Era of repowering arrives as renewables reach end of life
End-of-life wind-turbine facilities are being repowered with new technologies that will qualify them for another 10-years of federal tax credits and enable them to win new, low-priced power-purchase agreements with utilities and compete with low wholesale electricity prices. "Repowering is significantly more straightforward than building a new project because the impacts and variables are known to all the stakeholders and regulatory and permitting agencies," said Greg Wolf, CEO of Leeward Renewable Energy. A 2015 report from the National Renewable Energy Laboratory estimated the repowering market to be worth $25bn by 2030.
Renewable energy is a growth industry, so most media attention goes to installment numbers, expansion rates, and cost declines. Less is paid to the other side of the equation — what happens to facilities when they reach the end of their productive lives.

For most fossil facilities, reaching a retirement age means being decommissioned and demolished, if not retrofitted with a new turbine and cleaner fuel. But despite some persistent media rumors of “abandoned” wind turbines or assertions from a certain presidential candidate that "half of [turbines] are broken" or "rusted and rotting," the end of one renewable energy facility’s life most often marks the beginning of another.

Most solar farms are too new to be retired yet, but the first U.S. wind projects, built in the 1980s and 1990s, are reaching the end of their productive lives. Output is dwindling, maintenance costs are climbing, and new technologies make the turbines obsolete.

But the existing sites, with ready transmission connections and high wind potential, make them ideal candidates for what the industry calls “repowering.”

Wind developers and industry experts say projects repowered with new technologies will qualify for another ten-year round of the $0.023/kWh federal production tax credit (PTC), extended at the end of last year. That would allow them to win new, low-priced power purchase agreements (PPAs) with utilities or meet the low prices in today’s wholesale electricity markets.

“New wind turbines’ taller towers increase wind capture by 44% and their longer blades increase wind capture another 57%,” said American Wind Energy Industries (AWEA) Research Director Michael Goggin.

“At the same, advanced generator, gearbox, and component technologies have lowered turbines’ cost per MW,” Goggin added. “The result is a lower cost per MW and more MWh generated for the cost, which is driving the levelized cost of energy down.”

Contracts for the oldest projects’ output are largely expired, said John Hensley, AWEA manager of energy data. But IRS rulings on the PTC support financing project repowering. And the advanced technologies, along with their relative readiness for development, allow project owners to enter into PPAs or sell into energy markets at competitive prices.

The potential for repowering

The bulk of U.S. repowering so far has been at the Altamont, San Gorgonio, and Tehachapi Pass sites in California where the first U.S. utility-scale installations were built, Goggin said. The early generation of turbines were having increasing maintenance issues at sites identified for very high quality wind.

Repowering at Altamont has a unique driver. A historic 2010 agreement was brokered between the state and NextEra Energy by then-Attorney General and now Governor Jerry Brown to settle longstanding concerns about avian harms.

The developer agreed to replace 2,400 of the 30-plus year old turbines that were committing the most egregious offenses with 100 newer, taller turbines with slower blade rotation speeds.

The new turbines are also being sited more benignly and have other scientifically validated high-tech bird protections. Each of the new turbines will produce as much as 23 times the wind-generated electricity, according to local news reports.

With the extension of the PTC at the end of 2015, interest in repowering elsewhere accelerated as developers looked again at similarly wind-rich sites across the country where older projects’ PTC eligibility has expired. “The 61% decline in the LCOE for wind from 2009 to 2015 is making repowering an attractive option,” Goggin said.

Repowering can be “full” or “partial.” Full repowering is the complete dismantling and replacement of turbine equipment at an existing project site, while partial repowering involves replacing selected turbine or plant components to extend the life of a facility.

Under IRS ruling 94-31, retrofitted facilities can qualify for tax incentives even if they contain some used property.

The IRS 80/20 Rule governs the use of the PTC for partial repowering, Goggin said. Widely used for other types of power plants, it essentially requires that 80% of a power plant must be replaced in order to qualify.

A January 2015 report from the National Renewable Energy Laboratory estimated there will likely be only “a few hundred megawatts per year” of repowering by the early 2020s, assuming an average project life between 20 and 25 years.

The report forecasts a 1 GW to 3 GW U.S. repowering market by the late 2020s and an estimated repowering market total value of $25 billion through 2030, with the bulk coming in the second half of the decade.

