How Green Is My Electric Vehicle?

One of the biggest challenges in assessing the environmental benefits of electric vehicles is that electricity is generated in so many different ways, with differing costs and consequences, and that patterns of generation vary by region, season, and time of day. As a result, categorical claims that EVs are always greener than the hybrids against which they compete most directly, or even compared to efficient non-hybrid compact gasoline or diesel-powered cars, must be suspect. The Union of Concerned Scientists (UCS) has just issued a report that takes some of the mystery out of such comparisons, including a helpful map showing likely greenhouse gas emissions associated with EV use expressed in terms of equivalent miles per gallon from a gasoline vehicle. The takeaway is that as of now, the emissions advantage of purchasing an EV depends heavily on where you live, with equivalent emissions from average grid power in many parts of the country about on a par with those from a small car like the Chevrolet Cruze, and not even as good as from a Prius-type non-plug-in hybrid.

This apparent paradox becomes clearer when you examine the cities map that the New York Times distilled from the report, reflecting the local basis of electricity generation. An EV operated in L.A. or San Francisco would unambiguously beat a Prius on emissions, while an EV in my neighborhood in Northern Virginia would have only a slight edge, and one in Denver would yield emissions comparable to an ordinary car getting 33 mpg, unless the owner was scrupulous about recharging only when greener power was available. That's because despite the declining share of coal-fired power in our national generation mix, there are still many regions and locales where coal dominates the grid, and the GHG emissions from coal-fired generation are considerably higher than from natural gas or low-emission nuclear and renewables.

Any report such as this must incorporate a number of assumptions, and from my fairly quick perusal of the details they seem generally well-identified here. The UCS's emission-equivalent miles per gallon calculation is based on a Nissan Leaf getting 3 miles per kilowatt-hour (kWh.) Grid emissions are calculated using a model of average hourly emissions over the course of the year. It didn't appear that these hourly-averaged figures were weighted for seasonal variations in driving patterns, but that's probably more nuance than is necessary at this level of scrutiny.

The report also includes information about recharging costs in different locations under different rate plans. Prospective EV buyers would benefit from taking the time to understand what these issues mean in their specific locations before investing in one. From my perspective, the report should also provide serious food for thought for policy makers concerning the wisdom of a single federal tax credit for EV purchasers in the US. As hard as that policy is to justify in the best of locations, based on the equivalent cost per ton of CO2 avoided, it looks positively senseless in locations where coal is still king. And while the report makes the point that the generation mix in many regions will become cleaner over time as utilities respond to renewable portfolio standards and other policies, buying an EV in a high-emissions region and counting on that factor to improve the car's environmental benefits during its lifetime seems like a risky bet, particularly in economic terms.

The biggest caveat I'd offer about the report concerns its emphasis on comparing EVs to non-hybrid compact cars, both on costs and emissions. That just doesn't seem realistic, given the array of choices and types of consumers in the market. While the number of consumers willing to consider an electric vehicle is increasing, the "take rate"--the number who actually convert their interest into a purchase decision, remains minuscule, resulting in sales of just 0.3% of all US cars sold in March. Meanwhile hybrids have benefited from rising gas prices to hit 3.4% of sales. It's also worth recalling that the fuel, emissions and dollar savings from improved fuel economy decline with each additional increment. Hybrids already capture the most valuable savings over conventional cars, while the incremental fuel savings from stepping up from a hybrid to an EV are roughly comparable to what hybrids achieve, but require additional battery capacity and electricity, neither of which is free. That makes hybrids the technology for EVs to beat. As helpful as the information provided in the UCS report should be for consumers, the ultimate decision to buy an EV seems driven more by values than value, at least until EV costs fall significantly.

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The Beginning of the End for Coal?

I saw in Tuesday's Washington Post that the EPA was ready to issue its proposed rules for CO2 emissions from new power plants. When finalized, these rules would apply to facilities larger than 25 MW that begin construction more than a year hence. As the Post notes, the chosen CO2 emissions limit of 1,000 lb. per gross Megawatt-hour (MWh) generated would make it virtually impossible for a new conventional coal-fired generating plant to comply with this requirement. That looks like another positive for natural gas, which is coal's nearest competitor today. It might also help baseload renewables such as geothermal, since wind and solar power don't ordinarily compete directly with coal. However, anyone reading this as the epitaph for coal in the US shouldn't be too hasty, because the EPA has left room for technology and other strategies to keep coal in the future mix.

I'm completely swamped with work and other commitments at the moment, so this posting will be more like an extended Tweet. However, I thought this news was too important not to comment on it, however briefly. Lacking the time to research these data myself, I'll rely on Ms. Eilperin's thoroughness and use her figures of 1,768 lb. CO2/MWh for the average US coal plant and 800-850 lb./MWh for gas. The latter is certainly a long way from state of the art, and I'm sure that a modern ultra supercritical coal plant would come in considerably below the 1,768 lb. mark, as well, yet still above the magic half ton. What intrigues me about the EPA's chosen performance standard is that meeting it would require much less than 100% capture and sequestration of a facility's CO2 emissions. Perhaps as little as 25-30% would be sufficient, particularly, if the plant were also designed to be co-fired with biomass, as some existing coal plants are. That combination, or some other similar strategy, could significantly reduce the cost of compliance and keep coal in the game.

I know that outcome wouldn't please those who see coal as not only the logical place to seek large-scale greenhouse emissions reductions, but also a major contributor to various local environmental impacts. Yet it's also an enormous domestic energy source, the global demand for which continues to grow. Moreover, as coal is increasingly displaced from power generation by cheap natural gas, its price is likely to drop, making it more competitive for export. So perhaps this isn't the beginning of the end for coal in the US, but just the start of a new phase.

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Shale Gas Likely to Alter China's Energy Mix

Two recent news stories highlight the significant shifts underway in China's energy sector, along with the global impact that is already apparent from these changes. Last week the Chinese government announced a new estimate for the country's potential resources of shale gas that is nearly double the Department of Energy's latest estimate for US shale gas. However, having the resource and developing both it and the infrastructure and market to take advantage of it are distinctly different things, as I pointed out in a brief interview on the subject on public radio's Marketplace program. The key to that may be found in a front-page story in today's Wall St. Journal describing the recent pace of Chinese investment in the North American energy sector.

