What New Ethylene Crackers Tell Us

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

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?

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

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

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?

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

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.

Hedging the Risks of Selling Oil from the Strategic Petroleum Reserve

I see that the administration has asked Congress to approve a non-emergency sale of oil from the US Strategic Petroleum Reserve (SPR), in order to allow a storage cavern to be repaired before it starts to leak. That's fine, as far as it goes, though the article I read suggested this would be done as a net sale into the market, rather than an exchange for future oil, as has been done for many previous SPR releases. The distinction means that the government will either be exposed to buying the oil back at higher prices later, or would simply forgo refilling that portion of the reserve. The current shape of the oil futures market provides another alternative, though without the presumed political benefits of being seen to sell SPR oil when gasoline prices are high.

The sale in question was included in the administration's annual budget request and identified 6 million barrels to be sold "for operational purposes." That amounts to less than 1% of the 727 million barrels of oil currently in the SPR, equating to a little more than one day of import disruption insurance at the SPR's maximum output of 4.4 million barrels per day. Of course at current oil prices it would be worth over a half-billion bucks, so I can understand the appeal of doing this when federal finances are tight. However, the purpose of the reserve was never to speculate on the price of oil and harvest those gains when we came up short elsewhere; the oil is there to mitigate a serious disruption in the roughly 9 million barrels per day of oil imports on which our economy depends. Unless the administration now wants to undertake a comprehensive review of our SPR strategy--something I've advocated for several years--it is more or less obligated to replace the oil once the cavern has been fixed.

In that case, selling the oil, rather than offering it to refiners on a time-trade, will expose the government to a substantial amount of price risk while repairs are completed. For example, if they had sold this oil last fall and needed to buy it back now, the Department of Energy would have incurred a loss of up to $180 million, based on the increase in oil prices in general and the divergence of physical markets, which tend to track UK Brent Crude, from the futures market in West Texas Intermediate. Prices might fall in the meantime, but it is not the role of the DOE to bet on that prospect. The futures market offers a uniquely better alternative today.

Most of the time, the oil futures price curve is bent either up or down, in "contango" or "backwardation" in trader's terms, with oil for delivery several months or more from now selling for considerably more or less than for prompt delivery. That's usually an indication of expectations that the balance between supply and demand will be either tighter or looser in the months ahead, compared to today. The contango that prevailed until recently has flattened dramatically, so that if it acted quickly, the DOE could sell the oil from the caverns to refiners and lock in its future repurchase price on the futures market at only a dollar or two per barrel more than the sales price. Of course this would involve having the government participate in the dreaded futures market, even though it wouldn't be for the purpose of manipulation or stabilization, but for simple hedging of the kind that producers and refiners do every day of the week. (Backwardation would offer an even better deal, and the Brent market is currently mildly backwardated, but I can only imagine the hullabaloo if the US government hedged SPR oil on a European exchange.)

We would argue all day about which approach is riskier: hedging the oil sold from the SPR with futures contracts or waiting to buy back at whatever price prevailed later. In the larger scheme of things, neither looks as risky as emptying the cavern and not refilling it at all. Based on my experience and at least in this special case, hedging seems like a good way to ensure that the SPR cavern repair doesn't end up costing a lot more than the DOE expects, if its managers ignored oil-price risk.

The Cost of A Tougher Iranian Oil Boycott

Today's Wall St. Journal (subscription required) includes an op-ed calling for a stricter US boycott of Iran than the current one that prohibits importing Iranian oil. The proposal from Reuel Marc Gerecht and Mark Dubowitz of the Foundation for the Defense of Democracies would go a step farther, barring the importation of petroleum products that contain any components processed from Iranian crude elsewhere. Before any fuels or petrochemical products could be brought to the US, exporters "would have to certify that no Iranian oil was involved in its manufacture." Yet while the authors have clearly thought about how to maximize the impact of such a rule on the government of Iran, I'm not sure they've examined the potential impact on the US carefully enough. If their arguments about how European refiners would react to such a boycott are correct, then U.S. gasoline prices would likely rise as a result of these restrictions.

The logic of the proposal is grounded in fact. The US imports significant quantities of gasoline from Europe, though lately most of it is in the form of gasoline blending components, rather than finished gasoline that is ready to be put into a pipeline or sold over a refinery's or blending facility's truck rack. Last year total US gasoline imports averaged almost 900,000 barrels per day, with 39% coming from EU countries led by the UK, Netherlands, Spain and France. It's also true that many European refineries process some Iranian crude. In 2010, the EU imported 471,000 bbl/day of crude oil from Iran, comprising just over 4% of total EU oil imports of 11.1 million barrels per day. (Compare that to US oil imports in 2010 of 9.2 million bbl/day.) This amounts to roughly a fifth of total Iranian crude oil exports. At least on the surface, it looks like it shouldn't be too hard for European refiners to forgo this small input, in order to be able to continue exporting gasoline and other oil-derived products to the USA.

