As solar has continued to mature into a viable asset class, new investors have entered the marketplace. This influx of capital has increased the number of viable financing/investment options available to developers, and has created new structures for capital deployment.
Investors are deploying capital earlier in the project life cycle, looking to provide liquidity to small and mid-size developers while justifying higher returns. Dependent on the long term goals of a developer, this capital can come in both, debt and equity structures.
Developers can now access debt capital through development/construction hybrid facilities. These structures allow developers to recapitalize and “draw” upon their margin or equity, during development and construction. This is a great benefit for small to mid-sized developers who need to fund working capital and may not have access to other means of financing. Most debt structures will commence draw schedules effectuated by a signed PPA or equivalent revenue contract.
With an increased risk profile, these structures will often have increased security requirements and costs. Investors will likely require a belt & suspenders approach to security, requiring a pledge of project assets, project co membership interests, a corporate guaranty and even a pledge of corporate assets. These facilities often use a multiple approach to cost of capital (as opposed to an interest rate) which can be seen anywhere from 1.5-2x.
For Developers looking to recapitalize their projects due to longer than estimated project life cycles, growing budgets, or increasing working capital needs, partnership “bridge” capital is available. Investors with development expertise can offer a “cashout” scenario whereby their investment gives them control of the project, while the developer continues to develop through COD. A takeout party will buy the project pursuant to the existing take out agreement, thereby paying the bridge investor. This can be a huge benefit for developers who need to cash out and redeploy capital on the next opportunity.
As with the debt structure, this bridge equity comes at a hefty price. Most structures will see multiple based returns sized at 1.5-2x+.
Both structures are being utilized by Private Equity firms looking for higher returns in the solar market, than those of long term ownership. In either structure, the relationship between the investor and developer needs to be one of trust and transparency, as the investor is taking on a great deal of development risk. If developers have access to this kind of capital, they can aggressively pursue a greater number of projects knowing their origination efforts can be met with liquidity early in the project life cycle.
For developers looking to sell their projects, but monetize their efforts prior to commercial operation, SCF can provide a milestone based payment schedule. This is not unusual in the solar market, however, SCF will also engage with developers during the early stages of development, in order to provide the developer a firm takeout and development assistance, ensuring a bankable project.
With the solar market’s exponential growth and ascension as a viable asset class, project and growth capital will continue to be available for developers, in a variety of structures.
Following the confirmation of President Trump in 2017, concern mounted regarding tax reform and the potential impact on the solar industry. One of the main benefits of third party ownership of solar assets is the tax liability savings, consisting of the investment tax credit (ITC) and the Bonus MACRS Depreciation. If these are reduced or eliminated, it would obviously have a significant negative impact on solar ownership.
Most of the solar industry agrees that the administration is unlikely to touch the Omnibus Bill that allowed for the continuance of the Investment Tax Credit. That being said, if the federal tax rate decreases from 35% to the proposed 15%, the ability to receive the full amount of the ITC in the first year (any unused amount can be carry-forward to the next year) and not receive the full benefit of bonus depreciation will be negatively impacted. The federal tax rate isn’t the only concern for the solar industry.
The following tax code adjustments could impact the financing and third party ownership of solar projects:
- Reduction in the corporate income tax rate
- Changes or Elimination of the Investment Tax Credit (ITC)
- Changes or elimination of the Accelerated and Bonus Depreciation (MACRS)
- Implementation of the Border Adjustment Tax (BAT)
The corporate tax rate is currently set at 35%, but proposed tax cuts could lower it to as much as 15%. If this were to occur it could have a negative impact on the tax equity available in the market, as banks, utilities, and insurance companies would not be able to monetize 100% of the ITC in the first year. Less tax equity in the market would create an adverse condition in solar financing.