When we think about energy in China, we tend to focus on the vast scale of its coal use, which affects local, regional and, at times, trans-Pacific air quality, to say nothing of its huge greenhouse gas impact. Coal made up 70% of China's total energy mix in 2010. Or we might think of the explosive pace of renewable energy deployment, although China's solar industry, and to a lesser extent its wind power industry, are still mainly export-oriented. Non-hydropower renewables, which were identified as a strategic industry within the 12th Five-Year Plan, account for just 0.5% of China's energy, but the government has recently indicated it would rein in the "blind expansion" of such sources. Together with hydro and nuclear, low-emission energy sources account for just 8% of the total, less than half the 18% share of oil, which is likely to continue expanding as the transport sector grows and encompasses more personal cars. That leaves natural gas with just 4% and a much lower profile than in the US, where it supplies roughly one-fourth of total energy.

If the resource figures that were just released are any indication, the potential growth of gas in China may exceed that of all other energy sources over the next several decades. Nor is that growth dependent on shale gas development, which is in its infancy there, with only a few wells having been drilled. China has some conventional gas production and a small but growing coal-bed methane industry, and it is already one of the world's largest purchasers of liquefied natural gas (LNG). Although the shale gas figures might seem like bad news for companies planning LNG exports from the US, or for the enormous new LNG projects in Australia and elsewhere in the region, they could prove complementary in two ways.

First, the current availability of large and growing quantities of LNG in Asia-Pacific provides the basis for developing both the enormous potential gas market in China's coastal industrial centers and the infrastructure for serving it, including the crucial "reticulation system"--what other industries call the last mile. You simply don't build this unless you have a large, reliable supply on hand, and you also don't develop huge new domestic supplies unless they have an assured market. LNG could thus be the key to avoiding a classic chicken-and-egg dilemma that might otherwise retard the growth of gas in China for years.

At the same time, the recently identified shale gas resources solve a major problem for LNG vendors, by reassuring Chinese buyers that they will have access to ample gas to satisfy industrial, commercial and residential demand long after the 20-year or longer LNG contracts expire and the reservoirs feeding the region's LNG plants are depleted. But that's only true if China acquires the expertise for developing its own gas, and that's where its North American energy deals come into play.

The Journal article provides a good overview of how Chinese companies changed their approach to North American oil & gas mergers and acquisitions in the aftermath of CNOOC's failed bid for Unocal in 2005. Chinese investors have learned not to raise the hackles that that deal did, and they have focused on minority shares in oil & gas companies or in specific field developments, mainly in unconventional plays such as the Eagle Ford shale in Texas with Chesapeake Energy. Even if no intellectual capital flows back to the investing companies, the mindset required for selecting and managing such projects surely will, and that will have a direct bearing on China's enormous new shale resources, which if proved up would equate to 230 years of current consumption.

No one can know at this point how durable last week's estimate of 25.1 trillion cubic meters (886 trillion cubic feet--TCF) of undiscovered, technically recoverable shale gas will be. The Energy Information Agency recently cut its previous US shale gas estimate of 827 TCF by 42%, based on updated information on per-well recovery rates and other factors, particularly in the Marcellus formation underlying New York, Pennsylvania and other northeastern states. (Despite being widely publicized by critics of shale development, this adjustment won't have any bearing on actual shale gas output for many years, during which the resource estimate is likely to be further refined many times.) China will gain similar experience as it develops its shale resource and should have a much better handle on its probable size within a few years. As with nearly everything else related to the country's economic development, the number is still likely to be very big.

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Because That's Where the Emissions Are

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

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

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

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

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

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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.

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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.

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Industrial Scale Ethanol

After my recent posting on resurgent food vs. fuel competition from expanding corn ethanol production, one of my contacts called to ask if I was familiar with an industrial process developed by Celanese Corporation for producing ethanol from a variety of feedstocks, including natural gas, coal, and potentially cellulosic biomass. My initial reaction to him was based on my knowledge that such processes have been around for decades, and that until the policy-inspired growth of the corn ethanol industry, much of the ethanol for industrial use was produced in that fashion. However, I was unaware of plans to deploy this technology on a truly massive scale, in the form of a pair of 400,000 ton-per-year coal-to-ethanol plants in China. I consider this a really interesting development on several levels.

The attraction of producing ethanol for industrial or fuel use from indigenous non-food raw materials in China seems obvious. It enhances the country's food and energy security by avoiding imports of both. As I delved into the technology involved, I realized it starts with gasification, a process that my former employer, Texaco Inc., licensed to numerous facilities in China, going back to the 1980s. So China has deep experience with gasification as an effective and reliable way to turn feedstocks as diverse as waste oil, petroleum coke, low-value coal, and even natural gas into syngas, or synthesis gas, a mixture of carbon monoxide and hydrogen from which all sorts of useful organic chemicals can be produced. One of those is acetic acid (the acid in vinegar.) It turns out that Celanese's new ethanol process is an offshoot of the company's well-established "acetyl platform" for making acetic acid in plants like this one in Singapore.

It's noteworthy that the first ethanol plants Celanese is building are so large. 400,000 metric tons per year equates to 134 million gallons per year, larger than all but a couple of the corn-based ethanol plants in the US. I've also seen hints that these facilities could be expanded to 1 million tons/yr, which would put their output in the same league as the gasoline yield of the smallest oil refineries. That would be truly industrial scale fuel production that conventional or advanced biofuels can't yet match and may never do, because of their much more complex supply chain considerations. That also explains why Celanese could consider building a 40,000 ton ethanol plant in Texas based on natural gas. The supply chain isn't an issue when it's just an existing pipeline. In any case, large scale and low feedstock cost should result in ethanol output that's more than competitive with ethanol from biomass. US biofuel producers eyeing export markets ought to be concerned about the potential competition from Celanese, even if the federal Renewable Fuels Standard (RFS) guarantees them a market here.

My other instant reaction when I heard about this process focused on the potential environmental consequences of producing ethanol from coal. However, as I thought about it more carefully, it occurred to me that processing coal into ethanol using the extremely clean gasification process, which allows for sulfur and other contaminants to be easily and safely collected and disposed of, is probably a lot more benign than burning the same coal to produce electricity, particularly in power plants without state-of-the-art pollution equipment. Assessing the greenhouse gas impact of coal-to-ethanol requires a thorough lifecycle analysis that I have not yet found.

At the same time, it's clear that the environmental comparison to biofuels like corn-based ethanol isn't nearly as bad as suggested by an erroneous comment in a Business Week article on the subject last November, which stated that corn ethanol production "doesn't use a fossil fuel as a raw material." In fact, analysis by the Argonne National Laboratory of the US Department of Energy found that 78% of the energy in a typical gallon of corn ethanol comes from fossil fuels, including coal, diesel fuel, and natural gas. That's why the emissions from corn ethanol aren't much lower than from gasoline, after factoring in the natural-gas derived fertilizer used in growing the corn, the diesel fuel required for cultivation, harvesting and transportation, and the coal and natural gas used to generate electricity and process heat for the fermentation and distillations steps. Ethanol from coal might emit incrementally more greenhouse gases than food-crop based ethanol, but not orders of magnitude more. And I'd bet that a gas-to-ethanol plant would match or beat the emissions from a standard corn-based biorefinery, based on avoiding the need to separate the alcohol product from water. Distillation requires lots of energy.

