cost of most alternatives still above even today's elevated prices for oil and its products, the investment required to develop an alternative fuel industry capable of making a meaningful dent in the military's needs under such a scenario would be very substantial. Should the military make that investment, should someone else, or should it be left to the market? And that doesn't begin to address the issues related to the non-renewable alternative fuels that would be enabled by Section 313, including synthetic fuels derived from natural gas or coal, though these would still be subject to the restriction that they must be price-competitive with conventional fuels.
I suspect that the House bill will not be the last word on this subject, though I also imagine that in the new world of "sequestered" budgets and the fiscal challenges that lie ahead, the US military may need to rethink what can be achieved in this area without sacrificing readiness and combat capabilities. It's also important to note that the 2013 Defense Authorization Act's provisions on alternative fuels shouldn't affect the services' efforts to integrate renewable electricity generation, which looks like a real boon for some forward-deployed applications.
Friday, May 18, 2012
E15's Problems Are Symptomatic of A Failing Biofuels Policy
A new report on automobile engine durability casts further doubt on the compatibility of mid-level ethanol blends such as E15 (15% ethanol, 85% gasoline) with the existing US light-duty vehicle fleet. The report was issued this week by the Coordinating Research Council (CRC) under the auspices of API, Global Automakers, and the Alliance of Automobile Manufacturers. It found that at least some of the vehicles included in EPA's certification of E15 for use in cars manufactured since 2001 experienced excessive valve wear and other mechanical problems over the course of a simulated engine lifetime. Together with previous research highlighting the risks of E15 for gas station pumps, the report's findings raise serious questions about the federal government's current ethanol policy and who will ultimately bear its hidden costs.
I've written extensively about the EPA's approval of E15 for use in vehicles and the underlying rationale for increasing the ethanol content of most gasoline beyond the 10% limit (E10) for which most cars on the road today were designed. At current volumes, domestically produced corn-based ethanol accounts for roughly 10% of all US gasoline and displaces the energy equivalent of 600,000 barrels per day of imported petroleum products. However, without increasing the amount of ethanol blended into each gallon of gasoline, and in the absence of a miraculous transformation in the public's minuscule appetite for E85 (the 85% ethanol blend sold for flexible fuel vehicles) the US ethanol strategy has hit its natural limit. Since US gasoline consumption, which prior to the recession routinely grew at 1-2% per year, has stalled at a level comparable to what we used ten years ago, the enthusiasm of the US ethanol industry for E15 to expand its market is entirely understandable.
The CRC's results have been criticized by both the ethanol industry and the Department of Energy. Although I don't have the background to judge CRC's report assumption by assumption and result by result, it does appear that many of the criticisms raised by the DOE were addressed in the body of the report, including the choice of ethanol-free gasoline as the reference fuel. As for complaints that the auto and oil producers have a vested interest in making E15 look bad, ethanol producers are at least as conflicted for their part. Moreover, without impugning the integrity of the fine folks at the DOE, the federal government also has a significant conflict of interest in this matter: The administration and its cabinet agencies are stewards of a 2007 national biofuels policy that now depends on the adoption of mid-level ethanol blends like E15 if it is to have any chance of reaching its goal of 36 billion ethanol-equivalent gallons per year by 2022, from around 15 billion gallons per year today. The apparent damage to some engines running on E15 under test conditions similar to those used by the car manufacturers for their own product testing highlights risks that must be addressed before consumers should be asked to put this fuel into their cars.
In addition to concerns about the safety of this fuel for the mechanical integrity of the tens of millions of vehicles for which the EPA has approved it, including both of my family's vehicles, E15 still faces substantial practical obstacles to its widespread distribution--obstacles that will likely require significant new federal funding to overcome. My industry contacts tell me that gasoline retailers considering selling E15 must install brand new gas pumps, because the nationally recognized testing laboratories like UL won't certify existing product dispensers for use with E15. Anyone who ignores this requirement faces serious liabilities and could end up in violation of local fire codes. So not only would retailers selling E15 instead of E10 be excluding a large portion of their existing market--at a minimum all pre-2001 cars--but they would have to make significant investments to do so. Such investments are unlikely to be repaid by higher prices for E15 than for E10, because if anything, E15 should sell for a discount to E10. Its nearly 2% lower energy content than E10 would translate into a requirement for roughly one extra fill-up a year for the average driver, or a penalty of about $37 per year at current prices.
There's an obvious solution for the risks that the administration is asking motorists to take on with E15 fuel. Since neither vehicle manufacturers nor fuel retailers are prepared to accept the liability for excessive engine wear or fuel system damage from using E15 instead of E10 or purer gasoline--a position the Congress is considering granting statutory protection--the federal government should step up to this role. The DOE and EPA claim E15 is safe for cars. In the private sector, such claims would have to be backed up by warranties, explicit or implied. Why should this situation be any different? The President should therefore instruct DOE and EPA to carve out a portion of their annual budgets--after cuts--to fund a new federal warranty program for vehicles damaged by E15. If these agencies are unwilling to stand behind their assessment of E15, then perhaps this fuel is not as ready for prime time as they suggest. In any case, foisting this liability on consumers would represent a hidden and likely regressive new tax.
I've written extensively about the EPA's approval of E15 for use in vehicles and the underlying rationale for increasing the ethanol content of most gasoline beyond the 10% limit (E10) for which most cars on the road today were designed. At current volumes, domestically produced corn-based ethanol accounts for roughly 10% of all US gasoline and displaces the energy equivalent of 600,000 barrels per day of imported petroleum products. However, without increasing the amount of ethanol blended into each gallon of gasoline, and in the absence of a miraculous transformation in the public's minuscule appetite for E85 (the 85% ethanol blend sold for flexible fuel vehicles) the US ethanol strategy has hit its natural limit. Since US gasoline consumption, which prior to the recession routinely grew at 1-2% per year, has stalled at a level comparable to what we used ten years ago, the enthusiasm of the US ethanol industry for E15 to expand its market is entirely understandable.
The CRC's results have been criticized by both the ethanol industry and the Department of Energy. Although I don't have the background to judge CRC's report assumption by assumption and result by result, it does appear that many of the criticisms raised by the DOE were addressed in the body of the report, including the choice of ethanol-free gasoline as the reference fuel. As for complaints that the auto and oil producers have a vested interest in making E15 look bad, ethanol producers are at least as conflicted for their part. Moreover, without impugning the integrity of the fine folks at the DOE, the federal government also has a significant conflict of interest in this matter: The administration and its cabinet agencies are stewards of a 2007 national biofuels policy that now depends on the adoption of mid-level ethanol blends like E15 if it is to have any chance of reaching its goal of 36 billion ethanol-equivalent gallons per year by 2022, from around 15 billion gallons per year today. The apparent damage to some engines running on E15 under test conditions similar to those used by the car manufacturers for their own product testing highlights risks that must be addressed before consumers should be asked to put this fuel into their cars.
In addition to concerns about the safety of this fuel for the mechanical integrity of the tens of millions of vehicles for which the EPA has approved it, including both of my family's vehicles, E15 still faces substantial practical obstacles to its widespread distribution--obstacles that will likely require significant new federal funding to overcome. My industry contacts tell me that gasoline retailers considering selling E15 must install brand new gas pumps, because the nationally recognized testing laboratories like UL won't certify existing product dispensers for use with E15. Anyone who ignores this requirement faces serious liabilities and could end up in violation of local fire codes. So not only would retailers selling E15 instead of E10 be excluding a large portion of their existing market--at a minimum all pre-2001 cars--but they would have to make significant investments to do so. Such investments are unlikely to be repaid by higher prices for E15 than for E10, because if anything, E15 should sell for a discount to E10. Its nearly 2% lower energy content than E10 would translate into a requirement for roughly one extra fill-up a year for the average driver, or a penalty of about $37 per year at current prices.
There's an obvious solution for the risks that the administration is asking motorists to take on with E15 fuel. Since neither vehicle manufacturers nor fuel retailers are prepared to accept the liability for excessive engine wear or fuel system damage from using E15 instead of E10 or purer gasoline--a position the Congress is considering granting statutory protection--the federal government should step up to this role. The DOE and EPA claim E15 is safe for cars. In the private sector, such claims would have to be backed up by warranties, explicit or implied. Why should this situation be any different? The President should therefore instruct DOE and EPA to carve out a portion of their annual budgets--after cuts--to fund a new federal warranty program for vehicles damaged by E15. If these agencies are unwilling to stand behind their assessment of E15, then perhaps this fuel is not as ready for prime time as they suggest. In any case, foisting this liability on consumers would represent a hidden and likely regressive new tax.
Wednesday, May 16, 2012
Are Chesapeake's Problems A Red Flag For Shale Gas?
Chesapeake Energy has been in the news a lot, lately, concerning both the significant challenges it faces in financing its ambitious development program, and its high-profile CEO, who was recently forced to relinquish his role as Chairman. The company's stock is trading for half its value one year ago and less than a fourth of its 2008 peak. Chesapeake is the second-largest producer of natural gas in the US after ExxonMobil, and probably the company most associated with the shale gas revolution, yet it is struggling. I wouldn't be surprised if skeptics regarded the firm's travails as a warning that the transformative potential of shale gas for the US has been oversold. However, in evaluating that concern it's important to distinguish among the physical resource, the economics of the industry, and the unusual business model of this one company. Investors and policy makers may not share the same perspective on these issues.
Start with this key fact: If Chesapeake is in trouble, it isn't because the gas resource isn't there or can't be exploited profitably at a reasonable gas price. We'll come back to that. Fundamentally, Chesapeake is on the wrong side of a historic divergence between US crude oil and natural gas prices, and it is playing catch-up to get on the right side of that spread. This is the downside of natural gas that is trading for the equivalent of $15 per barrel when the global crude oil price--and the price of the most valuable US crude--is still over $100 per barrel. That relationship is great for US energy consumers but lousy for US gas producers. It's particularly difficult for Chesapeake, because the company has embarked on a strategy of reducing its focus on natural gas and increasing its production of liquids--crude oil and natural gas byproducts like pentane, butane and propane. That shift requires significant new investments at a time when the cash flow from its core gas properties has fallen off, despite steadily increasing output. It also doesn't help that Cheseapeake began this strategic shift later than competitors like EOG Resources.
Chesapeake's problems are further complicated by its business model, which has focused on finding and proving resources and then selling them down to fund the next big project. Consider transactions such as last year's sales of one-third interests in Chesapeake's Eagle Ford and Niobara shale holdings to China-based CNOOC for around $1.6 B plus a substantial share of development costs. This isn't your father's gas company. But with natural gas prices so low--even a year out they're still only equivalent to $20/bbl--its existing portfolio of gas assets is worth less to potential buyers. Other companies such as BHP that have bought shale assets in the last couple of years are reportedly considering write-downs. As a result of these market conditions, Chesapeake is apparently looking at a variety of new funding opportunities, including selling interests in oil-bearing properties and pre-selling production streams.
I don't have an opinion on whether they'll navigate these rapids successfully or not. I'm not in the business of providing investment advice to my readers, nor do I have any financial interest in Chesapeake. My interest here is in the implications of Chesapeake's dilemma for the larger US energy situation. The current low natural gas prices are clearly putting a lot of stress on independent producers, including the majority that have much simpler business models than Chesapeake's, based on acquiring leases, producing gas, and generating revenues that exceed their costs. If low prices persist, then a lot of producers could be in deep trouble, and some of them won't make it. That's the risk they took. However, the more salient question is what all that means for US natural gas production, which last year broke the production record set in 1973, when we produced 60% more crude oil than today. Could an industry shakeout lead to lower US natural gas production?
One indicator is that drilling for gas has already slowed significantly. According to Energy Information Agency statistics, the number of exploration and development wells targeting gas is down sharply, while those pursuing more valuable oil are up. Sometime soon that switch should be reflected in output trends, though because of the higher productivity of shale gas wells actual gas production may not decline before demand picks up. In its latest investor presentation Chesapeake forecasted producing nearly as much gas in 2013 as last year, despite its big shift to liquids.