Other repowering forecasts are more bullish. A report from EY cited by the Wall Street Journal this month estimates 15% of the 75 GW of installed U.S. capacity could be ready to retrofit — mostly facilities built before 2006, because their ten-year PTCs are running out.

Efforts to leverage the PTC are accelerating near-term repowering efforts in California but will peak and then slow with the tax credit’s phase down from 2017 through 2020, according to a presentation to California regulators earlier this year by John Pappas of utility Pacific Gas and Electric.

NREL estimates over 2.5 GW of repowering annually by the late 2020s. NREL report on repowering

Old projects never die

Lease agreements between wind project developers and landowners typically require projects to be decommissioned when taken out of service, said Ed Einowski, partner at law firm Stoel Rives. That means removing all hardware and restoring the land to its pre-construction condition.

But most PPAs, he added, “don’t say anything about decommissioning.”

“The utility does not take any responsibility for the project, but focuses on dealing with developers who they are confident will comply with the law,” he said.

Developers typically lease the land. If the developer does not meet the decommissioning obligation in the lease, the landowner has legal recourse against the developer. But it has rarely been an issue and is unlikely to be one, Einowski said.

“There has not been any significant decommissioning of modern turbines,” he said. “The land leases are usually 20 years or 25 years and typically contain a right to extend for another 20 years or 25 years.”

“The bulk of the decommissioning that will happen will be in combination with repowering.”

Though he could not detail them because of lawyer-client confidentiality, Einowski said Stoel Rives is presently handling deals in which the oldest turbines are being replaced with the most current technology, and are requalifying for the PTC under the 80/20 Rule.

“We have been handling those deals for some time,” he said.

Solar PPAs also do not typically cover decommissioning, he added. But decommissioning of solar power plants is even more unlikely than for wind projects because the economics of keeping them in operation are even more favorable.

The land for solar projects is more often owned by the developer, eliminating any complexity associated with renegotiating a lease. Because solar power generation has no moving parts, maintenance amounts largely to routine module cleaning. Module efficiency drops off no more than 0.2% to 0.3% a year, according to Einowski.

“That means that once the project is built and the capital costs are paid, which usually happens within the term of the PPA, it is a gold mine,” he said.

The capacity factor may drop off but "the generation is almost free so there is no reason not to sell to the market, whatever the price,” Einowski said. “We have not heard any serious discussions on decommissioning solar and it is entirely possible that will not be common.”

Decommissioning and what it means to restore the land to its original condition are most often found in underlying real estate documents, agreed CohnReznick Capital Markets Securities Director Gary Durden.

“Modern megawatt turbines beyond California are only now coming up on the end of their PTC life,” he added. “That is why there is an emerging discussion of repowering as a way to tap into that opportunity. It is becoming clear that in some cases it can be very cost-effective to repower them and requalify them for new PTCs.”

The extension of the PTC at the end of 2015 included a five-year phase down in the tax credits’ value, and investment in 5% of a given project qualifies it for that year’s credit rate.

According to the terms of the phase down, a 5% investment by the end of 2017 qualifies the project for 80% of the value of the PTC if it goes into service by the end of 2022. A 5% investment by the end of 2018 guarantees the project 60% the value of the PTC if it goes into service by the end of 2023. There are two further steps down before the tax credit terminates.

“Investors see real value in capturing the full value of the PTC,” Durden said. “By the end of this year there will be some decent amount of action in buying turbines and storing them to qualify.”

It is “probably-project specific” as to whether an 80% PTC will drive repowering but there will be "a significant difference” from the 100% credit available until the end of this year, he said.

Project financing involves “highly structured investments” and decreasing the PTC value alters the investment value to equity investors, Durden said. “It will make things more complicated and structuring the financing will be more challenging.”

With a reduced tax credit, “it could go one of two ways,” he said. “The complications could drive out investors or open the door to more traditional project debt financing.”

“Utility-scale PV is too new to think about repowering right now,” Durden said. “As long as a project is producing, it is likely to stay in place.”

In the early 2020s, the 30% federal investment tax credit (ITC) for solar drops to 10%, but solar repowering does not strike Durden as practical.

“To get a second opportunity at the 30% ITC, a solar project would have to be repowered in the next few years,” he said. “It doesn’t make sense to spend $200 million to build a project and then do it over three years later, even with a big ITC.”

On the other hand, a 10% ITC has tax equity value and the efficiency of the panels keeps getting better, he added. “Ten years from now it might make sense to repower to get the 10% ITC and the higher efficiency panels.”

