Energy Outlook

D.C. Auto Show Focused on Efficiency

2012-01-31T10:58:00.003-05:00

Last week I attended the media preview of the Washington Auto Show. With its dual focus on cars and energy policy, this is always a high point of the winter for me, even if this year's display lacked a draw of the magnitude of the pre-production Chevrolet Volt I drove at the 2010 show. Instead, I was pleased to find that the emphasis on fuel economy and technology in carmaker presentations was matched by a broad array of efficient and attractive new products. They still don't quite constitute the new car fleet needed for the 54 mile-per-gallon target the federal government requires them to meet by 2025, but in my opinion they're off to a very good start.

No one listening to the presentations I sat through last Thursday could have missed the shift in focus from previous years. Performance and drivability were still mentioned prominently, but in most cases the innovations allowing those attributes to be delivered along with improved fuel economy, instead of at its expense, received top billing. I heard about Ford's nine models that achieve at least 40 mpg, including the new C-MAX Energi plug-in hybrid that received Green Car Journal's Vision Award for 2012. GM touted a number of efficient new models, including the upcoming Chevrolet Spark subcompact, which will later be available as a full EV. In some respects I found the 2013 Malibu Eco with "e-Assist" even more impressive: With the new Malibu and this year's Buick LaCrosse, GM is building family-sized gasoline-powered sedans that achieve 36 or 37 mpg on the highway. And thanks to Fiat's MultiAir technology, Chrysler had its new 40 mpg Dodge Dart on display.

I was particularly interested in the VW press conference, where they debuted the 45 mpg 2013 Jetta turbo hybrid. The head of VW's US division introduced the car as part of his company's Think Blue sustainability drive, which with this latest model encompasses hybrids, clean diesels, efficient non-hybrid gasoline engines, and soon EVs. With all this technology to talk about, including the new, larger Passat sedan--where's the wagon?--built in VW's new Chattanooga, TN plant and sporting a diesel engine delivering 43 highway mpg (31 city), the biggest surprise was the amount of time he devoted to VW's partnership with Bikes Belong, a cycling safety group aimed at getting people out of their cars. That certainly reflects a bigger-picture view of vehicle sustainability.

My visit to the car show also included a meeting with Lars Ullrich, marketing director of Bosch Diesel Systems North America, and Jeff Breneman of the US Coalition for Advanced Diesel Cars. They updated me on the progress that diesels have been making in the US market, particularly in light of the greater cost-consciousness of consumers, post-recession. In the last five years, the willingness of consumers to consider diesels has nearly tripled to around one-third, while diesel sales passed the 100,000 mark for 2011--still less than 1%, but about where hybrids were just a few years ago. Clean diesel models are expected to double by 2014, including announced diesel versions of the Chevrolet Cruze, Jeep Cherokee, Dodge Dakota, and a Mazda crossover. Will diesels ever reach the level of popularity here that they've attained in Europe, where half of all new cars are diesel-powered? They must wage an uphill battle against fuel economy regulations that are anything but fuel-neutral, legacy perceptions formed by the dirty diesels of 20 years ago, and federal and state fuel taxes that still assume that all diesel fuel is used by heavy-duty trucks that wear out our highways. That's a shame, because this is a terrific technology that could be every bit as attractive to many consumers as more expensive hybrids.

Another noteworthy item I gleaned from the manufacturers' presentations was that several of them are forecasting a return to annual US car sales of 16 million within a couple years. That would be good for the industry and employment, but it's crucial for shifting the fuel economy of the entire light-duty vehicle fleet. One of the unnoticed consequences of the low car sales of the last several years is that the US fleet has been aging faster, notwithstanding the small blip from the Cash-for-Clunkers program of 2009. The difference between sales of 16 million a yar versus 12 million is an average turnover of 15 years, instead of more than 20, and faster turnover should translate to quicker improvements in average mpg.

For years we heard that the biggest obstacle to improving the fuel economy of the US car fleet was the auto industry, which only wanted to sell us big SUVs that carried higher profit margins. That excuse was always overly simplistic, and it has been relegated to the ash heap by a new generation of cars and light trucks featuring innovations delivering steadily improving efficiency, even in mainstream sedans and SUVs. Getting the entire fleet to 54 mpg won't be easy, but if what I saw at the D.C. auto show is any indication, the attainment of that goal now depends at least as much on sales mix as on the availability of efficient models. Within a few years, virtually every segment of the market will include hybrid, diesel and EV options that will put a big dent in both fuel bills and emissions, albeit at the expense of higher sticker prices. That means that future fleet mpg will likely be determined mainly by the decisions of consumers, rather than carmakers.

State of the Union: "All-Out, All-of-the-Above Energy"

2012-01-25T11:41:00.002-05:00

Anyone expecting the announcement of big new energy initiatives in this year's State of the Union address was disappointed last night. What was new, however, was a welcome shift in the President's emphasis on conventional energy--the fuels he referred to as "yesterday's energy" in last year's speech. Never mind that the resurgent oil production for which Mr. Obama took credit is demonstrably the result of events and policies that preceded his inauguration, or that his administration has pursued policies that have held back faster development. If his remarks signal a return to federal energy policy that expends more than 10% of its effort on the sources that account for more than 80% of the energy we use, we should applaud him. The other new ingredient last night was an effort to ground the rationale for greater support for renewable energy in the argument that it took federally sponsored R&D to make the shale gas revolution possible--R&D that ironically wouldn't have occurred under the research priorities this President has set for the Department of Energy. I hope President Obama is serious about an "all-out, all-of-the-above strategy" for energy, because that's precisely what we need.

The best way to put that in perspective is with the figures in the 2012 Early Release of the Annual Energy Outlook from the Energy Information Agency of the DOE. It was released just in time for the President's speech, and there are few coincidences in today's Washington. The reference case of their forecast for 2035 shows the US consuming 10% more energy within 24 years--an improvement from the 16% predicted in last year's Outlook. It also shows the contribution of renewable energy in the mix increasing from 6.7% today to 8.3%, including mature hydropower. So even after two more decades of strong emphasis on clean energy, oil, gas and coal would continue to provide 80% of our energy. It's clear that there's a disconnect between the lofty rhetoric of last night's speech and the analysis of the government's energy experts. I'll leave it to you to assess whether the discrepancy is due to unrealistic expectations, inadequately ambitious forecasting, or some combination of the two.

A couple of other points from the State of the Union are worth noting. The President called for Congress to "Pass clean energy tax credits," presumably a reference to the Production Tax Credit (PTC) for wind and other renewables that expires at the end of this year. Yet he didn't devote a word to whether the PTC should be restructured and gradually phased out in light of the steadily narrowing competitive gap between renewable and conventional power, let alone the kind of major tax reform he alluded to later in the speech. Mr. Obama also called for a Clean Energy Standard in lieu of a comprehensive climate bill. This is small beer when most of the states with attractive renewable energy resources already have fairly aggressive state-level Renewable Portfolio Standards. Meanwhile, the development of 3 million homes' worth of clean energy sources on public lands that he is directing his administration to allow equates to less than 1% of US electricity demand--helpful, though hardly transformational.

With little likelihood of a divided Congress enacting much that is new on energy this year, the President's remarks last night are mainly interesting for what they suggest about the energy platform on which he will run for reelection this fall. In terms of clean energy, that seems to mean more of the same from 2008 and the last three years, but with much less emphasis on climate change than we heard in his last campaign. The new element is his pivot to embrace rising oil production and the possibilities created by shale gas, even as he cautiously distances himself from the technologies (hydraulic fracturing and horizontal drilling) that make these two trends possible. Although this might appeal to independent voters, it's also vulnerable to deflation by fact-checking and stands in tension with his rejection--for now--of the Keystone XL pipeline. And if tensions in the Persian Gulf or some other oil hot spot were to increase, so would the scrutiny applied to the administration's energy policies. I'll take a much closer look at those policies when the campaign heats up.

Applying Innovation to Oil & Gas

2012-01-23T13:28:00.002-05:00

This Friday at noon Eastern Time I'll be participating in a webinar on The Energy Collective covering the application of innovation to the emissions from oil and natural gas. The topic is timely, not just because of the current debate over the fate of the Keystone Pipeline, but because despite the growing importance of renewable energy, oil and gas will constitute a major part of our energy diet for decades to come. As I was thinking about my remarks, it occurred to me that the best starting point might be a refresher on how the industry's current emissions are distributed along the value chain. For all the heavily-publicized concerns about higher emissions from the extraction of unconventional hydrocarbons such as oil sands crude and shale gas, combustion by end-use applications accounts for the biggest slice, to the tune of 80-84% of the average lifecycle emissions from gasoline, diesel and jet fuel. Even for fuels refined from oil sands, our tailpipes still put out more than two-thirds of the total emissions attributable to oil. The proportions are similar for natural gas.

The data I'm using come from a presentation of the National Energy Technology Laboratory, which is part of the US Department of Energy, and the NETL reports on which it was based. I could have chosen other sources, but they all reach pretty much the same conclusions, and I liked the way this one displayed the differences among various source crudes. It also goes beyond dividing the total "well-to-wheels" lifecycle (WTW) into well-to-tank (WTT) and tank-to-wheels (TTW) sources, those that happen before the fuel gets to your car and those that happen in your car, respectively. The former category was further broken down into segments of extraction, crude oil transport, refining, and finished fuels transport. All of these are amenable to improvements through innovation, and I plan to focus on the four WTT categories on Friday.

However, as helpful as it would be from an emissions perspective to get oil out of the ground with less expenditure of energy and less leakage of methane and other gases, and then to transport and refine it as efficiently as possible, the most effective emission-reduction strategies by far are those that address vehicle emissions from transport. That includes all the ways we normally think of to improve fuel economy, including hybridization and dieselization, which reduce CO2 emissions in direct proportion to fuel savings. Yet it also includes a whole gamut of strategies for reducing vehicle miles traveled, which are currently below the record set in 2007 but remain about 10% above year-2000 levels. Trip consolidation, telecommuting, carpooling, and using public transport can all make an important dent in emissions, and in the long run they eliminate upstream WTT emissions, too, as less oil is required for the same economic activity.

I'm sure that most of this is old hat to those who are well-informed on energy issues, but it's important periodically to remind ourselves of the basics, before we get overly enamored with all the exotic technology we could apply to other portions of the value chain. Deploying wind and solar generation in oil fields, generating geothermal energy from the hot fluids brought to the surface with oil and gas, and making the liquids shipped through pipelines slipperier can all contribute to reducing greenhouse gases, but we should understand clearly that these techniques can only tackle the 20% of emissions that happen before the fuel gets to the local gas station.

Playing Games with US Energy Security

2012-01-18T16:44:00.002-05:00

Well, that didn't take long. The administration issued its decision denying the Keystone XL Pipeline application today, rather than using the remaining 34 days in the Congressionally mandated timeline to attempt to find a better solution. This is a prime example of what frustrates so many Americans of all political affiliations about how the nation is being governed. If you read the carefully drafted press release from the State Department, which had been given responsibility for determining whether the pipeline was in the national interest, it explicitly states that today's decision was neither final nor on the merits of the project. Implicit in this document is that today's move is exactly that, the latest move in the game that the President and Congress have been playing with a project large enough to affect the energy security of this country for decades to come. It is unseemly, and it didn't have to be played this way, despite the White House's protests that the 60-day timeline was unrealistic--after three years of study.

Here's a different statement the President could have issued, which might not have satisfied either side of the argument but would have left his administration looking like one with a bias for action and answers, instead of delays and obstacles:

"Today I have instructed the State Department to issue a pro forma finding against the application for the Keystone XL Pipeline project, with the clear understanding that this decision is a temporary expedient to provide the time necessary to resolve the remaining outstanding issues, as quickly as humanly possible. I hereby commit that my administration will do everything in its power to work with the government of Canadian Prime Minister Harper and with Governor Heineman of Nebraska to reach a mutually satisfactory solution that will allow this critical project strengthening the energy bonds between our two nations to proceed, while finding meaningful ways to address the concerns that many Americans have about the project's potential local and global environmental impacts. With renewed tensions in the Persian Gulf and with millions of Americans still out of work, we can do nothing less, even as we remain committed to protecting the environment that benefits us all. I have directed Secretary Clinton to work closely with Energy Secretary Chu and EPA Administrator Jackson and with their counterparts in Canada to develop a solution that addresses these needs, and to report back to me within 90 days with its outline ."

I don't diminish the political challenges of issuing such a statement when key parts of the President's support base have been so vocal in opposing this project. All you have to do is look at the latest set of talking points against the project from the Natural Resources Defense Council (NRDC). As disappointingly illogical a mishmash as they may be, based on misinterpreted data and a bizarre defense of cheap oil for the Midwest, they still reflect heartfelt, even visceral, reactions to the Keystone project--or more accurately to the oil sands development that it was expected to enable. Fair enough. I respect their right to an opportunity to provide input and guidance toward an eventual compromise, but not to a veto over US energy policy.

Nor should the opponents of the Keystone XL project fool themselves. Today's decision was guided by expediency, just as the future, possibly quite different decision for which the door was left open would be, perhaps at a point in time when the political calculus has shifted in favor of the project due to some external event. A decision based on principle would have looked quite different. "The Department’s denial of the permit application does not preclude any subsequent permit application or applications for similar projects." Whose move is it now?

More Long-Term Pressure on Oil Prices

2012-01-17T15:10:00.001-05:00

A pair of items in today's Financial Times could signal a longer run of high oil prices, even if Europe were to slip into recession and economic growth elsewhere slow. The first article (registration required) reported that Saudi Arabia has raised its target oil price to $100 per barrel, up from the $75 level that King Abdullah had previously endorsed as "fair." Meanwhile, Venezuela has announced that it would withdraw from a World Bank body for arbitrating contractual disputes, preferring them to be resolved within its own judicial system. That can't be welcome news for companies that had been considering new investments in the country's oil and gas sector. Taken together, these stories suggest both less future supply and a greater likelihood that OPEC would respond to any significant weakness in oil prices by restricting output.

With markets currently tense over the prospect that Iran might make good on its threat to close the Strait of Hormuz, the prospect of Saudi Arabia boosting output if necessary to keep prices from going much beyond $100/bbl must seem welcome, at least in the short term. But as the FT explains, the choice of that figure, rather than a lower one, reflects the fiscal realities of a broad group of Middle East producers. The Saudis, Iran, Iraq, and the UAE all require oil prices north of $80/bbl in order to balance national budgetary requirements. Considering that the cost of producing much of this oil is likely still in either the single digits or low double-digits, that is an extraordinary commentary on just how much these countries depend on oil revenues to fund the social expenditures that maintain their respective domestic status quos. So while Saudi oil minister al-Naimi may have intended his comment to convey a comforting price ceiling, it probably said as much about his government's view of where the floor should be. With UK Brent crude currently trading at roughly the same $111/bbl level that set a full-year price record last year, I'm not sure how many of us would find that reassuring.

The decision by Venezuela's dictator to exit the World Bank arbitration mechanism shouldn't have come as a surprise, with an estimated $40 billion in international claims outstanding for his past actions in nationalizing assets and arbitrarily altering contractual terms in a variety of industries. The recent ruling by the International Chamber of Commerce in favor of an ExxonMobil claim might just have been the final trigger. Yet despite the obvious expediency of such an exit, it seems grossly counterproductive in the context of a producing country that depends increasingly on foreign investment to stem a long-term decline in output. Since President Chavez punished his nation's oil industry by firing its most capable managers and engineers following a strike in 2002-3, Venezuelan oil production has fallen by at least 15%, and it only avoided a larger drop due to the contribution of the big Orinoco production and upgrading projects built by foreign firms such as ExxonMobil, Chevron, ConocoPhillips and Total--some of which are now seeking compensation for expropriation of assets and other grievances.

Requiring disputes to be resolved within a court system that has been stacked with Chavez loyalists hardly seems like the recipe for reducing political risk and reassuring companies that have already seen past investments turn sour. While companies that have too much at stake to leave will try to make the best of this, others would be well-advised to steer clear. However this turns out for the industry, the likely outcome for Venezuela is lower production in the future and even greater support for hawkish price policies within OPEC, to prop up the oil revenues upon which Chavez's redistribution policies depend.

Of course none of this guarantees high oil prices in perpetuity. After all, OPEC was unable to prevent prices collapsing to below $40/bbl in late 2008, though it did restrain output enough to get them back to around $80 within a year. However, both stories should remind us that in a world in which oil prices are set to suit producers better than consumers, our primary focus should be on actions and policies that enhance our energy security. That means substituting plentiful natural gas for oil and its products where we can, promoting conservation and efficiency, pursuing cost-effective renewables, and ensuring that we have access to as much oil from domestic and trusted international sources as possible. Rejecting the Keystone XL Pipeline, instead of committing to find a way to make it work while addressing reasonable concerns about it, would be nothing less than a gift to OPEC.

Disclosure: My portfolio includes investment in Chevron, which is mentioned above and owns projects and facilities that could be affected by these events.

Because That's Where the Emissions Are

2012-01-12T00:57:00.003-05:00

Yesterday the Environmental Protection Agency released its tabulation of greenhouse gases (GHGs) from large facilities in the US. In perusing the data I couldn't help thinking of the quote attributed to Willie Sutton concerning why he robbed banks. Even if he never actually said, "Because that's where the money is," the simple logic of that analysis transfers neatly to the question of why we might be interested in assessing and ultimately managing GHG emissions from such installations. While there are other important sources, notably including motor vehicles and aircraft, the more than 6,000 sites reported in the agency's online registry account for roughly half of all US GHG emissions. Furthermore, just a quarter of these sites--power plants--contribute nearly three-fourths of US emissions from large facilities. That's where the emissions are and where US climate policy should focus.

Although that doesn't dictate that we should entirely ignore all the other facilities, it certainly raises serious questions about the threshold of reporting for the hundreds of installations emitting less than 10,000 tons of CO2-equivalent gases per year, compared to the top-100 facilities, the smallest of which emitted nearly twice that much every day.

It should also challenge the belief systems of some members of Congress concerning the relative importance of different sectors. The highest-emitting oil refinery in the country is also one of the biggest in the world by throughput capacity, at 573,000 barrels per day. Yet it comes in at #45 on the list, with only one other refinery appearing in the top 100. The entire refining sector, comprising 145 plants, emitted around 5.7% of the total GHGs represented in the registry, and thus less than 3% of the US total. Why does that matter as more than an industry talking-point? Because reducing emissions from refineries by 10%--no easy task when they are already roughly 90% efficient in terms of their total energy output vs. inputs--would be lost in the rounding in our national emissions statistics. We won't get very far chasing expensive diminishing returns.

By comparison, reducing emissions from the 1,555 power plants on the list by an average of 10% would reduce US emissions by more than 3%. And because we are blessed with many more processes for generating electricity than for refining oil, this could be achieved in a variety of ways, nor does 10% represent any kind of ceiling for what might be possible. One option would be to retire the least-efficient coal-fired plants and take up the slack at existing gas-turbine power plants, plus some additional renewables. That may happen anyway, as a consequence of other EPA regulations. We could also replace the worst coal plants with near-zero-emission nuclear power plants of advanced design, such as the AP-1000 reactor that won NRC approval late last year, or the various modular nuclear reactors now under development. Capturing and sequestering the CO2 from coal-fired power plants would be another option, if it can be perfected at a reasonable cost.

I would never suggest that climate policy could be truly simple, but the numbers the EPA just reported, combined with what we know about the lifecycle emissions from the petroleum value chain, indicate that the scope of the US climate policy debate could usefully be narrowed to focus on just two main emissions sources: power plants and the end-use combustion of hydrocarbon fuels. On the scale of overall US emissions, almost everything else is noise. Of course that leaves plenty of room for discussion and disagreement on the most effective ways to address these emissions at the lowest cost and least disruption to an already-fragile economy. We can still argue endlessly about the relative merits of putting a price on emissions, providing incentives for emission-reducing technologies, and setting command-and-control regulations. Yet when we contrast the potential effectiveness of such a limited approach with the intricacy and distortions entailed in "comprehensive" efforts like the failed Waxman-Markey climate bill of 2009, it looks like a very helpful simplification to pursue.

Petroleum Prices Set Records in 2011

2012-01-10T12:25:00.002-05:00

Without much fanfare, the Energy Information Agency of the US Department of Energy released a report on 2011 energy commodity prices yesterday. It confirmed that crude oil and key petroleum products set annually averaged price records last year. This largely snuck up on us, because it occurred without the kind of dramatic price spike we experienced in 2008 or in the oil crises of the 1970s. Prices rose early in the year, during the Libyan revolution, and they didn't fall much, subsequently. The situation was also masked by the ongoing crude oil bottleneck in the US mid-continent, which depressed prices of the grade of US oil that for decades had been regarded as the best indicator of global oil prices, a role in which it has recently fallen short. These record prices for oil and its products are of more than just statistical interest; they help to explain the persistent weakness of the economy, representing an incremental drain of roughly $100 billion, compared to 2010, based on our net petroleum imports. That's roughly half the impact of the social security payroll tax holiday over which Congress and the administration have been sparring.

The EIA reported that UK Brent Crude, probably the best gauge of global oil prices at the moment, averaged over $111 per barrel last year. That's 40% higher than in 2010, and $14/bbl over 2008, the year in which West Texas Intermediate came very close to $150/bbl before ending the year at $45. Of even greater interest to most Americans, the pump price for unleaded regular gasoline in 2011 averaged $3.52 per gallon. Although in contrast to 2008 it only broke the $4 mark in a few regional markets like California, New England and Chicago, and even there only for a month or two, it beat the 2008 national average by more than $0.25/gal. through sheer persistence. And for the most part that didn't happen because the US is now a net exporter of gasoline and other petroleum products. It happened mainly because the global crude oil market was influenced more by the instability in North Africa and the Middle East than by worries about the US economy and the fate of the European Union and its currency, the Euro.

Of course all of the above prices are in nominal dollars, so I thought it was worth taking a quick look at real prices. After adjusting for consumer price inflation, that $3.52 mark for gasoline ties 2008's real-dollar all-time annual record, and it exceeds the average for the peak oil-crisis-year of 1981 by about 28 2011 cents. It's a little harder to gauge whether last year's Brent price set a record for crude oil in real dollars, but it seems likely. Either way, what's remarkable about these price levels is that they occurred despite weak economic growth in the developed world and slowing growth in key developing countries like China. That raises ample questions about what we should expect this year.

I've seen a wide range of estimates for where oil prices will settle out this year. The fundamentals of oil itself seem on the bearish side, with US production growing, thanks to unconventional plays like the Bakken and the Eagle Ford shale, and Libyan output gradually returning. Demand growth could also ease, especially if Europe falls into recession. Arrayed against those factors are a fairly cohesive OPEC, which benefits when oil prices are as high as possible without actually throttling the economy, and the standoff brewing between tougher Western sanctions on Iran and Iran's threats to close down the Strait of Hormuz, through which something like 40% of global oil exports flow. Election-year politics might have an influence, too, recalling the administration's willingness last year to release oil from the US Strategic Petroleum Reserve for reasons that were rather less than compelling at the time. All in all, when we've spent the last several years lurching from one crisis to the next, it's not hard to imagine another crisis just around the corner. Let's hope that 2012 surprises us with stability.

"Energy Reality"

2012-01-04T17:45:00.001-05:00

Earlier today I attended a luncheon and press conference rolling out the annual "State of American Energy" report from the American Petroleum Institute. API's President and CEO, Jack Gerard, also used the occasion to launch a new "Vote 4 Energy" campaign, which he described as a non-partisan effort intended to start a conversation about energy during a key election year. He also touched on a number of issues that are very familiar to readers of this blog, including the Keystone XL Pipeline decision, the need for greater access to US energy resources, along with energy security and jobs. A phrase that Mr. Gerard used in his remarks, and that recurred several times during the press conference, was "energy reality." This struck me as an apt encapsulation for the energy policies that should be addressed by President Obama and whomever his Republican challenger turns out to be, from the shrinking pool of candidates.

I was pleased to hear Mr. Gerard cite the need for a full range of energy solutions, with renewables, nuclear energy and energy efficiency prominently mentioned along with the expected references to oil and gas. That is precisely the energy reality we should be pursuing: tapping the hydrocarbon riches with which the US is endowed, in order to reduce our dependence on unstable foreign suppliers, even as we ramp up the wind, solar, biofuel and other renewable energy sources that must take over the energy burden in the long run, and with all of it used more efficiently than today. Yet energy reality should also take account of the tremendous disparities of scale that still exist between conventional energy and renewables, and that are likely to persist for some time. After a decade of rapid growth, wind power accounted for less than 3% of the electricity generated here last year, and solar for much, much less than that--with neither displacing any meaningful amount of imported oil, since less than 1% of our electricity is generated from oil.

Energy reality came up again in the context of a question about the EPA's Renewable Fuel Standard, which was recently finalized for 2012 to require the use of 8.65 million gallons of cellulosic biofuel--a reduction of 98% from the 500 million gallons previously specified for this year in the RFS enacted by the Congress in 2007. Biofuel from corn, soy and animal fat has expanded to contribute nearly 10% of the US gasoline supply and a smaller fraction of diesel fuel. However, a law requiring the use of advanced fuels that don't yet exist in commercial quantities--and may not for many years--and forcing refiners to purchase credits in place of these non-existent gallons is certainly out of touch with objective energy reality and ultimately constitutes another tax on consumers.

I would argue that the decision that the President now has less than 60 days to make on whether to allow the Keystone XL Pipeline to go ahead also hinges on his understanding of energy reality. He must choose between the urgent concerns of employment and energy security articulated repeatedly in Mr. Gerard's answers to numerous questions on the subject, and an objective assessment of the environmental impact it might cause. Stripping away the various red herrings that sprang up in the course of the debates and protests over the pipeline, the latter boils down to the incremental greenhouse gas emissions from the extra oil sands production that the pipeline would facilitate, compared to the emissions from the conventional crude we would otherwise have to import from the Middle East or elsewhere. I've seen some wild exaggerations about that, including the doozy I ran across over the holidays from former Vice President Gore, to the effect that a Toyota Prius running on fuel refined from oil sands crude would have emissions equivalent to a Hummer. (When you do the math, it actually works out to the equivalent of a Ford Fusion hybrid.) In fact, the incremental emissions at stake in the Keystone decision amount to around 0.3% of total 2009 US emissions. That's the basis of the trade-off Mr. Obama must make, and no matter which side he chooses he will infuriate those supporting the other side.

As the 2012 presidential election approaches, I expect to find many opportunities for comparing campaign rhetoric to this kind of energy reality barometer. Elections tend to focus on the differences between candidates, and I have little doubt that the differences on energy will be significant. However, when the dust settles on November 7th it will be high time to start work on a new bi-partisan consensus on energy policy that might actually survive the next change in administrations, unlike the disruptive pattern we've been in for the last five cycles or so. Not reality? Perhaps, but certainly worth aspiring to. Happy New Year!

2011 in Energy: The Year of...

2011-12-26T06:00:00.007-05:00

At the start of 2011, I thought the hallmark of the year's energy events and trends might involve regulation, with the White House seeking to implement measures that couldn't garner enough support in Congress to become laws. But for every major new regulation issued, such as last week's release of the new Mercury and Air Toxics Standards for power plants, others were delayed or deferred, including the EPA's effort to regulate greenhouse gases under the Clean Air Act and the agency's proposed ozone standard. Outside of the utilities and other industry groups directly affected by these rules, it seems likely that 2011 will instead be remembered for big, unpredictable events like the Fukushima nuclear accident and the Solyndra bankruptcy scandal, along with several major trends that reached critical mass this year. Anyone attempting to pick the energy story of the year is spoiled for choice.

