Energy Storage and the Cost of Going Off-Grid

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

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

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

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

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

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

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

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

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

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

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

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

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

Calibrating Solar's Growth Potential

• A new report from the International Energy Agency suggests the possibility of solar power becoming the world's largest electricity source by 2050.
• It is noteworthy that IEA thinks this could happen, but the growth rates required, let alone the policies necessary to support them, will be challenging to sustain.

In the wake of last month's UN Climate Summit in New York City, Monday's report from the International Energy Agency (IEA) on "How solar energy could be the largest source of electricity by mid-century" ought to be welcome news. At the same time, it conflicts with perceptions that some countries are already farther along than that. So IEA's indication of the feasibility of generating 26% of global electricity from solar energy by 2050 either looks quite ambitious or quite conservative, depending on your current perspective.

For me it always comes down to the numbers, without which it's impossible to grasp systems on the scale and complexity of global energy. IEA's high-solar roadmap--it's not a forecast--includes significant contributions from both solar photovoltaic power (PV) and solar thermal electricity (STE)--often referred to as concentrating solar power, or CSP--with the former making up 16% of global electricity at mid-century and the latter around 10%. As the detailed report from IEA indicates, achieving the headline result would require global installed PV capacity to grow 35-fold between 2013 and 2050, equivalent to an average of 124 Gigawatts (GW) per year of additions, peaking at "200 GW/yr between 2025 and 2040." That's a 6x increase in installations over last year.

To put that in a US electricity generation perspective, IEA projects that the US would have to hit one million GW-hours per year from PV--roughly what we currently get from natural gas power plants--by around 2035 to meet its share of the anticipated global solar buildup. US solar installations are on a record-setting pace of nearly 7 GW this year, but matching natural gas would require 120x growth in solar generation, or a sustained compound average growth rate over 25% for the next 20-plus years. That's not impossible, as recent PV growth has been even higher, but it won't be easy to continue indefinitely, especially without further improvements in the technology, and in energy storage.

The solar thermal portion of IEA's technology roadmap looks like a much tougher challenge. STE has been losing ground to PV lately, as the costs of the latter have fallen much faster than the former, for reasons that aren't hard to understand. Making PV modules cheaper and more efficient is analogous to improving computer chip manufacturing, while making STE cheaper and more efficient is more similar to manufacturing cheaper, more efficient cars or appliances.

One of the main reasons IEA appears to have concluded that STE could suddenly start competing with PV again is its inherent thermal energy storage capability, which enables STE to supply electricity after the sun has set. While I wouldn't discount that, it looked like a bigger benefit a few years ago, before electricity storage technology started to improve. Storage of all types is still expensive, which helps explain why fast-reacting natural gas power plants offer important synergies for integrating intermittent renewables like wind and solar power. However, it looks like a reasonable bet today that batteries and other non-mechanical energy storage technologies will improve faster than thermal storage in the decades ahead.

The upshot of all this is that getting to 16% of global electricity from PV by 2050 is a stretch, and the 10% contribution from STE looks like even more than a stretch. So how does that square with recent reports that Germany--hardly a sun-worshipper's paradise--got "half its energy from solar" for a few weeks this summer? A recent post on The Energy Collective does a better job of clarifying the significance of that than I could, providing links to German government data indicating that solar's average contribution in 2013 was just 4.5% of electricity--hence less than half that in terms of total energy consumption. The author extrapolates that at current rates of annual installations, it would take Germany nearly a century to get to 50% of its electricity from the sun.

Much can happen in 35 years that we wouldn't anticipate today. For now, solar PV looks like the energy technology to beat, in terms of low lifecycle greenhouse gas emissions and long-run cost trends. But whether it reaches the levels of market penetration the IEA's report suggests are possible, or tops out at less than 5% of global electricity supply, as their baseline scenario assumes, it must function within an energy mix that includes other technologies, such as fossil fuels, nuclear power and non-solar renewables. And that's true whether or not electric vehicles take off in a big way, which would significantly increase electricity demand and make the IEA's high-end solar targets even more difficult to reach.

Energy 2013: More Shifts Ahead?

• 2013 was an eventful year for energy, though perhaps with fewer earth-shaking implications for the future than in other recent years.
• Several developments concerning global oil production, when taken together, improved the odds of lower oil prices in the next several years.

Year-in-review posts have become standard fare for energy blogs; I've written my share in the past. However, while 2013 hardly lacked for interesting energy-related news and events to populate a top-ten list, most fell short of the potential to affect energy markets strongly for years to come.

