Threats and Opportunities of Distributed Power Generation

• Rooftop solar panels aren't the only distributed generation technology that could challenge existing utility business models as it grows.
• Some power companies see DG as an opportunity and are entering this segment in ways that could prove challenging to their start-up competitors.

Two recent news stories highlighted different ways that utilities and large generating companies are beginning to respond to the emergence of distributed generation (DG) as more than back-up power. Arizona Public Service (APS) is launching its version of potentially the most challenging type of DG for utilities, rooftop solar. Meanwhile, Exelon Corp. announced an investment partnership with a provider of gas-powered fuel cells. The success of such ventures and the evolution of DG will have implications for electrical grid stability and our future energy mix, including the role of flexible, large-scale gas-fired generation.

APS is seeking regulatory approval for a program that might be characterized as free rooftop solar. In effect, they would lease approved homeowners' rooftops for $30 per month, in order to host a total of 20 MW of solar panels that would be owned and controlled by APS. The idea has generated some controversy, partly due to the utility's rocky relationship with the solar industry over issues like "net metering". 

The plan would enable homeowners who might not otherwise qualify for solar leasing from third parties to have solar installed on their homes, although they would apparently still receive their electricity through the meter from the grid, rather than mainly from the rooftop installation. That's a very different model from most DG approaches, though under current market conditions the net benefit to consumers reportedly would match or exceed that from solar leasing.

Exelon's announcement seems aimed at a different segment of the market, and based on a very different technology. The company would finance the installation of 21 MW of Bloom Energy's fuel cell generators at businesses in several states, including California. Bloom made quite a splash when it introduced its "energy servers", including a popular segment on "60 Minutes" in 2010.

Bloom's devices, which come in models producing either 100 kW or 200 kW, are built around solid oxide fuel cells.  At that scale they are too large for individual homes but suitable for many businesses. And because they are modular, they can be combined to meet the energy needs of larger offices or commercial facilities such as data centers. Unlike the fuel cells being deployed in limited numbers of automobiles, they do not require a source of hydrogen gas. Instead they run directly on natural gas from which hydrogen is extracted ("auto-reformed") inside the box.

In that respect, despite their novel technology, Bloom's servers are much closer than rooftop solar to traditional distributed energy, in which a customer owns or leases a small generator to which it supplies fuel. The advantages of Bloom's model are that its servers are designed for highly efficient 24x7 operation, without the expensive energy storage necessary to turn solar into 24x7 power, and with much lower greenhouse gas emissions and local pollution than a diesel generator.

In order to qualify as true zero-emission energy, these installations would need to be connected to a source of biogas, e.g., landfill gas, which effectively creates a closed emissions loop or recycles emissions that would have occurred elsewhere.  Even running on ordinary natural gas, the stated emissions of Bloom's energy servers are roughly a third less than the average emissions for US grid electricity, or 20% lower than the average for other natural gas generation. However, their emissions are over 10% higher than the 2012 average for California's grid.

I find it interesting that Exelon, the largest nuclear power operator in the US and owner of a full array of utility-scale gas, coal, hydro, wind and solar power, would make a high-profile investment in a technology that could ultimately slash the demand for its large central power plants. The company has invested in utility-scale solar and wind power, and as the press release indicated, is already involved in "onsite solar, emergency generation and cogeneration" via its Constellation subsidiary. In fact, it has apparently already achieved its goal of eliminating the equivalent of its 2001 carbon footprint.  However, the press release hints that something else might have attracted them to this deal.

Consider all the changes in store for the power grid. Baseload coal power is declining due to the combination of economic forces and strong emissions regulations such as the EPA's Clean Power Plan. Even some nuclear power plants, which have been the workhorses of the fleet for the last several decades, are facing premature retirement for non-operational reasons. At the same time, grid operators must integrate steadily growing proportions of intermittent renewable energy (wind and solar), along with increasingly sophisticated tools like demand response and energy storage. If any of this goes wrong, electric reliability will likely suffer.