In my search for a catchy title for this year's final posting, I toyed with "The Year of Solyndra", "The Year of Shale", "The Year of Fukushima", "The Year of Exports", and various other combinations of the energy buzzwords that percolated into our consciousness this year. In some ways, they'd all be apt choices. Here's a quick rundown on why they might merit that kind of recognition, with links to previous postings providing more details on each:

If 2011 is the year of Solyndra, it's not because of the possibility that the government's $535 million loan to the firm was the result of political influence (cue Major Renault), or even that the Department of Energy is unlikely to recover more than pennies on the dollar in the firm's bankruptcy. Instead, it's because Solyndra highlighted the much broader and deeper problems of a global solar industry that, despite continued demand growth that other industries would kill for, now faces overcapacity and the fallout from the winding down of unsustainable government support. Germany's Solar Millennium is just the latest victim of this trend. Along with BP's exit from the solar business after 40 years, it provides a further reminder that renewable energy firms must succeed not just as technology providers, but as businesses that can earn consistent profits and continue to attract investors.

Shale gas was hardly new to the scene in 2011; it has been expanding rapidly for several years and now accounts for up to a third of US natural gas production. However, the controversy surrounding drilling techniques like hydraulic fracturing that make its exploitation possible became much more widespread this year, while some scientists raised questions about its contribution to greenhouse gas emissions. Shale gas has the potential to transform nearly every aspect of our energy economy, and probably sooner than renewable energy sources could. That has some folks nervous, while others are eager for shale gas to displace coal from electricity generation, compete with oil in transportation, and revive the domestic petrochemical industry. I suspect we'll see all of those to some extent, provided we don't regulate shale out of the running.

The aftermath of Fukushima could prove equally transformational, though it remains to be seen whether the ultimate result is safer nuclear power or a global retreat from one of our largest sources of low-emission energy. All but 8 of Japan's 54 nuclear power plants are currently idle, and that nation must shortly decide whether it will eventually restart those units that weren't critically damaged, or shut down the rest and attempt to run its manufacturing-intense economy on a combination of renewables and much larger imports of fossil fuels. The German government's post-Fukushima decision to phase out nuclear energy entirely could provide an even quicker test of the same proposition.

Another major shift that has been in the news recently involves exports. Although the US has long exported coal and various petroleum products, we could shortly become a bigger, more consistent exporter of many fuels, including liquefied natural gas (LNG), gasoline and diesel. As the reaction in a CBS news segment last week demonstrated, the US public doesn't know quite what to make of this, yet. Becoming a major energy exporter while still importing a net 9 million barrels per day of crude oil is very different than the picture of isolated self-sufficiency that four decades of "energy independence"rhetoric has evoked. We shouldn't be surprised that energy can provide a boost, and not just a drain on our trade balance. This topic requires more public discussion and education, before we see serious proposals to ban such exports--proposals that would make no more sense than banning exports of corn, tractors, or aircraft in an attempt to keep their US prices low.

It's also tempting to call this the Year of Oil Price Confusion. The news media gradually woke up to the huge gap that had developed between global oil prices and the oil price that Americans tend to watch most closely, the one for West Texas Intermediate crude. Yet despite numerous stories on the storage and pipeline crunch and supply glut at Cushing, Oklahoma, few reporters and networks seemed able to follow through by breaking their old habit of treating the NYMEX WTI price and its gyrations as if it were still the best indicator of the overall oil market. Fortunately, the problem is in the process of being resolved, as pipelines are reversed and more tankage built.

Finally, there was the administration's non-decision on the Keystone XL pipeline. Observers can read much into this, including the growing influence of citizen activists mobilized via social media. However, if it does nothing else, the Keystone controversy should put to rest the superficial fallacy that anything that improves greenhouse gas emissions is automatically good for energy security, instead of requiring difficult trade-offs. In that context, the prospect that the administration might ultimately turn down the permit for Keystone would be easier to stomach if the net greenhouse gas savings involved amounted to more than a paltry 0.3% of annual US emissions, based on the emissions from incremental oil sands production the pipeline might facilitate, compared to those from the conventional imported oil it would displace.

It was a busy year for energy, and if my short list of top stories missed something crucial, please let me know. 2012 promises to be just as interesting, with a Presidential election, in which energy issues could feature prominently, added to the mix. In the meantime, I'd like to wish my readers in the UK and Commonwealth a happy Boxing Day, and to all a Happy New Year.

Do Lighting Standard Delays Threaten Consumer Choice?

2011-12-20T15:41:00.002-05:00

In just under two weeks, standard 100 Watt incandescent light bulbs will be officially banned in the US, in the first step of a gradual phaseout of Edison's technology. However, as a result of recent Congressional action, enforcement of this regulation has been delayed by about a year, leaving the bulbs and the retailers who sell them in a temporary limbo. This change adds to the confusion consumers now face when purchasing lighting products, as our choices have multiplied to include compact fluorescent lights (CFL), LEDs, halogen incandescents, and shortly another new option, the "electron stimulated luminescence" (ESL) bulbs produced by VU1 Corporation. The lighting efficiency standard of the Energy Independence and Security Act of 2007 helped to create this diversity, although it remains to be seen to what extent the desired improvement in household energy consumption will actually appear, and whether it will be accompanied by unintended consequences such as a black market in outlawed light bulbs.

When considered carefully, the lighting efficiency standard contains a paradox: It has had the effect of multiplying consumer choice, but by means of a mechanism that will actually limit choice, once it is fully implemented. Nor is this just a US concern. One reason we're seeing so many new lighting technologies on store shelves is that incandescent lights are being phased out in much of the developed world. As shown in Exhibit 17 of a recent report by McKinsey & Company, the phaseout of incandescent lighting is even farther along in the EU and Japan, with Russia and Brazil also winding down sales of these lights. The new lighting options that these measures helped stimulate didn't appear out of thin air; they occurred as a result of significant investments in technology and manufacturing by various companies, all of which are looking for a return on those investments that could be jeopardized by delaying the implementation of the standard.

The ESL bulb is a case in point. The market for it might not exist without the congressionally mandated lighting standard. I learned about VU1's technology through a press release and was immediately intrigued, because the company seems to have circumvented some of the biggest drawbacks of the CFL bulbs that have become the de facto alternative to incandescents in the last few years. ESL lights work like miniature cathode-ray TV tubes--the kind we had before flat-screen TVs became popular--and they apparently contain no mercury. That makes them inherently much safer than CFLs, particularly in households with children or pets. (Anyone unconvinced of the mercury hazard of CFL bulbs should visit the EPA web page providing instructions for how to remediate a broken one.) At an expected price point just under $15 for a 65W-equivalent R30 bulb at Lowe's hardware stores this winter, they should at least be competitive with CFLs.

In addition, the manufacturer claims that ESLs are not susceptible to overheating. That's a valuable feature, because heat buildup in recessed and other fixtures has shortened the life of several of the CFL bulbs I've bought, particularly in "can" fixtures. Without multiple years of additional service, compared to conventional light bulbs, the already situationally dependent economics and environmental benefits of expensive alternative bulbs turn sharply negative.

Economics are a key factor for all these new light bulbs. That even includes the halogen bulbs that are the nearest substitute for conventional incandescents, in both lighting quality and cost. Like many other energy efficiency technologies, advanced light bulbs trade higher initial costs--in some cases dramatically higher--for reduced operating expenses in the form of electricity savings and less frequent replacement. If you can afford to pay cash for them and your opportunity cost is a bank savings account yielding 1% or less, they're generally a good deal, paying for themselves within several years--or even quicker if you live in a region with high electricity rates. However, if your rates are near or below the national residential average of $0.12 per kilowatt-hour, or if you install them in fixtures that aren't used for at least a few hours each day, the payout will take longer. And if you purchase them on a credit card that you don't pay off in full every month, the advantage compared to conventional bulbs can disappear after tallying finance charges.

I plan to try out the ESL lights once they're readily available, but I also believe Congress was right to impose a delay in enforcing the lighting standard, although I would have preferred a less ambiguous method for achieving that. Mandates like the lighting standard, the federal Renewable Fuels Standard and the state Renewable Portfolio Standards for electricity are effectively taxes. In this case, the tax isn't paid to the government or utilities but to retailers and manufacturers. And while such mandates can be effective at achieving environmental targets, they also tend to be regressive, affecting lower-income consumers disproportionately. With a bi-partisan consensus on the undesirability of raising taxes on the middle class in the current, flat economy, the lighting standard delay arguably falls into the same category. The losers from this step will be companies that made investments on the assumption the standard would go into effect as planned. Let's hope their planning included some contingencies for regulatory risk, or some of our new lighting choices might be jeopardized, even as existing choices are preserved.

The Brazil Spill

2011-12-15T11:28:00.004-05:00

Late yesterday I saw a headline reporting that Chevron was being assessed more than $10 billion for a spill from its drilling activities offshore Brazil last month. The story was later revised to clarify that the amount in question was associated with a civil lawsuit being filed by a Brazilian prosecutor, rather than an actual fine by the government petroleum or environmental agencies. Either way, the sum involved goes beyond surprising. Given the quantity of oil that actually leaked from an appraisal well at Chevron's Frade platform, it is grossly disproportionate to any objective gauge of the scale of the spill and the effectiveness of the response, which stopped the leak within a few days and reduced the surface oil slick to around one barrel within a couple of weeks, without any oil reaching shore. For a nation that aspires to sit at the top table globally, including a permanent seat on the UN Security Council, the reaction to this event raises questions about due process and rule of law. It could also backfire badly, in light of the substantial foreign investment Brazil is seeking in order to develop the enormous "pre-salt" oil deposits off its coastline.

My purpose in writing about this incident isn't to defend Chevron. I don't have enough of the details of what happened, and my well-known conflict of interest as a former employee and Chevron shareholder would undermine my credibility on that front in any case. From my perspective the noteworthy aspects of this spill are its magnitude and the Brazilian government's hasty and exaggerated reaction to it. In terms of its energy implications, it almost doesn't matter what company was involved, except that it's highly unlikely that a similar spill by Petrobras, the partially-privatized national oil company of Brazil, would have elicited the same response.

Start with the magnitude of the leak. No oil spill is a good spill, but the estimated 2,600 barrels that leaked into open waters about 120 miles offshore was at least two orders of magnitude (100 times) smaller than the kind of worst-case tanker spill that oil companies routinely plan and train to be able to handle. Suggestions by the Brazilian government that a global oil company and its drilling contractor, Transocean, weren't prepared to handle a spill of less than 3,000 barrels--more than one year after the Deepwater Horizon accident--belong in the realm of politics, rather than serious analysis.

In fact, any comparisons to the disaster that killed eleven men and leaked 4.9 million barrels of oil into the Gulf of Mexico over 89 days, fouling beaches and harming birds and marine life in four states must pale. The total cost to BP and its partners in the Macondo well isn't yet known, but between the $20 billion escrow fund for Gulf Coast cleanup and claims, along with the federal fines they face, the bill could come to $40 billion, or 4 times what a Brazilian prosecutor is apparently seeking for a spill roughly 2000 times smaller, that never threatened Brazil's coastline. The Frade leak is also modest in comparison to spills from tankers and other ocean-going vessels. Comparable or larger spills averaged more than 3 per year in the last decade, according to the International Tanker Owners Pollution Federation.

Another interesting feature of the spill is that it didn't result from an uncontrolled well blowout, as BP's did, but from subsea oil seeps that developed during the process of drilling into the complex geology of Brazil's technically challenging pre-salt oil deposits. Although these particular seeps were apparently directly related to the well Chevron was drilling, similar seeps are a common feature of many oil-rich offshore regions. NASA has estimated that the Gulf of Mexico experiences similar, naturally occurring seeps on the order of 500,000 barrels per year.

So if the Frade spill was relatively small and contained in short order, why should anyone other than Chevron's management and shareholders care if Brazil slaps them with large fines or a multi-billion-dollar lawsuit, in an apparent attempt to make an example of them and enforce what amounts to a zero-tolerance policy toward oil spills from its offshore projects? I'd argue that we all have something at stake here, indirectly. Brazil's pre-salt reserves offshore represent some of the largest recent oil discoveries and are expected to contribute 2 million barrels per day or more to global oil supplies by 2020. With output in Latin America's two other largest producers, Venezuela and Mexico, falling due to mismanagement of their otherwise ample resources, Brazil's output could be a key factor in oil prices in this decade and beyond.

Brazil is poised to become a major oil exporter, but Petrobras can't take on the scale and risk of this opportunity on their own, without foreign partners. It's not that they lack the technology; Petrobras is a leader in deepwater development. However, if they have to go it alone because the government's response to this event scares off its potential partners, they will be forced to reduce the size of their program, and oil prices will end up higher than they would have otherwise. While I'm entirely sympathetic to the sentiment behind a "zero-tolerance" attitude towards oil spills, whether from oil platforms, tankers or pipelines, I'm afraid it belongs in the same category as a zero-tolerance toward plane crashes: a standard to aspire to, but not one on which national development policies with global consequences can realistically be based.

The Durban Climate Deal Inkblot Test

2011-12-12T12:48:00.001-05:00

After going into sudden-death overtime, the UN climate conference in Durban, South Africa wrapped up this weekend with an agreement that only a climate diplomat could love. Constituting in effect an agreement to agree to some future agreement, the outcome is open to interpretation. Is this the failure that was widely predicted, the breakthrough indicated by some involved, or just a fig leaf to perpetuate a seemingly endless series of climate conferences in the only manner possible, by avoiding a breakdown that might have ended the entire effort for good? From what I have read in the last day, it's probably a bit of all three. The reactions from environmental groups have certainly been a mixed bag.

Briefly, it appears that the participants agreed to begin negotiating toward a new global climate "protocol, another legal instrument or a legal outcome"--the key compromise wording that saved the day--to be adopted by 2015 and take effect by 2020. In the meantime, the Kyoto Protocol, which was due to expire at the end of next year, will be extended through 2017, even though three of the largest emitting countries, Canada, Japan and Russia, will apparently not take on binding commitments on emissions for that period, nor will the US, which never ratified Kyoto. Still, this should be sufficient to keep international emissions trading and the Clean Development Mechanism for capitalizing on projects to reduce emissions in developing countries, going in the interim. While the delegates had the good grace not to call this result another roadmap--two years after the deadline of the Bali roadmap--that's pretty much what the "Durban Platform for Enhanced Action" amounts to.

Even in a global fiscal and economic environment that made any outcome more ambitious than this a virtual non-starter, the Durban Platform doesn't inspire confidence in the UN climate process. The most notable aspect of the agreement is that for the first time emitters from both the developed and developing world have signed up to a process under which they would all be asked to take on more or less legally binding commitments to reduce emissions. As the Economist notes, this "promises to break a divisive and anachronistic distinction", and one that makes little sense when developing countries now account for more than half of global greenhouse gas emissions. US climate envoy Todd Stern was quoted as saying that the US had been seeking this kind of "symmetry...since the beginning of the Obama administration." In fact, that has been the consistent goal of US climate policy since the Clinton administration. The problem is that this all remains contingent on the details of a future negotiation and subject to ratification by future governments, many of which will change between now and the COP-21 in late 2015.

Ever since the debacle in Copenhagen two years ago, the UN climate process has looked like a weak reed. Whatever the optimum size of a committee might be, it is not one made up of 194 countries, particularly when the top 20 accounted for nearly 80% of global CO2 emissions in 2009. Even if you don't share my conclusion, reinforced by the aftermath of the recession and financial crisis, that international agreements are unlikely to result in enough emissions reductions to materially alter the trajectory of global warming, it ought to be abundantly clear that if climate change is as big a problem as the folks meeting in Durban believed, then we had better have a Plan B in mind. For some that means a much stronger focus on innovation, while for others, including myself, it also suggests we should get a lot more serious about both adaptation to climate change and the exploration of geoengineering options. Or perhaps the horse will learn to sing, after all.

The Battle to Extend Wind Incentives

2011-12-09T10:30:00.003-05:00

With the end of the year approaching, the annual Congressional debate over extending a variety of expiring federal tax credits and other benefits is gearing up again. Few of these measures are as high-profile as the payroll tax cut, but each has a vocal constituency, including renewable energy. The American Wind Energy Association (AWEA) has launched a major effort seeking inclusion of the Production Tax Credit (PTC) for wind power in this year's "tax extenders" package. That might seem premature, since the PTC won't expire until the end of 2012, until you realize that eligibility for the stimulus-funded Treasury renewable energy grants for which many wind project developers have opted over the PTC ends in a few weeks with little chance of a further extension. However, before simply tacking another year (or four!) onto a tax credit that began nearly 20 years ago, Congress should answer two basic questions: Is this still the most effective way to promote renewables like wind, and does wind power now require subsidies at all?

I don't blame AWEA for tackling this issue early, since the US wind industry has experienced significant volatility when previous PTC expirations went down to the wire, and in several cases lapsed for up to a year. At the same time, taxpayers deserve a more compelling rationale for continuing to subsidize wind power than the one now being offered. The "green jobs" argument is wearing thin, post-Solyndra, and it has become increasingly evident that helping to create a market for renewable energy technologies is a necessary but not sufficient condition to establishing a sustainable, globally competitive renewable energy manufacturing industry. Although more of the wind power value chain is now produced in the US than previously, too much of each wind subsidy dollar still goes offshore for this to be deemed an efficient way to boost to US jobs and manufacturing without reform.

In order to address the first question I posed, concerning the continued suitability of the PTC, it's important to understand how it works and how it compares to other renewable energy incentives. The current PTC provides wind project owners (or the parties to whom the tax benefit has been sold via a "tax equity swap") with an income tax credit of 2.2 cents per kilowatt-hour (kWh) of electricity actually generated and sold from the completed facility. Based on recent estimates of the levelized cost of electricity from unsubsidized wind power, that's over 20% of a typical wind farm's production cost. It's also equivalent to more than half of this year's average wellhead price of natural gas--a far larger subsidy per BTU than the controversial tax benefits currently provided to oil & gas firms.

The best thing about the PTC is that it is entirely outcome-based. You only receive the benefit when your project is completed, brought online, and as power is sold to customers. Mess up any of those steps and you get zilch. Put your project in a location with poor wind resource or limited access to transmission, and you won't get nearly as much tax benefit. So from that standpoint--ignoring the green jobs angle that arose mainly from expediency when the financial crisis and recession hit--we are getting what we pay for: actual low-emission energy. The structure of the PTC has cash-flow implications that are viewed as a problem by many wind developers but might be regarded as a useful feature by taxpayers. Smaller developers, in particular, have greater difficulty financing projects when the incentive must be deferred until after start-up, or they may lack sufficient taxable income to take full advantage of the credit. They complain about the need to transact swaps with bankers and other investors to realize the subsidy sooner, at a cost. But perhaps it's not such a bad thing for companies that small to have to convince an experienced third party that their project is really viable.

There are many alternatives to the PTC, including the 30% Investment Tax Credit (ITC), the same one received by solar and other technologies. The stimulus bill extended the ITC as an option for wind and allowed the Treasury Department to pay it as a cash grant, rather than waiting for subsequent tax filings. This certainly put money in the hands of wind developers much quicker--$7.6 billion since 2009 including $3.3 billion so far this year--and it has the added benefit of automatically scaling down as the cost of the technology falls. The solar feed-in tariffs favored in Europe didn't have such a feature, with the result that countries have had to cut them numerous times, but only after the fat tariffs gave birth to a huge export-oriented solar manufacturing industry in Asia. Similar competition is now emerging in the wind industry.

The main problem with the ITC is that when viewed from an outcomes perspective, which really gets to the question of effectiveness, the outcome being promoted is construction, rather than energy production. You would get the same tax credit for a project with the best wind resource as for one with the worst. (This has also led to a lot of solar installations in places that would never otherwise have been considered.) So of the two main policy tools the federal government has used to subsidize renewable electricity, the PTC is probably more cost-effective in delivering the result we should really want, which is more renewable energy. As it is, even with rapid growth over the last decade, wind accounted for just 2.8% of our power generation this year through August.

That brings us to the bigger question of whether wind should be subsidized at all after the current PTC term expires. I get emails practically every day from folks who have serious concerns about the health and environmental impacts of power, as well as its cost- and emissions-reduction effectiveness. Even if we ascribed all of these concerns to NIMBYism, it doesn't change the fact that the wind PTC, complete with annual inflation adjustment, is providing the same level of incentive as it did when the technology was much less mature and cost many times what it does today; AWEA cites wind costs having fallen by 90% since 1980. Other factors have also changed in the last twenty years. A majority of US states--and most of those with attractive wind resources--now have in place Renewable Portfolio Standards requiring utilities to include increasing proportions of renewable power in their supply. These mandates create a similar redundancy as the one between the ethanol blenders credit, which is also due to expire 12/31/11, and the biofuel mandates of the federal Renewable Fuels Standard. In the absence of the PTC, the state RPS system should provide a safety net--and more--for the industry.

There are two other key factors missing from AWEA's arguments for extending the PTC. The first is the economy, which is the main reason that US electricity demand has not been growing at a rate that would support large generating capacity expansions of any kind. New wind installations have been anemic for the last two years, in spite of last year's extension of the Treasury grants. Moreover, wind must now compete with the explosion of domestic natural gas production from shale, which when used in combined cycle gas turbines produces cheaper electricity than wind, with low emissions of the air pollutants that are of the greatest concern to most Americans, while still beating coal-fired power hands down on greenhouse gases.

Where all this leaves us depends on your priorities. If your main focus is on reducing greenhouse gas emissions and you see renewable power as a key strategy, then in the absence of a price on carbon you might support extending the PTC for at least a little longer. If you are concerned about climate change but more worried in the short term about the deficit, then letting the PTC lapse next year and relying on state RPS quotas to put a floor under wind looks reasonable. If boosting US cleantech manufacturing is your aim, you should prefer a more direct incentive than the PTC. And if your main worry is oil imports, then the PTC is irrelevant, since the US gets less than 1% of its electricity from burning oil, and most of that in remote and back-up power roles that wind can't easily fill. On balance, if after considering all the alternatives the Congress decides to extend the Production Tax Credit, it should be for an explicitly final period, at no more than the 1.1 cent/kWh rate that technologies like marine, hydropower and waste-to-energy now receive, and without the annual inflation adjustment that undermines the incentive to continue reducing costs.

Net Exports and Gasoline Prices

2011-12-06T10:07:00.004-05:00

US petroleum product exports have been in the news, along with the welcome discovery that we are apparently on track to become a net exporter of these fuels this year, for the first time since the 1940s. This is a far cry from energy independence, as various oil skeptics have been quick to point out, but it's still a noteworthy inflection point in energy trends. However, I've also seen stories suggesting that US consumers will pay a lot more at the pump as a result of this change, to which the most succinct response so far is "rubbish." Being a net exporter hasn't suddenly connected US fuel prices to the world market, as if they had somehow been insulated from it until now. In fact, we've been exporting products for many years--as I know from personal experience--but for most of that time we just happened to be importing more. The net effect of our new status on prices here will be minimal, while the main impact will be a positive nudge to our trade deficit.

I am sympathetic to the present urge to see a cloud in every silver lining; we seem to be going through one of those phases in our history. At the same time we should understand that to the extent net petroleum product exports aren't entirely good news, it's because the main driver of this departure from a long trend of steadily increasing net imports was the sudden slowdown of consumer activity that accompanied the recession and financial crisis, from which we are still recovering. And while I agree that more efficient cars have contributed, recent fuel economy improvements have been too incremental to our fleet of 240 million light-duty vehicles (passenger cars, SUVs and light trucks) to have made such a big dent in demand, quite so soon. Mainly, we're driving less, as the statistics on vehicle miles traveled indicate. That might be better news if it reflected a massive lifestyle change, instead of the grim reality of millions of un- and under-employed Americans for whom driving has become a luxury.

Even in that negative context, the fact that we are now exporting more gasoline and other petroleum products than we import is a plus, since without buoyant non-US demand, US refiners might have been forced to reduce operations by more than they have, or to idle more facilities and lay off staff. Today's net exports imply a positive margin between crude oil imports and product exports sufficient to cover refiners' costs, even after netting out freight. That results in more economic activity and value added here, driven by overseas demand, following the same export-led strategy that other industries are pursuing in order to compensate for lower US demand for their output.

More exports and fewer imports mean a smaller trade deficit, but the question on some people's minds is apparently whether this is being accomplished at the expense of US consumers. That might have been the case if, for example, exports had been banned until recently and refiners forced to create an artificial glut of petroleum products to drive down prices. (That's effectively the case in some other countries.) Instead, the US has long been part of a global market for both crude oil and refined products, and refiners and traders have always been alert for gaps between regional markets that could be profitably exploited. When I traded refined products for Texaco's west coast refineries in the 1980s, we occasionally took advantage of export opportunities, even though we were more often importers. When I traded products in London, my team routinely sold cargoes of gasoline, diesel or jet fuel from the US into Europe and Asia, and we did the reverse when the "arbitrage" worked in the other direction. We accounted for just a small portion of the trade in cargoes passing back and forth between continents, which continues today.

As a result of this global market in refined petroleum products, US consumers of gasoline and other fuels have always been competing with consumers in other countries, whether we realized it or not, especially in parts of the country where refiners have easy access to export markets. That's been true since the days when my former employer's advertising touted its success in "lighting the (kerosene) lamps of China". In terms of the impact on domestic prices, it doesn't matter much whether we're net exporters or net importers, as long as we're connected to the global market--a linkage that has saved our bacon on many occasions when US refineries were hit by hurricanes, blackouts, or other disasters.

A more tangible way to test the consequences of product exports involves comparing past and present crude oil and gasoline prices. Making that comparison accurately is complicated by the breakdown of the main US oil market indicator, the price of West Texas Intermediate crude, which for more than a year has been burdened by excessive inventory at Cushing, OK and other factors. For now the price of Louisiana Light Sweet (LLS) is a better gauge of the oil market. LLS has been relatively unaffected by WTI's problems and trended much closer to global oil prices, such as UK Brent crude. It turns out that 104% of the higher retail price of gasoline this November vs. a year ago is explained by the $23 per barrel increase in LLS since then. In other words, crude prices have increased by slightly more than gasoline, suggesting that raw material costs still have a much larger impact on prices at the pump than does the recent shift in US petroleum product trade patterns.

Although the evidence that product exports don't hurt consumers is strong, I don't expect it to dispel this handy new rationale for complaining about gas prices. After all, the price of gasoline is one of the most visible and volatile prices we're exposed to, and for which we have few practical alternatives. Having a narrative to explain these spikes and dips is empowering, even if it's wrong. However, in the midst of all the grumbling it's worth spending a moment thinking about the benefits of having an oil refining industry that has been able to find alternative outlets for its products while it waits for the US economy to recover, instead of yet another manufacturing industry on the ropes, shedding jobs and moving offshore.

Why Does Gazprom Oppose Shale Gas?

2011-12-01T15:18:00.003-05:00

I see that Russia's national gas company, Gazprom, is warning Europeans about the environmental risks of shale gas development. Aside from the hypocrisy stemming from a Russian legacy of environmental disregard that rivals the worst excesses committed anywhere, along with the likelihood of Gazprom profiting if it can deter competition from proliferating shale drilling technologies like hydraulic fracturing (a.k.a "fracking") and horizontal drilling, this looks quite clever. Environmental concerns--exaggerated or not--are the Achilles heel of shale drilling. We've seen how how effective environmental opposition to fracking has been in places like New York state. The mere fact of Gazprom's warning about shale drilling doesn't constitute a winning argument either for or against the practice, but the reasons they would be moved to comment might shed further light on shale's potential, which they publicly dismiss as a temporary phenomenon.

If Russia's leaders have anything to fear from the development of shale gas in Europe, much of the blame rests with their own behavior. Gazprom alone has access to the largest conventional natural gas reserves on earth--more than the entire natural gas reserves of Iran--and it has built the pipelines necessary to make Russia the dominant gas supplier to Europe. The latest addition to that network, the Nordstream pipeline--a source of some controversy of its own a few years back--opened just last month. They are also almost certainly correct that European shale gas would be more expensive than Russian gas, at least initially, if you ignore its value in providing Europe with some much-needed leverage with a supplier that hasn't hesitated to play hardball in the past, to the point of cutting off gas shipments during contractual disputes--in winter.

