Solar energy broke its own growth record in the third quarter last year, but it looks like those numbers will be broken again as solar installations finish out 2016 in strong form.
Between July to the end of September 2016, solar installers brought 4,143 MW online, nearly a 200% jump from the same time in 2015. A joint report from GTM Research and Solar Energy Industries Association (SEIA) said at the time it was solar’s biggest quarter yet. But with the pace of solar installations set to come online, 2016’s final quarter is set to beat it: The pipeline could hit 5 GW of installed capacity, Austin Perea, a GTM research analyst and co-author of GTM’s most recent Solar Market Insight, told Utility Dive.
“The biggest driver is utility-scale solar and residential solar growth is slowing,” he said. “That is the solar story of the year for 2016.”
Driven by state renewable mandates and historically low power purchase agreements (PPA), utilities continue to invest in solar power, with 70% of new solar this year slated to be utility-scale. And the U.S. Energy Information Administration said solar energy composed 39% of the nation’s new generation capacity in 2016.
“Utility capital spend in 2016 is at a record $120 billion and about $42 billion of that will go into generation,” Richard McMahon, vice president of energy supply and finance at utility trade group Edison Electric Institute (EEI) said.. “A significant portion will go to solar, wind, and natural gas, a trend that has been fairly consistent since 2008.”
But for the residential solar sector, the numbers show a different story. Installed capacity fell in the third quarter, reflecting a market transformation as the third party ownership finance model loses favor with customers.
These numbers open up paths for the agile utility to take advantage of non-traditional markets to grow solar investments, including community solar projects and utility scale solar.
The ITC extension's influence spreads far
It’s obvious that the federal ITC extension was vital for the boom in solar development, adding some 20 GW of capacity and set to grow an annual 10 GW until the 2020s.
Beyond the ITC extension, corporate customers are expected to be essential market drivers. Corporate buyers have already contracted for more than 1.5 GW of offsite wholesale solar, while California’s community choice aggregation programs could add more than 3 GW through 2020.
For the first time, more than half of the non-residential market will draw from virtual net metered projects, community solar and wholesale solar in 2016.
In 2017, onsite development will likely drive the growth as the demand for offsite contracts diminishes, according to the report. “In the long term, large corporate customers’ demand for solar-plus-storage versus offsite wholesale PPAs will play a critical role in shaping the breakdown between onsite and offsite development.”
In 2017, the residential and non-residential PV markets are projected to grow but a slowdown in the utility-scale sector from this year’s exaggerated pace to about 8 GW will bring the overall total down about 4%, according to the report.
By 2019, there will once again be year-over-year growth across all U.S. solar market segments, the report concludes. “By 2021, 30 states in the U.S. will be 100-plus MWdc annual solar markets, with 20 of those states home to more than 1 GWdc of operating solar PV.”
The utility-scale boom
A number of factors played a role in the looming utility-scale solar boom this year. First, the high numbers predicted to come online in 2017 are in part because of the rush to claim the 30% federal tax investment credit before it declined in 2016, Perea said.
“This is the first big wave of projects that were procured under the assumption the ITC would expire,” he said. “Of the pipeline scheduled to come online in 2017, 55% of the MW were pushed out from 2016. If not for that, there might be a much bigger cumulative installation this year.”
In the third quarter, utility-scale solar grew by 3.2 GW, composing 77% of total installed capacity for solar. Another 4.8 GW is under construction and expected to go online last quarter. All told, a total of 19.4 GW of contracted utility-scale solar in the industry’s pipeline.
But utilities are not procuring solar to meet renewable portfolio standards anymore. More than 70% of the solar in the pipeline for the upcoming year reflects that trend, the report noted. Instead, the biggest driver will be smaller solar projects that qualify under the federal Public Utility Regulatory Policies Act (PURPA) of 1978. The policy sought to break up the utility monopoly on generation choices by requiring them to buy from smaller developers of renewable energy at their avoidable cost rate for a long-term contract, usually set for 20 years.
Economies of scale have driven down installed costs, allowing PPA prices to fall between $35/MWh and $50/MWh, which is below the avoided cost for many utilities. Consequently, significant growth in PURPA-qualified solar is seen in states like the Carolinas, Oregon and Utah.
