What Utility Involvement in the Distributed Solar Market Means for the Future of the Solar Industry

For much of the last century, the typical electric utility model has involved siting large fossil-fuel or nuclear generating stations in remote locations. More recently, this "central station" model has included solar generation and other renewable fuel sources, such as the 354 megawatts (MW) of parabolic troughs dating from the late-80s in the Mojave (the SEGS plants), and Acciona's 64-MW Solar One plant commissioned last summer in Boulder City, Nevada. In fact, California utilities have about 3.5 gigawatts (GW) of contracts in place with central station solar projects, with much more to follow. There have also been major announcements of central station solar plants from Arizona to Florida.

What we have seen recently is entirely different. In March, Southern California Edison (SCE) submitted an application to the California Public Utilities Commission (CPUC) to install 250 to 500 MW of solar photovoltaics (PV), in projects of 1 to 3 MW on leased rooftops distributed throughout its service territory. If approved, the SCE application would allow SCE to own and rate-base the generating assets and sell the electricity to its customers. Not to be outdone, Duke Energy in North Carolina has announced that it wants to do US $100 million worth of distributed generation solar (about 16 to 20 MW), and more recently, San Diego Gas and Electric filed an application with the CPUC seeking approval of US $250 million of distributed solar (70 to 80 MW). That's a lot of solar, and it will be installed in a way that we are not used to seeing-not as large, central station plants, but as utility-owned generation sited at or near loads, providing wholesale power for utilities to sell to their customers. We hear rumblings from literally every corner of the country about other utilities considering similar moves. 

What does this new development mean for the solar industry? Some fear danger ahead. SCE made at least two claims in its application that rang alarm bells for solar advocates. First, SCE claimed that it can do solar much cheaper than it can be done by private companies using California Solar Initiative (CSI) incentives, California's $3 billion fund that provides incentives for utility customers to generate their own power with solar. Although SCE's projected costs (US $3.50/Watt installed) are better on a per-watt basis than the current average costs of systems going in with a CSI incentive, the ratepayer-funded CSI program provides only a relatively small portion of total project costs, and the bulk are covered by private investment. So, from a ratepayer perspective, SCE's claim is not correct.  With a fixed amount of ratepayer dollars, California can incentivize more solar development by providing a marginal incentive and leveraging private investment than by authorizing utilities to install and pay 100% of the cost.

Second, and more disturbingly, SCE suggested that since its ratepayers are going to bear the burden of paying for its proposed solar program, perhaps its ratepayers should be relieved of their responsibility for contributing to the incentive payments available under the CSI. That is a direct attack on the self-generation model supported by the CSI, and has some people wondering if SCE's application shouldn't more properly be viewed as a cynical calculation of the minimum amount of solar the utility needs to invest in to keep private solar companies under control-and from impacting their revenues. That's the pessimistic view. On the other hand, if the goal is to maximize the amount of solar generation on the grid, then massive utility investment could be a good thing.

We suggest that there is a third path available, where utility investment in solar as a wholesale generating resource at the distribution level will not only bring new solar onto the grid, but also provide an opportunity to carve out new market opportunities for all solar players.

Again, let's take the case of SCE. In its application, SCE justified its proposed investment by making strong arguments about the benefits ratepayers derive from installing photovoltaics inside of distribution networks-peak shaving, grid support, deferred transmission and distribution investment, reactive power, etc. The CPUC can only approve SCE's application if it believes that these ratepayer benefits are worth the cost-and this provides an opportunity for solar advocates to harness the same arguments and leverage SCE's request to open up the market opportunity up to everyone. Value is value-and if SCE is permitted to make solar investments on behalf of ratepayers, then other players that can provide the same value at a comparable or better cost can hardly be denied.

California's largest investor-owned utilities have argued that California's Renewable Portfolio Standard (RPS) already offers opportunities for small-scale, distributed solar generation. Now, it is true that systems of any size are in theory allowed to participate in the RPS. But as a practical matter, there have been very few wholesale power purchase agreements for delivery of solar power inside of distribution networks, and that is because the mechanism for purchasing wholesale power-responding to requests for proposals pursuant to the state's RPS and negotiating bilateral contracts-disadvantages smaller systems. The transaction costs associated with selling power from a 5-MW system are almost the same as those associated with selling power from a 500-MW system-and small project developers are finding it expensive and difficult to secure contracts. In other words, although California's RPS has produced contracts for large central station solar-as noted above, California utilities have about 3.5 GW of solar contracts in place-the RPS has not proven successful in facilitating a market for smaller distributed solar systems.