It's getting harder to draw meaningful distinctions between conventional fuels and alternatives when we can make ethanol efficiently from fossil fuels and produce "drop-in" fuels--synthetic gasoline, diesel or jet fuel--from biomass like sugar cane or algae. I haven't seen how the detailed economics and energy balance of the Celanese ethanol process compare to traditional and advanced processes for producing ethanol from biomass, but I think we're going to be hearing a lot more about this option in the future. I was surprised to see that it even garnered a mention in the White House press release for the President's visit to China earlier this year.

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Still Not Worse Than Coal

At the end of last year I examined assertions by a professor from Cornell University, based on his unpublished paper, that leakage from natural gas production and transportation systems in the US resulted in lifecycle emissions for gas that were actually worse than those from coal. From what I saw at the time, I couldn't agree with his conclusions. Now Professor Howarth's paper is apparently about to be published, with a specific focus on shale gas. It has already been leaked via the New York Times and The Hill news site. After seeing the data and calculations supporting its claims, I am still not persuaded, though I would be quick to concede that the subject deserves a more thorough assessment by a body actually equipped to gather the necessary data and process it rigorously.

I don't make a habit of reviewing scientific papers, but this one begs for a critique, for two reasons. First, it's appearing in the middle of a crucial national debate on the potential risks of the techniques involved in unlocking the potentially game-changing shale gas resources that have been found in the US and elsewhere around the world. What better way to make those risks--which I believe to be entirely manageable--seem not worth taking than by portraying shale gas as having more adverse environmental consequences than the chief fuel its supporters see it displacing: coal. So at a minimum the paper demands careful scrutiny because of its potential significance to the debate surrounding the largest energy opportunity the US has uncovered in decades.

In addition, practically every paragraph includes an assumption, simplification or choice by the authors that tends to increase the calculated environmental impact of natural gas. Whether that's the result of bias or merely a series of judgment calls, it undermines confidence in the final conclusions at the same time it amplifies them. I'll focus on the most significant of these decisions and forgo the questioning of many individually less-important, though still cumulatively consequential details for others better equipped to tackle them.

Probably the most significant choice the authors made was to emphasize the global warming impact of methane (the main component of natural gas) over a 20-year period, in preference to than the more commonly used 100-year interval. Then they bypassed the established Global Warming Potential (GWP) factors from the UN IPCCC's Fourth Assessment Report to use much higher factors for methane from a 2009 paper published in Science. I'll leave the angels-on-a-pin debate over this to the climate scientists, but I don't believe you need a Ph.D. in atmospheric physics to understand that if the outcomes of climate change will truly be determined in the next 20 years, we are already cooked. The world can't get global emissions down by enough, fast enough, to solve the problem on that time scale, at least not without a global economic shock that would return hundreds of millions of people to poverty. So when I recalculated the paper's estimate on shale gas emissions, I did so using the consensus 100-year GWP for methane of 25--less than 1/4 of the one on which the paper's scariest results rely.

The other major choice the authors made was to ignore the downstream conversion of gas and coal into electricity. As lifecycle analysis, this earns a failing grade. It's like comparing the overall emissions of a Nissan Leaf and Ford Explorer by focusing only on what happens upstream of the battery charger and the fuel tank. The authors dismiss this by saying that "this does not greatly affect our overall conclusion". That's wrong, not least because it's precisely the comparison of how gas and coal actually compete with each other that matters most here.

On the basis of these two points alone, the paper's conclusions crumble, even with the inclusion of supposed methane leakage rates from shale gas production that would have any engineer worth his or her salt scrambling to redesign the equipment so as to capture so much valuable "lost and unaccounted for" output. So how do shale gas and coal compare, on a full lifecycle basis from well and mine to the power plant bus bar, if 3.6-7.9% of gas actually leaked out during well completion, processing, transportation, storage and distribution, as Dr. Howarth's paper suggests?

Let's start at the power plant and work backwards. A current combined-cycle gas turbine unit requires around 6,700 BTUs of gas to generate a kilowatt-hour (kWh) of electricity. At the rate of 117 lb. of CO2 emissions per million BTUs of gas burned, that yields power plant emissions of 0.78 lb/kWh. But that's on the basis of the gas that reaches the turbine's combustor. We have to gross up that result to account for the emissions that occurred upstream of the plant. At Howarth's estimated leakage midpoint of 5.75%, and using the standard 100-year GWP for methane compared to CO2 on a molar, rather than mass basis, that leakage would add an extra 55% of CO2-equivalent emissions from the well to the combustor, bringing the effective emissions from that combined-cycle plant up to 1.2 lb/kWh. For comparison, the most efficient coal-fired power plant I know of (without carbon capture and sequestration) emits about 1.75 lb/kWh. Only if we included inefficient, simple-cycle gas "peaker" units that don't normally compete with coal would the upstream emissions that Dr. Howarth posits result in lifecycle emissions from gas-fired power worse than the typical coal-fired generation emissions of around 2 lb/kWh. In other words, the gas-fired generation that actually competes with existing coal plants still appears to emit nearly 40% less GHGs than its coal competition, even assuming the shale gas leaks that Dr. Howarth and his contributors reported.

Although my analysis admittedly falls into the back-of-the-envelope category, I'm not sure that the Howarth, et al paper is many notches above that level, given its reliance on non-peer-reviewed sources and its references to irrelevancies like Soviet-era gas systems. All in all, it seems a shaky edifice on which to mount such provocative conclusions. Perhaps all the authors wanted to do was to highlight some areas for the gas industry to investigate further, in order to ensure that methane emissions are kept to a minimum as shale and other unconventional gas deposits are developed. Unfortunately, it seems all too likely that its headline findings will be touted by those who are determined to stop the shale gas revolution in its tracks, or at least delay it for long enough that its utility in addressing our pressing energy problems will be lost. I wonder what Mr. Pickens thinks about all this, given that legislation promoting his plan to convert portions of the US truck fleet to natural gas, which depends on abundant shale gas supplies, has finally attracted bi-partisan support, including from the White House.

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Fewer Choices Post-Fukushima?

