Are Renewables Set to Displace Natural Gas?

• Bloomberg's renewable energy affiliate forecasts that wind and solar power will make major inroads into the market share of natural gas within a decade. 
• This might be a useful scenario to consider, but it is still likelier that coal, not gas, faces the biggest risk from the growth of renewables. 

A recent story on Bloomberg News, "What If Big Oil's Bet on Gas Is Wrong?", challenges the conventional wisdom that demand for natural gas will grow as it displaces coal and facilitates the growth of renewable energy sources like wind and solar power. Instead, the forecast highlighted in the article envisions gas's global share of electricity dropping from 23% to 16% by 2040 as renewables shoot past it. So much for gas as the "bridge to the future" if that proves accurate.

Several points in the story leave room for doubt. For starters, this projection from Bloomberg New Energy Finance (BNEF), the renewables-focused analytical arm of Bloomberg, would leave coal with a larger share of power generation than gas in 2040, when it has renewables reaching 50%. That might make sense in the European context on which their forecast seems to be based, but it flies against the US experience of coal losing 18 points of electricity market share since 2007 (from 48.5% to 30.4%), with two-thirds of that drop picked up by gas and one-third by expanding renewables. (See chart below.)

It's also worth noting that the US Energy Information Administration projected in February that natural gas would continue to gain market share, even in the absence of the EPA's Clean Power Plan, which is being withdrawn.

Natural gas prices have had a lot to do with the diverging outcomes experienced in Europe and the US, so far. As the shale boom ramped up, average US natural gas spot prices fell from nearly $9 per million BTUs (MMBTU) in 2008 to $3 or less since 2014.  Meanwhile, Europe remains tied to long-term pipeline supplies from Russia and LNG imports from North Africa and elsewhere. Wholesale gas price indexes in Europe reached $7-8 per MMBTU earlier this year.

But it's not clear that the factors that have kept gas expensive in Europe and protected coal, even as nuclear power was being phased out in Germany, will persist. The US now exports more liquefied natural gas (LNG) than it imports. US LNG exports to Europe may not push out much Russian gas, but along with expanding global LNG capacity they are forcing Gazprom, Russia's main gas producer and exporter, to become more competitive.

Then there's the issue of flexibility versus intermittency. Wind and solar power power are not flexible; without batteries or other storage they are at the mercy of daily, seasonal or random variation of sunlight and breezes, and in need of back-up from truly flexible sources. Large-scale hydroelectric capacity, which makes up 75% of today's global renewable generation and is capable of supplying either 24x7 "baseload" electricity or ramping up and down as needed, has provided much of the back-up for wind and solar in Europe, but is unlikely to grow rapidly in the future.

That means the bulk of the growth in renewables that BNEF sees from now to 2040 must come from extrapolating intermittent wind and solar power from their relatively modest combined 4.5% of the global electricity mix in 2015 to a share larger than coal still holds in the US. The costs of wind and solar technologies have fallen rapidly and are expected to continue to drop, while the integration of these sources into regional power grids at scales up to 20-30% has gone better than many expected. However, without cheap electricity storage on an unprecedented scale, their further market penetration seems likely to encounter increasing headwinds as their share increases.

BNEF may be relying on the same aggressive forecast of falling battery prices that underpinned its recent projection that electric vehicles (EVs) will account for more than half of all new cars by 2040. As the Financial Times noted this week, battery improvements depend on chemistry, not semiconductor electronics. Assuming their costs can continue to fall like those for solar cells looks questionable. Nor is cost--partly a function of temporary government incentives--the only aspect of performance that will determine how well EVs compete with steadily improving conventional cars and hybrids.

I also compared the BNEF gas forecast to the International Energy Agency's most recent World Energy Outlook, incorporating the national commitments in the Paris climate agreement. The IEA projected that renewables would reach 37% of global power generation by 2040, or roughly half the increase BNEF anticipates. The IEA also saw global gas demand growing by 50%, passing coal by 2040. That's a very different outcome than the one BNEF expects.

Despite my misgivings about its assumptions and conclusions, the BNEF forecast is a useful scenario for investors and energy companies to consider. With oil prices stuck in low gear and future oil demand highly uncertain, thanks to environmental regulation and electric and autonomous vehicle technologies, many large resource companies have increased their focus on natural gas. Some, like Shell and Total, invested to produce more gas than oil, predicated on gas's expected role as the lowest-emitting fossil fuel in a decarbonizing world. If that bet turned out to be wrong, many billions of dollars of asset value would be at risk.

However, it's hard to view that as the likeliest scenario. Consider a simple reality check: As renewable electricity generation grows to mainstream scale, it must displace something. Is that likelier to be relatively inflexible coal generation, with its high emissions of both greenhouse gases and local pollutants, or flexible, lower-emitting natural gas power generation that offers integration synergies with renewables? The US experience so far says that baseload facilities--coal and nuclear--are challenged much more by gas and renewables, than gas-fired power is by renewables plus coal.

The bottom line is that the world gets 80% of the energy we use from oil, gas and coal. Today's renewable energy technology isn't up to replacing all of these at the same time, without a much heavier lift from batteries than the latter seem capable of absent a real breakthrough. If the energy transition now underway is indeed being driven by emissions and cleaner air, then it's coal, not gas, that faces the biggest obstacles.

Energy Storage and the Cost of Going Off-Grid

• New energy storage offerings from Tesla and other manufacturers are widely expected to enhance the attractiveness of rooftop solar power and other renewables.
• However, recent analysis from the Brattle Group shows that even with rapid cost reductions, grid-independence will remain beyond the reach of most consumers.

Last month's Annual Energy Conference of the US Energy Information Administration included speakers and panels on topics such as crude-by-rail, potential US oil exports, and the role of the Strategic Petroleum Reserve, all of which should be familiar to my readers here. However, the topic that really caught my interest this year was energy storage.