From that perspective, Exelon's small--for them--step into DG also looks like a bet on the future value of reliability--"non-intermittent...reliable, resilient and distributed power." That's a bet even an old oil trader can understand: Uncertainty creates volatility, and volatility creates opportunities. I will be very interested to see how this turns out. 

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Can Solar Fill the Hydropower Gap During California’s Drought?

• Although the scale of California's conventional hydropower remains much larger than that of solar power, solar's rapid growth provides a meaningful contribution to the grid.
• Solar power can work nearly anywhere, but installing it where it's actually sunny much of the time pays big dividends.

After reading a San Jose Mercury article with the unwieldy title, “Drought threatens California’s hydroelectricity supply, but solar makes up the gap” I was intrigued enough to do a little fact-checking on state-level  electricity statistics. The article quoted the head of the California Energy Commission, who implied that solar power additions were sufficient to make up for any shortfall in hydro, historically one of the state’s biggest energy sources. My initial skepticism about that claim turned out to be largely unfounded.

Solar has been growing rapidly, especially in California, but even with nearly 3,000 MW of photovoltaic (PV) and solar thermal generation in place, it’s still well short of the scale of California’s 10,000 MW of hydropower dams, especially when you consider that the latter aren’t constrained to operate only in daylight hours. However, I also know better than to respond to a claim like this without checking the data on how much energy these installations actually deliver.

My first look at the Energy Information Administration’s annual generation data seemed to confirm my suspicions. In 2012 California’s hydropower facilities produced 26.8 million megawatt-hours (MWh), while grid-connected solar generated just 1.4 million MWh. However, when I looked at more recent monthly data, the mismatch was much smaller, due to solar’s strong growth in the Golden State. For example, in September 2013 California solar power generated 435 MWh, or nearly 24% of hydro’s 1.8 million MWh.

The potential drought benefits of solar stand out even more sharply when we compare the growth in solar generation to the change in output from hydro. Last year solar electricity in the state increased by 2.4 million MWh, compared to 2012, while hydropower fell by 2.3 million MWh. That added solar power won’t provide grid operators the same flexibility as the lost hydropower, because of its cyclical nature, but it is clearly now growing at a rate and scale that makes it a serious contributor.

I’d be remiss if I didn’t point out that solar in California is still nowhere near the scale of the state’s biggest electricity source, natural gas generation, which in 2013 produced over 100 million MWh, or 57% of the state’s non-imported electricity supply. Gas is also filling much of the roughly 18 million MWh shortfall left by the early retirement of Southern California Edison’s San Onofre Nuclear Generating Station last summer, and if the state’s drought worsens, gas will be the main backup for further declines in hydropower.

Yet solar’s growing contribution to the state’s energy mix provides a clear demonstration that while generous state and federal policies can make installing PV economically attractive nearly anywhere, it’s abundant sunshine like California’s that makes it a useful energy source, especially when drought conditions reduce the output of other, water-dependent energy supplies.

A different version of this posting was previously published on Energy Trends Insider.

Will Fewer Young Drivers Today Mean Lower Fuel Demand Tomorrow?

• Driver's licenses for those under 40 years of age are down in several large, developed countries, including the US. This is only partially explained by a weak economy.
• If this shift in attitudes towards driving persists, future demand for both cars and fuel could be permanently reduced.

Current forecasts from the Energy Information Administration indicate that US gasoline demand peaked in 2007 and is expected to decline steadily for at least the next two decades.  One of the most intriguing factors aligned with this shift, which would have been almost unthinkable only a few years ago, involves a surprising reduction in the number of licensed drivers under 40 years of age.  A new study from the Transportation Research Institute (TRI) at the University of Michigan helps to explain a trend that is apparently not unique to the US.