As mentioned, in December of 2015 Congress also revised and extended the investment tax credit (“ITC”) under Section 48 of the Internal Revenue Code for solar projects. The value of the ITC for solar energy property is equal to 30% of the cost of the investment if construction begins in 2017, 2018, or 2019. The value decreases to 26 percent of the cost of the investment if construction begins in 2020, and to 22 percent if construction begins in 2021. The value of the credit is then reduced to 10 percent of the cost of the investment in perpetuity for commercial and utility installations (residential installations will be set at zero). In January of 2016, after the ITC extension, it was estimated that approximately $10 billion in tax equity would be needed to fuel solar growth over the next five to seven years. However, any tax rate reductions could reduce tax liability offsets potential investors may have, which would have a negative impact on solar financing.
Beyond the tax credits, there are qualifying depreciable renewable energy property benefits from accelerated depreciation and bonus depreciation. Under Section 168 of the Internal Revenue Code, most solar property is classified as “5-year property” for purposes of accelerated depreciation. In addition, under Section 168(k) of the Code, 5-year property also qualifies for bonus depreciation, allowing taxpayers to deduct 50 percent of the cost of the qualified property in the first year it is placed in service and the remainder is deducted over the remaining depreciable life of the property. Bonus depreciation was previously scheduled to expire, but Congress extended bonus depreciation in 2015, subject to a phasedown. The percentage that can be expensed in the first year remains at 50 percent for qualified energy property that is placed in service before 2018. It is reduced to 40 percent for property placed in service in 2018 and further reduced to 30 percent for property placed in service in 2019. After 2019, bonus depreciation is scheduled to expire. At this time, it is not clear if the Trump administrations tax plan will impact the treatment of depreciation. If this is eliminated, it could have a dramatic effect on solar installations and solar financing.
Below is an example of a company investing $600,000 in a solar project, and generating revenue of $50,000 and incurring expenses of $45,000 in the first year. In addition, the company has other revenue and expenses of $950,000 and $0, respectively. The analysis is referring to only the first year of the project, but please note that this project could have a useful life of up to twenty years. The company has calculated their tax liability for a tax rate of 35% and 15%, and wants to determine tax liability offset savings. It first must decide what depreciation method to use (Bonus MACRS Depreciation or the Traditional MACRS Depreciation). Please note that there is no carry forward for depreciation. Once this is completed, it will apply any remaining tax liability to the investment tax credit (ITC). Any unused amount of the ITC can be carry-forward to future periods.
The first step is to calculate the investment tax credit amount of $180,000 ($600,000 project cost multiplied by the 30% ITC), and the depreciable asset value to be used in the MACRS depreciation of $510,000 (Project cost minus 50% of the ITC).
Next, calculate the annual MACRS depreciation. Please note that in year one the difference between the traditional MACRS depreciation and the bonus MACRS depreciation is $204,000.
Then calculate the tax liability using both a 35% and 15% tax rate, and the bonus MACRS depreciation and traditional MACRS Depreciation.
An analysis of the data reveals the following:
- If bonus MACRS depreciation is used, a tax rate reduction from 35% to 15% would result in a decrease in tax liability savings of $82,650 (or 13.8% of the investment value).
- Using the traditional MACRS, a tax rate reduction 35% to 15% would result in a decrease in tax liability savings of $52,050 (or 8.7% of the investment value).
- A reduction in the tax rate from 35% to 15% would result in a reduced tax liability savings. Selection of a depreciation method to could be based on the ITC strategy (maximum savings in year 1 or carry forward into future periods).
Border Adjustment Tax:
A border adjustment tax (BAT), is a valued added tax levied on imported goods. It is part of the proposed overhaul of the tax code suggesting a sweeping redesign of the current corporate tax framework, which it calls a destination-based cash flow tax (DBCFT). If enacted, it could raise prices of solar equipment from foreign equipment manufacturers by as much as a 20% tax on imports. This could have an adverse effect on the demand for installations, which would also negatively impact solar financing. The adoption of the border adjustment by the United States will cause both double taxation of import flows and non-taxation of export flows, which is inconsistent with the principles of international tax treaties currently in place.
The potentially high incremental tax burden generated by the border adjustment may indeed provide sufficient incentives for companies to relocate some of their foreign manufacturing operations to the United States. However, this does not guarantee that the product costs will be as low as they were prior to the border adjustment.
