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.

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

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

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

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

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

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

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

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

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

Is the Photovoltaic Price Trend Sustainable?

It has been widely assumed among pundits and policy makers that the continued expansion of solar photovoltaic (PV) installations will drive down PV costs until the electricity they produce is competitive with conventional power sources without the need for subsidies. This belief is grounded in both recent PV cost trends and the well-known "experience curve" effect in manufacturing, in which costs tend to fall in proportion to cumulative output. However, anyone following the fortunes of big PV manufacturers like First Solar, SunPower, and China-based Suntech and Trina Solar might have reason to question this conventional wisdom. Their latest earnings reflect an industry stressed by softening demand in its core market in Europe and facing global overcapacity along the supply chain. This has me wondering how much of the recent decline in PV prices was due to the inherent progression of the technology, and how much to unsustainable market and competitive pressures.

The solar industry has made tremendous progress in the last several years. One indication of that is the price trend for PV in the annual "Tracking the Sun" survey from Lawrence Berkeley Lab. Between 2007 and 2010 the average cost of PV installed in the US fell by around 22%, with the largest portion of that drop occurring last year, followed by a further 11% decline in the first half of this year. Most of the reduction is attributable to the falling price of solar modules, rather than from the non-module, or "balance of system" costs (inverters, structures, installation, etc.) The fact that these declines coincided with an explosion of global PV capacity and output seems entirely consistent with expectations about the likely path of PV costs. Cumulative global PV capacity doubled twice in that interval, based on figures in the newly released Renewables 2011 Global Status report from REN21, so we'd expect to see strong experience-curve cost reductions.

The problem is that the industry dynamic behind this trend didn't much resemble the pristine image that the term "experience curve" evokes, of diligent engineers relentlessly focused on continuous improvement. Without diminishing the contribution of a lot of smart people, a key driver was the tough competition for market share between silicon-based PV, which had to overcome a major bottleneck in the supply of its primary raw material, polysilicon--the price for which spiked and subsequently collapsed--and cheaper but less efficient thin-film PV technologies relying on entirely different chemistries such as cadmium telluride and copper, indium, gallium and selenium.

A further hint that this wasn't quite the standard picture of predictable cost declines promoted by the PV industry is that PV prices appear to have been falling faster than actual costs, which in the case of at least some manufacturers are no longer dropping much at all. This can be inferred from the compression of gross margins reported by the leading firms, and in results that show profits stalling or falling even as volume grows. SunPower, the largest US silicon-based PV maker, reported a net loss for the third quarter of 2011, following a loss in Q2, and issued guidance forecasting a loss in 4Q, as well. We'll get a better picture of the health of the big China-based producers when they report 3Q earnings next week, but in the second quarter Suntech, the world's largest solar panel maker, reported a substantial loss, even though sales were up by a third from a year earlier, similar to results at rival JA Solar. In response Suntech and other Asian producers have apparently slowed planned expansions and reduced throughput at existing facilities, while US PV leader First Solar postponed its new factory in Vietnam.

It's a testament to the ingenuity of the big, established PV producers that they haven't all shared the fate of Solyndra after investing so much in expanding capacity ahead of demand--a major accomplishment in itself when demand has been growing by roughly 80% per year--only to see the market weaken due to a prolonged economic slump and a financial crisis in Europe that has undermined the ability of governments to provide generous subsidies for PV installations. Assumptions about the future cost trend of PV won't mean much if the industry doesn't emerge from its current difficulties as a collection of healthy firms with solid balance sheets and financial performance that investors find attractive. That will require better margins achieved by some combination of improved pricing power--implying better matching of capacity to demand--and cost reductions that don't just rely on further scale-up, which will become less fruitful as experience-curve benefits stretch out.

In other words, even if PV manufacturing costs continue to fall quickly for the next few years, it's less clear that the PV prices paid by project developers, businesses and consumers will follow suit, particularly if the current low margins lead to a global shakeout or consolidation among producers. Time will tell whether the solar industry can sustain the cost path that it's been on, or if future cost reductions will be more modest, in which case a number of scenarios for future PV penetration and renewables-based emissions reductions would require revision.

Will Solar Bankruptcies Be Different From Ethanol's?

The solar equipment business appears to be undergoing a shakeout, as three US solar firms have declared bankruptcy in the last few weeks. The most prominent of these was Solyndra, which was notable for its receipt of a $535 million federal loan guarantee. Joining Solyndra in bankruptcy filings were Massachusetts-based Evergreen Solar, which had been ailing for more than a year, and former Intel spin-off SpectraWatt. These failures raise many questions, but one that I haven't seen discussed much is whether these companies' assets will merely be absorbed into other, more successful solar firms, or effectively sold for scrap. I suspect the outcome will be quite different from that of the ethanol bankruptcies that followed the financial crisis.