Prior to the Great Recession, US gasoline demand had grown by 1-2% per year, with few interruptions. Since the recession, it has been shrinking for reasons that don't appear to be temporary. New cars are becoming more fuel-efficient, and Americans are consistently driving less than before the recession,  as indicated in the latest statistics on vehicle miles traveled.  To some extent this is an understandable response to gasoline prices that have remained significantly higher in real dollars than they were from 1982-2006. However, there may be other, deeper shifts underway.  If a segment of younger Americans has not only delayed getting a driver's license, but may never get one, then the decline in motor fuel demand is likelier to be permanent.

Once I started reading the survey results in the new study by the TRI's Brandon Schoettle and Dr. Michael Sivak, I knew I also needed the context of their 2011 paper on "Recent Changes in the Age Composition of Drivers in 15 Countries." That study showed that from 1983 to 2008 the number of licensed drivers in the US as a percentage of each age group up to 40 had dropped significantly, while the opposite was true for those over 50. (See chart below.) The authors found similar shifts in 7 other developed countries, including Canada, the UK, Germany and Japan, with a 2012 update indicating a further decline in US pre-40 licensing through 2010. Interestingly, Spain, Poland, Israel and several other countries exhibited increases in licensing among both younger and older drivers.

In their current paper, the authors used an online, non-random survey of 618 under-40 non-drivers to explore the reasons for their status. The top reasons their respondents gave for not having a driver's license seemed mainly practical, rather than philosophical. Many of those under 30 reported being "too busy or not enough time to get a driver's license",  or "able to get transportation from others." The "cost of owning and maintaining a vehicle" was the second-most common reason among all respondents, and as the authors noted, that is consistent with the relatively high unemployment or full-time student status of this group--46% and 21%, respectively.

Other common responses suggest that at least some of those without licenses are in that position by intention, rather than necessity. Nearly 40%--likely including some overlap--reported a preference for biking, walking or public transportation as a primary or secondary reason, while 9% cited environmental concerns and 8% mentioned online alternatives to driving.

Having grown up in a time and place where obtaining a driver's license as close as possible to one's 16th birthday was both a rite of passage and a practical necessity, this is that rare energy issue that's hard for me even to relate to. Yet when I look at the above chart, with its mirror-image shifts, I'm struck by the similarity between recent under-40 driver's license data and those for the cohorts born between the World Wars.  Are the current license rates of Millennials and late-Gen-X'ers the anomaly, or will those of my Baby Boomer and early Generation X peers turn out to be uniquely high? Only the passage of time can clarify such questions.

While the authors stopped short of assigning cause and effect, it seems reasonable to conclude that at least part of what we're seeing here is the result of the stubbornly persistent youth unemployment of a tepid recovery and the "New Normal" economy. A few years of much stronger economic growth might shrink the gap shown in Figure 1, by addressing the reasons that many of those surveyed gave for not having a driver's license, particularly since only 6% of them reported they never learned to drive.  Of course that doesn't explain why more than a third of those in the 30-39 age group, who ought to be the most financially settled, indicated they planned never to get a license.

The survey's results and their implications ought to be of great interest to producers of conventional and alternative fuels, established auto manufacturers, car rental firms, as well as transportation planners and policy makers.  Even electric-vehicle startups like Tesla might wonder whether for a significant segment of their natural future market, the choice won't be between an EV and a conventional car, but between a car and not driving at all. This is a trend that bears watching.

 

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Deploying Extra Power for Japan

Just over two weeks after the earthquake near Sendai in northeastern Japan, which I'm increasingly seeing referred to as the "Great Tohoku Earthquake", the impact of the resulting disruption to various supply chains is being felt around the world. From car factories in Europe that rely on Japanese electronic components to producers of flat-panel displays and solar cells, several industries are feeling the pinch. This appears to be due more to the reduction in Japan's electricity-generation capacity than from actual damage to factories in the zone most affected by the disaster. With more power plants than just the troubled Fukushima Daiichi nuclear complex affected, the scale and potential duration of electricity shortages could result in a significant increase in the demand for smaller-scale generation, both conventional and renewable.