Even before the resolution of the crisis at the Fukushima Daiichi reactor complex--a crisis that has diverted media attention from the much larger humanitarian crisis caused by last Friday's tsunami--its consequences for nuclear energy policy are rippling across the globe. It is extraordinarily premature to form conclusions about these events, although that didn't stop many from arriving at similarly hasty and under-informed conclusions in the case of last spring's Deepwater Horizon accident. Pervasive instant analysis promotes knee-jerk responses. If the nuclear renaissance that had already been slowed by the recession and financial crisis was struck a fatal blow last week, what could that mean for our energy choices in the years ahead?

Although I want to focus mainly on the potential consequences in the US, what has already transpired in Germany provides a cautionary tale. As reported Tuesday, seven nuclear power plants of similar vintage and/or design to the damaged quartet at Fukushima are being shut down, at least temporarily, as the German government reassesses its decision to extend the operating life of the country's 17 power reactors. Germany hasn't been comfortable with its nukes for some time, though I find it remarkable that 70% of the population is apparently concerned that an accident that required an epic earthquake and a tsunami to trigger could happen there, too. (The next time someone lectures you about German practicality, this would be a fine counter-example to trot out.) However odd that reaction might seem to me and others with an engineering/hard science bent, it's a reminder that nuclear risks are viewed differently than many others, perhaps because radiation is invisible and insidious in its effects. Even if the reactors are finally cooled down with no further incidents and no injuries beyond the plant personnel, who have taken great risks for the public good, we will tend to focus on how much worse the outcome could have been.

Yet shutting down those nuclear plants in Germany is not without consequences, either, as noted by the Breakthrough Institute. Germany's greenhouse gas emissions will inevitably increase, because the country is already adding renewable generation as fast as it can and must make up any shortfall from fossil fuels. After committing an estimated €120 billion ($167 billion) for solar power through 2011, based on the 20 years of feed-in tariff support existing installations will receive, Germany still gets just 2% of its annual generation from solar, compared to around 24% from nuclear. That's mainly because Germany is such an unsuitable location for solar.

What about the US? Nuclear power supplied almost 20% of the electricity generated here in 2010, compared to 45% for coal, nearly 24% for natural gas, 10% for all renewables, and less than 1% from oil. Any notion of replacing the contribution of nuclear power in the longer term would require careful consideration of the energy sources that might fill the gap--based on scale and growth potential--and what it would mean for efforts to cut greenhouse gas emissions by reducing the generation of electricity from coal, which accounted for 81% of the emissions from the electricity sector and 26% of all US emissions in 2009. As for replacing nuclear power in the short run, that's simply out of the question, unless we want to bring on a recession that would make 2009 look like a boom year.

It's not that it's impossible to imagine a US energy mix without nuclear. After all, that's what we had on a much smaller scale prior to the 1960s. We certainly have enough coal and natural gas to take up any slack, although I don't think that would be quite the desired solution of those who would be most eager for an end to nuclear power. For that matter, a combination of geothermal power and concentrated solar power (CSP), the former baseload and the latter at least dispatchable, could also fill the gap, although a geothermal build-out on that scale would provoke concerns about "induced seismicity", while CSP would be largely a regional solution or require lots of very long-distance, high voltage power lines that present massive NIMBY issues of their own. Wind power, which until last year was growing at around 40% annually, could provide 20% or more of the generating mix by 2030, but it can't substitute for nuclear's central role without far more cheap power storage than we can reasonably expect to have available by then. And while solar has great potential, especially as its cost falls, it's no better suited to delivering reliable 24/7 power than is wind, and it is starting from an even smaller level than wind's 2.3% of generation last year.

The likeliest replacement for nuclear power in the US would thus be a combination of sources similar to our current non-nuclear mix, comprised of about 55% coal, 30% gas and 15% renewables, with some help from efficiency. On the basis of the average emissions from these sources, making up for the loss of the 807 billion kilowatt-hours generated by nuclear last year would increase US greenhouse gas emissions by around 580 million tons of CO2-equivalent per year, or 10% of net US emissions in 2009. That would hardly be conducive to meeting our Copenhagen pledge to reduce emissions by 17% by 2020, but then in a non-nuclear world most such pledges would have to be considered null and void.

Barring a worst-case outcome in Japan, I don't expect a groundswell in the US if favor of abandoning nuclear power--not even for the 35 reactors of generally similar design to the ones at Fukushima. Despite that, the emissions figures I calculated above remain relevant. Without a concerted effort to build new power reactors in the next two decades, the US will be on a sure path to de-nuclearization, as 41 of the existing plants would reach the end of their lives and operating licenses--many after a full 60 years of operations--by the mid-2030s. That process could accelerate significantly if the facilities that are awaiting license extensions now face much tougher scrutiny and are turned down in significant numbers. In that case we could lose up to 10,000 MW of nuclear capacity by the end of this decade, generating roughly the same annual output as our entire current wind power capacity. There are some who are already working to make that happen, either openly or more subtly. In that context the story on MSNBC yesterday listing US nuclear reactors in order of earthquake risk was either a public service or fear-mongering, depending on your perspective.

Whether we back away from nuclear power all at once, as Germany seems poised to consider doing, or one plant at a time, the result would be much the same: increased emissions, costlier and less reliable power, at least in the near-to-medium term, and more strain on infrastructure. I still think we'll choose to include nuclear in our evolving future energy mix, particularly given the significant improvements in the technology since the Fukushima reactors were built, along with the development of new, smaller-scale nuclear power options. Yet I have to admit my confidence in that result has been shaken by the reaction to the events in Japan.

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A Nuclear/Gas Alliance?

As I was scanning the news of the last few days I was intrigued by a headline featuring the CEO of the largest owner/operator of nuclear power plants in the US, Exelon Corp., extolling the virtues of natural gas and advocating an increase in its output. That might not sound earth-shattering, especially considering that Exelon also owns a fleet of natural gas-fired power plants with combined output equivalent to several nuclear reactors, unless you are convinced that nuclear and gas are engaged in a tooth-and-nail competition to supply America's future electricity needs. However, it's certainly attention-getting for Mr. Rowe, whose company recently acquired the substantial wind-generation business of John Deere, to go on record opposing clean-energy subsidies for a range of low-emission technologies.

The main message of Mr. Rowe's address at the American Enterprise Institute was apparently that Congress shouldn't interfere further with markets, regulations and technologies that he sees already being sufficient to reduce carbon emissions and clean up the air. Yet while I'm usually reluctant to read too much into remarks I wasn't present to hear, I do think it's possible to infer an alternative strategic dynamic to the nuclear vs. gas narrative that I have encountered in a number of blog postings in the last few years, particularly since shale gas production took off and the anticipated nuclear renaissance in the US encountered resistance. Because it's uncommon to hear CEOs touting their competition, I think it's safe to conclude that Exelon views nuclear and gas as complementary--a view I share--rather than competing for the same segment of the market.

