The coming step-down in federal tax credits for solar energy production will cast a shadow over the industry in 2017, but after that analysts expect the sector to return to strong growth, perhaps hitting 250 GW of cumulative installed capacity by 2030.

Residential electricity customers are responding enthusiastically to the solar opportunity, and utilities are increasingly seeing value too, according to the author of a recent GTM report titled "The Future of U.S. Solar; Getting to the Next Order of Magnitude."

"Distributed solar has a lot of momentum and is nowhere near its penetration limits, and utilities are just starting to consider centralized solar generation in their long term planning,” said Shayle Kann, GTM Research senior vice president and report author. “There is a meaningful role for both. How it will split depends on how the markets evolve.”

There was 2 GW of installed U.S. solar capacity at the end of 2010. Many thought it was too expensive to be an important part of the energy mix. But the residential installed cost has gone from $6.71/watt to $3.54/watt while the utility scale cost has fallen from $3.58 to $1.45. As a result, GTM estimates the U.S. will build 7.7 GW of solar in 2015 and have a 26 GW installed capacity at the end of the year. 

The question now is how much solar can make up the U.S. generation mix.

“There is a realistic path toward 10% over the next 10-15 years,” Kann wrote, making an installed capacity of 250 GW “a rough benchmark.”

The promise of growth

U.S. electricity prices are expected to keep rising, making the solar value proposition more appealing for home and business owners as well as for utilities. The Obama administration's Clean Power Plan will also open up a need for new low-emission generation as utilities close aging or expensive fossil fuel power plants close for compliance. 

What's more, Kann said, markets are being redesigned to incorporate solar and other distributed energy resources (DERs). Proceedings like New York’s Reforming the Energy Vision (REV) initiative, California’s AB 327 reforms package, and Hawaii’s DER docket are creating regulatory transformations too extensive to be reversed.

“It is possible the big regulatory transformations will be centered on distributed generation,” Kann said. But utilities are including utility-scale solar in their Integrated Resource Plans (IRPs), too. Depending on how the markets are structured, plant retirements led by the Clean Power Plan may be replaced with centralized solar generation.

The 250 GW of solar projected by GTM accounts for PV a the residential, commercial-industrial, and utility scales, but it does not include concentrating solar power, which uses mirrors to super-heat liquid to create steam to run a turbine. It's unclear what proportion of each sector will be represented in that total.

“The number of suitable rooftops is not the limiting factor,” Kann said. The current supply of solar suitable roofs is far from saturated. NREL GIS-based research put the technical potential for rooftop solar PV at 664 GW, he explained.

Projections through 2020 show distributed solar increasing its share of the market because the scheduled sunset of the 30% federal investment tax credit is expected to have a greater impact on utility-scale solar growth. Unless Congrss takes action to prevent it, the ITC is slated to revert to its pre-2006 levels of 10% for commercial investments and zero for residential investments at the beginning of 2017.

It's also expected to produce “the first year-over-year downturn in the U.S. solar market in more than 15 years,” Kann wrote in the report.

No one can predict whether the overall impact of the ITC reversion will slow solar’s long-term march toward 250 GW, but it “certainly will not bring about the end of solar growth,” Kann writes.

The Clean Power Plan, meanwhile has “enormous potential to support the expansion of solar." Even in the 27 states challenging the plan's legality in court, utilities are clamoring for regulators to put together compliance plans for the rule — plans that will likely boost renewable generation, including solar.

Of the many compliance options available to meet the emissions mandates, solar may especially beneficial. 

The newest paper from utility-strategist Peter Kind recognizes utility-scale solar investments as a smart choice in long-term generation planning because they align the interests of utilities, customers, policymakers, and third-party providers.

The threat of rate reform

Almost all U.S. distributed solar has been built with a net energy metering (NEM) incentive. But Hawaii, ever a "postcard from the future" in the utility sector, just terminated its NEM program and California’s major utilities are asking their regulators for a similar reform.

If all states were to match the Hawaii reform — which reduced NEM credit by about 50% — the only state with a competitive solar value proposition would be Hawaii, due to its disproportionately high electricity rates.

Perhaps more significantly, some regulators have granted utilities approval for fixed fees and demand charges that can also erode the solar value proposition. A demand charge approved for Salt River Project (SRP) in Arizona earlier this year has cut down the amount of solar buyers  by about 50% and possibly as much as 95%, according to solar developers in the state. 

But change will not come suddenly and will not be universal, Kann explained. As NEM credits fall, the price of solar is likely to come down, too, keeping solar competitive. Fixed and demand charges may come with time-of-use rates that make solar more competitive. And as they are introduced, the falling cost of storage may offer new values.

Why market reinvention matters

Utility customers value distributed solar because it reduces their electricity bills, while utilities value centralized solar largely only for the kWh it sends to the grid. With electricity market reforms, DERs can offer multiple values to the grid while continuing to provide either bill reductions for customers or kWh for utilities. Paired with energy storage and load control, earnings from aggregated DERs' multiple revenue streams can be significant.

“This may sound overly futuristic and speculative, but it is already beginning to happen today,” Kann wrote.

The California Independent System Operator’s Distributed Energy Resource Providers (DERPs) program, the Electric Reliability Council of Texas Distributed Resource Energy and Ancillaries Market (DREAM) taskforce, and the New York REV initiative are plans that will allow DERs to earn “grid-service value streams…[and] may present the most significant new opportunity for distributed solar in years.”