Observers of these firms might be tempted to look to the ethanol industry for a model of how their bankruptcies could turn out. After all, ethanol represents another green industry--or at least one with green aspirations--the growth of which has also been entirely predicated on government subsidies and mandates. And in a pattern similar to the current situation in the global solar industry, US ethanol producers had invested aggressively in capacity expansion ahead of actual demand and were faced with high costs that couldn't be recovered in the marketplace, particularly when growth slowed and the price of their product fell during the aftermath of the financial crisis. The shakeout that ensued saw a number of ethanol producers, including one the largest, VeraSun, enter bankruptcy with the intention of reorganizing, though most ended up in liquidation. With the exception of a few small facilities, the vast majority of the ethanol plants that were idled by these business failures were acquired and restarted by larger, better-capitalized entities such as refiner Valero. The buyers paid $0.30-.50 on the dollar for the assets, and most now have profitable ethanol businesses, after the legacy cost overhang was removed.

Unlike ethanol, however, the output of solar manufacturing is anything but a commodity. Solar cells, modules and panels are differentiated products and still quite costly, compared to conventional energy sources. Solyndra's cylindrical modules were very different from FirstSolar's thin film modules and SunPower's crystalline silicon modules. It's much harder to envision the assets of Solyndra, Evergreen and other failing solar manufacturers being snapped up by more successful competitors, for several reasons. First, technology differences likely make the idled facilities of little use in the manufacturing processes of the survivors. The location of the capacity is also an issue, because the winning solar suppliers have mainly adopted a strategy of shifting manufacturing to Asia, where costs are lower and supply chains possibly better integrated. So I doubt there's a Valero waiting to put these plants and their employees back to work quickly, nor do current economic conditions give much hope of these facilities being quickly repurposed for some other product. I would like to be proved wrong about that.

Because of the low likelihood of recovering more than a tiny fraction of its investment in these companies, it's crucial that the Department of Energy and its Congressional overseers immediately assess the lessons from Solyndra and ensure that the DOE's Loan Program Office doesn't sow the seeds of further expensive failures in its rush to issue additional loan guarantees before the appropriations for them expire at the end of the month. And just to clear up some confusion in the terminology, although the government's role in Solyndra is usually described as a loan guarantee, suggesting some future, contingent loss if Solyndra doesn't make good on its debts, the actual lender in this case was the US Treasury's Federal Financing Bank. There is nothing contingent about the losses that taxpayers face in this bankruptcy. Those losses will be even harder to stomach if the firm's nearly new factory and production lines aren't put to some good use.

Misguided Incentives

Today's Wall St. Journal includes an interesting article on the emerging controversy concerning Germany's subsidies for solar power and their unintended consequences for that country's solar industry. It seems that solar incentives there have been so generous that they have discouraged German solar manufacturers from focusing on becoming competitive, rather than merely bigger. As a result, a growing share of the incentives is going to foreign firms that can sell these products cheaper. The hue and cry about this suggests that perhaps the original motivation behind the subsidy program, which not long ago was paying as much as a dollar per kilowatt-hour for power generated from solar panels, had at least as much to do with industrial policy as protecting the environment. In fact, Germany may have harmed the environment by wasting money on an impractical solution for such a cloudy place, when the same funds could have bought much greater emissions reductions in other areas of the economy. This should serve as a cautionary tale for those who are promoting similar incentives here, and for columnists--even those with a Nobel Prize in Economics--who argue that going green will be cheap. It won't be if we encourage the wrong technologies with bloated incentives.

At the heart of the solar debate in Germany is something called a "feed-in tariff" or FIT. It requires utilities to buy the output of qualifying solar power installations at a guaranteed fixed price well above the prevailing price in the power market. What's unique about the FIT compared to incentives such as the US federal renewable Production Tax Credit of 2.1 cents per kWh is that the funds to pay this green premium don't come from the government but from each utility's ratepayers. In other words, it is a mechanism for redistributing wealth from utility customers to the owners of solar installations, whether the affected ratepayers receive any solar power or not. The paradox of the FIT is that it makes the most sense when a technology is at its very earliest stages, producing so little energy that the cost to average utility customers is just pennies a month. The more solar power is produced and bought at inflated prices, the higher utility bills go and the less competitive the entire economy becomes.

