Solar has reached competitive pricing with traditional generation resources in at least 20 states, but how utilities and regulators structure rates will determine if that number grows or shrinks in years to come.
With solar-friendly policies, the number of states with solar at grid parity could double by the end of the decade, or dwindle to only a few, according to a new study from GTM Research.
“The biggest factor in whether there are 42 states or two states at grid parity in 2020 is whether and how much solar installation cost declines outpace any downward changes in the solar value proposition through NEM and rate reforms,” said Cory Honeyman, senior solar analyst at GTM and lead author of the study "U.S. Residential Solar Economic Outlook 2016-2020," released earlier this month.
Solar boom, solar savings
Residential solar growth numbers continue to be striking, the study noted, as it is the fastest growing sector of the solar market. Since 2013, residential solar has grown over 50% year-on-year. “Between 2010 and Q3 2015, quarterly capacity additions have increased tenfold,” the study added. “By Q1 2016, the cumulative number of U.S. homeowners with rooftop solar will eclipse the 1-million mark.”
This growth calls for a better understanding of solar “grid parity,” which is “the minimum threshold of economic attractiveness where the levelized cost of energy (LCOE) dips below a customer’s electricity bill savings in year 1 of system life,” according to the study.
Typical parity calculations compare the LCOE to the customer’s blended retail electricity rate. But in reality, solar savings “are rarely equal to retail electricity prices,” the study says. A more accurate understanding of solar savings should include how rate design and net metering reform can and will impact and complicate residential solar economics.
But without regulators’ understanding of the intricacies of solar savings, the path to grid parity might be harder to attain, the paper reported. If every state’s major utility added the monthly $50 fixed charge for solar owners that has been proposed in several states already, only Hawaii and California would still be at parity.
There is a great deal of geographic and economic diversity within the states that reached grid parity,with rate reform initiatives equally wide-ranging, Honeyman noted. “Seven of the top ten residential solar markets have considered or approved some kind of net metering reform.”
Many of the proposed reforms have been reduced or rejected. Yet the trend suggests that the major national solar installers “should think about diversifying geographically as a hedge against being exposed in states that have a high chance of rolling back the solar value proposition with net metering or rate reforms,” Honeyman said.
Different reforms, different consequences
Monthly fixed charges currently rank as the “greatest policy risk” that could undermine residential solar economics, according to the study.
Depending on the added charges and rate changes, “the fixed charge is the one kind of reform that residential solar has no response to,” Honeyman said. Only Hawaii’s high electricity rates and certain ratepayer categories in California keep those states competitive with a $50/month fixed charge.
Rooftop solar users can address demand charges by exporting to the grid during peak demand for the higher value credit, he said. Another response is adding battery storage so the solar energy-generated electricity can be consumed onsite when grid electricity is most expensive.
Reducing the export credit can either drive solar owners to smaller system sizes focused on self-supply or they strengthen the case for solar plus storage, he added.
The fixed charge, however, “is a blunt instrument for cost recovery that doesn’t provide much incentive to make DERs a smarter asset and benefit to the grid,” Honeyman said.
About 15 states stay competitive in 2016 with a $10 fixed charge, according to the study. Almost as many are competitive with a $5/kW demand charge, which would be about $25/month for the average residential solar owner. Even with a $15/kW demand charge, which is about $75/month, the numbers will pencil in about eight states.
GTM said that a 10% cut in the net metering credit will affect no more than one or two states. Even a 50% reduction will not affect more than six states.
GTM foresees rates evolving away from flat and consumption-based tiered structures. Designing time-of-use (TOU) rates, “will play an even greater role in shaping residential solar economics by setting price signals that either align with or deviate from peak PV production,” according to the study.
TOU rates could either be a benefit or a challenge to residential solar economics, Honeyman said. If a utility’s peak demand and highest rates align with solar production, residential solar economics can remain viable or at least be an incentive to encourage adding storage.
“Homeowners are going to consume 40% to 60% of the solar generated electricity from their systems,” Honeyman said. “TOU will be a driver to self-consume.”
If a customer can get to that onsite consumption of 60%, or more, the risk of revisions that change the value of solar exports is reduced, he added. “That’s important.”
South Carolina Electric and Gas has introduced a rate structure that increases the solar value proposition 10% and the solar industry there is growing. But, Honeyman said, if a utility has too much daytime solar, its peak demand and highest prices may fall very late in the day. In that case, TOU rates may erode solar economics.
In the long run, he said, solar will become a mainstream power source and more states will look like Hawaii. In response, regulators and utilities are likely to use wholesale market prices to set the net metering credit. TOU rates will then be more likely to help solar stay competitive with electricity from the utility if peak solar production aligns with peak demand periods.
“As rooftop solar grows, its value may hinge on pairing it with battery storage or any complimentary DER that can shift production either by export or onsite use to match peak electricity price periods,” Honeyman said.
Something for every utility to watch
The experience of DTE Energy, the electricity provider for Detroit and Michigan's largest utility, demonstrates the potential impact utility policies can have on solar economics, according to the study.
With the current retail rate net metering credit, “Michigan is very close to parity. With additional utility level rebate opportunities there, the economics already make sense for some customers,” Honeyman said. “We expect the market to heat up between now and 2020, especially with the ITC extension.”
Michigan would “without question” reach parity in those conditions by 2020, he said. But if utilities and regulators impose the kinds of reforms proposed or instituted elsewhere, “it is by no means a done deal that it would get there.”
As it stands,the fixed charge represents 15% of a typical solar-owning DTE customer’s bill. This means solar can offset at most about 80% of the customer’s bill, the study found. As a result, “the LCOE for a 5-kWdc system installed in 2016 is actually 7%, not 3% higher than gross solar savings in year 1.”
This utility level analysis is “something for utilities and utility customers in every state to watch,” Honeyman said. For customers of utilities like PG&E in California, National Grid in Massachusetts, HECO in Hawaii, PSEG in New Jersey, and Arizona Public Service in Arizona, solar is at present economically attractive, he said. "But rate reforms could be pivotal."
Volumetric charges make up less than 80% of a customer’s annual electricity bill in only three states, the study reports. That is why, generally, the residential solar value proposition has remained viable while the commercial-industrial (C&I) solar market, where rates are already higher with fixed and demand charges, is stalled.
For C&I customers, whose bills may be 50% or more made up of demand and fixed charges, “the economics become even thinner and it becomes a tougher decision,” Honeyman said.
Revisions to rates and net metering rules could make the residential solar decision similarly difficult and "set solar back years,” he said. “With more aggressive fixed charges, the economics become completely untenable.”
The choices ahead
Utilities considering new fixed or demand charges or rollbacks to compensation for exported solar or the rollout of TOU rates should notice early responses from customers and regulators, though it’s likely too early for a widespread precedent to emerge,Honeyman said.
Hawaii’s solar market is expected to struggle back to equilibrium in the wake of net metering reforms imposed last fall. But Nevada’s market is a little different and might not be able to rebound as quickly.
California regulators took a different tack in January and decided to preserve the net metering credit with the understanding they will revisit the policy in 2019.
Each debate has unique factors, including commission politics and the politics of the debate between utilities and advocates, Honeyman said.
“But there has been a lot of opposition to fixed charges and most utilities have not had a lot of success getting regulators to impose them,” he said. “Utilities should consider putting forward more sophisticated proposals instead of blunt instrument fixed charges.”
A better goal, Honeyman suggested, might be “rate structures with price signals that drive residential solar and DER owners to deliver power at periods of peak electricity demand so they become grid assets.”