Right now, there are many aspects of clean energy development that make it a turbulent time for developers. Low interest rates for decades meant that borrowers could take on cheap debt to build projects while power purchase agreements (PPAs) locked in good financial returns. Those days seem long gone. In mid-April, the Fed announced plans to raise the federal funds rate to between 4.75 –5 percent, the highest level since 2007. To combat inflation, the Fed has increased rates nine times since March 2022. PPA prices have risen, and contract terms are less lucrative. In fact, PPA contracts signed today will be lower in project value because PPA prices are rising, resulting in a net cost to the buyer over the project term. As one data point: 2022 fourth quarter solar energy PPAs were 33 percent higher than the year before and 8 percent higher than the third quarter of 2022.
Construction costs are higher, driven by supply chain delays and trade policy uncertainty. Interconnection bottlenecks are extending project timelines further and further into the future; the estimated timeline from interconnection request to interconnection approval is four years in 2023, almost twice what it took a decade ago. The Berkeley Lab Electricity Markets & Policy reported that more than 8,100 energy projects, primarily wind, solar, and energy storage battery projects, were waiting for permission to interconnect with electric grids at the end of 2021. The PJM Interconnection queue is frozen until 2026 based on the total volume of projects. We previously outlined the FERC Notice of Proposed Rulemaking (NOPR), not yet final, which seeks interconnection reforms such as the “first ready first served process” to make the transmission interconnection process smoother.
In addition to the interconnection delays, the costs of upgrades to connect a new project to the grid has grown from 10 percent of the project cost to 50 percent or more of the project cost. Stakeholder groups between developers and utilities are trying to hammer out how these costs should be allocated. ISO New England, for example, is clustering projects together so that interconnection study requests can be grouped together and share costs for interconnection related transmission upgrades. This is a step in the right direction and one that other regional ISOs are exploring.
These issues are creating turmoil for project developers, even with the headwinds of the Inflation Reduction Act. How can projects get financed, given long interconnection queues, costly grid upgrades, and less lucrative offtake agreements? In many cases investors are taking over renewable energy projects to stave off construction risks, keep projects on schedule, and earn a stable rate of return. Developers are selling their assets early, sometimes even pre-construction. Are these the only answers?
Leyline’s Answer To These Challenging Times
The available solutions to the developer’s clean energy project conundrum are much fewer in today’s climate. Previously, in a cycle of low interest rates, developers could find an asset, buy, build, de-risk and then sell based on the expected future cash flows. Now transactions don’t follow this pattern; offtake agreements are less attractive. There are essentially three options for developers: (1) sell assets; (2) entertain an equity investment; and (3) take on non-dilutive capital. Let’s consider each of these.
The first option developers might consider is to simply sell assets to generate cash, even pre-construction. Many developers are already actively trying to find buyers, creating an abundance of supply and therefore a buyers' market. This results in a lower return on investment because projects are being sold earlier than they would be otherwise. Put simply, when projects are sold earlier in the development process, they are worth less. There is plenty of data to show that this option is being exercised, even among the large utilities. Duke Energy is selling its commercial renewable energy business – 5.1 GW of wind and solar projects, and a development pipeline of 1 GW.
Rather than selling projects, some developers will consider taking equity investment in their company to generate immediate cash reserves. While this will carry project assets further along in the development cycle, it is a total loss of control and future returns. In fact, there is less private equity investment now – it is the lowest for the first quarter of 2023 since 2020, during the height of the pandemic. Figure 1 below illustrates this trend.
Developers might think about more debt, but without knowing how long the cycle of turbulence remains, having more debt on the balance sheet of a company directly impacts a company’s valuation for any future equity raise.
There is also another option for developers with non-dilutive capital. This option is in some ways a blend of equity and debt. The developer does not have to give up equity in the company, which is important for startups, because they don’t want to dilute future profitability. The developer can take on debt for the project and repay it based on expected future revenue. Hence the blend of equity and debt.
A financial services company will lend capital to a developer, and the firm will receive repayment via proceeds from the projects when they are sold. In this situation, both the risk and reward for a project or a portfolio are shared by both the developer and lender.
Option #3 is where Leyline Renewable Capital comes in. Developers have choices beyond selling assets early, giving away more equity in the company or borrowing more money. We allow developers to keep their equity, manage their portfolio of projects, and own their project and its future. We are a team of former developers, and we understand that world, even when it is turbulent. If want to explore non-dilutive capital for your project, please contact us at https://leylinecapital.com/home/contact.
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