So far, this just sounds like a political matter. Germany decided to nurture a large industry to build and install solar products and chose to pay for it by sending the bill to utility customers every month. That might even make a certain amount of practical sense, if not for two facts. First, the subsidy remains extravagantly generous, even after having been significantly reduced in recent years. It currently stands at a range of 34-43 €cent/kWh, depending on the kind of installation involved. At current exchange rates, that equates to $0.50-0.635/kWh. A recent study comparing levelized power costs for a variety of power technologies puts the cost of unsubsidized solar power between $0.26-.32 for the crystalline silicon photovoltaic cells that most German solar firms produce, based on an average capacity factor above 20%. After adjusting for Germany's much poorer solar intensity, the cost of solar power might rise to as much as $0.40/kWh, still well below the level of the FIT. This makes un-sunny Germany a remarkably attractive place to sell solar panels, and German companies haven't been the only ones to notice this. Suddenly the FIT looks like a means for Germans to subsidize Chinese solar firms, and that is not going down quite so well. More importantly for the success of Germany's solar industrial policy, the Journal indicates that the head of one of the country's largest solar module manufacturers is now arguing that German suppliers will not become efficient enough to compete in the global market for solar panels unless they are weaned off such generous support.

The high effective cost of the emissions reductions these subsidies are buying ought to be of equal concern to German policy makers. Even if you assume that each kWh of power generated by FIT-subsidized solar panels backs out a kWh generated from coal, the extra premium over the cost of other low-emission power sources such as wind is enormous. The difference in the average solar FIT vs. Germany's FIT for offshore wind of 13 €cent/kWh ($0.19/kWh) yields an effective cost of CO2 reduction from solar of about $400 per ton. That compares to a current price for emissions credits on the European Climate Exchange of around $19/ton CO2. The more you pay for reducing emissions, the less of them you can afford to reduce, even in a prosperous country like Germany.

At the end of the day, German politicians appear to have spent billions of Euros of German consumers' and businesses' money to build a solar industry that has thrived on the installation of high-costs solar panels in one of the least suitable countries for solar power imaginable, and that may not be able to compete internationally without drastic restructuring. This initiative has also failed dismally as climate policy, purchasing less than 5% of the emissions reductions that could have been bought had this money been spent on other, more cost-effective power technologies or on energy efficiency. The further irony is that much of the German investment in solar technology to date would have to be written off should it turn out that the current generation of technology can't be made cheaply enough under any circumstances, and crystalline silicon cells ultimately give way to cells relying on non-silicon thin-film techniques or novel nanotech-based designs. These are the perils of industrial policy masquerading as environmental policy, and it is hardly a winning case for the application of a similar FIT in the US.

The Sun or the Atom

It looks like we might finally see a solar power installation built on a large enough scale to enable meaningful comparisons between it and our current largest low-emission energy source, nuclear power. Tuesday's announcement by First Solar, Inc. that it had negotiated a memorandum of understanding with the Chinese government to install up to 2,000 MW of capacity in Inner Mongolia could take solar out of the world of rooftops and into direct competition with central power plants. It also provides an opportunity to assess this technology on a more consistent basis with our other full-scale energy options, even if it's clear that they ultimately serve somewhat different portions of the power market.

For years I've been reading suggestions for covering large swaths of desert with solar panels, and this looks like the largest realistic proposal so far, involving 25 square miles of desert near the city of Ordos, China. While the Desertec project in North Africa might ultimately be much bigger, that still looks like a much more remote possibility, at this point, though it was also clear from First Solar's press release that their project in China will start at a modest scale of 30 MW and work its way up from there. I can't help wondering if some of the project's later phases might be contingent on continuing to reduce the cost of solar power from today's levels. As I noted recently, even with solar module costs below $1/Watt for First Solar's thin-film technology, non-module costs can still push total installed costs above $4/W. That would put the Ordos project in roughly the same category as a new nuclear power plant in terms of total cost, not just notional output.

And while we're looking at output, we ought to consider how comparable an installation of 2,000 MW of solar panels anywhere on earth would really be to two coal-fired power plants, as was mentioned in several news reports on this story. Although I couldn't find data specifying the actual annual number of peak-sun hours for Ordos City, a glance at this solar irradiance map of China suggests that this location gets around 6 kW/m2/day, equal to 6 peak-sun hours per day, on average. That gives this project an average capacity factor of 0.25, which means that 2,000 MW of peak solar power would generate roughly the same amount of electricity annually as one 700 MW coal-fired power plant or a single 550 MW nuclear power plant, if there were such a thing. Perhaps this project's biggest benefit is in its scalability. Unlike a new nuke, which would probably take about as long to build, the Chinese won't need to wait until the project was completed in 2019 to get useful electricity from it. Each sub-project would stand on its own, and the first one could start generating within a year or two.

On balance, then, this huge solar project could produce as much peak power as a pair of nuclear power plants (or large coal-fired plants)--though still quite a bit less than either of those technologies over the course of a year--while costing about as much as one large nuclear reactor, even allowing for significant cost improvement between the time the first and last solar panels are installed. How useful such a facility will be is largely a function of whether that region of China has a greater need for lots of power when the sun happens to shine, or reliable power around the clock. I'm as pleased as anyone that China appears to be diversifying its energy mix away from coal, even to a modest degree, and there's certainly nothing about building such a facility that precludes expanding nuclear power, since in the long run the country is likely to need lots more of both. Still, in terms of bang for the buck and without factoring in what this one project might do to help bring down the cost of solar power elsewhere, it hardly seems an obvious choice.