Storage has been in the news lately, particularly since the launch of Tesla's new home and commercial energy storage products. In fact, Tesla's Chief Technology Officer spoke on the first morning of the conference. Much of his talk (very large file) focused on Tesla's expectations for the cost of storage to decline sharply as electric vehicles (EVs) and non-vehicle battery applications grow. Whether battery costs can drop as quickly as those for solar photovoltaic (PV) cells or not, storage is likely to become a more important factor in energy markets in the years ahead.

One of the most interesting presentations I saw examined a provocative aspect of this question. Michael Kline of The Brattle Group, which consults extensively on electricity, took a detailed look at whether rooftop PV and home energy storage might become sufficiently attractive that a large number of consumers would employ the combination to enable them to disconnect from the power grid entirely.  That would be an extremely appealing idea for a lot of people. The author of a book I received from the publisher a few years ago referred to it as a movement.

Most people by now appear to understand that solar panels alone can't make a household independent of the grid. The daily and seasonal incidence of sunlight aligns imperfectly with the peaks and troughs of typical home electricity demand. This is why "net metering", under which PV owners sell excess power to their local utility--effectively using the grid as a free battery--has become contentious in some electricity markets.

In a true off-grid scenario, net metering would be unavailable. Onsite storage would thus be necessary to shift in time the kilowatt-hours of energy produced from a home PV array. However, a standalone PV + storage system must be sized to deliver enough instantaneous peak power to handle periodic high-load events like the startup of air conditioners and other devices. Another presenter on the same panel had a nifty chart demonstrating how wide those variations can be, with multiple spikes each day averaging above 12 kilowatts (kW)--several times the output of a typical rooftop PV array.

Brattle's off-grid model included PV and storage optimized to "meet load in every hour given a battery with 3 days of storage (at average load levels.)" Although that is still probably less than the peak load such a system would encounter, it is the equivalent of multiple Tesla "Powerwall" units and would only be practical with the kind of drastic cost reductions Mr. Kline assumed by 2025: PV at $1.50/W and storage at $100/kWh, installed. That equates to around a third of last year's average US residential PV installation and 1/7th the estimated installed cost of Tesla's offering on a retail basis.  

Mr. Kline framed this exercise as a "stress test", not just of the off-grid proposition but of the future of the electric power grid. If many millions of customers were to "cut the cord" for electricity as others have for wireline telephone service, even a "smart" power grid would become much less important and might shrink over time. That same logic should extend to the power generators supplying the grid. If most consumers went off-grid, the value of even the most flexible generation on the grid, which today is often provided by natural gas turbines, would fall, as would demand for the fuel on which they run.

In Brattle's assessment, despite the assumption of very cheap PV and storage, that prospect seems remote. For the three markets analyzed (California, Texas and Westchester County, NY) the levelized cost of energy (LCOE) for the off-grid configuration modeled was significantly more expensive than the EIA's projected cost of electricity in those markets in 2025. In fact, for consumers in California and Texas, as well as in all cases of the parallel commercial customer analysis Brattle performed, PV + storage would  be expected to cost a multiple of retail electricity prices.

As Mr. Kline explained, under more realistic assumptions the comparison was likely to be even worse for off-grid options. However, his conclusion that , "going off-grid...is unlikely to be the least expensive option for most consumers" does not mean that some consumers would not choose to do so, anyway. To them, a premium of 10-20 cents per kWh might seem like a small price to pay for personal energy independence. Yet at that price, it is hard to envision it would become a mass-market choice. 

Mr. Kline made a point of reminding his audience that Brattle's analysis did not mean that distributed energy  would  not be competitive in the future, or that it could not provide valuable services to customers and to the grid. Importantly, the figures he presented underlined the continued value of the power grid to customers, even in a future in which large quantities of PV and storage are deployed.  As he put it, "Distributed energy is a complement to the grid, not a substitute for it."

By extension, flexible generating assets like fast-reacting gas turbines should also continue to provide significant value, especially during those seasons when daily solar input is low, and in locations where average sun exposure is generally much weaker than in the US Southwest and other prime solar resource regions.  As appealing as the idea might be to some, storage seems unlikely to make either the grid or any class of generating technologies obsolete for the foreseeable future. As Bill Gates recently observed, that has implications for the cost of a wholesale shift to current renewables and away from fossil fuels.

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

What Will Fuel Today's Advanced Vehicles?

Last month I attended the annual "policy day" at the Washington Auto Show, which typically emphasizes green cars and related technology. This year it included several high-profile awards and announcements, along with a keynote address by US Secretary of Energy Ernest Moniz.  Yet while the environmental benefits of EVs and other advanced vehicles are a major factor in their proliferation, I didn't hear much about how the energy for these new car types would be produced.

The green car definition used by the DC car show encompasses hybrids, plug-in electric vehicles (EVs), fuel cell cars, and advanced internal-combustion cars including clean diesels. One trend that struck me after missing last year's show was that most of the green cars on display have become harder to distinguish visually from conventional models. For Volkswagen's eGolf EV, which shared North American Car of the Year honors in Detroit with its gas and diesel siblings, and Ford's Fusion energi plug-in hybrid the differences are mainly under the hood, rather than in the sheet-metal.

Of course some new models looked every bit as exotic as you might expect. That included BMW's i8 plug-in hybrid, which beat Tesla's updated 2015 Model S as Green Car Journal's "Green Luxury Car of the Year", and Toyota's Mirai fuel-cell car. The Mirai is expected to go on sale this fall in California, still the nation's leading green car market due to its longstanding Zero-Emission Vehicle mandate focused on tailpipe emissions. 

BMW i8 plug-in hybrid

Toyota Mirai fuel-cell car

Many of these cars have electric drivetrains, increasingly seen as the long-term alternative to petroleum-fueled cars. Although Secretary Moniz pointed out that the US government isn't attempting to pick a vehicle technology winner, there seemed to be a definite emphasis on vehicle electrification and much less on biofuels than in past years.

