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.

Marrying Gas and Renewables

A Turkish developer recently announced that it would build a new power plant using technology from GE that matches wind and solar generation to the output of a highly responsive natural gas turbine, all integrated in one package with the hardware and software to mesh its output with the grid. GE is apparently calling this scheme IRCC, for "integrated renewables combined cycle", adding yet another acronym to our growing list of energy choices. This development looks interesting from a technical perspective, but also for what it suggests about GE's view of the future market for generating equipment and power delivery.

The International Energy Agency's "Golden Age of Natural Gas" scenario remains a question mark, rather than a certainty, but if gas is to serve as the key fuel for bridging between our high-emission present and the low-emission future, then we're likely to see more installations like the one in Turkey emphasizing the synergies between gas and renewables, rather than the tough competition gas is giving renewables in some markets. The IRCC--not to be confused with an IGCC or the IPCC--is interesting because it goes well beyond the idea of using gas-fired power plants to back up the naturally variable output of wind farms and utility-scale solar arrays.

The IRCC concept is built around a new combined cycle gas turbine, the Flex-Efficiency 50, with an impressive capability to ramp up and down, as needed, with minimal loss of either efficiency or emissions performance. And thanks to the energy technology portfolio the company has built up over the last decade, GE is able to offer one-stop shopping with GE wind turbines and a solar thermal generating module from eSolar, in which GE has recently invested. The gas turbine/solar thermal hybridization looks especially useful in maximizing plant efficiency and incorporating solar thermal power into the grid at the lowest possible cost, by avoiding the expense of an extra steam turbine and generator. If all this works as advertised, the grid operator shouldn't know or care whether the power being dispatched was generated using wind, sun, or gas.

Before you confuse this posting for a GE ad, I should note that at least in the configuration chosen for the Turkish site most of the power from this integrated plant would still be generated by the gas turbine, which has 10 times the peak output of the concentrated solar power module and more than 20 times the rated power of the small wind farm tied into it. By the time you account for the capability of the gas turbine to run 24/7 when necessary, compared to typical capacity factors of 25-40% for wind and up to 25% for solar, the proportion of the IRCC's annual megawatt-hours generated from gas could exceed 95%. Nor is GE the only firm bringing turbines like this to market. So it's an impressive step, though more of an incremental than revolutionary one. However, with its inherent flexibility, I wouldn't be surprised if this type of gas turbine could effectively integrate a much larger quantity of renewable generation on the grid outside the IRCC's fence, particularly after the operating experience of the first few installations has been absorbed.

GE's timing in introducing its IRCC concept could prove especially apt. Not only does the Flex-Efficiency turbine look useful for helping to meet California's aggressive new 33% renewable electricity target, but the 50-cycle version featured in GE's marketing materials--likely minus the solar thermal module--could be just what Germany needs, now that its government has begun to come to grips with the quantity of new fossil generation that's going to be required to make up for the post-Fukushima accelerated retirement of its nuclear power plants.

Renewable Energy: Horses for Courses

It has become nearly impossible to keep track of all the major wind and solar projects underway at any point in time. Considering that I can recall when a month's worth of project announcements could be counted on the fingers of one hand, that's a sign of the tremendous progress in renewable energy over the last decade. Today, the projects that I notice tend to involve either novel technologies, or companies or locations in which I'm interested, such as the new rooftop solar thermal installation on the convention center of St. Paul, Minnesota, not far from where my in-laws live. I probably wouldn't have even paid attention to this one, if the eye-popping price tag hadn't included a cool million in federal stimulus funding. As I read on, it quickly became clear from the figures included in the news story that it requires more imagination than I possess to view this project as a good investment for taxpayers.

In putting the project's $2 million cost into perspective it's important to understand the distinction between solar thermal collectors and solar photovoltaic panels (PV). The former capture and transfer heat, while the latter turn sunlight into electricity, which is much more valuable. A 1 Megawatt (MW) PV installation would cost quite a lot more than $2 million, but that doesn't make this installation's price a bargain. Assessing that depends on the annual energy savings and resulting avoided fuel purchases. From the project description and the emissions reductions cited in the article it was possible to work out the expected annual energy savings involved, which appeared to have been something of a mystery to the facility spokesperson quoted. A MW of solar thermal equates to 3.4 million BTUs per hour, although the River Centre's rooftop clearly wouldn't generate that on a 24/7 basis even in a much sunnier location than the Twin Cities. However, the 900,000 pounds a year of avoided CO2 are unambiguous. At 117 lb. CO2 per million BTUs of pipeline gas, that equates to saving 7.7 billion BTUs of gas a year. And at last year's average commercial natural gas price for the state, that works out to an annual avoided cost of $58,000.

When I convert that stream of future energy savings into its net present value over 25 years, even with fairly generous assumptions on the cost of capital and future natural gas inflation, it is worth about what the convention center alone paid for it, or around $1 million, ignoring the impact of the two years it apparently took to build it. So in the parlance of corporate project evaluation, the federal officials who approved the RiverCentre's solar roof for that stimulus grant destroyed about a million dollars of taxpayer value when they decided to fund a solar thermal project in such a northern location with relatively low annual peak-sun hours. What were they thinking?

Well, the DOE official present at the facility's unveiling offered a clue by means of a hockey quote--always a good call in Minnesota. "We want to be where the puck is going to be, not where it is now." I would translate that as their funding of this project constituting an investment in bringing down the cost of future solar installations. Unfortunately, that would be much more credible if the installation in question involved leading-edge thin film or multi-junction concentrating PV technology, for which performance and cost have been improving steadily, if not quite in Moore's Law fashion. But this is solar hot water. The thermodynamics and heat-transfer considerations for such an application haven't changed since I was in engineering school, even if the packaging has improved. There's only so much heat to be captured and transferred, especially in a place with an average January temperature of 22°F.

When I'm critical of projects such as this one, it's not out of a sense that all renewable energy is impractical or ineffective. Renewables are earning a place in our energy mix, and they will become even more important in the years ahead. However, because they depend on harnessing diffuse energy sources in real time, rather than disgorging geologically stored energy in the manner of fossil fuels, it matters greatly where we put them. That's why I've been relentless in my criticism of Germany's overly-generous feed-in tariffs, and I see rooftop solar thermal in St. Paul in much the same light. Installing renewable energy devices in locations with poor resources, particularly using taxpayer money--or in this case money borrowed on the taxpayers' behalf--reinforces all the worst stereotypes about renewable energy as a boondoggle. The British have an expression that seems apt here, "horses for courses": run the right horse for each racecourse. If someone wants to bet their own money on rooftop solar in Minnesota, they do so with my blessing. But where my tax money is involved--and perhaps I'm especially sensitive about that this time of the year--I insist that it be done someplace that affords the technology a decent chance of earning an economic return, rather than just feel-good, PR value.