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August 13, 2020

A Deep Dive on PPA Terms Across Energy Markets: Key Considerations from K&L Gates

Edison Energy’s Visionary Voices: Perspectives in Energy Series features conversations with leading experts from across the industry. These thought leaders are driving innovation in energy markets and available solutions for commercial, industrial and institutional energy buyers. Their diverse perspectives and experience offer a real-time view into the transformation happening in the market today.



Teresa Hill is a partner at K&L Gates, a global law firm, where she focuses her practice in the areas of energy and infrastructure projects and transactions with an emphasis on wind, solar, biomass, geothermal and hydroelectric power. Teresa advises clients in the negotiation of development-related agreements, with an emphasis on negotiating major power purchase agreements. Teresa spearheads the K&L Gates Corporate Energy Sourcing initiative, which helps corporate customers develop and implement sustainability and carbon goals through their energy strategy.

From your perspective, what are the PPA terms that are generating the most discussion and negotiation today?  Has this changed in the last 12 months or more recently due to COVID-19 concerns?

There are typical terms that are always negotiated – credit, pre-commercial operation risk, environmental stewardship and managing reputational risk. As you would expect, we are seeing a lot more negotiation over force majeure risk and a lot of scrutiny around what qualifies or doesn’t qualify for a COVID-19 delay. Another interesting development over the past year has been the introduction of new basis risk mitigation terms. There seems to be a rebalancing of basis risk. For the early corporate virtual PPAs, some corporations signed deals that settled financially at the project node, so the buyer was exposed to the risk of congestion and pricing risks specific to the project location. Buyers soon recognized that settling at a liquid settlement hub reduced these risks (for buyer but shifted these to the seller). Seller was allocated the “basis risk” – that is the risk that the price at the node (where the seller will receive the market price) would be inconsistent from the price paid by the corporate buyer under the contract, and the amount seller would owe to buyer under the settlement. If the price between the node and the hub is too great, the seller is incentivized to shut down the project (economic self-curtailment) to protect themselves from this basis risk and the buyer not only loses the settlement, they do not get the renewable energy credits needed to support their environmental claims. Recent transactions have included mechanisms to recalibrate this risk and bring the parties’ incentives into alignment by shifting the settlement in certain scenarios to protect seller from extreme basis risk, while incentivizing them to produce so that buyer receives some settlement (even if reduced) and the renewable energy credits.

How are clients dealing with the challenge of unknown project timelines given COVID-19 that balance the developer’s needs and buyer’s needs?

These discussions are very fact specific and have evolved quickly as the COVID-19 impacts have changed over the past few months. For executed contracts, buyers have been very cooperative and understand that the goal is to bring more renewable resources onto the grid and some developers were truly sideswiped by pandemic related delays. For contracts under negotiation, buyers must rely on the expertise of experienced developers to adjust their timelines based on what we know now. Typically, we are seeing force majeure provisions that allow for extensions due to unknown impacts of COVID-19 going forward but try to limit claims based on the “current” impact, since the developer should be building those into their deadlines. The most encouraging thing I have seen is that corporations are continuing to set aggressive goals and go after them, even in this time of uncertainty. If anything, the dedication to these projects is stronger. It is great to wake up every day and walk to my home office, thankful to be safe at home working on transactions that have a lasting impact. I get the sense everyone working on these deals (on both sides) shares the same sense of purpose and gratitude.

As more corporate buyers move from executing transactions in the US to Europe, how similar are the PPA terms?  Are there areas where the terms are more buyer friendly in one region over the other or less buyer friendly?

We are seeing a lot of interest in Europe this year, primarily with clients who have already done transactions for their US load and are looking at Europe for their next transactions. So far, we have been able to successfully use their US transactions as the precedent document and have been able to carry over a lot of the terms from the US deals. This is a great benefit to the corporate clients since it reduces the internal burden to re-educate their stakeholders about the transaction structure and allows for some consistency among their global portfolio. Unlike US developers, which are getting accustomed to the unique asks of corporate buyers, a lot of European developers are doing their first corporate PPAs, so there is an education process required – similar to the first deals in the US markets. I haven’t personally seen regions that are particularly buyer-friendly (or not) regarding terms but like the US, I think we will start seeing clusters of PPAs in the regions where the economics are more favorable. I expect a lot of these deals will be announced over the next year, so we’ll know about how that market is shaping up in 2021. Corporations with global renewable goals are also taking their lessons learned in the US and going into LATAM, Australia and Asia to do deals and influence markets. It’s exciting to see the work everyone has done in the US be applied around the globe.

Are you seeing shifts in market preferences for wind vs. solar? How has this impacted terms, if at all?

We are seeing a lot of solar deals recently, which I am sure is largely based on economics (I haven’t had any client say they have a preference for solar over wind for any other reason than project economics so that is most certainly the driving force). Terms are largely that same between wind and solar projects, although solar typically has a shorter build timeline. The performance metrics (availability or performance guarantees) are more complex for solar and do not seem to have settled on industry standard terms in the same way that wind has.

Have you started to see storage paired with renewables projects, and what unique considerations should be made in this type of arrangement?

Yes, solar is commonly paired with storage because, if it is properly integrated (at least 75% of charging energy comes from solar system), it’s eligible for ITC. Storage + solar is increasing common in transactions with utility offtakers. Wind and storage are rarely paired because storage economics work better when supported by an ITC rather than a PTC. Storage + solar has been used less often in corporate transactions, but we are seeing the first of these transactions and expect more.

Do you see contract terms becoming more standardized, or more customized?

Different offtakers structure and phrase contracts somewhat differently, so they are not standardized in the same sense as an ISDA or the EEI form, but they are becoming standardized in the sense that more and more contracts are dealing with a discrete set of issues, such as performance guarantees and negative pricing in a fairly predictable set of ways. A few years ago, developers would often approach corporate buyers in the same way they did their utility buyers and the process was sometimes painful to get all of the parties on same page. Now, most developers understand the unique needs of the corporate buyers and the unique terms required to meet the corporate buyers goals. This has streamlined (and standardized) a lot of the discussion about Dodd-Frank requirements, accounting treatment and reputational risk.

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