In practice, I think it would be more difficult for European refiners to make that adjustment than the authors imagine. For starters, those refineries capable of exporting gasoline to the US must generally be located near ports, rather than inland, and likely run more Iranian crude than the EU average, since this oil is delivered by large tankers. Then there's the question of how much Iranian crude a refinery could run and still be able to certify its products to be Iran-free. If the standard were simply that you couldn't export a larger proportion of your products than the proportion of non-Iranian oil in your crude slate, that probably wouldn't change what any refiner is currently doing, since most of their output goes into the local market. Certifying that there were no molecules of Iranian origin in any products destined for the US would essentially require running no Iranian crude at all, because of the way that most refineries operate and manage their inventories of crude oil and unfinished products.

I presume that's what the authors have in mind, because it would certainly exert the greatest market pressure on the price of Iranian crude. However, substituting one crude oil for another in a refinery isn't like substituting one brand of cola for another in a fast-food restaurant. We've seen a prime example of that recently with the disproportionately large disruption caused by the curtailment of exports of high-quality oil from Libya. Refineries tend to be optimized around certain proportions of well-known crudes, with shifts in those proportions mainly driven by changes in the value of the products they yield, within a range set by the capabilities of the specific hardware. In other words, if your refinery model is telling you to run x% of Iranian Light, then choosing something else in order to be able to sell into the US market comes at a cost.

That cost would be passed on to companies importing European gasoline into the US in two ways. First, it would require a higher price to make it worthwhile for the exporting refinery to produce a cargo to US specifications. Less directly but just as significantly, it would reduce the number of refineries competing for the export opportunity, because some would simply find the changes too onerous, unless the premium they collected was really large. That would create a smaller pool of suppliers with higher costs. That's not what you want to face as a buyer.

Market dynamics might also amplify this effect. A portion of the gasoline exported from Europe to the US flows not under long-term contracts, but as "spot" cargoes shipped in response to occasional wide price differences between there and here. That's exactly the kind of trading I was involved in when I worked in London in the early '90s. Such "arbitrage opportunities" often result from supply problems such as refinery accidents and other unanticipated shutdowns, large weather events, or other situations leading to a local or regional price spike. As a result, much of the impact on the US from the authors' proposal could be delivered when gas prices here would already be rising, thus adding to the economic impact of a price spike.

Perhaps paying more at the pump to drive down the value of Iranian crude in the global market is a price most Americans would be willing to accept. I'd gladly kick in a few cents per gallon for that purpose, since I remain extremely skeptical of Iranian assurances that their nuclear program is entirely for peaceful purposes. Nothing has materially changed my view of that since my detailed analysis in 2005. However, I suspect that the strong likelihood that such a boycott would entail a certain amount of "blowback" at home would complicate the politics of passing the necessary legislation, particularly when gas prices are already quite high by US standards.

Tapping Salt Water's Energy Potential

It's rare to run across a novel form of renewable energy that hasn't already been touted as the Next Big Thing and the potential savior of humanity. Work on harnessing salinity gradient power, one aspect of which is also known as "osmotic power", has proceeded in relative obscurity, with only one demonstration-scale installation that I'm aware of, in Norway. However, recent developments at Stanford University, as reported in Technology Review, hold the promise of extracting electricity directly from the difference in salt concentration between fresh water and seawater. If it can be scaled up as indicated, it could offer yet another renewable energy option for coastal communities, though as with most others, it is unlikely to be free of undesired consequences. So far as I know, the law of no free lunches has not yet been repealed.

Most forms of energy production, renewable or otherwise, depend on taking advantage of some kind of gradient--differences in temperature, pressure, or another characteristic between two locations. In some cases, these gradients are inherent in the primary energy source involved, such as the pressure gradients that produce the wind harnessed by wind turbines, or the temperature gradients that drive geothermal power plants. In other cases, the gradient is created by the process of energy conversion in some device, such as an internal combustion engine, gas turbine or nuclear reactor. For most of us, it's probably easier to relate to the pressure and temperature gradients that drive such machines than to visualize the concentration gradients that Dr. Cui's team at Stanford was investigating. Reading about their work dusted off the cobwebs from my chemical engineering mass transfer studies, long ago.

The "mixing entropy battery" the researchers created uses electrodes chosen for their affinity for sodium and chloride ions, with surfaces optimized through the application of nanotechnology. By charging it from an external power source while immersed in fresh water and then discharging it while filled with salt water, they are able to extract more energy than they put into it. This is not perpetual motion, because the extra energy comes from exploiting the concentration difference between the two fluids. Impressively, they extracted 74% of that energy potential in their tests; few energy cycles recover more than 50% of the energy of their sources. The catch is that like any battery, the process stops when the electrodes are saturated. At that point, the battery must be recharged in freshwater. This cycle can be repeated many times.