Another announcement at last month's session addressed where such vehicles might connect to the grid. BMW and VW have partnered with Chargepoint, an EV infrastructure company, to install high-voltage fast-chargers in corridors along the US east and west coasts to facilitate longer-range travel by EV. In making the announcement BMW's representative indicated that EVs will need fast recharging in order to compete with low gasoline prices. With the relative cost advantage of electricity having become a lot less compelling than when gasoline was near $4 per gallon, EV manufacturers need to mitigate the convenience concerns raised by cars with typical ranges of 100 miles or less. 

Getting energy to these cars more conveniently still leaves open the basic question of the ultimate source of that energy.  Perhaps one reason this isn't discussed much is that unlike for gasoline or diesel-powered cars, there's no simple answer. The source of US grid electricity varies much more than for petroleum fuels: by location, by season, and by time of day. However, even in California, which on average now gets 30% of its electricity from renewable sources and has set its sights on 50% from renewables by 2030, the marginal kilowatt-hour (kWh) of demand is likely met by power plants burning natural gas, due to their flexibility. That's especially true if many of these cars will be recharged near peak-usage times, instead of overnight as the EV industry expects.

Based on data from the EPA's fuel economy website, most of the plug-in cars I saw at the Washington Auto Show use around 35 kWh per 100 miles of combined driving. That reflects notionally equivalent miles-per-gallon figures ranging from 76 for the BMW i8 to 116 mpg for the eGolf. On that basis an EV driven 12,000 miles a year would increase natural gas demand at nearby power plants by around 30 thousand cubic feet (MCF) per year. That equates to 40% of the annual natural gas consumption of a US household in 2009. 

To put that in perspective, if we attained the President's goal of one million EVs on the road this year--a figure that may not be achieved until the end of the decade--they would consume about 30 billion cubic feet (BCF) of gas annually, or a little over 0.1% of US natural gas production. With plug-in EVs making up just 0.7% of US new-car sales in 2014, they are unlikely to strain US energy supplies anytime soon. 

It's also worth assessing how much gasoline these EVs will displace. That requires careful consideration of the more conventional models with which each EV competes. While a Tesla Model S surely lures buyers away from luxury-sport models like the BMW 6-series, thus saving around 500 gallons per year, an e-Golf likely replaces either a diesel Golf or a Prius-type hybrid, saving 250-300 gallons per year.  A million EVs saving an average of 350 gallons each per year would reduce US gasoline demand by 22,000 barrels per day, or 0.25%.

At this point the glass for electric vehicles seems both half-full and half-empty. The number of attractive plug-in models expands every year, as does the public recharging infrastructure to serve them. However, they still depend on generous tax credits and must now compete with gasoline near $2 per gallon. More importantly, at current levels their US sales are too low to have much impact on emissions or oil use for many years.

 

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

Fuel Cell Cars and the Shale Revolution

• Although fuel cell cars have perpetually seemed to be the technology of tomorrow, carmakers’ persistence with them could still pay off, as a dividend from shale gas.

• Significant obstacles remain, including inadequate hydrogen infrastructure and competition from greatly improved vehicle batteries. However, the race is far from over.

As I was working off my reading backlog, I ran across an article in the Washington Post’s “Capitol Business” edition on “Are We Ready for Hydrogen Cars?” Published in conjunction with this year’s DC Auto Show, which I missed, it mentioned a new fuel cell model from Hyundai for the California market, while providing some background on a technology that looked much more like the next big thing a decade ago than it does to many, now.

Any evaluation of the prospects for fuel cell cars to become practical requires discussing the cost of fuel cell components, the infrastructure to deliver H2 to vehicles, and the suitability of various options for storing it safely onboard. However, I was surprised the article failed to mention a new factor that might do more than anything else to improve the odds for this technology: shale gas.

In the mid-1990s, when fuel cell vehicles (FCVs) first appeared on my radar, they seemed like an ideal alternative to the gasoline engines in most passenger cars, offering zero tailpipe emissions and very low lifecycle, or well-to-wheels emissions of all types. Onboard hydrogen (H2) storage, whether as a gas, liquid or chemically adsorbed in another material, enabled higher energy density than then-current batteries, giving an FCV significantly greater potential range than a comparable electric vehicle (EV). And like electric cars, they also provided a useful pathway for bringing energy from a wide variety of sources into the transportation market, which was and still is dominated by petroleum products. Cost and technology readiness were big barriers, along with non-existent retail H2 infrastructure.

Energy remains the key to FCVs, because H2 is an energy carrier, not an energy source. Standing up a competitive fleet of FCV models thus requires plentiful and preferably low-cost energy sources from which sufficient H2 can be produced and distributed. As recently as just a few years ago, this looked like a very tough challenge.

Most H2 used industrially is generated by chemically reforming natural gas. Until recently, US gas production was in decline, resulting in high and volatile gas prices. Generating H2 from electricity looked even worse, because power prices were climbing and seemed likely to increase steadily in the future, as natural gas prices rose and higher-cost renewables were phased in. And with US electricity generation dominated by coal, H2 from electrolysis–cracking water into its components using electricity–looked like a recipe for merely shifting, rather than reducing vehicle emissions.

Like many other aspects of the North American energy scene, this picture has changed radically in the last several years, mainly due to the shale gas revolution. We now have abundant gas at reasonable prices, and this is holding down electricity costs. (Renewables are also reducing wholesale electricity prices, though not necessarily the full cost of electricity, because they still depend on subsidies and mandates that don’t show up in wholesale prices.)

These developments create the potential for cheaper H2 sources than fuel cell developers expected. Moreover, US natural gas prices have diverged from oil prices and are now at a significant discount to oil. Wellhead gas today trades for the equivalent of $25 per barrel, compared to oil at over $100. Gas-derived H2 could end up with advantages in both cost and end-use efficiency over gasoline.

Of course the availability of natural gas isn’t the only thing that has changed for fuel cells in the last decade, from a competitive perspective. Automakers such as GM, Toyota and Honda have introduced various new fuel cell models. The most recent one I had an opportunity to drive was a fuel-cell version of the Chevrolet Equinox compact SUV in late 2007. In the meantime, though, EV models are proliferating.

