Q&A with Maxwell Cohen, Associate Director at IHS Markit, Renewable Power: What Can Wind Developers Expect After 2020?

Written By: Jen Neville
January 28, 2019

maxwell cohen

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windThe Wind Power Finance & Investment Summit is widely recognized as the leading gathering place for wind industry deal makers, or as one past event attendee called it – “the highest quality of industry participants on the conference circuit.

As the wind industry continues to see a boom driven by the federal Production Tax Credit (PTC), all eyes are on what comes next. Will financing structures change after the PTC phase-out? What sources of capital will be available for the various phases of wind projects in the future? What new challenges and opportunities will wind developers see after 2020?

Today, we caught up with Maxwell Cohen, Associate Director of IHS Markit, Renewable Power, to get his perspective on how the wind industry will be affected after PTC sunsets and how developers plan to tackle some of the foreseen challenges.

Plus, we are happy to announce that Maxwell will also be presenting IHS Markit Wind Forecast at Wind F&I Summit, February 5-7, 2019 in San Diego. Don’t miss the chance to get the scoop on the latest wind industry outlook!

Our readers get 10% off attendee registration using code ICNEWS10 at checkout.

IHS Markit's Maxwell Cohen answers our questions on what the financing outlook will be for the wind market after PTC sunsets

What strategies have developers adopted to ensure that their project will meet the PTC 2020 deadline?

Maxwell Cohen: Most are focused on ensuring they have their financing, interconnection, and turbines lined up (if not yesterday then tomorrow), as well as making firm plans for balance-of-plant, cranes, and other logistics. Since most wind projects typically come online in the fourth quarter each year, anything developers can do to pull forward their construction timelines will likely help them avoid the turbine delivery bottleneck that’s likely coming in August/September 2020.

What strategies have you seen developers adopt to obtain financing after PTC has been fully phased-out?

Maxwell Cohen: We are only just starting to get an indication of how much will be built in 2022 when the 60% PTC will be available, so there isn’t much hard evidence yet of which strategies developers will use. Debt will almost certainly play a larger role. When IHS Markit models wind project economics, we assume no tax equity for projects online in 2024 and onwards and moderately lower target returns, partially mitigating the loss of the PTC.

How have the tariffs imposed by this administration affected developers’ ability to complete their projects on time? How have they affected their future wind plans? Have they driven up the cost of future wind projects?

Maxwell Cohen: Per-kW turbine prices were falling about a year ago, accounting for a large part of recent capital cost declines. Tariffs, along with demand for turbines during the PTC period, have caused a bit of a rebound in turbine pricing. Along with anticipated market contraction post-PTC, the decline in real capex is likely to be blunted in the coming decade, with more progress being made in deploying turbines with higher capacity factors. As for project timing, I don’t think tariffs per se will make it difficult to complete projects on time; the potential turbine delivery bottleneck will likely have more of an impact.

What sources of capital or financial mechanism are available for wind projects in the future?

Maxwell Cohen: Private equity, pension funds, sovereign wealth funds, funds with climate goals, and developers based outside the US are increasingly interested in participating in the US wind market. Private equity has a higher tolerance for risk and is a good source of capital for repowering projects. The other entities I mentioned may have relatively low costs of capital, which could be beneficial for a post-PTC market. If you look up at Canada, we’ve seen First Nations participating in wind projects, and those projects actually were priced lower than similar projects without First Nations investors. We think this is due to beneficial taxation and/or low-interest financing, similar to what’s available to cooperatives here in the US. So those could potentially become interesting players in the US market in the future.

Will there be enough demand for the pipeline of projects to find contracts? How will demand be affected after PTC sunsets?

Maxwell Cohen: It’s definitely a buyer’s market these days, and it will only get more extreme post-PTC. Non-utility offtake and hedge agreements depend on wind being priced at a significant discount to wholesale power, so we could see those decline relative to other offtaker types. Solar’s investment tax credit phases out on a slower schedule and stays at 10% in perpetuity, so non-utility buyers in particular will probably shift somewhat from wind to solar. On the other hand, utilities are increasingly interested in owning wind assets outright. Utility-owned wind used to be 10-20% of the market in any given year, but it looks likely to be as much as half of what’s built in 2018 to 2020. Developers with an IPP model will need to consider how comfortable they are developing and flipping projects to utility owners.

What is the financing outlook for wind + storage projects? What kind of financial structures do you see for wind+storage projects?

Maxwell Cohen: Solar plus storage is more advanced than wind plus storage in terms of deployment, so we can look there for trends that could be a leading indicator of what will happen for wind plus storage. What we find is an interesting trend in utilities experimenting with different ways to compensate the storage component of hybrid projects. Instead of just bundling the cost of storage into a traditional solar PPA, for example, NV Energy signed contracts that disaggregate the two technologies, as well as provide stipulations about the battery’s availability and number of annual cycles. As other examples, First Solar’s project for APS will only be compensated for energy delivered during peak hours, and an EDF Renewables project will receive the locational marginal price plus a flat $15.25/MWh adder. If there’s a theme here it’s that utilities seem to be thinking harder about what exactly they want from storage, and structuring contracts around that. These evolving contracting models will have knock-on effects on how financiers view the risk and attractiveness of these projects, potentially leading to different financial structures.

Thanks Maxwell!  

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