Although this technique might be used to produce smaller-scale rechargeable batteries for consumer devices or perhaps even cars, the researchers apparently had in mind larger-scale applications that would exploit the differences in salinity where a river meets the sea. Not only are such locations quite common, but they also tend to be near centers of population, because of the historical relationship between waterborne commerce and settlements. They have apparently calculated that the global potential of the concentration gradients in estuaries could meet 13% of the world's energy needs, or around 2 terawatts (2 million Megawatts.)

What's not clear from what I've read of their work is how much of the salinity gradient in an estuary could be tapped without significantly affecting the local ecosystem. Even though the amount of salt returned to the estuary would match what was taken out, performing the relevant mixing somewhere else--inside a power plant--would alter the preexisting conditions. That might not be catastrophic, particularly if the scale of the plant were limited to the natural variation in water flow caused by seasonal rainfall patterns, but it would still count as an environmental impact. I don't regard that as a reason not to pursue this technology, because everything we do at the scale of our global civilization has an environmental impact somewhere, but it's at least cause to proceed cautiously. In the world in which we now live, anyone investing in this technology won't have a choice about that, anyway.

So it seems we should add salinity power to the existing long list of renewable energy options, including wind, solar, geothermal, ocean thermal, wave and tidal power. If historical precedents concerning the interval from laboratory to commercial application are any guide, we might expect the first large-scale salinity power plant to appear sometime in the mid-to-late 2020s, assuming that it doesn't encounter unexpected hurdles and can be scaled up economically. Even if it can't supply all our needs, salinity power could make an important contribution to the low-emission energy mix we anticipate by mid-century. I'll be watching developments with great interest.

Has the Solar Market Reached A Turning Point?

Several trends appear to be converging to make 2011 a watershed year for solar power, though not quite along the lines that solar advocates have been telling us to expect. The long-awaited arrival of "grid parity", when the unsubsidized cost of power from solar panels finally becomes competitive with that of power from the grid, is still either imminent or elusively out of reach, depending on who you ask. In the meantime, solar power remains critically dependent on government incentives. Changes in subsidy levels in key countries and the rapid growth of solar manufacturing in Asia are setting the stage for a shift in the geographical focus of the industry, with important implications for national energy policies.

Last year most of the new solar photovoltaic (PV) capacity in the world was installed in Europe, accounting for roughly 4 out of every 5 Watts of global PV additions. That shouldn't have surprised anyone, because it fits a long-standing pattern. However, the European policies that made it possible for PV to compete, even in such un-sunny northern locations as Germany, have come under considerable pressure as governments have been forced to confront high debt levels and other priorities. Feed-in tariffs (FIT) that guaranteed above-market power prices for the life of a PV installation have been slashed across Europe, including in Germany, Italy and France, in a trend that has lately spread beyond Europe. This is beginning to translate into lower demand. The reason it hadn't already resulted in a big reduction in European PV installations is that the cost of PV was dropping rapidly, further justifying legislated cuts to generous FITs.

Here's where the narrative diverges from the storyline that advocates outside the solar industry have been touting for years. Although a substantial portion of those cost reductions is attributable to economies of scale and experience curve effects--manufacturers finding new ways to cut costs as output climbs--a large slice of the reduction in global PV prices has been due to increased competition from lower-cost producers entering the game. The largest PV manufacturers in the world are now mainly based in China, rather than Europe, and PV producers outside Asia have had to shift much of their manufacturing to lower-cost locations in response. So for the last couple of years we've seen a global PV market focused mainly on sales in Europe but increasingly dominated by export-driven manufacturing in Asia. That picture is now changing as domestic demand in Asia picks up, along with growing installations in the US.

China is rapidly becoming the key country for solar, from both a supply and demand perspective. In addition to hosting leading PV producers such as JA Solar, Suntech Power, Trina Solar and Yngli Green Energy, China's latest five-year plan increases the country's solar power target to 10,000 MW by 2015 and 50,000 MW by 2020. That compares to global solar capacity of around 37,000 MW at the end of 2010, nearly half of which is in Germany. Ramping up installations to meet its new goals, as ambitious as they are, is unlikely to turn China from a net solar exporter to a net importer, as happened earlier for oil. That's because China's PV manufacturers are still adding capacity at a rate that should allow them to satisfy domestic demand in China--where they face only modest competition from foreign firms--while remaining highly competitive elsewhere.

