Utility Dive: What utilities need to know about solar growth after the ITC extension

Posted by Laura Arnold  /   January 12, 2016  /   Posted in Net Metering, solar, Solar Energy Industries Association (SEIA), Uncategorized  /   No Comments

What utilities need to know about solar growth after the ITC extension

The tax credit extension and the plummeting solar prices add up to unprecedented growth and new opportunities for power companies

With a five year extension and slow phase-down of the industry’s federal investment tax credit (ITC) now in place, the bubble that was building for 2016 — the final year credits would have been available before the extension — has harmlessly deflated.

Instead, there will be strong, steady growth far into the 2020s, beginning with the 7.4 GW of new PV installations forecast to come online in 2015 by most recent U.S. Solar Market Insight (USSMI) report from the Solar Energy Industries Association (SEIA) and GTM Research.

Some of the 15 GW of new PV previously forecast for 2016 will be delayed to 2017, according to GTM Research Senior Solar Analyst and report lead author Cory Honeyman.

An earlier forecast of over 40 GW for cumulative U.S. PV installation will also not be reached by the end of 2016, he now expects. But that number will seem trivial by 2020 in comparison to the additional 25 GW of installed capacity that will come from the tax credit’s extension, 54% more solar than there would have been without it, according to Honeyman.

"The ITC extension will result in a 20 GW annual solar market in the U.S. by 2020," said GTM Research Senior Vice President Shayle Kann. "At that rate, more solar will be installed each year than was added to the grid cumulatively through 2014."

An earlier report from Bloomberg New Energy Finance (BNEF) in October substantiated the new GTM Research projections. It predicted that without the full ITC, the U.S. would likely have built about 73 GW of solar PV by year-end 2022 as annual build rates fell from 8 GW per year to 6 GW per year from 2017-22.

But a five year extension of a 30% ITC, broadly similar to the one just enacted, would boost average build rates to about 10 GW per year from 2017-2022 and result in a cumulative installed capacity of over 95 GW, according to the report.

The extension just passed by Congress will add $30-$40 billion in incremental investment in the industry and bring the industry’s job total to 420,000 by 2020, according to SEIA President/CEO Rhone Resch.

It will also drive the installed cost of solar down 40%, he added. “That will make solar more cost-effective than fossil-generated electricity and make it easier for states to comply with the Clean Power Plan.”

Extension details

Since 2009, the ITC has returned 30% of the investment in any solar installation as a tax credit at the end of the first year of the installation’s service. That benefit was scheduled to drop to 10% for business investments and zero for residential investments at the end of 2016.

Instead, explained Gregory Jenner, partner and energy team co-chair at the law firm Stoel Rives, Congress has extended it through the end of 2021 for both utility-scale and residential installations, though at a diminished rate in its last two years. It also has a “commence construction” provision for utility-scale installations that will make the tax credit available beyond its date of termination.

If construction of a solar installation begins before 2020, 30% of the investment will continue to be returned, assuming the project goes into service within two years. If construction begins in 2020, there is a 26% tax credit. If construction begins in 2021, the tax credit is for 22% of the investment. If construction begins after 2021, the tax credit is 10%.

The commence construction provision also allows a 10% tax credit for installations that meet the criteria for being in construction before 2022 but are not placed in service before 2024.

Utility-scale solar, the most sensitive to the ITC step down, will see deployments increase 73% through 2020," GTM's Honeyman said.

BNEF's estimates again broadly backed up the GTM Research numbers. It calculated that a five year extension of the 30% credit — without the incentive step-down toward the end — would boost utility-scale solar installations between 2015 and 2022 by 10 GW, to 36 GW.

“Without the artificial deadline, we expect more projects to come online, we expect the build to be smoother, we expect fewer bottlenecks in 2016 as a result of the rush, and we expect second tier developers to have greater access to capital,” BNEF analyst and study co-author Maddy Yozwiak told Utility Dive at the time.

Given price trends, Honeyman said, utility-scale solar contracts will likely come in regularly over the next two years at less than $0.04/kWh.

The ITC extension will also lead to 35% more residential installations and 51% more non-residential installations between 2016 and 2020, according to GTM Research. And it will be “a critical policy bridge, as demand heats up in 2020 and beyond due to the Clean Power Plan,” he added.

The ITC extension will help drive a 20 GW annual solar market by 2020, according to GTM.
Credit: SEIA/GTM Research USSMI update

Back to 2015

In 2015’s third quarter, the U.S. brought 1,361 MW of solar PV online, according GTM's Solar Market Insight Report. In the year’s first three quarters, the U.S. brought 4.1 GW online, which was 30% of all new U.S. electricity generating capacity in those quarters.

Before the news of the ITC extension, the report forecast a record-breaking 3 GW-plus in Q4 2015 and a cumulative 7.4 GW for the year.

Q3 2015 residential PV installation was up 12% over the previous quarter and 69% over Q3 2014. California lost some market share but was still 48% of installations. New York also fell off but Massachusetts, New Jersey, and Maryland continued to grow and Nevada nearly quadrupled its installations over Q2 2015 to move into the top five states for cumulative 2015 installed capacity.

Non-residential installations — such as commerical and industrial systems — were up 19% over Q2 2015 and 4% from Q3 2014, but remained solar’s weakest segment. Only the California, Hawaii, and New Jersey markets grew in Q3.

