2015 has been a sunny year for the solar industry so far, but some stormclouds are beginning to appear on the horizon, according to a recent report.
Despite strong projected growth in residential and utility-scale solar for the upcoming year, industry leaders are increasingly questioning why the business community remains hesitant. And power companies are also uncertain over their future roles.
“There are still a lot more questions than answers in non-residential solar,” said Cory Honeyman, Senior Solar Markets analyst at GTM Research and lead author of the Q2 2015 U.S. Solar Market Insight Report published by GTM and the Solar Energy Industries Association (SEIA).
“That is the segment we are watching to understand what the biggest bottlenecks are and what solutions are being tried to make that market rebound," he said.
The most recent numbers
Installation numbers for residential and utility-scale solar for the second quarter showed solid growth compared to the same period last year.
Installation of residential photovoltaic (PV) solar in Q2 2015 was up 6% over the previous quarter, and up 70% over the same time in 2014.
Utility-scale PV installation increased by 729 MW in Q2 2015, comprising about 52% of all the capacity installed in the quarter. And it was the ninth consecutive quarter that the utility-scale segment of the market grew by about half a gigawatt.
But non-residential PV, however, was down 20% from the previous quarter, and down 33% from 2014's Q2. Installation for the quarter dropped below 200 MW, the least activity since 2011. The sector's numbers may be somewhat compromised because corporate procurements — an increasingly important factor in U.S. renewables growth — are included in the utility-scale solar category.
While much of the current 1 GW corporate solar pipeline is in projects larger than 50 MW, the report notes, that capacity could be included in the non-residential total.
Rate design depresses non-residential solar growth
Some of the difficulties of the non-residential segment could be explained in the report’s assessment of the solar policy landscape, Honeyman said.
At least 39 states have seen utilities consider or "approved or implemented various reforms to net energy metering (NEM) or rate design relevant to solar compensation,” he said. Until now, the most common reform has been proposals for a solar customer fixed charge. But regulators have rejected or reduced the vast majority of those proposals.
More recently, utilities are proposing the kind of peak demand charges for residential solar customers now primarily imposed on utilities’ non-residential commercial-industrial customers. “That is a type of reform that is increasingly going to be on the table,” Honeyman said.
At the same time, upfront incentives (UFI) and performance-based incentives (PBI) from states and utilities are being phased out in proportion to the growth of solar penetration.
That decline in solar incentives has tracked a “roughly 70% to 120%” drop in installed costs for solar, according to a recent Lawrence Berkeley National Labs study, indicating the success of policymakers’ deliberate strategy to use such incentive reductions to push solar installers to drive prices down further.
But explaining the difficulties of the non-residential market comes down mostly to rate design, Honeyman said.
NEM policies reimburse both residential and non-residential solar at the full retail rate of electricity. But the volumetric rate components composes the majority of the residential bill, which is offset by the NEM reimbursement.
Demand and higher fixed charges required of non-residential customers, however, could make up 50%, 60% of the bill, so "less of it is offset by solar,” Honeyman said.
“When that non-residential customer also loses state and utility UFIs and PBIs, project economics are more compromised.”
The overall levelized cost of energy (LCOE) for both residential and non-residential solar increase with state and utility incentives, Honeyman asserted.
“But the homeowner’s LCOE is still below retail, while the LCOE for the non-residential system is not," Honeyman said. "That lengthens the payback period non-residential solar and limits the solar value proposition.”
Now, solar advocates are concerned about utilities requesting that regulators impose similar kinds of value proposition charges on residential solar owners.
“The broader trend is that the debate has evolved to more complicated and sophisticated rate reforms, like peak demand charges, value of solar studies, attempts to revisit the value of solar in ways that does not make it a blanket fixed charge," Honeyman said.
Yet few proposals have won support from both industry stakeholders and utilities, he added. The one exception is proposals for minimum bills, which have at least been “tolerated” by both sides in debate hotbeds like Massachusetts and California, making such bills a "politically palatable compromise,” Honeyman said.
Even with the ongoing debates, solar's strong growth could continue if the right policies and regulations align on the national level.
The report uses its comprehensive and granular numbers to form a three-stage view of the U.S. solar market over the next ten years.
To the end of 2016, there will be “an unprecedented boom in solar installations" impacting all three market segments and most states.
Improving project economics, continued low interest rates, and a secure 30% federal investment tax credit (ITC) through the end of 2016 will drive continued growth, in addition to a rush to complete solar projects ahead of the ITC credit decrease at the end of 2016, the report predicts.
From July 2015 to December 2016, the report forecasts the U.S. solar PV market will add 18 GW, which is more than the cumulative capacity built by the industry up to the middle of 2014.
But more uncertainty over solar's growth lies between 2017 and 2019. Given the political inclinations of the current Congress, it is likely — though not certain — that the ITC will not be extended. The report identifies “five macro factors” that could swing the market one way or another:
- A drop-off in new larger-scale projects from the beginning of 2017, when the ITC drops to 10%.
- Tighter residential and non-residential project economics once the ITC plummets to 10%
- An eventual interest rate increase making project capital more expensive
- Delayed state support for renewables since Clean Power Plan (CPP) compliance is not required until 2022
- Dropping project costs allowing undeveloped new markets to ripen
Between 2020 and 2025, as installed costs reach new lows, imminent CPP compliance requirements will drive “a new era of growth for solar.” State incentives will spur more renewable energy growth to meet CPP standards. And solar will be on “a strong competitive playing field with both retail electricity and alternative sources of wholesale generation.”
Uncertainty will dissolve and there will be an “extended period of consistent expansion” across all 50 state markets. States are likely to redesign their electricity markets to bring in distributed energy resources, following the lead of initiatives now being worked out through California’s AB 327 and New York’s Reforming the Energy Vision proceedings.
And for utilities, seizing solar opportunities will help the resource expand its reach.
For utilities seizing solar opportunities
Honeyman points out that utilities are beginning to seize the solar opportunities.
“The low-hanging fruit for utility-holding companies is to use the deregulated arms to develop and own utility-scale solar assets, which they should move on before the end of December 2016.”
Dominion, NRG Energy and Duke Energy are all working aggressively towards those goals, not just in California and the Southwest, but also in emerging solar markets in the Southeast, he added.
Honeyman used Duke Energy’s purchase of a majority stake in REC Solar as one such example.
“Providing their low cost of capital and deep balance sheet to a company experienced in originating and developing commercial projects is the next, easy approach to solar for a utility,” he said.
The more complicated question, though, is how to develop solar in a utility’s service territory, Honeyman added. Regulatory constraints complicate how “to justify rate basing ownership of solar.”
It has worked for Arizona-based utilities like Tuscon Electric Power (TEP) and Arizona Public Service (APS) because “you had pre-existing capacity allocated to a utility ownership of solar program that was justifiably repurposed for rooftop solar,” Honeyman said.
Regulators also responded to those utilities’ intention to locate their rooftop solar where it bolsters grid reliability, he added.
Another justification for utility ownership is to provide solar to under-served segments of the community. Many homeowners don’t have south-facing roofs that maximize production or credit scores high enough to support low interest rate loans.
Houses with west-facing roofs support grid reliability, potentially warranting utility ownership. Utility-bill secured loans could justify engaging with low FICO score customers. Both are ideas being discussed in utilities' board rooms, Honeyman said.
Finally, he said, community-shared solar offerings located at sites that boost grid reliability are increasingly recognized as a solar ownership opportunity for utilities. And it's a avenue opening up access for lower income and other under-served customers.