What is it that makes ultracapacitors such a promising technology? And if ultracapacitors are so great, why have they lost out to batteries, so far, as the energy storage device of choice for applications like electric cars and the power grid?

Put simply, ultracapacitors are some of the best devices around for delivering a quick surge of power. Because an ultracapacitor stores energy in an electric field, rather than in a chemical reaction, it can survive hundreds of thousands more charge and discharge cycles than a battery can.

A more thorough answer, however, looks at how ultracapacitors compare to capacitors and batteries. From there we’ll walk through some of the inherent strengths and weaknesses of ultracaps, how they can enhance (rather than compete with) batteries, and what the opportunities are to advance ultracapacitor technology.

Capacitor 101

A basic capacitor consists of two metal plates, or conductors (typically aluminum), separated by an insulator, such as air or a film made of plastic, or ceramic. During charging, electrons accumulate on one conductor, and depart from the other. In effect, a negative charge builds on one side while a positive charge builds on the other.

The negatively charged electrons want to join the depleted (positive) side, but can’t cross over that non-conductive insulator (for the most part, anyway—there is some leakage). This separation of positive and negative charges, which want to balance out, or neutralize, each other, creates what’s called an electric field. Discharging occurs when the electrons are given a path to flow to the other side—in other words, when balance is restored.

Putting the “ultra” in ultracapacitors

Ultracap diagram courtesy of NREL

Ultracapacitors also have two metal plates, but they are coated with a sponge-like, porous material known as activated carbon. And they’re immersed in an electrolyte made of positive and negative ions dissolved in a solvent. One carbon-coated plate, or electrode, is positive, and the other is negative. During charging, ions from the electrolyte accumulate on the surface of each carbon-coated plate.

Like capacitors, ultracapacitors store energy in an electric field, which is created between two oppositely charged particles when they are separated. Recall that in an ultracapacitor, we have this electrolyte, in which an equal number of positive and negative ions are uniformly dispersed. And remember that in a capacitor, negative charge builds on one side and positive charge builds on the other. Similarly, in an ultracapacitor, when voltage is applied across the two metal plates (i.e. during charging), a charge still builds on the two electrodes—one positive, one negative. This then causes each electrode to attract ions of the opposite charge.

But for an ultracapacitor, each carbon electrode ends up having two layers of charge coating its surface (thus, ultracaps are also called “double layer capacitors”), John Kassakian, a professor in MIT’s Laboratory for Electromagnetic and Electronic Systems (LEES), explained to me: “In effect, an ultracapacitor is actually two capacitors in series, one at each electrode.”

Joel Schindall, another professor in MIT’s LEES and associate director of the lab, explained that during discharging, the charge on the plates decreases as electrons flow through an external circuit. “The ions are no longer attracted to the plate as strongly,” he said, “so they break off and once again distribute themselves evenly through the electrolyte.”

The ultracap advantage

Unlike capacitors and ultracapacitors, batteries store energy in a chemical reaction. Ions are actually inserted into the atomic structure of an electrode (in an ultracap, the ions simply cling). This is an important distinction, because storing energy without chemical reactions allows ultracapacitors to charge and discharge much faster than batteries, Schindall explained. And because capacitors don’t suffer the wear and tear caused by chemical reactions, they can also last much longer. (See previous post: Why lithium-ion batteries die so young)

Charge separation is at work in both capacitors and ultracapacitors. But in a capacitor, the separated charges can get no closer than the distance between the two metal plates. They’re awfully close together—on the order of tens of microns—but limited by the thickness of that ceramic or paper film in the middle (one micron is one-thousandth of a millimeter). In an ultracapacitor, the distance between the ions and opposite-charged electrode is so tiny it’s measured in nanometers (one-thousandth of a micron).

Why should we care about such small distances? Turns out the size of the electric field is inversely proportional to the separation distance. The shorter distance between those separated charges in an ultracapacitor translates to a larger electric field—and much more energy storage capacity.

That’s only part of why ultracapacitors can store more energy than regular capacitors. The activated carbon is also key. See, it’s “so spongy,” according to Schindall, that it affords a surface area 10,000 to 100,000 times greater than the linear surface area of the naked metal. Put simply, all those nooks and crannies in the surface allow more ions to cling to the electrode.

Measuring capacitance

Surface area makes a huge difference for what’s called capacitance, or the amount of electric charge a device will hold given a certain amount of voltage. Capacitance is the key metric for comparing capacitor performance, and it’s measured in Farads (named, as Lost fans might appreciate, after the chemist and physicist Michael Faraday).

Now, the Farad is such a huge unit of measurement, “it’s like measuring distance in light years,” said Schindall. So it’s much more common to see microfarads (one-millionth of a farad) and even picofarads (one-millionth of a microfarad).

A capacitor the size of a D-cell battery, for example, has a capacitance of only about 20 microfarads. But a similarly sized ultracapacitor has a capacitance of 300 Farads. That means, at the same voltage, the ultracapacitor could in theory store up to 15 million times more energy than the capacitor.

Here is where we run into some of the challenges with ultracapacitors, however. A typical 20-microfarad capacitor would be able to handle as much as 300 volts, while an ultracap would be rated at only 2.7 volts. At a higher voltage, the electrolyte starts to break down. So realistically we’re talking about an ultracapacitor storing about 1,500 times the energy of a comparably sized capacitor, said Schindall.

Ultracaps and batteries as partners

Despite offering a huge leap over regular capacitors, ultracaps still lag behind batteries when it comes to energy storage capacity. Ultracapacitors (which are also more expensive per energy unit than batteries), can store only about 5 percent of the energy of comparable lithium-ion batteries. And that, said Schindall, is a “fatal flaw” for many applications.

It would be technically possible, for example, to use ultracaps instead of lithium-ion batteries in cell phones, with some serious benefits: You would never have to replace the ultracapacitor, said Schindall, and the phone would recharge very quickly. But the phone wouldn’t stay charged for very long at all with today’s ultracapacitors—perhaps as little as 90 minutes, or five hours max, Schindall said.

Ultracapacitors are very effective, however, at accepting or delivering a sudden surge of energy, and that makes them a good partner for lithium-ion batteries, Schindall explained. In an electric car, for example, an ultracapacitor could provide the power needed for acceleration, while a battery provides range and recharges the ultracap between surges.

Think of it this way: The ultracapacitor is like a small bucket with a big spout. Water can flow in or out very fast, but there’s not very much of it. The battery is like a big bucket with a tiny spout. It can hold much more water, but it takes a long time to fill and drain it. The small bucket can provide a brief “power surge” (“lots of water” in this analogy), and then refill gradually from the big bucket, Schindall explained.

Putting ultracaps to work

Already, Schindall believes some electric vehicle manufacturers are using ultracapacitors for acceleration. The devices also appear in hundreds of other applications, from cell phone base stations to alarm clocks (as backup power) to audio systems.

For most music, Schindall explained, a high-end audio system with big speakers might do just fine with a 1-watt amplifier. “But then the kettle drum comes in,” demanding a sudden power surge of 1-kilowatt. One solution, Schindall said, is to build a 1-watt supply, plus an ultracapacitor to handle the peak.

Ultracapacitors hold promise for a similar job on the electric grid. Today, transmission lines operate below full capacity (often somewhere above 90 percent), said Schindall, in order to leave a buffer for power surges. Banks of ultracapacitors could be set up to absorb power surges, enabling transmission lines to run closer to 100 percent capacity.

It might not seem like much, especially considering that it would take warehouse-sized banks for ultracaps to do the job. But installing ultracapacitors to handle the peaks would actually be much cheaper, Schindall said, than adding even 5 percent more capacity with new transmission lines.

In cars, ultracapacitors could play a role in the growing market for “microhybrids,” which cut the engine during idling.  In these “start-stop” systems, Schindall explained in an email, “The ultracapacitor would provide power during the stop (lights, radio, air conditioner, etc.).” It would also provide power for the restart, and then be “recharged during the next interval of travel.”

How to build better ultracapacitors

There are two basic ways to improve the performance of ultracapacitors: increase the surface area of the plate coating, and increase the maximum amount of voltage that the device can handle.

Recall old Faraday again. Capacitance, measured in Farads, is how much electric energy our device will hold given a certain voltage. Increase the voltage, and you can increase the amount of energy our device holds (energy is equal to half the capacitance, multiplied by voltage squared).

Schindall is tackling the surface area challenge using carbon nanotubes (more like a shag carpet or paintbrush than the sponge-like activated carbon). Other researchers, he noted, are working with graphene or better activated carbon. In addition to boosting the surface area, carbon nanotubes and graphene can also “withstand a somewhat higher voltage” than activated carbon, said Schindall.

The voltage challenge, meanwhile “seems to be a tougher road,” he said. Researchers are experimenting with ionic liquid electrolytes (all ion, no solvent, behaves like a liquid), which under the right conditions can operate at up to three times the voltage of conventional electrolytes.

But ionic liquids are “fussy,” Schindall said. “They don’t like being liquids,” and tend to freeze below room temperature. They’re also expensive, and they have higher resistance than conventional electrolytes, which means you can’t get energy out as fast. The maximum power—one of ultracaps’ key advantages—is decreased. As Schindall put it, “There’s always a tradeoff.”

Image courtesy of Argonne National Laboratory, and NREL, stantontcaddy, Maxwell, Ioxus,

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But why does this happen? What’s going on in the battery that makes it give up the ghost? The short answer is that damage from extended exposure to high temperatures and a lot of charging and discharging cycles eventually starts to break down the process of the lithium ions traveling back and forth between electrodes.

The longer answer, which will take us through a description of unwanted chemical reactions, corrosion, the threat of high temperatures and other factors affecting performance, begins with an explanation of what happens in a rechargeable lithium-ion battery when everything’s working well.