As odd as it may sound, the future trajectory of US gas production likely depends on a race between potential supply and potential demand, both of which are enormous. The oil & gas industry hasn't seen the likes of this since the 1980s, and perhaps not since the early 20th century. Today's shale gas output is just scratching the surface of a new resource conservatively estimated at 482 trillion cubic feet (TCF), or 96 times 2010's shale gas output of 5 TCF. Meanwhile, gas is already eating coal's lunch in the utility sector, reducing the latter's share of electricity generation by about 6 percent of the market in the first two months of this year, compared to 2011. The opportunity in transportation is even larger, though clearly more difficult to exploit, because of infrastructure and fleet investments. Chesapeake seems to understand this, given the money it's investing in market development, on both advocacy and specific projects to turn gas into transportation fuels or use it directly in cars and trucks.
If natural gas could be stored and shipped as easily as oil, the current oversupply wouldn't be a problem, nor would domestic producers be forced to pace their expansions to match the growth of demand or exports. However, gas producers have always had to develop major new resources in tandem with markets, with that discipline often enforced by price, as we are seeing today. Time will tell whether Chesapeake expanded too rapidly, or like so many others merely missed the warning signs of the recession and financial crisis that hobbled demand growth at just the wrong time for them. Yet no matter how their story turns out, the fate of US shale gas is not dependent on the fortunes of a single company, and there will be plenty of larger, better-capitalized players waiting to snap up the assets of any first-generation shale gas producers that don't make it. That's because no matter how challenging today's low prices are for producers, the prices that prevailed just a year or two ago were adequate to support the growth of both production and new demand.
Start with this key fact: If Chesapeake is in trouble, it isn't because the gas resource isn't there or can't be exploited profitably at a reasonable gas price. We'll come back to that. Fundamentally, Chesapeake is on the wrong side of a historic divergence between US crude oil and natural gas prices, and it is playing catch-up to get on the right side of that spread. This is the downside of natural gas that is trading for the equivalent of $15 per barrel when the global crude oil price--and the price of the most valuable US crude--is still over $100 per barrel. That relationship is great for US energy consumers but lousy for US gas producers. It's particularly difficult for Chesapeake, because the company has embarked on a strategy of reducing its focus on natural gas and increasing its production of liquids--crude oil and natural gas byproducts like pentane, butane and propane. That shift requires significant new investments at a time when the cash flow from its core gas properties has fallen off, despite steadily increasing output. It also doesn't help that Cheseapeake began this strategic shift later than competitors like EOG Resources.
Chesapeake's problems are further complicated by its business model, which has focused on finding and proving resources and then selling them down to fund the next big project. Consider transactions such as last year's sales of one-third interests in Chesapeake's Eagle Ford and Niobara shale holdings to China-based CNOOC for around $1.6 B plus a substantial share of development costs. This isn't your father's gas company. But with natural gas prices so low--even a year out they're still only equivalent to $20/bbl--its existing portfolio of gas assets is worth less to potential buyers. Other companies such as BHP that have bought shale assets in the last couple of years are reportedly considering write-downs. As a result of these market conditions, Chesapeake is apparently looking at a variety of new funding opportunities, including selling interests in oil-bearing properties and pre-selling production streams.
I don't have an opinion on whether they'll navigate these rapids successfully or not. I'm not in the business of providing investment advice to my readers, nor do I have any financial interest in Chesapeake. My interest here is in the implications of Chesapeake's dilemma for the larger US energy situation. The current low natural gas prices are clearly putting a lot of stress on independent producers, including the majority that have much simpler business models than Chesapeake's, based on acquiring leases, producing gas, and generating revenues that exceed their costs. If low prices persist, then a lot of producers could be in deep trouble, and some of them won't make it. That's the risk they took. However, the more salient question is what all that means for US natural gas production, which last year broke the production record set in 1973, when we produced 60% more crude oil than today. Could an industry shakeout lead to lower US natural gas production?
One indicator is that drilling for gas has already slowed significantly. According to Energy Information Agency statistics, the number of exploration and development wells targeting gas is down sharply, while those pursuing more valuable oil are up. Sometime soon that switch should be reflected in output trends, though because of the higher productivity of shale gas wells actual gas production may not decline before demand picks up. In its latest investor presentation Chesapeake forecasted producing nearly as much gas in 2013 as last year, despite its big shift to liquids.
As odd as it may sound, the future trajectory of US gas production likely depends on a race between potential supply and potential demand, both of which are enormous. The oil & gas industry hasn't seen the likes of this since the 1980s, and perhaps not since the early 20th century. Today's shale gas output is just scratching the surface of a new resource conservatively estimated at 482 trillion cubic feet (TCF), or 96 times 2010's shale gas output of 5 TCF. Meanwhile, gas is already eating coal's lunch in the utility sector, reducing the latter's share of electricity generation by about 6 percent of the market in the first two months of this year, compared to 2011. The opportunity in transportation is even larger, though clearly more difficult to exploit, because of infrastructure and fleet investments. Chesapeake seems to understand this, given the money it's investing in market development, on both advocacy and specific projects to turn gas into transportation fuels or use it directly in cars and trucks.
If natural gas could be stored and shipped as easily as oil, the current oversupply wouldn't be a problem, nor would domestic producers be forced to pace their expansions to match the growth of demand or exports. However, gas producers have always had to develop major new resources in tandem with markets, with that discipline often enforced by price, as we are seeing today. Time will tell whether Chesapeake expanded too rapidly, or like so many others merely missed the warning signs of the recession and financial crisis that hobbled demand growth at just the wrong time for them. Yet no matter how their story turns out, the fate of US shale gas is not dependent on the fortunes of a single company, and there will be plenty of larger, better-capitalized players waiting to snap up the assets of any first-generation shale gas producers that don't make it. That's because no matter how challenging today's low prices are for producers, the prices that prevailed just a year or two ago were adequate to support the growth of both production and new demand.
Wednesday, May 09, 2012
Where Gas is Already $10 per Gallon
I've just returned from a business trip to Norway. One of the first things I noticed upon my arrival there, on the way into town from the airport, was the price of gasoline. Since Norway still uses its own currency rather than the Euro--lucky them--I had to look up the exchange rate before I could calculate that 15.40 Norwegian Kroner per liter equated to a penny or two under $10 per gallon. I'll bet that Norwegians would be ecstatic if it were only $4 a gallon. Gasoline isn't the only thing that's expensive in Norway--a draft beer was $9--but the remarkable thing about its price there is that, unlike nearly all European countries, Norway is a net exporter of both oil and refined products, including to the US. Most major producing countries subsidize motor fuel for their populations; Norway taxes it exorbitantly and effectively puts the proceeds into its Government Pension Fund.
As a result, there's at least one developed country that is well-positioned to manage its public pension liabilities. Although I wouldn't advocate adopting exactly the same system here, since among other differences we're still a significant net importer of crude oil--despite the weak economy having made us a net exporter of products--it does suggest some possibilities. Could Congress compromise on opening up more US oil and gas resources for development if the royalties were slated for infrastructure investment or a new Social Security trust fund that amounted to more than just an accounting exercise involving government paper? It's an interesting model to contemplate.
As a result, there's at least one developed country that is well-positioned to manage its public pension liabilities. Although I wouldn't advocate adopting exactly the same system here, since among other differences we're still a significant net importer of crude oil--despite the weak economy having made us a net exporter of products--it does suggest some possibilities. Could Congress compromise on opening up more US oil and gas resources for development if the royalties were slated for infrastructure investment or a new Social Security trust fund that amounted to more than just an accounting exercise involving government paper? It's an interesting model to contemplate.
Thursday, May 03, 2012
Resources from Space?
Last week a company called Planetary Resources, Inc. announced its intention to develop the means of exploiting minerals from near-earth asteroids on a for-profit basis. This news got some attention for its novelty, particularly at a time when the concerns of most companies are distinctly earthbound. It also attracted sneers from some in the financial press, though the author of a particularly scathing analysis in the Financial Times seems to have confused recovering material on the scale of a NASA space probe with the kind of large-scale mining that Planetary Resources contemplates. I don't know whether there's a pony in there or not, somewhere down the road, but there's certainly a larger message to be gleaned: The company's announcement serves as a useful reminder that the earth we live on is not a closed system. Anyone interested in truly long-term sustainability must take account of that.
Every aspect of our lives is affected by energy received from outside the earth's atmosphere. Other than nuclear, geothermal and tidal power, all our energy sources make direct or indirect use of sunlight that has been stored via photosynthesis or redistributed by the atmosphere and the hydrolologic cycle. And at least some of the resources we use arrived here during the bombardment this planet received from space in its early stages. You can carry that logic all the way to Carl Sagan's memorable comment that we are "made of star stuff." However, my main interest in this--and apparently that of the impressive list of staff and investors in Planetary Resources, Inc.--is on a practical, rather than philosophical level.
Start with the negative side of the ledger, which reminds us that although greatly diminished, the bombardment of earth from space still continues. A chapter in Neil deGrasse Tyson's latest book, "Space Chronicles", includes a sobering chart on the scale, relative damage, and frequency of impacts large enough to merit a comparison to nuclear weapons. As the Spacewatch project has documented, the volume of space through which we orbit the sun is not nearly as empty as we'd wish. Sooner or later we or our descendants will need capabilities such as those the Planetary Resources folks hope to develop--not for mining but to move a big rock like Apophis out of our way. Tackling climate change won't matter much if a nasty like that drops into the Pacific Ocean or turns part of a continent into dust. Dealing with low-probability, high-consequence risks is never easy, as we've learned to our regret in the last few years.
On a more positive note, the resources available in space are enormous, though at this point the cost of capitalizing on them is even larger. If that gap is ever to narrow, it will happen through the efforts of groups like Planetary Resources. Pure science only takes you so far, and building defenses against a global threat that might not materialize for a thousand or a million years is unlikely to galvanize governments that aren't even sure how to navigate the next year or decade, yet. But getting rich remains a pretty reliable motivation. If someone succeeds in overcoming the numerous obstacles that an effort such as that described on the company's website faces, rich won't begin to describe them.
Pursuing an opportunity like this isn't a substitute for addressing our present challenges on earth. My long-time readers know that I'm very interested in--and was even briefly involved in--space solar power. Its potential is also enormous, but that doesn't mean we should stop drilling for the hydrocarbons we'll need for the next several decades, while developing the renewable energy sources and other technologies that will help to reduce our greenhouse gas emissions. Space solar power isn't a bridge to a future energy technology; it's the kind of technology toward which we need a bridge. I view space resources in much the same light. We talk a lot about the impact on the climate a century from now of the emissions we're producing today. Why wouldn't we also plan for the resource base that the world of the late 21st century might need, unless we expect our descendants to be many fewer in number and so frugal that they consume less per person than the citizens of today's least developed countries? That vision might appeal to some environmentalists, but it doesn't appeal to me.
Planetary Resources faces huge risks, not the least of which are the customary ones faced by any startup. MIT's Technology Review has a thought-providing article on the difficulties that energy startups face today, and many of the points it makes would also apply to a space development company. It's not entirely irrelevant that the company's announcement came in the same month that one of our last space shuttles was flown to its new home in the Smithsonian's Udvar-Hazy aerospace museum not far from where I live. In order to succeed they must do something no one else has done before, in an environment as unforgiving as any that humanity has faced. Yet while I'm not in a position to bet my retirement savings on an idea like this, I'm very glad that some of those who have made their fortunes starting companies in other industries are willing to wager a portion of their wealth on this proposition. In the slim chance that they win their bet, it will change the world.
Every aspect of our lives is affected by energy received from outside the earth's atmosphere. Other than nuclear, geothermal and tidal power, all our energy sources make direct or indirect use of sunlight that has been stored via photosynthesis or redistributed by the atmosphere and the hydrolologic cycle. And at least some of the resources we use arrived here during the bombardment this planet received from space in its early stages. You can carry that logic all the way to Carl Sagan's memorable comment that we are "made of star stuff." However, my main interest in this--and apparently that of the impressive list of staff and investors in Planetary Resources, Inc.--is on a practical, rather than philosophical level.
Start with the negative side of the ledger, which reminds us that although greatly diminished, the bombardment of earth from space still continues. A chapter in Neil deGrasse Tyson's latest book, "Space Chronicles", includes a sobering chart on the scale, relative damage, and frequency of impacts large enough to merit a comparison to nuclear weapons. As the Spacewatch project has documented, the volume of space through which we orbit the sun is not nearly as empty as we'd wish. Sooner or later we or our descendants will need capabilities such as those the Planetary Resources folks hope to develop--not for mining but to move a big rock like Apophis out of our way. Tackling climate change won't matter much if a nasty like that drops into the Pacific Ocean or turns part of a continent into dust. Dealing with low-probability, high-consequence risks is never easy, as we've learned to our regret in the last few years.