It also sounds like Mr. Rowe sees gas and nuclear competing with coal, which makes eminent sense in the context of environmental policy and typical grid power-dispatch curves. Competition between nuclear and coal was especially obvious when both were viewed as enhancing energy security and before concerns about greenhouse gas emissions had become mainstream. And as recently as a few years ago, when most forecasts anticipated declining US gas production and rapidly increasing imports of LNG, yielding even more volatile natural gas prices, coal-fired power plants were the principal large-scale alternative to both new nuclear and gas-fired capacity. Today's emphasis on emissions, combined with next-generation reactor technology, gives nuclear an edge over coal in baseload for locations where communities are comfortable with the technology, while gas has a more than a 2:1 lead over coal in planned new generating capacity and seems likely to do even better in terms of capacity actually built, due to its substantial lifecycle environmental advantages.

It's also possible to envision a future grid relying mainly on nuclear for baseload power and natural gas for flexible power, without the need for any coal generation at all. Moreover, with the addition of smart grid technology and new long-distance transmission, that combination should provide a very hospitable environment for much larger increments of renewable energy. Gas-fired backup power remains the best enabler for incorporating intermittent generation from wind and solar power, particularly when these technologies are combined in installations such as Florida Power & Light's new hybrid solar/gas power plant in southeast Florida. That seems like a much more realistic approach than the notion of an all-renewable grid based on energy storage, even if storage technology were to become more effective and much cheaper. (Storage has a key role to play in the future grid, but I believe it will be used mainly for short-term buffering and for storing the cheapest off-peak power from any source, rather than as dedicated storage for renewable power.)

The biggest potential obstacle to this scenario is growth, or the lack of it. In a US electricity market that is barely growing at all, in contrast to the steady 2% or so per year expansion in demand from 1997-2007, and with renewables given the first shot at satisfying any growth in a majority of states, the only opportunity that looks big enough for both nuclear and gas-fired power to cooperate on is coal displacement. Yet if you agree with Mr. Rowe that "carbon legislation is dead", it's a lot less certain that coal would go away fast enough for the combination of gas and nuclear he is promoting to become the de facto future. It remains to be seen whether the market, together with an increased emphasis on local pollutants--excluding CO2--under the Clean Air Act will be sufficient to squeeze out a coal industry that, along with its numerous stakeholders, will not depart without a fight.

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High Coal Prices Bode Well for Renewables

I don't pretend to follow the coal market to any great extent. No one can keep track of everything. However, as I was reading an article in today's Wall St. Journal on the impact of the current Australian flooding on US coal exports, and another in the Financial Times concerning the implications of the timing of the floods for annual coal contract pricing, the dots seemed to connect. It struck me that all other things being equal, higher coal prices ought to be positive for natural gas, the main substitute for coal in electric power generation, while also giving renewable power a shot in the arm. That couldn't come at a better time for US wind power developers and the wind turbine manufacturers that supply them, many of whom are coming off a bad year.

As the Journal points out, the Australian state of Queensland is the leading exporter of the coal used in making steel. With much of Queensland under water, US coal exporters are finding a ready market for their output, with exports expected to surge by 10% this year. Although metallurgical coal represents a different segment of the market than the thermal coal that goes into power plants, the internationally-traded market for the latter has also tightened considerably, with prices well above $100 per ton, and apparently above their 2008 record levels. Nor is this solely the result of the Australian floods. Despite coal having fallen into disfavor in the US, its global fundamentals remain strong, supported by robust economic growth in developing countries that rely on it as a source of cheap and reliable power generation. China's coal demand has nearly tripled since 2000.

The first beneficiary of higher coal prices ought to be natural gas. The competition between gas and coal is complex, depending on the interaction between demand and available generating capacity in regional power markets. However, between 2007 and the most recent 12 months for which EIA data are available, the overall share of gas in US power generation increased from 21.6% to 23.7%--even as total electricity demand declined by about 2%--while coal's share fell from 48.5% to 45.4%. Much of this shift has been facilitated by the effect of expanding natural gas production on the price of gas into the power sector. The total share of non-hydro renewable power also grew during this interval, from 2.5% to 3.8%, even though intermittent sources like wind and solar power are likelier to compete head-to-head with gas-fired generation, rather than coal. So if renewables were taking share from gas, as a result of federal renewable energy incentives and state renewable portfolio standards, then gas was taking even more share from coal.

Today's high coal prices ought to support the continuation of that dynamic. While more expensive coal might not lead directly to the construction of more wind farms, it should certainly push up prices for baseload and mid-load electricity, making gas more competitive in those segments. That ought to boost gas prices, in turn making renewables more competitive with gas. Add in the return of some of the electricity demand that disappeared during the recession and developers of wind and solar projects should see increased interest from utilities in signing long-term power purchase agreements (PPA) for their output. The lag in PPA interest and weak financing environment were big factors in last year's lull in US wind turbine installations, which appear to have been the lowest since at least 2007, at roughly half the record level set the previous year.

That disappointing performance came in spite of the industry's receiving $3.2 billion in Treasury renewable energy cash grants, which were extended with much fanfare for another year as part of the lame duck tax compromise. Anyone expecting the extension of these incentives to lead to a surge of wind turbine installations this year was paying too much attention to their own PR; the best the industry could realistically have hoped for in the extension was to avoid falling off a cliff. However, if coal prices remain strong for the balance of the year and the economy continues on its current pace of recovery or improves on it, then the combination of all these factors just might contribute to a healthy rebound for wind.

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The Year of Regulation?

Some new years seem newer than others, bringing major changes rather than just the turning of a calendar page. 2011 is shaping up that way, with a return to divided government in the US and the beginning of national greenhouse gas regulation by the EPA based on that agency's interpretation of the Clean Air Act, rather than as a result of explicit new Congressional legislation. As the ongoing legal battle over this between the EPA and the state of Texas demonstrates, there's a lot at stake, and the final outcome has not yet been determined.

When the US Supreme Court ruled in 2007 that CO2 and other greenhouse gases constituted pollution that was subject to regulation under the Clean Air Act, it set in motion the process that is now culminating with the EPA's proposed rules for regulating these gases. Initially this will take the form of what the agency calls New Source Performance Standards, applying only to new facilities and modifications within existing facilitates, and only for sources emitting more than 50,000 tons per year of greenhouse gases (GHGs). That exempts residential and most business activities using less than the energy equivalent of about two gasoline tank-trucks per day. The first phase of these regulations is specifically targeted at power plants and oil refineries, and over time it could significantly alter the way that electricity is produced and oil refined in this country.