Since Gazprom's credibility on the economic and commercial merits of shale gas development is effectively nil, it makes perfect sense that they would pick up on the environmental arguments that have slowed development elsewhere and in some cases brought it to a standstill. The effectiveness of these arguments is enhanced because they contain a grain of truth: Like all other industrial-scale activities, shale gas drilling is not risk-free. It is possible for a drilling contractor to fail to cement a well properly, creating a chance of contaminating nearby water wells, although some presumed instances of this turned out to have other causes. It's also possible for a driller to mishandle fracking fluid or produced water above ground and affect surface water supplies. Then there are the allegations that leaking methane from shale gas wells negates any emissions benefits and renders the gas at least as bad as coal for climate change--never mind that these claims have been comprehensively examined and disproved.

Although I expect debate on these points to continue for some time, I believe that ultimately shale gas drilling will proceed on a large scale in the US and globally, with some minor tweaks to a regulatory system that already does a pretty good job of monitoring the activity and weeding out those producers that aren't diligent enough about protecting the public and environment. I would also argue that this scenario must be exactly what Gazprom's management believes will happen in Europe, absent a lot more support for those who oppose shale gas for a variety of reasons, including its competition with the more expensive forms of renewable energy. That doesn't automatically make European opponents of shale drilling convenient tools for the resource nationalism of an increasingly authoritarian neighbor, but it certainly ought to make them exercise great caution before entering into any "strange bedfellows" alliances with as self-interested a party as Russia's state energy complex.

Message to Durban: It's The Economy

2011-11-29T13:55:00.002-05:00

What if they held a UN climate conference and no one came? That's certainly not the case at this year's COP-17 (Conference of the Parties) meeting now underway in Durban, South Africa, but with expectations for dramatic progress low, and a breakthrough on the scale needed to salvage the expiring Kyoto Protocol nearly unimaginable, it could be where the UN-led process is headed. If Durban fails to deliver the goods, it won't be because the participants were any less concerned about climate change than those at past sessions. Nor will it be because of the latest release of Climategate emails, as embarrassing as some of them should be for the scientists involved. The reason is much simpler, and it's the same one that helped Bill Clinton unseat George H.W. Bush in 1992: "It's the economy, stupid." The solution to climate change is unlikely to be found in Durban or any future COP site until the leaders in Brussels, Washington and other capitals come to grips with the massive economic challenges they face and create the framework for a return to robust growth.

That observation might seem paradoxical, given the linkage between economic growth and the growth of greenhouse gas (GHG) emissions. One climate change expert at Shell recently questioned whether it's even possible to reduce these emissions, because the expansion of low-emission energy sources is merely displacing fossil fuels into other markets where the appetite for them remains insatiable. We've also seen the rebound in emissions that occurred once the US economy began to recover from the worst effects of the financial crisis and recession that began in 2008, and a new report from the International Energy Agency projects a similar result globally. Yet it's also the case that prosperity and concern for the environment go hand in hand, along with the capacity to afford the costs and penalties that a massive global reduction in GHGs would entail. It's no coincidence that the UN climate process and parallel US efforts lost most of their previous momentum during the Great Recession.

Although the "road map" that came out of 2007's Bali climate conference was ambitious, its timetable for developing a new set of binding emission-reduction commitments to dovetail with the end of the 2008-12 "first measurement period" of Kyoto looked achievable, allowing for some slippage. Just two years later, the delegates to Copenhagen were lucky to come away with a last-minute set of voluntary, non-binding commitments that, even if they were all implemented, would barely shift the trajectory of rising emissions. Nor did last year's meeting in Cancun restore the Bali road map.

At this point, even the less ambitious proposals on the agenda in Durban ultimately depend on developed countries that are grappling with high unemployment, crippling deficits and debt, and political turmoil underwriting large investments in the developing world. The present structure of the European Union--the primary supporter of action on climate change--is itself in jeopardy, and European economies are facing an oil price shock arguably as large as that of 2008. It's questionable that the EU can even pay for its own future emissions reductions, let alone subsidizing reductions and climate adaptation in the developing world. Meanwhile, support for Kyoto among other large emitting countries is flagging, and the US appears little closer to taking on binding emissions commitments than it was in 1997.

I don't dismiss the possibility that the Durban talks may accomplish more than just punting the ball to next year's session in Qatar. However, if they don't, then the folks that are footing the bills for this seemingly endless succession of sprawling confabs--wonderful for local chambers of commerce and tourism, but practically meaningless for tackling global emissions--should consider calling a hiatus pending the resolution of the global economic problems that will undermine any agreement they could reach in the interim. There might even be a scientific justification for that, in the form of a new, peer-reviewed paper in Science suggesting that the global climate's sensitivity to increasing concentrations of CO2 might not be as strong as previously thought. If Schmittner, et al, are correct, then we might have a bit more time before extreme climate change becomes imminent. Let's hope so, because it looks a lot more fruitful to reboot this whole effort once the global economy is back on an even keel.

Our Shifting Energy Diet

2011-11-22T16:05:00.002-05:00

It's fairly easy to agree on the desirability of shifting our energy diet away from fossil fuels and toward more renewable or sustainable sources, but it's much harder to agree on the time scale involved. While recognizing the great potential of renewable energy technologies such as wind, solar and geothermal power, along with advanced, non-food-based biofuels, I am convinced that the transition will take much longer than many hope--longer than many will have patience for, in light of pressing concerns about energy security and the environment. When considering future shifts in our energy diet, it's instructive to review some of the changes we've already experienced, and how long they took. The graph below displays the relative contribution of America's main energy sources since 1949, based on data from the Energy Information Agency of the US Department of Energy.

This chart, which compares the proportional, rather than absolute contribution of each source as a percent of the total, shows that the US energy diet has experienced constant change over the last seven decades. Some of these changes have been dramatic, such as the erosion of coal's market share in the 1950s and '60s by oil and natural gas, while others, such as the resurgence of biomass-based energy since the 1970s are less dramatic but still noticeable. On the scale of this graph the non-biomass renewables that I've lumped together appear relatively steady, because the recent rapid growth of wind and solar energy has so far only compensated for a contemporaneous decline in hydropower output. I'd expect the growth of that green segment to be more obvious in a few years, though still not on the scale of nuclear power.

The chart also reminds us that however prominent a given energy source might have become during this period, none overwhelmed the others. We talk a great deal about oil's dominance, yet it never exceeded a 48% share of our energy diet, and it has recently fallen below 37%. In fact, you'd have to go all the way back to the 1920s to find an energy source with a market share above 60%, which coal still enjoyed during the early years of oil's rise as the combination of mass-produced cars and the big oil finds in East Texas and Oklahoma upended the US energy landscape. That's one reason I generally find forecasts of renewables capturing 80% of the energy market within a few decades to be improbable.

Perhaps the most relevant example for renewables of a disruptive energy technology capturing a significant share of the market is commercial nuclear power, which contributed just 0.1% of US energy in 1962. That's about what solar provides today. Yet even with a major push by utilities and government and broadly favorable market acceptance until after the Three Mile Island accident, it still took nuclear power 25 years to reach a 6% share of total US primary energy, and nearly 40 years to reach its current 8% or so. Today's renewables also face similar limits on their potential market penetration, albeit due to very different factors relating to intermittency and the high cost of energy storage.

What would it take for renewables to repeat the model of oil's success against coal? In the absence of a high carbon price or incentives on a level unlikely to be either politically feasible or affordable in the current environment, I believe it would require technologies that don't just reduce greenhouse gas emissions or local pollutants, but actually enable something new and very attractive to consumers and businesses, along the lines of the quantum leaps in mobility and other economic activity that oil made possible. Otherwise, their promoters should be prepared to play a long game, in much the same way that the conventional energy industry did when it was building its market post World War II. Do investors and policy makers have the patience that requires?

By the way The Energy Collective is offering a free virtual conference on November 30 on the subject of "How to Save A Planet on A Budget." The conference includes panel discussions and case studies moderated by Marc Gunther of Fortune magazine, Jesse Jenkins of the Breakthrough Institute, and Gernot Wagner, economist at the Environmental Defense Fund. To register click here.

I'd also like to wish my US readers a pleasant Thanksgiving weekend.

Is the Photovoltaic Price Trend Sustainable?

2011-11-17T10:09:00.004-05:00

It has been widely assumed among pundits and policy makers that the continued expansion of solar photovoltaic (PV) installations will drive down PV costs until the electricity they produce is competitive with conventional power sources without the need for subsidies. This belief is grounded in both recent PV cost trends and the well-known "experience curve" effect in manufacturing, in which costs tend to fall in proportion to cumulative output. However, anyone following the fortunes of big PV manufacturers like First Solar, SunPower, and China-based Suntech and Trina Solar might have reason to question this conventional wisdom. Their latest earnings reflect an industry stressed by softening demand in its core market in Europe and facing global overcapacity along the supply chain. This has me wondering how much of the recent decline in PV prices was due to the inherent progression of the technology, and how much to unsustainable market and competitive pressures.

The solar industry has made tremendous progress in the last several years. One indication of that is the price trend for PV in the annual "Tracking the Sun" survey from Lawrence Berkeley Lab. Between 2007 and 2010 the average cost of PV installed in the US fell by around 22%, with the largest portion of that drop occurring last year, followed by a further 11% decline in the first half of this year. Most of the reduction is attributable to the falling price of solar modules, rather than from the non-module, or "balance of system" costs (inverters, structures, installation, etc.) The fact that these declines coincided with an explosion of global PV capacity and output seems entirely consistent with expectations about the likely path of PV costs. Cumulative global PV capacity doubled twice in that interval, based on figures in the newly released Renewables 2011 Global Status report from REN21, so we'd expect to see strong experience-curve cost reductions.

The problem is that the industry dynamic behind this trend didn't much resemble the pristine image that the term "experience curve" evokes, of diligent engineers relentlessly focused on continuous improvement. Without diminishing the contribution of a lot of smart people, a key driver was the tough competition for market share between silicon-based PV, which had to overcome a major bottleneck in the supply of its primary raw material, polysilicon--the price for which spiked and subsequently collapsed--and cheaper but less efficient thin-film PV technologies relying on entirely different chemistries such as cadmium telluride and copper, indium, gallium and selenium.

A further hint that this wasn't quite the standard picture of predictable cost declines promoted by the PV industry is that PV prices appear to have been falling faster than actual costs, which in the case of at least some manufacturers are no longer dropping much at all. This can be inferred from the compression of gross margins reported by the leading firms, and in results that show profits stalling or falling even as volume grows. SunPower, the largest US silicon-based PV maker, reported a net loss for the third quarter of 2011, following a loss in Q2, and issued guidance forecasting a loss in 4Q, as well. We'll get a better picture of the health of the big China-based producers when they report 3Q earnings next week, but in the second quarter Suntech, the world's largest solar panel maker, reported a substantial loss, even though sales were up by a third from a year earlier, similar to results at rival JA Solar. In response Suntech and other Asian producers have apparently slowed planned expansions and reduced throughput at existing facilities, while US PV leader First Solar postponed its new factory in Vietnam.

It's a testament to the ingenuity of the big, established PV producers that they haven't all shared the fate of Solyndra after investing so much in expanding capacity ahead of demand--a major accomplishment in itself when demand has been growing by roughly 80% per year--only to see the market weaken due to a prolonged economic slump and a financial crisis in Europe that has undermined the ability of governments to provide generous subsidies for PV installations. Assumptions about the future cost trend of PV won't mean much if the industry doesn't emerge from its current difficulties as a collection of healthy firms with solid balance sheets and financial performance that investors find attractive. That will require better margins achieved by some combination of improved pricing power--implying better matching of capacity to demand--and cost reductions that don't just rely on further scale-up, which will become less fruitful as experience-curve benefits stretch out.

In other words, even if PV manufacturing costs continue to fall quickly for the next few years, it's less clear that the PV prices paid by project developers, businesses and consumers will follow suit, particularly if the current low margins lead to a global shakeout or consolidation among producers. Time will tell whether the solar industry can sustain the cost path that it's been on, or if future cost reductions will be more modest, in which case a number of scenarios for future PV penetration and renewables-based emissions reductions would require revision.

Iran Oil Price Risk Returns

2011-11-15T16:51:00.001-05:00

Between the Libyan revolution and the shaky US and European economies, oil markets hadn't been paying much attention to Iran's nuclear program until last week's release of a new report from the International Atomic Energy Agency (IAEA.) For the first time, the IAEA presented a detailed picture of a well-organized Iranian effort encompassing projects and technologies that go beyond what could reasonably be construed as having purely civilian purposes. Traders are once again talking about an "Iran risk premium," though the market's initial response has been sufficiently muted that it's hard to distinguish from other factors, such as the narrowing of the spread between West Texas Intermediate and Brent crude and worries about the Euro. As long as the international reaction to Iran remains confined to the well-worn pattern of diplomatic protests followed by incrementally tweaked sanctions that dampen speculation about military options, oil will probably just exhibit some extra volatility.

I've been following this issue for a long time, and almost from the start I've been skeptical of the Iranian government's insistence that their nuclear effort was aimed only at producing electricity. Iran has cheaper and less controversial energy options in abundance. Perhaps the biggest surprise in the IAEA report was that the agency would risk the controversy inherent in releasing a thorough accounting of Iran's efforts to develop capabilities unique to designing and building a nuclear warhead that could be mounted on a missile. Moreover, the report suggests that at least some of these activities did not end in 2003, as the controversial US National Intelligence Estimate of 2007 concluded, but "may still be ongoing."

The oil market risk has several dimensions, the most obvious of which relates to a preemptive attack by the US or Israel. Yet even a stepped-up sanctions regime might either directly impede oil exports from Iran or provoke an Iranian reaction having the same effect, at a time when oil prices are already relatively high. Either scenario might trigger an oil price spike that would largely undo recent efforts to revive the global economy. At the moment, however, neither outcome seems very likely to me.

Whatever the IAEA's findings indicate about Iran's intentions or proximity to becoming a nuclear weapons state, the US has little appetite for initiating an attack with such uncertain outcomes on the basis of intelligence that remains incomplete. The public is hardly clamoring for another war, and the administration seems understandably reticent to take such a step, particularly going into an election year. Israeli public opinion--and even its leaders--appear split on the advisability of independent action against Iran's nuclear complex. Even in terms of sanctions, I would expect a response with more bark than bite that stops short of antagonizing Iran's regime to the point at which it might use its oil weapon. Unfortunately, the longer this protracted confrontation over Iran's nuclear program drags out, the greater the risk of one or more parties miscalculating, with results that could spin out of anyone's control.

The Council on Foreign Relations has put out some useful interviews and analysis on the IAEA report and the possible responses to it. Have a look and draw your own conclusions.

Breaking Our Oil Addiction

2011-11-10T17:01:00.004-05:00

In an article in today's Washington Post an official of the National Wildlife Federation was quoted linking rejection of the Keystone XL pipeline with breaking our addiction to oil. Even with the administration apparently having delayed its decision on the project until 2013--quite possibly killing it--this point merits further exploration. Just how might we go about breaking that "addiction", and when could we reasonably expect the task to be accomplished? As with everything else to do with energy, the answers to those questions must be based on facts and figures, rather than wishfulness.

The brief quote and its context imply that a decision to forgo additional supplies of oil from Canada or any other source would, by itself, move us significantly closer to breaking our addiction to oil, a rather vague phrase brought into common usage by President Bush's 2006 State of the Union address. Of course if delaying or rejecting the pipeline only results in continued or additional oil imports from other countries, that would be counterproductive from an energy security standpoint, and perhaps even from an environmental perspective. Ending our oil addiction requires more than just a real or artificial supply constraint; it calls for enormous quantities of energy from other sources, mainly for transportation, along with significant improvements in the efficiency with which we use that energy. How soon should we expect such a transformation?

Start with electric vehicles, which are essentially the only pathway by which renewable electricity sources like wind, solar and geothermal power would have any impact on our oil consumption, because less than 1% of US electricity is now generated from oil. Even if EVs turn out to be the long-term solution to our transportation needs, as I suspect, it will be many years before they can displace enough fuel demand to make a dent in our oil addiction. The current goal is to have a million EVs on the road by 2015. As ambitious as that target seems compared to current sales of less expensive hybrid cars, that would constitute just 0.4% of the 238 million cars and light trucks in the US as of 2008. Moreover, even if EVs replaced cars of only average efficiency, one million of them would displace just 31,000 barrels per day of gasoline. In other words, it would take more than 20 million EVs to save the volume of oil that the Keystone Pipeline could have delivered annually.

If we want to kick our oil habit quicker than by waiting for a hundred million EVs to turn up, we'll need an energy source that's compatible with the vast majority of existing cars, and the ones like them that will probably dominate new car sales for some time. Consider ethanol, our largest and most successful alternative energy initiative so far. Through August, ethanol accounted for 9.2% of 2011 US gasoline consumption, nearly four times its contribution in 2005. However, before we could use a lot more ethanol in our cars, in the way Brazil has, we would need to overcome some big hurdles. Raising the proportion of ethanol in gasoline above 10% creates logistical and reliability problems, and the flexible fuel vehicles that can run on nearly pure ethanol are relatively scarce. In addition, we would need to produce most of the incremental ethanol from a feedstock other than corn. With the latest disappointing crop forecast from the US Department of Agriculture, ethanol production will consume about 41% of this year's harvest. Whether or not that's already enough to cause major food vs. fuel concerns, doubling corn use for ethanol would clearly push corn prices up drastically and cause ripple effects throughout the global food economy.

The good news is that biofuels--including better fuels than ethanol--can be produced from a wide variety of non-food crops, along with their efficient production from sugar cane in the tropics. The bad news is that with the exception of cane ethanol, none of these has been demonstrated on anything close to the scale required. Two of the largest cellulosic ethanol projects under construction, POET's Emmetsburg, Iowa project and the Vero Beach, FL facility of INEOS Bio, will together be capable of supplying just 0.02% of US vehicle fuel needs. And until these plants are up and running, their owners won't know whether their economics are sufficiently favorable--even with the current $1.01 per gallon cellulosic tax credit--to provide a basis for building more and larger versions. Although some of the many competing processes for producing biofuels from non-food biomass including wood, waste, dedicated energy crops and algae look very promising, they all face major uncertainties in development and scaling-up, including the scale-up of their supply chains, and none is yet ready for prime time. That might still be the case ten years from now.

Of course there are many other fuels we could put in our cars, after some modifications, including methanol, compressed natural gas (CNG), liquefied natural gas (LNG) or possibly even ammonia. However, the production of all of these, aside from a relatively small amount of landfill gas, is currently based on fossil natural gas, and all would require major investments in infrastructure and/or vehicle fleets. For that matter, 78% of the energy content of corn ethanol comes from natural gas and other fossil fuels--it also consumes enormous quantities of water--and most of the incremental electricity consumed by the first EVs will likely be generated from gas.

Although it appears that we have ample resources of natural gas to expand its use beyond current demand, I'm not sure that's quite what environmentalists have in mind when they talk about breaking our addiction to oil. And so far we've only considered alternatives to gasoline, without factoring in the significant demand for petroleum products for moving goods by truck, train and ship, along with aviation fuels, lubricants and many other products. Together, they account for as much oil as we use in cars, with non-oil alternatives for most of them at an earlier stage than for gasoline. And while energy efficiency measures, including the substantial improvements in vehicle fuel economy that are possible on a technology-neutral basis--including shifting cars to fuel-efficient diesels--can help to reduce the size of the mountain we must climb, they can't turn it into a valley.

Taking all these considerations into account it's not realistic to imagine that we could break our addiction to oil to any great extent for at least another decade. In the interim, we should certainly pursue all options that could alter the feasibility of such a shift in the years ahead, in a manner consistent with the fiscal constraints we face. I'm also not oblivious to what that implies for greenhouse gas emissions and climate change, though I would point out that our use of oil in transportation is neither the worst emissions offender, nor the easiest high-emitting segment of the US energy economy to tackle in that time frame. In the meantime, we are committed by virtue of scale, infrastructure and fleet requirements to burn many billions of barrels of oil over the next few decades, from wherever they may come. In that light, the administration's decision on the Keystone XL pipeline could prove to be a costly misstep, no matter how much political pressure they were under to withhold approval.

Addendum: Bloomberg has put out an interesting post-decision editorial suggesting that there's no reason for the review of an alternate pipeline route to take as long as the State Dept. has indicated.

Will Energy Determine the 2012 Election?

2011-11-07T14:07:00.004-05:00

A year from today Americans will know who will serve as President from 2013 to 2017. Even though $4 gasoline was still fresh in the minds of voters, energy played only a minor role in the outcome of the 2008 election, overshadowed by two wars and a crippling financial crisis. Will that be the case again in 2012, or will energy loom larger, propelled by its close connection with the economy? Several Republican candidates have already raised energy as a campaign issue, and the administration has repeatedly emphasized the linkages between energy, jobs and taxes. Whether any of those arguments gains traction in a race that at this point seems likely to be dominated by unemployment and deficits could depend on how deftly the administration handles decisions such as the Keystone XL Pipeline permit, as well as the degree to which voters become interested in the details of the country's shifting energy balances.

From day one, the Obama administration has taken a calculated risk on energy by focusing most of its non-crisis-response attention on promoting renewables such as biofuels and wind, solar and geothermal power. According to the latest figures from the Energy Information Agency the combined contribution to our total energy diet from these sources increased from 2.2% in 2008 to 3.2% in 2010. Rightly or wrongly, the Solyndra fiasco could leave voters questioning the wisdom of the whole suite of renewables policies that promise large future benefits but have had little tangible impact so far. Nor do the administration's efforts to claim credit for increasing US oil production look very credible when they demonstrably reflected the characteristic time lags of investments made during the Bush years, and occurred largely in spite of policies such as the Gulf of Mexico drilling moratorium and various onshore lease cancellations.

Meanwhile, the single largest energy development of recent years, the harnessing of vast shale gas resources, which last year supplied the equivalent of more than triple the combined output of US wind, solar and geothermal power, has occurred against a background of governmental ambivalence and occasional outright hostility, as in the case of New York's state moratorium on hydraulic fracturing, or "fracking". Unless the Obama administration moves to embrace shale gas, which David Brooks of the New York Times referred to in his column last week as a "wondrous gift", it might not be very hard for the President's challenger next year to portray his policies as being focused on only 3% of the energy that drives the economy, while neglecting the other 97%.

In that context, the Keystone XL decision could prove crucial. The State Department has signaled that the decision, which was anticipated by year-end, might be delayed into next year or beyond. Recent remarks hinted that the President may make the call personally. And in an interview during last Thursday's Washington Post Smart Energy Conference, Energy Secretary Chu backed away from his previous partial endorsement of the project. Taken together, these moves have me questioning the conventional wisdom that expects a grudging approval of Keystone. Turning it down outright, or killing it by attaching a set of uneconomical conditions to a contingent approval, would play well with portions of the President's base, but it might be hard to defend to independent voters later, particularly if higher oil prices or some event moved energy up the list of top election issues. Delaying a decision past the election would probably satisfy no one.

Whoever wins in 2012, the nation will need a renewed energy policy that balances the need to continue funding research and development aimed at delivering renewable energy technologies that can compete with conventional energy with little or no need for further subsidies, while simultaneously and just as vigorously promoting domestic and wider North American production of the conventional energy sources we will still need for at least another several decades, if we don't want to return to our former trend of becoming steadily more dependent on imported energy. Even if today's 3% from new renewable sources grows to 30%, we will still depend on oil, gas, nuclear and coal for the other 70%, nor can we rely on energy efficiency to end our reliance on the latter sources. I look forward to seeing more detailed energy proposals from both sides over the next year.

Do LNG Exports Threaten the Shift to Gas?

2011-11-03T12:10:00.000-04:00

Last week US liquefied natural gas provider Cheniere signed a long-term agreement to sell BG (formerly British Gas) LNG exported from the Gulf Coast. The governor of Alaska was also recently quoted suggesting that his state's surplus natural gas might find a better market in Asia than if sent to the lower-48 via a new pipeline. Both stories indicate just how much the shale gas revolution has altered the US energy balance. They also provide further validation of its likely staying power. Coincidentally, they reminded me that time was running short to respond to my residential gas supplier's offer to lock in an annual fixed price, as I did last year. That's relevant, because even though the risk of a big spike in natural gas prices looks very low now, the prospect of future US gas exports--an unthinkable idea only a few years ago--serves notice that the shale bonanza is also stimulating new segments of demand that compete with existing ones and will tend to drive prices higher.

Cheniere's role in all this looks like a classic lemons-to-lemonade story. Their Sabine Pass LNG terminal and two others in development on the Gulf Coast were designed to import gas and feed it into the domestic pipeline system. They weren't the only ones to pursue this idea, which looked entirely reasonable when they were planned. In the first half of the last decade US gas production was in decline and LNG imports were climbing, facilitated by rising gas prices that made imports at the higher global gas price attractive, at least seasonally. The combination of a surge of shale gas output and the largest US recession in decades turned these plans on their head. Now Cheniere is redeveloping Sabine as an LNG liquefaction and export facility, with construction scheduled to begin next year.

The Wall St. Journal's Heard on the Street column had a good analysis of Cheniere's deal with BG. It closed with the observation that, "...it is natural that excess supply should seek a market." That got me thinking, not just about what I might be paying for natural gas to heat my home in a few years, but about whether exports pose a threat to ambitious notions of displacing large increments of coal-fired electricity with power from gas turbines, shifting large numbers of US cars and long-haul trucks to compressed natural gas (CNG) or LNG, and building new US chemical plants to capitalize on the abundance of shale gas. Most of these plans depend on gas remaining fairly cheap, particularly relative to oil. The current price of natural gas at its key Henry Hub trading point is the equivalent of $22.50 per barrel, a level that we haven't seen for oil since March 2002. Could gas exports drive up domestic prices to the point at which these other uses couldn't compete?

The answer depends both on how much gas would be exported and on the shape of the supply curve for shale gas. If the latter is steep--if not much extra supply can be brought on without requiring big increases in price--then exports could begin to look like a zero-sum-game at the expense of today's consumers and tomorrow's other new uses for gas. However, if large quantities of shale gas are waiting in the wings for only small increases in price, then while all these uses would be in competition with each other, they should be able to coexist at prices that leave gas considerably more attractive than oil, and competitive with both coal and the cheapest renewables. Assessing which view is likelier isn't simple, because it involves multiple shale basins and evolving federal and state regulations, but in general the data I've seen supports the more optimistic view. Many estimates suggest that most US shale plays would produce attractive returns at around $5-6 per million BTUs (MMBTU), compared to current prices around $4, which have left some producers with poor wellhead economics.

If that's correct, then even a big increase in demand from multiple sources, including a stronger economy, additional power generation, new chemical plants and LNG exports, might not boost natural gas prices by more than $1-2/MMTBU before significant additional supply came onstream. (A reality check on that is the sharp drop in the number of gas wells being drilled when prices slid below $6/MMBTU in late 2008, as the recession and financial crisis took hold.) $1/MMBTU sounds like a big jump at the wellhead, but for consumers it would represent an increase of only about 8% after transmission and distribution costs are added. For power generation in efficient combined cycle plants, it would raise costs by less than $0.01/kWh. And for vehicle use, it equates to an extra $5/bbl, or around 12.5 cents per gallon of gasoline-equivalent fuel. Although not trivial, such increases would be smaller than we've seen from market volatility over the last few years.

Putting the Cheniere/BG deal in perspective, the 3.5 million tons of LNG per year involved equate to 0.5 billion cubic feet per day of gas, or 0.8% of 2010 US "dry gas" production (natural gas with the valuable ethane, propane and butane removed.) The facility's total planned capacity of 9 million ton/y works out to 2% of US gas last year. By comparison the Department of Energy has forecasted US gas production growing by about 3.3 BCFD, or 6% in the next five years in their base case, and by up to 14% in their high-shale-resource case. These figures indicate that there's room for several of these demand sectors to expand, including both power generation and LNG exports, without putting intense pressure on prices. This issue is attracting some attention, including from the US Senate, which has scheduled a hearing next week to consider the consequences of gas exports.

How Many More Solyndras?