Because the border adjustment is essentially trade policy affected through tax policy, it is conceivable that other countries will adopt similar tax policies, tantamount to trade retaliation. If all countries adopted a border adjustment and adjusted import and export prices to zero, a company’s effective tax rate will equal the weighted average of the corporate tax rates in each country.
The effect of this on the corporate tax burden would depend on whether net importing and large domestic market countries have higher or lower tax rates than net exporting and small market countries. If net import and large domestic market countries have higher corporate tax rates than net export and small domestic market countries, corporate effective tax rates will rise. Note that the United States has the largest domestic market, is a very large net importer, and has one of the highest corporate tax rates.
A reduction in the tax rate may not have a negative impact on deciding to invest in a solar project. The decision factors may include more than just tax liability savings, such as future cash inflows and return on investment. However, until there is legislative change and a final “bill” is approved, we cannot determine the impact. Congress utilizes the legislative process to pass federal laws; this process begins when either a Senator or Representative prepares a proposed law (also called a “bill”). The “bill” is approved by congress and then sent to the President; when the President signs the “bill”, it becomes law. During this process there are multiple hearings. The average time it takes to have a “bill” passed into law is 263.57 days so some time will pass before tax changes are cemented. In the meantime, be prepared by analyzing various tax rates and their impact on project economics.
The C&I solar sector is maturing and with it, third-party ownership is on the rise. A critical component to design and diligence of a third party owned commercial solar system is the avoided cost analysis (ACA). In order to discern a fair and beneficial PPA rate for the off-taker and estimate customer savings, the ACA must be accurate and dependable.
It would to be easy if customers were charged a flat fee per kilowatt-hour for their electricity usage. As long as the PPA rate was lower than the utility rate, the customer would save money. Demand charges add a new set of variables to the calculation, and the solar industry has been working quickly to jump the new hurdle imposed by the Utilities’ new rate plans. Effectively, the base kilowatt-hour rate has been reduced to the point where it is not often feasible to install solar based on kilowatt-hour charges alone.
Today, many solar companies use an outdated method for their ACA. They take the entire bill and divide by the usage, giving them a calculated avoided cost well above what the customer will be saving. This neglects daily, connection, and demand charges that are not billed at a kWh rate. Often, customers, installers and originators use an incorrect method and derive an inaccurate avoided cost.
The crux of the issue is calculating demand charges. Demand charges are inherently statistical. There is a probability that each electricity usage peak will be offset by solar production and a probability that it will not. Because of that, demand charges are notoriously difficult to model financially. Due to that uncertainty, the capital markets loathe to include any demand charge reduction in their avoided cost models.
But there is additional avoided cost – and understanding where it comes from will set some companies apart from the rest. Energy Toolbase and Aurora are the industry leaders, and they juxtapose Green Button and weather data to calculate the anticipated avoided cost due to solar. If you’re looking to integrate storage into your solar solution, my colleague Dan Holloway has some additional insight to share with you in his recent blog post. If you have access to that data – great; if not, it can be difficult to discern the total energy savings a solar system will create. Most avoided cost analyses simply guess, if they include it at all. The solar integrators who understand how to model these variables will quickly edge-out the competition, and have happier customers to boot.
Mergers and Acquisitions (M&A) are a vital component of the solar industry. This series will focus on the major traps in M&A, from a C&I buyer’s perspective.
The solar industry is all grown up. Mergers and Acquisitions (M&A) activity has increased gradually over the past few years, with 2016 highlighted by Tesla’s SolarCity merger. Recent industry acquisitions include module manufacturers, installers, and utilities. On a granular scale, individual projects or portfolios are acquired frequently, typically without the fanfare of larger acquisitions. SCF, a C&I Buyer, specializes in acquiring development assets, or project companies owning them.
SCF works with a fantastic group of developers (Sellers) that understand SCF’s standard processes; this allows for smoother transactions. Both parties must be cognizant of their obligations, disclose all vital information, and maintain updated data. Deals won’t close if one party simply doesn’t understand its role and obligations in the transaction.