On a more positive note, the resources available in space are enormous, though at this point the cost of capitalizing on them is even larger. If that gap is ever to narrow, it will happen through the efforts of groups like Planetary Resources. Pure science only takes you so far, and building defenses against a global threat that might not materialize for a thousand or a million years is unlikely to galvanize governments that aren't even sure how to navigate the next year or decade, yet. But getting rich remains a pretty reliable motivation. If someone succeeds in overcoming the numerous obstacles that an effort such as that described on the company's website faces, rich won't begin to describe them.
Pursuing an opportunity like this isn't a substitute for addressing our present challenges on earth. My long-time readers know that I'm very interested in--and was even briefly involved in--space solar power. Its potential is also enormous, but that doesn't mean we should stop drilling for the hydrocarbons we'll need for the next several decades, while developing the renewable energy sources and other technologies that will help to reduce our greenhouse gas emissions. Space solar power isn't a bridge to a future energy technology; it's the kind of technology toward which we need a bridge. I view space resources in much the same light. We talk a lot about the impact on the climate a century from now of the emissions we're producing today. Why wouldn't we also plan for the resource base that the world of the late 21st century might need, unless we expect our descendants to be many fewer in number and so frugal that they consume less per person than the citizens of today's least developed countries? That vision might appeal to some environmentalists, but it doesn't appeal to me.
Planetary Resources faces huge risks, not the least of which are the customary ones faced by any startup. MIT's Technology Review has a thought-providing article on the difficulties that energy startups face today, and many of the points it makes would also apply to a space development company. It's not entirely irrelevant that the company's announcement came in the same month that one of our last space shuttles was flown to its new home in the Smithsonian's Udvar-Hazy aerospace museum not far from where I live. In order to succeed they must do something no one else has done before, in an environment as unforgiving as any that humanity has faced. Yet while I'm not in a position to bet my retirement savings on an idea like this, I'm very glad that some of those who have made their fortunes starting companies in other industries are willing to wager a portion of their wealth on this proposition. In the slim chance that they win their bet, it will change the world.
Monday, April 30, 2012
US Natural Gas Price Nears $10 per Barrel Equivalence
While the average pump price of gasoline has held the attention of most Americans for much of this year, the price trend for natural gas has been equally dramatic in the opposite direction. Gasoline prices flirted with the psychologically important $4 per gallon mark for several weeks before receding to around $3.82 today. Meanwhile natural gas prices continued their steady drift downward, briefly crossing $2 per million BTUs (MMBTU) before recovering slightly. To put this in perspective, when the spot price of natural gas bottomed out at $1.82 earlier this month, it was selling for the energy equivalent of oil at $10.56 per barrel. The last time oil prices were that low was during the Asian economic crisis of the late 1990s, and we're still feeling the consequences of that crash. The longer-term impact of today's dirt cheap natural gas is likely to be quite different, however.
Oil and natural gas used to be joined at the hip, and in the minds of many people they still are, even though the days when most US natural gas was a direct or indirect byproduct of oil production--either produced with oil or found by accident when a company was drilling for oil--are long past. The vast majority of our gas comes from dedicated gas wells in fields that were explored because of their gas potential, with shale gas and other so-called "tight gas" increasingly dominating output. The widely discussed shale gas revolution is the main reason natural gas is so cheap today, instead of costing over $10 per MMBTU as it would if shale gas hadn't happened and the industry's expectations about increasing LNG imports had materialized instead. Unfortunately for producers, because the surge of shale production has coincided with a weak US economy that is still struggling to get out of first gear, post-recession, the shale gas bounty is turning into a temporary glut.
Here's why the distinction between modern oil and gas production dynamics matter. When oil prices crashed in the late 1990s due to the combination of weaker-than-expected global demand and growing production, producers cut investments and scaled back new projects. Because of the time lags inherent in big oil projects the impact of those decisions was felt in the middle of the last decade, just as demand growth in the developing world hit its stride. Other things were happening, as well, but there's a good case that $10 oil in the late '90s helped set up $145 oil in 2008 and contributed to the persistence of prices well over $100/bbl today. So is the current natural gas price slump setting up a spike back over $10/MMBTU within a few years? I think that's unlikely, though I do believe gas prices will recover somewhat.
My reasoning involves several key differences between the oil and gas markets. First, the gas lifecycle is much quicker, at least where pipeline infrastructure is already in place. More than half of today's US gas production comes from wells drilled in the last 5 years. Gas drilling has already slowed, and more rigs are being redeployed to pursue much more valuable oil plays, but drilling could switch back to gas just as quickly. Then there's the underlying resource, which would support even higher gas production than today's for many decades. Finally, we have the factor referenced by Chesapeake Energy's controversial CEO, Aubrey McClendon in an interview in this weekend's Wall St. Journal: new demand.
The only reason that additional demand from utilities, petrochemicals, transportation, and exports hasn't already sopped up the gas surplus and boosted prices is that all of these developments involve time lags of their own. It will take time to build the new ethylene crackers announced by Shell and Dow Chemical. Natural gas power plants have already ramped up output and seized market share from coal, but bigger shifts will require more gas turbines. Converting long-haul trucking to natural gas requires expensive modifications to trucks and new refueling infrastructure. Meanwhile the first liquefied natural gas export terminal just received the go-ahead from FERC. Yet while none of these things can happen overnight, and there isn't enough gas to push them all to their maximum potential in any case, they are all being propelled by the enormous driving force of natural gas at the oil equivalent of $12-20/bbl in a $100-per-barrel world. The developers of renewable energy technology must also figure out how to compete with that, if they're going to prosper without fiscally unsustainable subsidies.
As scaled-back drilling and new demand mop up the current gas glut, only one thing can happen to prices. The $64,000 question is how high they could rise and still keep the demand expansion going. A return to $10 natural gas would halt the shift from coal to gas and stop the penetration of gas in transportation in its tracks, but it would also unleash an even larger wave of new production. Mr. McClendon's latest guess for the medium-term price is between $3 and $5, and that sounds reasonable. Even at the latter the BTUs in gas would still cost just $29/bbl. We won't see oil at that price any time soon, so gas doesn't need to remain at $2 to create a world-beating energy advantage for the US. If natural gas can fulfill even a portion of the potential we see today, we will soon need to rethink most of our assumptions of energy scarcity embedded by four decades of recurring oil crises. That will be uncomfortable for some people.
Oil and natural gas used to be joined at the hip, and in the minds of many people they still are, even though the days when most US natural gas was a direct or indirect byproduct of oil production--either produced with oil or found by accident when a company was drilling for oil--are long past. The vast majority of our gas comes from dedicated gas wells in fields that were explored because of their gas potential, with shale gas and other so-called "tight gas" increasingly dominating output. The widely discussed shale gas revolution is the main reason natural gas is so cheap today, instead of costing over $10 per MMBTU as it would if shale gas hadn't happened and the industry's expectations about increasing LNG imports had materialized instead. Unfortunately for producers, because the surge of shale production has coincided with a weak US economy that is still struggling to get out of first gear, post-recession, the shale gas bounty is turning into a temporary glut.
Here's why the distinction between modern oil and gas production dynamics matter. When oil prices crashed in the late 1990s due to the combination of weaker-than-expected global demand and growing production, producers cut investments and scaled back new projects. Because of the time lags inherent in big oil projects the impact of those decisions was felt in the middle of the last decade, just as demand growth in the developing world hit its stride. Other things were happening, as well, but there's a good case that $10 oil in the late '90s helped set up $145 oil in 2008 and contributed to the persistence of prices well over $100/bbl today. So is the current natural gas price slump setting up a spike back over $10/MMBTU within a few years? I think that's unlikely, though I do believe gas prices will recover somewhat.
My reasoning involves several key differences between the oil and gas markets. First, the gas lifecycle is much quicker, at least where pipeline infrastructure is already in place. More than half of today's US gas production comes from wells drilled in the last 5 years. Gas drilling has already slowed, and more rigs are being redeployed to pursue much more valuable oil plays, but drilling could switch back to gas just as quickly. Then there's the underlying resource, which would support even higher gas production than today's for many decades. Finally, we have the factor referenced by Chesapeake Energy's controversial CEO, Aubrey McClendon in an interview in this weekend's Wall St. Journal: new demand.
The only reason that additional demand from utilities, petrochemicals, transportation, and exports hasn't already sopped up the gas surplus and boosted prices is that all of these developments involve time lags of their own. It will take time to build the new ethylene crackers announced by Shell and Dow Chemical. Natural gas power plants have already ramped up output and seized market share from coal, but bigger shifts will require more gas turbines. Converting long-haul trucking to natural gas requires expensive modifications to trucks and new refueling infrastructure. Meanwhile the first liquefied natural gas export terminal just received the go-ahead from FERC. Yet while none of these things can happen overnight, and there isn't enough gas to push them all to their maximum potential in any case, they are all being propelled by the enormous driving force of natural gas at the oil equivalent of $12-20/bbl in a $100-per-barrel world. The developers of renewable energy technology must also figure out how to compete with that, if they're going to prosper without fiscally unsustainable subsidies.
As scaled-back drilling and new demand mop up the current gas glut, only one thing can happen to prices. The $64,000 question is how high they could rise and still keep the demand expansion going. A return to $10 natural gas would halt the shift from coal to gas and stop the penetration of gas in transportation in its tracks, but it would also unleash an even larger wave of new production. Mr. McClendon's latest guess for the medium-term price is between $3 and $5, and that sounds reasonable. Even at the latter the BTUs in gas would still cost just $29/bbl. We won't see oil at that price any time soon, so gas doesn't need to remain at $2 to create a world-beating energy advantage for the US. If natural gas can fulfill even a portion of the potential we see today, we will soon need to rethink most of our assumptions of energy scarcity embedded by four decades of recurring oil crises. That will be uncomfortable for some people.
Wednesday, April 25, 2012
A World Without Oil Price Speculators
The quality of media reporting on energy has improved significantly since I started this blog in 2004. However, one subject on which I think the state of energy reporting still leaves much to be desired concerns the role of market speculation in setting oil prices. It's a complex issue, and it has become highly politicized this year. Doing it justice requires more than just the obligatory video of the New York Mercantile Exchange (NYMEX) or interview with a "floor trader". I've encountered plenty of speculation on how much lower prices might be without the influence of speculators, but I've yet to see anyone go the next step to ask how prices might be set in the absence of any speculation at all. This is an important question, because the primary benefit of the futures markets in which speculators participate is transparent price discovery. I'd like to offer some perspective on that from my own experience trading oil and its products in the 1980s and early 1990s.
Imagine a world in which we're not really sure what the price of oil is on a given day. If that seems a bizarre notion, it's because the media have made the prices of oil futures contracts in New York and London nearly as ubiquitous as those of the Dow Jones and other stock market indices. That wasn't always the case. I can remember many occasions on which the price of an energy commodity was hard to determine, or was simply what a particular buyer or seller said it was that day.
When I started trading petroleum products in the mid-1980s, the NYMEX contract for West Texas Intermediate crude oil was relatively new, and the heating oil contract had only been around a few years longer. Their influence wasn't nearly as pervasive as now, beyond the localized Gulf Coast light crude and New York Harbor heating oil markets they were devised to support. The spot market transactions that I executed on behalf of Texaco's US west coast operations normally involved a fixed price arrived at through one-on-one negotiation, based on the buyer's and seller's perceptions of the market from other conversations, with input from limited and often suspect reporting on recent, similar transactions. When I shifted over to trading crude oil a few years later, most deals were still based on the system of "posted prices" that had existed for decades, in which producers and refiners issued periodic bulletins listing the current prices at which they solicited offers for each specific grade of oil in which they were interested. We bought or sold at small premia or discounts to the relevant posting--up to "P-plus" a dollar per barrel or so--with minor adjustments for actual quality received. Transactions for OPEC crude were similarly based on the producing country's official posted prices, which sometimes didn't change for months.
In other words, it's not so long ago that prices for many grades of oil or refined products were often either obscure or inflexible, and largely determined by an exclusive "club" of participants. Moreover, there were times when it simply wasn't possible to buy or sell a commodity when needed, because there were no active sellers or buyers. The management of my business unit had a strong bias against doing business with independent trading companies, the speculators of the day, but when we needed to buy gasoline or a cargo of crude oil because we were about to run out, and they were the only ones selling because our competitors were either in the same position as we were or didn't care to assist us in competing with them, then managers were usually willing to set aside those scruples. The nascent futures markets were an exception to that system, and as they grew in influence--complete with speculation--more and more business was transacted on the basis of an agreed premium or discount to a particular NYMEX contract. It wasn't a perfect system, but it had the advantage of greatly increased transparency and liquidity.