2011-11-01T10:33:00.001-04:00

Another firm that received a loan guarantee from the Department of Energy has just filed for bankruptcy. Beacon Power had drawn down $39.1 million of the $43 million authorized by the DOE for the construction of its 20 MW energy storage facility in Stephenstown, NY, but was still operating at a loss and unable to find additional backing. As was the case for Solyndra, the DOE's "loan guarantee" actually took the form of a direct loan from the Federal Financing Bank, an arm of the US Treasury, rather than from a commercial bank or other private-sector lender. If two data points can indicate a pattern, the one here reflects poorly on venture capital decisions made solely by government officials lacking any stake in the eventual outcome of the investment. Real venture capitalists make bad bets, too, but with an entirely different degree of accountability.

The Beacon failure is especially disheartening, because it involves the application of energy storage to grid services, which many believe is crucial for integrating large increments of intermittent renewable energy--mainly wind and solar power--into our electricity supply. In particular, Beacon's use of flywheels, rapidly rotating disks capable of storing and releasing large amounts of energy quickly, looked like a promising alternative to chemical batteries. I've long been intrigued by this technology, which is also being applied to race cars. Beacon's problems appear to be both technical and financial, with two of the company's flywheels having failed catastrophically since startup due to manufacturing defects, and the business model generating insufficient revenue to support the company's obligations.

Unlike Solyndra, the DOE's investment in Beacon Power might not turn out to be a complete loss, though I don't share the confidence of the DOE's spokesman that the "valuable collateral asset" will enable the government to recover the entire sum it lent Beacon. With an operating facility and ongoing revenues, it's possible that the firm's liabilities could be reorganized in such a way than it could emerge from bankruptcy as a viable entity. However, if its reported second-quarter revenue of $525,000 is indicative, it's very hard to see that either the business or the underlying assets could be worth more than a fraction of the $39 million federal loan liability, let alone their $72 million book value. "Haircuts" seem to be in vogue, and I'm guessing that Uncle Sam will take one on Beacon, in order to realize any value at all from the deal.

I'm relieved that the administration has finally ordered an independent review of the entire loan guarantee program, though it's a little late for that to accomplish much more at this stage than bringing additional problems to light. The main 1705 loan guarantee program is out of money and unlikely to receive further appropriations, at least until after the 2012 election. Meanwhile, another energy-related stimulus beneficiary, advanced-battery maker Ener1, was just de-listed from NASDAQ last Friday. The best coda on this whole situation may come from the blog of VC David Gold, who wrote yesterday that the administration's cleantech stimulus is turning out to be "Bad Policy, Bad Politics, and Bad for Cleantech." I'll bet there are many executives at cleantech firms who now wish they had never heard of Treasury grants and DOE loan guarantees.

Repaying Greece's Debts with Tomorrow's Sunlight

2011-10-28T09:21:00.004-04:00

Some days the economic news seems to emanate from the Twilight Zone. When the official summit document from Wednesday's meeting of EU leaders seeking to avert another financial crisis includes a reference to repaying a portion of Greek debt with the output of a huge PV array that might not be completed for several decades, if it is built at all, I don't know how else to describe it. And that's before considering the perplexing economics behind the Helios scheme, which apparently entails Germany or other EU members investing or lending--after lenders have just agreed to take a 50% haircut on previous Greek debt--up to €20 billion to build a 10 GW PV installation in Greece to generate power that would be sent to central Europe via transmission lines that don't all exist yet. Either I'm missing a key element of the plan, or the EU ministers didn't quite grasp the details involved.

Let's start by stipulating that the idea of generating solar power in a sunny location like Greece and sending it to darker northern countries like Germany probably makes a lot more sense than investing billions of Euros installing additional solar in the latter, where it will be lucky to produce annual output equal to an average of 10% of its nameplate capacity, compared to 25% or more in an ideal location. That's the same logic behind the much larger and better-known Desertec plan, which would accomplish much the same goal from installations in North Africa and the Middle East, if it ever gets built. The problem in the case of Helios, as the Greek project is called, isn't the basic engineering concept but the financial one necessary for it to function in the manner suggested in the EU document.

In order for Helios to generate significant value to offset part of Greece's borrowings from the European Financial Stability Facility (EFSF) and other EU institutions, it would follow that Greece should actually own either the Helios installation or the rights to most of the power it would generate. Yet it's also clear that Helios could only be built with massive non-Greek investment of either equity or debt. If equity, then wouldn't the foreign investors own most of Helios and its output, leaving Greece little from which to repay its debts? And if debt, wouldn't that mean Greece was repaying one debt with the proceeds of another, rendering this scheme just a circuitous form of rollover?

Perhaps the Greek government assumes it will end up with a large carried interest in the project merely from contributing the land upon which it would sit, and for streamlining the permitting process for building it. But what proportion of most PV projects is attributable to land, especially in competing, high-sun regions such as those involved in Desertec? I'd think it was pretty low compared to the value of all the solar and electrical hardware, which Greece can't afford to buy on its own. And once we determine how much of the project Greece would actually own, then we would need to calculate the revenue out of which debt repayment could be remitted. If they're counting on power prices close to today's German feed-in tariffs, which were just slashed again, I think they're going to be very disappointed at the end of the day. My guess is the power would be worth no more than around 10 €-cents per kWh at the source, to allow it to compete in the German wholesale market after accounting for transmission costs. At that rate a 100% share of twenty years of 10 GW of PV under Greece's average temperature-adjusted insolation might generate an undiscounted €25 billion, but that's before repaying the project's up-front investment and all other expenses.

Not so long ago the prospects for projects like Helios were mainly determined by the interaction of oil prices and climate policy, with strong global economic growth essentially a given. That proposition has recently been inverted, with oil prices, climate policy and energy development all being driven or constrained largely by economic factors. In this context Helios looks potentially useful as a development project that could provide some construction jobs and eventually generate some corporate tax revenue for Greece on the profits from exporting green electricity to the project's effective owners in central Europe. That could give the Greek economy a bit of a boost. However, the line in the EU communique in which , "Greece commits future cash flows from project Helios...to further reduce indebtedness of the Hellenic Republic by up to €15 billion with the aim of restoring the lending capacity of the EFSF," seems to reflect the same sort of thinking that brought Greece to its current situation.

Key Renewable Energy Subsidies About to Expire

2011-10-25T12:56:00.006-04:00

The US renewable energy industry faces a greatly altered incentive environment next year, as eligibility for two of its largest current subsidies comes to an end at the close of 2011. The corn ethanol sector will likely see the complete withdrawal of the blenders' credit that has fueled its growth for more than 30 years, while new projects generating electricity from renewable energy sources must shortly attract investment without the Treasury grants that provided up-front cash in place of federal investment tax credits against taxable income--a commodity sometimes in even shorter supply among recipients than the energy they seek to generate. With these expirations taking place against the backdrop of a US presidential election campaign and record levels of deficit and federal debt, the prospects for another round of one-year subsidy extensions look slim. Yet renewable energy development in the US won't grind to a halt without them, because these two programs represent merely the most generous layer of the complex web supporting renewables.

Consider the venerable ethanol tax credit, which was made mostly redundant by the passage of the Energy Independence and Security Act of 2007, with its Renewable Fuels Standard mandating the use of increasing quantities of ethanol in gasoline. In fact, ethanol producers were never more than indirect beneficiaries of the $0.45 per gallon credit, which was paid to refiners and other gasoline blenders in order to help create a market for ethanol. Mission accomplished. Moreover, with US gasoline sales having stalled at a level that can barely absorb all the ethanol that existing US ethanol plants can produce, unless gasoline blends containing more than 10% ethanol become popular, there is simply no need for corn ethanol output to expand further. In fact, the market will be more than sufficiently challenged providing outlets for the limited quantities of cellulosic and other advanced ethanol likely to be produced in the next few years. As I've noted previously, forward-looking members of the industry are now seeking help in expanding the market for high-ethanol blends, rather than perpetuating an outdated support for existing sales.

The situation for renewable electricity sources like wind, solar and geothermal energy is more complicated. The expiring Treasury grants were introduced as part of the 2009 stimulus to stand in for the "tax equity swap" market, a category of financial transactions that froze up during the financial crisis. These swaps provided a private-sector cash-flow bridge between project expenditures and tax credits that only paid off after start-up as income was earned or energy produced. That was particularly helpful for smaller, less profitable developers, but it also provided an additional check on marginal projects. Even after credit markets eased, most developers understandably preferred the cash grants, which reduced their financing costs and avoided the fees that bankers charged on tax equity deals. However, that preference doesn't justify continuing the cash grant program--particularly for the large, profitable corporations that increasing dominate this space. The industry should focus more effort on fostering the revival of a liquid and competitive tax equity market and less on lobbying for an extension of a temporary stimulus measure.

Either way, the tax credits behind these grants and swaps won't last forever. Under current law, the principal federal tax credit for wind will be in place only through 2012, for biomass and geothermal through 2013, and for solar through 2016. Instead of a scenario of perpetual last-minute extensions such as we've seen in the past, the industry and its investors should be thinking about a scenario in which all these tax credits end, either as part of comprehensive tax reform that eliminates most such "tax expenditures"--including the ones for the oil and gas industry that have become so contentious in the last few years--or a transition to providing renewables with similar sorts of incentives as oil and gas, which essentially amount to forms of accelerated depreciation and modest tax breaks for manufacturing in the US, rather than in other countries.

It's also important to realize that even without these tax credits and in the absence of comprehensive federal energy legislation that looks unlikely any time soon, the industry would still retain numerous state-level benefits, starting with the renewable portfolio standards (RPS) for electricity currently in place in 29 states and the District of Columbia, a tally that encompasses most of the states with the best wind and solar resources. These RPS's are similar to the Renewable Fuel Standard for biofuels in requiring utilities to include increasing proportions of renewable energy in their supply portfolios, whether owned or purchased. Such standards, including California's aggressive RPS targeting 33% renewable electricity by 2020, stand outside the polarizing political debate over taxation and government expenditures. They function as an implicit tax on ratepayers, rather than taxpayers, because they show up within customers' utility bills rather than on their 1040 forms. That distinction could be particularly important if the congressional supercommittee fails to reach a consensus, and the default spending cuts built into the Budget Control Act that resolved this summer's debt ceiling crisis kick in.

So while it might appear that the US renewable energy industry is about it be cut loose from the key incentives that enabled it to grow to its present dimensions, it will continue to benefit from supports not enjoyed by other industrial sectors. Even when the current tax credits expire, renewables will have a mandated market providing a floor beneath them. Ethanol output won't revert to 2005 levels, nor will renewables vanish from the landscape, even if their growth slows a bit while the rest of the economy struggles to emerge from the aftermath of the Great Recession and financial crisis, and to avoid a double-dip. Meanwhile, global overcapacity in wind turbine and solar module manufacturing will keep their prices trending lower--and installations stronger--pending industry consolidations that will position both for healthier, more sustainable growth in the long run. All of this falls well short of the level of help for the industry that most renewable energy supporters would like to see, but it's far more than the level playing field (ignoring externalities) that would see cheap and abundant natural gas sweep away all competition for new power generation.

US Energy Poll Reveals Contradictions

2011-10-20T13:49:00.001-04:00

Yesterday I received a press release announcing the results of a new poll on US consumer attitudes towards energy conducted by the McCombs School of Business at the University of Texas in Austin. I wasn't surprised to see that a plurality of the poll's respondents thinks the country is headed in the wrong direction on energy--triple the proportion that think we're on the right track--and many expect the situation to get worse in the next 25 years. That meshes with numerous readings on Americans' views of the overall economy. The poll also showed consumers broadly dissatisfied with the job that government and industry are doing in this regard, though the renewable energy sector, along with engineers, scientists and academia received somewhat better marks. At the same time, the results on several questions either contradict current consumer trends or reveal a poor understanding of energy market influences. Perhaps the most reassuring finding was that less than a quarter of consumers consider themselves knowledgeable on energy, while a large majority is interested in learning more.

The main question that grabbed my attention concerned consumers' "expectations for adopting new technology." 38% reported they were likely to use smart meter technology within the next five years, 30% said they were likely to own a hybrid car, and 21% were likely to install solar panels on their homes. On the face of it, these should be very encouraging results for the renewable energy and advanced vehicle sectors and those who invest in them. At the same time, it's hard to square these figures with the actual adoption rates for such technologies in the marketplace.

Consider hybrids, which have lost most of their novelty in the last decade, with cumulative US hybrid car sales standing at just over 2 million at this point. That's less than 1% of total US light-duty vehicles (cars, SUVs and light trucks), but it's still impressive, considering they started at essentially zero in the late 1990s. The problem is that even now, with practically every major carmaker offering at least one hybrid model, and several fielding an entire range of hybrids, 2011 sales have averaged just 2% of total US car sales of 9.5 million through September, based on figures compiled by hybridcars.com. Add plug-in electric cars like the Chevrolet Volt and Nissan Leaf and you get to 2.1%. Even before hybrid supplies were constrained in the aftermath of the earthquake in Japan, advanced vehicle sales never topped 3% in any month of this year.

The poll provides few insights into why the actual "take rate"would amount to less than a tenth of those with favorable attitudes towards buying a hybrid. However, it does suggest that the standard explanation that gas prices just aren't high enough yet is out of step with how consumers view those prices. Fully 95% of respondents described gas prices as either "very high" or "somewhat high", and 78% expected them to be somewhat or significantly higher in six months. One possible conclusion is that despite coming in compact, SUV, truck and luxury flavors, hybrid technology still doesn't deliver the value and/or performance most consumers are seeking, even if they're receptive to it in the abstract.

Then there's the even more dramatic disconnect on solar power. If 21% of single-family dwellings in the US were to install rooftop solar panels of 3 kW or more in the next five years, that would equate to at least 228 GW of solar power--about 90 times current US installed capacity--for average installations of 46 GW per year, or nearly three times the amount installed globally last year, mostly in Europe. As of the end of 2010, there were 153,000 grid-connected PV systems in the US, including commercial and utility installations. Even if all of them were on the rooftops of homes, that would still amount to just a 0.2% market penetration. Although PV prices are coming down rapidly and sales could approach 2 GW in 2011, this divergence between sentiment and sales suggests that a lot more Americans like the idea of rooftop solar than are actually willing to invest in buying (or leasing) it at this point.

Whatever the UT poll results indicate about the potential medium-term market share of new energy technologies, they provide a data point that Americans view energy as another important issue they believe government is getting wrong. They also highlight the need and opportunity for more education on how energy markets really work, with supply constraints and growing demand actually having a much bigger impact on energy prices than the limited pricing power most energy companies enjoy.

Pipelines in the Spotlight

2011-10-18T12:05:00.001-04:00

There aren't many parts of the energy value chain that normally receive less attention than pipelines. Energy production, whether from oil and gas fields, nuclear power plants, or rapidly growing renewable sources usually garners far more attention for the impressive technology and capital involved. By contrast pipelines are long-lived, relatively low-tech and low-return assets that often seem invisible to those outside the industry. Sunday's announcement of Kinder Morgan's bid for El Paso Corp., uniting two pipeline giants into a $94 billion enterprise, reminds us just how big this low-key infrastructure can be. This deal also signals important shifts underway within the fossil fuel industry. Just as the rise of wind and solar power requires an upgraded electricity grid, changes in the sources of our oil and gas have big implications for the networks required to bring these fuels to market.

As an article in today's Wall St. Journal states in its title, the Kinder Morgan-El Paso deal heralds the arrival of the Age of Shale. It simultaneously validates the potential of US shale gas resources and points to a new set of growth opportunities created by unconventional oil and gas resources that couldn't have been produced a decade ago, either economically or technically. This couldn't have come at a better time for the pipeline industry, when its bread-and-butter business of transporting refined products to distribution terminals is reaching a plateau, as developed-country markets exhibit Peak Demand and biofuels output grows. That's a big change from when I worked in the "mid-stream", which includes pipelines, distribution terminals and trading. Then, the challenge was keeping conventional crude pipelines full as domestic onshore oil fields depleted, while expanding capacity to transport gasoline, diesel and jet fuel to meet steadily rising demand. Today the advent of shale gas, shale oil and oil sands crude coincides with the development of a much more diverse energy market.

Recent changes in the economy also make pipelines, which used to be considered dull, more interesting as an investment. With interest rates historically low and equity markets weak and volatile, the modest but stable returns that midstream oil and gas assets offer must seem a lot more attractive than they did prior to the financial crisis, particularly when managed in tax-efficient structures such as the master limited partnerships that Mr. Kinder helped pioneer. And those same low interest rates make the capital required for new private-sector infrastructure projects more affordable. Such projects also look doubly beneficial in the current environment of high unemployment, providing both large numbers of jobs in the short term, during construction, and ensuring the reliable energy supplies needed for sustainable job growth once the economy hits its stride again.

Of course pipelines aren't always dull, particularly when they are the focus of controversies such as the current one concerning the proposed Keystone XL Pipeline. But what many of that project's critics, including celebrities who appear to know less about such facilities than most of my readers, have missed is that despite rare, unfortunate accidents, pipelines remain the best and most efficient means of transporting large volumes of fuel over long distances. Unless you honestly think we can do without these fuels entirely--a scenario that I am convinced will not be realistic for at least another few decades--then it makes little sense to shun pipelines and thus proportionally increase the quantity of fuel that will be carried by truck, rail and ocean-going tankers, all of which are also subject to accidents. Like all infrastructure pipelines require proper maintenance, but they are not inherently risky.

No bet on the scale of the one Kinder Morgan is making can ever be a sure thing, and I can think of several things that might go wrong, topped by a double-dip global recession that lasted for years and sapped both energy demand and gas drilling economics. However, this deal taps into a number of converging trends supporting a US natural gas boom that is part and parcel of the potential global Golden Age of Gas that the International Energy Agency recently described. I wouldn't be surprised to see more transactions along these lines.

More Lessons from Solyndra

2011-10-14T11:03:00.005-04:00

I'll bet that those working and investing in renewable energy are even more tired of the steady stream of headlines from the unraveling Solyndra mess than the rest of us are. Today's crop includes more evidence of the political linkages to the overall process for determining the company's suitability for federal backing and the revelation that an investor in Solyndra was advising the US Navy to sign a contract with them, even as the firm was on the verge of collapse. None of this has done either the industry or the administration any good, and there is much to be learned from this episode. That includes lessons concerning direct government support for the full-scale deployment of renewable energy and other technologies.

Start with the ethics issues. No one should be surprised that investors in Solyndra were lobbying the DOE and White House in support of the company's application for a federal loan guarantee. That was hardly unique to Solyndra or renewable energy. And I'm perfectly willing to accept, unless proven otherwise, that both the DOE advisor whose wife works for a law firm representing Solyndra, and the venture capitalist who apparently advised the Navy to buy Solyndra's technology in his capacity with the Pentagon's Defense Venture Catalyst Initiative, thought they had done everything necessary to resolve any potential conflicts of interest in this matter. Yet in both cases it seems clear that even if nothing improper was done, the appearance of impropriety is very hard to dispel after what seemed like a routine transaction turns into a front-page scandal.

Whenever I see this sort of thing I can't help recalling the early training I received as a petroleum products trader for Texaco, which took anti-trust compliance very seriously. The lawyer who advised our Supply & Distribution department on such matters always reminded us to think about how our dealings with other companies might look if we had to explain them from the witness stand in a court of law. He invariably advised going beyond mere compliance; his mantra was, "Avoid the appearance of evil." That's a lesson that it seems many of the officials involved in the Solyndra debacle either forgot or never received, even if they believed they were in full compliance with existing ethics policies.

When you step back from such details it becomes apparent that these are precisely the sorts of conflicts that result, when the government involves itself so deeply in transactions of a magnitude that would normally be handled in the commercial sector--which even when it makes mistakes does so with shareholder dollars, rather than tax dollars. And make no mistake, if Solyndra had gone broke after receiving $500,000 from Uncle Sam, rather than $535 million, none of these other issues would matter or have seen the light of day.

It's perfectly appropriate--even necessary--for the government to make modest-sized bets on new technology in key areas, particularly when they require greater patience than most corporations are capable of. And it's to be expected that many or even most such bets will turn out to be dead ends, as Solyndra did. The problem is that while a few million dollars will buy a lot of renewable energy R&D, they will buy only a negligible amount of deployment. While the government can afford to make numerous small bets that don't turn out well but advance our knowledge in the process, it can only afford to make a small number of bets on the scale of the Solyndra loan. That ought to be especially true when the deficit and debt loom as large as they do, unless you're a firm believer in the "broken windows" theory of stimulus, or Lord Keynes's suggestion that the government could productively bury bottles of money and let people dig them up.

The easy question is whether the Department of Energy should have backed Solyndra. I have concluded the answer is no, and not just based on after-the-fact information. The much harder question is whether the US government should be in the business of providing this level of support for large-scale manufacturing or deployment, rather than just R&D. And even if it should, can it develop the necessary expertise and processes, not only to make such decisions at least as well as its commercial counterparts would, but also to insulate the decision-makers from the political influence that such high stakes are bound to attract. Answering that depends on a lot more than just one's political or economic philosophy.

Is Mount Everest the Best Place for Solar Power?

2011-10-12T11:42:00.002-04:00

A new study on the impact of regional temperature differences on solar generating potential arrives at some surprising conclusions about the world's best locations for solar power. While the US desert southwest still ranks high, as you'd expect, it turns out that some of the best sites may be in places most of us would never suspect, including the Himalayas and Antarctica. That's because the crystalline silicon-based photovoltaic (PV) cells that dominate the market today are sensitive to ambient temperature and perform best at low temperatures, such as those found in the polar regions and high altitudes. These results could have interesting implications for future energy supply and greenhouse gas emissions in India and China, and for regional cooperation in what has historically been a tense neighborhood.

The paper by researchers from Japan's National Institute for Advanced Industrial Science and Technology was published in Environmental Science & Technology. Their approach involved superimposing mapped global average temperatures onto the map of average solar radiation, or "insolation", that has been the standard guide for assessing solar power potential. This produces some interesting shifts in the world's best solar locations, particularly by reducing the PV potential of the tropics and increasing that of colder regions. (Note that this comparison isn't applicable to solar thermal installations.) High-altitude locations look especially attractive for PV for two reasons: Not only are they colder, with average temperatures falling by 4-10ºC for each kilometer of altitude (12-28ºF/mile), but they also receive more sunlight, due to the thinner atmosphere at these heights.

The resulting differences in output are significant. The same PV module that generates 600-800 kWh/year per Watt of nameplate capacity in the UK or Germany and 1,400-1,600 kWh/W in Arizona would top 2,000 kWh/W in the Himalayas and parts of the Andes, as well as near the South Pole. The authors recognize that the latter might not be very useful without low-cost, high-volume energy storage, perhaps in the form of hydrogen, due to extended periods of darkness in the antipodal winter. I would note that the enormous distances to the nearest market might also be overcome by borrowing some ideas from the plans for space solar power (SSP). Either way, it doesn't take high storage or logistical costs to render large-scale Antarctican PV impractical, and the installation, maintenance and transmission challenges in the Andes and Himalayas aren't trivial, either. Whether the paper's conclusions turn out to be more than just scientifically interesting will depend on the detailed economics of the projects necessary to implement them.

The economics of PV entail a lot more than just the solar generating potential in a given location. Proximity to markets, or at least access to transmission, is a big factor, as is price, including both the market price for power and any relevant government or utility incentives or carbon pricing. However, it's also true that it takes either very high local prices or very high subsidies, such as Germany's solar Feed-in Tariffs, to make PV competitive in regions with low temperature-adjusted solar output. Such subsidies are a rich-country game on any scale large enough to matter, and even European countries are finding it hard to sustain these added costs as their economies teeter on the brink of another financial crisis and recession. The advantages to developing countries like China and India of pursuing high-altitude solar--even if it requires long transmission lines--could be compelling in the long run.

Energy Efficiency: An Uphill Battle on A Slippery Slope

2011-10-06T15:10:00.005-04:00

With apologies for the dueling clichés in today's title, that image conveys the conflicting messages I received from a pair of events on the topic of energy efficiency this week. Yesterday I watched a panel discussion on energy efficiency finance, part of the valuable First Wednesday series of seminars from Resources for the Future in D.C. Yet as I listened to the discussion of creative mechanisms for overcoming the numerous financial and behavioral obstacles impeding the widespread adoption of efficiency technologies, I couldn't help framing it in the context of Tuesday's blogger call on "efficiency rebound", also known as the Jevons Paradox, hosted by the Breakthrough Institute. This latter, offsetting effect has been controversial in the US but is apparently more widely accepted in EU policy circles.

Energy efficiency is probably the energy topic to which I've devoted the least space in this blog in the last seven years. That hasn't been a deliberate slight, though perhaps it reflects the bulk of my personal experience on the supply side of energy. It's also a tricky subject because it's a moving target. We often hear efficiency described as the low-hanging fruit in discussions of energy security or emissions reductions, but that usually ignores the fact that the truly low-hanging fruit in efficiency was mainly captured during the energy crises of the 1970s and early 1980s, and in subsequent price spikes in electricity and natural gas. That doesn't mean there isn't still ample scope for further improvement, but it does leave those efforts subject to the long list of barriers described in yesterday's presentations. They include lack of funding, low awareness, landlord/tenant issues, and lack of expertise.

One of the other obstacles that intrigued me was the mismatch between the scale of most efficiency projects, even in the commercial sector, and the much larger scale of investor interest in financing efficiency, as described by the panelist from Citibank. He suggested the answer lies in aggregation, in which the financing of numerous smaller projects would be bundled and sold off in tranches to investors. If that sounds familiar, it should, because it reflects a similar approach to securitization to the one that contributed to the recent housing bubble. However, I would stress that efficiency instruments need not be inherently very risky, as long as they are assembled with due concern for the creditworthiness of the project owners, and without heroic assumptions about the risk-abating portfolio effect of aggregation. Another element that could assist this process is the sort of project performance guarantees described by the panelist from Johnson Controls. In any case there is no shortage of federal, state and local programs focused on energy efficiency financing, including the controversial Property Assessed Clean Energy (PACE) mechanism.

I hope you get the sense from this brief summary that implementing energy efficiency on a large scale is quite difficult enough in its own right, even when those investing in such improvements can safely assume that they will enjoy 100% of the promised cost savings when the projects are completed. The research on rebound by a team commissioned by the EU's Directorate General for the Environment highlighted a number of mechanisms by which efficiency gains may lead to additional energy consumption, either by the individual or organization implementing it or within the larger economy. In some cases this could even lead to post-efficiency consumption exceeding the pre-efficiency level, a condition referred to as "backfire." The potential for these offsetting effects not only makes efficiency a tougher sell on a project basis, but it also undermines the efficacy of macro-scale efficiency measures in mitigating climate change or reducing energy imports. This view is consistent with the findings concerning rebound assembled by the Breakthrough Institute.

The logic of rebound begins simply and locally, before becoming complex and widespread. When you invest in efficiency, your energy bill goes down, leaving you more money to spend on either more of the services that consume energy (e.g., transportation, lighting, heat or air conditioning) or on other goods or services, after accounting for the cost of the upgrade or the cost of financing it. Now think about what happens in the economy: the demand for energy has dropped by a little bit, as has the money spent on it. You'd expect energy prices to fall and the freed up money not spent on energy to result in consumption or investment somewhere else. But those goods and services likely consume energy, too, along with the embedded energy in the efficiency technology, the installation of which started this cascade. And as overall energy productivity goes up, economic growth should also increase, resulting in additional energy use. The EU report found evidence of rebound in the range of 10-30%, including 26% for the UK efficiency investments that were studied. For example, the UK government apparently assumes that 15% of the benefit of home insulation will be lost to rebound.

Some of these mechanisms are more intuitive than others, and I am still thinking through what I heard, particularly in terms of why much of the rebound effect wouldn't be offset by market feedback mechanisms or by the reaction of company management to disappointing post-expenditure reviews on efficiency projects. When I raised these points during the call, Dr. Maxwell, the co-leader of the EU study team, assured me that my concerns weren't supported by the empirical research they examined.