Lithium-ion battery 101

In a typical lithium-ion battery, we’ll find a cathode, or positive electrode, made out of a lithium-metal oxide, such as lithium cobalt oxide. We’ll also find an anode, or negative electrode, which today is generally graphite. A thin, porous separator keeps the two electrodes apart to prevent electrical shorting. And an electrolyte, made of organic solvents and lithium-based salts, allows for the transport of lithium ions within the cell.

During charging, an electric current forces lithium ions to move from the cathode to the anode. During discharging (in other words, when you use the battery), ions move back to the cathode.

Daniel Abraham, a scientist at Argonne National Laboratory leading research into how lithium-ion cells degrade, compared this process to water in a hydropower system. Moving water uphill requires energy, but it flows downhill very easily. In fact, it delivers (kinetic) energy, said Abraham. Similarly, a lithium cobalt oxide cathode “does not want to give up its lithium,” he said. Like moving water uphill, it requires energy to take lithium atoms out of the oxide and load them into the anode.

During charging, ions are forced between sheets of graphene that make up the anode. But as Abraham put it, “they don’t want to be there. When they get a chance, they’ll move back,” like water flowing downhill. That’s discharging. A long-lasting battery will survive several thousand of these charge-discharge cycles, according to Abraham.

When is a dead battery really dead?

When we talk about “dead” batteries, it’s important to understand two performance metrics: energy and power. For some applications, the rate at which you can get energy out of the battery is very important. That’s power. In electric vehicles, high power enables rapid acceleration and also regenerative braking, in which the battery needs to accept a charge within a couple of seconds.

In cell phones, on the other hand, high power is less important than capacity, or how much energy the battery can hold. Higher-capacity batteries last longer on a single charge.

Over time the battery degrades in a number of ways that can affect both power and capacity until eventually it simply can’t perform its basic functions.

Think of it in terms of another water analogy: Charging a battery is like filling a bucket with water from a tap. The volume of the bucket represents the battery’s energy, or capacity. The rate at which you fill it — turning the tap on full blast or just a trickle — is the power. But time, high temperatures, extensive cycling and other factors end up creating a hole in the bucket (dear Liza, dear Liza . . .).

In the bucket analogy, water leaks out. In a battery, lithium ions are taken away, or “tied down,” said Abraham. Bottom line, they’re prevented from going back and forth between the electrodes. So after a few months, the cell phone that initially required a charge only once every couple of days now needs a charge every day. Then it’s twice a day. Eventually, after too many lithium ions have been tied down, the battery won’t hold enough of a charge to be useful. The bucket will stop holding water.

Why does this happen? Well, in addition to the chemical reactions that we want to happen in the battery, there are also side reactions. Barriers arise that impede the motion of lithium ions. So the electric car that went, say, zero to 60 in 5 seconds off the lot will take 8 seconds after a few years, and maybe 12 seconds after 5 years. “All the energy is still there, but it can’t be delivered fast enough,” said Abraham. The ions run into roadblocks.

What breaks down and why

The active portion of the cathode (the battery’s source of lithium ions) is designed with a particular atomic structure, for stability and performance. When ions are removed, sent over to the anode and then inserted back into the cathode, we ideally want them to return to the same spot, in order to preserve that nice stable crystal structure.

The problem is that the crystal structure can change with each charge and discharge. An ion from apartment A doesn’t necessarily come home but could instead insert herself into apartment B next door. So the ion from apartment B finds her place occupied by this drifter and, not being one for confrontation, decides to take up residence down the hall. And so on.

Gradually these “phase changes” in the material transform the cathode to a new crystal structure with different electrochemical properties. The particular arrangement of atoms, which enabled the desired performance in the first place, has been altered.

In hybrid vehicle batteries, which only need to provide power when the vehicle is accelerating or braking, noted Abraham, these structural changes occur much more slowly than in electric vehicles. This is because only a small fraction of lithium ions in the system move back and forth in any given cycle. As a result, he said, it’s easier for them to return to their original locations.

Problem of corrosion

Degradation can occur in other parts of the battery as well. Each electrode is paired with a current collector, which is basically a piece of metal (typically copper for the anode, aluminum for the cathode) that gathers electrons and moves them to an external circuit. So you have slurry made from an “active” material like lithium cobalt oxide (which is ceramic and not a very good conductor), plus a gluelike binder painted over this piece of metal.

If the binder fails, the coating can peel off the current collector. If the metal corrodes, it can’t move electrons as efficiently.

Corrosion within the battery cell can result from an interaction between the electrolyte and electrodes. The graphite anode is highly “reducing,” which means it gives up electrons easily to the electrolyte. This can produce an unwanted coating on the graphite surface. The cathode, meanwhile, is highly “oxidizing,” which means it easily accepts electrons from the electrolyte, which in some cases can corrode the aluminum current collector or form a coating on the cathode particles, Abraham said.

Too much of a good thing

Graphite — the material commonly used to make an anode — is thermodynamically unstable in an organic electrolyte. What that means is that the very first time our battery is charged, the graphite reacts with the electrolyte. This forms a porous layer (called a solid electrolyte interphase, or SEI) that actually protects the anode from further attacks. This reaction also consumes a little lithium, however. So in an ideal world, we would have that reaction occur once to create the protective layer and then be done with it.

In reality, however, the SEI is a sadly unstable defender. It does a good job of protecting the graphite at room temperature, said Abraham, but at high temperatures or when the battery runs all the way down to zero charge (“deep cycling”), the SEI can partially dissolve into the electrolyte. (At high temperatures, electrolytes also tend to decompose and side reactions accelerate.)

When friendlier conditions return, another protective layer will form, but this will eat up more lithium, giving us the same problem we had with the leaky bucket. We’ll have to recharge our cell phone more often.

Now, as much as we need that SEI to protect the graphite anode, there can be too much of a good thing. If the layer thickens too much, it actually becomes a barrier to the lithium ions, which we want to flow freely back and forth. That affects power performance, which is, as Abraham emphasized, “extremely important” for electric vehicles.

Building better batteries

So what can be done to make our batteries last longer? In the lab, researchers are looking for electrolyte additives to function like vitamins in our diet, enabling the battery to perform better and live longer by reducing harmful reactions between the electrodes and electrolyte, said Abraham. They’re also seeking new, more-stable crystal structures for the electrodes, as well as more-stable binders and electrolytes.

Engineers at battery and electric car companies, meanwhile, are working on the battery pack and thermal management systems to try and keep lithium-ion cells within a constant, healthy temperature range. As consumers, the rest of us can avoid extreme temperatures and deep cycling, and for now keep grumbling about those batteries that always seem to die too soon.

Images courtesy of Argonne National Labs, felixtsao, warrenski, MitchClanky2008, bizmac

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It turns out cell phones and electric cars have more in common than you might think, and technology developed for phones could help pave the way for more powerful electric cars. A prime example of this is that one of the world’s largest carbon and graphite producers, GrafTech International, has begun eying the world of electric vehicles as a new opportunity for materials designed to handle heat in the shrinking confines of gadgets.

From iPhone to EV

GrafTech International, a massive graphite electrode supplier, has been manufacturing flexible graphite materials since the 1960s. In electronics, GrafTech first saw its graphite heat spreaders used in flat panel TVs, and later in laptops and smart phones, including Apple’s iPhone. As Julian Norley, a senior corporate fellow at GrafTech, explained in an interview, “It can take heat from any component and basically spread it out.”

Today, GrafTech is in the process of turning its heat-spreading materials into a component for battery packs that could appear in retrofits of current electric vehicles as early as 2014, and in production EVs sometime after that, according to the company, which also makes carbon and graphite-based materials for applications ranging from solid state lighting and semiconductors to fuel cells and nuclear reactors.

In the electric car space, battery pack manufacturers and systems integrators are GrafTech’s target customers, although as Ian McCallum, manager of GrafTech’s market development group, noted, some automakers (notably General Motors and Tesla Motors) are taking it upon themselves to own their own battery pack technology.

Graphite’s Appeal

Aluminum and copper were the traditional heat spreaders for electronics, said Norley. But graphite, boasting lighter weight and higher thermal conductivity than either metal, has displaced aluminum and copper on “the higher-performance end.”

Yet EV makers and their battery suppliers, “without any other obvious options,” said McCallum, are commonly using “relatively thick aluminum dividers between cells and calling that their thermal solution.” Often, he added, there is also a liquid or air cooling system integrated on top of that.

What graphite-based alternatives can do, at least in theory, is handle the same amount of heat with much less bulk than aluminum (or handle significantly more heat for the same bulk). Based on internal models, Norley said the combined weight of heat spreaders in a typical automotive battery pack could be reduced by about 75 percent when using graphite materials instead of aluminum.

Of course, heat spreaders are but a sliver of the cell. Swapping out aluminum for graphite heat spreaders in a 9-millimeter-thick cell, for example, might make room for 214 cells in a pack where previously only 200 cells would fit. “Not very impressive,” as McCallum put it. “But battery manufacturers would kill for a 7 percent increase in energy density” (packing those 14 extra cells into the space of a 200-cell pack).

Simply swapping out the aluminum for the graphite has its benefits: making it possible to build a battery with the “same cells, but less stuff in the pack,” as GrafTech research scientist Ryan Wayne put it. But what gets Norley and Wayne really excited is the possibility of designing batteries in new ways with these new materials. “Maybe you fit two packs where you could only fit one,” suggested Wayne, or use “a thicker graphite that can handle more heat” for a more powerful pack.

Cost is key

Alex Carter, an analyst with the market research firm Lux Research, agreed that thermal management materials offer a “big opportunity going forward,” since they sit at the intersection of two growth industries: electronics and energy storage.

Yet in a time when batteries still make up as much as 40-50 percent of the total cost of an electric car, said Carter, low-cost aluminum has a distinct advantage. EV makers are “in a phase right now where cost is paramount,” he said.

As the cost of other battery components comes down, Carter predicted, it will create “breathing room” for car companies and battery suppliers to consider investing in higher performance, higher cost materials like graphite heat spreaders.