I've argued for years that this is entirely the wrong way to go about reducing emissions, because greenhouse gases are global, rather than local in effect, and a command and control approach applied to point sources of CO2 and other GHGs will miss many of the least expensive emission reduction opportunities while forcing businesses to focus their efforts on some of the most expensive. Cap and trade or some other means of establishing a price on emissions would have been much more efficient, although the version of cap and trade passed by the House of Representatives in 2009 was a miserable excuse for such a system, distorted as it was by preferential treatment for favored groups and sectors.

But this isn't just a question of economic efficiency; it's also a question of effectiveness. Regulating power plant emissions addresses 34% of total gross US GHG emissions, including roughly 92% of the emissions from the coal value chain, while regulating refineries tackles less than 10% of the emissions from the petroleum value chain--and some of the hardest ones to cut, at that. Refineries are already about 90% efficient. Squeezing even more efficiency from them--which would be the net effect of capping their GHG emissions, since most of those are associated with the combustion of fossil fuels--is likely to cost a lot more than the value of any energy savings such changes would yield. That could have a significant impact on states like Texas, which is home to more than a quarter of the country's refining capacity. The result would also increase national energy costs in either of two ways, with higher operating costs at US refineries being passed on to consumers in the price of fuels, or by reducing US refining throughput and capacity and increasing our reliance on product imports. The latter works directly against the widely-held notion that anything that reduces emissions must automatically be good for our energy security.

None of this is set in stone, although I certainly wouldn't bet against some version of it coming into effect. The incoming Republican chairman of the House Energy and Commerce Committee has already indicated his determination to restrain the regulation of GHGs by the EPA, and even without a majority in the Senate the House, which controls the government's purse strings, could make it much harder for EPA to pursue this course. At the same time, several previous sponsors of Senate energy and climate legislation have expressed interest in a new, bi-partisan approach to energy, and it's not inconceivable that watering down the proposed EPA regs could become part of a deal to establish a national low-emission energy standard that would include not just renewables, but also nuclear energy and possibly even natural gas. I will be watching these developments with great interest in the weeks and months ahead.

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Worse than Coal?

As I noted in last Wednesday's posting, one of the questions that came up in a webinar on shale gas in which I participated concerned the climate consequences of higher recent estimates of methane leakage from US natural gas systems. In reading further comments and blog postings on this subject, I was surprised to see assertions that went beyond drawing attention to the importance of the leakage of a high-value, high global-warming-impact gas, to suggest that the apparent rate of leakage renders the lifecycle emissions from natural gas as bad as those from coal, or worse. If that were true, it would have significant implications not only for the development of shale and other natural gas resources, but also for our entire emissions reduction strategy. From what I can tell, however, such claims have not been substantiated by current studies.

Several comments I received in email or on the posting pointed to the work of Professor Robert Howarth of Cornell University, and specifically to a press release describing a paper he has apparently submitted addressing the climate impact of methane leaks from shale gas production, transportation and storage. Until the details of the paper are available, the information provided in the press release simply doesn't stand on its own or merit further analysis. In the meantime, a recent EPA report evaluating greenhouse gas emissions from the oil and gas industry identifies significantly higher estimates for methane emissions from natural gas systems than those incorporated into that agency's most recent US Greenhouse Gas Inventory. I became aware of the EPA report in the course of reading one of the blog postings I alluded to above.

The EPA estimated the total CO2-equivalent methane leakage from the production, processing, transportation, storage and distribution of natural gas in the US in 2006 at 261 million tons per year. That amounts to more than 4% of total net US emissions for that year, so it is hardly insignificant. It's also about 2.5 times the figure reported in the agency's latest GHG inventory. Converting that quantity back into natural gas at normal conditions yields 656 billion cubic feet of gas, or 3.4% of marketed US natural gas production in 2006. That's a lot higher than typical leakage estimates of less than 1%, as David Lewis notes in his blog. The question is whether this higher level of leaks, or some even higher notional level of leaks proposed by other critics, would be sufficient to make the emissions from gas worse than those from coal.

To understand why that might even be possible, you have to know something about the relative strength of different greenhouse gases (GHGs). While much of the public's attention has been focused on CO2, the most prevalent man-made GHG, other gases have dozens or hundreds of times the impact on climate, per ton. Because of the way it decays in the atmosphere, methane's global warming potential (GWP) starts high and diminishes over longer time spans. Most reports, including the EPA's, use a 100-year GWP estimate indicating methane is around 21 times worse than CO2.

However, it's not correct to infer from that that upstream leaks of 3.4% of all natural gas must therefore inflate the lifecycle emissions of the gas we consume by 21 times 3.4%, or 71%. That's because a ton of methane doesn't convert to a ton of CO2 when burned; it yields 2.75 tons, as a result of basic high school chemistry:

CH4 + 2O2 --> CO2 + 2H20

So for each ton of natural gas, it's roughly 7.6 time worse for it to be vented or leaked than burned, after adjusting methane's standard GWP for the ratio of molecular weights from the above reaction equation. In fact, when I added the EPA's latest methane emissions estimates to their figures for indirect and direct CO2 emissions from natural gas in the GHG inventory, the result was very close to the 26% increase you'd get from multiplying 3.4% by 7.6. As a result, although the emissions advantage of natural gas over coal is less than it would be without such a high rate of leakage, gas still emits 35% less CO2 equivalent per BTU over its lifecycle than coal, on average.

When you consider how natural gas actually competes with coal, its effective emissions advantage should be larger than that. Even after accounting for upstream emissions (including leakage) that add 30% to its CO2 emissions from combustion, an efficient combined-cycle power plant still generates electricity with emissions per kilowatt-hour that are more than 40% lower than those from a highly-efficient coal plant. That's because the combined cycle turbine converts more than half the BTUs in its fuel into electricity, while the coal plant converts less than 40% of coal's BTUs into power. Fewer BTUs for the same output results in fewer emissions.

I don't claim my back-of-the-envelope analysis is definitive, but it certainly doesn't support the notion that gas is worse than coal. Barring conclusive evidence of a much higher level of upstream natural gas leakage than indicated by the EPA's latest work on the subject, natural gas--even with existing infrastructure--could reduce the emissions associated with coal use in power generation by at least a third, and by much more than that depending on the specific generating facilities involved. At the same time, that shouldn't be read as excusing avoidable leaks of gas. If that 3% figure is accurate or low, then several billion dollars worth of gas--even at today's depressed prices--is escaping into the atmosphere rather than being captured and turned into useful energy by gas customers. That sounds like the epitome of low-hanging fruit to me.