If this rebound effect is as prevalent as the evidence seems to indicate, then the implications aren't very positive. Although individuals and companies implementing efficiency measures are likely to get most of the value they expect, even if it's in some form other than direct savings on their energy bills (e.g., more mobility, more comfort, higher output) society likely wouldn't see the expected energy and emissions savings at the level of the entire economy. That requires increasing efforts on efficiency even further--against all the barriers discussed above--or expending more effort on the supply side of energy, through promotion of higher energy production and more investment in renewables. In other words, those low-hanging efficiency gains that have defied so many efforts to implement look even harder to achieve in practice and somewhat less valuable.

I'm not sure to what extent I buy into all this, yet. Direct rebound due to less expensive energy services for the individual or firm seems fairly straightforward, but the wider ripple effects involve positive and negative feedback loops requiring complex modeling to assess--with all the uncertainties to which such models are subject. Nor does it require the existence of a large rebound effect to appreciate just how difficult it will be to move the needle on total energy consumption and emissions very far by means of efficiency measures that must ultimately be implemented by individual companies and consumers that already face a large array of competing priorities. I intend to look into this further and report later on any insights that turn up.

The Energy Glass Is More Than Half Full

2011-10-04T15:35:00.000-04:00

A recent comment from a frequent reader got me thinking about the good news that has accumulated on the energy front, even as the rest of the economy has bogged down in pessimism. There's actually quite a lot of it, though perhaps it has been easy to miss, because most of these developments look like bad news from someone's perspective, as organizations and social-media-empowered individuals seek to outdo each other in the hunt for negative ramifications and unintended consequences. Recognizing the positive aspects of such nuggets as shale gas and its recent extension into shale oil, along with factors like the plummeting price of solar panels that contributed to the Solyndra debacle, requires stepping back to view them through the lens of the big energy problems that have plagued us for decades.

As recently as a few years ago, it was widely assumed that the US was running short of both oil and natural gas. Domestic oil production was declining steadily, as it had been since the mid-1980s, even as US oil consumption kept rising. The result was a wedge of oil and petroleum product imports that seemed likely to widen indefinitely. Moreover, US natural gas production appeared destined for the same outcome, as non-associated gas fields in the shallow waters of the Gulf of Mexico declined faster than expected, and diminishing oil production slowed associated gas output. The combination of these trends made energy security a priority concern again, after more than a decade of complacency.

The turnaround in these trends has been nothing short of astonishing. Last week the Houston Chronicle published an article with the headline, "N. American oil output could top 40-year old peak", accompanied by a graph showing a clear inflection point in 2008--not by coincidence about five years after oil prices began their climb from the $20s to a peak just shy of $150 per barrel. Motivation plus investment equals production, after an inherent time lag. But what's really changed is that those investments weren't just going into more of the same onshore conventional oil fields that had been declining; they were going into deepwater drilling, oil sands extraction, and lately into the application of shale gas drilling techniques to similar deposits of shale oil that weren't in anyone's reserves just a few years ago, because no one knew how to tap them effectively and economically.

The latter provides a fascinating example of innovation, today's hot buzzword. Drillers have been hydraulically fracturing oil wells since the late 1940s--about a million of them--and horizontal drilling has been around for more than a decade, too. Combining these techniques, along with modern seismic visualization, has unlocked what looks like a century's worth of natural gas supplies. But if this weren't enough of a game-changer, setting up gas-fired power plants as both a replacement for coal and as the on-demand backup for intermittent renewables like wind and solar, some smart folks realized that the same combination of techniques could produce oil from other shale deposits. Suddenly fields like North Dakota's Williston Basin (the Bakken formation) and the Eagle Ford shale in Texas are counted among the largest oil fields in the country, with billions of barrels of potential reserves and production in the hundreds of thousands of barrels per day.

When we look at these successes and recognize that some of the most prospective US oil resources remain locked away behind actual and virtual drilling bans, the mantra that we can't drill our way to energy independence at least merits a serious reassessment. But what's even better about these recent energy revolutions is that they aren't occurring in a 1970s' context in which all this extra oil and natural gas would merely be burned in gas-guzzling cars and inefficient power plants. Instead, they coincide with impressive advances in fuel efficiency, in which muscle cars like the Camaro and Mustang can get at least 30 miles per gallon on the highway, while true economy cars get over 50 mpg today. Meanwhile, we've squeezed almost all the petroleum out of the utility sector, with just 0.9% of US power generation last year coming from oil-based fuels, while nearly 54% came from lower-emission sources such as gas, nuclear and renewables. These trends are moving in the right direction, too.

Renewables have come a long way, since solar cells were niche or novelty items and the economics of wind power only appealed to wealthy taxpayers seeking write-offs against marginal tax rates of up to 70%. Notwithstanding the struggles of individual firms like Solyndra and Evergreen Solar, global photovoltaic (PV) generating capacity grew by 74% last year to 40,000 MW, roughly where wind power was in 2003, if you ignore how much of the former has been installed in places with miserably poor solar resources. Wind power is still cheaper than solar power, but solar looks much more useful in the long run, because its output is more predictable and better aligned with demand. Both remain more expensive than conventional energy sources, though the gap is narrowing, especially for solar, and without cheap and abundant natural gas from shale resources it might not exist at all in some markets. Together with a resurgent geothermal energy sector, these renewables could soon survive with little or no subsidies by concentrating on regions with the best combinations of resources and transmission-accessible markets. (Germany would have installed its last solar panel in that scenario.) That wasn't an option just a decade ago.

The greatest contribution the energy sector can make is providing affordable and reliable inputs for the rest of the economy. Building on the developments above it should be possible to craft cost-effective energy policies to improve US energy security significantly and greatly reduce the leverage of the sources of our imported oil, including OPEC as a whole. At the same time we could move the electricity sector, which never really had an energy security problem but remains the largest source of US greenhouse gas emissions, towards much lower emissions without breaking the bank. Those outcomes seem attainable, if we can moderate our impulses to treat energy policy as a piggy bank for patronage or a laboratory for industrial policy. In that respect, energy just might be the most solvable of all our big problems.

The East Coast Refinery Gap

2011-09-28T12:30:00.002-04:00

I see that ConocoPhillips has announced it will idle its 185,000 barrel-per-day Philadelphia area refinery, as a prelude to selling it or closing it permanently. Combined with the recent announcement that Sunoco would exit the refining business and sell or close its two refineries in Philadelphia, this amounts to just under half of the operating refining capacity on the US east coast, and that's counting PBF Energy's Delaware refinery, which is apparently in the process of starting up again after having been sold last year by Valero. If none of these three facilities finds a buyer, the resulting closures would leave a large gap in the east coast petroleum product market that must be filled either by shipping more products via pipeline from the Gulf Coast, to the extent capacity permits, or by means of increased imports from Europe and Canada. East coast gasoline and diesel prices could be higher for years to come.

The story in Reuters gives a good overview of the circumstances leading to Conoco's decision, and you've read about most of these factors in previous postings here. Topping the list is the persistent divergence of crude oil prices between the US mid-continent and the global oil market, due to a bottleneck at Cushing, OK resulting from several factors. Last week the gross margin ("3:2:1 crack") for importing crude priced at the level of UK Brent and turning it into gasoline and diesel or heating oil for the northeast market stood at a breakeven, and it's only a few dollars a barrel in the black today, after yesterday's market recovery. That's not much of an inducement to hang onto massively complex, capital-intensive facilities and to continue investing in them to keep them in compliance with ever more stringent regulations. Sometimes it just makes more sense to take a write-down and sell to someone else, who then starts with a lower capital base and has a better chance of making a return--not unlike the restaurant business. The problem in this environment is that it's not obvious who would step into the shoes of Sunoco and Conoco in Philadelphia. A few years ago buying refineries from integrated companies that wanted to redeploy their capital was a thriving game, with lots of players. Not so much, now.

Conoco's timing on this move is interesting, too. If it were only a question of margins, I'd think they'd wait to see how much profitability improved after Sunoco's plants shut down. Instead, it appears they are focused on a bigger picture. Even if they don't find a buyer, closing a marginal or money-losing facility will improve their overall refinery portfolio as they prepare to spin off the refining and marketing business, while allowing them to use the capital expenditures they won't have to put into the Trainer refinery for more lucrative opportunities like shale gas, which the company has been touting in a series of ads. That probably makes sense for the company's shareholders, though it won't do much for consumers in my neck of the woods, especially if the company's larger New Jersey refinery meets the same fate.

Oil refining has always been a tough business, with its occasional good years normally more than offset by years or decades in the doldrums. But the combination of reduced demand from the recession-weakened economy and the increased supply of biofuel--mainly corn ethanol, so far--has increased the pressure. When I ponder all this it makes me wonder why so many startups are so eager to get into the fuels manufacturing business, even if it will be based on biomass rather than oil, when they will ultimately be exposed to similar market forces.

Drawing Conclusions from Solyndra

2011-09-26T16:17:00.010-04:00

When the energy portions of the 2009 stimulus were announced I remarked to a colleague that I wouldn't be surprised if its billions in incentives led to a future scandal or two. In fact, I was thinking more along the lines of fraudulent diversions from the Treasury's renewable energy grant program, which has handed out $8.7 billion since its inception. That program had its own day in the spotlight when it turned out that a significant portion of the initial disbursements were going either to non-US companies or to pay for equipment made outside the US, undermining its green jobs rationale. However, I wouldn't have guessed that the biggest scandal would erupt from the ostensibly lower-risk loan guarantee program of the Department of Energy. The prospect that a tussle over a small cut to that program, for which eligibility is due to end in a few days, nearly set up another government shutdown crisis seems even stranger.

Whatever happens to the loan guarantee program, the decision to lend over $500 million to Solyndra looks bad, and not just in retrospect, with the firm in bankruptcy. The market environment that Solyndra was betting on was already shifting in late 2008--months before its loan was approved. The global bottleneck in the supply of polysilicon, the key raw material for the crystalline silicon photovoltaic modules with which Solyndra's unique CIGS modules competed, was easing as new polysilicon capacity was coming on line, more was under construction, and polysilicon prices were falling. Someone at the DOE should accept responsibility--and the consequences--for ignoring or missing that signal and concluding that it was a good time for Solyndra to double its capacity and fixed costs.

As tempting as it might be to dwell on Solyndra's failure, that should not be our primary concern right now. If laws are found to have been broken or influence improperly used, there will be ample time to address that. Nor should we dwell on the fate of the other projects for which $10 billion in loans or loan guarantees have already been concluded. Many of those projects involve generating renewable power and selling it under long-term agreements that will ensure a profit, with little additional risk. Instead, oversight should focus urgently on those projects that are still under consideration or have received only conditional approvals to date.

One of the applications that apparently got caught in the fallout from Solyndra was a project of Solar City Corp. to install up to 371 MW of rooftop solar panels at military facilities across the US. Solar City was seeking a partial (presumably 80%) guarantee of up to $344 million in loans to carry out these projects. This is precisely the sort of initiative necessary to deliver on the military's goals to increase its use of renewable energy. I heard a lot more about that at an Air Force energy briefing at the Pentagon earlier this month and will write about that session when I receive the responses to the follow-up questions I sent in.

The military faces two major obstacles in achieving its energy objectives, and projects like Solar City's would help overcome both. First, energy generation assets are expensive and would compete with military hardware procurement and other budget priorities. Having someone else make those investments and charge the services for power that they'd otherwise have to buy from a utility is as useful for the military as it is for homeowners who can't afford the up-front costs of rooftop solar. The other aspect with which the project helps is that the economics of rooftop solar still depend on federal and state incentives that the Department of Defense can't access directly. In this case, Solar City would buy and install the hardware and collects the tax credits and other incentives that allow them to charge the military a competitive price for power. With time running out on its application, the company has apparently decided to pursue a scaled-down version of the project with only commercial financing.

As for any remaining applications, if the DOE can't convince itself that they are sound before the clock runs out at the end of the month, then it must either turn them down or ask the Congress for more time. Whatever call the DOE makes it had better be prepared for the scrutiny and second-guessing they are bound to receive. The Solyndra debacle has arguably done as much harm to US renewable energy policy as the Enron scandal did to energy trading. Another Solyndra might just put an end to the whole proposition of financing green energy with public funds in the US.

Note: Posting updated to reflect the current status of Solar City's project.

Breaking Oil's Monopoly on Transportation

2011-09-22T15:46:00.001-04:00

I've been thinking about an op-ed in Tuesday's New York Times written by a former National Security Advisor and a former CIA chief. They propose breaking oil's monopoly on transportation fuels by introducing more fuel competition at the point of use. This isn't a new idea, nor is their preferred tactic of requiring all vehicles sold in the US to be flexible fuel vehicles (FFVs) capable of running on a variety of fuels. I looked at this in April, following another op-ed by Mr. Woolsey, and several times previously in conjunction with the Open Fuel Standards Act, a piece of unpassed--so far as I know--federal legislation designed to put such competition into effect. The idea is as interesting as it has always been, though several trends pose new challenges for its ultimate success.

The op-ed was apparently timed to mark the introduction of a new group called the United States Energy Security Council, the membership of which constitutes a who's who of national security and energy leaders. The Council's issue statement is worth a read and stands apart from some other similarly-well-intended efforts for its clear recognition that our energy security problem with oil has nearly nothing to do with electricity, and thus won't lend itself to leverage from renewable electricity sources until large numbers of electric vehicles are on the road. That could take decades, as I've noted elsewhere. However, I wish the group had spent more time pondering the source of oil's natural monopoly in transportation energy, because I think it might have given them pause concerning methanol, one of the competing fuels they're trying to promote.

The sources of that natural monopoly--the reasons oil continues to dominate the transportation energy market 93 years after the introduction of the Model T Ford--owe little to the market power of OPEC, and much to the energy density and convenience of storage, transportation and distribution of petroleum products. Making fuels like E85 ethanol and methanol as readily available as gasoline, and making cars as compatible with them as they are with unleaded gasoline, won't affect the miles per gallon and range advantage that gasoline enjoys. That advantage is especially evident relative to methanol, which packs just under half the BTUs per gallon in gasoline.

Even though the abundance of shale gas could conceivably alter the economics of fuel methanol enough to put it into serious competition with gasoline, it would face an even more serious marketing challenge than E85, with its smaller but still significant range and mpg penalties, and its miles-per-dollar penalty that could expand significantly when the ethanol blenders credit expires at the end of the year--or sooner. Without substantial engine modifications to take advantage of methanol's other properties--modifications that wouldn't be compatible with fuel flexibility, as I understand it--both mpg and range would reflect a similar ratio as energy content. And unless methanol (with all appropriate federal, state and local motor fuel taxes applied) could be delivered to your corner gas station at less than half the cost of gasoline, then not only would its range be inferior, but also the miles delivered per dollar spent. Consumers tend to notice such things after a while. And that is aside from my long-standing concerns about the mass-market use of methanol.

The group's focus on alcohol-based fuels also goes against another recent trend in the biofuels industry towards what are called drop-in fuels: fuels that despite their non-petroleum origins are 100% compatible with engines designed to run on petroleum products. Despite all the hype about cellulosic ethanol, it is looking increasingly likely that the main fuels we will get from non-food biomass could closely resemble today's gasoline, diesel and jet fuel. And drop-in fuels don't require vehicles to be modified as FFVs.

When viewed from a technical perspective, I don't find the Council's arguments for mandating FFVs especially persuasive. However, I think there's a more compelling argument to be made, relying on option value. If it costs $100 to modify a car to run on other fuels besides gasoline, then that investment would still have value even if in practice the car's owner never actually bought those fuels, as has been the case with the vast majority of the cars already capable of using E85. The option still has value because it provides an insurance policy against some future circumstance in which the only fuels available (or affordable) are non-petroleum ones, for whatever reason: an oil embargo, peak oil, pipeline failure, or some weather-related catastrophe, take your pick. That kind of competition for oil doesn't even require large sales of non-petroleum fuels before having an impact in the market. The key question is whether it's worth enough to us as a society to require the collective expenditure of roughly $1.2 billion a year (adapting all new cars) or up to $24 billion (retrofitting the entire light-duty vehicle fleet) to force it to happen, as opposed to leaving this as the consumer and manufacturer choice that it is today.

Secretary Chu Advised on "Prudent Development" of Oil and Gas

2011-09-20T10:55:00.000-04:00

A news item concerning last week's release of the National Petroleum Council's "Prudent Development" report referred to a recommendation supporting a national tax on carbon. That caught my attention. Given the NPC's makeup, a consensus on such a controversial issue would be surprising. The actual text of the report proved somewhat less dramatic on the climate policy front, but no less worthwhile for its comprehensive assessment of the abundance of North American hydrocarbon resources, as well as the development approach "necessary for public trust, protection of health, safety and the environment, and access to resources." The report doesn't just focus on macro concerns about climate change and other environmental issues, but also on timely details such as the methane emissions, water and land-use impacts involved in shale gas production and other resource development.

For those not familiar with the NPC, the organization is charged with advising the Secretary of Energy on matters relating to oil and gas, though in practice it looks at a much broader array of energy issues. In 2007 I helped with the renewable energy analysis in the group's previous study, entitled "Hard Truths." The current study is one of two requested of the NPC by Secretary Chu; the other will look at future transportation fuels and is due out in the first half of next year. What makes these reports unusual is that they incorporate the views of academics, government officials, non-governmental organizations, and the legal and financial sectors, along with those of the energy industry. In the current study, just under half the participants represented oil and gas companies, while the Emissions and Carbon Regulation Subgroup included members from the National Resources Defense Council and US EPA, and the Environment and Regulatory Subgroup was chaired by someone from the Environmental Defense Fund. I think we'd all benefit from more such "strange bedfellows" collaborations.

The report's specific recommendation on carbon pricing as a mechanism for addressing greenhouse gas emissions appears in the Executive Summary and originates in an entire chapter on "Carbon and Other Emissions in the End-Use Sectors." Although it's much more generic than the Fuelfix article indicated, it's still noteworthy. It deals with the need to internalize emissions costs into fuel and technology choices, with a carbon tax mentioned as just one option among a range of measures for establishing an explicit or implicit price on carbon. It states,

"As Congress, the Administration, and relevant agencies consider energy policies, they should recognize that the most effective and efficient method to further reduce GHG emissions would be a mechanism for putting a price on carbon emissions that is national, economy-wide, market-based, visible, predictable, transparent, applicable to all sources of emissions, and part of an effective global framework."

It goes on to address non-market mechanisms such as performance standards and clean energy standards, and how a policy on carbon should be phased in. While individual oil and gas companies have supported cap and trade or a carbon tax either individually or within multi-industry groups, I can't recall such a broad cross-section of this industry going along with the idea of carbon pricing, even in this non-specific manner.

The timing of this is interesting. It's hard to envision a comprehensive climate bill passing the Congress between now and the November 2012 election, or even being introduced on anything other than a symbolic basis. The pork-laden monstrosity of the Waxman-Markey bill succeeded only in making cap and trade toxic, and I can't imagine a worse environment for introducing any kind of new tax--a price on carbon is clearly a tax--even if the concept behind cap and trade has a solid bipartisan pedigree. Short of the miraculous materialization of a carbon tax as a compromise revenue solution from the deficit-fighting Supercommittee, carbon pricing in the US looks dead until 2013 and possibly well beyond. I'm also starting to see more comments along the lines of this one from the blog of the Information Technology and Innovation Foundation suggesting that policies promoting innovation might be a lot more important in addressing climate change than any level of carbon pricing that could realistically be implemented here.

So whether you regard this recommendation by the NPC as an attempt to restart a stalled debate on carbon pricing, or merely a tardy entry in a formerly crowded field, I think it also signals that the energy industry isn't oblivious to the fact that its emissions--including the lion's share associated with end-user consumption of their products--must eventually be dealt with. Chances are, that will await a return to economic health and stability, when US consumers, voters and taxpayers might be expected to prove more willing to incur the sacrifices this will entail. The report also includes a good perspective on the considerable North American resource upside that could be unleashed with different policies than the ones now in place, and that might just hasten the arrival of more favorable economic conditions for carbon policy.

Renewable Energy Faces the European Debt Crisis

2011-09-15T10:49:00.004-04:00

With all the bad economic news and political turbulence in the US, it's been easy to lose track of the sovereign debt crisis in Europe, which appears to be spreading from smaller, peripheral countries like Greece to affect the banking systems of core European Union members like Italy and France. To read Paul Krugman's column in last Sunday's New York Times, Europe could be on the verge of another financial crisis on the scale of the one triggered by the collapse of Lehman Brothers in 2008. Aside from the global economic consequences of such an event, it would send ripples throughout the energy sector, affecting both conventional and renewable energy markets and participants. While such an outcome is far from certain, it's a worrying scenario to contemplate.

The 2008 financial crisis is a good place to begin looking for the implications of a potential 2011 credit crunch in Europe. Start with oil, which in the fall of 2008 slid from around $100 per barrel to below $40 by mid-December of that year. Of course oil prices had already retreated from a high of $145 that summer, as the weakening US economy and collapsing housing market slowed US demand for oil. Yet it's worth noting that despite their generally more efficient use of energy and higher consumer energy prices, the countries of Europe together import slightly more crude oil and petroleum products than the US does. And as I've noted before, the economies of the EU's Euro area have been partially sheltered from high oil prices by the strength of the Euro relative to the US dollar, in which most oil transactions are settled. Even without a full-blown financial crisis, a sharp drop in the Euro/dollar exchange rate resulting from sovereign debt worries would create a regional energy price spike that could further hamper the EU's growth and reduce its energy demand. OPEC appears to be preparing to trim output for just such an eventuality.

Next consider what happened to renewables, such as wind and solar power. Lending to renewable energy projects in the US dried up in late 2008, as credit became harder to obtain in general, and participants in "tax equity swaps" retreated. Without the generous renewable energy supports in the 2009 stimulus, wind turbine installations might have ground to a halt, and the expansion of solar manufacturing that has recently hit a rocky patch might never have occurred. European projects and suppliers weren't affected to the same degree, thanks to a combination of higher direct subsidies for renewables and robust lending from EU agencies such as the European Bank for Reconstruction and Development.

Those protections look less dependable in a new crisis. European governments have been busily cutting renewable energy subsidies, and growth is already slowing, squeezing local firms like Germany's Q-Cells between a weaker domestic market and low-cost import competition from China and elsewhere. It's anyone's guess whether commercial lending to the renewable energy sector and loans from groups like the EBRD could be sustained in another financial crisis focused on the Eurozone.

A sudden contraction in European funding for renewable energy projects would be felt around the world. Suppliers in the US and Asia have relied on European sales of wind turbines, solar panels and components for much of their planned growth, and the further decline in equipment prices that would follow a big demand drop would leave all but the best-capitalized, lowest-cost competitors scrambling. And even as renewable energy growth has shifted in recent years toward developing countries and away from North America and Europe, Europe has remained the most important market for many of these technologies--particularly for solar PV and offshore wind power--just as Europe has retained the strongest focus globally on reducing the greenhouse gas emissions implicated in climate change. Every aspect of the global energy business has a big stake in the success of Europe's leaders in navigating through the current crisis, but none more than the renewable energy sector.

The American Jobs Act's Poison Pill(s)

2011-09-13T08:44:00.002-04:00

I had a completely different topic in mind for today's posting, but I'll have to come back to the energy implications of a potential European financial crisis later. Since President Obama's jobs speech to Congress last week I have been awaiting the text of the actual proposed bill, rather than the summaries I'd been seeing. It finally came out at the end of the day yesterday. I feel obliged to point out a few provisions that haven't been widely advertised, either in the original speech or on the fact sheet that the White House published. These include several measures related to alternative energy, such as the inclusion of some project categories within the purview of the proposed National Infrastructure Bank, or the funding for putting solar panels on abandoned and foreclosed buildings as part of their rehabilitation. However, I'm not sure how much any of this matters, because the bill sent to the Congress also includes a slate of provisions that were certain to be regarded as a "poison pill"--sections that would preclude passing it on the all-or-nothing basis that the President seemed to be pushing for last Thursday. Energy features prominently in these poison pill measures.

I can't do justice to a 155-page legislative draft in the few hours I've had to review it. I'll restrict my comments today to the "offset" provisions that escaped being mentioned in the administration's fact sheet and reserve comment on the other aspects of the bill for a later date, if necessary. It seems clear from reading Sections 431-442 that the architects of this bill view the US domestic oil and gas industry as a declining cash cow, rather than as the source of new jobs and growth that I described in last Thursday's posting. Those sections set out to repeal every single oil and gas industry tax benefit of which I was aware, and a couple I hadn't even heard of. Included are the Section 199 manufacturing tax credit enjoyed by every other manufacturing company in America, along with portions of the tax code designed to prevent US companies from being subject to double taxation on their global income, protections that I believe their non-US competitors enjoy automatically under the territorial tax systems in use in most developed countries. In a different context I wouldn't have found any of this surprising, but rather a measure of consistency, since the administration has pursued the termination of these benefits in every budget proposal since 2009 and in a number of bills introduced by its allies in Congress.

The surprise comes from their inclusion in a bill intended to provide immediate relief for the large number of Americans still out of work, and possibly to avert a double-dip recession--a bill described as consisting mainly of provisions that have been backed by both parties at various times. However, the legislative history and likely fate of the poison pill provisions is abundantly clear: they have failed every time they were proposed, including in the previous Congress in which the President's party held overwhelming majorities in both houses. Along with the other "offset" provisions, such as those limiting itemized deductions for taxpayers making more than $200-250,000 per year, or going after the tax treatment of hedge fund income and corporate jets, it's hard to see their inclusion in the American Jobs Act as anything other than politically motivated. This morning's headlines reflect the entirely predictable reaction to them.

It's not that these measures aren't a legitimate subject for debate and action. However, that debate is part and parcel of the growing bipartisan consensus on the need for comprehensive reform of our convoluted tax code, in which the majority of current deductions and exemptions, including those for energy, would be sacrificed in exchange for the lower tax rates necessary to make all US businesses--not just a chosen few--more globally competitive. Squandering that opportunity to pay for a short-term boost to the economy would, among other outcomes, leave the US energy sector less competitive and the nation worse off in the long run. Meanwhile, when the Congress rejects these poison pills and proceeds to cherry-pick among the bill's headline measures, it might also adopt the American Jobs Act's final provision, which dumps the problem of paying for it in the laps of the Supercommittee appointed to find the remainder of the deficit reductions agreed in the Budget Control Act of 2011--already a pretty tall order.

If there was ever a chance for a "clean" jobs bill to pass intact, the pursuit in this venue of the administration's long-standing agendas with the oil and gas industry, hedge fund managers, and corporate jet owners erases it. Whatever the outcome of the negotiations with and within the Congress over this bill, you can count on hearing a lot more about these issues between now and next November.

Turning to Energy for Jobs

2011-09-08T12:25:00.003-04:00

Yesterday's Energy Jobs Summit at the US Capitol, hosted by The Hill and API, focused on the potential of the energy sector to add large numbers of new jobs to help alleviate the national jobs crisis that President Obama will discuss in tonight's speech. The figures presented by API and others were impressive, with the oil and gas sector alone capable of creating over a million jobs if provided increased access to US resources. Panelists also discussed "green jobs", including those from energy efficiency projects. Yet I was struck by the inherent tension between today's job-creation imperative and our long-term need for an energy sector that is as productive and cost-effective as possible, in order to support economic growth and reemployment in the roughly 92% of the economy beyond energy. That makes highly productive private-sector energy jobs requiring little or no public investment especially valuable.

In a new study released at the summit, Wood Mackenzie estimates that the US oil and gas industry could increase its employment by 1.4 million by 2030, with a million of those jobs attainable by 2018--more than half in the next two years--under new policies that would lift the current bans on offshore drilling outside the established areas of the Gulf of Mexico and on shale drilling in New York, speed up permit issuance in the Gulf, open up new onshore acreage for leasing, and approve the Keystone XL pipeline. In the process, domestic production of oil and gas liquids could eventually nearly double, while natural gas output would grow by over 60%. Even better, from a deficit-and-debt reduction perspective, this effort would require no new government expenditures and stands to contribute a cumulative $800 billion in additional federal and state royalties and tax receipts.