When I hear people who have never participated in the oil markets suggest that only those parties with "legitimate" needs to do so should be able to buy or sell futures and options, I wonder if they understand that this path could lead back to a market with inherently less transparency and less competition--one that might in some respects be easier to manipulate, with prices set more arbitrarily than the result they accuse speculators of producing.
In my view the old way of trading oil still has a few things to recommend it, even though it was roughly as prone to sudden spikes as the current system is. However, it's hard for me to imagine that the public and politicians would really prefer to revert to a situation in which oil prices were set between producers and refiners--by OPEC and oil companies, if you will--instead of the present one in which they are determined in a market with much broader participation. I don't even think oil companies would want to go back, because they're in a much better position to defend their profitability when they can state with confidence that they don't actually set prices.
I realize that I've set up a more extreme choice than most of those who are unhappy with the current situation would advocate; most of them appear to want to restrain speculation, rather than eliminating it entirely. Yet I wonder whether that nuance is any more realistic, or helpful. I believe that the distinction that ought to be drawn more sharply is not between speculation and the participation of "legitimate" players, but between trading for either hedging or profit and attempts to manipulate prices. It's one thing to bet on the price of oil going up or down, which after all requires someone else to take the opposite bet. It's quite another to try to rig the game in your favor.
Imagine a world in which we're not really sure what the price of oil is on a given day. If that seems a bizarre notion, it's because the media have made the prices of oil futures contracts in New York and London nearly as ubiquitous as those of the Dow Jones and other stock market indices. That wasn't always the case. I can remember many occasions on which the price of an energy commodity was hard to determine, or was simply what a particular buyer or seller said it was that day.
When I started trading petroleum products in the mid-1980s, the NYMEX contract for West Texas Intermediate crude oil was relatively new, and the heating oil contract had only been around a few years longer. Their influence wasn't nearly as pervasive as now, beyond the localized Gulf Coast light crude and New York Harbor heating oil markets they were devised to support. The spot market transactions that I executed on behalf of Texaco's US west coast operations normally involved a fixed price arrived at through one-on-one negotiation, based on the buyer's and seller's perceptions of the market from other conversations, with input from limited and often suspect reporting on recent, similar transactions. When I shifted over to trading crude oil a few years later, most deals were still based on the system of "posted prices" that had existed for decades, in which producers and refiners issued periodic bulletins listing the current prices at which they solicited offers for each specific grade of oil in which they were interested. We bought or sold at small premia or discounts to the relevant posting--up to "P-plus" a dollar per barrel or so--with minor adjustments for actual quality received. Transactions for OPEC crude were similarly based on the producing country's official posted prices, which sometimes didn't change for months.
In other words, it's not so long ago that prices for many grades of oil or refined products were often either obscure or inflexible, and largely determined by an exclusive "club" of participants. Moreover, there were times when it simply wasn't possible to buy or sell a commodity when needed, because there were no active sellers or buyers. The management of my business unit had a strong bias against doing business with independent trading companies, the speculators of the day, but when we needed to buy gasoline or a cargo of crude oil because we were about to run out, and they were the only ones selling because our competitors were either in the same position as we were or didn't care to assist us in competing with them, then managers were usually willing to set aside those scruples. The nascent futures markets were an exception to that system, and as they grew in influence--complete with speculation--more and more business was transacted on the basis of an agreed premium or discount to a particular NYMEX contract. It wasn't a perfect system, but it had the advantage of greatly increased transparency and liquidity.
When I hear people who have never participated in the oil markets suggest that only those parties with "legitimate" needs to do so should be able to buy or sell futures and options, I wonder if they understand that this path could lead back to a market with inherently less transparency and less competition--one that might in some respects be easier to manipulate, with prices set more arbitrarily than the result they accuse speculators of producing.
In my view the old way of trading oil still has a few things to recommend it, even though it was roughly as prone to sudden spikes as the current system is. However, it's hard for me to imagine that the public and politicians would really prefer to revert to a situation in which oil prices were set between producers and refiners--by OPEC and oil companies, if you will--instead of the present one in which they are determined in a market with much broader participation. I don't even think oil companies would want to go back, because they're in a much better position to defend their profitability when they can state with confidence that they don't actually set prices.
I realize that I've set up a more extreme choice than most of those who are unhappy with the current situation would advocate; most of them appear to want to restrain speculation, rather than eliminating it entirely. Yet I wonder whether that nuance is any more realistic, or helpful. I believe that the distinction that ought to be drawn more sharply is not between speculation and the participation of "legitimate" players, but between trading for either hedging or profit and attempts to manipulate prices. It's one thing to bet on the price of oil going up or down, which after all requires someone else to take the opposite bet. It's quite another to try to rig the game in your favor.
Tuesday, April 17, 2012
How Green Is My Electric Vehicle?
One of the biggest challenges in assessing the environmental benefits of electric vehicles is that electricity is generated in so many different ways, with differing costs and consequences, and that patterns of generation vary by region, season, and time of day. As a result, categorical claims that EVs are always greener than the hybrids against which they compete most directly, or even compared to efficient non-hybrid compact gasoline or diesel-powered cars, must be suspect. The Union of Concerned Scientists (UCS) has just issued a report that takes some of the mystery out of such comparisons, including a helpful map showing likely greenhouse gas emissions associated with EV use expressed in terms of equivalent miles per gallon from a gasoline vehicle. The takeaway is that as of now, the emissions advantage of purchasing an EV depends heavily on where you live, with equivalent emissions from average grid power in many parts of the country about on a par with those from a small car like the Chevrolet Cruze, and not even as good as from a Prius-type non-plug-in hybrid.
This apparent paradox becomes clearer when you examine the cities map that the New York Times distilled from the report, reflecting the local basis of electricity generation. An EV operated in L.A. or San Francisco would unambiguously beat a Prius on emissions, while an EV in my neighborhood in Northern Virginia would have only a slight edge, and one in Denver would yield emissions comparable to an ordinary car getting 33 mpg, unless the owner was scrupulous about recharging only when greener power was available. That's because despite the declining share of coal-fired power in our national generation mix, there are still many regions and locales where coal dominates the grid, and the GHG emissions from coal-fired generation are considerably higher than from natural gas or low-emission nuclear and renewables.
Any report such as this must incorporate a number of assumptions, and from my fairly quick perusal of the details they seem generally well-identified here. The UCS's emission-equivalent miles per gallon calculation is based on a Nissan Leaf getting 3 miles per kilowatt-hour (kWh.) Grid emissions are calculated using a model of average hourly emissions over the course of the year. It didn't appear that these hourly-averaged figures were weighted for seasonal variations in driving patterns, but that's probably more nuance than is necessary at this level of scrutiny.
The report also includes information about recharging costs in different locations under different rate plans. Prospective EV buyers would benefit from taking the time to understand what these issues mean in their specific locations before investing in one. From my perspective, the report should also provide serious food for thought for policy makers concerning the wisdom of a single federal tax credit for EV purchasers in the US. As hard as that policy is to justify in the best of locations, based on the equivalent cost per ton of CO2 avoided, it looks positively senseless in locations where coal is still king. And while the report makes the point that the generation mix in many regions will become cleaner over time as utilities respond to renewable portfolio standards and other policies, buying an EV in a high-emissions region and counting on that factor to improve the car's environmental benefits during its lifetime seems like a risky bet, particularly in economic terms.
The biggest caveat I'd offer about the report concerns its emphasis on comparing EVs to non-hybrid compact cars, both on costs and emissions. That just doesn't seem realistic, given the array of choices and types of consumers in the market. While the number of consumers willing to consider an electric vehicle is increasing, the "take rate"--the number who actually convert their interest into a purchase decision, remains minuscule, resulting in sales of just 0.3% of all US cars sold in March. Meanwhile hybrids have benefited from rising gas prices to hit 3.4% of sales. It's also worth recalling that the fuel, emissions and dollar savings from improved fuel economy decline with each additional increment. Hybrids already capture the most valuable savings over conventional cars, while the incremental fuel savings from stepping up from a hybrid to an EV are roughly comparable to what hybrids achieve, but require additional battery capacity and electricity, neither of which is free. That makes hybrids the technology for EVs to beat. As helpful as the information provided in the UCS report should be for consumers, the ultimate decision to buy an EV seems driven more by values than value, at least until EV costs fall significantly.
This apparent paradox becomes clearer when you examine the cities map that the New York Times distilled from the report, reflecting the local basis of electricity generation. An EV operated in L.A. or San Francisco would unambiguously beat a Prius on emissions, while an EV in my neighborhood in Northern Virginia would have only a slight edge, and one in Denver would yield emissions comparable to an ordinary car getting 33 mpg, unless the owner was scrupulous about recharging only when greener power was available. That's because despite the declining share of coal-fired power in our national generation mix, there are still many regions and locales where coal dominates the grid, and the GHG emissions from coal-fired generation are considerably higher than from natural gas or low-emission nuclear and renewables.
Any report such as this must incorporate a number of assumptions, and from my fairly quick perusal of the details they seem generally well-identified here. The UCS's emission-equivalent miles per gallon calculation is based on a Nissan Leaf getting 3 miles per kilowatt-hour (kWh.) Grid emissions are calculated using a model of average hourly emissions over the course of the year. It didn't appear that these hourly-averaged figures were weighted for seasonal variations in driving patterns, but that's probably more nuance than is necessary at this level of scrutiny.
The report also includes information about recharging costs in different locations under different rate plans. Prospective EV buyers would benefit from taking the time to understand what these issues mean in their specific locations before investing in one. From my perspective, the report should also provide serious food for thought for policy makers concerning the wisdom of a single federal tax credit for EV purchasers in the US. As hard as that policy is to justify in the best of locations, based on the equivalent cost per ton of CO2 avoided, it looks positively senseless in locations where coal is still king. And while the report makes the point that the generation mix in many regions will become cleaner over time as utilities respond to renewable portfolio standards and other policies, buying an EV in a high-emissions region and counting on that factor to improve the car's environmental benefits during its lifetime seems like a risky bet, particularly in economic terms.
The biggest caveat I'd offer about the report concerns its emphasis on comparing EVs to non-hybrid compact cars, both on costs and emissions. That just doesn't seem realistic, given the array of choices and types of consumers in the market. While the number of consumers willing to consider an electric vehicle is increasing, the "take rate"--the number who actually convert their interest into a purchase decision, remains minuscule, resulting in sales of just 0.3% of all US cars sold in March. Meanwhile hybrids have benefited from rising gas prices to hit 3.4% of sales. It's also worth recalling that the fuel, emissions and dollar savings from improved fuel economy decline with each additional increment. Hybrids already capture the most valuable savings over conventional cars, while the incremental fuel savings from stepping up from a hybrid to an EV are roughly comparable to what hybrids achieve, but require additional battery capacity and electricity, neither of which is free. That makes hybrids the technology for EVs to beat. As helpful as the information provided in the UCS report should be for consumers, the ultimate decision to buy an EV seems driven more by values than value, at least until EV costs fall significantly.
Wednesday, April 11, 2012
Could Solar Power Boost Saudi Oil Exports?
How often have we heard that installing renewable energy sources like wind and solar power will improve US energy security and reduce oil imports? There are other reasons for promoting these technologies, but this one has little substance, because we generate less than 1% of our electricity from oil. Ironically, this logic looks much more relevant to the part of the world with the largest oil reserves and that accounts for the lion's share of global oil exports, the Middle East. This week's Economist reports that Saudi Arabia generates 65% of its power from oil, and the impact on its oil exports could grow dramatically as the country's population and economy expand. Other Gulf producers have similar profiles. The Saudi government's strategy to increase its use of nuclear and renewable energy could pay big dividends in preserving oil for exports, though the volumes freed up by such means wouldn't be cheap.
Saudi Arabia has set a goal of deriving 10% of its electricity from renewable sources by 2020. Solar power looks like the leading option, and a Saudi company recently announced a deal to build a plant to produce polysilicon, the raw material for many of today's photovoltaic (PV)cells. (Its output would likely be exported for some time, until the downstream value chain developed.) Saudi Arabia has tremendous solar potential, with much of the country receiving more than 6 hours per day of peak sunlight, on average. Based on recent electricity demand of around 200 billion kilowatt-hours (kWh) per year, it would take roughly 9,000 MW of PV capacity to achieve their goal. How much oil would that save, and at what effective cost?