Sizing up the competition

In addition to GrafTech and other suppliers of engineered graphite, companies like Leyden Energy are already using graphite foil in lithium-ion batteries. And advanced graphite materials are part of a larger trend of “carbon materials coming into their own,” said Carter. Down the road, he added, flexible graphite materials could face stiff competition from graphene (a single-atom-thick sheet of carbon), which Intel is developing for use in heat spreaders for computer chips.

Plus, aluminum producers shouldn’t be expected to stand still. “Alcoa wouldn’t want to lose a major growth market,” said Carter. So as aluminum comes under pressure from new materials, expect higher-performance aluminum alloys to come on the market. That’s what happened in the aerospace segment, said Carter, when carbon fiber began to compete with aluminum.

So far, GrafTech has tested its materials in battery packs for an electric bicycle and an electric motorcycle (the latter in partnership with Ohio State University). The University of Einhoven, another GrafTech partner, is building a 16 kWh lithium-ion pack for racing using all-graphite heat spreading materials. Beyond academia, GrafTech said multiple battery makers are testing its heat spreaders for use in electric vehicle applications.

According to Norley, incumbent technology is the biggest competitor for graphite heat spreaders in electric vehicle applications. Working with graphite would require the understanding of a new material and a new way of doing things in a field where already “everything’s uncomfortably fast,” said McCallum. But then, that’s the same challenge GrafTech faced in consumer electronics, and now we have graphite heat spreaders sandwiched into our phones.

Images courtesy of yellowcloud, GrafTech, Appfire, International Battery, and Leyden Energy.

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Louisiana pledged back in 2009 to provide up to $67 million in grants under a “mega fund” for economic development — on the condition that, among other things, Next Autoworks wins low-cost federal loans requested under the Department of Energy’s Advanced Technology Vehicles Manufacturing program.

But now state lawmakers are considering a proposal to take $82 million from the mega fund to fill gaps in Governor Bobby Jindal’s spending plan for the fiscal year beginning July 1. If the proposed amendment passes, Jindal economic development chief Stephen Moret told the local Monroe News Star, “It would definitely kill the Next Autoworks project.”

Importance of the Mega Fund

The state funds are an important piece of Next Autoworks’ case, when it comes to winning the funds from the ATVM program. The ATVM program already rejected the company once, partly due to insufficient private capital and the lack of solid distribution plans. The promise of state funds is evidence of both local support and the startup’s ability to come up with its share of financing if the loan comes through (ATVM loans can cover only 80 percent of project costs).

But the clock is ticking, and Louisiana has a budget to balance. “I’ve fought this for three years, but I just can’t hold it any longer while we wait on Washington,” Louisiana House Appropriations Committee Chairman Jim Fannin told the Star last month. “We don’t normally hold unencumbered money that long.”

While the Energy Department’s Loan Programs Office declined to comment on a specific application, a representative did confirm with us this week that the agency considers financial support from state and local governments as part of its overall evaluation of a project and its financial viability.

Still Hope

David Hitchcock, Vice President of Louisiana Operations for Next Autoworks, said in an interview that local and state officials still support the Next Autoworks plan to set up manufacturing at a shuttered plant in northeastern Louisiana. “We’re extremely honored by their confidence and patience,” he said, emphasizing that the budget proposal has not been signed into law. “The money’s still there,” he said. After the final vote, expected June 23, “that’s when we’ll know for sure.”

But some damage may already be done. Moret was quoted in the News Star saying just the committee vote sends a message that lawmakers may not support economic development. “If it’s not reversed, it’s a crushing blow to northeastern Louisiana, and even if it’s reversed, it undermines our efforts,” he said.

Still Banking on DOE, After All These Years

According to Hitchcock, the two years that Next Autoworks has spent pursuing federal funds have not gone to waste or forced the company into catch-up mode. “What doesn’t kill you makes you stronger. This time has been well spent,” he said. Although he declined to provide specifics, Hitchcock said the company has made progress in refining its business model, brand, and the design of the car itself to make it “more fun and modern.”

Next Autoworks has “several” prototypes now, including “one all dressed up as a demo vehicle.” It also has a new CEO, Kathleen Ligocki, who came on board last fall after the DOE rejection triggered Frank Varasano’s departure.

Since then, the company has “reexamined everything we’ve been doing,” said Hitchcock. One thing it has not seemed to have done is concentrate on a backup plan in case Uncle Sam says no. It’s not uncommon for companies vying for government funds to be mum on alternatives, but they’ll sometimes note the possibility of manufacturing overseas (A123 Systems, Boston-Power, Coda Automotive), for example, or raising private capital (Aptera, Bright Automotive).

Others simply go about their business developing sources of revenue that don’t require a big factory (again, Bright). That’s not Next Autoworks’ style. Hitchcock said he “wouldn’t want to speculate on Plan B,” as the company is tightly focused on the DOE loan and being able to act quickly if it comes through.

Struggle to Keep Up With the Fords

The Next Autoworks team has been working hard to “keep track of where the market’s trending,” especially in terms of fuel economy and connectivity. After all, the American market for high-MPG small cars has become considerably more crowded since Next Autoworks first unveiled plans for a “high quality, environmentally friendly and fuel-efficient” vehicle two years ago.

Add to this the fact that plug-in hybrid and electric vehicles are now commercially available, and one has to wonder if the window of opportunity has closed for a startup with no large-scale manufacturing experience, little brand recognition, and a plan to use the old internal combustion engine for supposedly advanced vehicles.

Yet Next Autoworks has always said its competitive strength will lie in the whole package — in offering “the best value, not the best,” as Hitchcock put it. For an unnamed affordable price, the company says it will sell a car with not the best fuel economy, but better than average, and connectivity tools that are “not earth shattering,” but “intuitive, easy.” Hitchcock calls the strategy “intelligently frugal.” That’s a tough spot for a startup years away from achieving the economies of scale enjoyed by legacy automakers. Yet Next Autoworks remains confident.

“If our car was in the marketplace now, we’d be doing very well,” Hitchcock said. If and when the car rolls out, “I think the market will still be there,” and it will be big enough for Next Autoworks to carve out a slice. “I think there’s room.”

Image courtesy of Kevin Briody.

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Michael Parrella, founder and chief executive of GTherm, told us in an interview that the bright idea for the company’s innovation came when he realized that they could move heat instead of water. Three years ago, he set about reading hundreds of patents related to geothermal energy, and realized much of the geothermal industry was stuck on moving water. Parrella’s knowledge of thermodynamics, however, led him to ponder: why not move heat?

“It was a Eureka moment,” Parrella said.

The geothermal power industry’s laser-like focus on moving water was partly the result of a federally funded report released in 2007 by analysts at the Massachusetts Institute of Technology, which looked at the future of engineered, or enhanced, geothermal systems (EGS) in the U.S. The report found promise in geothermal systems using large amounts of water pumped through an area of fractured rock, and after the report came out “everybody stopped looking at other ways of doing it,” Parrella said.

The same landmark MIT study also recognized the potential seismic risk that could come with fracturing hot rock using huge amounts of water under high pressure (called “fracking”), and noted that some regions would have difficulty supplying enough water for these thirsty geothermal plants. But the GTherm concept, dubbed Single-Well Engineered Geothermal System, or SWEGS, is meant to circumvent those challenges.

Smarter Geothermal

The SWEGS design, which has yet to be demonstrated at scale, calls for the creation of a “heat nest,” made up of a heat exchanger at the bottom of a well, a specialized thermal grout, and what Parrella calls “heat highways.” These are horizontal drilling bores extending several hundred feet out from the well into hot rock.

Rather than piping water through the rock, GTherm proposes using Duratherm, a fluid that transfers heat. The fluid (“environmentally inert,” according to Parrella) is circulated in a closed-loop system through the heat nest and up to the ground level. It heats fluid circulating through a second loop, driving a turbine connected to an electric generator.

As the Electric Power Research Institute (EPRI), which is working with GTherm and Dartmouth University to analyze the SWEGS concept, noted earlier this year, GTherm has a ways to go on the road to large-scale commercial deployment. “Ultimately, down-hole heat exchanger designs, grouts, and working fluids will need to be tested and optimized in field environments over increasingly large scales,” EPRI wrote.

Yet if it works as planned, GTherm’s approach could offer several advantages over competing geothermal technology, eliminating the need for large amounts of water, limiting exposure to corrosive, mineral-laden brine, reducing seismic risk, and avoiding the cost of injection and production wells. “It’s a much less dangerous situation on the topside,” said Parrella.

Maintenance is minimal, required only for above-ground valves, pumps, and generators — or as Parrella calls them: “the spinning things on the surface of the power plant.” Each SWEGS plant requires about two acres of land, but the projects needn’t monopolize the surface. In Jamaica, for example, the company is working to develop a 10-megawatt plant underneath an airport.

“We pick up the heat, bring it up top, and use it to generate electricity,” Parella said. And the “amount of heat we extract equals the refresh rate of the rock.” That means the “well will never deplete,” he said. The system could be put to work at “dead geothermal wells,” in the deep rock of the Northeastern U.S., and at abandoned oil and gas wells around the world. According to EPRI, however, this type of single-well system will likely be most effective when deployed in a “fractured or porous medium” that is highly saturated.

The company is applying for several grants from the Department of Energy and EPRI. Already, EPRI has helped GTherm complete mathematical modeling, Parrella said.

In addition to its U.S. staff, GTherm has subsidiaries in the Dominican Republic, Jamaica, Costa Rica and Chile, employing a total of about 35 to 40 people. Citing job estimates from the Department of Energy, Parrella emphasized GTherm’s plants could employ hundreds more if they come online as planned.

GTherm has a handful of plants in the pipeline, including a 2 MW plant in the Dominican Republic; a 4 MW plant in Southern California; a pair of 10 MW plants in Costa Rica and Jamaica; and a 30 MW plant in Texas. Each plant is expected to cost less than $4 million per megawatt, according to Parrella.

