Lynne Kiesling
Recently the New York Times ran a Sunday magazine article from Jeff Himmelman profiling some companies in the solar industry in the US. The main thrust of the article is that despite the industry’s technological and economic challenges, it’s starting to look like a better investment:
Two factors have hurt the industry’s growth. The first is abstract and well ingrained in the American psyche: the negative association of “green” technologies with inefficiency and idealistic, hippie-fueled impracticality. The second is concrete and recent: the sleek, vacant headquarters of Solyndra, the infamous federally subsidized solar-panel manufacturer that went bankrupt in 2011. The glassy campus sits just off the Nimitz Freeway, visible to commuters between San Francisco and Silicon Valley as they battle rush-hour traffic each morning, surreptitiously checking their phones.
Though the failure of Solyndra has dominated the political and social discourse around solar power, the reality of the industry — as evidenced by the enormous investments that companies like Google and Bank of America are making in residential solar power — is that it has rapidly become a smart, practical and profitable investment. Despite a lack of widespread acceptance, the market is growing and the competition is getting tight.
Why? According to Himmelman, financial innovation in the residential contracts that solar companies can enter into with residential and commercial customers in which the company retains ownership of the equipment:
The reason that the residential solar industry has begun to buck this general trend is because, instead of appealing to our heartstrings, it has begun to appeal to our checkbooks. The innovation that made this possible — selling solar services instead of solar panels — was pioneered in the commercial market by Jigar Shah. Though Shah was trained as a mechanical engineer, his most important bit of engineering was financial: in 2003, he started a company called SunEdison, which offered something called a solar-power purchase agreement (P.P.A.) to commercial customers.
Instead of having to pay all of the money for a solar installation up front and then having to carry that payment as a debt on their balance sheets, which no publicly traded company wants to do, companies like Whole Foods and Staples contracted with SunEdison to have solar panels put up at no initial cost. SunEdison then charged the companies for the amount of energy that the panels produced at a fixed rate for a period of 20 years — a rate that was less than what the companies were already paying the utilities, and that would ultimately save them even more money as energy prices inevitably rose over time. The bold stroke was that they were selling the power, not the hardware.
Another theme in the article is the regulatory, cultural, and business model obstacles that keep the regulated monopoly utilities from adapting to what may turn out to be a disruptive decentralized generation business model.
Having read that article, later that week it was interesting to read this Greentech guest commentary from David Rubin at PG&E, who sees a bright future for rooftop solar from the utility perspective … except for (1) the regulated retail rate, (2) the existing regulated net metering rules, and (3) regulatory rules limiting rate changes for some customers, which essentially embeds cross-subsidization in the regulated rate structure. Other than that, the future is bright for utilities providing rooftop solar!
Actually, although Rubin’s article reads like the PR essay that you’d expect, I think he does have a point about how regulatory rules introduce distortion, bias, and cross-subsidization into the market for the provision of rooftop solar services. Consider an alternative scenario in which regulated distribution monopolists like PG&E are precluded from offering retail services, including rooftop solar, and the competing firms that Himmelman profiled can compete both in how they structure the transactions (equipment purchase, lease, PPA, etc.) and in the prices they offer. One of Rubin’s complaints is that the regulated net metering rate reimburses the rooftop solar homeowner at the full regulated retail price per kilowatt hour, which over-compensates the homeowner for the market value of the electricity product. In a rivalrous market, competing solar services firms would experiment with different prices, perhaps, say, reimbursing the homeowner a fixed price based on a long-term contract, or a varying price based on the wholesale market spot price in the hours in which the homeowner puts power back into the grid. Then it’s up to the retailer to contract with the wires company for the wires charge for those customers — that’s the source of the regulated monopolist’s revenue stream, the wires charge, and it can and should be separated from the net metering transaction and contract.
The presence of the regulated monopolist in that retail market for rooftop solar services is a distortion in and of itself, in addition to the regulation-induced distortions that Rubin identified.
Another option is Austin Energy’s value of solar tariff (VOST), which takes into account the wires charge point and the fact that solar is usually being used most when the grid overall is under the most capacity stress. It’s still an administered, bureaucratically-determined price proxy for what could be more economically efficient separate retail solar and regulated wires charges. But it seems to be less distortionary than California’s net metering rate that Rubin is criticizing.
Utility rates are typically set based on estimated or actual sales in a “test year”. Utilities over-earn their allowable rates of return in years with higher total sales than the test year; and, under-earn their allowable rates of return in years with lower total sales than the test year. That earnings sensitivity is the result of regulated rate structures which collect only some fraction of the utilities’ fixed costs and their allowable return on rate base in the fixed portion of their rates (monthly service charge or wires charge) and require that the balance of the fixed costs and allowable return on rate base be recovered through the variable portion of the rate (the energy charge). Eliminating this distortion would go a long way to resolving many of the issues involved with on-site generation.
Until Solar solves that nasty problem of the sun going down every evening, it will always be fringe stuff for the inhabitants of cloud cuckoo land.
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I’ve often commented that it is not just the average cost of energy from renewable resources that is important; the value of the energy at the time and place it is generated is every bit as important. Famously, the average cost of wind generation is coming down to the point of flirting with that of fueled resources, but the value of the energy is far less because of its timing and times its location, especially if it is concentrated far from load centers. In support of Lynne’s point, photovoltaic generation at least generates during the day when energy values are high, and solar generation is more likely to be literally sitting on top of a consuming location.
However, it isn’t quite accurate to say that solar output corresponds with the peak of electrical consumption. The output of stationary solar panels on a cloudless day makes a nice zero-to-peak-to-zero curve, a concave-down parabola. The problem is that this parabola peaks prior to the electrical system peak. This means that fueled capacity (or storage) must be standing by to serve that peak, not to mention the standby needed to cover cloud-induced reductions in output. The alternative sources must ramp all the more rapidly to meet the load because the solar resources are declining.
We would sometimes speak of post-hydro load as the load that the fueled capacity “sees” and has to serve. Increasing penetration of solar and wind and other non-dispatchable resources complicate that picture, and I suspect that the dispatch of hydro resources, for those lucky enough to have them, will reoptimize toward the role of providing storage, backup, and late-peak generation. In bid-based markets this will happen quite naturally because the price will drop somewhat for the solar peak and rise a bit further afterwards. This will be exaggerated in markets lacking sufficient flexible hydro.