Unfortunately for fuel cell developers, H2 distribution has had a somewhat checkered history, as the Washington Post article notes. Providing fuel for FCVs is a much more involved and expensive undertaking than setting up a network of recharging points for EVs. How many H2 stations will suppliers build before FCVs appear in large numbers, and how many FCVs can carmakers sell before sufficient infrastructure is available to serve them? California still has just a handful of public H2 stations, after years of development.

Energy trade-offs dominate the competition between FCVs and EVs. The former have longer ranges between refueling than moderately-priced EVs–the Tesla Model S has excellent range–and can be refueled in much less time than even high-voltage EV recharging can achieve. However, FCVs are much more dependent on refueling infrastructure than EVs, which can recharge at home. And thanks to robust federal support for battery R&D and production, including from the 2009 stimulus, along with extremely generous federal and state EV tax credits, EVs have gained significant awareness and initial market penetration since the current administration took office and scaled back federal support for fuel cells.

EVs may have an edge over fuel cell cars, for now, but EV sales remain disappointing and they must compete with more convenient, mainstream hybrid cars, with and without plug-in capability. They must also compete with conventional gasoline and diesel cars that are becoming more efficient every year, reducing EVs’ advantages in operating costs and lifecycle environmental impacts. Given all that, there’s still ample time for another technology like FCVs–or natural gas vehicles (NGVs)–to scale up, if they can reduce costs quickly enough and overcome infrastructure hurdles. Those are big ifs.

Nor is it the case that EVs and FCVs are mutually exclusive in the automotive market. Fuel cell cars are fundamentally electric vehicles, too, and most will likely be offered as hybrids, with regenerative braking and traction batteries. So advances in EV architecture, battery capacity and cost, and safety also benefit FCVs. That makes it seem even likelier that our future vehicle mix will be quite diverse, with EVs and FCVs coexisting with NGVs, various hybrids, and much more efficient gasoline and diesel models than today’s.

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

...and Two Steps Back for Cleantech

• The Better Place bankruptcy ends an interesting effort to circumvent some big impediments to the wider adoption of electric vehicles.
• DESERTEC's original concept would have matched European solar investment with superior North African solar resources, but was no match for European politics.

Within the last week two of the previous decade's Big Ideas for accelerating the shift from fossil fuels to renewable energy--or at least to electricity generated from a variety of cleaner sources--have come up short.  On May 26th electric-vehicle-battery-swapping firm Better Place filed for bankruptcy liquidation in Israel, and just a few days later the DESERTEC Foundation reportedly "abandoned its strategy to export solar power generated from the Sahara to Europe".  Both of these concepts originally looked promising, and I take no satisfaction in their apparent failure.  However, these events must be telling us something.

Better Place was aimed squarely at two of the largest perceived barriers to wider acceptance of electric vehicles (EVs): the limited range of today's EV batteries and the relatively long times required to recharge them, compared to a typical three-minute fill-up at the gas pump.  Better Place's big idea involved the standardization of EV battery packs on a design that could be quickly removed from the vehicle and robotically replaced with a fully charged battery. This required large up-front investments in facilities and hardware, but the firm didn't fail for lack of capitalization. 

Despite having raised around $800 million since its founding in 2008, and convincing French carmaker Renault to produce vehicles designed to work with their technology, Better Place failed to standardize the emerging EV battery market.  Tesla used a different battery configuration from the start and has focused on its own fast-charging technology, while even Renault's global alliance partner Nissan didn't make compatibility with Better Place a standard feature of its Leaf EV in markets like the US or Australia. That led Better Place to invest in building more-conventional EV recharging networks to accommodate other EVs, diluting both its capital and its concept. 

I see two lessons here. First, EVs and related services are still a niche market, and in spite of its aspirations Better Place became a niche within this niche, largely dependent on the success of EV manufacturers at growing their potential market.  That's a poor place from which to launch a business that ultimately depends on achieving high volumes.  The other lesson is that when you can't make sense of a company's revenue and working-capital model, there's probably a good reason.  At this stage in their development, EV battery packs are apparently still too expensive to sit idle in large numbers, waiting for a swap, when the hardware to exchange them requires the same retail footprint as a car-repair bay--all this to support a service arguably only worth a few hundred dollars per year to an EV owner, compared to the normal cost of recharging.

DESERTEC's big idea was even simpler than Better Place's.  A well-sited solar array in North Africa would inherently generate at least twice as much electricity per year as the same array in Germany, the Netherlands, or Belgium.  All else being equal, it would make more sense to invest in solar where the sun shines brightly for more than 6 hours a day, on average, and to send it by wire to the cloudy, northern countries that want more green power.  Of course physics can't always trump politics, and I suspect that this has more to do with DESERTEC's withdrawal from its basic concept than the cited concerns about transmission capacity and grid congestion across Spain and France. 

Politics enter the story in two main ways.  Renewable energy in the EU is deeply entangled with industrial policy and green jobs. From that standpoint, it's even better if a PV panel in Germany produces half the output as one in Morocco, because you can sell twice as many, all installed by local firms and workers. Then there's the interaction between the EU's generous solar subsidies and the solar manufacturing incentives in Asia and elsewhere, resulting in enormous overcapacity, relative to demand, and a now-global wave of solar bankruptcies and defaults.  This has pushed PV module prices down to a level at which the other costs of solar energy, including installation and transmission, begin to outweigh the module costs. That erodes North Africa's solar advantage relative to its northern neighbors. Throw in the lingering effects of the financial crisis, and a once-big idea looks like an unworkable dead end, at least for now.

Neither the failure of Better Place, which might yet find a bargain-hunting savior, nor the retreat of DESERTEC looks like a mortal blow to the long energy transition now underway.  However, they do suggest that the timeline is a little less likely to be shortened by the kinds of big leaps they offered.  EVs will have to gain market share the hard way, with better, cheaper batteries and ample recharging infrastructure--plus continued taxpayer subsidies--while inefficient solar subsidies continue to divert investment away from some of the world's best renewable energy resources, keeping the technology's global contribution smaller for longer.    

Can Energy Storage Make Wind and Solar Power As Reliable As Coal?