With average Saudi power generation operating at 31% efficiency, according to a report by ABB, saving the oil used to generate 20 billion kWh would free up roughly 100,000 bbl/day for other uses, including exports. That doesn't sound like a lot for a country that's currently producing 10 million bbl/day, but it's the equivalent of a medium-to-large offshore oil platform. However, the more interesting aspect of this strategy is its cost, both in aggregate terms and in the effective cost of the oil it would release.
A recent report from Lawrence Berkeley National Laboratory estimated the installed cost of utility-scale solar power in the US last year at around $4 per Watt. Assuming current costs are 10% lower--module costs have fallen by more, but balance-of-system costs typically fall more slowly--that would result in a required investment of $32 billion at today's prices. That's about what ExxonMobil spent on its entire global oil & gas development program last year, which will presumably yield a lot more than 100,000 bbl/day of future production. Moreover, using NREL's simplified model for calculating levelized electricity costs from different technologies, the output of PV in Saudi Arabia at $3.60/W installed would cost around $0.13/kWh without subsidies. Using that same 31% efficiency factor for oil-fired power generation yields an effective cost for each barrel saved by solar power of $70. That looks cheap compared to current oil prices, but it's almost an order of magnitude higher than what many assume it costs the Kingdom to produce a barrel of oil today. Even if we assumed installed PV costs fell to $2/W before they're done, that's still around $40/bbl. If that looks attractive to them, what does it say about their other opportunities?
One way to address that without getting into thorny questions about peak oil is to consider the alternative of using gas-fired generation to displace oil from Saudi Arabia's power sector. The Kingdom has the world's fifth-largest natural gas reserves. At 264 trillion cubic feet they appear more than ample for the purpose, if developed. Even if gas from new fields cost $5 per million BTUs, the effective cost of the oil freed up by switching to efficient gas-fired combined cycle power generation would be about $25/bbl. And with recent trends showing the energy intensity of the Saudi economy getting worse, not better, the scale of the efficiency opportunity there indicates that the cheapest displaced barrels might be from investments in improving energy efficiency, rather than new generation of any kind.
I'm not suggesting that solar power has no place in Saudi Arabia's energy mix. If the technology makes sense anywhere, it is in sunny countries like this that rely on expensive fuels for most of their current generation. Yet as clever and appealing as the idea of using abundant solar energy to free up Middle East oil for export might sound, from both an environmental and oil-consumer perspective, the numbers suggest that it's probably not even their second- or third-best option for that purpose.
Saudi Arabia has set a goal of deriving 10% of its electricity from renewable sources by 2020. Solar power looks like the leading option, and a Saudi company recently announced a deal to build a plant to produce polysilicon, the raw material for many of today's photovoltaic (PV)cells. (Its output would likely be exported for some time, until the downstream value chain developed.) Saudi Arabia has tremendous solar potential, with much of the country receiving more than 6 hours per day of peak sunlight, on average. Based on recent electricity demand of around 200 billion kilowatt-hours (kWh) per year, it would take roughly 9,000 MW of PV capacity to achieve their goal. How much oil would that save, and at what effective cost?
With average Saudi power generation operating at 31% efficiency, according to a report by ABB, saving the oil used to generate 20 billion kWh would free up roughly 100,000 bbl/day for other uses, including exports. That doesn't sound like a lot for a country that's currently producing 10 million bbl/day, but it's the equivalent of a medium-to-large offshore oil platform. However, the more interesting aspect of this strategy is its cost, both in aggregate terms and in the effective cost of the oil it would release.
A recent report from Lawrence Berkeley National Laboratory estimated the installed cost of utility-scale solar power in the US last year at around $4 per Watt. Assuming current costs are 10% lower--module costs have fallen by more, but balance-of-system costs typically fall more slowly--that would result in a required investment of $32 billion at today's prices. That's about what ExxonMobil spent on its entire global oil & gas development program last year, which will presumably yield a lot more than 100,000 bbl/day of future production. Moreover, using NREL's simplified model for calculating levelized electricity costs from different technologies, the output of PV in Saudi Arabia at $3.60/W installed would cost around $0.13/kWh without subsidies. Using that same 31% efficiency factor for oil-fired power generation yields an effective cost for each barrel saved by solar power of $70. That looks cheap compared to current oil prices, but it's almost an order of magnitude higher than what many assume it costs the Kingdom to produce a barrel of oil today. Even if we assumed installed PV costs fell to $2/W before they're done, that's still around $40/bbl. If that looks attractive to them, what does it say about their other opportunities?
One way to address that without getting into thorny questions about peak oil is to consider the alternative of using gas-fired generation to displace oil from Saudi Arabia's power sector. The Kingdom has the world's fifth-largest natural gas reserves. At 264 trillion cubic feet they appear more than ample for the purpose, if developed. Even if gas from new fields cost $5 per million BTUs, the effective cost of the oil freed up by switching to efficient gas-fired combined cycle power generation would be about $25/bbl. And with recent trends showing the energy intensity of the Saudi economy getting worse, not better, the scale of the efficiency opportunity there indicates that the cheapest displaced barrels might be from investments in improving energy efficiency, rather than new generation of any kind.
I'm not suggesting that solar power has no place in Saudi Arabia's energy mix. If the technology makes sense anywhere, it is in sunny countries like this that rely on expensive fuels for most of their current generation. Yet as clever and appealing as the idea of using abundant solar energy to free up Middle East oil for export might sound, from both an environmental and oil-consumer perspective, the numbers suggest that it's probably not even their second- or third-best option for that purpose.
Friday, April 06, 2012
Buying Your Own Refinery
Has the high cost of fuel got you down? Why not buy your own oil refinery? That's apparently what Delta Air Lines is considering. With jet fuel purchases constituting one of the largest operating costs for carriers like Delta, and with several refineries in the Northeast US facing permanent closure due to poor profitability, it's not hard to see why this idea would seem attractive, at least superficially. However, there are a host of reasons why most of the press I've seen on this story is negative, including today's Heard on the Street column in the Wall St. Journal, entitled, "Delta Chases Fuel's Gold." The fundamental problem is the same one that has made me skeptical about the benefits of airlines investing in the production of renewable aviation fuel: Any advantageous pricing they may choose to provide to their airline division must come at the expense of lost opportunities for the fuels business, because the value of that fuel is set by the market.
How a company should reflect such opportunity costs in its inter-departmental transfer pricing is an age-old problem. I dealt with this routinely when I traded refined products for Texaco's west coast refining and marketing business in the 1980s. The marketing department always wanted to receive the output of the refineries at a lower price than we were charging them, so that they could capture market share and justify investments in new and remodeled gas stations. But making them look good at the cost of the refineries just made it harder to justify the investments needed to keep the refineries operating efficiently and in compliance with current and future regulations. Delta might buy ConocoPhillips' Pennsylvania refinery at a low price today, but they could be forced to invest at least as much within a few years to meet new gasoline sulfur regulations or other changes. It doesn't trivialize the situation to put it into the category of no free lunches.
Then there's the question of reorienting a refinery to make a lot more jet fuel that it has done historically, as one article suggested Delta was considering. Modern refineries are fairly flexible, and it would be possible to do that to some degree, though within limits that would require significant investments to exceed, making the proposition look much less attractive. Moreover, refineries optimize their output every day to make the slate of products that yields the highest profit, as crude and product prices fluctuate. Steering a less flexible course would almost certainly make the facility less, not more profitable, and it's only on the market because it wasn't sufficiently profitable as it was.
The only scenario in which I could see this idea actually working to Delta's benefit is if the refinery closures now being planned tightened the supply of jet fuel into the New York market so significantly that Delta was able to effectively corner that market, forcing other airlines to pay it a significant premium, either in cash or in jet fuel supply in other locations, while artificially keeping costs for its own flight operations low and allowing it to expand its share of the important NY air market. But New York isn't some isolated inland location, and they'd always be competing with jet fuel cargoes brought in by vessel, or with fuel shipped from Gulf Coast refineries via the Colonial Pipeline, which is expanding to meet the new demand its faces in light of the pending refinery closures. They might eke out a few extra cents, but would that be enough to justify taking on the enormous capital and operating costs--not to mention the substantial operating risks--of owning a refinery? If Delta has discovered some enticing angle I've missed, I'd love to know what it is.
How a company should reflect such opportunity costs in its inter-departmental transfer pricing is an age-old problem. I dealt with this routinely when I traded refined products for Texaco's west coast refining and marketing business in the 1980s. The marketing department always wanted to receive the output of the refineries at a lower price than we were charging them, so that they could capture market share and justify investments in new and remodeled gas stations. But making them look good at the cost of the refineries just made it harder to justify the investments needed to keep the refineries operating efficiently and in compliance with current and future regulations. Delta might buy ConocoPhillips' Pennsylvania refinery at a low price today, but they could be forced to invest at least as much within a few years to meet new gasoline sulfur regulations or other changes. It doesn't trivialize the situation to put it into the category of no free lunches.
Then there's the question of reorienting a refinery to make a lot more jet fuel that it has done historically, as one article suggested Delta was considering. Modern refineries are fairly flexible, and it would be possible to do that to some degree, though within limits that would require significant investments to exceed, making the proposition look much less attractive. Moreover, refineries optimize their output every day to make the slate of products that yields the highest profit, as crude and product prices fluctuate. Steering a less flexible course would almost certainly make the facility less, not more profitable, and it's only on the market because it wasn't sufficiently profitable as it was.
The only scenario in which I could see this idea actually working to Delta's benefit is if the refinery closures now being planned tightened the supply of jet fuel into the New York market so significantly that Delta was able to effectively corner that market, forcing other airlines to pay it a significant premium, either in cash or in jet fuel supply in other locations, while artificially keeping costs for its own flight operations low and allowing it to expand its share of the important NY air market. But New York isn't some isolated inland location, and they'd always be competing with jet fuel cargoes brought in by vessel, or with fuel shipped from Gulf Coast refineries via the Colonial Pipeline, which is expanding to meet the new demand its faces in light of the pending refinery closures. They might eke out a few extra cents, but would that be enough to justify taking on the enormous capital and operating costs--not to mention the substantial operating risks--of owning a refinery? If Delta has discovered some enticing angle I've missed, I'd love to know what it is.
Tuesday, March 27, 2012
The Beginning of the End for Coal?
I saw in Tuesday's Washington Post that the EPA was ready to issue its proposed rules for CO2 emissions from new power plants. When finalized, these rules would apply to facilities larger than 25 MW that begin construction more than a year hence. As the Post notes, the chosen CO2 emissions limit of 1,000 lb. per gross Megawatt-hour (MWh) generated would make it virtually impossible for a new conventional coal-fired generating plant to comply with this requirement. That looks like another positive for natural gas, which is coal's nearest competitor today. It might also help baseload renewables such as geothermal, since wind and solar power don't ordinarily compete directly with coal. However, anyone reading this as the epitaph for coal in the US shouldn't be too hasty, because the EPA has left room for technology and other strategies to keep coal in the future mix.
I'm completely swamped with work and other commitments at the moment, so this posting will be more like an extended Tweet. However, I thought this news was too important not to comment on it, however briefly. Lacking the time to research these data myself, I'll rely on Ms. Eilperin's thoroughness and use her figures of 1,768 lb. CO2/MWh for the average US coal plant and 800-850 lb./MWh for gas. The latter is certainly a long way from state of the art, and I'm sure that a modern ultra supercritical coal plant would come in considerably below the 1,768 lb. mark, as well, yet still above the magic half ton. What intrigues me about the EPA's chosen performance standard is that meeting it would require much less than 100% capture and sequestration of a facility's CO2 emissions. Perhaps as little as 25-30% would be sufficient, particularly, if the plant were also designed to be co-fired with biomass, as some existing coal plants are. That combination, or some other similar strategy, could significantly reduce the cost of compliance and keep coal in the game.
I know that outcome wouldn't please those who see coal as not only the logical place to seek large-scale greenhouse emissions reductions, but also a major contributor to various local environmental impacts. Yet it's also an enormous domestic energy source, the global demand for which continues to grow. Moreover, as coal is increasingly displaced from power generation by cheap natural gas, its price is likely to drop, making it more competitive for export. So perhaps this isn't the beginning of the end for coal in the US, but just the start of a new phase.
