Maybe it's the old adage “if you can’t beat ‘em, join ‘em" — utilities are rapidly becoming the biggest players in the large-scale solar market, new data show.
The solar industry is on track to shatter growth records this year by adding 14.5 GW of photovoltaic (PV) capacity, a 94% increase over the 7.5 GW installed in 2015.
Typically, first quarter growth is the year's weakest, but solar developers added 1,665 MW in Q1 2016. That was 64% of all new U.S. electric generating capacity for Q1 and towered over the 18 MW of natural gas that came online in the same timeframe. It brought the cumulative installed U.S. solar capacity to 27.5 GW.
Utility-scale solar was 43% of capacity installed in Q1 2016 and is expected to account for nearly three-fourths of the new capacity for the year. Utilities themselves are expected to play the dominant role in the build-out, according to the recently-released Q2 2016 U.S. Solar Market Insight update from GTM Research and the Solar Energy Industries Association (SEIA).
Residential PV growth was 34% higher than in Q1 2015 but grew only 1% over its Q4 2015 performance in Q1 2016, after averaging an 11% quarter to quarter growth throughout the previous year. Flat growth in California, which is half the residential solar market, was a major factor, but that market is expected to bounce back, according to the update.
Debates over net energy metering (NEM) and rate design are expected to slow growth in many important residential solar markets. But “we expect a number of smaller state markets to pick up steam and balance out the demand slowdown seen in major states,” the update reports.
The non-residential mid-size PV market segment, made up of large commercial, industrial, and public sector customers, has been flat for three years, the update notes. It grew 6% less in Q1 2016 than in Q4 2015, but 36% more than in Q1 2015. It is expected to see some “rebound” over the course of the year from newly-instituted state-level policies, particularly for community solar.
By contrast, the utility-scale segment of the solar market is “on the verge of an unprecedented rate of project completion, with 8.4 GW already announced as under construction,” the update reports, led by record low power purchase agreement (PPA) prices ranging from $35/MWh and $50/MWh.
Utility-scale PV had an inflated 21.4 GW pipeline of projects with PPAs at the end of Q1, built up in 2015 before the 11th-hour extension of the federal 30% investment tax credit (ITC), it adds.
“Altogether, the utility PV market remains on track to install more than 10 GW in 2016 from late-stage projects that are coming on-line,” the update forecasts. In addition, utility-affiliates could, through direct ownership and PPAs, account for over half of the solar that comes online through the end of 2017.
ITC spillover delays some deployment
The 10 GW forecast for this year is “impressive,” but only a portion of what developers were preparing to build this year when they thought the ITC would drop from 30% to 10% on December 31, 2016, the GTM update observes.
“There were a total of 18 GW that had publicly announced they would go online before the end of 2016 to qualify for the ITC,” GTM Research Sr. Solar Analyst Cory Honeyman told Utility Dive.
The five year extension of the tax credit “opened up the possibility for about 5 GW in that pipeline of projects to spill over from 2016 into 2017,” Honeyman said. “A little over 60% of the capacity we now expect to go online in 2017 will be in projects that had been scheduled to come online this year.”
Three key PPA stipulations take some pressure off solar developers by allowing the spillover into 2017, Honeyman said. Without the PPA provisions, projects left from 2015’s pipeline must either be built this year or be at risk of cancelation.
First, developers are finding the financial penalties specified in PPAs for interconnection delays are low enough so that returns will be "sufficient" even they do not meet the contracts' 2016 commercial operation dates (CODs), the update reports.
Some PPAs with utilities and other off-takers have a predictable, pre-determined penalty of as much as $10,000 a day for failing to meet the COD, Honeyman said. Other PPAs define the penalty as the daily difference between the PPA rate and the average daily wholesale electricity price.
A solar developer can predict the per day penalty and decide whether the total amount of the loss can be absorbed by the project’s “rainy day fund,” he said. That loss might be preferable to expenses like higher labor costs for rushing to meet the PPA’s COD. A penalty based on the market price of electricity is unpredictable, and more likely to incline the developer to avoid the expense of the delay.
Second, many of the PPAs in the huge 2015 project pipeline had two CODs, Honeyman said — a voluntary one established to meet the ITC deadline and a mandatory one in 2017 established by the utility or other off-taker.