It takes eight weeks to “put a hole in the ground,” for GTherm’s system, and for a project on the scale of the Texas plant, GTherm’s contractors will need to drill as many as 36 well holes. These projects are modular in the sense that “as each two holes are drilled, a nest is built,” and it can start generating electricity, said Parrella.

GTherm has been “self-funded” to date, according to Parrella. It is in the “final stages of negotiation” to secure power-purchase agreements for the projects, but Parrella said the company is fully committed to completing them, adding, “We’re ready to rock and roll.”

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In the long run, Aquion executives believe these bulk storage devices will help solar and wind power give expensive natural gas “peaker” plants a run for their money as the go-to choice for meeting electricity needs during periods of highest demand.

Matt Rogers, former senior adviser to Secretary of Energy Steven Chu, in 2009 called Aquion’s solution “ingenious,” and said the technology (which the Department of Energy has supported with a $5 million stimulus grant) could potentially store huge amounts of energy at one-tenth the cost of the alternatives. High profile venture capital firm Kleiner Perkins Caulfield & Byers has also backed the company.

In the Beginning

Founded in 2007, Aquion is at an early phase that’s both exciting and uncertain. Yet the Pittsburgh, Penn.-based startup has global ambitions. Previously called 44 Tech Inc., Aquion dropped the numeric moniker last year when it learned 44 is “the number of least luck in China,” said founder and chief technology officer Jay Whitacre. “44 Tech,” he said, was “the equivalent of double-death battery.”

The current mash-up of “aqueous” and “ion” (Aquion) may be more appropriate for a startup working with some of the most benign materials in the battery business. According to business development chief Ted Wiley, Aquion’s battery is made from widely available precursor materials that are very easy to work with. “It’s literally edible—every single material in the battery.”

Whitacre developed the basic science for Aquion’s devices at Carnegie Mellon University. The battery pairs a carbon anode with a sodium-based cathode. Water-based electrolytes shuttle ions between the two electrodes during charging and discharging, as opposed to solvent-based electrolytes.

When Whitacre arrived at CMU as a new professor, less than four years ago, he “wanted to do something different.” With assistance from students, he set out to identify materials that could be “massively used” and “incredibly scalable.” He focused on stationary applications, where–unlike mobile applications such as vehicles, electronics –lower energy density can be an acceptable trade-off for lower costs and longer life. Whitacre sought to “fail fast,” tossing out any materials or designs that “from a manufacturing stand point were not going to float.”

Whitacre began talking with David Wells of Kleiner Perkins in late 2007. “I was working in the lab, and told him I would get back to him when I had a ‘hit,’” said Whitacre. The hit ended up arriving in spring 2008, and soon Wells and Kleiner Perkins partner Bill Joy were interested enough in the technology to sponsor an incubator at Carnegie Mellon for Whitacre to develop it. With Wells and Joy, Whitacre began spinning a venture off-campus for commercializing aqueous sodium-ion technology a year later.

In late March, Kleiner chairman Ray Lane described the startup as “one of our most promising venture investments, transitioning from an early-stage technology development organization into a full-fledged product company.”

Taking the Heat (and Cold)

Importantly, Aquion says its battery can withstand a wide range of temperatures without losing storage capacity. That means the devices could be installed alongside a solar installation, for example, without sapping energy for air conditioning to keep the batteries cool. According to Wiley, Aquion has not observed any capacity fade during a year of testing with its sodium-ion cells in temperatures ranging from -10 degrees Celsius to 60 degrees Celsius.

Prototypes in the company’s lab and in the hands of third-party testers have shown more than 5,000 deep cycles with very little capacity fade, Wiley said. “As long as it’s maintained, it does not degrade.”

In fact, the only “natural limit” to the battery’s life, he added, “is if it’s sealed improperly.” Using hermetic sealing, the company expects its battery to last as long as 20-30 years. When cycling rates are slow enough (ideally charging and discharging over 8-20 hours), Whitacre said Aquion is seeing upwards of 90 percent efficiency in the lab.

Hurdles Ahead

Aquion would not be the first battery developer touting an energy storage breakthrough to encounter delays en route to commercialization. Wiley believes the startup faces the same challenge of “every science innovation company.” It has a novel chemistry and “no history,” and it’s targeting markets that are “slow-moving and resistant to technology change,” he said.

In addition, just selling into a utility-scale energy project can take as long as three years, said Wiley. For a venture-backed startup, being that far out from a major deal can be daunting (although Whitacre notes revenue in the near term could come from sales for smaller installations, like residential solar).

However, Aquion at this point seems to be moving with impressive speed. As of Monday, the company has grown to 35 employees, and it expects to employ more than twice that number by this time next year. Aquion plans to have products (built on a pilot line) in customers’ hands for evaluation this summer, and it aims to launch commercial products during the first quarter of 2012.

Money for Manufacturing

Aquion hopes to break ground on a 500 megawatt-hour manufacturing facility during the second quarter of 2012, and bring this facility online in 2013. That will depend on financing, of course.

To pay for the project, which will cost an estimated $75 million to $80 million, Aquion plans to seek public and private investment. Wiley said Aquion could be a good fit for the Department of Energy loan guarantee program, but “there’s no more money left.” If Congress funds the program again, he said, Aquion would apply for a loan guarantee.

In the meantime, Aquion hopes to close a $25 million to $30 million round of private capital this summer to kick-start the project.

Image courtesy of Suicine, Nanosolar and SolFocus.

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At a time when public funds are supporting the installation of thousands of charging stations nationwide by 2012, Ford Vehicle Electrification and Infrastructure Manager Mike Tinksey says the number of charge points isn’t what matters most. Rather, it’s about the approach to installing those stations, and the processes and programs in place to help knock down a range of barriers to adoption over time.

Barriers vary by location. For example, offering discounted electricity rates for “off-peak” or night-time charging will generally “really help electrification,” said Tinksey. San Francisco, a city Tinksey said is a clear leader among the top 25, has these so-called time-of-use rates in place. Other leading cities earned points because of similar plans moving through regulatory commissions. Yet a city like Seattle “needs it less,” he said, because abundant hydropower in the area helps keep electricity rates relatively low.

According to Tinksey, Ford gave the most weight in its ranking to factors related to private charging, such as the availability of online permit applications and assurance that inspections will be completed within a reasonable amount of time. The automaker expects most electric car drivers to charge at home for some time to come. (Update: This post was updated with a new image from Ford, the previous one had an error in it.)

For “urban dwellers who typically don’t have the same parking spot” each night, workplace charging at corporate campuses will offer an important alternative. Public and private fleets will generally rely on centralized “depot” charging, said Tinksey, while public charging will be used least frequently. The company wants to see “an urban planning approach” to public charging infrastructure, incorporating charge points and signage into the city landscape in a way that will maximize the use of each location.

Ford is not the first entity to assess EV readiness, and as Tinksey put it, “It’s pretty safe to say there’s considerable overlap” between this latest ranking and lists compiled by others in the industry, or the Rocky Mountain Institute’s Project Get Ready. So why did Ford go to the trouble of creating its own scoring matrix and list?

According to Tinksey, each manufacturer has different priorities and a unique perspective on what makes a city ready for electric vehicles, depending on their vehicle design and strategy. Because Ford has designed the Focus BEV (due out this year) to carry a “larger onboard charger” for charging at home in less than three hours, Tinksey says the company is “endorsing a much larger charging station,” as well as a larger gauge wire to accommodate it, and a separate outlet for easy diagnosis in the event of a malfunction.

When it comes to selecting initial launch markets, Tinksey added, Ford has considered confidential data (notably hybrid sales) it wouldn’t want to share with competitors. But there’s plenty of room — and need — for collaboration around charging stations. That’s not just so every plug will fit every car, but also so each automaker can display charge spot locations in vehicle navigation systems, said Tinksey. “We view the infrastructure piece as a non-competitive arena.”

At this point, Ford seems to see its list as a starting point, a possible catalyst for more cities to approach the automaker about improving their score. “Very few cities are completely EV-ready,” said Tinksey. “These are the ones on the right path.” Here’s the full list, in alphabetical order:

• Atlanta
• Austin, Texas
• Baltimore
• Boston
• Charlotte, N.C.
• Chicago
• Dallas
• Denver
• Detroit
• Hartford, Conn.
• Honolulu
• Houston
• Indianapolis
• Los Angeles
• New York
• Orlando, Fla.
• Phoenix
• Portland, Ore.
• Raleigh, N.C.
• Richmond, Va.
• Sacramento, Calif.
• San Diego
• San Francisco Bay Area
• Seattle
• Washington, D.C.

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Specifically, Freescale plans to begin marketing Fuji’s insulated-gate bipolar transistor, or IGBT, devices to its automotive customers. These devices convert alternating current (AC) control signals to the current needed to turn the motor. Or, as Fuji explains in this 2007 issue of the corporate technical journal, Fuji Electric Review, IGBT modules in hybrids are used to “convert the power generated by the engine into electrical energy, to charge and discharge a battery, and to drive the motor.”

Found in applications ranging from solar and wind power systems to robots, IGBTs are known for fast switching and high efficiency. This combination makes them “ideal,” Freescale says, for use in electric vehicle motors ranging from 20KW to 120KW. The company adds that with a more efficient IGBT, a hybrid or electric car will lose less power as wasted heat.

In a mid-range vehicle sold in the U.S., electronics make up 20-30 percent of the car’s cost, enabling stability control, navigation, transmission and engine management and many systems in between, Freescale Global Automotive Marketing Manager Steve Nelson said in an April 2010 interview for GigaOM Pro (subscription required). Hybrid vehicles, with their regenerative braking and start-stop systems designed to reduce fuel consumption, “have substantially higher semiconductor content compared to regular passenger cars,” according to the research firm Frost & Sullivan. The Volt, a plug-in hybrid car, uses 10 million lines of software code and 100 electronic controllers, and each Volt on the road has its own IP address.

