America’s solar industry is hoping for an attractive post-2016 economic outlook by pushing to extend the federal Investment Tax Credit while strengthening state-level regulations and policies. But our regulatory priorities shouldn’t overlook an equally important economic issue: properly assessing the value of solar generation.
As federal and state incentives decline, our attention must turn to accurately pricing and valuing kilowatt-hour revenue from solar electricity sales. Multiple factors tally up to the true value of a solar kilowatt-hour, including the costs of moving solar across a transmission and distribution network, external environmental costs of fossil-fuel generation, and avoided capital for anticipated grid maintenance costs, to name a few.
Since solar is primarily developed as a distributed energy resource, externalized costs are lower than centralized generation, but they often aren’t reflected in pricing. This point is reflected in a recent analysis of 11 studies showing that rooftop solar’s median value was $0.17 cents per kilowatt-hour, while the average U.S. retail electricity rate was $0.12 cents per kilowatt-hour.
Pricing solar for the end consumer
Solar is priced differently for different customers, often at a discount from retail or generation rates, with distributed assets receiving retail rates and utility-scale assets priced at generation rates reflecting wholesale market pricing.
This works today, but in a post-ITC world with tighter profit margins, generation rates will be highly challenged and the $0.04 or $0.05 kilowatt-hour PPAs we’re seeing bid in 2015 will be increasingly difficult to make work in 2017.
Retail plus/minus rate structures, on the other hand, include many additional costs of getting electrons to the customer. Here, retail rates more accurately reflect what a residential, commercial, or industrial end user pays for on their bill. If solar projects can sell at a retail minus rate -- or better, reflecting external or avoided costs -- developers can lock in a higher kilowatt-hour revenue stream for assets and maintain solar’s economic competitiveness.
The spread of community solar and virtual net metering further complicates matters by creating a new category of solar development and value, and forces the question of how a solar kilowatt-hour will be priced to the purchasers of these electrons.
A looming ITC cliff and declining incentives creates even more pressure to get the value of solar right. So how do we get there from here?
Several states have tried assessing the value of solar and their experiences provide valuable lessons on how utilities, regulators, and solar developers can collaboratively determine the proper rate.
Maine may be a laggard in solar deployment, but it’s become a leader in valuing solar through collaboration. Maine’s Public Utilities Commission released a value-of-solar study earlier this year, determining solar’s actual value at $0.33 cents per kilowatt-hour.
As someone selling solar power, this seems high and would probably sound expensive to most customers who aren’t in Hawaii or Alaska. But the state PUC’s solar valuation process examined all economic values of the technology and should be emulated by other states. Maine’s PUC assessed avoided-capital costs and capacity investment, reduced financial risk, increased grid resiliency, and environmental benefits, resulting in a more accurate price closer to retail costs and benefits.
Maine is also exploring an entirely different valuation model by creating a central entity, or “Solar Standard Buyer” to aggregate smaller projects and monetize the value of solar generation. Larger purchasing entities allow developers to design across a larger footprint while employing cheaper financing and costs of construction, thus providing optimal consumer rates while locking in stable revenue streams.
Minnesota made headlines when it became the first state to set a value-of-solar tariff that included the value of delivered energy, generation and transmission capacity, transmission and distribution line losses, and environmental benefits. This process included all relevant parties and economic inputs, but arrived at a figure close to generation rates of roughly $0.12 cents per kilowatt-hour.
Any analysis will be judged by marketplace economics, and considering available costs of capital and construction alongside limits to individual asset sizing, the concerns may be correct -- but it’s still too early to determine if Minnesota got it right. Rising interest rates and increasing demand for low-emission power mean previously expected capacity may still be built, and the state could become a success story over time.
Tennessee Valley Authority
TVA determines electricity prices for 9 million customers in seven Southeastern states, many of which are just blossoming into solar markets. So its new "Distributed Generation-Integrated Value" report has major implications for valuing solar.
The report confirms distributed solar avoids a range of costs from burning coal or natural gas for electricity, but only looks at the value of TVA savings, not solar’s value to the region from reduced pollution or water use. As a result, TVA concluded the value of solar is $0.07 cents per kilowatt-hour, far below the $0.12 cents per kilowatt-hour it pays to solar owners for their excess output.
TVA’s analysis is a positive exercise in such a nascent regional solar market. But without including all true values of solar and external costs of fossil fuels, it underprices solar’s grid and regional benefits. This discrepancy is worth remembering as regulators start shaping solar policy in states like Georgia, Mississippi and Alabama.
While it boasts some of America’s best solar resources, Arizona represents a difficult example for policy rationalization and contentious fights between solar developers and incumbent utilities. At this point, neither side is focused on rational arguments about solar’s true value or how much capacity should be on the state’s grid.
When the state’s utilities and regulators approved adding poorly justified fees onto monthly bills of new solar customers, they created confrontation between industry parties and a policy quagmire. If Arizona had engaged in a collaborative process to understand the true value of adding solar to the grid, hosting and access costs could have been equitably and fairly priced in. But instead, solar development slowed and energy consumers lost out.
Fortunately, Arizona regulators are starting a full cost-benefit proceeding to determine solar’s value through a combination of cost-of-service and value-of-solar studies. The proceeding’s exact details have not been announced, but if it includes an impartial and comprehensive evaluation of the best way to allocate solar costs and benefits over rate structures, both sides should agree to honor the third-party determined methodology and allow the state’s solar market to move forward.
An accurate value of solar can work for all sides
America’s solar industry will be challenged to keep profitable projects coming on-line after the ITC cliff. Some of this slack will be picked up through the 40 percent solar system pricing decline GTM Research forecasts by 2020 and the use of efficient capital deployed across the solar project finance capital stack, but we’ll ultimately need market-driven conditions where developers and builders secure a minimum revenue stream derived from the true value of solar.
Setting a value of solar -- if done methodically and collaboratively with regulatory, utility, and solar market participants -- can yield a value that provides tailwinds behind current solar pricing trends. Rationalizing solar pricing to a retail environment should be a primary feature of America’s post-ITC solar market, and will support solar’s continued expansion using strong policy and economic logic.
Jesse Grossman is the CEO and co-founder of Soltage, a full-service renewable energy company that develops, finances, and operates solar energy projects across the United States.