Vague acquisition or purchase agreement
SCF acquires project assets via an asset purchase agreement (APA) and project companies via a membership interest purchase agreement (MIPA; SCF’s most commonly used structure). Common contractual shortfalls within a MIPA include indemnity clauses, default provisions, and remedies.
How does a Buyer remain protected? On the topic of indemnity, it’s important to get comfortable with the credit of your counter party. Indemnity sounds great on paper, but oftentimes doesn’t carry weight if there isn’t a balance sheet behind it. With regards to default and remedies, it’s great to have collateral as an option. In SCF’s world, we often acquire several project companies within a transaction. If so, cross-collateralizing the assets and having set-off rights can be very convenient. To assist in these efforts, SCF provides its Sellers with a form MIPA, drafted to protect both the Seller and Buyer, with clear roles and responsibilities.
Incomplete Disclosure Schedule
Disclosure schedules are a Buyer’s best friend in any acquisition. Collecting a disclosure schedule protects the Buyer in the event a Seller has not disclosed vital information pertaining to the project company. The Buyer and Seller should begin populating a disclosure schedule as early as possible in a transaction. If the Seller submits an incomplete disclosure schedule, then the Seller is taking on more risk because they aren’t disclosing details that are pertinent to the transaction (i.e. encumbrances). The Buyer could suffer damages, and then the Buyer must dedicate valuable resources to correct any problems that may arise and legal resources to seek damages from the Seller.
From a Seller’s perspective, this could be a worst case scenario. SCF assists its Sellers, prior to close, with populating the disclosure schedule, based on information the Seller previously shared. Ultimately, the Seller remains liable for an incomplete disclosure schedule; however, SCF will be a proactive partner during the closing process.
No dedicated data room
Without a dedicated data room for both parties (and all of their third party representatives), M&A is dreadful. Disorganized Sellers and Buyers oftentimes have project documents stored in Dropbox, Box, Google Drive, email, etc. Closing can be delayed by days or weeks as both parties attempt to track down previously circulated documents, while third party representatives (legal, accounting, engineering, etc.) only have limited access to documents. SCF has mitigated this trap, by utilizing a data room within the SCF Suite, where all project level data is originated. All documents required for closing are organized and easily accessible. The SCF Suite allows Sellers to auto populate SCF’s closing documents (from SCF’s templates), which reduces the transactional burden tied to each closing. SCF’s due diligence and closing checklists are automatically populated to simplify the closing process with its Sellers.
Making exceptions during diligence as a “favor”
No Buyer wants to admit it, but everyone does it. To maintain a strong relationship with a Seller, the Buyer may waive certain due diligence requirements until a later date, or completely remove the obligation. In isolation, these waivers don’t have a significant impact on the bottom line. However, if a majority of the assets acquired from a Seller have critical diligence requirements waived, then the overall portfolio carries more risk.
The above list merely highlights some of the traps C&I Buyers must avoid during M&A transactions. This is the first entry in a series of posts dedicated to M&A. Have a solar project worth acquiring? Contact us today at firstname.lastname@example.org.
Storage has long been hailed as the holy grail of the renewable energy market, as it allows for a greater integration of technologies like solar PV and wind into the electrical grid. So, a lot of people have asked why energy storage hasn’t taken off in a more substantial fashion and at a more rapid pace. The simple answer is “Bankability”.
Bankability is a term used in the renewable energy world to describe the likelihood that any particular technology or manufacturer will be funded by financiers. If a technology is new and unproven, banks and other financial institutions will be unlikely to fund associated projects until they have developed an industry track record through the performance of such technology, and have gained maturity in the marketplace.
In the case of storage, bankability has two facets. The first is the bankability of the technology itself. While batteries have been around for well over a decade, the number of large scale installations (in relative terms) is still very small. For a technology and ultimately a manufacturer of that technology to be considered bankable by the financial market, companies must have developed and constructed a sufficient number of storage projects, and accumulated enough real world operational data to prove to financiers that their systems will perform or outperform their datasheets.