With these developments, policy makers in Europe and the US who have been as focused on the creation of national solar manufacturing industries as on the deployment of solar as an element of their broader renewable energy strategies must answer a crucial question: As the PV industry develops and matures, will it follow the path of wind turbine manufacturing, in which established US and EU firms have been able to remain globally competitive, similar to the aerospace industry, or is it likelier to emulate consumer electronics, for which manufacturing is now dominated by Asian producers? If it's the latter, then the whole system of solar incentives must be rethought.

In the meantime, the shift of the solar power center of gravity away from northern Europe should advance the prospects for grid parity, because low-cost solar power depends as much on high-quality solar resources as on cheap PV panels. Geography isn't always destiny, but in the case of solar power its full potential will only be achieved when its deployment aligns large power demand with high average annual solar irradiance. In the long run, that points to a global PV market focused squarely on the US and China.

Fueling the Aerotropolis

Roger Cohen's column in Monday's New York Times sent my mind spinning with its portrayal of a global network of airport-based businesses and organizations that might have closer links to airports a country or continent away than with the traditional urban centers for which these facilities are often named. I'm embarrassed to admit that it was the first time I had run across the "Aerotropolis" concept, which has apparently been around since 2000. Its implications are thought-provoking, not least for their impact on energy and the environment.

The term aerotropolis was apparently coined by a professor at the University of North Carolina business school; it's also the title and subject of his new book. It evokes a retro-1920s science fiction vision of gleaming cities connected by flying cylinders, crossed with the gritty reality of the modern airport and its environs. I wasn't surprised to learn that a third of world trade-- though just 1% by weight--moves by air, but the idea of a hospital integrated into an airport in Hyderabad, India, or an entire city in South Korea growing up around the Incheon International Airport was new to me. The possibilities seem endless, though I can't think about them without also considering where the energy to facilitate the implied explosion of air travel and air freight will come from.

A few years ago, I would have said that air travel was even more closely linked to petroleum than are automobiles. That's not because alternative aviation fuels seemed impossible--quite the contrary--but because the aviation world has historically been understandably cautious and conservative about what goes into the engines that power aircraft. From a technical standpoint, jet turbines offer a great deal more fuel flexibility than the internal combustion engines under the hoods of most automobiles. However, while a fuel failure in your car is a major inconvenience, a fuel failure at 30,000 feet is catastrophic. In some respects the alacrity with which the aviation industry has begun to embrace alternative fuels is nearly as big a surprise as the shale gas revolution, and perhaps ultimately as transformative. Airlines and militaries have entered partnerships and set targets for integrating alternative jet fuel into their consumption, and supplies are gradually appearing.

Scale remains an issue. Kerosene-based jet fuel accounted for 7% of US petroleum consumption last year, down from nearly 8.5% a decade ago, as air carriers have transitioned to more efficient aircraft and higher load factors. That's still a big volume, though it turns out to be easier to make suitable kerosene substitutes from a variety of sources, including natural gas, coal and biomass, than to make comparable substitutes for gasoline. Nor does jet fuel produced from camelina seeds, algae, or the gasification and FT-synthesis of bulk biomass, natural gas or even animal fat entail the kind of performance penalties inherent in our primary gasoline alternative, ethanol. Delivering on this potential will require significant investment, but of a magnitude that seems much more achievable than what is required for many other renewable energy goals.

Another important aspect of scale concerns the logistics of gathering enough biomass to produce meaningful quantities of "biojet". The government of Ontario Province just awarded Rentech, Inc., a company with long expertise in gasification and fuel synthesis, a 1.3 million ton-per-year supply of forest waste and other biomass from Canada's Crown Forests, specifically for the production of renewable jet fuel. The proposed facility would produce around 22 million gallons per year of biojet, along with another 11 million gallons of non-jet products. That equates to roughly 1% of Canada's current jet fuel consumption. Canada might have enough forest biomass available to produce a sizable fraction of its jet fuel needs from such sources, but other countries don't, so it's fortunate that alternative jet fuel can be made through so many different pathways.

That's also fortunate for the aerotropolis concept, because without an incremental supply of non-petroleum jet fuel, meeting the energy needs inherent in this idea without dramatic increases in aviation's current approximately 3% share of global greenhouse gas emissions could become a major obstacle within just a few years. With sufficient supplies of renewable and gas-to-liquids jet fuel, the concept might even be able to withstand a peak in global oil output, even if the price of such alternatives seems likely to track that of oil-based jet fuel.

Honey, I Shrunk the Oil Industry

I finally finished watching the archived video from last week's Senate Finance Committee hearing with the heads of the five largest major oil companies in the US, including the two that are based in the EU. The few nuggets of real information and insight that were exchanged were nearly drowned out by political posturing, but my hat is off to Chairman Baucus (D-MT) for his willingness to engage in a genuine give and take with his guests. I attribute much of the frustration that was on display to the conflict between the facts and their context: Although the companies are mostly right on the principles and consequences involved in the proposal to strip them of their tax incentives, it's nearly impossible for anyone outside the industry to get past the large profits these companies are making and the out-of-control federal deficit that the Congress must endeavor to rein in. Perhaps I can offer a bit of perspective for both sides of the argument.