The potential jobs impact is extraordinary, when you think about it. Oil and gas is an incredibly capital-intensive industry with very high worker productivity--one reason that salaries in the industry tend to be much higher than average. An industry like that is hardly the first place one might think to look when seeking massive job growth. The fact that such growth is even possible is both a validation of the tremendous untapped resource potential we still possess, and an indictment of decades of bipartisan energy policy mismanagement that has preferentially outsourced US energy production, rather than exploiting our own resources.

What about the contribution of "green jobs"? The growth of cleantech--renewable energy and energy efficiency--can certainly contribute to US job growth, yet we should understand clearly that such jobs won't spring forth spontaneously from the private sector without substantial continued government incentives and subsidies. Nor are those a guarantee of success. The US wind industry installed just 2,151 MW of new capacity in the first half of 2011. While that was considerably better than last year's pace of 1,250 MW, it's still 47% below installations in the first half of 2009, despite last December's against-the-odds extension of the Treasury renewable energy grants, which paid out $2.2 billion to wind projects this year. And the recent solar bankruptcies and the aggressive offshoring by solar manufacturers fighting to stay competitive with Asian suppliers also demonstrate that green jobs, other than those in installation and construction, are just as vulnerable to global competition as in any other US manufacturing industry.

Conventional energy jobs aren't immune from competition, either. I was startled to read yesterday that regional refiner Sunoco plans to exit the refining business after more than 100 years. Its two Philadelphia-area refineries will either be sold or shut down by mid-2012, with 1,500 jobs at stake. Prospects for a quick sale of these facilities look poor, because these plants are among the most exposed to global oil prices that have been running more than $20 per barrel higher than for crudes produced in Canada and the US mid-continent. Idling these plants would take a big bite out of east coast gasoline supplies and inevitably lead to both higher product imports and higher gasoline prices in the northeast and mid-Atlantic regions. As someone pointed out at yesterday's session, it's a sad commentary that Sunoco can make more money selling sodas and snacks at its retail facilities than it can refining crude oil.

That dynamic makes the production-related jobs in the Wood Mac study even more attractive: Despite being tied to a depleting resource, US oil & gas exploration and production enjoys a greater sustainable competitive advantage in the global marketplace than either refining or cleantech manufacturing, at least when it has sufficient access to domestic resources.

However, these opportunities also pose a test of our seriousness on the jobs issue. Opening up the Virginia and California coastlines, for starters, along with the coastal plain of the Arctic National Wildlife Refuge to exploration raises a host of NIMBY and environmental concerns. I don't want to trivialize them, but I would suggest that the time when we could afford such sensibilities may have passed, heralded by our continued descent in the rankings of national global competitiveness and the rapid growth of our indebtedness. Creating a number of "green jobs" comparable to Wood Mac's estimate of 1.4 million from oil and gas would require the expenditure of tens to hundreds of billions of dollars the federal government doesn't have, and that the current Congress seems unlikely to be willing to appropriate. It would also risk embedding expensive energy at the core of the US economy, hobbling our non-energy economy, where most Americans are employed.

Yesterday's energy jobs summit was held in the new Capitol Visitor Center, which I hadn't seen before. It's a gorgeous facility and a suitable addition to the paramount edifice of our democracy. However, I was also struck by the contrast it provided with the meeting's subject matter. Recall that the Visitor's Center ended up costing over $600 million, well over twice its original plan. I hope that when the President presents his jobs program tonight, it will be grounded in the crucial distinction between that kind of government-funded, "shovel-ready" project that might put some of our fellow citizens back to work for a few years and an energy-and-jobs resurgence funded entirely by companies and their investors.

Will Solar Bankruptcies Be Different From Ethanol's?

2011-09-02T12:03:00.002-04:00

The solar equipment business appears to be undergoing a shakeout, as three US solar firms have declared bankruptcy in the last few weeks. The most prominent of these was Solyndra, which was notable for its receipt of a $535 million federal loan guarantee. Joining Solyndra in bankruptcy filings were Massachusetts-based Evergreen Solar, which had been ailing for more than a year, and former Intel spin-off SpectraWatt. These failures raise many questions, but one that I haven't seen discussed much is whether these companies' assets will merely be absorbed into other, more successful solar firms, or effectively sold for scrap. I suspect the outcome will be quite different from that of the ethanol bankruptcies that followed the financial crisis.

Observers of these firms might be tempted to look to the ethanol industry for a model of how their bankruptcies could turn out. After all, ethanol represents another green industry--or at least one with green aspirations--the growth of which has also been entirely predicated on government subsidies and mandates. And in a pattern similar to the current situation in the global solar industry, US ethanol producers had invested aggressively in capacity expansion ahead of actual demand and were faced with high costs that couldn't be recovered in the marketplace, particularly when growth slowed and the price of their product fell during the aftermath of the financial crisis. The shakeout that ensued saw a number of ethanol producers, including one the largest, VeraSun, enter bankruptcy with the intention of reorganizing, though most ended up in liquidation. With the exception of a few small facilities, the vast majority of the ethanol plants that were idled by these business failures were acquired and restarted by larger, better-capitalized entities such as refiner Valero. The buyers paid $0.30-.50 on the dollar for the assets, and most now have profitable ethanol businesses, after the legacy cost overhang was removed.

Unlike ethanol, however, the output of solar manufacturing is anything but a commodity. Solar cells, modules and panels are differentiated products and still quite costly, compared to conventional energy sources. Solyndra's cylindrical modules were very different from FirstSolar's thin film modules and SunPower's crystalline silicon modules. It's much harder to envision the assets of Solyndra, Evergreen and other failing solar manufacturers being snapped up by more successful competitors, for several reasons. First, technology differences likely make the idled facilities of little use in the manufacturing processes of the survivors. The location of the capacity is also an issue, because the winning solar suppliers have mainly adopted a strategy of shifting manufacturing to Asia, where costs are lower and supply chains possibly better integrated. So I doubt there's a Valero waiting to put these plants and their employees back to work quickly, nor do current economic conditions give much hope of these facilities being quickly repurposed for some other product. I would like to be proved wrong about that.

Because of the low likelihood of recovering more than a tiny fraction of its investment in these companies, it's crucial that the Department of Energy and its Congressional overseers immediately assess the lessons from Solyndra and ensure that the DOE's Loan Program Office doesn't sow the seeds of further expensive failures in its rush to issue additional loan guarantees before the appropriations for them expire at the end of the month. And just to clear up some confusion in the terminology, although the government's role in Solyndra is usually described as a loan guarantee, suggesting some future, contingent loss if Solyndra doesn't make good on its debts, the actual lender in this case was the US Treasury's Federal Financing Bank. There is nothing contingent about the losses that taxpayers face in this bankruptcy. Those losses will be even harder to stomach if the firm's nearly new factory and production lines aren't put to some good use.

Three Studies Confirm Shale Gas Is Not Worse Than Coal

2011-08-30T09:30:00.006-04:00

For most of this year the enormous potential of shale gas has been clouded by controversy over its alleged climate impact. This began with the draft and later the leaked pre-publication version of a paper from a Cornell professor suggesting that the greenhouse gas emissions from gas were no better than those from coal and might even be worse. When I examined Dr. Howarth's analysis in two postings last December and this April I found that his methodology and assumptions were sufficiently flawed to undermine his conclusions. However, I also recognized the informal nature of my assessment and suggested the need for further scrutiny of this issue by organizations with more resources. That has now taken place, though I claim no credit for it. Within the last month three separate teams have issued reports bearing on this question, and not one of them validates Dr. Howarth's findings against shale gas.

The first of these studies comes from IHS Cambridge Energy Research Associates, addressing not just Dr. Howarth's paper, but also the EPA's estimates of methane leakage that were a key input for its calculations of greenhouse gas emissions from shale gas. Although a skeptic might find reasons to dismiss a study from a consultancy with a large energy industry clientele, the other two studies have connections to groups with unimpeachable environmental/sustainability credentials. One is a collaboration between Worldwatch Institute and Deutsche Bank, while the other paper, published in Environmental Research Letters, is from a team at Carnegie Mellon University with financial support from the Sierra Club. I encourage you to read them, but here are the highlights:

The Carnegie Mellon team focused on shale gas from the vast Marcellus formation underlying several eastern states. (See Friday's posting for some perspective of the scale of this resource.) They found that while the current techniques for developing and completing a Marcellus shale gas well do result in higher methane emissions than from conventional gas wells, the extra methane only increases lifecycle emissions from well to burner tip by 3% on average. This is the case because, "The life cycle emissions are dominated by combustion that accounts for 74% of the total emissions." As a result, when burned in a combined cycle power plant to generate electricity, shale gas results in emissions per kilowatt-hour (kWh) that are 20-50% lower than those from coal, depending on equipment and sources. This is the crucial comparison that Howarth's paper gave short shrift. They also compared shale gas emissions to those from LNG, which we'd now be importing in large quantities had shale gas development not ramped up as it did a few years ago. The Mellon team found shale gas and LNG roughly comparable, with both emitting around a quarter less CO2 equivalent per BTU than diesel fuel. That suggests that shale gas isn't just a lower-emitting fuel for power generation, but also for transportation. Finally, they looked at the possibility of shale gas wells being fractured multiple times, rather than just once during their production life, and found that it would take more than 25 fracturing events to negate gas's advantage over coal.

The Worldwatch/Deutsche Bank study considered both top-down and bottom-up views of shale gas emissions, including that of Howarth. They looked at the average US natural gas supply including current proportions of shale gas and found that the emissions from gas-fired power plants beat coal-fired plants by an average of 47%, even with the EPA's higher figures for methane venting during gas production. They also found that among bottom-up assessments of shale gas emissions, including the one from Carnegie Mellon and another from the DOE's National Energy Technology Laboratory, Howarth's results appear to be an outlier, and that shale gas is materially lower than coal in lifecycle emissions for power generation. And while their analysis was performed using the standard 100-year global warming potential for methane of 25 times CO2, they considered sensitivities ranging up to a GWP of 105:1, at which extreme gas still performed better than coal.

It's probably too much to hope that these independent studies will alleviate all of the concerns that have been raised about the greenhouse gas emissions from shale gas, which will only improve as technology and standards progress. (The studies also highlighted both the need and potential to reduce methane emissions from shale gas development, in order to minimize the extra greenhouse gas contribution, irrespective of any comparison to other fuels.) I also get that with the current mood in much of this country, claims for the game-changing energy potential of shale gas must sound too good to be true, without some fatal flaw. Yet everything I see indicates that the problems associated with shale gas development are all manageable, and that while it isn't a panacea, it does represent an extraordinary opportunity for the US from an economic, energy security and environmental perspective. It's time to recognize this as the tremendous gift that it is.

How Small Is That Revised Marcellus Estimate?

2011-08-26T16:30:00.001-04:00

I see in The Hill that some critics of shale gas drilling are pointing to a revised estimate of the shale gas resources in the Marcellus formation as evidence that there's not enough gas to justify any risk from hydraulic fracturing. Earlier this week the US Geological Survey updated its previous estimate to 84 trillion cubic feet (TCF) of natural gas, a figure substantially less than the estimate of 410 TCF from the Department of Energy. Now, I'd have thought that even without doing the math on this, 84 TCF would still sound like a heck of a lot of gas, even if trillions have become the new billions in another context.

Perhaps cubic feet of gas don't convey quite the same degree of familiarity as barrels of oil, which most people can visualize, so it might be useful to think of this gas in its oil-equivalent terms. Using standard conversion factors, that 84 TCF in the Marcellus equates to roughly 14.5 billion barrels of oil. For comparison, that's half again as big as the original estimate of 9.6 billion barrels for the Prudhoe Bay field on the Alaskan North Slope. (FYI, Prudhoe Bay had produced a cumulative 11.5 billion barrels as of the end of 2007 and was still estimated to have a few billion barrels to go.) In that light, does anyone still want to argue that the Marcellus resource is inconsequential?

Why Haven't Gas Prices Fallen More?

2011-08-25T14:38:00.001-04:00

With the US economy stuck in the doldrums, weakening the demand for oil and its products, and with the fall of at least portions of Tripoli foreshadowing the eventual return of Libyan oil exports to the market, it must seem puzzling that US gasoline prices haven't dropped farther in the last few weeks. As of Monday, the national average price for unleaded regular stood at $3.58 per gallon, only 3% lower than a month ago, when crude oil was just shy of $100 per barrel, compared to around $84 today. On Monday's evening news, CBS ran a segment attempting to explain this apparent disconnect. Unfortunately, they over-simplified the main explanation with a graphic showing cheaper domestic crude oil mixing with higher-priced imported oil. The "A" answer to this question is simpler but not well-understood, even though its elements have been fairly widely reported: Americans are simply looking at the wrong crude oil price, out of long habit. When you compare current gasoline prices and more representative crude oil prices, there isn't much of a disconnect about which to grumble.

The source of this confusion is the price of West Texas Intermediate crude oil (WTI), which for three decades has been the most watched and widely traded oil price in the world, and the basis of what most people mean when they talk about the price of "oil." In fact, there are numerous distinct grades of oil, each with its own price reflecting quality, location and availability. However, until recently most of these prices were based on the price of WTI, plus or minus a relatively narrow band of premiums or discounts, so using WTI as a barometer of all oil prices didn't cause much confusion or inaccuracy. The emergence of a pronounced and lengthy supply bottleneck at the Cushing, OK delivery location for the WTI futures contract has exploded this convenient set of relationships and assumptions.

Because more oil has been going into tankage at Cushing than was leaving those tanks over the last year or so, the price of WTI--itself a category, rather than a single stream of oil--has become massively depressed relative other types of crude oil, not just imported oil but also oil in other locations in the US that aren't affected by the bottleneck. Consider some important examples. While oil produced in Kansas, New Mexico and Oklahoma is all cheaper due to the Cushing effect, Louisiana Light Sweet, which historically traded within a dollar of WTI, is now worth nearly $20/bbl more, putting it much closer to the price of UK Brent crude--the best current gauge of global oil prices--than to WTI. Meanwhile, Bloomberg reports Alaskan North Slope crude (ANS) for delivery on the West Coast at nearly $107/bbl, or $24 over WTI. That's surprising, considering that ANS is heavier and higher in sulfur than WTI, and thus requires more processing. Just as remarkably, California heavy crude at Midway-Sunset is quoted at more than $10/bbl above WTI, when based on history and quality I would expect to see a discount of at least that magnitude. In other words, for now at least, the price of WTI is simply no longer representative of the crude that many US refineries are processing, from either foreign or domestic sources.

When you compare the wholesale price of gasoline from US refineries near the East, West and Gulf coasts to the cost of their crude inputs at around $100 or more, the difference of $15-17/bbl isn't historically unusual. Meanwhile, refineries in the middle of the country have recently been experiencing much stronger margins. This disparity is evident in the second quarter earnings reported by various US refining companies. East coast refiner Sunoco, which hasn't benefited much from cheap WTI, reported a net loss for the quarter, while Valero, with a bigger and more geographically dispersed refining system that includes facilities processing large quantities of WTI-related crude, saw refining segment earnings increase by 39% compared to the second quarter of 2010. The Cushing effect was even more pronounced for the recently merged HollyFrontier Corp., which apparently runs little crude that isn't priced near WTI and saw second-quarter net income almost triple versus 2Q2010. Even after that extra profit margin, gas prices in Tulsa, OK are currently as low as $3.30/gal., or about 15 cents per gallon less than the national average after adjusting for differences in state gas taxes.

Gasoline prices are determined by more than just crude oil prices, though in the long run the two must move together, because the latter represents the largest component of the cost of the former. At least until the bottleneck in Cushing is resolved by new pipeline capacity to the Gulf Coast, one option for which was just canceled, we will need to look beyond our old reliable WTI price indicator in order to compare gasoline and crude prices on a representative basis. I've been paying a lot more attention to the Brent market, and the Wall St. Journal still publishes daily prices for Louisiana Light Sweet and ANS. When and if those indices drop significantly, then it will be time to start looking for a commensurate drop in retail gasoline prices at the pump.

Oil Sands Anxiety Is Overblown

2011-08-22T16:27:00.001-04:00

As I was catching up on a two-week backlog of news after my vacation, I ran across a New York Times editorial with the promising title of "Tar Sands and the Carbon Numbers." Thinking that perhaps the Times might have woken up to the necessity of comparing the lifecycle emissions from oil sands to those from other crude oils, I was disappointed to find its editors perpetuating the common misunderstanding concerning these emissions when viewed only from an oil-production perspective. That's a shame, because it results in the scape-goating of Canadian producers and pipeline companies while conveniently avoiding the soul-searching that ought to accompany a clear understanding that, whether we're talking about oil sands or conventional oil imported from any other source, the vast majority of the lifecycle emissions will occur here, when the products into which these oils will be refined are consumed. It is also condescending toward the sovereign responsibility of our NAFTA neighbor for managing their national emissions under the Kyoto Protocol, which they ratified but we didn't.

The pending State Department review of the proposed Keystone XL pipeline project linking Alberta's oil and oil-sands projects to Gulf Coast refineries has become a hot-button issue for US environmental groups. Producing oil from oil sands, which were more commonly called tar sands until that became a term of disparagement, certainly involves more environmental consequences than most--though not all--conventional crude oils. Since US groups haven't been very successful targeting the oil sands projects in Alberta, where they contribute significantly to Canada's oil output and overall economy, the export pipeline has become a target of convenience. From my perspective, the angst about pipeline safety and acidic bitumen is mainly a red herring; the oil industry routinely handles other crude oils of similar sulfur levels and acidity, usually by adjusting the metallurgy of the pipes and vessels involved. The real issue here is greenhouse gas emissions, which the Times and most other critics of oil sands narrowly compare to those from producing conventional oils.

The Environment Canada report cited by the Times indicates that oil sands production and upgrading result in emissions about 70% higher per barrel than for the production of Canada's average conventional oil. That's in the range of other estimates I've seen. However, what the Times fails to mention is that such "upstream" emissions only account for a fraction of the total lifecycle emissions attributable to any oil. By far the biggest portion--even for oil sands--comes from the combustion of petroleum products by end-users.

So if at least 70% of the emissions from oil sands crude occur in the US, rather than Canada, and if the lifecycle (well-to-wheels) emissions from oil sands only average around 15% higher than for the average US refinery's crude slate, while emitting little or no more than some commonly imported crude oils from other countries, are the XL pipeline's opponents exaggerating its impact? I believe they are, unless they're also willing to take on imports of consumer goods and other products from higher-emitting countries like China. That would be difficult to justify to the World Trade Organization, considering that the US doesn't have a statutory limit on its own greenhouse gas emissions. It might also put us in an awkward position with regard to our exports to countries that have adopted strict emissions reduction targets.

Meanwhile we shouldn't forget that under UN agreements it is Canada that bears responsibility for the extra emissions that oil sands generate in Alberta. The Environment Canada report indicates that oil sands are likely to contribute 11.7% of Canada's GHG emissions by 2020, up from 6.7% in 2005, when Canada's share of global GHG emissions stood at less than 2%. The expected increase in oil sands output would account for essentially all of the projected 7% rise in Canada's emissions over that interval, an amount equivalent to 0.1% of current global emissions. The means by which Canada could address those incremental emissions include improved technology, offsetting cuts in other sectors, emissions trading and offsets purchased from other countries, or the Canadian government could simply choose to restrict oil sands output. Whatever path they choose, we have plenty of our own emissions to consider without going into a tizzy over a Canadian sector that currently emits roughly as much as US livestock waste management.

Trying to control the emissions from oil sands by blocking this pipeline is a perfect illustration of the difficulty of attempting to tackle a complex global environmental problem by focusing on isolated measures that only bear indirectly on the outcomes that matter. The weakness of the Times' argument is reflected in the following sentence, referring to Canada's policies: "The United States can't do much about that, but it can stop the Keystone XL pipeline." The implication seems to be that we would be better off if Canada exported its oil sands to developing Asia, their next best market, relieving us of any associated guilt, even if it made no actual difference in global emissions. I hope that when the State Department decides this matter, it gives appropriate weight to the fact that, other than fuel economy improvements in the US car fleet, our energy ties with Canada represent the single most effective energy security measure undertaken by this country since the oil crises of the 1970s.

US Renewables Need A Fallback Plan

2011-08-04T11:14:00.003-04:00

When I described some of the energy implications of the debt limit crisis last month, the most serious ones were associated with a default by the US government in the event the debt ceiling wasn't extended. That risk has been resolved, for now. But that doesn't mean that everything looks rosy, especially for renewables. Renewable energy technologies and projects are far more dependent on government assistance and policies than conventional energy. The fate of a wide range of federal energy incentives looks highly uncertain, and the impact of that uncertainty is matched by doubts about the health of the US economy and its growth prospects. With the pace of growth already slowing in some renewable energy sectors, any manufacturers or project developers that aren't thinking seriously about how they would manage without federal incentives could be setting themselves up to become roadkill.

Understanding why requires taking a closer look at the debt ceiling bill that Congress passed in the context of the federal budget baseline--never mind that the US Congress has not enacted a budget in more than two years. In April the Congressional Budget Office (CBO) published its assessment of what the economy would look like under the budget submitted by President Obama in February, as well as under the laws already on the books. The latter comprises the "March CBO Baseline" that was mentioned frequently during the debt limit talks and that formed the basis for comparing different proposals. (See Table 1-5 of the CBO report.) Without factoring in this week's debt limit agreement, the CBO projected a cumulative deficit for fiscal years 2012-21 of $6.7 trillion. That figure is important for several reasons.

First, it serves as a reminder that even after the $917 billion of cuts agreed up front and the $1.2-1.5 trillion of future cuts to be determined later this year, the US debt would still grow by more than $4 trillion over the next decade, mainly through increases in mandatory, or non-discretionary spending--entitlements and other untouchables. That won't change even under the deal done by the Senate and House this week; all of its pre-programmed cuts are to discretionary spending, the category into which most federal spending on renewable energy would fall.

But even that $4 trillion figure looks optimistic. As I understand it the CBO baseline assumes that next January 1 all of the Bush-era tax cuts will expire on schedule, resulting in substantial increases in taxes on both ordinary income and dividend income. And that's not just for those earning more than $200,000 per year, or whatever the threshold of "wealthy" is determined to be; it's for everyone. Nor would the Alternative Minimum Tax, which has been biting a growing number of middle class families every year, be indexed as proposed. It also assumes that the Social Security payroll tax will revert to its normal level of 6.2%, up from this year's 4.2%. Barring a dramatic improvement in the economy between now and the end of the year, it seems unlikely that all of those tax increases will be allowed to take effect. That means that the government's revenue through 2021 is likely to be significantly lower than the CBO forecast, because both growth and tax rates are likely to be lower. That translates into bigger deficits and more pressure for deficit reduction.

So the environment for continued support for renewables will be one in which the government's projected deficits continue as far as the eye can see, even after painful cuts, while its ability to continue borrowing on that scale looks suspect. With the main focus of budget cuts falling on the category that includes cash support for renewables, how likely is it that the Congress would extend the Treasury renewable energy cash grant program when it expires on December 31, 2011, or add new appropriations for the Department of Energy's Loan Guarantee Program? And if the Congressional super-committee's proposals include tax reform that would eliminate many "tax expenditures"--tax credits and deductions--then a host of programs such as the solar investment tax credit, the wind, biomass and geothermal energy production tax credit, various biofuel tax credits, and the electric vehicle purchase tax credit, could end up on the cutting block. In the coming scramble to avoid the budget knife, renewables will be competing with better-established programs with broader and more influential constituencies.

It has always been a risky proposition to build companies and industries, the economics of which depended on substantial government subsidies. Some folks could be on the verge of finding out just how risky. If we go down that path, it will probably also result in awkward questions being asked about some of the decisions made by the stewards of these government programs. They should be; I've never understood what kind of due diligence could have resulted in hundreds of millions of dollars in grants or "loans" going to to clean energy and automotive startups with minimal track records, when private investors weren't willing to bet on those risks at that scale. From a national energy policy and strategy perspective, our focus should not be on saving individual companies--no TARP for renewables, I suspect--but on preserving key capabilities essential to ensuring a long-term competitive US position in the global clean energy market.

What would that entail? First, as government funding for renewables becomes constrained it should be focused on R&D at the expense of deployment. Not only would the available money go much farther, but it would also create more options for the future. The next step should be to ensure that whatever the government does spend on deployment should go to projects that are close to being viable without help, or in the case of the military that enhance combat capabilities. That means, for example, focusing solar development assistance on sunny places like the southwest--preferably in proximity to existing transmission infrastructure--and putting an end to paying people to install utility and rooftop solar in places that receive less than about 5 "peak sun hours" (kWh/m2) per day, on average. Again, the money would go farther, and we'd be shoring up nearly viable operations, instead of trying to command the tide not to overwhelm the marginal ones. And finally, as I suggested last week, a greater emphasis on exports to developing country markets, where energy demand is growing at impressive rates and where renewables are becoming increasingly popular, would increase export earnings and employment while participating in volume-related unit cost reductions. And looking beyond renewable energy, the US government has a bird's nest on the ground in the form of the potential lease bid and royalty income from the substantial oil and gas resources that have been placed off limits for various reasons. Tapping those looks like a much smarter source of revenue--not to mention job creation--than selling off the Strategic Petroleum Reserve bit by bit.

If that sounds like a recipe for putting the US cleantech industry on life support after years of robust government-supported growth, then that's consistent with the severity of the fallback plan that could become necessary. The need for this would depend on the priorities set by the special Congressional deficit reduction committee established by the debt ceiling bill, and by the Congress as a whole, along with the subsequent efforts that will be necessary to prevent our long-term debt from growing beyond our ability to service it. Nor would it be quite the starvation diet it might appear, as long as states kept their renewable portfolio standards in place. This isn't a scenario the cleantech industry would willingly choose, but it's one that it can't ignore.

The Next Big CAFE Loophole

2011-08-02T13:14:00.001-04:00

The great pitfall of government policies, no matter how well-intended they might be, is their inevitable unintended consequences. When those are truly surprising, it's hard to attach much blame to the legislators or regulators involved. However, that degree of indulgence shouldn't apply when the unintended consequences are as obvious as the ones inherent in the new fuel economy regulations that were announced with such fanfare last week. After all, an earlier generation of CAFE standards gave rise to what might just be the classic unintended consequence of recent times: the "SUV loophole" that fed a 20-plus-year SUV fad and dug the nation's oil consumption hole much deeper than it needed to be, affecting oil prices, trade deficits and energy security. Now regulators are proposing the creation of a similar loophole for electric vehicles.

I'm not surprised that the coverage I have read on the latest CAFE debate didn't remind the public of the ongoing consequences of treating pick-up trucks and delivery vehicles differently than passenger cars when the first CAFE standards were established in the 1970s. (That loophole was mostly closed just a few years ago.) Who could have guessed that a provision intended to help small businesses would blow up, because an entire generation embraced deluxe versions of such vehicles as their primary transportation--by the tens of millions--undermining the purpose of the CAFE standards to reduce gasoline demand? When I looked at this several years ago, I estimated that SUVs had increased US gasoline consumption by over 400,000 barrels per day, or roughly 5% of total demand, equivalent to the energy contribution of around 10 billion gallons per year of ethanol.

In this case the problem starts with the evolution of Corporate Average Fuel Economy standards from a tool intended solely to improve US energy security by reducing the consumption of petroleum products in transportation, to one encompassing the greenhouse gas emissions implicated in climate change. Although there are important overlaps between these two goals--keeping a chorus of pundits employed touting them--they are not identical in operation or effect. Consider the specifics of the new CAFE proposal.

The "supplemental notice of intent" from the National Highway Traffic Safety Agency (NHTSA) of the Department of Energy, the body that along with the EPA designs and enforces the CAFE standard, spells out the special treatment accorded EVs in the rules that will be forthcoming. It states that EPA intends to give manufacturers multiple credit for each EV, plug-in hybrid (PHEV) and fuel cell vehicle they sell, starting at a multiplier of 2.0 for EVs and fuel cells and declining to 1.5 by 2021, as if these cars somehow canceled the emissions of more than one vehicle. They also intend to treat EVs and the electric portion of PHEVs as having zero emissions, regardless of how the power they use is generated. So in order to meet the tough greenhouse gas standards that accompany the 54.5 mpg CAFE standard, carmakers will have every incentive to produce as many EVs they can. Unfortunately, it's not obvious that this will reduce emissions in the real world, except in the rare instances when EVs recharge exclusively from renewable or nuclear power, which provide only 30% of our electricity mix today, up from 28% in 2005.