Many utilities, especially in the Southeast, are also procuring voluntarily. They see low fixed price, long-term solar contracts as a hedge against natural gas price volatility. Corporate buyers in California, Texas, and PJM markets, as well as community choice aggregators in California are also taking advantage of solar contracts’ low and long-term fixed prices to meet sustainability and clean energy goals.
Community solar markets emerge
In the non-residential solar sector, the third quarter grew 15% from the previous quarter, marking its second biggest one yet. More than 800 MW of offsite, wholesale solar will be added this year, mostly for corporate customers with large industrial loads or renewable energy targets.
But the biggest growth driver came from the large pipeline of community solar projects, Perea said.
“In Q3 and Q4 2016, we are seeing the first wave of the robust community solar pipeline that has been building up Minnesota, Massachusetts, and Colorado,” Perea said. “The hundreds of community solar MW in development, especially in Minnesota and Massachusetts, that have finally cleared regulatory and legislative hurdles will drive a big build-out into 2018.”
The community solar market is expected to add more than 200 MW this year, a 400% jump from 2015’s 50 MW, he added.
Trouble on the roof
It’s a more dismal story for residential solar. Installations fell 10% in Q3 from the previous quarter.
“It has become clear that the national residential market is experiencing a significant slowdown as major state markets continue to see deceleration,” the report noted.
California, which claims about half of the residential installations, experienced its first year-on-year drop off in Q3.
“The market in California is fully saturated,” Perea said. "People are tired of door-to-door sales and all the other marketing from residential solar companies.”
The top five state markets, which have accounted for 70% of the residential market, will slow from the same “market saturation and customer fatigue,” he added.
Between 2010 and 2015, residential solar had a 55% annual growth rate, according to the research. “Growth will fall to a more stable ‘low teens’ level in 2017 and for the next few years,” Perea said. “The early-adopter customers have adopted solar, making the overall sales cycle for acquiring one customer lengthier and costlier.”
In addition to this more competitive landscape, the regulatory battles over net energy metering and other rate reforms make selling solar riskier and, subsequently, more difficult for installers, he added.
But outside the top five states, some markets are emerging. Leading national installers have moved into Utah, Texas, and South Carolina to take advantage of “expiring incentives and early-adopter customers,” according to the report. But they only “partially offset” the national deceleration and “are susceptible to incentive-driven boom-and-bust cycles and the same regulatory concerns.”
On another front, solar companies are moving from the third party financing model, which drove much of the growth in the residential solar arena.
“The 2015 financing forecast, made before the 30% federal investment tax credit (ITC) was extended, anticipated the market would flip from TPO systems to customer-owned systems by 2020,” said Nicole Litvak, a senior solar analyst for GTM Research. “The market has transitioned to loans and cash sales even faster than we expected.”
With that shift, utilities could find opportunities in providing loan options to customers who desire rooftop solar arrays.
The trends inside the numbers
Overall, the trend is clear: solar has become more competitive as its costs fall.
“It is a price-competitive replacement for retired coal plants and because the fixed PPA price can be a hedge against natural gas price volatility,” Perea said.
Most notably, this is seen in Nevada as five major casinos defected from incumbent utility NV Energy, Perea said.
Despite the high exit fees, casinos felt their chances to meet renewables goals were better served on the retail market, a symbol of how solar has evolved into a cost-effective resource. “That is a trend that poses a pretty significant risk,” he said. “It underscores the need for utilities to structure better green tariffs or find ways to acquire generation to meet their larger customers’ demand if they do not want to lose significant portions of their load.”
Meanwhile, utility-led community solar programs are also gaining traction, Perea said. While private developers continue to helm most of the community solar projects, “utility-led programs are expected to pick up in 2018 and beyond.”
For utilities, community solar provides many advantages. First and foremost, they see it as an effective tool for customer engagement as it promises to open access to renewable energy to all incomes and “it keeps customers from going to rooftop solar,” Perea said.
EEI’s McMahon said community solar development can also be sited near load, an advantage over utility-scale and rooftop solar, which are both usually sited away from load. For instance, utility-scale solar is usually installed in open areas away from load sites, while rooftop solar depends on the proper rooftop.
If rooftop solar is added where distribution system infrastructure cannot meet the needs of the distributed generation at the location, upgrading can add to utility costs, McMahon said. “Utility-led community solar arrays can be located to optimize their value to the grid.”
Community solar’s larger arrays also offer economies of scale, which tips in their favor when it comes to price.