I'm completely swamped with work and other commitments at the moment, so this posting will be more like an extended Tweet. However, I thought this news was too important not to comment on it, however briefly. Lacking the time to research these data myself, I'll rely on Ms. Eilperin's thoroughness and use her figures of 1,768 lb. CO2/MWh for the average US coal plant and 800-850 lb./MWh for gas. The latter is certainly a long way from state of the art, and I'm sure that a modern ultra supercritical coal plant would come in considerably below the 1,768 lb. mark, as well, yet still above the magic half ton. What intrigues me about the EPA's chosen performance standard is that meeting it would require much less than 100% capture and sequestration of a facility's CO2 emissions. Perhaps as little as 25-30% would be sufficient, particularly, if the plant were also designed to be co-fired with biomass, as some existing coal plants are. That combination, or some other similar strategy, could significantly reduce the cost of compliance and keep coal in the game.
I know that outcome wouldn't please those who see coal as not only the logical place to seek large-scale greenhouse emissions reductions, but also a major contributor to various local environmental impacts. Yet it's also an enormous domestic energy source, the global demand for which continues to grow. Moreover, as coal is increasingly displaced from power generation by cheap natural gas, its price is likely to drop, making it more competitive for export. So perhaps this isn't the beginning of the end for coal in the US, but just the start of a new phase.
Tuesday, March 20, 2012
Is North America the New Middle East for Oil?
With the President of the United States currently playing the role of pessimist-in-chief with regard to US energy independence, it's refreshing to see that goal raised as a serious possibility by someone whose experience and position give him deeper insights on the subject. A few years ago Ed Morse was running the oil trading operation for Hess, and now he's at Citigroup. His op-ed in today's Wall St. Journal offers an upbeat analysis of the ongoing resurgence in US and Canadian production and the potential for North America to move within striking distance of true oil independence. He doesn't appear to be predicting $2.50 per gallon gasoline any time soon, but he does remind us that permanently higher oil prices needn't be inevitable, although he is also very clear about the obstacles that could impede these developments.
How often have politicians and pundits reminded us that we can't drill our way to energy independence? I've said that myself numerous times in the eight years I've been blogging here. So before exploring the implications of producing significantly more oil than we do today, it's worth asking why some experts are starting to question what has been a bedrock assumption about the US energy situation since our conventional oil production peaked in 1970--not coincidentally just before the first oil crisis in 1973-74.
If the tired talking point about the US having just 2% of the world's oil reserves were truly reflective of reality, rather than a technicality based on the way the SEC requires oil companies to account for their chief assets, people like Ed Morse wouldn't give energy independence a moment's thought. The number to focus on is not the 21 billion barrels of proved reserves on companies' books, but the nearly 200 billion barrels of discovered and undiscovered "technically recoverable oil resources" onshore and offshore, in the lower-48 and Alaska. That figure represents more than 95 years of production at current rates.
That estimate is also mostly based on assessments from the 1980s done with technology that bears the same relationship to current exploration techniques as an old Ma Bell rotary phone does to an iPhone. It's technology that is shifting expectations about what is actually possible. Consider the Bakken shale formation in the Dakotas. The conventional Williston Basin oil fields were discovered in the early 1950s and mostly played out by the late 1980s. The billions of barrels of resources in the adjacent Bakken shale, which might produce a million barrels per day by the end of this decade, simply couldn't have been produced at commercially useful rates with the technology that was available until the last decade. The hot question now is where the next Bakkens will be found.
Then there's deepwater drilling, which suffered a big setback with the Deepwater Horizon accident and spill but is still contributing 1.2 million barrels per day and could reach 1.9 million next year. What moves Mr. Morse's speculation from wishfulness into the realm of practical possibility is the potential of applying technologies like those to exploit conventional and unconventional reservoirs to which industry has not had access since their development, if ever.
Another talking point that we've heard like a drumbeat over the last several months is that even if the US could produce more oil, it would make little difference to oil prices in a global market of 90 million barrels per day. We simply don't control the price of oil; OPEC does. That has been true for essentially the entire time I've worked in energy. But here's where it's handy to have the background in oil trading that I share with Mr. Morse. Traders have to think about how prices are really set, and they understand that it's the interaction of the last few million barrels per day of supply, demand and spare capacity that really count, along with inventories. An extra million or two barrels per day--a quantity of which North America is certainly capable--can make a huge difference in oil prices. We saw that in 2009, when a drop of about 3 million barrels per day of demand sent prices from $140 to $40 within a few months, and we saw something similar involving both supply and demand during the Asian Economic Crisis of 1997-98. (See chart below.)
Nor is OPEC monolithic; it's made up of a group of producers with very different levels of reserves and production, and differing domestic requirements for the revenue they earn from selling their oil. That means that, contrary to yet another talking point, OPEC does not have unlimited capacity to back down production, in order to keep prices high when others increase output. And even when it can maintain enough cohesion to tighten quotas and restrict its own output, the production in question merely shifts to "spare capacity", the expansion of which reduces oil market volatility. Imagine how different the market's response to the current confrontation over Iran's nuclear program might look if other producers had a multiple of Iran's exports in reserve.
Just because something is possible with a decade or so of determined effort doesn't make it inevitable. While I share Mr. Morse's optimism about the benefits of boosting North American oil production on a scale that would dwarf the modest recent upturn, which has received so much attention from politicians who had nothing to do with it, I'm also skeptical that it could proceed to quite that extent in today's climate. Aside from people who are genuinely concerned about the possible environmental impact of more oil development, there are also those who would regard such a turn of events as contrary to their own interests and their perception of the nation's. How would we convince consumers to pay the premium for new cars achieving an average of 54.5 mpg in 2025 if gasoline remained between $3 and $4 per gallon, instead of trending toward $6--let alone shifting them into electric vehicles that the government and carmakers have invested billions in developing? And how would we stimulate production of advanced biofuels if the future price of crude oil were seen as being capped at or below $100 per barrel, except during geopolitical crises?
I believe all such questions have answers that don't depend on us constraining access to our resources at the cost of remaining more vulnerable to overseas suppliers and weakening both our trade deficit and our currency. I'd rather have the extra domestic oil and then worry about how to spend some of the resulting windfall of federal and state taxes, bid bonuses and royalties on achieving our other policy objectives, such as promoting efficiency and reducing emissions. Nor is relying on OPEC to keep prices high the best or most effective way to encourage us to use oil more frugally.
I don't know if North America is the next Middle East, although it's worth recalling that we were the world's biggest oil supplier before the first well was drilled in Saudi Arabia, and DOE estimates suggest we have as much oil left as we've produced to date since 1859. However, I do know that I would much rather give OPEC's leaders sleepless nights worrying how they'll keep oil prices high in the face of a wave of new production from the US, Canada and possibly Mexico, in preference to giving US consumers sleepless nights about how they'll pay for the gasoline they need for their commutes and the fuel to heat their homes, if prices stay this high or higher from here on out.
How often have politicians and pundits reminded us that we can't drill our way to energy independence? I've said that myself numerous times in the eight years I've been blogging here. So before exploring the implications of producing significantly more oil than we do today, it's worth asking why some experts are starting to question what has been a bedrock assumption about the US energy situation since our conventional oil production peaked in 1970--not coincidentally just before the first oil crisis in 1973-74.
If the tired talking point about the US having just 2% of the world's oil reserves were truly reflective of reality, rather than a technicality based on the way the SEC requires oil companies to account for their chief assets, people like Ed Morse wouldn't give energy independence a moment's thought. The number to focus on is not the 21 billion barrels of proved reserves on companies' books, but the nearly 200 billion barrels of discovered and undiscovered "technically recoverable oil resources" onshore and offshore, in the lower-48 and Alaska. That figure represents more than 95 years of production at current rates.
That estimate is also mostly based on assessments from the 1980s done with technology that bears the same relationship to current exploration techniques as an old Ma Bell rotary phone does to an iPhone. It's technology that is shifting expectations about what is actually possible. Consider the Bakken shale formation in the Dakotas. The conventional Williston Basin oil fields were discovered in the early 1950s and mostly played out by the late 1980s. The billions of barrels of resources in the adjacent Bakken shale, which might produce a million barrels per day by the end of this decade, simply couldn't have been produced at commercially useful rates with the technology that was available until the last decade. The hot question now is where the next Bakkens will be found.
Then there's deepwater drilling, which suffered a big setback with the Deepwater Horizon accident and spill but is still contributing 1.2 million barrels per day and could reach 1.9 million next year. What moves Mr. Morse's speculation from wishfulness into the realm of practical possibility is the potential of applying technologies like those to exploit conventional and unconventional reservoirs to which industry has not had access since their development, if ever.
Another talking point that we've heard like a drumbeat over the last several months is that even if the US could produce more oil, it would make little difference to oil prices in a global market of 90 million barrels per day. We simply don't control the price of oil; OPEC does. That has been true for essentially the entire time I've worked in energy. But here's where it's handy to have the background in oil trading that I share with Mr. Morse. Traders have to think about how prices are really set, and they understand that it's the interaction of the last few million barrels per day of supply, demand and spare capacity that really count, along with inventories. An extra million or two barrels per day--a quantity of which North America is certainly capable--can make a huge difference in oil prices. We saw that in 2009, when a drop of about 3 million barrels per day of demand sent prices from $140 to $40 within a few months, and we saw something similar involving both supply and demand during the Asian Economic Crisis of 1997-98. (See chart below.)
Nor is OPEC monolithic; it's made up of a group of producers with very different levels of reserves and production, and differing domestic requirements for the revenue they earn from selling their oil. That means that, contrary to yet another talking point, OPEC does not have unlimited capacity to back down production, in order to keep prices high when others increase output. And even when it can maintain enough cohesion to tighten quotas and restrict its own output, the production in question merely shifts to "spare capacity", the expansion of which reduces oil market volatility. Imagine how different the market's response to the current confrontation over Iran's nuclear program might look if other producers had a multiple of Iran's exports in reserve.
Just because something is possible with a decade or so of determined effort doesn't make it inevitable. While I share Mr. Morse's optimism about the benefits of boosting North American oil production on a scale that would dwarf the modest recent upturn, which has received so much attention from politicians who had nothing to do with it, I'm also skeptical that it could proceed to quite that extent in today's climate. Aside from people who are genuinely concerned about the possible environmental impact of more oil development, there are also those who would regard such a turn of events as contrary to their own interests and their perception of the nation's. How would we convince consumers to pay the premium for new cars achieving an average of 54.5 mpg in 2025 if gasoline remained between $3 and $4 per gallon, instead of trending toward $6--let alone shifting them into electric vehicles that the government and carmakers have invested billions in developing? And how would we stimulate production of advanced biofuels if the future price of crude oil were seen as being capped at or below $100 per barrel, except during geopolitical crises?
I believe all such questions have answers that don't depend on us constraining access to our resources at the cost of remaining more vulnerable to overseas suppliers and weakening both our trade deficit and our currency. I'd rather have the extra domestic oil and then worry about how to spend some of the resulting windfall of federal and state taxes, bid bonuses and royalties on achieving our other policy objectives, such as promoting efficiency and reducing emissions. Nor is relying on OPEC to keep prices high the best or most effective way to encourage us to use oil more frugally.
I don't know if North America is the next Middle East, although it's worth recalling that we were the world's biggest oil supplier before the first well was drilled in Saudi Arabia, and DOE estimates suggest we have as much oil left as we've produced to date since 1859. However, I do know that I would much rather give OPEC's leaders sleepless nights worrying how they'll keep oil prices high in the face of a wave of new production from the US, Canada and possibly Mexico, in preference to giving US consumers sleepless nights about how they'll pay for the gasoline they need for their commutes and the fuel to heat their homes, if prices stay this high or higher from here on out.
Tuesday, March 13, 2012
A Cleantech Trade War with China?
While we wait to see whether the next big move in oil prices--and hence gasoline prices--is up or down from today's level of around $125 per barrel, two stories in today's Wall St. Journal highlight some of the challenges facing manufacturers of equipment used to produce renewable energy. One concerns the intention of the US administration to seek the World Trade Organization's assistance in easing China's restrictions on its exports of rare earth materials used in a wide range of devices, including wind turbines, hybrid and electric vehicles, and some solar panels. The other is an op-ed offering a solution to the looming trade war over solar panel and wind turbine tower exports from China, modeled on the 1996 Information Technology Agreement that lowered trade barriers in that industry. The two stories are related, reflecting major unintended consequences of the ways we have approached our transition away from fossil fuels and toward lower-emission sources of energy.
