A new, more rigorous method for calculating the value of solar could give regulators the tools they need to resolve the growing tension between utilities and rooftop solar builders.

“Calculated values will differ from one utility to the next,” declares A Regulator’s Guidebook: Calculating the Benefits and Costs of Distributed Solar Generation, from the Interstate Renewable Energy Council (IREC), but “the approach used to calculate the benefits and costs of distributed solar generation should be uniform.”

The paper was written for IREC by attorney Jason B. Keyes, a veteran of the utility industry, and former utility executive and Texas regulator Karl Rabago. It takes lessons learned from sixteen distributed solar generation valuations summarized in a recent Rocky Mountain Institute study to construct “a standardized valuation methodology” for settling disputes over the net metering incentive that is in place in 43 states.

The need became clear earlier this year, when, co-author Karl Rabago noted, a solar cost-benefit study from Arizona’s biggest utility showed a net solar value of less than 4 cents per kilowatt-hour, while a solar industry study conducted in the same general timeframe found a value in excess of 21 cents per kilowatt-hour.

The paper focuses on three key conclusions about distributed solar generation (DSG) costs and benefits.

1. “DSG primarily offsets combined-cycle natural gas facilities, which should be reflected in avoided energy costs.”

Because solar is usually available during periods of peak demand, it competes with the marginal unit of energy, Rabago said. “Solar is not dispatchable, but it does have the peak availability coincidence.”

2. “DSG installations are predictable and should be included in utility forecasts of capacity needs, so DSG should be credited with a capacity value upon interconnection.”

“If solar comes on when the utility needs capacity because demand is high,” Rabago explained, “it has a higher capacity value.” Utilities also sometimes say DSG shouldn’t get capacity credit because their resource plan shows no capacity need until 2018, Rabago added. “That avoided-cost thinking ignores the fact that DSG is already meeting peak demand. Every single day, the grid gets capacity from rooftop solar. More might defer the need for new capacity to beyond 2018. Pushing it a year would save millions.”

3. “The societal benefits of DSG policies, such as job growth, health benefits and environmental benefits, should be included in valuations, as these were typically among the reasons for policy enactment in the first place.”

“One side says the externalities are too complicated to quantify,” explained Rabago, “and the solar industry talks about the importance of those benefits. The goal is economically efficient decisions. Capturing all those costs and benefits is important, because when we leave them out, we know we make a distorted decision about how much of the resource to acquire.”

Utilities’ resources were once typically acquired “in the hundreds or thousands of megawatts,” Rabago said. “Some utilities have difficulty quantifying a small distributed resource. This paper will give them tools to move beyond the old avoided-cost model.”

The paper is intended to add “analytical rigor to the discussions about net metering,” Rabago said. Utilities are worried about a cost shift from solar owners to non-solar ratepayers due to net metering “because they have an obligation to serve all ratepayers without unjust discrimination,” he explained.  “But a lot of utilities use the simplistic formulation that everything but the energy value or market price must be a subsidy.”

And they have concluded the subsidy is flowing to solar customers from everyone else, Rabago said.

“The point of this solar analysis is to show that not all kilowatt-hours are the same,” he explained. “The generic brown kilowatt-hour that comes in at the market price and a kilowatt-hour of clean, waterproof, climate-proof energy from a rooftop are different. One goes right to work from the rooftop to the house, and one has to be transmitted over big parts of the system.”

And the difference is crucial, he added. “For the work done, every kilowatt-hour is the same. But they don’t have the same costs and benefits and only after their relative worth is established can the solar customer’s compensation be evaluated.”

Rabago referenced studies showing that retail electricity's value is less than the value of solar. “If those numbers are right, it is fair to argue that solar customers are subsidizing everyone else, because they are not getting more than retail even though they are providing benefits that exceed retail.”

Benefits, according to the paper, must include:

  • Energy
  • System losses
  • Generation capacity
  • Transmission and distribution capacity
  • Grid support services
  • The financial factors of fuel price hedge and market price response
  • The security factors affecting reliability and resiliency 
  • Carbon and other environmental factors
  • The implications of economic development

According to the report, costs must:

  • Determine whether lost revenue or utility costs are the basis
  • Assume administrative costs will be automated
  • Not include interconnection costs that DSG customers pay
  • Not overestimate future penetration levels

“This is a regulators' guide because regulators are the ones who are supposed to sort out the competing views,” Rabago said. “One of the most important things a regulator can do is ask good questions. That induces evidence and arguments that inform the record and lead to better decisions. This paper, I hope, as a former regulator, will enable regulators to ask more and better questions about the value of solar and solar programs.”

Tags: avoided cost, capacity credit, ccgt, ct, dsg, energy value, externalities, fuel price hedge, grid support, interconnection costs, irec, market price, natural gas, net metering, regulators