Cypress Creek Renewables now 2nd biggest developer behind First Solar

Posted by Laura Arnold  /   November 17, 2016  /   Posted in Renewable Electricity Standard (RES), solar, Uncategorized  /   No Comments

Utility-Scale Solar M&A Activity Picks Up as US Developers Scramble to Build Bigger Pipelines

Photo Credit: Cypress Creek Renewables

Utility-Scale Solar M&A Activity Picks Up as US Developers Scramble to Build Bigger Pipelines

Cypress Creek Renewables is now the second-biggest developer behind First Solar. Its recent acquisition of FLS Energy is a sign of a looming trend.

One of America’s largest utility-scale solar developers just got bigger.

Last week, Cypress Creek Renewables announced that it had signed an agreement to acquire North Carolina-based solar developer FLS Energy. The combined company will boast an impressive pipeline of solar projects.

According to the companies, FLS Energy has an operating portfolio of 350 megawatts and a “near-term pipeline” of over 600 megawatts. This will add to Cypress Creek’s own solar portfolio of 735 megawatts that are either in operation or under construction, and 4 gigawatts in various stages of planning.

“This move solidifies its place as a major developer of utility-scale solar in the U.S.,” said Colin Smith, a solar analyst at GTM Research.

Cypress Creek is now the second-largest utility-scale solar developer in America, behind only First Solar, according to Smith.

For its part, Cypress Creek believes the acquisition of FLS will make it stronger in both project finance and construction -- and better poised to take advantage of new growth opportunities.

“We are active in 15 states. FLS will help us grow in those markets, as well as other states in the coming months and years,” said Jeff McKay, a company spokesperson. “We can’t say what those states will be, but we are actively trying to grow.”

Expect more mergers and acquisitions

Cypress Creek’s acquisition of FLS Energy comes at an interesting time for utility-scale solar in the U.S. Although its projections have not yet been finalized, GTM Research expects that 9.9 gigawatts of new projects will come on-line in 2016, double the amount added in 2015.

This year could have seen even more utility-scale solar installed if the 30 percent Investment Tax Credit (ITC) had not been extended through 2018, when it is slated to ramp down incrementally through 2021 and remain permanently at 10 percent starting in 2022.

“Because utilities were expecting to have the ITC fall off in 2016, they over-procured to meet their obligations,” said Smith. When the ITC was extended, some of the projects that were slated to come on-line in 2016 were pushed to 2017.

Smith says the Cypress Creek deal is notable for a couple of important reasons.

In particular, the rush by utilities to procure large solar projects before the end of 2016 ultimately reduced RPS solicitations for coming years, and forced developers to scramble to fill up a dwindling project pipeline.

Smith expects to see an increase in merger and acquisition (M&A) activity as more developers seek to build their pipeline by ingesting entire companies. “We think it’s the beginning of a trend of companies that want to buy other companies to get their pipeline,” he said.

It also could mark a fundamental shift in the driving force behind utility-scale solar development. “Renewable portfolio standards were behind utility-scale PV in the U.S. [Cypress] is an example of a company that has leveraged non-RPS mechanisms to become the No. 2 developer in the country in terms of pipeline,” said Smith.

Moving beyond the RPS

The way Smith sees it, new drivers of utility-scale solar include voluntary utility and corporate procurement by companies that realize solar is competitive with natural gas and a good hedge against rising fuel prices. Additionally, the ongoing decline of solar prices has made it possible for more and more projects to be economically viable under the Public Utility Regulatory Policies Act (PURPA).

Passed in the 1970s, PURPA was meant to encourage energy conservation and renewable energy development by allowing developers to sell the energy they produced to utilities, as long as it was at a price equal to or below avoided cost. “With the cost of renewables dropping, solar plants can be cheaper than avoided costs,” said Smith. PURPA has prompted solar development in states like North and South Carolina, as well as Indiana and Oregon.

Though there’s no cap on PURPA projects, it is an inherently risky approach. When utilities see they have too much power in their interconnection queues, said Smith, they petition state regulators to change avoided-cost rates, lower contract lengths, or reduce the maximum project size. “It’s very risky in the sense that you can have abrupt policy shifts." Montana has recently experienced just such a pushback.

Despite the risks, Smith expects PURPA-driven projects will meaningfully contribute to the 2017 utility-scale solar market. As RPS procurements wane, a combination of voluntary purchases by corporations and utilities, as well as solar’s increasing competitiveness in wholesale energy markets, will take up some of the slack.

It’s also possible that local governments -- like Marin County in Northern California -- will ramp up their energy procurement and become a larger driver of utility-scale solar development.

GTM Research’s latest projection for 2017 utility-scale solar installations is 8.7 gigawatts, although 2.5 gigawatts of that total consists of projects initially slated for completion in 2016. “There’s an inevitable decline, because there was so much over-procurement in 2016,” said Smith.

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