Demand for pre-construction solar, wind, and storage projects has only increased since we released our first Renewable M&A State of the Market update this past June. At that time, our premise was that the many headwinds working against renewable energy development would result in a high volume of pre-construction projects dumping into the market come fall: a reversal of the prevailing sellers’ market. Why?
- Ongoing interconnection queue congestion across North American markets with increased deposit and/or more stringent site control and commercial readiness requirements
- Growing cost of capital, with benchmark SOF rates rising from 0.05% to over 2.95% in Q3
- Growing concerns around solar panel tariff clawbacks from February’s Commerce Department investigation into whether panels sourced from Southeast Asian producers were circumventing tariff rules on Chinese-produced PV components
- A significant elongation of supply chain lead times for everything from transformers to conduit, with delivery periods expanding from historical averages of 3 months to as long as 18 months
- A 600% growth in polysilicon prices from 2020 levels: moving from ~$7/kg to over $40/kg, pushing panel prices up from below 30c/w to 40-50c/w
These headwinds should have cast a fear over the development community and the capital markets that finance them, leading to widespread liquidation of pre-construction portfolios unwilling to maintain the carry costs in an elongated, more expensive, and more volatile environment.
Apparently, the capital markets did not get this message. PE firms continue to back renewable developers with large allocations of capital to build platforms of projects and people. Behind these, development capital providers are deploying larger funds to support development costs at the project level. Finally, the proverbial “two guys and a truck” are raising private capital from wealthy individuals and family offices, who have apparently taken to heart the growing, media-fueled sentiment promoting the opportunity in renewable energy.
Aside from this, two key U.S. policy events dumped fuel on the fire of enthusiasm in the renewables development market:
- In June, President Biden announced that he would waive tariffs on solar panels imported to the United States from Cambodia, Malaysia, Thailand, and Vietnam for two years, thereby reducing uncertainty for developers around the Commerce Department’s investigation into anti-circumvention allegations against PV component manufacturers in the region
- In August, the Inflation Reduction Act caught industry by surprise, bestowing a vast array of tax benefits for renewable energy projects and other energy transition-related items
In addition to the legacy domestic developers, European and Asian renewable companies have redoubled their efforts to enter the North American market: seeking to set up regional development shops and build project pipelines.
In this quarterly update, we have limited good news for large developers seeking to meet annual deployment hurdles through M&A. The market remains extremely tight, with aggressive pricing and deal structure reflecting the plentiful capital supporting new and old entrants.
Pre-construction Project Valuation
This quarter, LevelTen is releasing its inaugural quarterly pricing analysis for pre-construction renewable energy projects in PJM, MISO, and ERCOT. Generating this type of information is fraught with complexity and uncertainty. Our analysts have combined information from transactions we have executed, transactions we have heard about, and general market feedback from our customers. This is an inexact science with wide spreads, but, with time and greater experience, we will be able to add regions and get more granular insights from the raw data we collect.
Equally as important as the nominal prices described above are the structure and timing of payments. The traditional purchase structure — the return of capital invested at close, with developer profits delivered at milestone payments largely weighted towards NTP — is being pressured by the intensity of the demand for projects. We saw some developer profits paid at close in PJM in 2021. These upfront payments are now prevalent across North America, obviously depending on the stage and timing of the projects. Buyers should expect competition to drive closing payment in excess return of invested capital more broadly, even for early-stage projects.
The above metrics reflect solar only. Our data set for wind is too small at this time to provide meaningful analysis, but our experience suggests that these transaction prices and structures closely align with the solar metrics above. The market for pre-construction storage project M&A is immature. Transactions we have seen and heard about focus on acquiring near-term projects to get to market quickly, and prices reflect a bull market and a generalized FOMO sentiment.
Transaction Activity and Results
Over the last few years, development M&A has been used to accelerate strategic growth and gain market share. This has been one of the main contributors to extremely high demand for renewable energy assets. This, paired with limited supply, has resulted in fiercely competitive processes with historically-high premiums paid for assets. We discussed this in our last market insights blog.
Our ability at LevelTen Energy to generate bilateral opportunities from our buy-side services was robust in 2020 and 2021, but we have seen a shift towards competitive processes with a large number of NDAs being executed — even for the more esoteric and complex properties coming across the platform.
Our competitive processes are yielding excellent results. Sellers are realizing price appreciation through the auction process. The final closing price is up to 60% greater than the average non-binding offer initially received.
We have observed some of the largest renewable energy players become less aggressive in their acquisition efforts. These companies have built out large pipelines through their own greenfield development and M&A, and are now looking to optimize their portfolios and look at divestiture of non-core projects.
The Battery Storage M&A Market Exits Childhood
The passage of the IRA and its 30% ITC for standalone battery storage projects has added jet fuel to an already buoyant energy storage project development market. The industry appears to have recognized the utility of widespread storage deployment, with batteries having been noted as being supportive of emergency mitigation efforts during the heat waves in Texas and California this summer. Private equity is rolling out the red carpet for storage developers with new allocations announced each week. Finally, the construction lending market is open for standalone battery storage projects, with several aggressive loans inked in the third quarter at spreads akin to contracted solar and wind indicating a maturation of the market.