The remedy is to open up the market for small-scale distributed systems by developing a standard-offer contract for solar generation delivered inside of distribution networks, pursuant to RPS goals. Yep, that's right-a feed-in tariff. In California, a suite of solar advocates including Vote Solar, the Solar Alliance, the California Solar Energy Industry Association (CalSEIA), Green Volts, Recurrent Energy, and others have pursued this approach in several different venues: both in response to SCE's application to the CPUC, and through the CPUC's ongoing AB 1969 implementation proceeding.

If the effort is successful, what would the FIT price be? There are two basic approaches to setting a FIT: a cost-based approach and a value-based approach. Under a cost-based approach, the CPUC would consider the least-cost wholesale solar options. Certainly, SCE's projected price-point  would serve as one benchmark-and SCE thinks its average installed cost will be $3.50/W, and estimates its levelized cost of energy (LCOE) at around 30¢ per kWh (without the federal investment tax credit). On the other hand, First Solar is projecting that somewhere around 2010-2012 its cost of manufacturing will be between 65¢-70¢/W and that it will be able to profitably sell electricity in the U.S. between 8¢ and 10¢ per kWh. Finally, California is blessed with solar resources that allow a wide variety of solar technologies to compete, and multiple solar companies representing concentrating solar power, tracking PV and thin-film technologies already have several gigawatts of contracts. For concentrating solar, the Department of Energy estimates future price projections in the First Solar range. While contract prices are not available to the public, it can be reasonably assumed that they are well below SCE's 30¢/kWh. When the conversation turns to wholesale solar power, these are the benchmarks California policymakers would most likely consider under a cost-based scenario.

Under a value-based approach, the CPUC would start with the current Market Price Referent or MPR (the MPR is the energy and capacity value of a combined cycle gas turbine, 20-year LCOE-it's used as the benchmark for the cost of non-renewable generation), currently about 10¢ per kWh, and then look at adders to capture additional value. Currently, the CPUC includes a time-of-delivery adder to capture the value of providing electricity on peak, and a greenhouse gas adder to capture the anticipated future value from avoiding the cost of carbon emissions (though many of us argue that this additional value, roughly 1¢ per kWh, is unrealistically low). The CPUC could incorporate an additional adder to capture the value of siting generation inside of a distribution grid. In our joint filing before the CPUC, the solar advocates have suggested that the CPUC quantify all the benefits SCE cited to justify its application-peak shaving, grid support, deferred T&D investment, reactive power, etc-and incorporate that value into a locational-specfic adder.

We don't presume to predict how the CPUC will rule, but we believe it is a pretty compelling argument, made all the more palatable by mirroring both the arguments and value proposition put forward in SCE's application. An additional benefit of this approach is that it turns the typical conversation about solar's costs into a discussion of solar's value. A tariff developed under this approach wouldn't be considered a subsidy or incentive, but rather the equivalent of an avoided-cost valuation, and as a result, much more durable.

In either case (a cost-based approach or a value-based approach), feed-in tariff pricing (and RPS contract prices, for that matter) will eventually need to be set at a level below retail rates — if not at first iteration, then certainly in the future. It is axiomatic of successful business models that wholesale costs must be less than retail prices, and if solar is to come to scale as a meaningful wholesale generating resource, it too will have to fit within this paradigm. And in that event, a utility customer with a solar system on her roof will be better off net metering that electricity and using it herself. That way she will get retail value for all on-site generation as opposed to selling the electricity to a utility at a wholesale rate then buying back electricity from a utility at a higher retail rate. An additional benefit of this approach is that it allows homes and businesses to use solar to fix energy costs, hedge against future utility rate volatility, and reduce utility bills-a possible benefit of solar not harnessed under a wholesale purchasing model.

Policy debates often derail in a search for a single silver bullet policy that is envisioned as the only path forward. But it is important to keep in mind that unlike many other technologies, there are two possible markets for solar: a retail market, where generation serves on-site load and the price benchmark is retail electricity rates, and a wholesale market, in which generation is sold to utilities for further distribution and re-sale to utility customers. The path forward will be one of adding-and fine-tuning-the avenues for solar to express its value in all of the markets we have discussed. We see a future with an RPS for large, central station plants, a feed-in tariff for smaller systems (likely at the distribution level, where they have the most value) selling wholesale power, and net metering for systems that serve on-site load and reduce retail utility purchases for hosts.

In many ways, the most exciting impact of utility expansion into distributed generation markets is the opportunity it provides to open markets for private developers of wholesale solar. At the same time — and there is a minor irony here — as markets and policymakers prepare for the long-sought future where solar can deliver wholesale power at conventional wholesale prices, the counterintuitive result is an increased imperative on also securing the policies necessary for self-generation. To achieve this goal in the US, we must maintain continued support for net metering. But don't take our word for it. Germany has just established a self-generation program, too.

Adam Browning is executive director of Vote Solar. Kevin Fox is a partner with Keyes & Fox LLP.