Can Solar Compete?

I'm still catching up on articles I missed during my recent vacation. A pair of them from MIT's Technology Review caught my attention, because they seemed to contradict each other. In this month's briefing on low-carbon electricity technologies, TR concluded that while the cost of solar power has declined significantly, it remains too expensive to compete with electricity from fossil fuels. What's needed, they indicate, is better technology. And yet in another article earlier in August TR reported that industry experts at a recent symposium argued that current solar technology had already achieved the necessary cost reductions to compete with conventional energy, and would become more competitive as it scales up. If even MIT's signature technology journal can't agree who's right on this point, how in the world should policy makers decide whether the priority for solar should be further R&D or deployment of the technology we've already got?

There's little debate that solar power is one of the most promising energy options available to us, at least for eventually replacing much of the electricity we currently generate from fossil fuels. The basic science has been well-understood for a long time, either in terms of photovoltaic cells that produce power directly, or the use of concentrated solar radiation to generate steam for power. Unlike energy technologies such as biofuels from cellulose or algae, we don't have to wonder whether we can ever harness solar at a useful scale. Notwithstanding the serious challenges of transmission, distribution and storage, we know that if we covered a modest fraction of the surface area of the US with solar panels or concentrators, they could generate as much electricity as we currently consume, in contrast to the 2/100ths of a percent that it contributed last year. So while there's still plenty of room to improve the technology for turning sunlight into electricity, the main obstacle we encounter is cost. If solar isn't quite cheap enough today, could merely scaling up the existing technologies make it truly cost-competitive with power from coal and natural gas?

Answering that question is complicated by the way we typically compare different power generating technologies on the basis of their "capacity" costs--what it costs to manufacture and install or construct them. For many years the solar industry has pursued a goal based on reducing the manufacturing cost of a solar module below $1 per peak Watt, which would roughly match the installed cost of a gas turbine power plant and come in around half the cost of a coal-fired power plant. Last year a company called First Solar announced that it had reached that milestone. Unfortunately, however, module costs are only half the story. A solar installation requires more than the bare solar module, which converts sunlight into DC power. In fact, a recent study by the Lawrence Berkeley National Laboratory showed that in the last decade non-module costs had declined from around $6 per Watt to just under $4. So even if we extrapolate that trend to $3/W, the installed cost of the industry-leading solar technology would still be around $4/W, and many of the utility-scale solar projects I've been reading about come in around $5-6/W, a level that is far higher than the cost of a natural gas turbine.

Of course gas turbines have a big hidden cost, too, in the form of a perpetual fuel requirement. If you do the math, though, even with fuel cost included a gas turbine runs around half the cost of currently-deployed utility-scale solar power. In order to calculate this, you must make an assumption about how many hours per day the turbine will operate. For the purposes of an apples-to-apples comparison, I chose six hours, which is roughly the number of peak-sun-hours that a solar array would get in a prime location in the Southwest. At a conservative heat rate of 10,000 BTU/kWh, the comparable fuel consumption for each Watt over 20 years would be around 440,000 BTUs. That sounds like a lot, but at recent natural gas prices it would cost around $2. Add another buck for the capacity cost, and we're under $3/W on an undiscounted basis. (Assume that future gas prices inflate at the discount rate, and the NPV would match this figure.) Even adding a $20/ton charge for CO2 emissions would only bring that up by about $0.50/W, based on average emissions for gas-fired power plants. That ignores maintenance and other costs, but then I've ignored solar array maintenance and the gradual deterioration of solar cell output, as well.

In this simple comparison, at least, it appears that today's best solar technology is still somewhat more expensive than the fossil-based power it's likely to be displacing in a typical power grid, while most of the solar arrays now being installed reflect costs at least 40% higher than gas turbines, even after accounting for fuel and CO2 emissions. I'm skeptical that simple economies of scale beyond those already achieved could deliver that kind of improvement any time soon. That might explain the necessity for a 30% federal tax credit or grant on solar installations, along with generous state-level incentives and renewable portfolio standards--mandates on utilities for a targeted level of renewable power. Absent these, much of today's solar activity would probably grind to a halt.

In this light, answering the question we started with requires defining the basis on which we expect solar power to compete in the future. If we're satisfied with needing to apply a combination of incentives and utility mandates more or less indefinitely, in order to achieve the desired level of solar power deployment, then the current technology and its incremental evolution might be perfectly adequate to the task. If, on the other hand, we'd prefer to see solar and other renewables weaned off these subsidies and able to compete on a truly level playing field with conventional energy sources--after adjusting for emissions at market prices--then it looks like a lot more R&D is called for.