As reported in today's Wall St. Journal, the electricity shortfall resulting from the quake and tsunami is severe and affects both consumers and businesses. The Japanese government is exploring a number of emergency measures to mitigate the problem, including increasing electricity prices, instituting Daylight Savings Time, and calling on customers to conserve power. At the same time, the government appears to understand that Japan's scope for large-scale energy-efficiency improvements is limited. With an energy intensity in BTUs per dollar of GDP already 37% lower than that of the US, only the UK among large developed countries is more efficient. Efficiency and conservation will be helpful, but they can't cover the massive shortfall Japan faces now.

One of the most detailed analyses of the impact of the quake and tsunami on Japan's electricity sector that I've seen so far suggests that as much as 15,000 MW of generating capacity in the Tokyo/Tohoku region is offline and likely to remain so for durations ranging from a few months to several years--or permanently, in the case of most of the reactors at Fukushima Daiichi. This is something like 20% of the pre-quake generating capacity of the two main utilities serving the region, not counting the pumped-hydro storage capacity used for meeting peak demand. As a result, that part of Japan is experiencing an electricity deficit that will likely grow as the summer peak demand months approach, and that could persist even after the least-damaged facilities return to service. Nor can surplus power from southern Japan provide much assistance, because the northern and southern systems are relatively isolated from each other, with limited interconnections, and run on different frequencies--60 cycles for the south and 50 cycles for the north. Back-up and distributed generation appears to be the only real alternative to a protracted economic slowdown caused by insufficient electricity for Japan's businesses and industries.

We've seen this pattern before, if from different and less-catastrophic causes. In the early 1990s the Philippine grid was chronically unreliable, and many businesses bought or leased diesel generators to fill the gap, including barge-mounted units that could be brought in quickly and moved around coastlines and rivers as demand shifted. More recently, diesel demand in China increased substantially in the lead-up to the 2008 Summer Olympics, as the central government idled large, dirty power plants in order to reduce air pollution, and a number of factories chose to generate their own power, rather than shutting down.

For Japanese factories and other businesses facing the same dilemma, cost is unlikely to be the major factor in deciding whether or not to become more energy self-sufficient. Factory managers can often justify paying a lot more for power if their only other option is to slow production or shut down. They have several choices available, including some renewable power options, and I expect to see a surge in solar power installations. However, that's probably a better medium-term rather than short-term option, not just because the entire world didn't install enough solar panels last year to make up for the lost output of the Japanese nuclear plants, but because while solar can help with supply, it can't provide the reliability that is crucial right now. That makes diesel generation the leading contender to backstop Japan's idled power plants in the short term.

I can't speak to the availability of diesel generators, although I can easily envision suppliers and leasing agents scrambling to meet frantic Japanese orders. However, if enough generators are available to cover even 3,000 MW of the shortfall, running just half the time, they would require around 65,000 barrels per day of incremental diesel fuel, or roughly the entire diesel output of a medium-sized refinery. Whether that represented an increase in overall Japanese diesel consumption requiring additional imports would depend on the extent of the other economic consequences of the Tohoku disaster, and on when Japan's refineries return to normal operations.

So the use of diesel generators to make up for damaged or otherwise unavailable generating capacity in Japan could provide another modest boost to global oil demand, which already appears to have exceeded the record level set prior to the recession and financial crisis. And since much of that increased demand is for diesel, rather than gasoline, the impact of Japanese generation needs could affect diesel prices disproportionally. As a result, consumers around the world could see diesel prices rise, as the ripples from the events in Japan spread.