For example, it is newsworthy that another year has passed without an indication of whether the White House will approve or reject the cross-border permit for the Keystone XL pipeline project. Yet the consequences of that decision are becoming less significant, at least in the reported view of Bakken shale pioneer Harold Hamm. That's due in large measure to the dramatic increase in the transportation of oil by rail, which should be on anyone's top-ten list. Nor is it clear that the EPA's proposal to scale back the Renewable Fuel Standard's (RFS) corn ethanol quota for 2014 will affect more than this year's fuel market, unlike pending Congressional legislation to reform the RFS.  California's adoption of an energy storage mandate for utilities is another notable event, but its long-term impact is contingent on the development of cost-effective storage technology and business models to enable much greater integration of renewable energy on the grid.

Instead of extending that list, I'd like to focus on three stories in which I see significant, related implications for oil markets. The first involves the temporary international agreement concerning Iran's pursuit of nuclear technology. Although relaxation of the sanctions limiting Iranian oil exports depends on a highly uncertain final agreement governing uranium enrichment, the  Arak reactor's plutonium potential, and a more intrusive inspections regime, the interim deal signals that around a million barrels per day of Iran's oil--and eventually more--could be back on the market in less than two years.

If that happens, it won't be because the Iranian government's repeated assurances of its aversion to nuclear weapons have suddenly become credible, but because most of the permanent members of the UN Security Council plus Germany--the "P5 + 1" negotiating with Iran--are tiring of the protracted confrontation and understandably have no appetite to address this in the same way that the collapsing UN sanctions regime for Iraq was resolved in 2003.

Next consider the stunning reversal of the Mexican government's 75-year-old nationalization of oil and gas. As a result of the reforms just enacted by their congress and ratified by a majority of Mexico's states, the state oil company Pemex will be run along more commercial lines, and foreign firms will be allowed to partner with Pemex in developing the country's large untapped hydrocarbon resources. If the terms prove attractive for international energy firms, the result will move North America even closer to net energy independence. Meanwhile the Transboundary Hydrocarbon Agreement between the US and Mexico that was just passed by the US Congress will simplify energy development that straddles the border.

Mexico's potential could be even more significant for oil markets than an unconstrained Iran. The former's production has declined by 24% since 2004--a loss of 900,000 bbl/day-- mainly due to limited reinvestment. Foreign investment can help to restore that output, but the upside potential is much bigger. Pemex has barely scratched the surface of its deepwater resources in the Gulf. Its proven and contingent reserves are estimated at 45 billion barrels, while US estimates put Mexico's shale oil, or "tight oil" resources at 13 billion barrels, slightly more than the country's proved conventional reserves. (Shale gas could exceed 500 trillion cubic feet.)

Mexico's oil output has grown dramatically before. In the decade following the Arab Oil Embargo of 1973 production increased from 500,000 bbl/day to around 3 million. A similar performance seems possible again from a higher starting point, but it's unlikely to happen overnight. As Dan Yergen pointed out in a recent Wall St. Journal op-ed, "exploration and development could take another five to 10 years" beyond the first bid rounds.

And that brings us to Saudi Arabia's options for dealing with a shifting market that will include projected US crude oil output of 9.6 million bbl/day by 2016, the recovery and growth of Iraqi production, possible exports from Canada to Asia, Mexico's potential, and the eventual return of full Iranian exports. Whether or not this wave of new or restored production will be sufficient to replace production declines elsewhere, it must undermine OPEC's control of pricing in this decade. In that light, it's hard to ignore reported indications that Saudi Arabia might abandon its role of swing producer, particularly when it comes to unilateral output cuts to balance new non-OPEC supplies.

Haven't we seen this movie before? After a dozen years of high prices and tight markets OPEC steadily lost market share in the 1980s as new fields in Alaska, Mexico and the North Sea came online. That trend culminated in Saudi Arabia's 1986 "netback pricing" decision, linking the price of its oil to the value of its customers' refined petroleum products. Following the price collapse that policy helped precipitate,  oil prices took 18 years to reach $30/bbl again, by which time the dollar had lost a third of its value.

I doubt we're in for anything that dramatic. Back then, most demand growth came from the developed countries of the OECD, rather than from the expanding middle classes of developing Asia and the Middle East itself. Moreover, today's new production has higher costs--up to $70-80 per barrel--ruling out a return to $20 oil. With many serious geopolitical risks still in play, an oil-price price correction or extended soft market seems likelier than another price collapse. In the meantime, if we're seeking $20 oil, we already have it in the form of US shale gas that averaged the equivalent of $21.64/bbl last year. And that's the early, odds-on favorite for the energy story of the decade.

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

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

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

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

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

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

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

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

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

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

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

How Many More Solyndras?