The utility-scale PV pipeline of projects with contracts is now 18.7 GW, which is more than the cumulative U.S. installed capacity through the end of 2014, according to the USSMI. The utility-scale segment, at 42% of all new Q3 2015 installed capacity, continues to be “a bedrock driver of installation growth,” it reports. Though its 2016 total may not reach the 10 GW-plus foreseen before the ITC extension, growth will continue to be driven by cost-competitiveness.

The concentrating solar power segment of the U.S. solar industry, by contrast, seems to be sputtering. After a record-setting 767 MW performance in 2014, it has not added installed capacity this year. SolarReserve’s 110 MW Crescent Dunes installation is expected to be fully operational by early 2016.

Estimates on an ITC extension from BNEF in October substantiate findings from GTM and SEIA on the impact of the tax credits.
Credit: From BNEF (used with permission)

Four important trends

The four important trends shaping the national solar market at the state level are geographic diversification, rate design reforms, new buyers and sellers, and cost-competitive solar, Honeyman said.

Geographic diversification: Over half of the nation’s states now have more than 50 MW of cumulative solar PV installed, according to the USSMI. That means a more diversified marketplace. More importantly, it means there are more markets where the customer appeal of solar will sooner or later play out.

Nevada is a prime example, Honeyman said. It jumped from the 14th biggest residential solar market in 2014 to the second biggest state market last year, driven by policy factors and “a number of national installers that have accelerated the sales cycle and installation process."

As the reality of solar grows in new markets, this is likely to happen more often, Honeyman expects.

Rate design reforms: The rate design debate has entered a new phase, Honeyman said. Proposed reforms and net metering policies “are drastically different from a year or two ago."

Regulators, utilities, and renewables advocates are increasingly trying to align policies with the real costs and benefits of solar exported to the grid. The debates are heated but they include the role of peak demand charges, time of use rates, and a more diversified understanding of the value exported solar.

California, New York, Texas, and Hawaii are at the forefront of the discussion but Arizona is also a hotbed and innovative policies and new approaches are coming from very nascent markets in the Southeast like South Carolina, Georgia, and Mississippi.

New approaches to net metering have been political compromises that led to short term net metering policies,” Honeyman said. “It will be interesting to see how residential and commercial installers in new state markets take advantage of policies with net metering for only a finite period and how the market responds.”

New buyers and sellers: In community solar programs, utilities are selling solar to residential customers. In the absence of workable green tariffs, corporate customers and other large energy users are buying directly from independent power producers.

“There is a wave of empowered corporate entities,” Honeyman said. “We are tracking a GW of large centralized projects that have been procured by large corporations, universities, and municipalities.”

Unique interconnection and net metering programs are capturing the attention of buyers and developers who were previously only interested in business-as-usual incentive-funded opportunities. Over the past half year, “just as many corporates have procured large centralized projects as those that have installed rooftop and ground-mount net metered projects,” Honeyman said.

Community solar development is attracting utilities and project developers who are blurring the definitions of solar’s utility-scale, commercial-industrial, and residential segments. Community solar offers access to project finance and economies of scale, like utility-scale solar. But as much as 40% of the buy-in may come from a single big commercial-industrial customer. And there can 500 residential customers involved in filling out the project's subscriptions.

“As the market continues to grow and mature, these clearly distinguished market segments become increasingly less relevant indicators of where the market is heading,” Honeyman said.

Cost-competitive solar: Utility-scale solar projects are increasingly being procured not because utilities have to meet renewables mandates but because they are beating the competition. It has become a driving force in the almost 19 GW utility-scale solar pipeline.

“We are tracking well over 7 GW that have been procured because they werecompetitive with natural gas alternatives,” Honeyman said. In areas where incentives, the solar resource, the cost to build solar, and the price of electricity come together, “we are very much in an era of cost parity for utility-scale solar as a hedge against natural gas price volatility,” Honeyman added.

For utilities facing potential generation shortfalls due to the need to retire coal plants that do not meet EPA pollution regulations, the appeal of cost-competitive utility-scale solar as a hedge will be accentuated, he said.

As solar becomes more cost-competitive, observed Solar Electric Power Association (SEPA) President/CEO Julia Hamm, it will “accelerate the deployment of other distributed energy technologies – such as storage, demand response and energy efficiency – which will provide even more opportunities for creating value for both individual consumers and the grid as a whole.”

What utilities should note

Utility leaders, first and foremost, need to think about the solar-related product opportunities that fit their business models, Honeyman said.

A cooperative or a smaller municipal utility has more flexibility in procurement and development, he pointed out. “That fits naturally with building out ambitious community solar programs and with thinking about the utility’s eventual role in a rooftop solar program.”

Investor-owned utility leaders need to think more about the tension between constraints and opportunities. In a market with an ambitious renewables mandate, “it is worth noticing how cost-competitive utility-scale solar has become,” he suggested.

Where there is no near-term mandate obligation, IOU leaders should recognize the widespread expectation that over a utility’s long-term planning horizon,natural gas prices are likely to rise, meaning solar can act as a hedge against price volatility in a power company resource plan. Utilities looking to deeper decarbonization in anticipation of future environmental regulations to meet obligations under the Paris climate treaty can also look to solar for low-cost generation without carbon emissions.

“There is a big value proposition in a $40/MWh to $60/MWh fixed price contract for a large scale solar asset that represents a significant portion of load,” Honeyman said. “That is the business case utilities are considering in states like Arkansas, Alabama, and Mississippi where they have never procured a MW of solar before.”

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