“Customers want greener attributes in their supply but they also want it to be reliable and affordable,” McMahon said. “Community solar can deliver the greener attributes in an affordable, reliable way. Once customers know what the relative prices, they can make their own choice between community and rooftop solar.”
Perea does not think community solar will "meaningfully” erode the residential market in the near term. “There is a substantial market of people with solar suitable roofs and good enough credit scores and who appreciate having on-site generation,” he said.
In addition, the many subscribers needed to make a community solar project work makes their customer acquisition costs high, Perea said. “But if private sector or utility developers can reduce those costs, there is the potential in a few years that community solar could provide a better value proposition in some state markets.”
The shift away from TPO financing opens doors for utilities
While other parts of the solar sector have grown robustly, residential solar is shifting gears over its financing model. The shift from third party financing to cash or loan purchases have opened up a window of opportunity for utilities.
The shift was made possible by the increasing affordability and reliability of rooftop solar. It was led by small local installers who found they do better financially when customers purchase. It is now supported by offerings from large national installers like SolarCity, Sunrun, Vivint, SunPower, OneRoof and Sungevity.
The move away from TPO is supported by the rise of a special set of lenders such as Mosaic, EnerBank, DividendSolar, Sungage Financial, Sunlight Financial, Green Sky, and Blue Wave to name a few. Most operate nationally and work with both the large and small installers, Litvak said.
They have been around a few years but are essentially start-ups, Litvak said. “Some have had more success than others at raising money for loans, so installers often work with more than one. Customers can also get home equity or specially-marketed solar loans from local banks,” she added.
Any company interested in finance could make loans or fund loan providers because it is "simple debt," Litvak said. With interest rates low and solar an increasingly a good long-term investment, significant financing is available for loans “but it is not clear who the big players are or how the market will shake out,” she added. “Leaders will likely emerge in the next year.”
There is no reason, Litvak acknowledged, that utilities could not use their strong balance sheets and access to low cost capital to provide loans or to offer funding to loan providers. “Utilities are one of the many potential investors but many may not be aware of the opportunity. It would definitely be a way to profit from the solar expansion.”
Some utilities are already testing those waters. Perdenales Electric Cooperative (PEC) in Austin, Texas, the Municipal Utility for Fort Collins, CO, and Public Service Electric and Gas of New Jersey (PSE&G), the investor-owned utility in New Jersey are among the first.
PEC offers loans for up to $20,000 with 10-year terms. Customers can finance grid-tied distributed energy resource (DER) systems, including distributed solar and grid-tied battery storage installed by one of the ten participating local vendors. PEC members can repay the loan through monthly installments thanks to on-bill financing.
In the Colorado muni’s case, its loan program provides $500 to $25,000 to finance solar, water conservation and energy efficiency installations. But first, the customer must participate in a home energy audit.
Neither the muni nor the co-op returned Utility Dive requests for information on the progress of their programs.
In New Jersey, third party financing remains “the overwhelming financing mechanism for residential solar” in PSE&G’s market, but its loan program is working for customers who want to own, PSEG’s spokesperson Francis Sullivan said. “Any trend toward ownership over TPO in New Jersey would be beneficial to participation.”
The New Jersey Board of Public Utilities approved the PSE&G Solar Loan Program for a specific number of MW, and there is adequate funding to fulfill the now nearly-met program allocation, Sullivan said. A “minimum SREC value guarantee” included with the loan mitigates that volatile market’s risk for borrowers.
PSE&G was granted a rate of return on its financing programs by regulators because without the utility’s capital the New Jersey SREC program may otherwise impose costs on taxpayers. The utility continues to originate loans but has no plans to move from its current SREC-based repayment method to an on-bill option.
“Utilities bring a lot to the table. Surveys repeatedly show utilities have a credibility with their customers that is unique because we are not going anywhere,”Susanna Chiu, director of marketing for PSE&G, told Utility Dive recently.
Its solar loan business is probably an exception to usual utility offerings in the power sector, Chiu acknowledged. But the utility’s strong balance sheet provides access to low cost capital vital to the growth of a New Jersey solar industry strongly supported by state policy.
If any doubts remain over investing in solar, EEI’s McMahon said that efforts to enhance the grid should erase those concerns for the most part. “Over the next three years, electric companies will spend more than $300 billion to enhance the energy grid and to make our generation fleet even cleaner, including through increased investment in solar energy.”