A lot of press has been written lately related to California’s aggressive new policy to promote a 100% RPS by 2045. This issue has become much more relevant in light of President Trump’s recent decision to pull out of the Paris Climate agreement. Essentially, states are looking to supplant the Federal Government in the area of addressing Global Climate Change. As David Hochschild of the California Energy Commission recently stated, “ California has the sixth largest economy in the world and is home to 40 million people – we’re larger in many metrics than most countries in the world. I think particularly given recent events, leadership on the renewables has shifted to the states.” This is a very telling statement, because it says to the rest of the world, if the U.S. Federal Government will not step up, many of the largest states (by both geography and population) in the U.S. are not going to wait for them. States are going to continue to push policies that promote renewable energy and to increase the amount of energy coming from renewable sources.
That being said, as many have chimed in already, the reality of an energy grid being powered by 100% renewable energy is fraught with hurdles. Many of those hurdles are “supply side” issues related to the intermittent nature of renewable energy and the inability of today’s energy grid to balance the supply and demand of that energy production through the use of large utility-scale storage. Many have written on this topic extensively, but few are discussing the “demand side”. It’s one thing to build a grid that can support the use of 100% renewables. It’s quite another to fund the implementation and construction of those energy assets. To date, the vast majority of solar PV systems that have been installed in California have been either residential or utility scale systems. If we assume that the residential sector represents 15-20% of the overall market and the utility sector at 30-35%, we would only get to 45-55% of the total available market. The lion’s share of the usage of electricity comes from the Commercial and Industrial (C&I) sector. Why then, don’t we see the majority of solar PV installations coming from this sector? The simple answer is that this is the least funded sector from an investment perspective.
Solar PV is an expensive proposition and while many companies have a strong desire to adopt renewable energy, they also prefer to use their CAPEX budgets to build and support their own businesses, rather than funding long-term renewable assets. Solar City learned this lesson many years ago when it started in the residential market. Once they began offering low-cost, long-term financing to support solar PV, their sales soared. The C&I market is no different. Without a systematic, well-funded financing program for C&I assets, this market will languish. What makes matters worse is that by almost all accounts, this sector is (by far) the largest segment of the market, and has the least amount of penetration. So, one could ask the question, without a robust financing solution for the C&I market, how can California hope to reach their new 100% RPS target? The answer is, it is likely impossible.
Defining the C&I Space
To put some bounds around this problem, most would define the C&I sector as both for-profit and non-profit entities with solar PV system needs in the 50 kW to 5 MW space. However, the vast majority of systems needed in the C&I space are in the 50 kW to 500 kW range. Think of schools, churches, municipal buildings and local businesses. Just like the residential sector, without a financing mechanism, the total available market may drop from 50% of the total to less than 10%. The number of companies offering financing for solar PV systems below 500 kW is incredibly small, with most offering short and medium-term loans (which reduce the borrowing capacity of the off-taker), and some offering 7-10 year operating leases (which are economically challenging). What is truly needed to get this huge chunk of the market jump started is a third-party ownership model that offers Power Purchase Agreements (PPAs) and/or Solar Services Agreements (SSAs), targeted directly at the smaller end of the C&I segment. If this is such a large percentage of the market, and such an obvious target for financing companies, why aren’t there more solutions? The short answer is credit, and soft costs.
Determining the credit quality of an unrated off-taker is a labor intensive process. The way the residential sector was able to overcome this was by adopting the FICO score which has been used for decades by those providing personal credit and home loans. Everyone has one, so it was easy for residential giants like Tesla Solar and Vivint to adopt this. However, for the C&I sector, no such rating system exists. Some small percentage of entities in the C&I space do have public credit ratings (think Walmart, most municipalities, and some schools), but the vast majority do not. Determining a systematic and efficient methodology for assessing credit is the first major hurdle to solving the C&I financing puzzle.
The second major challenge for the small end of the C&I market is soft costs. These include legal fees for contract review, real estate expenses (like title searches and land surveys), accounting expenses, independent engineering costs, and many others. To get a financing institution comfortable with any project requires a lot of due diligence and documentation. Financiers want to make sure that all of the legal documents that are being implemented have been reviewed and verified by legal experts with a strong competence within the solar PV arena. They also want to know that systems are built with quality components (Tier 1 solar modules, for instance), and that systems are built to meet National Building Codes like the NEC. They also want to know that the owner of the property where the system will be installed has clear title to the property. All of these services can be expensive because they are labor intensive and need to be performed by high-paid professionals. Many companies spend between $30,000-100,000 (possibly much more) to process a PPA project, regardless of the size of the system. If you were to look at financing a 100 kW system that cost $2.50/watt to build, the total cost of that system would $250,000. If you needed to add another $40,000 in soft costs to that system, you are essentially adding $.40/watt or 16% to the build cost, and in most cases, are killing the deal. To truly solve the issue of soft costs requires a standardized approach to the C&I sector. Financiers that want to pursue this space need to push the same level of standardization as we are seeing in the residential market. Here is a short list of items that will need to be standardized before soft costs will begin to come down:
- Standardized Contracts – first and foremost, projects in the C&I sector need to start using a standardized set of documents including PPAs, EPC agreements, Site leases, and an assortment of other documents. The C&I sector needs to take a page out of the residential playbook by using repeatable documents rather than the “one-off” approach that most Developers and EPCs follow. Throwing legal dollars at a new set of contracts, or incorporating major overhauled revisions from a counter party, for every project is a recipe for disaster.
- Verification tools – another key aspect of financing solar PV projects is being able to verify key metrics like system production and avoided cost analysis. Choosing industry accepted tools like PVSyst to verify system production, for instance, and getting everyone to standardize on these tools is vital to creating efficiencies and lowering costs.
- Design – system design is becoming a hot topic in the online software market. There are a handful of new companies that are supporting online design services that not only provide the ability to quickly and accurately design systems remotely, some also provide production analysis, shading analysis and even avoided cost analysis. To the extent that these tools become accepted by the general industry, there will be a strong push to choose a standardized approach to the design aspect of the process to improve overall efficiency in design review.
There are many additional areas that can be improved by standardization, but these are some of the key areas that will need to be addressed. In essence, the goal of financiers that want to pursue the C&I sector should be to make small C&I look as much like the residential space as possible. Without a substantial and systematic financing solution for the C&I market, I believe that California will struggle to meet its 100% RPS goal.
SCF, with EPC services provided by Vista Solar, recently completed several new solar PV systems for the City of San Joaquin, in California. The project is comprised of three separate systems on three unique parcels located within the city. The installs include a ballasted roof mount, a ground mount and a carport, with an aggregate system size of approximately 200 kW. The project serves as another example of SCF’s commitment to support municipalities, and the C&I marketplace.
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.