The utility would have interconnected the project this year to allow it to qualify for the tax credit, but the developer now can wait until 2017 without incurring any penalty, Honeyman said.
That allows a developer with a big pipeline to plan when and where to work, Honeyman said. A project will be developed this year if it will incur penalties for going online in 2017 and will be developed next year if its 2016 COD is voluntary.
“A lot of PURPA projects in the Pacific Northwest were announced as 2016 completions but their PPAs actually required CODs for the first 6 months to 9 months of 2017,” Honeyman said. “Some will still come online this year but many will now come online next year.”
Finally, there will be spillover led by utilities, the update reports. If a developer demonstrates substantial progress toward project completion, an informal compromise or a formal agreement with the utility allows an interconnection delay into 2017.
Utilities in California and the Southwest well ahead of their state-imposed renewables mandate interim targets are particularly inclined to offer such delays, Honeyman said. By giving project developers a break in handling the new high level of project construction, utilities also give themselves a break in processing the projects.
Some procurement programs, including California’s Renewable Auction Mechanism for investor-owned utilities, also allow for utility-led spillover, the update adds.
These interactions between solar developers are not necessarily precursors to any kind of grand bargain on other utility-solar issues, but they do demonstrate “a successful necessary collaboration and negotiation on administrative issues,” Honeyman said.
Utilities taking the lead
Regulated utilities cannot readily monetize the ITC, but it can be of value to the unregulated independent power producer (IPP) subsidiaries of utility holding companies, Honeyman noted. That, and PPA prices low enough to compete with other generation sources, are driving a new level of interest in the solar market among utilities.
Southern Company, Dominion, Duke, Mid-American, and NextEra are some of the leaders in a trend of utility involvement in large-scale solar through those unregulated power development arms, he said.
“As this big influx of projects comes online, a lot of it is going to be owned by the unregulated counterparts of the regulated utilities that have been procuring much of this very cheap, large scale solar,” he added.
Utility IPPs already own 50% of all operating utility-scale solar as well as about 5 GW of the projects in development, he said. More of the projects now in development will be acquired by IPPs when they achieve commercial operation.
“They are on track to account for 50% or more of what will come online over the next 18 months," the GTM analyst said.
Many of the most active utility-scale solar developers have longstanding relationships with those unregulated utility IPPs, Honeyman pointed out. First Solar has sold a significant portion of its U.S. pipeline to Southern Company and SunPower has worked closely with MidAmerican on some of the country’s most ambitious installations, he noted.
There is little indication the utility IPPs will compete with these developers in originating PPAs, Honeyman said, because they recognize the proven expertise of companies like First Solar and SunPower in that area.
“There is more margin if they develop the projects," he said. “But there are so many projects in development right now, the unregulated IPPs see more opportunity and lower risk in project acquisition.”
But they are increasingly interested in acquiring projects built by name-brand developers within the territories they know best, those of the regulated utilities in their own holding companies, Honeyman said. They can then work with those affiliates on off-take agreements.
Southern Power, Southern Company’s unregulated IPP subsidiary owns every project with which Georgia Power has an off-take agreement except one, he said. It is also increasingly doing deals with Southern Comany subsidiaries Mississippi Power, Alabama Power, and Florida’s Gulf Power.
This is not necessarily a planned collaboration between unregulated and regulated affiliates, Honeyman stressed. Many of the utility-owned IPPs have long been investing in solar projects where it has been sound business.
To date, unregulated subsidiaries have focused away from the territories of their regulated affiliates to minimize competition. Instead, they have taken competition into the territories of utility holding companies with which their parent companies compete.
Now, with solar becoming more cost-competitive and customer demand rising, more regulated utilities are procuring solar. Many, especially those in the Southeast, Midwest, and Pacific Northwest, are doing so for the first time, Honeyman said.
“At the same time,” he added, “their unregulated affiliates are recognizing an opportunity to grow their businesses in regions where they have a competitive advantage in their longstanding understanding of the regulated territory.”
Contracts with their IPP utility subsidiaries also allows the regulated affiliates to meet rising demand for renewables-generated electricity from key corporate customers without the need to partner with a private sector developer from outside the service territory, Honeyman added.
Utility-affiliated IPPs talk project acquisition
Dominion Resources historically has been largely a fossil fuel and nuclear generator, with more than 24 GW of capacity today in its unregulated arm today.