One needn't assume that EVs might be recharged using only coal-fired power to see that they aren't always a big improvement, emissions-wise, over non-plug-in Prius-type hybrids or clean diesels. Using the average US grid CO2 emissions of around 1.3 lb/kWh, a Nissan Leaf getting 3 miles per kWh is responsible for the emission of roughly 200 grams of CO2 per mile traveled. By comparison, a 2011 Prius with its 50 mpg EPA average emits around 196 g/mi. A more rigorous comparison would require a full well-to-wheels lifecycle assessment, but that is precisely what the new CAFE rules eschew in the interest of leaning on the scales to help today's preferred vehicle technology.

Subject to further refinement, this back-of-the-envelope analysis suggests that skewing the new CAFE regulations in favor of EVs isn't going to do much to reduce greenhouse gas emissions. Its main advantage is in reducing oil consumption, since less than 1% of our electricity is generated from oil. But if we only cared about oil and not emissions, producing gasoline from domestic coal--in the same manner as a sizeable fraction of South Africa's fuel supply--would be equally effective at backing out oil imports. Meanwhile, a gallon of gasoline saved by an advanced internal combustion engine with stop-start technology and other low-cost efficiency features would be worth exactly as much as a gallon saved by an EV, while costing dramatically less. That's especially true when you factor in the $7,500/car EV tax credit, which I can't help thinking will be a prime target when the joint Congressional committee on deficit reduction established by the debt limit bill passed by the House of Representatives last night and by the Senate just a few minutes ago sets up shop this fall.

The unintended consequence that is easily envisioned from this special treatment of EVs is a massive over-investment in a particular and still very expensive vehicle technology, at the expense of other, less costly and more cost-effective technologies. I certainly accept that EVs represent a major long-term trend in cars, but I don't believe that their development requires fiddling with the CAFE rules in this way. Nor is it obvious that US manufacturers enjoy any particular competitive advantage in producing EVs, which depend on ingredients such as rare earths for which we are even more import-dependent than for oil. If saving oil and emissions is what we really care about, then we are entitled to expect that new fuel economy regulations would focus squarely on those outcomes, without being diverted by the industrial policy fad of the moment. Perhaps this will be one of the topics taken up by the House Oversight and Government Reform Committee of the Congress as it investigates the new CAFE rules.

The Market for US Cleantech Is Out There

2011-07-29T09:47:00.000-04:00

One of many press releases I received this week highlighted the new Clean Energy Export Principles developed by a "multi-industry coalition, which was coordinated by the National Foreign Trade Council, and U.S. government representatives." They recommend a significantly expanded and technology-neutral effort by the US government to promote exports of clean energy gear, including equipment for the smart grid, energy efficiency and energy storage. They also suggest the need to reduce trade barriers affecting such exports globally, not just to help US industry but to increase the effectiveness of efforts to mitigate climate change. I can only hope that the administration embraces these recommendations as enthusiastically as it has other aspects of its green agenda, because these principles are aimed squarely at the biggest opportunities for clean energy technology and emissions reduction, outside our borders.

It doesn't really matter whether these principles reflect the sensible recognition of trends in the global energy marketplace, or merely make a virtue of necessity at a time when government support for domestic clean energy deployment is approaching its statutory and practical limits. However the current debt ceiling crisis is resolved, the capacity for the federal government to continue providing generous incentives for cleantech deployment, either through the Treasury renewable energy cash grants that have totaled nearly $8 billion to date, or the Department of Energy Loan Guarantee program that has backed or directly funded more than $40 billion in loans for clean energy projects is likely to be far more constrained in the future.

Nor is this simply a question of money. The whole notion that we are in some kind of renewable energy deployment race with China or any other country ignores the big differences in our respective levels of economic development. If there were such a race we would be bound to lose, and not because we don't have the right policies or strict enough regulations, but because US electricity demand is growing slowly and is backed by both ample generating capacity and ample supplies of relatively cheap and low-emitting fuel. Meanwhile both electricity demand and capacity in the developing world are growing rapidly, and the indigenous generation fuel in good supply is mainly coal. That, together with the disparities in economic growth coming out of the global recession, is the underlying reason why investment in renewable energy in the developing world apparently surged past that in the developed world last year.

With cleantech supply chains already substantially globalized, the leaders in this industry must be global in scope and focus. US manufacturers of cleantech equipment shouldn't ignore the US market, but they must be realistic about it. Even with growing opportunities in the smart grid and solar power, the US will account for only a small fraction of the global market for such goods and services, as growth shifts away from the mature markets of Europe and North America. The market share that counts, for competitive strength and economies of scale, is global market share. And global sales will provide the volumes needed to drive down costs for both exports and domestic installations. There's a huge, growing market for cleantech, and it is mainly out there.

The Anthropocene and Other Topics

2011-07-27T08:23:00.003-04:00

For the first four years of this blog I published nearly every weekday, and as time went on occasionally struggled to find suitable topics. Lately, I've been running across more good blog topics than I could conceivably cover. I think more is at work in that than my having scaled back the blog's frequency; energy has become an integral part of so many crucial conversations in the meantime. So instead of my customary single topic, today's post includes three essentially unrelated ones, all of which I thought merited sharing with my readers.

The first item concerns compact fluorescent lighting, those "CFL" bulbs people seem to either love or hate, and upon which many base unrealistic expectations of energy and emissions reductions. According to the tracking of NEMA, the Association of Electrical and Medical Imaging Manufacturers, US demand for CFL bulbs has declined for four straight quarters, while demand for the incandescent bulbs that are being phased out by law has revived to 79% of the market. This shift begs for deeper analysis. Is it the result of consumers stocking up on 100 Watt incandescents before they disappear from store shelves next January 1 and become a new kind of black market commodity, or is it more along the lines of what happened to tire sales after steel belted radials were introduced? Like the latter, CFLs last a lot longer than the traditional product they're replacing, and at some point one would expect sales to plateau at a much lower level than incandescents previously held. Or is it the case, as in my household, that CFLs are simply not viewed as a satisfactory replacement in all the fixtures where they could be placed, because of a combination of lighting quality, cost effectiveness, and concern about potential mercury contamination?

Now let's turn to plastics. Two stories, both involving Dow Chemical, caught my eye. In the first, Dow is investing in a facility to make polyethylene, a very common plastic, from ethanol in Brazil. As the article in Technology Review notes, Brazil is one of the few places that would make sense. The process of producing ethanol from sugar cane is so energy-efficient and cost-competitive that ethanol can sensibly be substituted for the petroleum products from which it might otherwise be produced there. In the other story, Dow recently announced a process for extracting most of the available energy from non-recycled plastic waste. Taken together, these two items challenge our traditional view of the relationship between oil and plastics: not only does oil no longer have a lock on the feedstock market, but it could face competition from waste plastics in end-use energy applications, or possibly even as a potential source of synthetic oil, as I noted a couple of years ago.

Finally, I'd be remiss if I didn't recommend an article from the May 28, 2011 issue of The Economist, which had been in my reading pile for weeks. It suggests that we are living in a new epoch of the earth called the Anthropocene, signifying humanity's having become the equivalent of a force of nature in our effect on the earth and its systems. I'm intrigued by this not just because it dovetails with my view that essentially everything we do on a civilization-wide scale, including energy production and consumption, agriculture, transportation and public works, has consequences for the entire planet, but also because of its implications for what sustainability is likely to mean going forward. If the cited scientists are correct, we influence the earth's systems as much as the climate does, with climate change only one example of our impact.

The corollary to that is that an earth restored to the conditions that prevailed in the Holocene epoch from which we emerged--before we started messing with the nitrogen cycle, the carbon cycle, and other key processes--could not support the population expected by mid-century. There's just no going back to our bucolic roots, but neither is that a justification for the large-scale destruction of the environment needed to sustain humanity. The other interesting twist to this is that it's possible we will need the energy from the large-scale harnessing of solar power to conduct the intentional geoengineering that might be necessary to get the global climate back on an even keel. It's the sort of thing that gives environmentalists nightmares but makes believers in an approaching Technological Singularity nod sagely.

Energy Crisis Prices Persist

2011-07-22T09:37:00.005-04:00

Watching oil prices is a hard habit to break, once formed. They're always moving up and down, sometimes for obvious reasons and sometimes not. It has probably escaped most observers' notice that the magnitude of this year's price moves has exceeded the total nominal price of oil that prevailed not many years ago, yet without the sort of apocalyptic events that one might expect such volatility would require. Perhaps that's because we seem to be stuck in the middle of an ongoing, slow-boil oil crisis from which the financial crisis and the demand contraction that accompanied the global recession only provided a brief respite. In fact, when you glance at the oil price trend in real dollars over the last 40 years, it's apparent that prices are back at the level associated with the peak of the oil crisis of the late 1970s and early 1980s:

One reason I've been paying extra attention to oil prices lately is that I've been observing the impact of the coordinated release from the US Strategic Petroleum Reserve (SPR) and strategic reserves of other members of the International Energy Agency. So far, my initial assessment that it would have little lasting effect seems to have been validated, though I'll reserve judgment until the oil is actually delivered during August, when we might see the market respond to the increase in commercial oil inventories that should result. Robert Rapier had an excellent posting yesterday on the folly of this decision. My view is, if anything, less flattering. Not only was this choice unwise, but it also appears to have been ineffective, which in the current economic climate is an even more damning assessment.

The modest response to this move tells us something about the fundamentals of the market. In the past, an SPR release on this scale would have crushed prices--not just for a few days, but for months at least. Consider the release that accompanied the start of the first Gulf War in 1991. Only about half of the nearly 34 million bbls authorized was eventually sold, but the price of oil dropped by 33% overnight and took 13 years to recover to the peak it had reached during the lead-up to Desert Storm. By comparison, the announced release of 30 million bbls from the US SPR--the sale of which was fully-subscribed--and another 30 million bbls from other IEA members managed to depress the price of oil by only around 5% for a week or so. As of this morning Brent crude, the global marker, is $4/bbl higher than it was on June 22nd. And as of this Monday's survey, the average pump price of unleaded regular in the US was also higher than before the President announced the release.

The market's tepid reaction to the SPR release suggests that oil prices have been driven up by more than just speculators. Speculation may be playing a role, but it's more like the head on a glass of beer. Beneath that froth lies the robust demand growth in the developing world, which has pushed global oil consumption to a record level of 89 million bbl/day this year. On the supply side, some point to incipient Peak Oil, but characterizing the crisis we're in doesn't require a grand theory. In addition to the curtailment of production from places like Libya and Yemen, and OPEC's desire to keep a lid on output to preserve their revenues, there's a fundamental mismatch between the companies that have the capital and the desire to invest in new production, and the willingness of some governments to grant access to the resources, whether in the Middle East or the US. All of this is compounded by the inherent time lags in resource development, which can range from 5-10 years, depending on the technology and permits required.

As different as the causes and symptoms of this crisis are from those of the 1970s, the broad outline of solutions remains quite similar: Reduce demand, increase supplies, and diversify our sources of energy. We have more and better options than in 1979, but still no miracle cures.

Energy Implications of a Federal Default

2011-07-18T14:49:00.000-04:00

Much of the attention concerning a possible failure to increase the US debt ceiling by month-end has focused on the government's ability to borrow, and on how individuals might be affected, whether as recipients of social security, pay or pensions from various branches of the federal government, or as consumers seeking car loans or mortgages. I haven't seen a lot of discussion about the potential impact on energy, other than some speculation about higher oil prices. As I started to consider how different categories of energy might be affected, it occurred to me that a list, or a set of lists was the best way to tackle this. It's not intended to be comprehensive, and I would welcome your input on what I've overlooked.

The first category of energy impacts concerns companies or individuals who are awaiting a check or wire transfer from the government, for which funds might not be available in the absence of a prompt deal to extend the debt ceiling. These include:

Projects that have qualified for Treasury renewable energy cash grants, but have not yet received the funds, or that hope to qualify shortly. Since this program started in 2009, the Treasury has disbursed $7.8 billion to project owners and developers.
Companies that sell energy to the federal government and its various branches. This includes start-ups selling renewable aviation and diesel fuels to the Department of Defense, as well as firms selling the government the large quantities of electricity and conventional fuels it uses. (I will be attending a joint Army/Air Force energy forum tomorrow.
Companies with contracts related to various energy efficiency programs initiated under the stimulus or previous legislation, including weatherization.
Individuals who receive federal energy assistance.

The next category includes companies that aren't expecting cash, but are relying on loan guarantees from the federal government to help them secure more attractive financing--or in the case of some risky projects and technologies, any financing at all--either from commercial lenders or directly from the Federal Financing Bank.

Beneficiaries of the Department of Energy's loan guarantee program that have not yet secured loans are a good example of this category. Note than many of the projects listed on the Loan Program Office's site have only obtained conditional approvals, indicating that their financing has not yet closed. They would be vulnerable either to a protracted default or one that undermined confidence in the government's "full faith and credit" to such an extent that a federal loan guarantee wouldn't aid in lining up lenders.

The next category covers the large number of entities that benefit from energy-related tax credits and deductions. Although they aren't directly vulnerable to a default, they are exposed to the risk that their particular tax benefits might be canceled or reduced as part of an agreement between the Congress and White House to extend the debt limit.

Refiners and others blending ethanol into gasoline and collecting the Volumetric Ethanol Excise Tax Credit.
Producers of biodiesel and cellulosic biofuels and small ethanol producers, all of which receive tax credits for producing renewable fuels.
Oil and gas companies benefiting from the various tax credits and deductions that have been in the administration's cross-hairs since it took office.
US manufacturers, including oil and gas companies, power generators, ethanol producers, and a wide array of non-energy recipients of the Sec. 199 deduction for manufacturing their products in the US.
Purchasers of electric vehicles eligible for the tax credit of up to $7,500 per car for EVs and qualifying plug-in hybrids, or up to $4,000 for natural gas vehicles and other alternative fuels.
Car manufacturers and dealers depending on these tax credits to help sell their vehicles.

Then there's the effect on the vast majority of us who aren't in line for an energy-related grant, loan guarantee, or tax credit, but could see the ripple effects of all of these concerns in our energy bills, along with the more basic question of how a default might affect the price of oil and other mainstream energy sources. That subject deserves a posting of its own, but my quick take on this is that while a default could certainly drive up oil prices by means of a weaker dollar, that could be offset by the reduced oil demand that would follow the slowing of the US and global economies in the aftermath of a default. Up, then down, perhaps? I will join you in hoping we don't have to find out the hard way.

Carmageddon, Hybrid Cars and Diamond Lanes

2011-07-14T09:50:00.002-04:00

The looming "Carmageddon" in Los Angeles made the front page of today's Wall St. Journal, as residents there brace for the two-plus day closure of ten miles of the famed San Diego Freeway (I-405) this weekend. The disruption is apparently required to allow for some demolition necessary for the construction of new high-occupancy vehicle (HOV) lanes on the 405. As locals assess their alternate routes--there are many--they might also want to spend some time thinking about who will be allowed to drive in those new HOV lanes. California recently decided to deny ordinary (non-plug-in) hybrid cars that privilege, in preference to plug-ins and other alternatively fueled vehicles. The new policy and the one it replaces both reflect muddled thinking, but I would argue that abandoning hybrids at this juncture is a mistake, at least if saving gas is still a priority in the Golden State.

I routinely commuted on that stretch of the 405 between the Santa Monica Freeway (I-10) and the Ventura Freeway (US-101) when I lived on the West Side and worked in Mid-Wilshire and later in the San Fernando Valley. I carpooled for part of that time but for most of it, like most other Angelenos, I drove alone. I would have found the option of going solo in the HOV lanes a very appealing way to avoid the frequent stop-and-go traffic, and that's why offering that right to hybrid cars has been a useful non-cash incentive to boost their sales. State officials apparently concluded that normal hybrids are now commonplace, so the incentive should be shifted to the even more efficient cars now becoming available. They have emissions data on their side, because California's electricity mix is dominated by hydropower, nuclear and efficient gas turbines, plus a growing contribution of non-hydro renewables, though it also includes some imported coal-fired power from the Four Corners region. A plug-in should indeed emit less CO2 (directly and indirectly) than a Prius-type hybrid under those conditions.

What I think the state's regulators have missed, however, is that simpler hybrids, which currently enjoy no other incentives, still look like an equally effective way to save gasoline. That's particularly true if most buyers of plug-in cars are choosing them in preference to non-plug-in hybrids, rather than instead of gas-guzzling conventional cars. It comes down to the simple, but often counter-intuitive math of fuel economy the way we calculate it in the US, yielding diminishing gallon savings for increasing miles per gallon (see chart below.) Consider a 50 mpg hybrid that replaces a 25 mpg conventional car. Driven 12,000 miles per year, this choice saves 240 gallons per year. Trading in that hybrid for a plug-in like a Nissan Leaf only saves an additional 240 gallons per year, while a Chevy Volt would save somewhat less than that, unless it were never filled up.

Moreover, plug-ins didn't lack for incentives already. In addition to the federal tax credit of up to $7,500 per car, California offers its own rebate of up to $5,000 for qualifying plug-ins, which also receive discounted rates for electricity. Then there's the money the state is investing in recharging infrastructure. Whether or not the aggregate level of incentives is justified on grounds of economics, environmental and energy security benefits, throwing the HOV benefit on top of them seems like an unnecessary gilding of the lily. The 85,000 hybrids that were given the sticker allowing HOV access for solo drivers still represent a tiny fraction of the state's 39 million registered motor vehicles, and offering 40,000 new stickers for EVs won't make a noticeable dent in California's emissions, or its 40 million gallon-per-day gasoline consumption.

I don't know whether this weekend's Carmageddon will live up to its name, or like L.A.'s 1984 Summer Olympics result in lighter-than-normal traffic because motorists had enough notice to allow them to plan ahead. Yet it does seem that continuing to offer HOV access for non-plug-in hybrids would provide a meaningful incentive for a class of gas-saving vehicles that still represents only around 3% of US car sales, at no cash cost to the state. And if the state is truly concerned that a growing hybrid population could choke the HOV lanes and make them less useful for everyone, an even better option would be to auction the stickers, with only buyers of hybrids, plug-ins and other alternative fuel cars eligible to bid. The proceeds might be sufficient to relieve the state's battered budget of a large portion of the cost of the cash subsidies they're already paying on plug-in cars.

Ethanol's Future Without Subsidies

2011-07-12T10:47:00.001-04:00

Given the remarkable longevity of the tax credit for ethanol blended into gasoline, it seems fitting that it would take a problem on the scale of the massive US deficit and $14 trillion federal debt to trigger its demise. Yet despite a widely-publicized Senate vote in June and the announcement of a key compromise among three Senators last week--two from the corn belt and one from the West Coast--it remains unclear just when and how the cancellation of this subsidy will become law. And because the fate of the subsidy is linked to that of the parallel tariff and duty on imported ethanol, the US ethanol industry faces not just the prospect of a more challenging market by year-end, but one that could include competition from foreign suppliers with special advantages under US renewable fuels regulations. Some producers may end up wishing they hadn't expanded output quite so fast.

I've followed the ethanol subsidy for much longer than I've been blogging about it. As I was reading a two-part assessment of the changing ethanol situation in Biofuels Digest it occurred to me to take the dusty report from my long-ago M.B.A. project off the shelf. Its topic was the market for "gasohol", gasoline blended with up to 10% ethanol, on the West Coast in the early 1980s. At the time, blenders received roughly the same tax credit as today's $0.45 per gallon of ethanol blended, thanks to the 1978 Federal Energy Tax Act and the Highway Tax Act of 1983. That benefit was a lot more generous in then-current dollars than now, but much smaller in aggregate. In the intervening decades, gasoline with ethanol has expanded from around 2% of the market to nearly 100%. In much of the country it is now harder to find gasoline without ethanol than it was to find gasohol back then.

That's only one indication of the tremendous success this industry has enjoyed, due almost entirely to government policies like the Volumetric Ethanol Excise Tax Credit and the national Renewable Fuels Standard (RFS) established in 2005. In fact the eventual demise of the ethanol tax credit was virtually guaranteed by the passage of an even more ambitious RFS as part of the federal Energy Independence and Security Act of 2007. Under the RFS, blending ethanol into gasoline in steadily increasing proportions became mandatory, rendering the tax credit paid to refiners and other gasoline blenders redundant. Just as importantly, it expanded the scale of ethanol blending to such an extent that the total annual cost of the so-called blenders credit grew from roughly $1.8 billion in 2005 to a projected $6 billion this year--too big to ignore.

The deal agreed by Senators Feinstein (D-CA), Klobuchar (D-MN) and Thune (R-SD) last week would reportedly result in the early termination of both the ethanol tax credit, which was due to expire at the end of 2011 but could have been renewed, and the corresponding ethanol import tariff. It would devote $1.33 billion of the unspent funds to deficit reduction, while diverting another $668 million to extend tax credits for alternative fuel refueling (or recharging) infrastructure and cellulosic biofuel tax credits. This outcome appears to have pleased at least part of the ethanol industry. However, in order for it to become law, it must still be voted on by both houses of Congress, either by itself or as a provision within another bill, perhaps even the debt ceiling extension package that could emerge from the ongoing deliberations between the House, Senate and White House.

The ultimate effect of these changes on the ethanol industry remains somewhat uncertain, though it is hard to see them as a net positive, other than the longer-term benefit of supporting infrastructure investments that could be crucial in resolving a key bottleneck in ethanol distribution. Without much higher sales of gasoline blends containing more than 10% ethanol, the market is already nearly saturated with ethanol, and that's before factoring in the additional imports that the elimination of the tariff is likely to promote. And at least in the case of ethanol derived from sugar cane, those imports will enjoy an important advantage over ethanol derived from corn: most of them are likely to qualify for the stricter designation of "Advanced Biofuel" under the RFS, a category for which the annual quota is just starting to take off, and that cannot be satisfied by corn ethanol but also seems unlikely to be filled by domestic cellulosic ethanol any time soon.

Biofuels Digest suggested that long-dated ethanol futures have already nose-dived in anticipation of the end of the tax credit. It's true that ethanol for delivery in January 2012 is trading for around $0.35/gal. less than the August 2011 ethanol futures contract, reflecting a widening of ethanol's discount to the gasoline futures contract over that interval of around $0.11/gal. However, it also seems highly relevant that corn futures have recently retreated from their early-June peak of nearly $8/bushel to $6.80, with December corn--from which January ethanol might be produced--down at $6.20/bu. That leaves ethanol producers a small but still positive margin on that January futures price. So it is hardly certain that the end of the tax credit will, by itself, stress US corn ethanol producers. If anything, refiners and consumers--who have arguably received most of the benefit of the credit in recent years--stand to lose the most from its disappearance.

Import competition could have much more serious consequences, as the fuel ethanol industry truly begins to globalize. Brazil is the big player internationally, even if the recent rise in sugar prices and a smaller-than-expected cane crop have created the bizarre situation of Brazil actually importing corn ethanol from the US. The historically fragmented Brazilian sugar cane industry is currently both expanding and consolidating, led by companies like Raizen, the new joint venture between Shell and Cosan, which has indicated plans to double its ethanol capacity to 5 billion liters per year (1.3 billion gallons per year.) Nor is Brazil the only tropical country that can grow cane and produce sugar, ethanol and electricity from modern facilities. The Brazilian model could be replicated elsewhere in Latin America, the Caribbean, and West Africa. Not all of that extra ethanol will come here, but enough of it could, helped by the RFS, to put an effective cap on US ethanol prices. I'm not aware of a similar constraint on corn prices.

The US ethanol industry has matured in the last three decades. Today's ethanol plants are much more efficient than the ones supplying the small quantities used for gasohol in the early 1980s, and they now consume around 40% of the US corn crop. The industry has expanded on a scale that would have seemed nearly impossible thirty years ago, though in my view it has in the process fallen into the classic overcapacity trap of commodity manufacturers. Whether that situation is temporary or permanent depends on the success of blends containing more than 10% ethanol--blends that the market has so far treated with indifference. But either way, when the training wheels finally come off with the end of the blenders credit and import tariff, we shouldn't be surprised to see more of the small and higher-cost producers fall by the wayside. That will have local consequences, but the ethanol industry will survive, just as it survived the bankruptcies of some ethanol producers during the financial crisis. Ethanol is here to stay, and it is about to embark on a new career as a more normal commodity.

A New Era in Space

2011-07-08T07:06:00.000-04:00

In the lead-up to the launch of the last space shuttle, "Atlantis", I've been seeing a number of articles on the general theme of an era ending. This week's Economist went so far as to suggest it marks the "End of the Space Age." I sincerely hope they are wrong, and not just because I have followed the US space program avidly since before the first moon landing, but also because of my primary focus on energy. Most of the resources of the solar system, including most of its energy resources, lie outside the earth's atmosphere. To choose a relevant example, space solar power (SSP) might not contribute significantly for decades, but it still looks like an important option for ensuring that energy limits don't constrain our long-term prosperity after the ages of oil and coal wind down.

One presentation that I still recall vividly from the many meetings involved in the economic review of NASA's "Fresh Look" approach to SSP in the 1990s, and from my time on NASA's oversight committee for SSP, dealt with the crucial role of a low-cost, high-frequency launch system in putting the components of solar power satellites into orbit affordably. Even then, it was clear that the current shuttle was not that system. It was equally clear that the traditional alternative of disposable rockets couldn't come close to the $ per pound-on-orbit threshold required. He was proposing a second- or third-generation system using unmanned reusable cargo vehicles that would land like airplanes. This was before the recent advances in drone aircraft.

I wonder what that scientist would recommend today. Perhaps he would build on some of the private spacecraft designs currently under development, such as those of SpaceX, Orbital Sciences and XCOR. However, assembling a solar power system over dozens or hundreds of launches involves very different requirements than taking tourists into space or sending astronauts back to the moon or on to Mars. In any case, without reliable access to space--traveling as passengers on Russian vehicles using a 50-year-old design doesn't count--the benefits of space will be limited to capabilities like the communications and remote sensing of today's satellites. Those are impressive enough and have transformed our world and our view of it, but they can't supply us with the concentrated energy to power cities or industries.

During the space shuttle program's 30-year history, shuttle crews accomplished extraordinary feats at tremendous risk, and sadly some of them paid with their lives. It's interesting to contemplate, as a noted space commentator did this week in Technology Review, whether the right shuttle design was chosen in the early 1970s, though mainly from the perspective of what it might tell us about what our next steps in space should be. I'm as intrigued as anyone by the prospect of resuming manned exploration beyond earth orbit, but it's hard to square the cost of that with the deep cuts that must be made elsewhere to set our financial house in order. A serious examination of the techniques and hardware necessary to deliver space resources for use on earth--now that it wouldn't have to fit an existing shuttle's capabilities--could provide a suitably pragmatic focus for NASA in the current environment.

I have a hunch that a goal of obtaining non-polluting energy from space would go a lot farther towards galvanizing the necessary public support for NASA than the next planetary mission--which incidentally might be easier to construct with the capabilities that a more nuts-and-bolts effort might create. Either way, while it's nice to look back at past achievements, I'd much rather be looking ahead to the accomplishments of the next era in space.

A Shale Gas Bubble?

2011-07-01T10:08:00.001-04:00

Last weekend the New York Times published a front-page article raising serious questions about the true scale and economics of the production of natural gas from shale, invoking the specter of another asset bubble. To say that this created a buzz would be an understatement. Yet while the article addressed important concerns, it mischaracterized the overall situation by conflating the fortunes and prospects of individual companies with the long-term viability of exploiting the underlying resource. Even if some prominent shale-focused companies were to fail, that wouldn't alter the quantity of shale gas in the ground. It also wouldn't change the fact that shale gas accounted for more than 15% of domestic US natural gas production in 2009 and is expected to supply at least 25% by 2035, even in the most pessimistic shale gas scenario included in the Department of Energy's 2011 Annual Energy Outlook. Comparisons to Enron or the Dot-Com bubble make little sense when the shale gas bonanza has shifted the fundamentals of physical supply and demand, irrespective of its effect on the equity values of companies in this sector.