Wind and solar power generated 3.5% and about 0.1%, respectively, of US electricity last year.  These figures represent large increases from much smaller levels in the last decade as the cost of these technologies declined significantly, particularly for solar photovoltaic (PV) modules. However, other barriers to wider deployment remain, including their intermittent output.  Energy storage is often portrayed as the killer app for overcoming the intermittency of renewables, and a number of interesting developments have occurred on this front, including a new "hybrid" wind turbine with integrated storage from GE. To what extent could more and cheaper storage enable wind and solar to function as the equivalent of high-utilization, baseload generation? 

Assessing that potential requires, among other things, recognizing that energy storage is neither new nor monolithic. Nor is the intermittency of renewable energy a single challenge.  For example, the output of a wind turbine and the wind farm in which it operates varies on time scales of minutes, hours and days, as well as months and years.  The output of a PV installation varies somewhat more predictably, but no less dramatically. 

Generating companies and project developers have an array of new storage options, involving various battery technologies, flywheels, and compressed air. Pumped storage, in which water is pumped uphill and generates power later when it flows back downhill, is an old, though hardly obsolete option and already operates on a large scale. According to the National Hydropower Association the US has 22,000 MW of installed pumped storage. This, too, is expanding and remains one of the cheapest forms of power storage in terms of cost per megawatt-hour (MWh) delivered.   Enough new projects have received preliminary permits to more than triple that figure, in 23 states.

All of these storage alternatives have limitations or drawbacks.  Batteries and flywheels, while very responsive, are still expensive.  Compressed air storage often relies on unique local geological features, and some versions essentially function as a supercharger for a gas-fired turbine, resulting in some emissions. Pumped storage works well at a variety of scales but is less responsive than batteries, has a larger physical footprint, and requires suitable terrain. 

What makes GE's "brilliant turbine" with battery storage look clever is that, with the help of predictive models, it requires a very small amount of battery storage--perhaps as little as that in an electric car--to smooth the output of the turbine for 15 minutes to an hour. That provides significant benefits, including financial ones, in terms of integrating it predictably into the power grid. However, it doesn't transform the turbine into a fully dispatchable generator capable of sending power to the grid whenever demanded.  That would require storing much more energy per turbine and delivering it at rates sufficient to replace the entire output of the installation for at least several hours, along the lines of concentrated solar power installations with thermal storage.

Even these techniques don't get us to the point at which a dedicated wind farm or solar installation could replace a baseload coal-fired power plant of similar capacity running 80% of the time.  For starters, energy storage doesn't alter the total amount of energy collected from the wind or sun.  In an area with good onshore wind resources, generating the same energy as 100 MW of coal capacity would take around 267 MW of wind turbines, because the wind doesn't blow at optimum speed all the time, and other times it doesn't blow at all. The wind farm would also need enough storage to absorb any output over 100 MW, and then make up any shortfalls below 100 MW for the longest duration that would be expected.  The figures for a solar installation would be similar. It just doesn't sound very practical, unless storage became dirt cheap.

Fortunately for renewable energy developers, that isn't what grid operators expect of wind or solar.  In most situations the local grid takes their output whenever it's available, though not necessarily at the price that a generator capable of committing its capacity in advance or responding on demand would receive.  So there's a financial incentive for renewables to add a bit of storage to "firm up" some capacity, while bulk storage appears to be more desirable as a separate asset available to the grid, just like a "peaking" gas turbine, to support multiple renewable sources. Of course in that case there's no guarantee that the power stored would come from renewables.  It's likelier to come from whatever is the cheapest off-peak generation in that market.

So while it's easy to see how improved energy storage can enhance the economics of renewable energy and enable it to be integrated into the grid to a greater extent than otherwise, it's less obvious that even cheap, large-scale energy storage is a panacea for intermittent renewables like wind and solar.  It might even have greater benefits for low-emission but more reliable forms of generation, such as nuclear and geothermal, by allowing them routinely to shift a set portion of their output into more valuable segments of the regional power market. 

Disclosure: My portfolio includes investment in GE, which makes products mentioned above.

Ex-Shell Chief Hofmeister Promotes US Fuel Diversity

Alternative fuels have lost some of their luster in the US, lately, for understandable reasons.  Oil production here is booming based on shale resources that keep expanding, while the market for ethanol, our most successful alternative fuel, has stalled at the long-anticipated "blend wall", resulting in ethanol plant closures and bankruptcy filings.  More advanced cellulosic biofuel is still only available in minute quantities, and last year's sales of electric vehicles will displace less than 24 million gallons per year of gasoline--around 0.02% of US gasoline demand.  With all this in mind, it seemed like an excellent time to speak with former Shell Oil Company President John Hofmeister, who recently joined the advisory board of the Fuel Freedom Foundation, a group dedicated to expanding fuel diversity. 

I don't conduct many interviews for Energy Outlook, but I wouldn't have missed the opportunity to discuss energy with Mr. Hofmeister.  Given the focus of Fuel Freedom Foundation, which arranged the call, I started by asking him what kind of changes he expects in the US fuel mix over the next 10 years.  Mr. Hofmeister replied that his outreach efforts at Fuel Freedom, together with Citizens for Affordable Energy, which he founded after retiring as head of Shell's US operations, are intended to "make sure something has changed 10 years out. Left to our own devices, not much will change."  With plans and "enablers of change" from government, he sees an opportunity to "transform the nation in 10 years." He went on to describe what that transformation might include, in the form of further decreases in our dependence on imported oil and more "inward investment".  He also clarified that he includes domestic oil in his list of alternatives. 

When I asked him about the barriers impeding the fuel diversity that he advocates, he immediately mentioned the interest groups that spring up, pro and con, whether concerning oil, natural gas, the lifecycle and materials for advanced vehicle batteries, or infrastructure for hydrogen fuel cell vehicles.  He would like to see federal and state governments enable change and "tell the interest groups to back off."  He observed that despite the shale revolution, "we still rely on imports and can't agree on creating new markets for natural gas" or to build the Keystone XL pipeline.  These disagreements stifle development. Together with federal regulation of hydraulic fracturing, this results in "government as disabler", not enabler of change.