Displacing More Oil from Power Generation

Increasing the US contribution of wind and solar power, geothermal energy, and even nuclear power would have virtually no effect on our oil imports or energy security, because we use so little oil for power. However, a pair of articles reminded me that this logic doesn't necessarily apply elsewhere. On Monday the Financial Times described the rapid growth of electricity demand in the Middle East, much of it fueled by oil that might otherwise be exported. Saudi Arabia apparently burns up to a million barrels per day of oil for power generation in the summer. And last week Fast Company highlighted the potential of large fuel cells to replace the diesel engines that generate power aboard tankers and other ships. As oil prices again approach $100 per barrel, with the possibility of even higher prices ahead when the entire global economy has returned to normal growth, these situations represent golden opportunities to save large quantities of oil for other uses for which its nearest substitutes still cannot replace it at scale.

Based on Department of Energy data the US generated just 0.9% of our electricity from petroleum and its products in the last year, with more than a third of that fueled by petroleum coke, a low-value solid byproduct of oil refining. The 43.5 million barrels of petroleum liquids used in power generation in 2009 represented only 0.6% of the 6.9 billion barrels the US consumed that year. When you break that sliver down by location, much of it is used for either backup generation or on islands or other remote locations. In other words, the remaining potential to displace oil from power generation in the US is very small and not necessarily well-suited to the intermittent renewable energy technologies now in favor. (That should change as electric vehicles enter the fleet by the millions, but that prospect remains some years off, at least.)

That situation isn't representative of the world as a whole, however, with oil accounting for almost 5% of global electricity generation in 2007. It was even higher on a regional basis, at 7% outside the countries of the OECD and 35% in the Middle East. Globally this amounted to 5 million bbl/day, or nearly 6% of total oil demand. That might not sound like much, until you consider that a drop in demand of around 3 million bbl/day from the first quarter of 2008 to the first quarter of 2009 contributed to a decline in oil prices--ignoring the mid-2008 spike to $145/bbl--of roughly $50/bbl. The price of oil is truly determined by the last few million bbl/day of supply and/or demand. You don't need to be worried about Peak Oil to see the oil used globally for power generation as potentially low-hanging fruit for redeployment, and as a significant emissions-reduction opportunity.

The best candidates to displace that oil vary by country and region. For countries with a lot of natural gas, like the big producers of the Middle East, a switch to that fuel seems like an obvious choice. However, much of the world's natural gas outside North America, including most LNG on long-term contracts, is priced based on oil, so the savings probably wouldn't be as large as they would be here. Even for oil exporters like Saudi Arabia, it might still make more sense to burn the residual fuel from the country's many large refineries, instead of importing LNG (or developing more of its own gas) and investing in the refining hardware to turn that residuum into gasoline, diesel and jet fuel. That might explain why the Kingdom is pursuing nuclear power to cover much of its future generating capacity growth. Renewables have also been capturing a foothold in the region, particularly in projects like Masdar City.

Finally, the large-scale marine fuel cell opportunity described in Fast Company would target a segment where oil has a near monopoly, outside of military fleets: shipboard power. And while these molten carbonate or solid-oxide high-temperature fuel cells would still consume fossil fuels to auto-generate the hydrogen they use, their high efficiencies would reduce overall oil consumption in shipping. If it proves possible eventually to use even larger fuel cells as the basis for electrifying vessel propulsion, as the article speculated, then oil savings would be much more substantial. Global consumption of bunker fuel by ships amounts to roughly 3.7 million bbl/day, or around 4% of total oil demand. And the environmental benefits of such a switch would go beyond greenhouse gases to include significant local air pollution benefits, particularly in ports.

None of this represents new thinking, but rather an extension of some of the strategies by which the developed world of the time adapted to the high oil prices of the twin oil crises in the 1970s. Still, it's easy to forget that that the quantity of oil tied up in the sectors mentioned above exceeds the output of the entire North Sea at its peak. If oil prices hadn't buckled under the weight of the financial crisis and recession a couple of years ago and instead remained on their previous trajectory, I imagine we'd already be well down the path of freeing up more of this oil. Recent price trends suggest that the primary motivation for doing so could be about to return.