Grid-scale storage construction remains largely centered in CAISO and ERCOT due to supportive market design, but development pipelines are robust throughout North America in both vertically integrated markets and competitive regions. The M&A market for pre-construction portfolios accelerated from a standstill to a roar in 2022. Multiple mid-stage and late-stage development portfolios have been trading hands at acquisition multiples, and with structures equal to and more aggressive than the robust trades being seen in the solar and wind space. LevelTen has been active in this space, with 600 MW of storage projects closing during H1 of this year, with another 500 MW in the pipeline. High closing premiums are being realized for near-term projects (2023/24 COD), with large, sophisticated developers seeking to leapfrog the development phase through acquisitions. Sellers are at the right place at the right time in the market, and are seeing nominal developer fees of 8 to 13c/w — similar to those seen in solar.
How many renewable IPPs can there be?
The operation of power plants is a low-margin business that requires economies of scale and the mitigation of substantial complexity in a volatile market environment. In and of this, why are there so many project developers seeking to retain control of their development pipeline after COD and become IPPs?
NextEra, the largest North American operator of renewable assets, controls a total capacity of approximately 30 GW of generating assets. Such portfolio sizes decrease rapidly, with the tenth-largest renewables producer having a total operating capacity of approximately 10 GW.
There are approximately 50 conventional power IPPs in North America, competing and trading independent gas, oil, and coal plants between themselves. Most of the profits are made on the acquisition: buy low, sell high. The small IPPs outsource much of the operations to firms such as NAES or CAMS, and energy management to firms such as Tenaska and EDF.
The total generation capacity in the US and Canada is approximately 1,500 GW, which is largely still conventional thermal generators and nuclear facilities. Assuming large renewables incumbents will continue to build scale, and operating economies will demand large portfolios, some quick math on 1,500 GW of total available market indicates perhaps 50 to 100 renewable IPPs in North America.
Widespread capital availability is supporting aspirations of “mailbox money” in the form of management dividends from the operations of generating renewable projects. The industry may evolve in a similar fashion to oil and gas or the real estate industry, allowing for high-yielding private ownership stakes in small portfolios of assets or single projects. However, the actual management of the projects will concentrate into a small group of large owner/operators or independent management companies with operating, procurement, and balance sheet leverage. Creativity and entrepreneurship on the part of the developer is vested in the development of the projects — local knowledge, risk capital, and hard work — begetting 10x return profiles vs the 8-9% IRR of operating projects. Originating, developing, and delivering de-risked projects to large, capital-hungry operators will remain a winning game for small- to medium-sized players.
Time will tell who will be the winners and who will be the losers when the plethora of operating platforms start merging. Recent deals by RWE, Brookfield, and Enbridge indicate the roll-up is beginning to blossom. For those who have already invested in the operating platform, systems, and people, the future looks bright provided they can attract the vast amount of new projects coming into the market. New operators just entering the market may be left with limited return on operating platform investment.
Inflation Reduction Act
We have been diving into the Inflation Reduction Act (IRA) to understand its contents, as well as its immediate and future impacts. While there are many great components of the bill, below we focus on the renewable energy project tax credit expansion and extension and tax credit transferability and its impacts on developers and investors.
Tax Credit Provisions
Renewable energy tax credits have historically been renewed sporadically by the U.S. Senate, creating significant financial uncertainty for developers, investors, and lenders, and contributing to “boom and bust” cycles of investment and development. In contrast to this precedent, the IRA establishes a tax credit program for a full decade — providing an unprecedented degree of economic certainty for the developer community.
The IRA’s project-related tax credits come in two forms: the Investment Tax Credit (ITC), which is essentially an upfront credit based on a project’s construction cost, and the Production Tax Credits (PTC), which is tied to the energy produced by a project over its first 10 years of operation.
- Historically, the PTC has generally been considered more valuable than the ITC, and has only been available for wind projects. The IRA extends the PTC to solar projects, which can be expected to reduce the delivered cost of solar – especially for large projects in regions with high solar energy production.
- Historically, storage projects have only been eligible for the ITC if paired with, and charged by, wind or solar projects. The IRA extends the ITC to standalone storage projects, which will reduce the delivered cost of storage across the U.S.
- In 2025, the PTC and ITC will become technology-neutral, and will be generated by any non-carbon-emitting source of electricity generation (including carbon removal technologies and green hydrogen). These credits will continue until either 2032, or until U.S. power sector emissions are reduced 75% below 2022 levels. After either of these points are reached, credits will taper off over the following three years.
- Developers will only receive the full ITC and PTC values by meeting prevailing wage and apprenticeship requirements — the specifics of which the IRS has yet to provide. Falling short of meeting these standards will reduce the value of these credits by a factor of five for both the ITC and PTC.
- The current PTC for developers meeting workforce requirements is 2.6 cents/kWh ($26/MWh) of produced electricity.