We had a lively conversation about some of the specific fuels that would make up the more diverse mix Mr. Hofmeister would like to see in the marketplace, such as methanol, ethanol, natural gas and electricity.  I expressed some of my own concerns about the energy-equivalent cost of methanol and the safety risks involved in its use on the service station forecourt.  He replied that with expanded supply based on abundant US natural gas, the price of methanol could fall significantly from today's level of $1.60/gal. (equivalent to wholesale gasoline at $3.25/gal.)  That's certainly conceivable, because at a typical 70% conversion efficiency, the natural gas feedstock to produce a gallon of methanol would only cost about $0.37 at recent industrial gas prices.  He also envisioned fuels like this being dispensed in a closed system, to maximize safety.

We discussed natural gas as a bridge fuel for vehicles and whether it might be hard to get off this bridge, later.  In response he pointed to what he called the "EV lifestyle"--the improved convenience and driveability already experienced by EV owners who don't need extended driving ranges--and seemed to agree with my own view of electrification as  a given in the long-run.  He also suggested that this transition could be promoted by a coherent and comprehensive plan.  Earlier, he had pointed out that the administration's "all of the above" approach was just a concept, not a plan, because it lacks the targets, milestones and accountability necessary for a real plan--a point on which an ex-CEO and current strategist were bound to agree.

I couldn't end the interview without asking Mr. Hofmeister whether the tremendous recent turnaround in US oil production had led him to alter his idea, expressed in various talks and in his book, "Why We Hate the Oil Companies," for the US to establish an energy equivalent of the Federal Reserve Bank.  "I'm convinced it's the way to go," he said. "There's too much politics in energy policy now." He believes an "Energy Reserve Board" would stimulate the economy with investments focused on short, medium and long-term goals.  "What energy needs is consistency."

My half-hour conversation with him validated my view that John Hofmeister isn't your typical oil guy.  His ideas are grounded in the scale and complexity of the energy industry, but not bound by its conventional wisdom.  Although I didn't agree with all of them--particularly concerning the degree of government intervention necessary--his responses to my questions were forthright and reflected long and careful analysis, along with a strong sense of the benefits available to the US from a more rational and planned approach to our national energy endowment and opportunities.

A123 Bankruptcy Casts Doubts on EV Goals

The theory was that the federal government could guide an entire US electric vehicle (EV) industry into existence by orchestrating a constellation of grants, loans and loan guarantees to manufacturers and infrastructure developers, along with generous tax credits for purchasers.  That vision was attractive, because EVs have the potential to be an important element of a long-term strategy to counter climate change and bolster energy security. However, yesterday's bankruptcy of battery-maker A123 Systems, Inc. provides a costly reality check. Along with the earlier bankruptcy of another advanced battery firm, Ener1, and disappointing battery-EV sales, it raises new doubts concerning both the government's model of industrial development and the achievability of President Obama's goal of putting one million EVs on the road by 2015. 

A123 was built around a novel lithium-ion battery technology developed at MIT.  For a time they were the darling of the advanced battery sector, with a market capitalization above $2 billion following its 2009 initial public offering. That IPO came on the heels of A123's receipt of a $249 million stimulus grant from the Department of Energy and $100 million of refundable tax credits from the state of Michigan. Subsequently, though, they experienced low sales and a costly battery recall that contributed to their signing a memorandum of understanding with China's Wanxiang Group to sell an 80% interest in the company for around $450 million.  Instead, it now appears that Johnson Controls, a diversified company that was the recipient of a $299 million DOE advanced battery grant of its own, will end up acquiring A123's assets for around $125 million.  Johnson is apparently providing "debtor-in-possession" financing for A123's Chapter 11 process.  It's not clear whether Johnson would be able to draw down the unused portion of A123's federal grant.

Because of the government's close involvement with A123, and in particular its structuring of aid to A123 in a manner that left taxpayers without any call on the firm's assets ahead of suitors like Johnson Controls or Wanxiang, this event is inherently political.  I was a little surprised it didn't come up in last night's presidential debate.  If it does become a "talking point" in the next two weeks, however, I'd prefer to see the conversation focus on the real issues it raises.  The reasons for A123's failure appear very different from those behind the much-discussed failure of loan-guarantee recipient Solyndra.  While the latter ultimately called into question the judgment of officials who loaned money to Solyndra when that company's business model was already doomed, A123 highlights the much deeper challenges involved in attempting to conjure an entire industry out of thin air.

The earlier failure of GM's electric vehicle effort in the 1990s, the EV-1, demonstrated the chicken-and-egg nature of EV sales: Vehicle sales depended on recharging infrastructure that in turn depended on robust vehicle sales to justify infrastructure investment.  But at least GM could begin then by relying on a mature lead-acid battery industry.  Those batteries turned out to be inadequate to meet consumers' expectations of range and recharging convenience, which led to the creation of another chicken-and-egg dependence for the new EV industry: carmakers needed a reliable supply of advanced batteries from producers who couldn't invest in the capacity to make them, without knowing that vehicle sales would consume enough batteries to turn a profit.  So in 2009 the administration set out to short-circuit all those inter-dependencies by simultaneously funding the key elements of these loops, including advanced battery makers.  It makes me wonder if anyone involved had any direct manufacturing experience--a natural doubt considering that the entire US auto industry was restructured in 2009 by a task force without a single member who had worked in any manufacturing business, let alone the auto industry. 

The main causes of A123's failure appear to have involved basic manufacturing issues of capacity utilization and quality control.  The company wasn't selling enough batteries to cover its costs, and too many of the batteries it sold came back in an expensive recall.  They weren't the first business to experience such growing pains, but their challenges were compounded by the burden of a manufacturing line that had been sized to meet the demand of an EV market that hasn't yet materialized. US EV sales through September amounted to just 31,000 vehicles, or less than 0.3% of total US car sales.  The picture looks even worse if you subtract out sales of GM's Volt and Toyota's plug-in version of its Prius, the gasoline engines of which provide essentially unlimited range, circumventing the limitations of today's batteries.  I think there's a strong argument that the government's assistance to A123 was actually a key factor in leading them to bankruptcy, by prompting A123 to grow much faster than could have been justified to its bankers or private investors.