Shale Gas and Climate Change

In Wednesday's posting on the likely consequences of the latest version of greenhouse gas (GHG) cap & trade legislation, I hinted at an important option for electricity suppliers to reduce their emissions promptly. Today I'd like to elaborate on it. Although the power sector accounts for the largest share of US GHGs, its existing generating fleet already has the potential to reduce those emissions substantially by relying less on coal-burning plants and more on those that burn natural gas. That could be done with little or no new investment, at least on the part of generating companies. This isn't exactly a new idea, but what makes it feasible now--when it wouldn't have been not so long ago--is the development of enormous new US natural gas resources found in shale deposits such as the Barnett, Haynesville and Marcellus shales. Twice in just the last week I have seen shale gas referred to as a "game changer", without the least hint of exaggeration.

Capitalizing on shale gas to take a big bite out of US GHG emissions would depend on two key facts: First, gas-fired power plants emit on average 37% less CO2 than coal-fired plants. At the same time, although the US generated more than twice as much electricity from coal as from gas last year, we actually have more gas-fired generating capacity than coal-fired. The former is merely utilized less--an average of 25% of the time, compared to 73% for coal--for reasons that made perfect sense in a world in which CO2 emissions didn't matter. If we doubled our utilization of existing gas-fired power plants and burned correspondingly less coal, the country would emit roughly 330 million fewer tons of CO2 per year, representing about 13% of the emissions from the power sector, or a reduction of a bit more than 5% of all US net emissions. And that's probably a conservative estimate, since the best combined-cycle gas turbine power plants emit less than half the CO2 per kWh of the oldest, least efficient coal-fired plants.

There are two principal reasons we aren't doing this already. The simplest is that coal has generally been much cheaper than gas on a fuel cost per kWh basis. However, the recent drop in gas prices has already put significant pressure on coal prices. At $4 per million BTUs, even at an unspectacular turbine heat rate of 8,500 BTU/kWh, the marginal fuel cost of gas-fired power is only 3.4 cents/kWh. But $4 gas may not be sustainable, since shale deposits are not exactly low-cost sources. The current long-dated gas futures price of roughly $7/MMBTU reflects that. In order for gas to displace large quantities of coal, it would probably take both stable gas prices higher than today's plus the kind of CO2 pricing envisioned under cap & trade--provided the utility sector isn't entirely insulated from this by excessive free emissions permit allocations.

Another reason for the current fuel mix is that most coal-fired power plants were built to run in baseload mode at high utilization rates, while many gas turbines were built to run intermittently to cover mid-peak and peak power demand. They probably couldn't all run at an 80-90% utilization rate, though we wouldn't need them to. They're also not evenly distributed around the country. California has lots of gas turbines, because that's pretty much all you could build there since the 1970s. That's not true everywhere. However, probably the biggest limitation has been concerns about the long-term availability of gas. Power generation already consumes 29% of the US gas supply, which in 2008 was about 87% domestic and 13% net imports, mostly from Canada. Until recently, any incremental demand would have been expected to be met mainly from imported LNG, at a higher price than domestic gas, or by destruction of existing demand in other sectors, such as chemicals. Abundant shale gas has altered that outlook, while putting downward pressure on LNG prices, as well.

In some respects, this is all somewhat "back to the future"; a decade ago it was widely assumed that natural gas would play a pivotal role in reducing our emissions. That notion went partly out of fashion, as gas prices climbed and environmentalists focused more on the lower emissions from wind and solar power, which despite their rapid growth still generated only 1/16th as much power as gas last year. The potential of shale and other "unconventional" resources makes gas once again a viable medium-term strategy for mitigating climate change, with a few caveats. I recall seeing similarly exuberant forecasts of gas supplies in the late 1990s, just before conventional onshore production nosedived and prices spiked. Shale gas looks more sustainable, but it depends on lots of well-capitalized companies drilling like crazy and earning enough from that to keep on drilling. If the economics don't hold up, most of that gas will stay underground. It also depends on drilling techniques that have suddenly become controversial, as noted on API's new blog. Preserving this option for reducing GHG emissions will require Congress and regulators to stay focused on the big picture.