All-electric vehicles will have even higher semiconductor content. As we explained over on GigaOM Pro last spring, electric cars rely on computerized systems to extend their range and manage complex battery packs made up of hundreds of lithium-ion cells, each of which needs monitoring. Thermal controls and other management systems help ensure efficient charging and longer life.

Fuji has made it a goal to expand use of the company’s IGBTs in hybrid and electric vehicles, as well as renewable energy, reaching beyond the industrial sector that currently makes up the bulk of its IGBT business. According to Freescale, IGBTs make up the largest segment of the market for electric vehicle power systems. They’re also the final piece of the puzzle for the Austin, Texas-based chipmaker’s EV system portfolio. The company says this latest deal with Fuji means it can now “offer all of the major electronic components of EV systems,” including microcontrollers, analog gate drivers, battery monitoring integrated circuits, power IGBTs, modeling and simulation tools, and software tools for motor control development.

To learn more about connected and electric cars come check out Green:Net on April 21 in San Francisco, and hear from speakers from GM’s Onstar, Ford, Tesla Motors, Coda Automotive, and startups like Virtual Vehicle (one of our 10 Big Ideas companies).

Image courtesy of Yutaka Tsutano.

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The IEA’s Clean Energy Progress Report, released ahead of an international meeting of government energy leaders this week in Abu Dhabi, notes that countries have spent $17 billion on renewable energy and energy efficiency research during the last 10 years — less than a third of the $56 billion directed to nuclear energy research. As much as $22 billion has gone toward fossil fuel research during the same period.

A marked shift occurred in 2009, when governments recognized “that clean energy is a driving force for economic recovery.” Public sector investments in energy research and development “rose to its highest level ever, eclipsing the previous high achieved during the oil crisis of the 1970s.” But as stimulus programs petered out, spending levels for 2010 fell to close to 2008 levels.

If countries are going to meet clean energy and carbon reduction targets (not to mention the larger goals of sustainable and affordable energy) they will need to adopt a longer view, says IEA. “Higher spending levels must be sustained over the long term and spending priorities need to shift,” the agency writes, away from nuclear and fossil fuels, and toward renewables and efficiency. Fossil fuels in 2009 received $312 billion in consumption subsidies, compared to $57 billion for renewable energy. Clean energy ministers, according to IEA, should provide incentives for private sector investments in energy projects, using tax credits, “innovative public/private partnerships,” and “market-creating mechanisms.”

IEA says fossil fuel subsidies ought to be “phased out,” and governments should establish a price for carbon emissions, which are two ideas that face significant obstacles in Washington. Today’s report comes on the heels of a 2012 budget proposal from House Republicans that promises to continue tax benefits for oil companies while cutting “government bureaucracies seeking to impose a job-destroying national energy tax,” as well as spending on “applied and commercial [energy] research or development projects best left to the private sector,” as Greenwire reports.

The IEA, meanwhile, emphasizes a need for cooperation between the public and private sectors, and for support that goes beyond tax breaks or grants. The agency urges governments to clear “non-economic barriers” for renewable energy research, development, demonstration and deployment, which can range from administrative burdens to the somewhat nebulous challenge of public acceptance and awareness. The agency also calls for governments to “facilitate the uptake of clean energy technologies into energy systems by supporting integration of technologies such as smart grids,” and to guarantee specific levels of support for different technologies that would decrease as they become more competitive.

The right combination of policies and could deliver nothing short of “a clean energy revolution,” says the IEA. For examples, the agency points to Denmark’s successful cultivation of biomass and wind since the 1980s, and to China’s leap to achieve three times the installed wind power capacity of India in just five years.

You can check out the full report here.

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Founded in early 2006 in Santa Cruz, Calif., Zero builds street and dirt bikes that run on lithium-ion batteries and sell for about $10,000. By 2007 it had found some high-profile customers, including Google founder Larry Page. The company is in the midst of a common phase in startup growth where new money comes in, old leadership exits, and seasoned executives step up to try and bring the company into the big leagues.

“It’s definitely a different company now,” Marketing VP Scot Harden said in an interview today. Investors have had a strategy “to make over the company for over a year now.” The overriding goal is to go from a niche electric bike startup to “a true, honest-to-god motorcycle company.” And that means building a team with “true, honest-to-god motorcycle experience.”

Chief Operating Officer Karl Wharton, who joined Zero in February after several years at Triumph Motorcycles, will take over direction of day-to-day operations while the company seeks a new CEO, a Zero spokesperson confirmed with us today. Although Banman will remain on the board of directors, he plans to “get some R&R and travel, and then do some part time work with non-profits,” according to Zero’s release.

Saiki started the company with his wife Lisa in their garage, having previously worked as an engineer for NASA and designed bike frames for Trek and Santa Cruz Bicycles. Banman, meanwhile, is one of many entrepreneurs, investors and executives who shifted gears from infotech to greentech over the last 5-10 years. (Check out our list of 25 who switched.) His background includes 15 years at Sun Microsystems, where he spent five years heading up Sun Microsystems, Japan. Later he became chief executive of the network firewall startup NetContinuum (acquired by Barracuda Networks in 2007). (See Saiki in our video clip below)

Both Banman and Saiki “were instrumental in convincing” private equity firm Invus Group to invest in Zero, Invus Managing Director Afalalo Guimaraes said in a statement on Tuesday. Invus became the company’s principal backer in 2008.

For 2011, said Harden, Zero is focused on “laying the foundation” for growth by establishing new engineering, manufacturing and marketing processes, and changing its approach to sales and distribution.

In the company’s early stages it “made sense” to use independent sales representatives, he said. But now Zero is working to establish distribution through “more traditional power sports dealers.” As part of that effort, it is “going through the process of getting licensed in every state,” and within 3-6 months Harden said Zero hopes to be ready for sales throughout the U.S. Next, the company plans to turn its attention to Europe.

Zero has sought to reinvent not only processes, but also the product itself. Previous models were basically “mountain bikes with electric motors in them. They lacked components that real motorcyclists would see right off the bat,” said Harden. Zero’s 2011 lineup includes five models: the Zero DS, Zero S, Zero XU, Zero MX and Zero X. Popular Mechanics reviewed the Zero DS and concluded that the company’s designs have “come a long way” in the last few years:

Their two-wheeled creations now feel less like glorified mountain bikes and more like motorcycles—well, perhaps junior motorcycles. They’ve increased battery capacity and reinforced suspension components, offering a product that’s more mature than it’s ever been.

At this point Zero is assembling about 30-40 bikes per week at its new Scotts Valley factory, which just a few weeks ago “was an empty warehouse,” said Harden. “We could easily do 60 to 70 a week once we get some rough edges smoothed out.” The company has about 70 employees, up from fewer than 50 around this time last year.

According to Pike Research, in a small market with seven or eight different manufacturers (including Brammo and Mission Motors), the bottom line for electric motorcycle manufacturers eyeing the U.S. market is whether they will prove “either profitable enough or specialized enough to be sustained over the next several years until demand grows to meet the growing supply.” So for all of Zero’s ambition, and its financial fuel for growth, it’s still an open question how much appetite Zero will be able to stoke for its electric motorcycles when the dust finally settles from its shakeup.

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The crash, which killed both pilots, occurred near Dubai on September 3, 2010. The Boeing 747-400F jumbo jet had departed Dubai International Airport on a cargo flight toward Cologne, Germany. At 32,000 feet, 22 minutes into the flight, the crew told air traffic control on the ground in Bahrain that warning systems on the cargo compartments indicated fire in the main deck, and that they needed to land as soon as possible.

The plane turned back to Dubai, and the crew donned goggles and oxygen masks. Less than five minutes after the fire alarm, according to the report, smoke entered the cockpit, ultimately engulfing it and obscuring flight instruments. Landing gear stopped functioning, and the jet flew over the Dubai runway. The 747 ended up crashing just south of the airport on a military installation.

Package details identified “many” shipments onboard the 747 as “lithium batteries and electronic equipment containing or packed with lithium batteries.” According to the investigators, at least three shipments contained lithium ion battery packs that met criteria for hazardous materials. They “should have been shipped as regulated materials….and thus should have appeared on the cargo manifest,” in accordance with international rules for the transportation of dangerous goods. (Technical instructions established by the International Civil Aviation Organization require all dangerous goods to be packaged, and generally also restrict the quantity per package based on the degree of hazard and the type of aircraft that will carry them.)

In other words, given the known risks for some of these battery packs, they should have been clearly marked for careful handling and special treatment. Yet the investigators found that ”there were no declared shipments of hazardous materials onboard the airplane.”

The stated purpose of the  preliminary report, released on Sunday by the United Arab Emirates’ General Civil Aviation Authority, is to “inform the aviation industry and the public of the general circumstances of the accident.” As the Wall Street Journal notes today, the report comes on the heels of the U.S. House of Representatives approving an aviation bill that includes “a provision effectively blocking adoption of tough new rules under consideration to crack down on air transport of lithium batteries.”

A coalition of battery manufacturers, cell phone companies, and other industry groups have opposed measures under consideration by the Obama administration for ensuring safer transport of lithium ion batteries.

The UAE investigators caution that information could still become available that would alter the report. But it’s clear at this point that lithium batteries, given the wrong combination of elements, can be dangerous at various stages in their production, shipment, use and disposal.

Late in 2009, battery recycler Toxco attributed multiple explosions and a major fire at its storage facility in Trail, British Columbia, to an internal short in one of the batteries in storage. In years past, reports and photos of laptop fires caused by overheated lithium batteries have also stoked these fears.

Just last year, in response to the deadly UPS crash near Dubai, the Federal Aviation Administration issued a safety alert on transporting lithium batteries in the cargo hold of an aircraft. The FAA advised airlines to request that customers identify bulk shipments of lithium batteries, and to stow these shipments in sections equipped with fire-suppression systems. “Lithium-ion cells are flammable and capable of self-ignition,” the agency wrote. There can be a number of triggers for self-ignition, such as “when a battery short circuits, is overcharged, is heated to extreme temperatures, is mishandled, or is otherwise defective.”