Additionally, these manufacturers have to show financial stability, and a strong enough balance sheet to prove to financiers that they will be around to support the warranties that they provide with their systems. If manufacturers can meet these minimum criteria, financing groups may consider them “bankable”.
However, bankability does not only apply to the underlying technology and the manufacturers of that technology. Bankability also applies to the financial projections of the actual storage projects themselves. When a financier looks at a storage project within the commercial and industrial market, the following questions arise:
- Based on the revenues and costs of a particular project, what financial return can be earned?
- Are there any extraneous factors that could add additional costs or reduce cash flow to the project, and how can the financier mitigate these risks?
- How much does the financier trust the revenue projections presented to them both from a performance analysis perspective as well as a savings analysis perspective?
In SCF’s opinion, the last of these questions is the primary reason that storage has taken so long to come to market. The question addresses how risk factors are assessed and ultimately how the final agreements for a project are written, and requires some very sophisticated modeling to determine system performance and an analysis of projected savings. There are two primary methodologies used to develop savings for an off taker using battery storage technology:
- Demand Shaving – demand shaving revolves around the idea of shaving off demand spikes using battery storage. Shaving off these spikes lowers demand costs, which can account for nearly 50% of an energy customer’s electrical bills.
- Time-of-Use Bill Management – the idea here is that in areas where electrical rates vary based on the time of day (Time-of-Use tariffs), energy can be drawn from the grid at very low off-peak rates (typically at night when overall usage is at its lowest) to charge the batteries. This energy is then used to offset energy usage during on-peak rate times when energy costs are much higher (typically in the middle of the day when overall usage is at its highest). The difference in these two rates multiplied times the capacity of the battery then become the savings generated.
Out of the two methodologies, Demand Shaving is the more prevalent methodology used in the industry. However, the primary issue with both of these methodologies is that it they are highly dependent on the off taker’s demand load patterns and usage patterns. A customer’s demand load or usage patterns may vary from year to year based on changes in the customer’s business relating to:
- Increases or decreases in labor force
- Building additions
- Addition or subtraction of manufacturing equipment
- Addition of energy efficiency equipment or technology
- Changes in weather patterns
- Or for any other reasons
If such changes occur, the storage modeling a financier relies on to determine project economics may vary substantially from the customer’s real world patterns. This can have a corresponding dramatic effect on potential savings. With this factor looming so large, financiers have looked to third party companies to provide storage modeling software to provide them with their expert analysis so that they may rely on their numbers.
This is no different than the solar PV space. Financiers are not solar PV experts. Financiers rely on industry wide, agreed upon, solar PV modeling platforms which confirm system production with a high degree of accuracy. In this case, most financiers use PVSyst as their model of choice to confirm system production. Additionally, financiers also are not “avoided cost” experts; for this analysis, many financiers have become comfortable using Energy Toolbase as a reliable modeling tool for predicting avoided cost.
The challenge with the storage market is due to a lack of universal bankable software modeling tools. Financiers who wish to purchase or finance projects are currently looking for software platforms that provide reliable, repeatable, and accurate predictions for storage (or more often, solar plus storage) from a performance standpoint, as well as from a projected savings perspective. There have been limited options in the past for this type of modeling software, with most of this modeling being done in-house by several of the larger battery storage providers. However, there is a lot of activity in this space, and we are beginning to see the roll out of some solid candidates for platforms that the industry may soon embrace. Here are two of the top contenders:
ESyst: ESyst was recently launched by Growth Energy Labs, Inc. (GELI), and is an online platform that performs analysis and design of investment grade storage projects. It is an all-in-one package that provides site analysis, system selection, and robust financial projections for storage applications.
Homer Pro: Homer Pro is a micro-grid software modeling platform that was originally developed by NREL labs and has continued its evolution within the Homer Energy Corporation. This is a powerful modeling platform that allows users to model hybrid power systems that include storage plus solar, wind, generators and other technologies.
As the industry has time to digest these and other platforms, we believe a clear winner will emerge that will allow the investment community to embrace storage in a much broader fashion and will allow this segment of the market, which is so necessary to the continued growth of renewables as an industry, to finally thrive.