First, neither this Congress nor the administration is proposing windfall profits taxes--government's traditional threat when oil profits soar--nor are there serious calls for nationalization of the industry. Having watched other countries make a hash of such moves, it appears we've learned a thing or two in the last three decades. The measures currently under consideration are much less extreme than that, and I imagine they sounded reasonable and fair to a lot of Americans who are in sticker shock every time they drive by a gas station. However, that doesn't make them good policy--energy or tax.

At the same time, despite Senator Hatch's pie chart showing the relative size of the US oil industry compared to the global industry, including OPEC, few of those grilling the CEOs seemed to grasp the scale involved--a major factor in the absolute magnitude of the profits in question--including the size of companies with which these firms must compete for opportunities around the world. For comparison I couldn't turn up an estimate of Saudi Aramco's first quarter earnings through a Google search, so I had to devise one myself. Based on an average OPEC basket price of $101/bbl and a conservative production cost of $20/bbl, Aramco's average volume of oil exports in January and February, as reported in the database of the Joint Organizations Data Initiative, implies quarterly earnings of around $50 billion--more than the total of the five companies represented at the hearing--and that's assuming that every barrel Aramco refines and sells within the Kingdom is at a breakeven. When it comes to oil profits, big is relative. Even the much smaller Petrobras, 64% owned by the Brazilian government, posted $6.7 B in first quarter earnings, beating US #2 Chevron, in which I own shares.

Several of the Senators complained that the math didn't seem to work, in terms of understanding how the withdrawal of a couple of billion a year in tax incentives could have a serious impact on the five companies and shift investment away from the US, a much more serious concern than the effect on earnings. Having participated in the project portfolio process of a major oil company in the past, I believe I know what the Senators were missing.

It seems counter-intuitive, but corporate-level accounting profits reported after the fact have virtually nothing to do with project selection decisions, other than influencing how much money is available to invest. The choice of which new projects to pursue and which to leave on the shelf hinges on detailed comparisons of expected future after-tax earnings and cash flow for each project. Tax rates, deductions and credits play an important role in those calculations. For some projects the go/no-go decision rests on a knife edge of risked net present value, and in that environment a lost tax deduction (Section 199) or tax credit could make US projects look consistently less attractive than their foreign counterparts. (Ironically, these companies' renewable energy investments in the US would also suffer the same disadvantage.) Put enough US energy projects in that position, and the result is inevitable: fewer wells drilled here, less future US production as current production declines, and eventually a smaller domestic oil industry with fewer capabilities.

Despite a few half-hearted attempts to channel the ghost of William Jennings Bryan, I doubt that any of the Senators participating in the hearing really wants such an outcome. It wouldn't help the millions of Americans who are alarmed by high gas prices, and it's hardly consistent with the President's goals of reducing oil imports by one-third and improving US energy security. Unfortunately, because of the way the question has been framed, in terms of a narrow set of tax breaks the industry enjoys, there are no good answers. Those can only be found by expanding the conversation to encompass a truly constructive US energy policy promoting both conventional and renewable energy, along with meaningful deficit reduction.

Collecting Road Taxes After Peak Gasoline

On Monday I was interviewed on Chicago's WGN Radio on the subject of switching the collection of federal highway taxes from the current assessment on motor fuel sales to a fee on vehicle miles traveled (VMT). The gas tax is always a hot-button subject, and when it's combined with potential concerns about privacy it becomes even more controversial. However, the path we're on is a slow-motion train wreck, for multiple reasons, and I'm relieved to see that with so much attention focused on other, larger aspects of the budget deficit and taxation, this relatively small yet important corner of the tax system hasn't been forgotten. It's high time to plan for how we will pay for the upkeep of our highways as sales of gasoline begin to decline.

The interview was prompted by some comments I made on this subject to Tom Curry of MSNBC. Since my conversation with him and then with Mr. McConnell of WGN I've been doing some more thinking about the problem, which I've discussed here since 2005. For some time it's been apparent that we have a disconnect between federal energy policies explicitly aimed at reducing our consumption of petroleum products and a road tax system that depends on the stability and growth of those sales. With gas prices again near their 2008 maximum and the auto industry required to sell consumers a more efficient mix of cars each year, it appears that US gasoline demand might have peaked in July 2007 and won't reach that level again. Lower gasoline sales mean lower gas tax collections, unless the tax rate is steadily increased, encroaching on one of the third-rail issues of US politics.

