RISK: Increased PPA pricing environment could lead to COD delays in 2022
A convergence of factors is forcing renewable project developers to push projects towards 2023, with the industry increasingly viewing 2022 as a bumpier year.
Supply constraints and labor shortage have contributed both to a rise in project prices and a corresponding rise in PPA prices. However, some developers who inked PPAs in the past few years with a view towards a 2022 COD could be looking at some of those projects now at risk of being unprofitable.
How developers will cope with the situation will vary since there is still a reluctance among some shops to renegotiate PPAs given both the reputational risk associated with doing so and the plethora of options on the table for potential offtakes.
“[Rising] costs are often passed through as changes to PPA rates and terms, though certainly not always and in any event, not usually a full pass-through,” said David Riester, Founder and Managing Partner of renewable investor Segue Sustainable Infrastructure.
PPA pricing is difficult to generalize as solar and wind prices will vary in different ISOs. LevelTen Energy created a P25 National Index which shows solar prices increased 14.7% to USD 33.25 per MWh in 3Q21 on a year-over-year basis, while wind prices increased 19.1% to above USD 26.00 per MWh in 3Q21. LevelTen’s “National Index” represents the P25 value across all its markets, irrespective of ISO. Other market participants have seen in upwards of 25% in PPA pricing increases in certain regions during that same period.
The projects slated to go COD in 2022 are the most at risk at this point. In these cases, developers and offtakers usually negotiated a PPA upwards of two years ago under far less dire circumstances where manufacturing costs were at a low ebb. This has caused some concern that those agreements might now be underwater for developers.
“We’ve heard some utility-scale PPA pricing that was locked in prior to supply chain issues is now not going to pencil or be profitable to build. That means developers may need to either delay projects to wait for costs to correct or go to offtakers to renegotiate PPAs. In our experience, utility-scale projects are very sensitive to EPC price changes. We have heard some utility-scale PPAs are being renegotiated given the current situation,” said one investor in renewable generation.
Aside from renegotiating, another tactic has been to simply delay COD until the pricing environment starts to level off. There is an expectation this could occur in 2023, but it is still very unpredictable.
One mechanism, for instance, which could cause a rollback in pricing is if the PTC tax credit in solar is reinstated. Separately, the bill also incentivizes domestic supply production which is a huge ask of both the solar and storage industries struggling with supply chain bottlenecks in China. These provisions are included in the latest version of the Build Back Better Act, but of course, the bill’s approval and final language remains in abeyance before the US Senate, after the US House of Representatives cleared the bill earlier this year.
The Perfect Storm
The price to develop solar and wind farms gradually went down in recent years thanks to technological improvements and increased capital support. However, that trend reversed in 2021 on multiple levels.
On the manufacturing side, developers are being hit by disruptions in the polysilicon supply chain in China. Polysilicon manufacturers are being hit by allegations of forced labor, while also being imposed massive tariffs by the US on exports. The current spot price for polysilicon is USD 35.42 per kg up from below USD 12.00 per kg at the start of January, according to German-based research firm Bernreuter Research.
The net effects include US renewable developers renegotiating supply contracts, while others are rethinking module suppliers all together, according to a survey conducted by LevelTen.
Past that, there are supply bottlenecks effecting all shipping imports due to the likes of COVID and labor shortages.
This has not stopped the demand side as public utilities and private corporations alike continue to source for renewable energy to meet federal and state mandates, as well as incorporating a stricter ESG focus into their broader practices. While institutional capital has helped jumpstart the growth of solar and wind developers, they are all vying for the same capacity which is now causing bottlenecks of its own.
All told there is 402 GW of solar projects, 226 GW of storage and a combined 224 GW of onshore and offshore wind projects, which are pre-operational, and registered through the interconnection queue and utility queues, according to NPM data.
“Regulated utilities and corporations are ramping up renewable energy procurement at the same time. The constraint is no longer demand; it is often the interconnection queue,” said Eamon Perrel, Senior Vice President at Apex Clean Energy adding that “with all of the projects competing to supply this demand, the interconnection queues have become overwhelmed and what used to take a few years now takes much longer.”
The transmission system owner or regional grid operator must approve the impact that a new project’s added capacity will have on the grid. This is done through a series of sequential, technical studies to quantify the cost and timeline for building out any required grid enhancements to accommodate the new renewable energy project, according to LevelTen.
The build-up of projects has created bottlenecks, particularly in the vast PJM Interconnection region—spanning from Illinois to Virginia--which has 131 GW of solar projects in the queue.
The PPA
The developers, hamstrung by higher capex costs and interconnection bottlenecks, have been able to pass on prices to customers in the form of higher PPAs in some instances. Questions remain though on how this has affected the dynamic between developers and potential offtakers.
“Developers have fought hard for limited price re-openers, but they have to provide evidence the cost has gone up and therefore they would have to justify not just on cost basis, but profitability on project has decreased to a certain percentage,” said a source familiar with the situation.
This places a much heavier burden on developers, particularly when negotiating corporate PPAs, as they have not been able to command terms as they had previously with utilities.
“I would love to see the market shift a bit here where offtakers take a little more accountability and responsibility for doing their work to validate project viability, while relying less on oversized deposits meant to do that work for them. Posting a deposit probably says more about how large of a company the developer is, than it does about project quality and viability” said Segue’s Riester.
Cypress Creek’s Chief Development Officer Noah Hyte has seen PPAs start to incorporate more termination rights making them more developer friendly, since off takes are really motivated to get these projects done, particularly around certain communities. Offtakers, also, have bought into the tax equity of those projects as another incentive in deregulated markets.
Corporates also have to deal now with scarcity in terms of finding the right project and that has also contributed to higher PPAs.
“The constraint today is quality projects, not offtake,” said Hyte, adding that corporates are pushing hard on both renewables and renewable energy certificates (RECs).
“For PJM and ERCOT, there has never been more diversity of choice, if you are investing the right products and relationships within the varying types of offtakers,” added Hyte.*
*This story was originally published exclusively for NPM subscribers earlier this month.