2011 in Energy: The Year of...

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?

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

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

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

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

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?

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

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

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?

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

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

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?

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?

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.