This is the long-term part of the gas tax problem. It's true that it takes decades to turn over the US passenger car fleet. Nevertheless, the more highly efficient cars are sold, including this year's crop of 40 mpg non-hybrids, plus hybrids, clean diesels, and a tiny but growing number of EVs and other cars using no liquid fuels at all, the harder it will become to fund the cost of road maintenance from its traditional source at the gas pump.

The problem has a more immediate dimension, too, because gas tax collections haven't been sufficient to balance the Federal Highway Trust Fund (HTF) for some time. According to a recent study by the Congressional Budget Office the taxes on gasoline and diesel fuel brought in about $32 billion last year, but between 2008 and 2010 an additional $30 billion had to be transferred from the general fund to the HTF to keep it in the black and avoid canceling or delaying projects. Given the deficit, such transfers add directly to the national debt. Nor is the current level of expenditures adequate to address the decay of many of our roads, as assessed by the American Society of Civil Engineers. This issue received a lot of attention in the aftermath of the 2007 collapse of the I-35W bridge in Minneapolis-St.Paul, but it faded after a few news cycles.

So we need to come up with more money to keep federally-funded highways in good repair, despite the principal funding mechanism being on a gradual but inexorable downward slope. States face a similar dilemma. Solving this problem requires creativity and most likely a new funding mechanism for all or part of a gap that is expected to grow in the years ahead. Simply extending the status quo will require steadily larger transfers from the general fund, exacerbating the deficit. It would also create growing inequities by weakening the long-established link between usage and financial responsibility, compounded by EVs and other vehicles that pay no road taxes at all under the current system. Unless you think EVs will never expand beyond a tiny niche of early adopters, that's unsustainable. (Some might argue that EVs should escape this tax as a further stimulus to sales, but in my view $7,500 per car ought to be inducement enough for anyone interested in buying one.)

There are several possible remedies for shrinking gas tax revenue, with partial or total conversion to a mileage-based system topping the list. It retains the fairness of "user pays" and encompasses all cars, whatever their energy source. It might also trade off a lower tax burden for the drivers of older, less-efficient cars for a slightly steeper bill for newer, more frugal cars. However, considering that the annual federal gas tax bill for someone driving an average car 12,000 miles per year is currently only about $100, any differences between the gas tax and a replacement VMT tax--not to be confused with a VAT tax--would be unlikely to influence car choice one way or the other.

If a VMT tax is the answer, the question of how to assess and collect it looms large. As I noted in the interview I worry about a tendency to rush to a technology solution, even though other options might do the job without requiring GPS-based tracking that a significant number of Americans would consider unacceptably intrusive. If you doubt that, consider the controversy over alleged smartphone tracking by Apple and Google. I would not dismiss low-tech methods such as odometer readings at vehicle inspections, or even self-reported odometer readings where such inspections aren't required. This might introduce new opportunities for fraud, but I'm willing to be that a GPS tracker could be spoofed, and all of these potential loopholes pale compared to the current problem of fuel tax evasion by organized crime and unscrupulous distributors and dealers.

I like the idea of testing this concept in a few locations, particularly if the tests include a wide variety of approaches. The slow uptake of EVs and the gradual shift of total fleet fuel economy give us enough time to find the best solution, if we start now. But lawmakers should ensure that such tests are finite and designed for quick evaluation, so that the window of opportunity presented by the broader tax reform discussions between now and the next presidential inauguration isn't missed.

Justifying $15 Trillion for Renewables

Yesterday I received a joint press release from a group of renewable energy trade associations. It touted a new report from the UN Intergovernmental Panel on Climate Change (IPCC) on the potential growth of renewable energy by 2050. The report has already garnered an impressive array of headlines, such as "Renewable Energy Can Power the World" and "Renewable Energy Key to Solving Climate Change". The headline from the Financial Times was characteristically more concrete, "World faces $15,000 bn renewable energy bill." Unfortunately, although the final report, rumored to run 1,000 pages, might support all of those conclusions when it is issued at the end of the month, the 25-page "Summary for Policymakers" falls far short of inspiring such confidence. Heaven help those policymakers if the summary is all they actually read.

I'm not even sure if "read" is even the correct verb to apply to this document. Once I got beyond the introductory paragraphs it seemed to degenerate into jargon and bureaucratese that was very hard to parse into plain meaning. The report's genesis as the product of pure consensus is readily apparent. Or as Andy Revkin of the New York Times' Dot Earth blog kindly put it, "it doesn't take readers much beyond what is already well established." That's a shame, because we don't need yet another report telling us that we are swimming in enough renewable energy to power our civilization umpteen times over, if we can merely muster the willpower to reach out and tap it. What we urgently need is a roadmap that describes a path--or preferably several possible paths--through the brambles that separate the energy status quo of 2011 from its ideal low-carbon state of 2050.

