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  • Writer's pictureAlison Brown

Solar Financing

by Jasper Pakshong

Solar photovoltaic installations are historically pricey investments, but over the past few years there have been significant cost reductions that make them competitive with other renewable, nuclear, and even fossil fuel generators. A common metric to measure the competitiveness of renewables is the levelized cost of energy (LCOE). If the LCOE is equal to or less than the cost to purchase the same amount of energy from the local grid, then it is said that the renewable resource has grid parity in that region. This is an important concept as it is a strong indicator of whether a renewable development will be viable or not. In 2016, Greentech Media (GTM) reported that residential solar has reached grid parity in 20 states of the US, and predicts that 42 states could reach grid parity by 2020 under business-as-usual conditions. The recent tariffs [ brief | dive ] will alter this trajectory of course, but most analysts consider this as a temporary setback, not an industry killer. The point is that the base cost of solar is becoming less and less expensive, allowing it to compete with other forms of energy – add on federal and state incentives and you have a very attractive investment. This series of posts will aim to clarify the many terms and types of agreements / relationships used in the financials of solar (and other renewable energy) developments.

PART 1 – Fundamentals: basic consumer-developer relationships

First, there are three fundamental structures for which the end userdevelopertransactions: Cash Purchase, Power Purchase Agreement, and Lease. The following evaluates each method from the perspective of the end user:

Cash Purchase: This is just as it sounds – a complete upfront purchase of the system.

Pros: By taking full ownership of the solar system, the end user receives all of the generation, full access to whatever incentives apply, and a faster project timeline as there is no need for a third party credit evaluation.

Cons: A cash purchase is inherently the highest risk option for the end user. Full ownership of the potential gain also means full ownership of the potential risk. Without an external party managing the system, the end user will have to contract with another firm to operate and maintain (O&M) the system, or perform that work themselves. Lastly, the purchaser may not have a large enough tax appetite (ability to use the available tax credit) to take full advantage of the available incentives. In addition to these risks, because of the size of the capital investment, cash purchases usually are of residential or commercial projects.

Power Purchase Agreement (PPA): A financing agreement which allows the end user to purchase solar electricity at a fixed price (lower than local electricity prices) in exchange for hosting the project. The solar system is installed on the host site, but the host does not own the system.

Pros: Because this is merely an exchange of goods and services (host site for lower cost of electricity), there is no capital investment needed, usually providing immediate net positive returns. The fixed price also protects against rising utility prices. Unlike a cash purchase, the third party accepts the performance risk as well as O&M responsibility. The third party usually has a larger tax appetite, making it more likely for the incentives to be received in full. These savings can then be passed down to the end user in the form of cheaper electricity prices.

Cons: It can be a very complicated and long contracting process, a credit review is required, and the project timeline will be longer than a cash purchase (by a month or so depending on the complexity of the legal agreements).  Additionally, most models assume aggressive changes to utility pricing which may result in less savings over the course of the project lifetime.

Lease: Again, this is just as it sounds – the end user will receive access to a solar system in exchange for monthly lease payments. This is similar to a PPA, but instead the lessee receives direct access to the generated energy instead of a reduced $/kW price. Often, there will be an option to buy out the system towards the end of the lease.

Pros: This requires little to no capital investment upfront, making solar accessible to a wider range of economic backgrounds. This also protects against rising utility prices and usually provides an immediate net positive return. Depending on the terms of the lease, the user may assume no O&M responsibility.

Cons: This is generally the least favorable option of the three. On top of its inherent faults, their contracts are usually the most aggressive and malicious – commonly written with hidden charges, unspecified payment increases, and other unfavorable terms. This isn’t to say that a lease is never a viable option, but that the terms and conditions should be evaluated closely. A lease requires the strictest credit requirements and the most complex legal terms, therefore they will usually have the longest project timeline. The investment is also the least efficient of the three options: unless a buyout is enacted, the investment disappears at the end of the lease; the total lease payment is likely more costly than the total payment by any of the other financing means. Finally, because the lessor receives a fixed monthly payment regardless of the energy produced, the lessor assumes very little performance risk and therefore lacks the incentive provided by a PPA.