Trade wars are risky things, because you never know where they will lead. The classic example of this is the Smoot-Hawley tariff of 1930. It and the responses to it by other countries helped deepen and extend the Great Depression, and I have never seen any analysis of them that concluded they were a good idea. A major trade dispute now over renewable energy hardware and the ingredients needed to produce it looks doubly unwelcome, because none of the parties comes to it with clean hands. Much of China's output of rare earths is being consumed by China-based manufacturers producing permanent magnet wind generators, electric vehicle motors, compact fluorescent lights, and solar equipment, much of which is exported to global markets that owe their very existence to government interference in the form of manufacturing, deployment and consumer tax credits; government loans and loan guarantees; feed-in tariffs; and fuel economy and lighting efficiency standards. There's hardly a single aspect of the global cleantech industry that is the result of unaided market forces.
The US complaint about solar imports is a good example. I wouldn't be surprised if the US government can make a strong case that the Chinese solar firms in question benefited from government assistance in ways that constitute unfair competition under established rules of international trade. Yet the same US government has provided substantial assistance to US solar manufacturers in the form of direct R&D support and federal loans and loan guarantees, as well as indirect help in the form of solar investment tax credits, cash grants, and project loans and loan guarantees that helped create and sustain a domestic market for them. All of these were necessary, because despite the significant cost reductions these incentives facilitated, the output of solar panels is still substantially more expensive than electricity from conventional generation. If we win this round with China, do we open the door to a whole series of WTO complaints against us by others who could claim harm from our own renewable energy policies?
From my perspective, these trade issues are a symptom of the larger problem of global overcapacity in wind and solar equipment manufacturing that has been created by the complex interaction of a mare's nest of national and local incentives and support for the production and deployment of these technologies, amplified by the disruption caused by the global financial crisis and recession of a couple of years ago and the ongoing financial crisis in Europe. A vast industry was created out of nothing and handed a market through a set of policies that could not sufficiently fine-tune development to prevent the emergence of a boom-bust cycle, and that now appears to be unsustainable itself in light of developed-country deficits and debts.
Trade disputes are one possible mechanism for attempting to rationalize this overcapacity, but in my view they constitute a much less productive approach than the one suggested by Professor Slaughter, who if I understand his proposal correctly is urging the rationalization of the government subsidies that have caused this situation in the first place. My biggest concern about his advice is his choice of the UN climate negotiating process as the best body to pursue such an initiative. That might be an appropriate venue, but its recent history doesn't inspire much confidence that it is up to the task.
Trade wars are risky things, because you never know where they will lead. The classic example of this is the Smoot-Hawley tariff of 1930. It and the responses to it by other countries helped deepen and extend the Great Depression, and I have never seen any analysis of them that concluded they were a good idea. A major trade dispute now over renewable energy hardware and the ingredients needed to produce it looks doubly unwelcome, because none of the parties comes to it with clean hands. Much of China's output of rare earths is being consumed by China-based manufacturers producing permanent magnet wind generators, electric vehicle motors, compact fluorescent lights, and solar equipment, much of which is exported to global markets that owe their very existence to government interference in the form of manufacturing, deployment and consumer tax credits; government loans and loan guarantees; feed-in tariffs; and fuel economy and lighting efficiency standards. There's hardly a single aspect of the global cleantech industry that is the result of unaided market forces.
The US complaint about solar imports is a good example. I wouldn't be surprised if the US government can make a strong case that the Chinese solar firms in question benefited from government assistance in ways that constitute unfair competition under established rules of international trade. Yet the same US government has provided substantial assistance to US solar manufacturers in the form of direct R&D support and federal loans and loan guarantees, as well as indirect help in the form of solar investment tax credits, cash grants, and project loans and loan guarantees that helped create and sustain a domestic market for them. All of these were necessary, because despite the significant cost reductions these incentives facilitated, the output of solar panels is still substantially more expensive than electricity from conventional generation. If we win this round with China, do we open the door to a whole series of WTO complaints against us by others who could claim harm from our own renewable energy policies?
From my perspective, these trade issues are a symptom of the larger problem of global overcapacity in wind and solar equipment manufacturing that has been created by the complex interaction of a mare's nest of national and local incentives and support for the production and deployment of these technologies, amplified by the disruption caused by the global financial crisis and recession of a couple of years ago and the ongoing financial crisis in Europe. A vast industry was created out of nothing and handed a market through a set of policies that could not sufficiently fine-tune development to prevent the emergence of a boom-bust cycle, and that now appears to be unsustainable itself in light of developed-country deficits and debts.
Trade disputes are one possible mechanism for attempting to rationalize this overcapacity, but in my view they constitute a much less productive approach than the one suggested by Professor Slaughter, who if I understand his proposal correctly is urging the rationalization of the government subsidies that have caused this situation in the first place. My biggest concern about his advice is his choice of the UN climate negotiating process as the best body to pursue such an initiative. That might be an appropriate venue, but its recent history doesn't inspire much confidence that it is up to the task.
Thursday, March 08, 2012
Is There A Better Way to Use Strategic Petroleum Reserve Oil Now?
With US gas prices rising rapidly to record levels for this time of year, it was inevitable that some politicians would start calling for a portion of the oil in the Strategic Petroleum Reserve (SPR) to be released in hopes of moderating high oil prices, which are mainly responsible for the current gas price spike. A narrow majority of Americans apparently agrees. This is a profoundly bad idea, for reasons of both actual US energy security and the uneven effectiveness of past releases. However, rather than railing against this proposal, it occurred to me that there might just be a better way, an alternative that could send the signals that those concerned about commodity speculation wish to send, but without draining oil that we would miss in an actual supply crisis. What if instead of instructing the Secretary of Energy to sell a certain quantity of oil from the SPR, the President told him to sell an equivalent volume of call options on SPR oil, on the condition that they that could only be executed in an actual emergency?
The SPR was established in the 1970s, and as I've noted on several occasions it's overdue for a major redesign to reflect the ways in which both the world and US energy consumption patterns and infrastructure have changed in the interim. However, this is clearly not the appropriate time for such an undertaking, with the very real prospect of a major disruption in the Middle East that might require the largest-ever SPR release to address.
The past history of SPR releases is well-documented. The two releases most relevant to the current situation include last year's release of 30 million barrels in coordination with other member countries of the International Energy Agency, to compensate for reduced exports from Libya resulting from the revolution that overturned Col. Gaddafi's regime. Although one could argue about the appropriateness of that response in the absence of a meaningful disruption in oil deliveries to the US, its outcome is now clear. The market impact of the release was small and quickly dissipated in the noise of market volatility. That stands in marked contrast to the SPR release announced at the start of hostilities in the Gulf War in 1991. Following the announcement of a 34 million barrel SPR sale, only half of which was ultimately delivered, oil prices fell by 33% literally overnight. I will never forget that, because I was trading petroleum products in London for Texaco at the time and the sudden shift in prices was stressful, to say the least. The lesson I take from these and other examples is that SPR releases are much more effective in an actual emergency than when they are perceived as merely attempts to manipulate the market.
But let's give those calling for a release now the benefit of the doubt that $125 oil and the resulting near-$4 gas prices might be at least partly the result of speculation--all the while recognizing that for every speculative buyer there must be a seller taking the opposite view of prices. If the Department of Energy were to sell options on SPR oil, instead of the oil itself, it could accomplish several useful things in this scenario. First, it would send a stronger signal to the market than the will-he-or-won't-he cloud that customarily hangs over such releases, conveying that the US is serious about covering a shortfall that might result from the manifestation of the various risks that have driven up oil prices by about 13% since the beginning of the year, notably focused on tensions with Iran. It would also generate a bit of revenue for the Treasury, in the amount of the option premiums collected. More importantly, it could significantly shorten the normal delay between the decision to hold an SPR sale and its actual execution, by identifying, pre-qualifying and contracting with specific buyers ahead of actual need. Hastening the flow of SPR oil in a crisis by a week or two could be very helpful. And the best feature from my perspective is that the whole time the oil would stay right where it should remain until it's really needed, in the SPR caverns on the Gulf Coast.
A number of crucial details would have to be worked out, including the careful specification of the precise circumstances under which the options could be triggered, how long they would remain active before expiring, who would be eligible to purchase them, and for what purposes. In order to be of value to buyers, the triggering event(s) would have to be objectively observable and not under the seller's control. Perhaps a specified reduction in exports through the Strait of Hormuz, or the outbreak of hostilities between Iran and Israel or the US would be the most suitable choices, since it is presumably such risks that have taken oil prices to their current level.
I don't know whether selling SPR options would be permissible under current statutes. If not, it might be hard to get a change like this through a deadlocked Congress, even though the idea of selling options rather than physical oil ahead of an actual emergency straddles the concerns of both parties. I'm also sure there would be unintended consequences, as well as a lot of finger-pointing after the fact if some trader or refiner made a fortune on one of these transactions. Still, it seems worth exploring as an alternative that might be useful, not just when we're facing high prices and a potential crisis but under more routine circumstances.
The SPR was established in the 1970s, and as I've noted on several occasions it's overdue for a major redesign to reflect the ways in which both the world and US energy consumption patterns and infrastructure have changed in the interim. However, this is clearly not the appropriate time for such an undertaking, with the very real prospect of a major disruption in the Middle East that might require the largest-ever SPR release to address.
The past history of SPR releases is well-documented. The two releases most relevant to the current situation include last year's release of 30 million barrels in coordination with other member countries of the International Energy Agency, to compensate for reduced exports from Libya resulting from the revolution that overturned Col. Gaddafi's regime. Although one could argue about the appropriateness of that response in the absence of a meaningful disruption in oil deliveries to the US, its outcome is now clear. The market impact of the release was small and quickly dissipated in the noise of market volatility. That stands in marked contrast to the SPR release announced at the start of hostilities in the Gulf War in 1991. Following the announcement of a 34 million barrel SPR sale, only half of which was ultimately delivered, oil prices fell by 33% literally overnight. I will never forget that, because I was trading petroleum products in London for Texaco at the time and the sudden shift in prices was stressful, to say the least. The lesson I take from these and other examples is that SPR releases are much more effective in an actual emergency than when they are perceived as merely attempts to manipulate the market.
But let's give those calling for a release now the benefit of the doubt that $125 oil and the resulting near-$4 gas prices might be at least partly the result of speculation--all the while recognizing that for every speculative buyer there must be a seller taking the opposite view of prices. If the Department of Energy were to sell options on SPR oil, instead of the oil itself, it could accomplish several useful things in this scenario. First, it would send a stronger signal to the market than the will-he-or-won't-he cloud that customarily hangs over such releases, conveying that the US is serious about covering a shortfall that might result from the manifestation of the various risks that have driven up oil prices by about 13% since the beginning of the year, notably focused on tensions with Iran. It would also generate a bit of revenue for the Treasury, in the amount of the option premiums collected. More importantly, it could significantly shorten the normal delay between the decision to hold an SPR sale and its actual execution, by identifying, pre-qualifying and contracting with specific buyers ahead of actual need. Hastening the flow of SPR oil in a crisis by a week or two could be very helpful. And the best feature from my perspective is that the whole time the oil would stay right where it should remain until it's really needed, in the SPR caverns on the Gulf Coast.
A number of crucial details would have to be worked out, including the careful specification of the precise circumstances under which the options could be triggered, how long they would remain active before expiring, who would be eligible to purchase them, and for what purposes. In order to be of value to buyers, the triggering event(s) would have to be objectively observable and not under the seller's control. Perhaps a specified reduction in exports through the Strait of Hormuz, or the outbreak of hostilities between Iran and Israel or the US would be the most suitable choices, since it is presumably such risks that have taken oil prices to their current level.
I don't know whether selling SPR options would be permissible under current statutes. If not, it might be hard to get a change like this through a deadlocked Congress, even though the idea of selling options rather than physical oil ahead of an actual emergency straddles the concerns of both parties. I'm also sure there would be unintended consequences, as well as a lot of finger-pointing after the fact if some trader or refiner made a fortune on one of these transactions. Still, it seems worth exploring as an alternative that might be useful, not just when we're facing high prices and a potential crisis but under more routine circumstances.