For example, we need to understand just how renewables will supplant the petroleum that currently provides around 94% of all transportation energy, at least in the US. That demand might be met by biofuels, although the report points out that the first-generation biofuels that supply nearly 3% of global road transport fuel today, but are still the only kind available on a commercial scale, have serious shortcomings. Closing the gap between 3% and 94% would require a true revolution in next-generation biofuels from sources such as cellulose and algae, yet after reading the Summary for Policymakers we are no wiser about when and how this will occur. I might note that such developments are rarely amenable to precise timetables, as the EPA is learning to its chagrin.

Alternatively, or in combination with biofuels, renewables might replace petroleum in transportation via the potentially more robust pathway of vehicle electrification, matching improved batteries with rapidly expanding supplies of intermittent renewables (wind, solar, tidal, etc.) delivered via increasingly intelligent power grids. But if that's the scenario, its crucial details are barely hinted at here.

The basic message of the summary appears to be that with enough investment, supported by the right policies, the currently identified renewable energy sources could expand by enough that in the very best case (out of 164 scenarios they considered) they could supply roughly as much energy by mid-century as we currently get from fossil fuels. That corresponds to 77% of total expected energy consumption in 2050 and may be the source of the headlines I saw. Of course the median level of those 164 scenarios is quite a bit lower, and the determination of the share of renewables in total energy relies on a projection implying that total global energy consumption will grow by an average of just 0.25% per year over the next 40 years. That suggests either a massive energy efficiency effort or minimal further economic uplift in the developing world. On a more reasonable track of 1% annual energy growth, the top scenario in the scatter chart on page 19 would meet 58% of total 2050 demand, while the median result would cover just a third of global energy needs. That's still impressive, compared to where we are today, but not quite as headline-grabbing.

I will be keenly interested to see what sort of scenarios the IPCC looked at in putting together the report on which this summary is based. Something tells me that they are likelier to fall into the category of what I would call projections or "cases" than true scenarios, which dig deeply into underlying trends and uncertainties and are not merely the output of a mechanistic model. That's not just a technical quibble, because I'm not aware of a single model-type forecast from 1970 that accurately projected the economic and sociopolitical conditions in which we find ourselves today. The intervening improvements in computing power and econometric sophistication still seem insufficient to conquer the fundamental unpredictability of looking that far into the future. But then the IPCC has a built-in bias to accept the results of such work, since long-term climate models underpin its entire effort. I hope I'm not alone in thinking that the expenditure of up to $15 trillion requires a much more rigorous justification than anything provided in this document. Whether or not Saint-Exupery really said it, a goal without a plan is just a wish.

If it seems that I'm being overly critical of a 1,000 page report that I haven't even seen on the basis of the horse-by-committee summary that I have seen, I plead guilty. But isn't that the same sin that the journalists and industry spokespeople are committing when they use this summary as the basis of glowing claims about the potential of renewables? And then there are the politicians and bureaucrats who will attempt to commit vast sums without ever reading any more than summaries such as this--at best--and without questioning the host of assumptions that went into them. If anything, this Summary for Policymakers reinforces my concern that the UN climate process has become so unwieldy and unresponsive that we must look elsewhere for leadership on this complex challenge. Meanwhile, we deserve a clearer articulation of how renewables can overcome the considerable obstacles that stand between their recent impressive performance and the achievement of the milestones this report suggests lie ahead.

Twilight of the Ethanol Subsidy?

The current tax credit for blending grain ethanol into gasoline, the Volumetric Ethanol Excise Tax Credit (VEETC), has outlived its usefulness. That's not just because I consider it unwise to subsidize any industry to such a generous extent for more than thirty years, but also because the passage of the ambitious federal Renewable Fuels Standard in 2007 made it redundant. Refiners aren't just paid to blend ethanol into gasoline; they're required by law to do so. One of the trade associations for the ethanol industry reached a similar conclusion last year, though presumably for different reasons. Nevertheless, the politics of such a big change looked dire. Now it appears that the unthinkable might be happening with the introduction of two separate bills in the Senate, one of which would scale back the ethanol credit significantly, while the other would eliminate it outright.

The tougher of the two bills comes from a pair of Senators representing states that consume far more ethanol than they produce. In fact, I couldn't find a single ethanol plant in Oklahoma, which Senator Coburn (R) represents. Whether the Feinstein-Coburn bill stands a chance or not, I'm much more interested in the equally bi-partisan measure from two farm state senators, Kent Conrad (D-ND) and Charles Grassley (R-IA). As described in the press, it would reduce the VEETC from $0.45 per gallon this year to $0.20/gal. for 2012 and $0.15/gal. for 2013, after which it would fall to a level indexed to oil prices. At the current price of West Texas Intermediate, it would be zero.