Natural Gas Limelight

A decade ago, natural gas looked like the certain winner of a shift to lower-emission energy sources, as concerns about greenhouse gas emissions grew. The path to that outcome has been much bumpier than expected, however. Rising natural gas prices and supply concerns coincided with another shift, this one among environmentalists who identified gas as a key element of a "carbon economy" they were driven to transform, rather than the least-emitting fossil fuel. These dynamics are shifting again, and the future again looks positive for the US gas industry, thanks in part to the increased visibility created by the Pickens Plan and a new industry PR campaign. Its improved supply outlook and relative pricing against oil are helping, as well.

Since 1998 demand for natural gas in the power sector has grown by 50%, and gas-fired turbines now account for 41% of US generating capacity and 21% of net generation. But by 2004 US gas production had dipped by about 5% from its recent high in 2001--a slump that was deepened in 2005 and 2006 by the lingering effects of Hurricane Katrina. As a result, natural gas prices are running at about four times their 1998 level of around $2 per million BTUs, and winter spikes to $10 or higher have become the norm. As recently as a couple of years ago, many analysts saw natural gas as the country's quiet energy crisis, with our import dependence beginning to mirror that of oil.

Today, that perspective has been dramatically altered by the success of the US gas industry in tapping unconventional sources, including coal-bed methane and the shale plays that are driving the success of companies such as Chesapeake Energy. BP is purchasing a 25% interest in Chesapeake's Fayettville Shale assets. Although it comes too late to save many of the gas-intensive industries that moved offshore in search of lower input costs, and while I'm skeptical of claims that the US might become a net natural gas exporter, the resurgence in US gas production could not come at a better time, given our intertwined concerns about energy security and climate change.

The greenhouse gas advantage of natural gas for power generation looks significant, compared to coal. In 2000 the average US gas-fired power plant emitted nearly 40% less CO2 per kilowatt-hour than the average coal-fired plant. But with wind and solar power booming, this glass was increasingly viewed by environmentalists as 60% full, rather than 40% empty. That did not stop gas from gaining market share at the expense of coal, but its green image hasn't held up as well as its supporters expected. Some of that luster is being restored by the attention generated by Mr. Pickens, who casts gas as an environmentally-friendly bulwark of US energy security. Recent remarks by Speaker Pelosi and Senator Obama suggest that this approach is working.

It also helps that the Pickens Plan focuses on increasing natural gas consumption in transportation, where its emissions benefits and cost savings align nicely. A natural gas vehicle emits about 25% less CO2 per mile, measured from "well-to-wheels", than the comparable gasoline car, and it appears to be slightly greener than a flexible-fuel vehicle running on E85. Factor in the substantial price discount for compressed natural gas, compared to gasoline, and this ought to be a winning proposition for consumers, particularly if legislation to provide incentives for buying or converting a car to run on compressed natural gas passes.

Let's put all of this in perspective. Higher US natural gas production should provide economic and environmental benefits for the entire country, even if it doesn't result in a gas glut, but it is still no panacea. At 23 trillion cubic feet (TCF) per year and growing, US gas consumption still exceeds the highest previous level of US production, 22.6 TCF in 1973. And with US electricity demand having grown by 78 million MWh last year--a multiple of the additions from wind and solar power--and with new coal-fired plants being canceled left and right, natural gas consumption in the power sector seems likely to increase, not decrease, at least for the next several years. That means that in order for gas use for transportation to grow large enough to have an impact on US greenhouse gas emissions, it must compete for its share of growing production, or rely on imports, undermining its perceived energy security benefit. Moreover, politicians tempted to nudge the market in the direction of more natural gas cars should keep in mind that much of the nation's gas is consumed in ways that would have a large and fairly direct impact on consumers' wallets, should increased competition for it drive up its price.