Part 2 - Programs and Incentives

Government programs and incentives have historically fostered technological innovation by increasing it’s financial viability [ brief | dive ]. While there is undeniable value in the services provided by distributed generation, like peak shaving, demand management, and demand response, the market has not yet quantified the value in potential revenue streams.  Therefore, what often makes a project viable are the available government programs and incentives. Unfortunately, the interrelations between the numerous federal and state incentives are difficult to navigate. On top of that, they can vary greatly from state to state, making it hard to determine what path is best for a project. To simplify things, in this post we will review only four of the largest and most widely used renewable programs and incentives: Net Energy Metering, Feed In Tariffs, Investment Tax Credits, and Bonus Depreciation & MACRS.


The following programs are meant to encourage faster adoption of renewable energy resources but are not necessarily meant to be scaled in the long run. Thus in general, these incentives will ramp down over time to prevent overburdening of the grid and oversaturation of the market.

Net Energy Metering (NEM): NEM is a program that allows on-site generated energy to offset the site’s energy consumption. However, unlike a standard non-export, behind the meter generating facility (GF), under NEM, all excess on-site generation can be exported to the grid in exchange for credit equal to the cost of purchasing that same energy. Unused credit at the end of a monthly billing cycle is carried over to the next billing cycle instead of being lost. There is also an option to participate in Net Surplus Compensation (NSC), a program that allows net GF’s (GF’s that produce more energy than they use) to be compensated for their overproduction on a yearly cycle at wholesale prices. Under NEM the grid basically becomes a battery of unlimited capacity, minus the ability to conduct demand management and other cost saving functions which would require control. This is incredibly valuable for desired generators as the risk of overproduction is greatly reduced. NEM programs often have a system size cap (usually as a capacity or % of load), which creates a threshold to how many credits could be generated, but it is much more appealing than the alternative of losing any excess generation.

NEM in CA: California has been a pioneer of the NEM program and the clear leader in installed NEM capacity (over 2 GW installed to date). In July 2017 CA shifted from NEM-1.0 to NEM-2.0 (which will last until 2019). This marks the first stage of its transition from the original program and adds a few important updates: (1) All customers installing a solar system will be automatically switched to Time-of-Use (TOU) rates. This means that the value of the exported excess energy depends on the time during which it was exported (i.e. energy exported during an on-peak period will be worth more than energy exported during an off-peak period), making the option of choosing when to export energy through a combination of solar + storage even more appealing; (2) there is an additional interconnection fee required depending on your utility; (3) NEM facilities are no longer fully exempt from Non-Bypassable Charges (NBCs) (under NEM-2.0, all energy delivered by the grid will be subject to NBCs of ~0.02 – 0.03 $/W).

Feed-in Tariff (FiT): A FiT is similar to NEM in that it allows export to the grid. However, unlike NEM, exported energy is sold to the grid at a predetermined price, not stored as credit. This means there is no limit to how much energy one could export to the grid. Since rapid and large increases in exported energy can cause serious strain on the grid, many utilities have built in disincentives: (1) The base price is usually lower than the purchasing price of energy; (2) most states have either a project cap or program cap to limit the gross generation operating under the FiT program; (3) some include a “tariff degression” – a tiered decrease in selling prices based on how much or how long energy has been sold in the program.


Similar to the programs above, these incentives are to create action NOW. Therefore they are limited in time and often contain degressive tiers.

Investment Tax Credit (ITC): The federal ITC permits purchasers of specific items (solar systems and battery systems are among those included) to take a tax credit equal to 30% of the investment. This is tiered down over time to 26% (2020); 22% (2021); 10% (2022+). Because solar developments can be fairly expensive, these 30% tax credits often correspond to large amounts of money in credits. Therefore, to take full advantage of the ITC, the developer must either have a large enough tax appetite (which is uncommon), or they must enter a third party financing agreement with a tax equity.

Bonus Depreciation & MACRS: Bonus Depreciation and MACRS (Modified Accelerated Cost Recovery System) are federal incentives designed to encourage and accelerate investment in private development. Each incentive reduces the timeline of depreciating an asset, reducing tax liability and increasing rate of return on an investment. Note: Projects utilizing the Federal ITC must reduce the depreciable value by half of the ITC credit (if 30% ITC is claimed, a 15% reduction or 85% total depreciable value).

Bonus Depreciation: As a response to the 2008 recession, Congress passed an Act allowing companies to depreciate a larger portion of their investment in its first year. It started as 100% bonus depreciation for capital investments put in place by December 31, 2011, but has since been extended multiple times to its most recent iteration – a tiered degression. The tiers are as follows: 50% bonus (2015-2017); 40% (2018); 30% (2019); 0% (2020+).