More than a few venture-backed battery companies see opportunity where lithium ion batteries fall short, and they’re building part of their business case around promises to deliver safer and more stable batteries for electric vehicles, and at higher energy densities (in general, the higher the energy density of lithium-ion batteries, the more volatile the technology).

Today’s EV manufacturers say they have largely kicked the safety challenge. Of course, they would also prefer not to talk about what can happen in the rare event of a so-called “thermal runaway” (lithium-ion batteries blow up), because they don’t want to scare potential owners in such a new market. Last fall, when Tesla Motors recalled 439 of its electric Roadsters to fix a problem with a cable that could start a fire, the company made a point of noting that the possible fire risk did not in this case involve the battery pack or power system.

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According to Ted Sullivan, an analyst with Lux Research, the DOE program was “incredibly helpful during the depths of the recession.” He cited comments from renewable energy executives that at one point a 5 percent spread existed between DOE debt and private debt for startups. “That’s huge.” But since private capital has become more available and “spreads have tightened,” he said, the program offers less of a boost.

NRG Energy CEO David Crane told us in a recent interview that in general “the government is requesting more and more conservative terms,” which may be comforting from the point of view of being a tax payer, but defeats the purpose of a program meant to provide debt financing where it wasn’t available from the private sector. “If the government’s terms are more onerous than the private sector then it becomes sort of, what’s the point?” said Crane. The DOE has not yet divulged specific terms in the company’s own bid for a loan guarantee to build new reactors in South Texas, said Crane.

“Given the continued uncertainty around the negotiation of acceptable terms and the final outcome, Suniva has decided to discontinue expending money, resources and time on the process at this time,” Suniva chief marketing officer Bryan Ashley told us in an email last week, while declining to discuss the decision beyond that. The Department of Energy is “doing the best it can under the guidelines of the program,” he added, but Suniva has nonetheless decided to “suspend participation in the loan guarantee program.” According to PV-Tech.org, the company spent about $750,000 on lawyers and consultants as part of its effort to secure the award.

Loan guarantees essentially serve as a promise by the government to make good on a loan if the company can’t. But the guarantee itself comes at a cost that is prompting some applicants to seek greener pastures.

Loan Guarantee Gripes

Back in December, DOE Loan Program director Jonathan Silver told us that it takes about six months “soup to nuts” to get applications processed and finalized. Throughout this process, fees are charged in three chunks. The first two — application and facility fees — depend on the size of the requested loan guarantee. The third, a maintenance fee, is payable each year during the construction, startup, commissioning and operation of the project, or as a lump sum up front when the deal closes. For the largest loan guarantee requests (over $500 million), application and facility fees alone could run up to $1.75 million, plus .50 percent of the guaranteed amount, as explained on the agency’s website. (Update: We added a decimal to the percent.)

Suniva is the latest–but not the first–company to grumble about terms in a possible loan guarantee deal. Two years into its effort to obtain a guarantee on some $7.5 billion in loans, in October 2010, Constellation Energy declared the proposed terms and conditions for the guarantee “unworkable.” Together with French energy giant EDF, through a joint venture called UniStar Nuclear Energy, Constellation had requested the loan guarantee to support construction of a new nuclear reactor at the Calvert Cliffs power plant in Southern Maryland.

In a letter to DOE officials, Michael Wallace, chairman of UniStar as well as vice chairman and chief operating officer for Constellation Energy, said the agency’s initial estimate for the “credit subsidy cost” (the expected long-term liability to the federal government when it issues the loan guarantee) was “shockingly high,” at 11.6 percent, or about $880 million. “Such a sum would clearly destroy the project’s economics (or the economics of any nuclear project for that matter), and was dramatically out of line with both our own and independent assessments of what the figure should reasonably be.”

Just a few months earlier, in July, Constellation executives had warned that “time is running out,” as the Baltimore Sun reported. “There is some level of frustration that we haven’t had an answer at this point,” Constellation Energy Group CEO Mayo A. Shattuck told the Sun. The company had previously hoped to secure a conditional commitment by the end of 2009.

Constellation ultimately pulled out of the project, selling its 50 percent stake in the joint venture to EDF for $140 million in October. A UniStar spokesperson told us that UniStar remains “engaged with DOE and believes that the Calvert Cliffs 3 project is a strong candidate to receive a conditional commitment for a loan guarantee.”

In total, the DOE has chosen 21 clean energy projects for loan guarantees and offered conditional commitments for $21 billion in loan guarantees. In December, Silver told us the loan program office had already issued term sheets for more projects than it actually has the budget to finance. (A term sheet details the terms and conditions under which the Energy Department may enter into a conditional commitment with the applicant.) Not every term sheet will lead to a final loan agreement, but according to Silver, there are “more solid projects in the queue than we have capital for.”

Greener Pastures

At the end of the day, the relative appeal and value of a DOE loan guarantee depends in part on what alternatives exist. Silver acknowledged in our December interview that “private capital markets have come back for less complex projects,” including some solar and wind developments. As a result, he said, we’ll see fewer small and medium-sized wind deals coming out of the loan guarantee program.

According to Lux Research analyst Matt Feinstein, many renewable energy financiers have concluded, “DOE guarantees are great for unproven technologies, and we want nothing to do with either of those things.”

Originally, new technologies were the central focus for the loan guarantee program. When Congress created it under the Energy Policy Act of 2005, section 1703 stipulated that awards would support only projects using “new or significantly improved” technologies. If a project involved technology that for more than five years had been installed at more than three other projects in a similar application within the U.S., it was considered “commercial,” and thus not eligible for these 1703 awards, as the firm Wilson Sonsini Goodrich & Rosati explains.

But then, in 2009, along came Section 1705. As part of the Recovery Act, Congress added a provision for loan guarantees supporting projects that needn’t use new or significantly improved technology, as long as they begin construction before the end of September 2011. And funds were appropriated to cover the credit subsidy cost.

For nuclear projects, loan guarantee recipients are required to pay the credit subsidy cost. Constellation and the Nuclear Energy Institute, an industry group, take issue with the formula for calculating this cost in the first place. “This fault will continue to hamper both nuclear energy and renewable energy project development – exactly the opposite intention of Congress when it passed the 2005 law,” argues NEI, which calls for an end to use of standard assumptions of risk in favor of project-specific assessments for credit subsidy costs.

Back in 2009, the New York Times quoted Constellation Executive Vice President James Connaughton calling for a 1 percent credit subsidy fee. The Union of Concerned Scientists, meanwhile, has argued that an “extremely poor track record on cost overruns” in the nuclear industry warrants much higher fees. Climate Progress argues that credit subsidy fees on nuclear loan guarantees should be at least 10 percent, and possibly as high as 30 percent.

In the wake of the disaster at Fukushima Daiichi, it will be much more difficult for the nuclear industry to make the case that these investments are low-risk. As Paul Fremont, managing director at Jeffries & Company, said in a Houston Chronicle article this month, however, the crisis in Japan “almost doesn’t change the fact that new nuclear looks to be a bad investment….Constellation (Energy) walked away and said keep your loan guarantee, it’s not economic to build.”

As for Suniva, the company says it has “made no decisions on potential sites, nor has it excluded any.” According to Ashley, Suniva hopes to “announce something early in Q2.” That’s just a couple months from now — the blink of an eye compared to the time it takes applications to move through the loan program pipeline.

Image courtesy of Suniva.

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The plan is to move the battery from “shot glass” scale, to hockey puck, to pizza, and eventually to ping-pong table-sized. Down the road, Sadoway tells us, he envisions possibly spinning off a company with some of his coworkers. Here are 15 questions and answers (excerpted and edited) from our interview with Sadoway:

Q. What are some of the benefits of using liquid metals for electrodes–why focus on this?

Sadoway: The thing that drew us to the use of liquid metals was a belief that a battery based on liquid metal electrodes would be stable, and scalable at an acceptably low cost for grid storage and renewables storage applications. That’s the number one problem with storage right now. We have batteries that can cycle and do all sorts of things that will meet the technical requirements of the application, but they’re far too costly.

We thought that by going to liquid metal, if you wanted to make a big battery, we would just have a large pool of liquid metal as opposed to thousands of individual cells, each of them the size of a soda can, for example. That difference in form factor is what we believe will allow us to reach the cost targets.

Q. What progress have you been able to make under the ARPA-E program?

Sadoway: The ARPA-E money allowed us to expand our operations to hire on more staff, students and post-docs, and to divide the technical challenges amongst a large team. We’ve looked at a lot of alloy systems that we couldn’t have without the ARPA-E funding. We’ve been able to address materials challenges, operation challenges — and by that I mean how you run one of these cells, what kind of charging currents, discharging currents one can sensibly expect — basic electrochemistry. We’ve been able to really move much more quickly than we could have before we got the ARPA-E funding.

Q. How do you envision this technology moving out of the lab and into a commercial product?

[Editor's note: Sadoway explained that his team is currently working in the lab with 1-amp-hour cells in order to screen various alloy combinations. In parallel, they have also designed and built a cell at 20 amp-hours.]

Sadoway: There’s the 1-amp cell, which I call the shot glass, the 20-amp cell which I call the hockey puck, and there’s going to be the 200-amp cell, which will be about the size of a pizza. Once we can show that as we move from the shot glass to the hockey puck to the pizza, that things hold, or if anything the performance improves, I think at that point we’re ready to build a big cell. That would be about the size of a ping-pong table.

Q. Would that be full-scale?

Sadoway: I don’t know just yet. We might get to the size of the ping-pong table and decide it would be better to have something maybe four times that. Or we may decide, based on the performance, that the ping-pong table is sort of the right cell size. Instead of making a bigger battery, you could put a whole bunch of ping-pong table sized batteries together. That’s all part of this question of how do you build large-scale storage capacity cheaply? I don’t know. This is something we’re going to learn by scaling as it comes.