New, larger turbines can help repowered projects sell at lower prices and deliver savings to consumers. U.S. Department of Energy

Repowering in the real world

There are three basic types of repowering economics, according to AWEA’s Hensley.

In the majority of situations, the off-taker has the leverage because the project’s PPA has expired. “If it is renegotiated, it would likely be at a lower rate,” he said.

The repowered site may have the same or an increased nameplate capacity but, in either case, the new technology would produce more MWh and its generation would likely be purchased at a lower price. “That is clearly beneficial for the utility and its customers.”

Another possibility is a “blended agreement” in which the MWh covered in the existing PPA remain at the price set by the original contract, but new generation would be purchased at a lower price, Hensley said. “Or those MWh could be sold into the wholesale market, where prices are likely to be lower than the price used in the original PPA, at least for the foreseeable future.”

The third type of repowering is an 80/20 partial repowering of a project without a PPA, but with the advantages of a transmission interconnection and strong winds in a wind-friendly jurisdiction.

For developers of these merchant projects without PPAs, “repowering is a way to boost the lower cost MWh output sold into the wholesale market which, again, benefits utilities and their customers,” Hensley said.

Greg Wolf, CEO of Leeward Renewable Energy CEO Greg Wolf is overseeing the repowering of his company’s 52 MW, 63 turbine Mendota Hills project in Illinois. He told Utility Dive he’s not sure which financing model will cover his project.

Both the PPA and the PTC on the 2003 project have expired. Leeward is currently selling both energy and renewable energy credits into the PJM Interconnection market. It is also negotiating with original equipment manufacturers (OEMs) for hardware to repower to a higher 72 MW installed capacity, has applied to PJM for the necessary interconnection, and is talking to potential off-takers about a new PPA.

Leeward expects a 30% to 50% reduced cost per MWh from repowering and “the benefit of that will flow through to our customers, whether through merchant sales or a long term off-take partner,” Wolf said.

He doesn’t expect significant permitting hurdles. “Repowering is significantly more straightforward than building a new project because the impacts and variables are known to all the stakeholders and regulatory and permitting agencies.”

Leeward is also “investing enough money to meet the IRS guidelines by the end of the year and qualify for the 100% PTC,” Wolf said.

“It is the kind of decision many wind developers are now wrestling with,” he added. “If our regulators do not approve our application for a larger installation, we will be able to use the turbines in another project.”

Another uncertainty is whether the tax equity capital vital to wind’s growth will be attracted by a stepped down PTC, he said. But wind’s falling costs and the strategic value of project cash flow are also attractive to investors.

“If the power prices go up or the costs go down, a lower PTC might still be enough to make the project work,” Wolf said. “A $25/MWh PPA and the $23/MWh PTC make up a $48/MWh revenue-equivalent," he estimates.

With the same $25/MWh PPA and a 20% lower tax credit, there will likely be less tax equity investment. “But if project costs remain low and technology drives higher project productivity, debt investors could find projects more investable.”

In the near term, investors will safe harbor equipment to guarantee access to the full PTC “even for projects that might not be fully built until as far out as 2020,” Wolf said. “But that won’t be the whole market. There will be a good amount of wind being built that won’t have the full PTC.”

As part of its repowering of Mendota Hills, Leeward is planning to upsize the 800 kW turbines to machines “in the 2.3 MW to 2.6 MW range, depending on the tier-one OEM vendor-partner we choose,” Wolf said.

Leeward sees Mendota Hills as a near-term opportunity. “Purchasing a few extra turbines before the end of the year won’t make much of a difference because we expect to be buying the rest of the turbines in 2017 anyway,” he said.

Leeward is also buying additional safe harbored turbines for other projects, some of which will go into repowered sites and some of which may go into new projects. “We are safe harboring turbines for option value in full repowering, new development, or partial repowering,” Wolf said. “We expect to add all three flavors of development.”

For partial repowering, Leeward is also considering investing in something like retrofit kits that are sold by major OEMs like GE, Vestas, and Siemens.

“If that money is spent this year, it can be deployed in future years to capture the full value of the PTC,” he said.

Partially repowered turbines would retain the same tower and base but, working with the OEM, Leeward would replace core components like gearboxes and generators.

It will challenge Leeward’s project management skills to plan for the different types of repowering and for meeting the IRS PTC guidelines, Wolf said. “There is not a long track record for how to do this."