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

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

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

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

Storing Wind Power in Gasoline

I just read an intriguing article by the inventor of a scheme for using the energy in off-peak wind power to recycle waste CO2 into hydrocarbon fuels like gasoline or diesel. If it works, it would be a clever way to finesse the energy storage challenge that has hampered wider application of intermittent energy sources such as wind, and it appears to rely on largely proven chemistry and technology. Like so many other novel energy ideas I encounter, it almost sounds too good to be true. In this case determining whether it is or isn't depends less on the technology involved than on an assessment of the markets that the developer's company, Doty Energy, would have to tap for its inputs. In a nutshell, I question whether it's possible to base a new fuels industry on the assumption that off-peak wind power will always remain dirt cheap.

The basic opportunity on which Dr. Doty's "Windfuels" concept seeks to capitalize is that because wind turbines don't necessarily generate power when the grid needs it, and because it's currently expensive to store electricity unless you have a hydropower dam and the right topography handy, much of the off-peak wind power the grid can accept is sold for a song, while some is "curtailed", or rejected by the grid entirely. With a substantial supply of wind power costing just a penny per kilowatt-hour (kWh), it might be possible to convert that excess wind energy into chemicals, effectively storing it in the form of gasoline, diesel or jet fuel.

The process described on the company's website marries three distinct segments, including electrolytic generation of hydrogen--an off-the-shelf item--Fischer-Tropsch synthesis of hydrocarbons--proven in a variety of applications since before World War II--and the conversion of CO2 and hydrogen into synthesis gas using the reverse of the standard water-gas shift reaction that is in wide use in the chemical and refining industry. The company must prove that it can master the latter step and integrate these components successfully into a scheme that is ultimately driven by an intermittent and unreliable energy source, off-peak wind generation. The operational challenges that presents might be surmounted by means of pressurized hydrogen storage, as suggested in the flow diagram provided in a company presentation, but the economic obstacles involved seem less straightforward.

Assuming this process could be made to work effectively and efficiently, its inputs and intermediate steps raise questions about the cost and value of these streams. The biggest probably relates to the long-term availability of cheap off-peak wind power itself. Based on cumulative capacity and output, the average capacity factor of US wind generation in 2009 was around 27%. I don't know how much of that was off-peak, but it was probably less than half. While Doty Energy sees an opportunity to arbitrage between wind power at 1¢/kWh and gasoline that currently wholesales for an energy-equivalent price of 7¢/kWh, developers of electrical energy storage systems see an arbitrage opportunity between cheap off-peak power (from any source) and peak power markets in excess of 20¢/kWh, or occasionally much more. Even if Doty's process, which it claims is 50% efficient overall, worked as well as energy storage technologies such as compressed air energy storage (CAES), it seems likely that the future competition for that off-peak wind power from various applications would drive up its price. The economics of CAES might not be harmed much by having to buy off-peak power at 3¢/kWh, but that would be a deal-breaker for Windfuels, unless gasoline prices were much higher than today's.

Then there's the question of how to value that hydrogen, once you've made it. Even with plenty of 1¢ wind power to generate the H2, its value is what it could be sold for. The vast majority of hydrogen today is produced from natural gas, and it can be worth as much as $10/kg at a commercial hydrogen station. That's the energy equivalent of 30¢/kWh. If electrolysis of off-peak wind power is such a good source of hydrogen, why not just stop there and sell the hydrogen into its large existing commercial and industrial market, without having to build the rest of the conversion hardware for making hydrocarbons?

Perhaps my receptiveness to the Windfuels concept was affected by the inventor's arguments slamming practically all other energy alternatives besides his, including biofuels (conventional, cellulosic and algae-based), hydrogen, solar power (ground-based PV, solar thermal and space solar power), nuclear (fission and fusion), unconventional hydrocarbons and electric vehicles as impractical or uneconomic. I suppose that might be an effective way to drum up financing in some quarters. Yet while I've expressed skepticism or reservations about certain of these approaches myself, it seems absurd to set up an untried process as the only viable alternative to our current energy sources, particularly for transportation energy. The good news is that Doty Energy has the same opportunity to prove its concept in the marketplace of ideas and financing as the thousands of others that have emerged in the last few years. Making it through all those gates and hurdles will be the only test of the viability of Windfuels that really matters.

Storing Sunlight

An article in MIT's Technology Review on a new liquid battery technology got me rethinking an assumption I've been making for some time concerning the synergy between renewable energy and better batteries. The article's author makes a similar assumption, suggesting that with bigger, cheaper batteries, electricity from solar power might be supplied around the clock. But while this new battery, consisting of a combination of molten metals and molten salts, looks clever, I'm not sure it would make sense to use it to store solar electricity in the way the author envisions. The main impediment to the large-scale application of solar power today is not so much its cyclical nature--which storage can address--but its high cost per generated kilowatt-hour, compared to other technologies. The power likeliest to be stored for later delivery won't be the most expensive, but the cheapest.