Q. What is the timeline you’re expecting for scaling up?

Sadoway: The ARPA-E grant runs its course about two years from now. By the end of that grant, we need to know if we’ve got something here or not. Because building the cell the size of a ping-pong table is going to cost far more money than building a cell the size of a hockey puck. Somebody’s going to have to put up that money, and they’re going to want to do so with some reasonable assurance that the risk is a sensible risk and not a Hail Mary kind of last-minute pass down the field.

Q. So after two years, the idea would be to get further investment in order to set up more manufacturing capacity?

Sadoway: Yes. Well, I think there’s an intermediate state there. You want to take something off-campus. Because at that point you’re going to be building cells that are too big to be operated on campus.

Q. Would you spin off a company, as opposed to licensing out the technology?

Sadoway: I want to make sure the technology doesn’t stumble, and I think by spinning off a company with some of my coworkers here, that heightens the chances of success. You’ve got people who are really competent with the technology and who are eager to see it succeed. When you license it to an organization that doesn’t have a stake in what’s going on, I have concerns about the level of commitment and what lengths people are willing to go to make something succeed.

ARPA-E wants to see these technologies in the marketplace. Either you license the technology to some big company, which then says “we’re going to build these things and sell them,” or you see the technology move off campus into a startup company, which has the added incentive of trying to build a business out of nothing except an idea. That would be a powerful incentive.

Q. Are you devoting a lot of energy and focus now to the idea of building a business out of this?

Sadoway: We’re definitely considering. The ARPA-E folks know what our plans are in that regard, and they support us because they want to see the technology mature to the point where it’s actually available for people to use.

Q. If this technology lives up to its potential, what might the future look like? What could this enable?

Sadoway: It will enable grid-level storage in the extreme. There are a variety of applications. You could imagine batteries about the size of a small refrigerator in the basement of every home, where people can take energy off the grid in the wee hours of the morning, then draw upon that stored energy throughout the day and maybe even sell it back to the grid during peak demand times.

You could imagine batteries the size of a small building acting as a ballast at the level of a subdivision. You could imagine batteries near power plants, central facilities being able to draw down huge amounts of electric power and then push that back in the middle of the day. And that would mean you don’t have to build more power plants.

When it comes to renewables, these batteries could be the lifesaver, because wind and solar both suffer from the fact that they’re intermittent. Nobody wants intermittent power. They want power they can count on. That means we’ve got to figure out a way to allow wind and solar to become part of base load, and the enabling device is a battery. And so if this battery is scalable and at an acceptable price, then you can imagine it being used in conjunction with either a wind farm or a solar farm to give us the ability to store that energy and provide continuous electricity.

We haven’t invented a battery; we’ve invented a battery platform. There’s a suite of chemistries that all have the common feature of liquid metal on top, liquid metal on bottom, molten salt in between. But the identities of the two metal layers and the molten salt layer, those identities can vary over a wide range of chemistries.

Q. What do expect to be the earliest applications for this platform; what’s the lowest hanging fruit?

Sadoway: I’m thinking maybe the unit for a single-family home. Maybe, but I’m not sure.

Q. What makes that seem the most feasible?

Sadoway: It may be the smallest scalable size. I say we’d like to be able to store the grid, but I just don’t know if we can build something that big and do it right the first time. So I’d like to start with something smaller. If it’s too small, it won’t be self-heating, so I think the single-family home is probably the right application for starters.

Q. What’s your target for the cost, and how far is your team from reaching that goal?

Sadoway: It’s got to be below $100 per kilowatt-hour. The materials cost are down around $20 a kilowatt-hour. The question is, if we start with something that just costs $20 a kilowatt-hour for starters, can we put it all together and ship it at say around $50 and have some head room for profit? I don’t know the answer to that.

Q. Who do you see as your biggest competitors, and how do your costs compare?

Sadoway: There really are no competitors. People are starting to use a little bit of sodium sulfur in stationary installations, and sodium sulfur, as best we know, is up around $600 a kilowatt-hour. Lithium-ion is almost $800 to $1,000 a kilowatt-hour.

Those batteries are just far too expensive. But people are trying to work with them anyway in the hope that there’s some kind of unforeseen benefits and ultimately a cheap battery will come along, so let’s get the electrical engineering in place. [This way,] when the right battery comes along we’ll have enough operational experience to know how to use a battery in boosting the productivity of a power generating facility.

Q. Would you explain why this platform is meant exclusively for stationary applications?

Sadoway: Because you’ve got three liquid layers, you can’t have motion. If you put this in a car and the car accelerates, you could end up in a situation where the contents of the battery slosh back and forth. You would just get mechanical mixing of the two alloys and at that point you can’t draw current from it.

Q. What would happen if one of these batteries was disturbed in some way, during an earthquake for example?

Sadoway: You would lose the composition of the battery. The top metal might alloy with the bottom metal, but then you could restart the battery. That’s very different from trying to put it in a car or train or something. Sometimes you need to slam on the brakes, and you could cause the contents to flip over. You don’t want to lose the battery while you’re driving. It’s elevated temperature, too. I’m not sure you want a battery at 700 degrees in your car, so we’re focused on the stationary applications. It’s a huge market and it’s an unmet need right now, so if we can make it work there, that will be a big service to society.

Image courtesy of Simon Strangaard.

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President Obama at Smith's facility in Kansas City, Mo.

Is it a good time to be an electric truck maker? Well, the answer depends on who you ask.

According to Bryan Hansel, the chief executive of Smith Electric Vehicles U.S., the answer is a resounding yes. The company has seen demand grow “exponentially” over the last year, he told us in an interview recently, and along with government support, $58 million in new funding from private investors, and the recent uptick in oil prices, times have never been better.

But times are quite a bit tougher for another electric truck maker: Modec, based in Coventry, United Kingdom. The 7-year-old company reportedly has £40 million (about $64 million) in debt and has just entered administration – a process similar to bankruptcy filings in the U.S. According to representatives from Zolfo Cooper, the firm appointed to try and save Modec, the electric truck maker is experiencing “severe cashflow difficulties.” (Navistar and Modec have not responded to requests for comment as of this writing.)

Common Ground

The surprising thing is that Smith and Modec actually share some common ground. Both companies trace their roots to the UK and in recent years have moved into the U.S. Lord Jamie Borwick, former head of the London taxi maker Manganese Bronze, founded Modec in 2004 in Coventry. Then in 2009, the company formed a joint venture with Navistar to build electric delivery trucks for North, Central and South America. That same year, the UK’s Tanfield Group, which makes aerial work platforms, formed SEV U.S. in 2009 through its British electric vehicle unit, Smith Electric Vehicles UK.

Setting up shop stateside allowed the companies to benefit from government investments in electric vehicles under the Recovery Act. The U.S. Department of Energy awarded $32 million in stimulus grants for Smith to build 510 trucks with on-board telemetry systems, and $39.2 million for the Navistar-Modec EV Alliance to build electric trucks at an old RV plant in Elkhart, Indiana.

In addition, Smith and Modec have each delivered vehicles for major corporate fleets. For Modec that includes FedEx, UPS and supermarket giant Tesco. Smith counts Coca-Cola, Staples, Frito-Lay and AT&T among its customers. The companies’ trucks are even said to travel the same distance: 100 miles on a full charge.

Paths Diverge

Despite their similarities, some key differences have set the two electric truck makers on divergent paths. Hansel tells us he believes Modec missed the boat on some crucial design specifications in light of the U.K.’s driving license categories. The U.K. license requires vehicles weighing between 3.5 tonnes and 7.5 tonnes to have a commercial vehicle license, which adds cost for fleet operators. While Modec’s trucks weigh 5.5 tonnes, they offer a payload (2 tonnes) comparable to trucks in the lighter vehicle class, says Hansel. So buying a Modec truck essentially forces a customer to commit to not only go electric, but also to pay the extra cost of a driver carrying a commercial license, without getting a bigger payload, says Hansel.

Smith, on the other hand, offers a range of vehicle sizes and payload capacity, points out Hansel: “I think they had the wrong product. We’re more accessible to fit the general marketplace. If I’m going to pay for a commercial driver, I want more payload.”

Modec began producing vehicles in March 2007, after investing $30 million in research and development over five years, including a 6 million effort to make the final product at least 98 percent recyclable), according to the company’s website. Modec has sold just 400 of its electric vehicles, the Financial Times reports. UPS, which began testing a Modec van in early 2008, placed an order for 14 vehicles last month. Tesco, meanwhile, has not come back for more since its initial order of 15 Modec electric vans back in 2007, according to FT.

Smith, meanwhile, is gearing up for expansion. The company’s latest $58 million financing round will help fund its January 1 acquisition of Tanfield’s British electric vehicle unit, SEV UK (Tanfield retains a 49 percent stake in the combined company). Smith is now producing more than 40 trucks per month, according to Hansel. While the company is “predominately” focused on building its U.S. business and setting up decentralized, regional manufacturing, Smith is also “actively looking at new markets.”

The Future of Electric Trucks

Modec’s troubles do not bode well for electric truck makers. “You never want to see anyone fail. It’s not good for the industry,” said Hansel. Modec‘s position on the financial brink could have a silver lining, however, if it spurs more public investment in commercial EVs in the UK, suggested Hansel. “There’s not a lot of us out there,” he said, expressing hope that the UK will see a “big outcry” from people questioning, “Why would we let a company like this go?”

When it comes to government support and private investment, U.S. electric vehicle companies “definitely have an advantage,” compared to competitors across the pond, said J.D. Power and Associates powertrain analyst Michael Omotoso. Europeans are generally “happy with their diesel trucks and passenger cars,” and are less compelled than the U.S. to subsidize electric vehicles, he said, offering a note of skepticism that Modec’s fate will trigger a rush to subsidize the UK’s plug-in vehicle market. Given the state of the economy in the UK and other EU countries, Omotoso added, “I don’t think the atmosphere is right for a push towards EV subsidies in the car or truck market.”