MACRS: Similar to Bonus Depreciation, MACRS are a method to accelerate the depreciation process. However, instead of a single year increase, MACRS allow an investment to be depreciated over a set shortened timeline. For solar, this is a 5 year recovery period, but the timeline varies depending on the technology being depreciated. The exact yearly depreciation varies (usually weighted more heavily towards the early years), but a 5 year recovery period averages to 20% a year.

These particular incentives are not mutually exclusive; a single project could use any number of the above incentives in parallel. To see how they affect each other, here is an example case:

In total, the first year tax deductions are equal to $454,700 ($300,000 from ITC and $154,700 from depreciations). This equates to a ~45% savings on your investment within the first tax year!

As you can see, these incentives lead to massive savings, showing why they can be so influential in encouraging investment. While the total amount of savings is the same regardless of the depreciation route you take, the depreciation incentives above provide the cash in hand at a much earlier date (full depreciation in ~5 years rather than ~35 years). Earlier return means quicker access to capital and in turn a quicker return on  investment. Combining the decreased cost of investment with the program benefits makes distributed generation a more valuable asset and a very attractive investment.

Part 3: Third Party Financing

In the distributed generation world, TPF is a financing structure that provides a workaround to the limits placed on tax equity funding by a developer’s tax appetite. It allows the solar/storage developer to reap the benefits of the tax equity provided by the incentives described in Part 2 (or other related incentives) by going through a third party financier. When the financier is used for this purpose specifically they are called a tax equity financier. This is accomplished essentially by the developer trading ownership with the financier (who has a much larger tax appetite). The topic of this post will be the three primary routes by which TPF is accomplished: sale-leasebacks, partnership flips, and inverted leases (summarized from Woodlawn Associates).

First, there are three primary players and a few key terms to be defined:


Developer: The solar or storage developer in charge of identifying and executing the project.Tax Equity: This is the financial party to which the project ownership is transferred in order to take full advantage of the tax credits.Customer: The beneficiary/ host of the project who will be receiving the energy or value of the energy, likely through a lease or PPA.

Key Terms

Fair Market Value (FMV): This is generally defined as the price at which an asset would change hands between a willing buyer and a willing seller given both have reasonable knowledge of all the relevant facts. There are three commonly accepted ways to determine this value: (1) income – the income that will be generated by the asset; (2) market – the cost of similar assets on the market; (3) cost – the cost to develop or replace the asset.Special-Purpose Entity (SPE): A legal entity created to carry out only a specific set of tasks. By limiting the SPE’s operations, they can isolate financial risk from their parent company, and therefore are often used for complex financing situations.


The sale-leaseback is the simplest of the three financing structures where the Developer contracts with a Customer before handing it off to the Tax Equity firm, who acts as the middleman. Steps 2 & 3 relate to the financing transaction, while 1 & 4 are standard to any developer-customer transaction.

Figure 1: Sale-Leaseback Diagram


Developer identifies Customer, signs the contract (lease or PPA), provides/ contracts engineering, procurement, and construction (EPC) for the system.Developer sells the system and the contract to Tax Equity. Tax Equity is now the owner and can take full advantage of the relevant tax incentives (ITC & depreciation).Developer leases the system back from Tax Equity at agreed upon rate.Developer charges Customer monthly fees (higher than the lease cost from [3]).


This is the simplest option.Allows full transfer of tax benefits to Tax Equity (because the purchase price associated with the tax benefits is now based off of the Developer-Tax Equity transaction, which often includes a marked up development cost, the benefits will be correspondingly larger).Minimal financing required from Developer.Buffer time between system completion and financing structure (90 days).


Most of the capital comes from Tax Equity. Because the cost of capital from Tax Equity is usually high compared to other forms of financing, this can lead to an inefficient financing structure.Depending on the structure of the Developer-Tax Equity and Developer-Customer contracts, the developer can be exposed to significant performance risk.Developer loses ownership. If they want to reclaim ownership at the end of the lease, they will have to pay FMV (contract must be structured such that FMV is 20% at the end of the lease).

Partnership Flip

Under this financing structure, the Developer (sometimes called “Sponsor” in this scenario) and Tax Equity partner to form the Project Company, a joint venture SPE made specifically to own the development and allow transfer (“flips”) of distribution of profits, cash, and benefits back and forth between the parties. The Project Company is organized as an LLC so that income taxes are paid on the entities individual corporations as opposed to the Project Company.