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German Solar: Too Much of a Good Thing?

Until the recent reduction of its feed-in tariff, Germany provided some of the most generous solar incentives in the world. However, based on a statement last week by the head of the German energy agency, DENA, the rapid solar buildup threatens to overwhelm the country's power grid. Stephan Kohler proposed capping the amount of new solar that could be added each year at 1,000 MW, or around 10% of the capacity in place as of the end of 2009, in contrast to the 3,800 MW added last year, and as much as 6,000 MW expected to be added this year. Germany's solar incentives are often held up as a model for others to follow, but that rarely takes into account a growing list of unintended consequences that now appears to include grid congestion at high solar penetration.

The problem that Herr Kohler identified is rooted in the large disparity between the average and peak output of solar panels installed in high latitudes and under Germany's notoriously cloudy skies. The principal consequence of this disparity has been economic: it takes a lot more megawatts (MW) of solar capacity to produce the same output in Germany as in a sunnier location such as Spain, North Africa, or the US Southwest. The German government has overcome this impediment by throwing money at the problem. Until recently Germany had some of the most generous solar incentives in the world--generous enough that Germany accounted for more than half of all new solar installations last year. Even after several rounds of cuts this year, the owner of a new building-mounted solar array can still collect up to €0.33/kWh, equating to $0.46/kWh at the current exchange rate. Under the feed-in tariff system, utilities pass on the extra cost of buying renewable power to ratepayers, and as reported by the German Energy Blog recently, that will add €0.035/kWh ($0.049/kWh) to the average consumer's bill next year. Nearly half of that premium is attributable to solar power, even though it apparently accounted for only about 7% of all renewable power generated in Germany in 2009, because the country is such a poor location for solar power.

On average, every MW of solar capacity installed in Germany generates only about 100 kW over the course of the year. If that were a constant, it would be a lot easier for grid managers to accommodate. But of course that capacity generates nothing at night, while still putting 1 MW into the grid at noon on a bright summer day. That's more than twice the peak-to-average output ratio for solar in a good location in Southern California, Arizona or Nevada. The difference affects how much backup capacity must be available to the grid and likewise how much other capacity must be taken offline as solar output ramps up daily and seasonally. It also determines the nature of that swing capacity. While in a sunny location it might suffice to keep a few "peaking" gas turbines on standby--a role that might even be filled by electricity storage in the future--in a place as un-sunny as Germany it requires substantial capacity capable of running economically for many hours a day, week after week. That doesn't sound like a recipe for replacing German coal-fired power plants (or nukes) with photovoltaics.

Everyone knows solar power is cyclical. However, while I've tended in the past to ignore peak output and focus on the average output of solar in a given location, because that's what determines how much energy is actually delivered over time, the implication of Herr Kohler's comments is that the low capacity utilization inherent in solar installations in northern, cloudy regions amplifies the impact of solar's cyclicality. It's starting to look like the German feed-in tariffs, which were certainly effective as a solar policy in maximizing installations, despite Germany's disadvantages of climate and geography, weren't a very smart energy policy. They've placed too much emphasis on a technology that under German conditions only yields a third as much energy, on average, as the same amount of wind capacity, while still being capable of swamping the grid when the sun does shine. I hope that policy makers and grid planners in such similarly sub-optimal locations for solar as New Jersey and Ontario, Canada are paying very close attention.

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Locking In Gas Prices

I recently received an offer from my household natural gas supplier, Washington Gas, to lock in my gas purchases for the next 12 months at a price of $0.699/therm. They reminded me that I had paid as much as $0.96/therm and as little as $0.68/therm over the last 12 months, before distribution charges, so on the surface this looks like a good deal. Of course the real measure of the attractiveness of this offer is not what I've paid in the past, but what I'm likely to pay in the future if I don't take advantage of it. Unsurprisingly, Washington Gas left that for me to work out. This is no simple task, even if you follow energy trends as closely as I try to do.

The price of natural gas is notoriously volatile, particularly in years when supply is tight, the economy strong, and weather extreme. Historically, gas often spiked in the winter months, as cold weather drew down stockpiles, and traders bid up the price for prompt delivery. That pattern has shifted somewhat in recent years, as seen in the chart below, not because global warming is making winters warmer--though that seems to be the case in the most general sense--but because US gas consumption patterns have shifted.

In 1997 residential users accounted for 22% of total US gas demand, commercial and industrial users took nearly 52%, and just 18% went to power generation. Last year residential use was 21%, but commercial and industrial had fallen to 40%, while the power sector took over 30%. And since power generation, for which gas turbines are often the incremental supply, typically peaks in the summer months, the annual peak of gas prices is now as likely to occur in June or July as in January or February. That's an important consideration if you're a residential customer like me. Of the roughly 1,100 therms my household consumes each year, 84% are bought between November and March.

In this context the first place to check on whether the offer from Washington Gas is fair was the futures market. Yesterday's average closing price for the one-year "strip" from November 2010 to October 2011 was $4.26/million BTUs. That's the price at the Henry Hub, a gas distribution point in Louisiana. In order to compare it to what I've been offered, I need to account for the average differential, or "basis", between that location and the supply point for Northern Virginia. The "city gate" price for Virginia over the last year averaged $2.39/MMBTU higher than Henry Hub. Even that doesn't quite get me to the Purchased Gas Price that shows up on my utility bills. Over the last 12 months I paid an additional $0.60/MMBTU, on average, because the mix Washington Gas sells me includes gas purchased under long-term contracts, as well as incorporating the results of its hedging activities. When I add all this together, the equivalent futures-based price to compare to the deal I've been offered for the next 12 months works out to about $7.25/MMBTU, or $0.73/therm. For the November-March period that will affect me most, it's around $0.71/therm.

From that I conclude that my supplier is offering me a price that's in line with the market, and that I couldn't beat it even if I did the hedging myself. However, it's important to recall that the futures market isn't a forecast; it's just the current consensus on what buyers and sellers are willing to agree on today, based on everything they know. In order to decide whether I should lock that in and give up any upside or downside, I ought to have a point of view on gas prices, based on supply, demand and inventories. The supply side is dominated by surging shale gas output, which has taken US gas production to levels we haven't seen since the 1970s. For production to drop by enough to drive up prices significantly within the next year, the shale gas bandwagon would have to slow appreciably. That's certainly possible. In several presentations at the recent IHS Herold Pacesetters Energy Conference I saw graphs indicating that a number of producers aren't covering all their costs at current prices. Some of them must continue drilling new wells in order to satisfy the terms of their leases, but others could slow down if they chose. A slowdown in drilling would translate into reduced supplies fairly quickly, because of the rapid drop-off of output from individual wells. Even bigger supply risks are inherent in the growing environmental concerns surrounding shale gas drilling, which have seen New York's state senate vote to impose a moratorium on shale drilling. Yet while it's hard to envision a big enough drop in output from any of these factors, soon enough to affect this winter's prices, it's even harder to see so much additional shale gas coming to market in the next year that it would drive prices well below current levels.