- The ITC for developers meeting workforce requirements is 30%.
The IRA introduces new bonus credits that can significantly enhance PTC and ITC values for developers that meet specific requirements. Bonus credits can be “stacked” to create additive economic value. These ”adder” credits include:
- A 10% bonus credit for projects that meet domestic content requirements
- A 10% bonus credit for projects constructed in an “energy community”
- For projects under 5 MW, a 10% bonus credit for being developed in, or in collaboration with, a low-income community, or on Indigenous community lands
- A 20% bonus credit for projects that are part of a qualifying low-income residential building project
Finally, the IRA creates two entirely new options for developers and asset owners to monetize project-related tax credits beyond traditional tax equity investors:
- Transferability allows developers to transfer (i.e., sell) their tax credits to a third party for cash. Theoretically, this will significantly expand developers’ monetization options, and potentially reduce the premium associated with finding a tax credit investor/buyer.
- Direct Pay is even more valuable than Transferability, allowing select organizations to cash in their tax credits directly to the federal government for their full value (rather than a Transferability sale, where the buyer would be expected to pay a discount vs the face value of a credit). However, direct pay in the IRA is relatively limited in scope, available only to non-profits, state and local governments, electric cooperatives, Indian Tribal governments, and Alaska Native Corporations.
Immediately following the IRA’s passage, we saw restructuring of deal terms to include tax benefit cost-sharing. These changes will dissipate as the tax credits become better known, and will be incorporated into asset valuations moving forward. We will most likely see construction timelines shift into 2023, as projects that reach COD next year may be able to achieve bonus tax credits.
We have observed in the market conflicting views on the value of tax credit transferability. Generally, market participants agree that transferability will be a boon for distributed generation projects that have struggled to access the traditional tax equity market due to low standardization and high due diligence transaction costs. However, the verdict is out on the value for utility-scale projects. Transferability does not provide for monetization of MACRs in the structure versus traditional tax equity, resulting in comparative loss of value. Many developers have suggested this will mitigate the enthusiasm to use the structure in utility-scale projects. Others, however, are suggesting that the value lost from booking MACRs is offset by the reduced complexity of the structure, plus improvements in project debt metrics (see below). Ultimately, the market will determine the break-even point between the two. In any event, the credit transfer option, even if not competitive across all projects and developers, will put a price floor on the value that tax equity providers can demand, and likely improve the competitiveness of what has historically been an oligopolistic market for tax equity.
Of interest will be the evolution of the project debt market. Traditionally, tax equity providers have required project debt to be structurally subordinated to the tax equity (holdco debt or back leverage). The credit transfer will likely eliminate this requirement, allowing project debt to be structured at the project company. This should improve terms, allowing for both increased leverage and reduced interest rate spreads. These improvements may offset any value slippage associated with a credit transfer.
Tax indemnities are another area impacting capitalization structures. Whether the IRS can still challenge the amount claimed and recapture any deficits in the event the project is taken out of service remains an open question. The buyers of tax credits will likely require tax indemnities from the project, and the project or sponsor will need to provide adequate assurance of payment to ensure the tax credit market remains low risk. The interaction of the rights of the indemnity provider and the project-level debt will need to be worked through.
Previously, storage could only qualify for ITC if it is paired with an ITC-eligible technology — most often solar or wind. Prior to the IRA, we saw an increase in the number of standalone storage projects that were being offered for sale. Adding the ITC improves project economics, leading to even more standalone storage projects entering the market in more disparate regions such as WECC, SPP, and MISO (vs CAISO, ERCOT, New York, and Massachusetts).
While the IRA is a big step in the right direction, it will not immediately lead to an increase in the number of projects available. There are major structural problems hindering industry growth including supply chain issues, ongoing anti-dumping/circumvention concerns, an aging grid, and major permitting and interconnection delays. The new domestic manufacturing investments included in the bill will, over time, result in facilities to help meet demand. We most likely will not begin to see the full impacts of the Inflation Reduction Act, and the acceleration of renewable energy project supply, until 2024.
As the pace of renewable development accelerates, more people are entering our industry every day — making accessible educational materials more important than ever. We outline the six foundational pillars renewable energy developers must navigate in bringing their projects to market in our Six Pillars of Project Development guide, available here for free download.
LevelTen’s Asset Marketplace: Your Key to Success In Today’s Market
In today’s fast-paced and highly competitive market, every advantage counts. LevelTen Energy’s Asset Marketplace connects clean energy project developers and financiers, and provides the software, analytics, and M&A transaction expertise they need to execute transactions quickly. Our team of M&A experts are ready to help you make the right move at the right time. To learn more about how your organization can leverage the LevelTen Energy Asset Marketplace, contact Patrick Worrall at Patrick.Worrall@LevelTenEnergy.com, Clare McReynolds at Clare.McReynolds@LevelTenEnergy.com for North American opportunities, or Carlos Almodovar at Carlos.Almodovar@LevelTenEnergy.com for European opportunities.