Of course the context for the Conrad-Grassley bill is that without legislative action the current blenders credit is due to expire completely at the end of this year. However, we've been in this position before, more than once, and each time the tax credit was rolled over with a few minor tweaks, such as the cut from $0.51/gal. to $0.45/gal. in 2008. My default assumption has been for a similar rollover this year, but with support from the largest ethanol trade groups in the country, the provisions of the Conrad-Grassley Bill appear to have become the new default. The bill also extends some tax credits for cellulosic biofuel and alternative fuel refueling facilities, including E85, and reduces the ethanol import tariff modestly, starting in 2012.

Although outright termination of the corn ethanol tax credit would be justifiable, it would also be highly disruptive to an industry that we've encouraged for so long, and that has struggled with thin margins even with the tax credit in place. A phase-out seems reasonable and would at least save taxpayers up to $3.3 billion next year and more the following year, depending on how much ethanol is actually sold and how many retailers take advantage of the incentives for installing E85 facilities. There's an argument that this might result in higher prices at the pump, as refiners' blending costs rise, though any such impact is likely to be lost in the noise of normal fuel price volatility.

Winding down this subsidy in an orderly fashion is important, but it's even more important that we learn the lessons it teaches. The cultivation of corn and its conversion to ethyl alcohol are subject to natural limits of scale that are lower than those for wind and solar power or plug-in electric cars, all of which also benefit from generous subsidies. Our pockets simply aren't deep enough to repeat our experience with ethanol subsidies with these other energy alternatives. In an era of fiscal limits, alternative energy tax incentives that are orders of magnitude higher per BTU or kilowatt-hour than those enjoyed by conventional energy sources should only be offered for a limited time, and then phased out on a predictable schedule before they take on the mantle of permanent entitlements.

A Geothermal Bankruptcy

I just caught up with last week's bankruptcy filing by Raser Technologies, Inc., a small developer of geothermal power plants. Burdened with excessive debt, Raser is filing for Chapter 11 protection to restructure its liabilities and continue operating under new ownership. In the process the current shareholders will see their much-diminished equity wiped out. This outcome is further evidence of just how challenging it is for small, poorly capitalized companies to exploit what is arguably the best, most reliable renewable energy technology in the world, other than hydropower.

Raser's bankruptcy hardly comes as a surprise. The company has been highly leveraged for a long time, and investors were losing patience with the firm. Last year its stock price fell below the minimum listing requirements of the New York Stock Exchange, and it moved to the over-the-counter market, effectively becoming a "penny stock." In the year prior to delisting, Raser had lost more than 80% of its market capitalization, or about $100 million. With only one operating asset generating cash--a 10 MW plant in Utah built with the help of a $33 million renewable energy grant from the US Treasury--and a number of projects under development consuming cash, Raser was losing the race to bootstrap its way into profitability.

Why is it so hard for start-ups to succeed in this space? It's not an accident that the world's largest geothermal operators are mainly big, well-capitalized firms like Chevron, Calpine, or the Green Power spinoff from Italian utility Enel. (Disclosure: I am a Chevron shareholder.) Geothermal developers face some fundamental challenges that require financial flexibility to manage. First is the capital cost of the assets, compared to other power generation technologies. The last figures I saw suggested that the cost of new geothermal capacity per installed megawatt was up to twice that of a wind farm and 4x that of a natural gas turbine. One reason the cost is so high is that it includes a lot more than the above-ground generating hardware.

Geothermal reservoirs must first be discovered, assessed, and drilled. That's why I've long thought that this technology is a natural for oil and gas companies, since it involves many of the same core skills. Geothermal exploration introduces not just additional cost, compared to wind power development, but also a daunting array of risks, including the possibility that the resource won't turn out to be as large as expected, or that its geology won't permit commercially attractive flow rates of steam and/or hot water. In the worst case, this results in the equivalent of a "dry hole", but even if it merely reduces the amount of power a given well can generate, that has a significant impact on project economics that depend on producing power predictably and reliably for decades. In effect, geothermal has all the up-front risks of oil and gas exploration without the quick payoff of a successful oil or gas well.

Geothermal power provides clean energy production for the power grid on a nearly 24/7 basis, something that neither wind nor solar power can match without energy storage capabilities that remain prohibitively expensive today, in most cases. However, it is both capital-intensive and risky to develop. The handful of publicly traded geothermal companies left after Raser's Chapter 11 filing, including firms such as Ormat Technologies and Magma Energy Corp., are doing yeoman work. However, it's hard to envision geothermal energy achieving its full potential without much greater participation from much larger, better-capitalized firms that could pursue such opportunities on a completely different scale.