On the demand side, the weak economy dominates, particularly in the industrial sector, which despite having rebounded from last year's lows is still running well below its consumption in the early 2000s. A sizable fraction of that lost demand isn't coming back, even if the economy started growing at rates more characteristic of past post-recession expansions, because the high gas prices of the previous decade drove some fertilizer and petrochemicals producers out of business or offshore. The biggest upside demand potential comes from the power sector, which is also suffering from low demand, at the same time we see low gas prices and environmental pressures displacing coal with gas and renewables. That's a clear medium-term trend, though as with reduced shale drilling, the situation seem unlikely to change much in the next 3-6 months.

That leaves gas inventory as the last major fundamental factor to assess. As of the most recent figures, gas storage was running about 5% below the same week last year, but ahead of the previous three years. A severe cold snap might test these inventories, but they don't loom as a big upside price risk today.

On balance, then, it appears I've been offered a fixed price that is not only in line with the current futures market, but at which I would also be giving up relatively little chance of paying significantly lower prices later--barring a double-dip recession--while gaining protection from weather or supply-related surprises. If the next year looked exactly like the last one did, I'd end up saving a bit less than $100. If you've followed my logic this far, you might think this was a lot of effort in order to convince myself that what looked like a good deal really was, but then I guess that's the lot of a former commodity trader who routinely had to make decisions like this, but for much larger stakes. And perhaps I've given you some food for thought, in case you're facing a similar decision.

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FutureGen Switches Tracks

The standard knock on carbon capture and sequestration (CCS) is that it hasn't been tested and proven on an industrial scale. That's really only true in the narrow sense in which you start with coal, produce electricity, and then collect and bury the CO2 that comes out the stack--which I imagine is what CCS evokes for most people who have even heard of the technology. Some years back, the US government set out to close that gap by building a large-scale test facility to demonstrate the coal-to-CCS cycle, with help from a consortium of industry partners. The program was called FutureGen. It died in 2008 after reported cost overruns but was revived in a different format last year. Now the reoriented effort has spawned a new project at a different location--though still in Illinois--to replace the ill-fated Mattoon project. Its basic concept differs significantly from the original FutureGen, and in ways that might improve the odds that coal could continue to contribute a substantial share of the US energy mix for many decades.

The CO2 produced by power plants is much harder to capture and dispose of than the traditional pollutants we associate with them, not least because it is the primary chemical result of the combustion of hydrocarbons, along with water vapor, rather than a byproduct resulting from a fuel impurity or imperfect combustion. That requires dealing with emissions that exceed the mass of fuel being consumed, rather than an order of magnitude or two smaller. And when fossil fuels are burned in air, the CO2 produced must be separated from all that nitrogen, which is the largest constituent of flue gas, before it can be sequestered. All this is expensive, in both energy and financial terms. The original FutureGen was designed to finesse this problem by converting coal into a hydrogen-rich gas that could be burned efficiently in a combined-cycle gas turbine (IGCC), producing emissions consisting mainly of water vapor, plus a sequestration-ready CO2 stream from the hydrogen-production process. Unfortunately, the hardware necessary to do that isn't cheap, either.

FutureGen 2.0, as announced, would take a different tack. It aims to convert an existing power plant owned by Ameren Corporation into an "oxy-coal" plant, in which pure oxygen replaces air in the boiler for combustion, resulting in flue gas consisting mainly of CO2. This approach has pluses and minuses, compared to IGCC. It requires a bigger air separation plant to support full combustion, but it eliminates all the hardware associated with hydrogen. That should entail somewhat lower capital costs, but not necessarily lower operating costs, particularly when you consider that the efficiency of IGCC exceeds that of most existing US coal power plants, though not necessarily supercritical or ultra-supercritical pulverized coal plants. (I couldn't tell how much the basic power block of Unit 4 of Ameren's Meredosia, IL plant, which formerly burned fuel oil, will be modified.) As in FutureGen 1.0, the resulting compressed CO2 would then be pipelined to a disposal site elsewhere in the state.

Although it would take some doing to convince me that oxy-coal with CCS is a better technology than IGCC with CCS, the revised approach to FutureGen looks like a good call on the part of the government. That's because the context in which FutureGen is being pursued has altered significantly since it was first devised. Instead of a scenario of continuing to build many new coal-fired power plants every year to meet steadily-growing electricity demand, the future--at least in the US--looks quite different. An article in yesterday's Washington Post pointed out that a number of new coal plants are still under development, but the rate of new construction has slowed dramatically, due to regulatory pressures, weaker electricity demand, competition from cheaper natural gas, and the growth of renewables. If we want to have an impact on the emissions from the US coal-fired power plant fleet--which accounts for 31% of total US emissions and 91% of the emissions from the electricity sector--then our best strategy probably doesn't involve building hundreds of gleaming new IGCC plants, but rather retrofitting hundreds of existing units built with older technology, for which conversion to IGCC would likely be cost-prohibitive. If FutureGen 2.0 succeeds--technically, if not economically--it would validate that retro-fitting potential.

The world hasn't stood still while the Department of Energy wrestled with all the political and technical challenges that FutureGen faced. The original siting competition between Texas and Illinois looked like a textbook case of logrolling, and FutureGen 1.0 exhibited the hallmarks of a classic government boondoggle. Meanwhile, commercial projects such as Duke Energy's Edwardsport IGCC (without CCS, but in effect CCS-ready) and the Good Spring IGCC project of Future Fuels LLC have emerged and appear to be making progress. The latter is based on technology from the Thermal Power Research Institute of China, which is a good bet to beat all of these projects to the punch with its GreenGen power plant in Tianjin. If FutureGen 2.0 is going to matter, it must be built smartly, quickly and cost-effectively. Yet technical success still won't guarantee that this technology will be taken up and deployed widely. In a market economy, rather than a centrally-planned one, it's hard to see any of this going beyond a demonstration plant or two without a substantial price on CO2 emissions to offset the inherently higher costs of generating power this way.

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