Perhaps it's some consolation that A123's technology has apparently been snapped up by a competitor, rather than going the way of Solyndra's odd solar modules.  Yet that outcome hardly justifies the casual dismissal of A123's fate by a DOE spokesman as a common occurrence in an emerging industry.  That sort of talk merely perpetuates the perception of cluelessness fostered by Energy Secretary Chu's failure to hold anyone accountable for the Solyndra debacle.  Yes, companies in emerging industries fall by the wayside, but the preferred response would be to examine what happened and apply the lessons learned to the rest of the "venture capital portfolio" with which the administration's industrial policy has saddled the DOE.  With EV sales still low and several key EV makers experiencing delays and production problems, a thorough public review of the entire EV strategy is in order.

Cleantech Firms Paying the Price for Subsidies

In observing the recent struggles of various segments of the global cleantech industry, including renewable energy and advanced energy technology firms, a pattern is emerging. Today's Wall St. Journal reports "Wind Power Firms on Edge," as the US wind industry hunkers down pending the renewal or expiration of a key subsidy at the end of 2012. A maker of electric-vehicle batteries that received a federal grant to build a factory in Indiana is reorganizing via bankruptcy, wiping out the equity of its original investors. Meanwhile, the US International Trade Commission may be on the verge of imposing retroactive tariffs on imported Chinese solar power equipment. Each of these stories has unique features, but what they share in common is the consequences of renewable energy policies around the world that promoted overcapacity in manufacturing and fierce competition in deployment, effectively setting up some of their past beneficiaries for failure or at least a period of very low margins. Depending on your perspective, this is either an indictment of such subsidies or collateral damage on our way to a brighter future.

One blogger from an advanced battery trade association noted that "Ener1 Is No Solyndra", and I tend to agree. As I've noted previously, the decision to award Solyndra a $535 million federal loan was ill-advised, not just because of competition from other solar manufacturers, but because at the time the government approved the loan the failure of Solyndra's business model was essentially already predetermined. Solyndra didn't contribute much to the global overcapacity in solar modules and panels, because its technology was never competitive. By contrast, Ener1's problems appear more fundamental. Like much of the global wind industry and solar industry, it was induced to invest in new capacity, the market for which depended almost entirely on subsidies and regulations that governments might not be able to sustain as these technologies scaled up, and that has gotten significantly ahead of demand.

The best examples of that are probably the various solar feed-in tariff (FIT) subsidies in Europe, which until recently were so generous that they not only supported the intended growth of an indigenous solar industry to capitalize on them, but also gave rise to an entirely unintended new export-oriented solar industry in Asia that had essentially no local market when it started, yet has since gone on to dominate global solar manufacturing and eat the lunch of the European solar makers and developers who got fat off the earlier stages of the FITs.

Or consider the US wind industry, including the imported equipment that still supplies around half of the US wind turbine value chain, according to the main US wind trade association. If the 2.2¢ per kilowatt-hour (kWh) Production Tax Credit (PTC) is renewed, and if wind generation grows from the current level of 115 billion kWh per year to 141 billion kWh by 2021, in line with the latest Department of Energy forecast, then over the next 10 years the wind industry would collect up to $30 B, with much of that locked in for projects that have already started up, less the amount generated by projects that opted for the expired Treasury cash grants in lieu of the PTC to the tune of $7.9 B from 2009-11. Yet based on these figures, wind would supply just 3.2% of US electricity in 2021. The industry now seems to be arguing that it needs just one more renewal of the PTC in order to become competitive. As of 2012, this benefit has been in place on an on-again, off-again basis for twenty years.

Although the theory that underpins such subsidies doubtless has some validity--that governments can help new technologies to develop quicker than markets alone would support, create markets for them by stimulating demand, and thereby move them down their learning curves to earlier competitiveness with conventional technologies--in practice such policies also have the serious shortcomings we are seeing. Because they do not operate in Soviet-style centrally planned economies, none of these governments can tell manufacturers precisely how much production capacity to build, or how much they will sell when it comes on-stream. In the absence of such powers--which in any case proved to be over-rated--companies and their investors are at the mercy of the boom-and-bust cycles such policies generate, with the normal, self-correcting mechanisms of industry consolidation dampened by continued intervention. Nor do the policies now in place seem very successful at creating industries that can survive without them. If you doubt that, ask the US wind industry for their forecast of new installations next year if the two-decade-old PTC is not renewed. According to the Journal, it would be somewhere between 0% and 30% of 2011's 6,810 MW, which was itself a third below the 2009 peak of 10,000 MW, despite the late-2010 extension of the cash grants to cover last year's projects.

The appropriate response to all of this depends on one's politics and the firmness of one's belief that these technologies are essential tools for combating climate change. Falling between the extremes of "just say no" and "look the other way" is the view that governments at least have an obligation to learn from the past and avoid the temptation to yield to demands that they leave existing subsidies in place until their beneficiaries decide they are done with them. If wind tax credits are extended, it should be at a level that recognizes the narrowing competitive gap with conventional energy and phases them out on a schedule. Electric vehicle subsidies should also be reassessed so that we don't find ourselves still providing upper-income taxpayers with incentives of $7,500 per car, even after sales have taken off and sticker prices fallen significantly. And solar subsidies ought to be fundamentally rethought to make it less attractive to install solar panels in regions with low sunlight, such as New York and New Jersey, than in those with abundant sun. And we shouldn't do that just for the benefit of taxpayers and in response to trillion-dollar budget deficits, but in the interest of producing healthy, globally competitive companies in these industries.

How Many More Solyndras?