But subsidiary Dominion Energy is also the developer-operator for multiple solar projects across the U.S. representing over 700 MW of installed capacity, according to Spokesperson Ryan Frazier. But it shifted its focus in 2016 to developing for Dominion Virginia Power, the holding company’s regulated arm, Frazier told Utility Dive.
There were two motivations behind the unregulated utility’s early development activities, he said. One was to monetize the 30% federal investment tax credit (ITC). The other was to build a utility-scale solar knowledge base for the regulated Dominion subsidiary.
“We have built the knowledge base and intend to provide best-use and best-practices so the regulated utility can meet its 2020 target of adding 400 MW of utility-scale solar in its Virginia-North Carolina territory,” Frazier said.
But the IPP's decision to shift its focus was made with the expectation the ITC might not be extended beyond this year, he added. Now that the ITC has been extended, Dominion is reconsidering the possibility of developing more long term contracted assets outside the regulated territory.
With the price remaining low, acquiring and developing solar continues to have appeal to the utility but it also sees advantages to investing in natural gas. The key factor behind its emphasis on solar could be that “Dominion is moving ahead as though the Clean Power Plan will be the law of the land,” Frazier said. “Solar will allow us to comply with carbon rules and is a cost-effective option for our ratepayers.”
Duke Energy Renewables’ model is to "own and operate the projects we develop ourselves or acquire from others,” Spokesperson Tammie McGee told Utility Dive.
The decision is based on each project’s “risk and return profile,” she said. Duke will move forward on those that make the most business sense and promise to deliver the most value.
The unregulated IPP arm of Duke Energy — another legacy fossil generator — holds over 405 MW of solar in some 20-plus utility-scale projects and has invested over $4 billion in more than 2,500 MW of wind since 2007, according to the company’s website.
Its increasing interest in utility-scale solar is due to the current low solar cost, the value of the ITC, the demand from customers at all levels, solar’s value as a hedge against natural gas price volatility, and the opportunity as owner/operator to control how solar is developed and used, McGee noted.
Both acquisitions and development are likely to continue to be important parts of the IPP’s business strategy, according to McGee.
Duke typically constructs sites after it has signed a PPA with a credit-worthy counterparty, she said. Its off-takers have been and will continue to be other regulated and unregulated utilities, munis, co-ops, and large corporate and non-profit customers.
“To prevent any perception of crossing the line in affiliate transactions, Duke Energy Renewables has never developed a renewables site for the company’s own regulated utilities,” McGee said.
Southern Company declined to comment on the trend described by Honeyman of unregulated IPPs using regulated affiliates as off-takers. But Spokesperson Meredith Leigh Knight noted July 2016 acquisitions of full ownership of the 102 MW Lamesa Solar Facility in Texas from RES Americas and of a controlling interest in the 102 MW Henrietta Solar Project in California from SunPower.
Looking ahead: Lull and reboot
The residential and commercial segments of the market remain hamstrung by policy uncertainty created by net metering and rate design debates, the update reports. Examples are in Hawaii and Nevada, where residential installations have slowed significantly after regulators reduced the value of net metering credits.
“This question of how policy uncertainty interacts with growth is a mundane topic that warrants attention from utilities,” Honeyman said.
Residential rate design controversies are likely to continue but utilities and regulators may be able to address a bottleneck in the non-residential market, he said.
Policy-driven pipeline spikes such as those created by new community solar rules can be alleviated by standardized and streamlined utility processes for approving commercial solar projects,” Honeyman observed.
New standardized interconnection procedures just instituted in New York and a commence construction provision intended to flatten a policy-imposed spike in Massachusetts interconnection applications will be "worth watching," he said.
The current flurry of building that resulted from over-procurement of utility-scale solar caused by the ITC uncertainty will likely last through the end of 2017, Honeyman said. After that, he expects a lull in procurement in 2017 and a dip in utility-scale solar growth in 2018.
Beyond 2018, there will likely be “a reboot in procurement of utility-scale solar,” he said. It will be driven by many of the same factors underlying the current boom, including further cost reductions, the need to meet new and rising state renewables mandates, solar’s value as a hedge against natural gas price volatility, and increasing voluntary purchases by utilities to meet customer demand.