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LiquidPiston

The son, an MIT-trained computer scientist named Alec Shkolnik, is LiquidPiston’s president and chief executive. The father, Nikolay Sholnik, is a physicist who previously worked in clean energy development and now serves as LiquidPiston’s chief technology officer. Over the last four years the pair have built a proof-of-concept engine, have put together a six-person team at their Bloomfield, Conn. headquarters, and have also attracted $6.5 million in venture capital, including $5 million announced last week.

LiquidPiston is one company among a raft of VC-backed startups working to make the internal combustion engine more efficient, often with a business plan that involves licensing technology rather than manufacturing engines. Venture capitalist Vinod Khosla has argued that these innovations could be implemented with much less cost compared to developing all-electric vehicles, while helping to reduce fuel consumption and emissions.

Like startup IRIS Engines, LiquidPiston is eying the nascent market for range-extending engines in plug-in vehicles (such as General Motors’ Chevy Volt) as an early opportunity for the company. LiquidPiston also plans to target auxiliary power units and generator sets as entry points to the commercial market. “That’s not to say we can’t scale up later,” said Shkolnik, but he recognizes that “automotive and trucks are very conservative markets.”

So far, LiquidPiston’s tale is one of persistence. Nikolay Shkolnik had been mulling thermodynamic efficiency, or the amount of work that an engine produces from a given amount of fuel, “for 30 years,” Alec Shkolnik said. But it wasn’t until Shkolnik began his PhD studies at MIT that he began to appreciate his father’s ideas. In 2004 they joined with a couple MBA candidates to vie for the $50,000 prize in MIT’s entrepreneurship competition. They won $10,000 as runners up in the competition. That was enough to cover LiquidPiston’s first patent application.

More importantly, the competition also introduced the Shkolniks to William Frezza, a partner at venture capital firm Adams Capital Management. As LiquidPiston’s mentor in the MIT competition, Frezza told Shkolnik that if the startup “every had a term sheet on the table,” he would take a look and weigh in on whether it was a good deal. By 2007, LiquidPiston did have a term sheet for a proposed investment by Northwater Capital. Frezza took a look, Shkolnik recalled, and decided that Adams Capital “wanted in.”

At a basic level, internal combustion engines generate movement through the rapid expansion of gas from burning fuel. LiquidPison’s engine, similar to a Diesel engine cycle, has fuel injected into the combustion chamber, where it ignites automatically. Rather than being allowed to immediately expand, however, the mixture is kept at constant volume as the fuel and gas burn, similar to the Otto cycle used in a conventional gas engine.

LiquidPiston claims that its mix-and-match approach eliminates inefficiency found in the traditional cycles. The company’s so-called High Efficiency Hybrid Cycle, can use both diesel and gas, and can deliver 74 percent thermodynamic efficiency, in theory. In practice, the team is hoping to achieve something “in the 50s,” said Shkolnik, compared to about 30 percent for many diesel engines and even less for gas engines.

Initially, said Shkolnik, the idea was to use liquid as the piston. “Every year the design got simpler and simpler,” he said, to the point where the company’s current design has only three moving parts. “We’re married to the thermodynamics,” Shkolnik said, “but not to any particular engine design.”

LiquidPiston says its latest prototype, called M2.5, is the first naturally aspirated (not turbocharged or supercharged) rotary engine to fire on both gasoline and diesel fuels. According to Alec Shkolnik, the 20-horsepower prototype weighs about 90 pounds. But it’s basically “a large block of steel” at this stage. With further development and focus on optimizing for less weight, Shkolnik said LiquidPiston aims to build a 40-horsepower diesel engine weighing just 75-90 pounds, compared to a typical engine weighing more than four times that amount.

With its latest financing round, LiquidPiston is now set to hunker down for about two years of engineering, according to Shkolnik. The company plans to build several more prototypes, hire four more people, and ready a design for delivery to potential strategic partners, taking its concept on the long journey from a theory played out in a block of steel to a competitive product.

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Getaround, along with a spate of competitors including RelayRides in San Francisco and Boston, SprideShare in San Francisco, WhipCar in the UK, and CityzenCar in France, fits into the larger trend of using the web to help people share “stuff.”

How to Get Around

Here’s how it’s supposed to work: To sign up as a driver in Getaround’s Beta launch, you enter some basic information on Getaround.com, including date of birth, gender, zip code, and whether you know how to drive a stick shift. To complete the signup, you log in to Getaround using your Facebook account, granting it access to some of your Facebook data. Before you can rent a car, Getaround also checks your driving record.

For the car owner, Getaround seeks to provide “a lot of flexibility and control” over who can rent the vehicle and how. “You can choose to share with one or two people, or the whole neighborhood,” said Jessica Scorpio, co-founder and business development chief for Getaround. “We’re the marketplace to make it happen.”

The owner of a Tesla Roadster Sport in the program, for example, only considers requests from drivers who are at least 30 years old, and she requires a minimum 2-hour rental period (at $25 per hour). Drivers can “bundle” requests for up to five cars for a given rental period, and then the car owner who responds first wins the gig. Owners set the rental rate, and Getaround takes a 30 percent cut of each transaction.

Requiring users to have a Facebook profile helps Getaround verify identity, said Scorpio, and also encourages good behavior. “If drivers know you have access to their real Facebook profile,” she said, “they’ll be more cautious.” Down the road, Getaround plans to integrate more closely with Facebook, enabling users to rent their vehicle only to existing network connections, for example.

Once a driver and owner have agreed to a rental, Getaround generates an email confirmation that will allow the driver to locate, honk, unlock the car using a smart phone, thanks to the “Carkit” device that owners can have installed on their vehicle for $200. Currently Getaround offers an app for the iPhone and it plans to release an Android app in the near future, but the browser on a smart phone can also do the job, according to Scorpio. Car owners who prefer to meet the renter and hand over keys in person can skip or delay the hardware installation.

Getaround accepts only vehicles from the 2000 model year or later with no more than 100,000 miles on the odometer, and the company hopes to recruit a large number of “green vehicles,” including more all-electric models. Scorpio said Getaround currently has 60 cars active throughout California, mainly in the San Francisco Bay Area and San Diego, where the University of California has provided funding for a small-scale trial project. At least 40 additional vehicles are moving through Getaround’s approval process. In all, Scorpio said “a few thousand” people have signed up to use Getaround.

While the 12-person company is focusing most of its efforts on proving its model in San Francisco, said Scorpio, Getaround can support peer-to-peer car sharing anywhere in California. Next year the ambitious startup hopes to expand across the country, and within five years it aims to go global.

Peer to Peer Car Sharing

It’s not mere coincidence that distributed car sharing services are sprouting up in California. In September legislation called AB 1871 passed in the state that paves the way for distributed or “peer-to-peer” car sharing programs. The legislation established rules for when a vehicle owner’s insurance policy stops applying, and when a commercial policy held by a service provider like Getaround kicks in.

Getaround “did as much as we could” to encourage passage of AB 1871, said Scorpio. But the company’s origins trace back to a 2009 group project at Singularity University’s 10-week, $25,000 summer program in Mountain View, Calif. Created by futurist Ray Kurzweil and X Prize chairman and CEO Peter Diamandis, Singularity University’s courses and programs focus on “exponentially growing technologies in order to address humanity’s grand challenges.”

The group’s concept for an iPhone app that facilitates “peer-to-peer” car-sharing won the “best money making app” category in a hackathon competition at Yahoo headquarters in July 2009. By September three of the team members — Scorpio, plus Sam Zaid and Director of Engineering Elliot Kroo — had officially founded the startup now known as Getaround.

Given its Silicon Valley roots, it’s no surprise that Getaround considers itself a technology company. But at the end of the day, Getaround’s success and growth will depend as much, if not more, on the company’s handling of low-tech issues like auto insurance, legislation and customer service. Streamlining the hardware aspect will be crucial for the company to achieve its vision of a global footprint.

As Spride Share co-founder Sunil Paul put it in an interview, Spride’s distributed car-sharing platform (which unlike Getaround, requires a key fob for entry) offers an example of a greentech venture that’s enabled by technology, yet fundamentally is not a technology play. “This is not going to be the whiz bang app, or the whiz bang anything,” he said. Rather, Spride’s success will hinge on catching policies up with an opportunity and capitalizing on what Paul sees as a general trend toward cars in “reasonably dense settings” becoming a shared resource.

Mobile Phone Tech As Enabler

During a rental session, Getaround tracks location data via users’ smart phones as well as the so-called Carkit installed on each vehicle. The company allows vehicle owners to set when and where other Getaround users can view the location of their car when it’s parked. And according to the company’s privacy terms, the vehicle owners also “may be able to see the location” of their car during the rental period. “Other than that,” says Getaround, “other users will not be able to see your movements….unless you choose to enable ride-sharing features.”

Might Getaround partner at some point with a smartphone-based ride-share service, such as Zimride, Carticipate, Avego or Daimler’s Car2gether? According to Scorpio, the company is interested in partnering with car sharing companies, municipal transportation departments, universities, and “P2P companies,” which she described as “anything that helps you share assets.”

According to Scorpio, Getaround does not actively monitor driving information in real time. Rather, she said the company is more interested in patterns (for example, if you speed during every rental session) and being able to track down a stolen vehicle. “We want to know if it’s going 100 miles an hour toward Mexico,” she explained.

Getaround has built a device called a Carkit that allows this data collection, and also makes keyless entry using the company’s iPhone app possible. The device, according to Scorpio, is “as non-invasive as it can get,” plugging in “very easily” to a car’s ODB-II (on-board diagnostics) port. Currently Getaround picks up vehicles from new members and brings them to professional mechanics for the Carkit installation. This is a clunky, costly step for a startup trying to build a web-based global service, so Getaround is working to simplify the process and hardware.

Scorpio expects 2011 to be a big year for the company. Getaround has raised seed funding from Redpoint Ventures and Powerset founder Barney Pell. The startup not hurting for cash at the moment, said Scorpio, but it plans to seek Series A financing this year.

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