My focus here is not on the rooftop solar panels being installed on homes. Storage isn't an issue in most such cases, unless you're in a remote location or insist on grid independence. Net metering--the ability to sell excess electricity back to the grid and buy power from it when the sun isn't shining--typically offers a much better deal for homeowners than batteries, by effectively using the grid as free storage. Since rooftop solar has the inherent advantage of competing with retail, rather than wholesale electricity prices, I'm more interested in the utility-scale solar installations springing up all over. These compete directly with the output of gas-fired simple-cycle turbines, the standard "peaking" power plant technology. Utility solar projects currently cost around $6,000 per installed kilowatt (kW) based on several recent project announcements turned up by a quick web search. Even with the 30% solar investment tax credit and a site in a sunny location, such as Florida, that results in an amortized cost of generation of roughly $0.25 per kilowatt-hour (kWh), based on a 20-year life and 6% interest rate. That might be acceptable for peak demand periods, such as hot, sunny afternoons, but it doesn't compare very well to off-peak wholesale power costs from other technologies, including wind and gas turbines, let alone coal or nuclear power.

Nor is the cost per kWh the only barrier solar power must overcome, in order to be competitive around the clock, even if the cost of storing it were negligible--which is certainly not the case today. The capital involved in amassing enough capacity to serve a given market 24/7 is much higher for utility-scale solar power than for other technologies because solar's capacity factors, reflecting the fraction of time when these facilities are available and generating peak power, often average below 20%. In the Florida example above, a solar array would receive an average amount of sunlight equivalent to 4-4.5 hours of peak sun per day. That equates to a capacity factor between 17-19%. Replacing the baseload power from a 500 MW coal-fired power plant operating at an average capacity factor of 80% would require 2,200 MW of solar power plus a commensurate amount of storage. So at $6,000/kW, a solar power plant capable of generating as many kWhs as a $1.5 B coal-fired plant would cost $13.2 B, excluding the cost of delivering power when needed, instead of when the sun happens to be shining. (It also implies a very high cost per ton for the avoided CO2 emissions.)

With current solar technology, the entire proposition of storing lots of solar power looks impractical and unnecessary. Using large-scale, cheap storage--of whatever technology, whether batteries, compressed air, or pumped water--to time-shift renewable power makes much more sense when applied to lower-cost generation from wind power, the normal output of which also has a much poorer overlap with typical daily and seasonal power demand curves than solar power. In most markets, solar power should be going after the premium associated with the afternoon demand peak. Solar needs little or no storage for that, other than to buffer the effects of cloudiness or extend its output by an hour or two on either side of its natural output peaks. That looks easiest with solar thermal technology, which stores energy as heat, rather than electricity. As a result, developers of new batteries should not pin their hopes on the growth of a market for storing solar power.

An Old Idea Made New

A friend sent me a link to a story about some companies using a twist on a very old technology to reduce their office air conditioning bills. Several facilities have installed large vats of water that they freeze every night and then use the melting ice to cool the air during the day--apparently including the former White Plains, NY headquarters of Texaco, now owned by Morgan Stanley. The article goes on to suggest that the system actually improves cooling efficiency, besides shifting the cooling load to nighttime hours when power is cheaper. If this proves attractive enough, it could have important implications for the way we use energy.

Air conditioning is a major component of electricity demand, and one of the largest segments that fluctuates with the seasons. Its use is still growing, worldwide. Higher incomes and increasing urbanization are responsible, and the result is not just higher energy consumption, but a reshaping of power generation capacity to meet the daily and annual cyclicality of demand created by people's natural desire to stay cool. If ice cooling became popular, it would help to even out at least the daily peaks and valleys, while reducing the absolute magnitude of the summer/winter difference. That would allow a country's electrical needs to be met with less--and potentially less polluting--capacity.

This idea might even dampen one of the feedback mechanisms of climate change. A warmer climate requires more air conditioning, using more power, which in turn generates more of the emissions that contribute to climate change. Even if ice cooling could cut peak electricity demand by only 10%, that could be significant.

While installing giant ice vats might not be feasible for everyone, the economics should compare favorably with battery storage, or schemes to generate hydrogen at night and run it through fuel cells to meet peak demand. Ultimately, this is about storing power, efficiently, which is one of the keys to making the best use of intermittent sources of renewable energy, such as wind power.