If and when effective market rules that recognize DERs as grid assets are implemented, DERs will yield more value to the grid and earn more in wholesale markets.

“We are just into the first wave of this market reinvention,” Kann said. “It will be a totally different paradigm when both the current value of DERs and their value as grid services are recognized and remunerated.”

A recent Rocky Mountain Institute study affirmed Kann’s point about the potential value of multiple stacked services from aggregated DERs. 

With today’s cost structures, “batteries deployed for only a single primary service generally do not provide a net economic benefit,” RMI concludes. But those primary services require less than half a battery’s life. Stacking other uses on them “shifts the economics in favor of storage.”

The increasingly popular idea of a “prosumer” in a two-way interaction with the grid may soon be inadequate to the complex role that customers will eventually play, Kann wrote.

The most forward-thinking regulatory reforms are turning DERs into “grid-responsive assets,” he suggested. The customer of the future in a smart home connected to the grid with a simple interface will need only some form of generation, like solar, to seize big revenue opportunities. 

It's not clear when that future customer will arrive, but current plans for reinvented markets suggest there will be “an array of new opportunities to extract value for customers and the grid from on-site solar,” Kann wrote.

The threat of value deflation

The downside is that as solar becomes a bigger portion of the generation mix, its value and the revenue  begin to drop. Unless paired with storage, solar is non-dispatchable and must sell when it is generated. At some level of penetration, the grid will not need more, and solar’s value will fall.

“The more solar is placed on the grid, the less the grid needs power when solar production is highest,” Kann wrote. “As solar becomes a mainstream power source, regulators and utilities are more likely to align solar compensation more closely with wholesale market pricing.”

Value deflation is when compensation becomes the market price, and solar owners start seeing declining revenues.

“The next kWh is worth less than the previous kWh because the more you put on the grid, the less you need that new generation at that time,” Kann said.

This occurance relates to the bottom half of the infamous Duck Curve chart in which solar over-generation in the middle of the day precedes a fast ramp of load just as solar productivity drops off with the setting sun. 

Precise wholesale market modeling affirm the phenomenon of value deflation for utility-scale and distributed solar. A Lawrence Berkeley National Laboratory study estimated "solar value to be 38% lower when solar is at 10% penetration of residential sectors of Los Angeles,” Kann wrote.

But, Kann noted that retail rate NEM credits can mask value deflation. Even so, a California study of residential solar showed that solar owners compensated at time-varying wholesale prices lose 35% of bill savings with a 15% solar penetration compared to solar owners with NEM and a zero solar penetration.

“That is where storage is incredibly valuable,” Kann said. “Storage mitigates value deflation by allowing the shift of solar generation from the time when it is less needed to the time when it is more needed.”

Storage, load control, and new possibilities

Storage can mitigate value deflation even if NEM is reduced and a high demand charge is imposed. SRP’s new residential rate structure for new PV system owners imposed a $9.25 per kW per month demand charge and reduced the NEM credit from the retail rate of approximately $0.09 per kWh to $0.05 per kWh.

Still, a GTM research analysis found solar-plus-storage economics, with certain parameters, could be superior to solar-only economics.

Behind-the-meter and in-front-of-the-meter energy storage can both support solar growth, Kann writes.

If NEM credits drop below the retail electricity rate and demand charges are imposed, distributed solar owners with behind-the-meter storage can retain over-generation instead of selling it back to the grid at low rates. Then, they can use stored, solar-generated electricity instead of costly peak period electricity that drives up their demand charges.

System level, in-front-of-the-meter energy storage can also head off value deflation. according to the report. 

At midday, when the solar irradiation is most intense, a utility-scale project’s bulk output can be stored instead of released to the grid when other solar production in flowing into the system. That can eliminate off-peak over-generation. The stored electricity is then available when the grid’s load increases, boosting its value to system.

That is the strategy behind the recent 13 MW solar PV array that Kauai Island Utility Cooperative (KIUC) is installing with a 13 MW/52 MWh lithium-ion energy storage system, Kann writes.

The battery storage “will be used to shift the PV generation into the 5 p.m. to 10 p.m. evening peak, displacing expensive peaking plants, providing more value during peak hours, and minimizing stress on the existing baseload plant.”

Hawaii is unique because the solar penetration is as high as 30% of single family homes on some parts of the grid. In the rest of the country, “the economics aren’t there yet but the need is not there yet either,” Kann said.

The challenge of solar value deflation will increase. The ability of storage to mitigate it “will depend on the costs of solar and storage continuing to fall, which we expect,” Kann said.

What energy storage can do to support future solar growth on the supply side, load control can do on the demand side, the paper reported. The use of smart and networked appliances and services can offer a “demand flexibility” that an RMI study estimated could “reduce grid costs by $13 billion per year,” Kann  wrote.

“RMI did a good job of making the argument that load control is just as important and the potential is just as big as storage, depending on what controllable load the customer has and what the load profile is,” Kann added..

A bumpy ride to a bright future

The near-term outlook is likely to be a bumpy ride requiring much work by advocates of solar, which the paper describes as an “incentive- and regulatory-driven technology."

Though costs will continue to fall, it will be at a slower rate. Even utility-scale solar, which comes with economies of scale, will only see an installed cost drop of 11% between 2020 and 2030, the report projects.

But solar has the Clean Power Plan, market reinvention, rate design solutions, and storage and load control technologies on its side.

“I find it very difficult,” Kann concluded, “to conjure a realistic scenario that doesn’t include solar achieving the next order of magnitude by 2030, if not earlier.”