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

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

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

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

Tapping Salt Water's Energy Potential

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

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

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

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

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

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

Temperature Extremes and EV Battery Trade-offs

The first production-model Nissan Leaf electric vehicle is scheduled to be delivered to a customer in the San Francisco Bay Area tomorrow. I know if I were on the receiving end, I'd be as excited as a kid on Christmas morning, particularly in a place where having the first Leaf will score its owner many green points. However, if the assessment by MIT's Technology Review of Nissan's choices concerning the temperature control of the Leaf's battery pack is accurate, then it's probably just as well that the first one is going to a location with such a benevolent climate, instead of the Midwest, upstate New York, or the desert Southwest. Batteries are sensitive to external temperature, in terms of both performance and longevity, and Nissan appears to be betting that making the battery simpler to replace is a higher priority than optimizing its condition at all times, as GM has done for the battery pack in the Chevrolet Volt.

It's easy to forget that batteries are fundamentally chemical, rather than just electronic devices. The chemical reactions in a battery absorb or release heat during the charge/discharge cycle, and the capacity of the battery's environment to accommodate those heat flows can affect these reactions. For a battery pack storing and delivering as much energy as required to run a car, these interactions are significant, and early adopters of EVs are already learning that the range of EVs becomes more limited in hot or cold weather. It's not as clear that they understand the degree to which extreme temperatures can degrade battery life. The economics of an EV could look very different if a battery pack only lasted six or seven years, instead of ten.

As the article explains, GM chose a liquid cooling system for the battery pack in its Volt range-extended EV. This system cools or heats all of the battery's cells, as necessary, and sometimes draws power for this purpose even when the vehicle is parked, as I learned when I test-drove one with the Volt's Vehicle Line Director last winter. According to him, GM's design team knew it had to go to extraordinary lengths to ensure the battery would perform reliably and last the expected ten years or 150,000 miles. Nissan appears to have taken a different path to battery management, providing a cooling fan for the battery pack and an optional battery heater--an option reportedly not available on the first Leafs. You don't have to be an expert in heat transfer to guess that air won't move heat around the battery pack's cells as well as liquid can, and that as a result, at least part of the Leaf's battery could potentially be exposed to more heat and cold--and possibly suffer more performance impact from them--than the Volt's.

That trade-off might reflect a different vision for how the battery will be used. Nissan (with its alliance partner Renault) is the main carmaker working with Better Place, Shai Agassi's EV battery recharging-and-exchanging start-up. A battery pack with only electrical connections to the car will be much easier and neater to swap in and out than one with liquid hoses running to a radiator and heater. This situation wouldn't even be a consideration for the Volt, which has an onboard generator to take over when the battery's charge falls too low. But for battery-only EVs, battery-swapping is as close as they can get to replicating the convenience of refueling a gasoline or diesel car in a few minutes. If EVs catch on via a business model like Better Place's, in which consumers routinely exchange their flat batteries for fully-charged ones (and might not even own the battery pack, but instead rent it by the month or the mile) any shortcomings from Nissan's less robust battery-conditioning strategy would fall on someone other than the consumer, as a statistical cost of doing business.

From my perspective this is just one of the uncertainties concerning the operation and consumer acceptance of EVs about which we'll learn more as their numbers climb from the low thousands to the hundreds of thousands and millions. However, I find it interesting that few journalists have picked up on an issue that could have far more impact on the EV ownership experience than the tempest in a teapot that some stirred up when they found out that the Volt's wheels are occasionally driven partly by the engine-generator, rather than entirely electrically. If I were buying one of these cars, I'd be a lot more interested in how far its expensive battery pack will carry me and how long it will last, than in whether the car is truly a range-extended EV or just a plug-in hybrid.

China's Leverage on Renewable Energy Increases

Last month's announcement that China was cutting its export quota for rare earth elements by 72% for the second half of 2010 didn't seem to attract wide attention, but now that the other half of its strategy has been revealed, that might change. Today's Wall St. Journal reported overtures from Chinese officials to firms interested in accessing these materials, which are critical for the production of some components of renewable energy technology and advanced vehicles. The apparent deal: invest in rare earth processing in China to obtain access, with the output from new facilities incorporated into products for the rapidly-growing internal market or export. Not only would this practice compound the difficulties faced by US and other foreign renewable energy firms seeking to market their products in China, it could also make it much more expensive to produce them outside the People's Republic.

For some time I've been intrigued by growing concerns about access to rare earths and scarce metals. These include the true "rare earths" from the periodic table of the elements, as well as other scarce elements such as Indium, Gallium and Tellurium. Their uses include solar panels, wind turbines, hybrid car motors and batteries, and other "clean energy" devices, along with many non-energy applications. As the Journal noted, China accounts for over 90% of global production of the rare earths and is among the top producers of the other scarce materials. And although China doesn't have a natural monopoly on them, it currently enjoys an effective one, as plans to resume or ramp up production in North America, Australia, South Africa and elsewhere will require both time and significant capital.

This development poses an unwelcome challenge to a variety of renewable energy firms. At a minimum, it could significantly raise their production costs, just as they are trying to move down the experience curve in order better to compete with conventional energy--including newly-abundant natural gas--and at the same time that governments around the world are being forced to cut back on subsidies, due to fiscal imbalances and the weak economy. Any company that depends on a stable, let alone expanding supply of these ingredients must either be looking seriously at relocating production to China or making potentially fundamental changes in their technology to switch to more abundant raw materials. Green jobs, perhaps, but where?

China's efforts to capture higher returns and more of the value-added for these scarce materials shouldn't surprise anyone; it's basic economics. OPEC tried this strategy in the 1980s, when it built export refineries in the Middle East and bought existing ones elsewhere. This didn't work out very well, because it contributed to a persistent glut of global refining capacity that, with the exception of a few standout years, generally benefited consumers more than producers. China could experience something similar in rare earths, once new, non-Chinese sources are brought online--assuming they are. Mining and processing such deposits entails large capital costs that, once invested, can set up a classic boom-and-bust commodity cycle. Unfortunately, the prospect of a future rare earth glut will be of little comfort to makers of wind turbines, advanced car batteries, and thin-film solar cells for the next several years, at least.