The “flips” provide the means for the general functions of a Sale-Leaseback, without a complete transfer of ownership. A common partnership is split into two phases. (1) The vast majority of tax benefits, profits, and losses are allocated to Tax Equity (the distributions of profit and tax benefits do not have to match). Over this period there are usually losses, which reduces Tax Equity’s corporate tax payments. (2) After a minimum of 5 years, the allocations “flip” such that Developer receives the majority of the attributes. If the flip is executed before year 5, a portion of the tax benefits will be recaptured by the government. After the flip, Developer often has the option to buy out Project Company.

There are two primary categories of these flips: (1) Yield-based flips are subject to the performance of the assets; the flip does not occur until Tax Equity meets its predetermined return – these are the most common; (2) Fixed flips are not conditional on a specific return being met, rather they flip at a predetermined date regardless of performance – these are less common and make most sense when tax rates are very stable.

Figure 2: Partnership Flip Diagram


Developer (Sponsor) and Tax Equity provide capital (majority usually provided by Developer) to Project Company.Project Company provides/ contracts EPC of system.Customer enters lease or PPA and makes associated payments.Project company distributes the tax benefits (usually ~99%) and enough cash to meet the target IRR to Tax Equity (cash is not synonymous with profit). The remaining tax benefits and cash is distributed to Developer.Assets and attribute “flip” to a new distribution after tax benefits have been used/ Developer buys out Project company.


The structure is well established and is widely used in renewables.Reasonable buyout price for the developer after the flip.There are rarely fixed payments meaning that under will not have direct monetary costs but rather will cause a delayed flip.


Requires a much larger capital investment from Developer than a Sale-Leaseback.Maintains a slight risk to the tax appetite of Developer.Developer must enter the partnership prior to the assets being installed.High overhead, especially in legal and accounting.

Inverted Leases

There are two types of inverted leases which are structured differently so they will be broken down separately. These inverted leases are basically inverted forms of the two structures we already discussed which keep ownership in the hands of Developer. The first is a Simple or Clean inverted lease and the second is a Partnership inverted lease.

Figure 3: Inverted Lease (Simple) Diagram

Steps (Simple/Clean):

Tax Equity leases the system from Developer, allowing the Tax Equity to receive 100% of the incentive.Tax Equity makes lease payments to Developer.Customer makes scheduled payments to Tax Equity.After the lease term ends, Customer pays Developer directly.

Steps (Partnership): The primary role here is to allow Developer to keep nearly half the tax benefits. For this reason it is not as favorable to Tax Equity financiers. Two new SPE’s are created in this TPF agreement, the Master Tenant and the Owner/Lessor.

Developer and Tax Equity fund a new entity called the Master Tenant (similar to the Project Company). Tax Equity funds the vast majority (~99%) of Master Tenant.Developer and Tax Equity fund another new entity called the Owner/Lessor which takes ownership of the solar system. Structured such that Developer is the majority owner (~51%).Owner/Lessor provides capital to Developer.Owner/Lessor leases system to Master Tenant, passing the ITC benefits over as well.Master Tenant subleases to Customer in exchange for scheduled payments. Master Tenant passes some of this payment to Owner/Lessor.After lease term ends, Customer pays Owner/Lessor directly.Developer and Tax Equity take ITC benefits proportional to their ownership of Master Tenant (~1:99 respectively).Developer and Tax Equity take depreciation benefits proportional to their ownership of Owner/Lessor (~51:49 respectively).


Developer keeps some of the depreciation benefits (not always a pro).Because the recipient of the ITC is a lessee and therefore has no insight into the actual cost of the project, ITC amount is based off of the FMV according to the appraised value of the transaction.


The lowest portion of tax benefits go to Tax Equity in this structure.Highest tax structuring risk.This is not a common structure and is usually unfavorable to Tax Equity.

These posts show the wide spectrum of difficulty that can be involved in getting solar financed and installed. I haven’t included all the considerations, yet it is clear a standard homeowner looking to put some panels on their roof already has some tough decisions. Further, the complexity of the decision tree for a developer of large commercial or industrial projects grows exponentially. What is the limit to cost of installation, O&M, and other overhead to meet my desired rate of return? How much funding will be required and where will it come from? Who is going to take the tax benefits? Which tax benefits even make sense given their limitations? The ramifications of these complex considerations are what determine the financeability of a project. They may not be a necessity for everyone in renewables to understand, but a grasp of the fundamentals can prove to be very useful.


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