Tuesday, March 06, 2012
Shale Gas Likely to Alter China's Energy Mix
Two recent news stories highlight the significant shifts underway in China's energy sector, along with the global impact that is already apparent from these changes. Last week the Chinese government announced a new estimate for the country's potential resources of shale gas that is nearly double the Department of Energy's latest estimate for US shale gas. However, having the resource and developing both it and the infrastructure and market to take advantage of it are distinctly different things, as I pointed out in a brief interview on the subject on public radio's Marketplace program. The key to that may be found in a front-page story in today's Wall St. Journal describing the recent pace of Chinese investment in the North American energy sector.
When we think about energy in China, we tend to focus on the vast scale of its coal use, which affects local, regional and, at times, trans-Pacific air quality, to say nothing of its huge greenhouse gas impact. Coal made up 70% of China's total energy mix in 2010. Or we might think of the explosive pace of renewable energy deployment, although China's solar industry, and to a lesser extent its wind power industry, are still mainly export-oriented. Non-hydropower renewables, which were identified as a strategic industry within the 12th Five-Year Plan, account for just 0.5% of China's energy, but the government has recently indicated it would rein in the "blind expansion" of such sources. Together with hydro and nuclear, low-emission energy sources account for just 8% of the total, less than half the 18% share of oil, which is likely to continue expanding as the transport sector grows and encompasses more personal cars. That leaves natural gas with just 4% and a much lower profile than in the US, where it supplies roughly one-fourth of total energy.
If the resource figures that were just released are any indication, the potential growth of gas in China may exceed that of all other energy sources over the next several decades. Nor is that growth dependent on shale gas development, which is in its infancy there, with only a few wells having been drilled. China has some conventional gas production and a small but growing coal-bed methane industry, and it is already one of the world's largest purchasers of liquefied natural gas (LNG). Although the shale gas figures might seem like bad news for companies planning LNG exports from the US, or for the enormous new LNG projects in Australia and elsewhere in the region, they could prove complementary in two ways.
First, the current availability of large and growing quantities of LNG in Asia-Pacific provides the basis for developing both the enormous potential gas market in China's coastal industrial centers and the infrastructure for serving it, including the crucial "reticulation system"--what other industries call the last mile. You simply don't build this unless you have a large, reliable supply on hand, and you also don't develop huge new domestic supplies unless they have an assured market. LNG could thus be the key to avoiding a classic chicken-and-egg dilemma that might otherwise retard the growth of gas in China for years.
At the same time, the recently identified shale gas resources solve a major problem for LNG vendors, by reassuring Chinese buyers that they will have access to ample gas to satisfy industrial, commercial and residential demand long after the 20-year or longer LNG contracts expire and the reservoirs feeding the region's LNG plants are depleted. But that's only true if China acquires the expertise for developing its own gas, and that's where its North American energy deals come into play.
The Journal article provides a good overview of how Chinese companies changed their approach to North American oil & gas mergers and acquisitions in the aftermath of CNOOC's failed bid for Unocal in 2005. Chinese investors have learned not to raise the hackles that that deal did, and they have focused on minority shares in oil & gas companies or in specific field developments, mainly in unconventional plays such as the Eagle Ford shale in Texas with Chesapeake Energy. Even if no intellectual capital flows back to the investing companies, the mindset required for selecting and managing such projects surely will, and that will have a direct bearing on China's enormous new shale resources, which if proved up would equate to 230 years of current consumption.
No one can know at this point how durable last week's estimate of 25.1 trillion cubic meters (886 trillion cubic feet--TCF) of undiscovered, technically recoverable shale gas will be. The Energy Information Agency recently cut its previous US shale gas estimate of 827 TCF by 42%, based on updated information on per-well recovery rates and other factors, particularly in the Marcellus formation underlying New York, Pennsylvania and other northeastern states. (Despite being widely publicized by critics of shale development, this adjustment won't have any bearing on actual shale gas output for many years, during which the resource estimate is likely to be further refined many times.) China will gain similar experience as it develops its shale resource and should have a much better handle on its probable size within a few years. As with nearly everything else related to the country's economic development, the number is still likely to be very big.
When we think about energy in China, we tend to focus on the vast scale of its coal use, which affects local, regional and, at times, trans-Pacific air quality, to say nothing of its huge greenhouse gas impact. Coal made up 70% of China's total energy mix in 2010. Or we might think of the explosive pace of renewable energy deployment, although China's solar industry, and to a lesser extent its wind power industry, are still mainly export-oriented. Non-hydropower renewables, which were identified as a strategic industry within the 12th Five-Year Plan, account for just 0.5% of China's energy, but the government has recently indicated it would rein in the "blind expansion" of such sources. Together with hydro and nuclear, low-emission energy sources account for just 8% of the total, less than half the 18% share of oil, which is likely to continue expanding as the transport sector grows and encompasses more personal cars. That leaves natural gas with just 4% and a much lower profile than in the US, where it supplies roughly one-fourth of total energy.
If the resource figures that were just released are any indication, the potential growth of gas in China may exceed that of all other energy sources over the next several decades. Nor is that growth dependent on shale gas development, which is in its infancy there, with only a few wells having been drilled. China has some conventional gas production and a small but growing coal-bed methane industry, and it is already one of the world's largest purchasers of liquefied natural gas (LNG). Although the shale gas figures might seem like bad news for companies planning LNG exports from the US, or for the enormous new LNG projects in Australia and elsewhere in the region, they could prove complementary in two ways.
First, the current availability of large and growing quantities of LNG in Asia-Pacific provides the basis for developing both the enormous potential gas market in China's coastal industrial centers and the infrastructure for serving it, including the crucial "reticulation system"--what other industries call the last mile. You simply don't build this unless you have a large, reliable supply on hand, and you also don't develop huge new domestic supplies unless they have an assured market. LNG could thus be the key to avoiding a classic chicken-and-egg dilemma that might otherwise retard the growth of gas in China for years.
At the same time, the recently identified shale gas resources solve a major problem for LNG vendors, by reassuring Chinese buyers that they will have access to ample gas to satisfy industrial, commercial and residential demand long after the 20-year or longer LNG contracts expire and the reservoirs feeding the region's LNG plants are depleted. But that's only true if China acquires the expertise for developing its own gas, and that's where its North American energy deals come into play.
The Journal article provides a good overview of how Chinese companies changed their approach to North American oil & gas mergers and acquisitions in the aftermath of CNOOC's failed bid for Unocal in 2005. Chinese investors have learned not to raise the hackles that that deal did, and they have focused on minority shares in oil & gas companies or in specific field developments, mainly in unconventional plays such as the Eagle Ford shale in Texas with Chesapeake Energy. Even if no intellectual capital flows back to the investing companies, the mindset required for selecting and managing such projects surely will, and that will have a direct bearing on China's enormous new shale resources, which if proved up would equate to 230 years of current consumption.
No one can know at this point how durable last week's estimate of 25.1 trillion cubic meters (886 trillion cubic feet--TCF) of undiscovered, technically recoverable shale gas will be. The Energy Information Agency recently cut its previous US shale gas estimate of 827 TCF by 42%, based on updated information on per-well recovery rates and other factors, particularly in the Marcellus formation underlying New York, Pennsylvania and other northeastern states. (Despite being widely publicized by critics of shale development, this adjustment won't have any bearing on actual shale gas output for many years, during which the resource estimate is likely to be further refined many times.) China will gain similar experience as it develops its shale resource and should have a much better handle on its probable size within a few years. As with nearly everything else related to the country's economic development, the number is still likely to be very big.
Thursday, March 01, 2012
What Would It Take for Gas to Hit $5 per Gallon?
After returning from a business trip to California, I don't find media speculation concerning the possibility of $5 gasoline later this year quite as far-fetched as I might have last week. Perhaps seeing $4.299 per gallon posted for unleaded regular on many street corners there, compared to $3.699 or so here, gave me a touch of "availability bias" even if I also understand that gasoline taxes in the Golden State are a full 29¢ per gallon higher than in Virginia, and that environmental regulations there make it very much more difficult for refineries to produce fuel that meets California's specifications. Without dwelling on regional differences that could make $5 gas likelier in some places than others, I thought it might be worth spending a moment considering what it would take to reach that level on a national average.
In a situation such as the current one, as I described a few weeks ago, it comes down to crude oil prices. Calculating the oil price implied by $5 gasoline requires backing out the other key components of the pump prices we observe. Start with federal and state taxes, which according to API averaged 48.8¢/gal. in January. (That's only a snapshot, because many states include sales taxes that change in proportion to the overall price level.) You also have to subtract the retailer/distributor margin, which is typically around 15¢/gal. That leaves $4.36/gal., or roughly $183 per bbl, for pre-tax wholesale gasoline. But we still have to account for refining margin, or more accurately the spread between wholesale gasoline and crude oil, since a true refining margin would include the influence of a range of other products and byproducts like diesel, jet fuel, lubricants and petroleum coke. In 2010, before the Cushing crude bottleneck depressed West Texas Intermediate prices to the extraordinary degree we've seen in the last year, the average difference between gasoline and light crude futures on the New York Mercantile Exchange was $9.67/bbl. Knock that off the above calculated wholesale price and we get an implied price for light sweet crude of just under $175/bbl.
As of today, Louisiana Light Sweet and UK Brent, the best current indicators for this kind of crude, stood at $127 and $126, respectively, while poor old WTI languished at $109. So based on the above calculation, $5 gasoline would require world oil prices to rise by about $50/bbl--or more if you back-calculate from last week's average US gas price of $3.72/gal. Short of the saber-rattling in the Persian Gulf turning into a shooting war, it's hard to see that happening without the kind of economic conditions that took oil close to $150/bbl in 2008. That experience also suggests that if we reached $5/gal., the event might be short-lived as the shock waves it would cause undermined the economy and thus the fundamentals of oil prices.
Unlike Tom Kloza of Oil Price Information Service, I will not don a clown suit if the average US price of gasoline reaches $5 this year. However, I would be very surprised, barring the outbreak of hostilities between Iran and the US or Iran and Israel, a global or self-imposed boycott of Iranian oil exports, or a sudden, unexpected problem in another major producing country. Whether that makes predictions of $5 gas "hyperbole", as Mr. Kloza apparently suggested, or merely the result of failures to do the math, I leave for you to decide.
In a situation such as the current one, as I described a few weeks ago, it comes down to crude oil prices. Calculating the oil price implied by $5 gasoline requires backing out the other key components of the pump prices we observe. Start with federal and state taxes, which according to API averaged 48.8¢/gal. in January. (That's only a snapshot, because many states include sales taxes that change in proportion to the overall price level.) You also have to subtract the retailer/distributor margin, which is typically around 15¢/gal. That leaves $4.36/gal., or roughly $183 per bbl, for pre-tax wholesale gasoline. But we still have to account for refining margin, or more accurately the spread between wholesale gasoline and crude oil, since a true refining margin would include the influence of a range of other products and byproducts like diesel, jet fuel, lubricants and petroleum coke. In 2010, before the Cushing crude bottleneck depressed West Texas Intermediate prices to the extraordinary degree we've seen in the last year, the average difference between gasoline and light crude futures on the New York Mercantile Exchange was $9.67/bbl. Knock that off the above calculated wholesale price and we get an implied price for light sweet crude of just under $175/bbl.
As of today, Louisiana Light Sweet and UK Brent, the best current indicators for this kind of crude, stood at $127 and $126, respectively, while poor old WTI languished at $109. So based on the above calculation, $5 gasoline would require world oil prices to rise by about $50/bbl--or more if you back-calculate from last week's average US gas price of $3.72/gal. Short of the saber-rattling in the Persian Gulf turning into a shooting war, it's hard to see that happening without the kind of economic conditions that took oil close to $150/bbl in 2008. That experience also suggests that if we reached $5/gal., the event might be short-lived as the shock waves it would cause undermined the economy and thus the fundamentals of oil prices.
Unlike Tom Kloza of Oil Price Information Service, I will not don a clown suit if the average US price of gasoline reaches $5 this year. However, I would be very surprised, barring the outbreak of hostilities between Iran and the US or Iran and Israel, a global or self-imposed boycott of Iranian oil exports, or a sudden, unexpected problem in another major producing country. Whether that makes predictions of $5 gas "hyperbole", as Mr. Kloza apparently suggested, or merely the result of failures to do the math, I leave for you to decide.
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