I understand why the Times' assessment might resonate just now. In the aftermath of a series of asset bubbles and the economic contractions they helped trigger, skepticism about claims such as the game-changing potential of shale gas comes naturally, particularly when it appears that some industry and government insiders don't share the consensus enthusiasm for shale gas. There's nothing wrong with asking some tough questions, particularly given the scale of the opportunity and what it could mean for long-term electricity prices and the displacement of higher-emitting fuels. I have made a career of asking tough questions, myself. However, I also hope that these government officials asked questions at least that tough before issuing billions of dollars in cash grants, loans and loan guarantees to renewable energy developers and electric vehicle start-ups with shorter track records than most shale drillers, and facing greater uncertainties.

That's not as much of a non sequitur as it might seem, because of the prominent placement of the article and its context within the series of probing articles the Times has done on shale gas and its main enabling technology, hydraulic fracturing or "fracking." I wouldn't be surprised to learn that that the paper's editors, like many in environmental circles, find the development of this resource to be an unwelcome diversion on the path to a lower-carbon future. After all, while natural gas emits much less greenhouse gas than coal over its lifecycle, particularly for electricity generation, it certainly emits much more than wind, solar and geothermal power. Many renewable energy projects have struggled to compete with the low cost of gas-fired power generation that shale gas helped bring about. Ultimately, the price of natural gas lies at the heart of both the concerns raised in Sunday's story and the worries of many environmentalists that cheap gas could delay the shift to renewables by many years--although I would remind them that gas-fired power also looks very helpful for enabling the grid to accommodate more renewables.

If I thought that natural gas prices were likely to remain at their current level of roughly $4 per million BTUs indefinitely, I might share some of those concerns. I'd also be even more vocal than I have been in highlighting the opportunity for gas to displace imported oil at an energy equivalent of under $25 per barrel. However, there are good reasons to believe that today's prices aren't just the result of abundant shale gas, but also of a weak US economy. It's no coincidence that they fell precipitously as the recession was starting to bite in the second half of 2008, in tandem with oil prices. Stronger growth is likely to bring more demand from existing users, along with new demand of the type I highlighted in Monday's posting. If the futures market reflects the current consensus on prices in the future, then that consensus expects a fairly steady increase in gas prices in the next few years, reaching $6/MMBTU by late 2015.

By itself that would resolve many of the concerns of environmentalists about competition between gas and renewables, as long as renewables like wind and solar continue on their recent cost-reduction trajectories. It would also negate many of the notions in Sunday's article, because at $6 the project economics of most of the shale plays the Times considered would be cash-positive or at least cash-neutral. That means a driller could finance development without having to bootstrap into it by selling reserves, a practice that appears to have inspired the Times' references to shale gas as a form of Ponzi scheme.

Meanwhile, at an average of $6 per MMBTU the price of natural gas would still be lower--and possibly less volatile--than in the boom years of the last decade, while remaining cheap enough to eventually displace a lot of imported oil. The resulting $35 per oil-equivalent barrel would have looked expensive as recently as 2003, but it would be a bargain in today's world.

In its larger context Sunday's article, by making a case that the future output of shale gas could be much lower than has been assumed, lays the groundwork for opponents of shale development to claim that it is both too risky and not material enough to be worth the risks they attribute to it. After studying this issue carefully, I am convinced that neither aspect of that proposition is correct. Shale can be developed safely, particularly when following guidelines such as the Operating Principles for shale and tight gas that Shell just put out. And shale certainly looks big enough to make a significant difference in the energy balances of entire countries, including both the US and China. Not every company producing shale gas will be financially successful, but that's been true in the oil patch since Col. Drake drilled his first well in 1859. In the unlikely event that shale gas turned out to be a bubble, it wouldn't be the first one in the history of oil and gas exploration. However, if it were a bubble, like previous ones it would leave behind a large number of wells that will be producing vitally important energy for many years to come, whatever the fate of the companies that originally drilled them.

What New Ethylene Crackers Tell Us

2011-06-27T09:20:00.001-04:00

Sometimes a news item informs us about much more than the event in question. Recent announcements of new petrochemical projects in the US fall into that category. Both Shell and Dow Chemical are planning new ethylene crackers in the US, a market in which established ethylene facilities were being shut down only a few years ago, as part of the demand destruction necessary to balance natural gas demand with shrinking US supplies. Anyone looking for further indications of the game-changing nature of shale gas need look no further than these projects. Yet they also give us intriguing hints about two other situations of great interest: global oil prices and US economic growth.

The Shell project is of particular interest, because of its location. The company is apparently planning to locate it in Appalachia, where it will depend on the byproducts of natural gas produced from the giant Marcellus shale deposit. Considering that most of the other ethylene crackers in the US are located on or near the Gulf Coast, where gas can be supplied from numerous onshore and offshore fields, that's a remarkable endorsement of the potential of the Marcellus. You just wouldn't leave such a facility dependent on one gas field if that field weren't both very large and likely to be producing for a very long time. Anyone suggesting that shale gas is a flash in the pan should look long and hard at this project, as I'm sure Shell has done.

It's also worth pausing to recall the way Shell approaches projects like this. Shell is one of the pioneers of scenario planning, and its business plans are all based on its periodic, carefully developed views of different potential futures. I wouldn't assign some notion of infallibility to this; Shell has made its share of mistakes in the last decade, too. However, it does suggest that the company's decision to invest in this project wasn't just based on a straight-line extrapolation of current conditions. Deciding to build an ethylene cracker, a facility that turns the heavier components of natural gas into one of the basic building blocks of the petrochemical and plastics industry, in such a location is a big vote of confidence. It suggests that Shell has concluded that the current uncertainties facing shale gas development are very likely be resolved without undermining shale's capacity to produce large quantities of gas at relatively low cost, and that shale developers will find ways to resolve concerns about fracking, methane emissions, and other issues both with the affected communities and with state and national regulators.

These projects also suggest at least two other things. First, as the Reuters article noted, they represent sizable wagers on the relationship between the global price of oil and the US price of natural gas. I've commented before on the extraordinary divergence between the two, with oil bouncing around the $100 per barrel mark and US natural gas selling for the energy equivalent of $25 per barrel. A company would be unlikely to make a long-term investment like this if it thought gas and oil were likely to move back into parity any time soon. Even if gas prices eventually recover to around $6 per million BTU, as suggested by current long-dated gas futures, that's still the equivalent of less than $40/bbl--an oil price we haven't seen since the worst stretch of the global recession and financial crisis in early 2009.

And that leads to the last implication I draw from this news: these investments are bets on the health of the US economy. If the economy were headed for a protracted period of slow or no growth, adding petrochemical capacity here would be too risky, rather than putting it in the Middle East, where gas is even cheaper and the growing markets in Asia are much closer. That doesn't' mean that our problems of high unemployment, high indebtedness, and gaping federal, state and local budget deficits aren't extremely challenging, but it provides at least one modestly positive sign among the many ominous ones that are routinely amplified by the basic nature of the news media business.

SPR Release Catches Market Napping

2011-06-23T13:03:00.002-04:00

I see that the administration has decided to release 30 million barrels of oil from the US Strategic Petroleum Reserve, in coordination with a matched release from the strategic stocks of other OECD member countries of the International Energy Agency (IEA.) The release will be spaced over the next month, though it's not clear how soon it can begin, since it should take at least a few days to line up the requisite buyers, sign contracts, and schedule pipeline space. Politicians who have been calling for such a release to punish speculation in oil futures and alleviate pressure on consumers are crowing, and the oil markets have responded by dropping $5-6 dollars per barrel. As welcome as this will be for consumers, it is simultaneously a drop in the bucket and an unwelcome precedent for the future stewardship of these emergency reserves.

As I noted when I assessed the outcome of the recent OPEC meeting, oil inventories aren't unusually low, and the current shortfall in global production compared to demand will take a while to develop into a problem. I suspect the main concern behind the IEA's decision to release stocks now, rather than waiting for a true physical shortfall to materialize, is the mismatch between the quality of the Libyan and Middle Eastern oil that has been taken off the market as a result of the ongoing turmoil of the "Arab Spring" and that of the OPEC spare capacity available to fill in for it, mainly in Saudi Arabia. In this context, the US SPR release looks more like an expression of solidarity with its EU partners, for whom the Libyan shortfall is much more significant, than a direct assault on the market.

Nevertheless, the concerns I expressed in my posting of June 2nd regarding a smaller "operational" release from the SPR apply to this release, as well. The SPR doesn't exist to game the market, especially not for political purposes. It's there in case of a serious interruption in supply, the scenarios for which are numerous and unfortunately not very hard to imagine for either us or the potential perpetrators.

Perhaps an extra 2 million barrels per day will alter the psychology of the futures markets and catalyze a larger price drop than we've seen today. By itself, that seems unlikely. Because it's a temporary measure, the market will want to know what comes next, and that's the real problem. Unless the designers of this program have made a lucky choice and timed their release to coincide with a further easing of prices due to weakening demand, the calls for another release will start in a month, if prices remain at a level deemed high enough to threaten the economic recovery. Selling off 4% of the SPR in the absence of a real emergency--and with no clear plan for replacing it--might not be a big problem, but additional releases that added up to a substantial portion of the reserve would be. Let's hope we don't have cause to regret this.

How Do Renewables and Oil Sands Affect Energy Security?

2011-06-21T10:04:00.000-04:00

Despite its frequent use in policy and other discussions, "energy security" lacks a single, fixed meaning, and the consensus on its definition seems to be in flux. As an outgrowth of the oil crises of the 1970s, it has usually been associated with the economic, defense and geopolitical implications of imported oil and petroleum products, focused mainly on security of supply. It was often seen as a more nuanced term than energy independence. Over time, it has taken on other connotations, including the financial impact of imported energy. However, an even more recent trend to incorporate climate change and other sustainability concerns into energy security bears careful consideration, because it can sometimes lead to a direct conflict with energy security's most basic aspects. When I see advocates of a renewable electricity technology like solar power touting its energy security benefits, I can't help wondering how carefully they've thought through that claim, especially in light of the significant energy changes arising from the shale gas revolution.

A blogger conference call hosted by the American Petroleum Institute last week got me thinking about this topic again. Based on API's analysis, increased access to US oil resources that are currently off limits for exploration and development, together with approval of the Keystone XL pipeline to bring in more Canadian crude--including synthetic crude from new oil-sands projects--could dramatically reduce US oil imports. Imports from countries other than Canada could fall from 38% of our supply in 2010 to just 8% by 2030. Their assessment builds on a US Department of Energy forecast that already incorporates improvements in vehicle fuel economy and the expected contribution of oil shale resources such as the Bakken Shale in North Dakota and Montana. In API's resulting scenario, US oil production would increase by 4.8 million barrels per day (bpd) and domestic biofuels output would grow by 1.9 million bpd, along with an extra million bpd of imports from Canada. That combination would shrink our net non-Canadian imports of crude and petroleum products from 7.2 million bpd last year to just 1.8 million bpd in under 20 years.

However one views the potential environmental consequences of the steps necessary to achieve such an outcome, that would be a stellar result under the most commonly used definition of energy security. That's because these actions would directly replace imported oil and products, barrel for barrel, with supplies from more stable and dependable countries--including our own--as an extension of one of the main energy security strategies we've employed since the 1970s. Assessing the energy security benefits of some of our other options is less clear-cut, particularly when it comes to the generation of electricity from renewable sources.

Consider today's most familiar renewable energy projects, wind farms and rooftop solar installations. Both reduce greenhouse gas emissions, but do they also enhance energy security? The answer depends on where they are installed and how their output is used. If the venue is Europe, which imports large quantities of natural gas, or Japan, where the post-Fukushima electricity shortage is leading to significant increases in imports of fuel oil and liquefied natural gas (LNG), it's clear that they do. But the answer isn't as obvious in the US, where the generation they displace is mainly fueled by coal--a domestic resource--or natural gas. Prior to the explosion of domestic gas production from shale resources, it was much easier to argue that displacement of gas from a peaking gas turbine power plant backed out imported LNG somewhere and thus bolstered energy security. Today, with most gas coming from domestic wells and with most renewables relying on gas-fired backup power, that assertion is becoming a stretch.

Making the case for energy security benefits from wind and solar on the basis that they can back out oil imports by powering electric vehicles looks like even more of a stretch. This notion might be true in the 2030 time frame of the API scenario described above, by which time I'd expect to see many more EVs on the road, along with a smarter power grid capable of channeling the output of renewable power generation into EV recharging. In the nearer term, however, there simply won't be enough EVs on the road to substantiate such a claim. In fact, it would take more than 23 million EVs like the Nissan Leaf to consume the output of the wind and solar installations already in place last year. And in most locations, the EVs coming to market will be recharged mainly with average grid electricity, which includes a significant contribution from coal, even in California, thanks to that state's sizable electricity imports from neighboring states.

Resorting to such contingent and indirect claims of enhanced energy security sets up a debate that only liquid biofuels are currently positioned to win. However, it seems equally unrealistic to adhere to a definition of energy security that ignores the many ways in which our perspective on the world has changed in the last decade. I wasn't surprised to find a definition of energy security from within the US military incorporating sustainability along with sufficiency and surety. In effect, sustainability represents a new, albeit self-imposed, risk on the security of supply for conventional fuels that we're less accustomed to considering. It can also cut both ways, leaving some renewables, such as food-based biofuels, vulnerable under a definition of energy security that includes this metric.

Our notions of energy security are moving into a 21st century context, as they begin to recognize factors beyond supply and demand. That seems appropriate. At the same time, the term should still convey the pragmatism that gave rise to this concept in the first place. The traditional view of energy security never constituted a trumping argument in US energy policy, or else we wouldn't be sitting here with so many billions of barrels of technically recoverable resources off-limits to exploitation because of worries about the possible effect on beaches, tourism, wildlife and a myriad other concerns, broad and narrow. Similarly, a greater inclusion of sustainability aspects into our view of energy security should not be expected to disqualify efforts like the Keystone XL pipeline or expanded access to hydrocarbon resources. Even if such endeavors must also demonstrate their soundness on other criteria, they would unquestionably leave the US more secure in its energy sources. Instead of pitting one view of energy security against another, I'd prefer to see a scenario for 2030 that incorporates more access to North America's liquid fuel resources, together with expanded efforts on energy efficiency, transportation energy diversification, and creative capitalization on our new-found natural gas wealth--all of which would enhance US energy security.

Gasoline Could Cost Consumers an Extra $150 Billion in 2011

2011-06-16T13:19:00.003-04:00

A poll reported in this morning's Wall St. Journal (subscription) indicated that more Americans are significantly affected by high gas prices than by rising food prices, falling home values, unemployment or foreclosures. That's a surprising result, considering that transportation fuel only accounts for about 5% of average household expenses. However, gasoline has one of the most visible prices in our society, and the scale of our fuel use is such that price increases of the recent magnitude aggregate to a very large total. Based on year-to-date prices and compared to a more typical year like 2006, the drag on the US economy is running between $100 and $150 billion for 2011, reversing any "gasoline stimulus" we received in 2009.

As of the latest price report from the Department of Energy's Energy Information Agency, the national average price for unleaded regular gasoline has dropped back to $3.71 per gallon from its May peak of just under $4. Despite that, it's still more than a buck higher than this time last year. In fact, until a couple of weeks ago gas prices were trending well above their path in 2008, when prices reached an all-time high of $4.11/gal. that July. (See above chart.) When I compared this year's prices to those in 2006, which averaged only about 20 cents per gallon lower than last year's but exhibited more normal seasonality, and then multiplied by the more than 137 billion gallons of gasoline the US is likely to consume this year, the total drag on the economy worked out to between $100 and $150 billion on a full-year basis. (See chart below.) If these prices persisted, that would be enough to negate the effect of the entire 2% cut in Social Security taxes for 2011.

Fortunately, barring an escalation of the current supply disruptions in the Middle East, a major hurricane affecting Gulf Coast refinery operations, or an unexpected surge in economic growth, we've probably either already seen the peak gasoline price for the year or are within a few weeks of it. The outcome of last week's OPEC meeting, while not as bearish for prices as an agreement to increase quotas and output would have been, has had little lasting effect on oil prices, which are running at a level consistent with this week's US average pump price or a bit less. However, no one should confuse a seasonal easing in prices with a permanent return to cheaper gas. Short of another global economic crisis, global oil supply and demand remain closely enough matched that any hiccup will quickly translate into higher prices at the pump. I feel safe in predicting that we'll be flirting with $4 again before long, and the consequences of that should be factored into any forecasts of future economic growth.

Marrying Gas and Renewables

2011-06-14T07:01:00.006-04:00

A Turkish developer recently announced that it would build a new power plant using technology from GE that matches wind and solar generation to the output of a highly responsive natural gas turbine, all integrated in one package with the hardware and software to mesh its output with the grid. GE is apparently calling this scheme IRCC, for "integrated renewables combined cycle", adding yet another acronym to our growing list of energy choices. This development looks interesting from a technical perspective, but also for what it suggests about GE's view of the future market for generating equipment and power delivery.

The International Energy Agency's "Golden Age of Natural Gas" scenario remains a question mark, rather than a certainty, but if gas is to serve as the key fuel for bridging between our high-emission present and the low-emission future, then we're likely to see more installations like the one in Turkey emphasizing the synergies between gas and renewables, rather than the tough competition gas is giving renewables in some markets. The IRCC--not to be confused with an IGCC or the IPCC--is interesting because it goes well beyond the idea of using gas-fired power plants to back up the naturally variable output of wind farms and utility-scale solar arrays.

The IRCC concept is built around a new combined cycle gas turbine, the Flex-Efficiency 50, with an impressive capability to ramp up and down, as needed, with minimal loss of either efficiency or emissions performance. And thanks to the energy technology portfolio the company has built up over the last decade, GE is able to offer one-stop shopping with GE wind turbines and a solar thermal generating module from eSolar, in which GE has recently invested. The gas turbine/solar thermal hybridization looks especially useful in maximizing plant efficiency and incorporating solar thermal power into the grid at the lowest possible cost, by avoiding the expense of an extra steam turbine and generator. If all this works as advertised, the grid operator shouldn't know or care whether the power being dispatched was generated using wind, sun, or gas.

Before you confuse this posting for a GE ad, I should note that at least in the configuration chosen for the Turkish site most of the power from this integrated plant would still be generated by the gas turbine, which has 10 times the peak output of the concentrated solar power module and more than 20 times the rated power of the small wind farm tied into it. By the time you account for the capability of the gas turbine to run 24/7 when necessary, compared to typical capacity factors of 25-40% for wind and up to 25% for solar, the proportion of the IRCC's annual megawatt-hours generated from gas could exceed 95%. Nor is GE the only firm bringing turbines like this to market. So it's an impressive step, though more of an incremental than revolutionary one. However, with its inherent flexibility, I wouldn't be surprised if this type of gas turbine could effectively integrate a much larger quantity of renewable generation on the grid outside the IRCC's fence, particularly after the operating experience of the first few installations has been absorbed.

GE's timing in introducing its IRCC concept could prove especially apt. Not only does the Flex-Efficiency turbine look useful for helping to meet California's aggressive new 33% renewable electricity target, but the 50-cycle version featured in GE's marketing materials--likely minus the solar thermal module--could be just what Germany needs, now that its government has begun to come to grips with the quantity of new fossil generation that's going to be required to make up for the post-Fukushima accelerated retirement of its nuclear power plants.

Do OPEC Meetings Matter?

2011-06-09T09:35:00.006-04:00

Yesterday's meeting of OPEC in Vienna attracted extra attention because of disagreements between Saudi Arabia and Iran that extend well beyond the oil fields. The resulting impasse over increasing production to stem high oil prices and support a weakening global economy produced a much-quoted assessment from the Saudi Oil minister, Ali Naimi, who described it as "one of the worst meetings we ever had in OPEC." Yet while the events in the Middle East were at the forefront for most commentators, the outcome of the meeting seems understandable purely in the context of OPEC's own history and the current fundamentals of the market. I'm not sure why so many people appeared to expect OPEC to boost output in anticipation of demand that might not materialize.

I have followed OPEC meetings for nearly 30 years, though not always as closely as when I was trading oil and its products, the prices of which stood to rise or fall depending on what was decided in Vienna. My interest in this meeting went up significantly when I received a call inviting me to participate in a panel discussion about it on the Voice of Russia radio network yesterday afternoon. An hour or two of research revealed a global oil market that is currently well-supplied, with inventories in most developed countries running at fairly typical levels and inventories in the US actually on the high side of normal for this time of the year. That's pretty much the argument that OPEC's price hawks took into yesterday's session.

However, the Saudis and others arguing for higher quotas were looking ahead to the effects of summer demand, especially in rapidly growing Asia, and the buildup of inventories for the fall and winter heating fuel season. They--along with the IEA--anticipated demand growing faster than supply, particularly when the impact of the curtailments from Libya and Yemen are factored in. Such events are important because of the quality difference between the oil that's been shut in in those countries and the spare capacity elsewhere that's available to make up for it.

OPEC's main problem is that the outlook for the global economy has weakened in the last few weeks, and not just because oil has risen to above $115 per barrel, compared to its average of $80 or so last year. The stakes for them look even higher when you factor in a history that includes boosting production in the late 1990s to meet roaring demand in Asia-Pacific, only to see the Asian Economic Crisis slam demand growth in the region into reverse, sending crude prices tumbling from the $20s to single digits by the end of 1998. The doves within OPEC were focused on keeping prices below the level at which large chunks of demand were destroyed in 2008, while the hawks seemed willing to risk that outcome to avert a future price collapse and preserve the revenue they need to fund their national agendas.

The potential consequences for individual OPEC members are substantial. Consider Algeria, which exports about 1.8 million barrels per day. The difference between the current price and what they realized last year equates to more than $20 billion annually. That might sound small in the context of the current debate over trillion-dollar US deficits, but it's nearly 15% of Algeria's GDP. It's no wonder that smaller producers and others with limited capacity to increase output--and thus revenue--would drag their feet on agreeing to raise quotas for countries with spare capacity.

If it sounds like I'm rationalizing cartel behavior that would be illegal in the US, that's not my intent. It's clear to me that oil prices are significantly higher than they would be, because OPEC has chosen to produce around 2 million barrels per day less than it did in 2008. In part they've had to do that to accommodate higher non-OPEC production--think Brazil and Russia--along with rising biofuel production, without weakening prices. The consequences for US consumers are equally clear: Gasoline prices are still more than $1 per gallon higher than a year ago, and even ignoring the impact on diesel or jet fuel that translates into an additional drain of $100-150 billion per year that can't be spent on other goods and services that would contribute more to the recovery.

OPEC meetings do matter, because as long as OPEC possesses both spare production capacity and the discipline to withhold it from the market, it retains the power to control oil prices. If we want to understand the decision process of this group of countries that is always struggling to reconcile its own often-competing, but still broadly aligned self-interests, our assessment should focus on their issues more than ours, however much we are affected by the outcome. Yesterday we saw the price hawks stymie the efforts of those producers who are worried that if they squeeze consumers too hard, demand will fall back to the lows of 2009, costing them hundreds of billions of dollars per year in revenue. But if demand continues to grow, that was surely not the last word, and this debate must be revisited within a few months.

The Golden Age of Natural Gas

2011-06-07T08:20:00.002-04:00

A regular reader of this blog kindly sent me a link to the International Energy Agency's new study on global natural gas, to which he contributed. The report, entitled, "Are We Entering A Golden Age for Gas?" was launched with a press conference yesterday in London. It presents a scenario in which gas use grows rapidly due to faster demand growth, particularly in the developing world, increased supply from unconventional sources such as shale gas, and a slower expansion of nuclear power in the aftermath of the Fukushima Daichi accident. Its key findings envision gas providing 25% of world energy by 2035, up from 21% today, and eclipsing the share of coal before 2030, with corresponding benefits for global greenhouse gas emissions.

The IEA's presenters were careful to point out that they are not proposing this view as the likeliest scenario, but as an offshoot of their primary World Energy Outlook scenario published last fall, which incorporated the commitments at the Copenhagen climate conference. The new gas scenario depends on a number of uncertainties, including the resolution of some of the concerns about the environmental impacts of unconventional gas production, along with the realization of carbon-intensity and gas-development targets in places like China. However, it doesn't depend on new technology or dramatic changes such as a massive move to natural gas for vehicle use. (The latter is presented as a "High Impact Low Probability" sensitivity.) Its big shifts occur in the big existing gas market segments, for power generation globally and for industry and buildings in the developing world.

I was struck by several elements of the scenario. First, although much of the focus on unconventional gas has been on North America, where many of the techniques were pioneered, this is very much a global story. The IEA shows estimated unconventional gas resources from shale, "tight gas" and coal-bed methane that exceed conventional gas resources in Asia and Africa and rival them even in Eastern Europe/Eurasia. On the strength of its unconventional resources China could become the world's third-largest gas producer by 2035, behind Russia and the US. So even if the US plaintiffs bar attempts to turn "fracking" into the next tobacco or asbestos, unconventional gas exploitation will likely progress elsewhere. At the same time, increases in conventional gas production are expected to exceed those from unconventional sources, by 60/40 over the period studied. That requires big increases in LNG production in Australia and a substantial increase in pipeline capacity linking Russian and Central Asian gas to markets in Europe and Asia. It's also worth noting that despite the shale gas bonanza, the IEA doesn't envision the US becoming a net gas exporter.

As one of my mentors frequently reminded me, natural gas doesn't get developed without a market, and in this scenario the biggest source of new demand is in power generation, where the combination of lower gas prices and the 60% thermal efficiency of combined cycle gas turbines makes gas highly competitive, even with coal. It's less clear whether gas is taking market share from new nuclear based on price, or mainly filling the gap that the response to Fukushima is leaving in some markets. From what I heard on a power industry webinar yesterday, the former is a significant factor, at least in the US. The strong connection between gas and power is another reason why so much of the growth in gas demand--80% by the IEA's estimate--is expected to occur in developing countries including China and India, where electricity demand is expanding at rates that the US and Europe haven't experienced for years or decades. Perhaps the most startling forecast in the report is that China's gas demand could grow from roughly matching Germany's today to about the level of the entire EU in 25 years. That would be supported as much by additional imports as from domestic unconventional gas output.

As I'd have expected, the IEA provided a sober assessment of the environmental implications of their scenario. Increasing the share of gas in global energy demand reduces global GHG emissions by 160 million tons of CO2 equivalent by 2035--less than 1% of total emissions--by substituting for coal and some oil. That's a lot less than if the extra gas didn't also contribute to higher energy demand by keeping electricity prices lower, while outcompeting some lower-emission renewables and nuclear projects. The IEA states plainly that relying on more gas is not a silver bullet for climate change, although it is a positive step.

In addition to pointing out the need for safe handling of the fluids involved in hydraulic fracturing, the report also specifically addresses the critique of Howarth and others concerning the direct emissions from shale gas production. The IEA found that CO2-equivalent emissions for shale gas from well to burner exceed those for conventional gas by 3.5%-12%, depending on whether the methane liberated during well completion is captured, flared or vented to the atmosphere. Even at the high end, that does not negate gas's emissions advantage over other fossil fuels, especially when power generation efficiencies are factored in. The report's authors apparently see most of the excess emissions compared to conventional gas production as representing an opportunity that can be captured with current technology and best practices.

The IEA put a price tag on this shift to gas: a cumulative $8 trillion through 2035 , nearly $1 trillion higher than the gas infrastructure investment in their global energy scenario of last fall. Those figures aren't as hard to fathom in the context of developed-country budget deficits and debt as they might seem, because they mainly reflect unsubsidized, economically attractive investments by publicly-traded and state-owned energy companies that are making healthy profits and have substantial cash flow on which to draw. Surprisingly, the IEA sees most of the incremental investment in gas coming at the expense of oil. Although they deliberately framed the title of their scenario as a question that hinges on a number of variables, the report comes across as a plausible and credible glimpse of our possible energy future.