By Eli Katz

The market for financing solar energy equipment is still evolving as capital providers and solar developers search for cost effective ways to finance the equipment.

Most solar energy projects financed in the past few years have involved distributed energy. They have been solar energy systems that sell power to retail customers at a host location rather than directly to the grid. The next wave of solar systems coming to the market, both photovoltaic and solar thermal, are larger in scale and the electricity from many of them will be sold directly into the grid.

The lessons learned and techniques developed in financing smaller distributed solar energy projects will inform how, and to what extent the next generation of solar projects raises financing. Ultimately, the ability of solar to reach grid parity and claim its place as a viable cost-effective method of power generation will depend on whether these projects can attract financing on the scale enjoyed by wind, biomass and geothermal projects over the last few years.

Differences From Other Renewables

In the distributed energy market, the most typical arrangement is where the owner of a solar energy system retains the equipment and sells the power to a host offtaker under a power purchase agreement. These projects tend to be relatively small in scale when compared to utility-size power projects. Most of them are less than one megawatt of rated capacity. These projects are financed on an individual basis or aggregated together with a number of similar projects.

The financeable revenue streams from these projects are comprised of cash flow from the sale of power to the host offtaker, cash subsidy payments paid by state or municipal governments, renewable energy credits and federal income tax incentives in the form of tax credits and tax depreciation. The revenue stream associated with the tax incentives is worth 56% of the cost of the system.

The investment tax credit is 30% of the cost of the solar equipment. It “vests” over five years. If the equipment is sold or destroyed during this vesting period, then a portion of the credit previously taken must be paid back to the government. Solar equipment is depreciated largely over five years; 85% of the cost is deducted using the 200% declining-balance method, meaning that the deductions are front loaded into the early part of the five-year period. Tax benefits that cannot be used immediately can be carried forward for up to 20 years.

Solar tax subsidies are very different from those found in other forms of renewable energy projects, and the financing market is still refining structures that optimize these benefits in an efficient manner. Some of these differences create unique challenges as well as opportunities not available to other renewable energy projects. There are five key differences between the tax subsidies for solar and those in most other forms of renewable energy project financing.

First, the investment tax credit is claimed in the first year the system is placed in service for tax purposes. Other forms of renewable energy, such as wind and geothermal, qualify for a production tax credit that is claimed over a 10-year period.

Second, the amount of the investment tax credit is a function of the cost of the system. The tax credit can be viewed as a pure hedge against the future performance of the system; the credit is locked in regardless of how efficiently the system produces energy. Conversely, production tax credits for wind, geothermal and biomass projects have no correlation to the cost of the project; they are strictly a function of the amount of power generated by the project. The production tax credit for wind-generated power, for example, is currently set at $21 a megawatt hour of electricity output.

Third, the investment tax credit is available only to the first owner of the system. With very limited exceptions, the owner on the in-service date claims the entire investment tax credit. In a wind project, the 10 years of production tax credits are claimed by whoever owns the project when the qualifying power is produced.

Fourth, the investment tax credit may be claimed by an owner of a solar system even though the owner is not also the user or producer of the power. The production tax credit in a wind project, for example, may be claimed only by the owner of the project if he is also the producer of the electricity.

Fifth, in the distributed solar energy market, each individual project is far smaller then those that fall within the strike zone of most project financiers. The individual systems are typically aggregated together to form a more sizable investment and attract larger financing players. This has helped some, but variations between the individual projects and the resources needed to confirm that each individual project qualifies for the investment tax credit continue to challenge financing parties looking to minimize transaction costs and leanly staff these investment opportunities.

Monetizing the Tax Subsidies

Few solar developers have the tax base to use the tax subsidies themselves. To solve this problem, a developer might sell the equipment to someone who can use the tax subsidies and negotiate a sales price that reflects the tax subsidies. Alternatively, it can use one of two strategies to get value for the tax subsidies while retaining control over the project. The two most commonly used strategies are a flip partnership and a sale-leaseback.

In a flip partnership, the developer sells the solar equipment to a newly-created project company that it forms with an investor that has a large enough tax liability to make full use of the tax subsidies. The investor contributes cash to the project company to finance all or a portion of the equipment, or simply pays the cash directly to the developer to reimburse it for the cost of the system. The project company is a partnership for tax purposes. The partnership is the owner of the solar equipment and is entitled to all the revenue associated with the equipment, including the tax subsidies.

Partnerships themselves do not pay tax. Instead, the tax liabilities, tax credits and tax deductions pass through directly to the partners. The ratio in which a partnership divides its tax items among the partners is referred to as a partner’s distributive share. A partner’s distributive share of tax items does not have to correlate to its ownership percentage in the partnership. Also, the distributive share allocated to each partner may vary from year to year. Once the partnership is formed, the investor earns a preferred return on its cash investment equal to a return of its cash investment plus an agreed return on its capital (currently in the range of 7% to 8%, although returns are increasing). The investor’s preferred return is measured on an after-tax basis and is paid through a combination of cash received by the partnership (from government rebates, sale of renewable energy credits and payments for electricity from the offtaker under the power purchase agreement) and the tax subsidies that are allocated by the partnership to the investor. The developer begins to share in the partnership profits once the investor has received its preferred return.

The partnership tax rules place a number of significant restrictions on this arrangement. First, during the preferred return period, the investor cannot receive more than a 99% share of partnership tax items. Second, even after the investor receives its preferred return, it must continue to receive at least 5% of the share it was getting during the preferred return period. For example, if the investor received 99% of the partnership profits in the first few years of the investment, it must keep 4.95% of the profits (5% of its interest in the earlier period) after it reaches its preferred return.

Third, while the developer can have the right to buy out the investor’s interest in the partnership, the buyout price must be at fair market value. It cannot be set at a fixed price at the beginning of the investment.

Lastly, the amount of tax benefits that the investor can absorb from the partnership is limited by its “capital account” balance and “outside basis” in the partnership. The capital account balances and outside basis account are used to track the economic value of the investor’s interest in the partnership. Tax losses that exceed these balances cannot be used by the investor right away; they must be deferred until the investor’s economic interest grows large enough to absorb them. The investor’s economic interest in the partnership grows as the partnership earns income or as the investor contributes additional capital to the partnership. This last limitation usually comes into play when the investor makes a relatively small cash investment in the partnership. Its economic interest, as measured by its capital account and outside basis account might then be too small to take a 99% distributive share of the tax benefits.

The other way for the developer to get value for tax subsidies it cannot use is through a sale-leaseback transaction.

Such a transaction works like this. After the developer has signed the power purchase agreement and constructed the system, it sells the system to an investor and then immediately leases it back. The lease term will generally be coterminous with the power purchase agreement. The investor is now the owner of the equipment and receives the tax subsidies. The developer pays rent under the lease. The rent that the developer pays usually matches or is slightly less than the payments the developer expects to receive from selling power under the power purchase agreement. At the end of the lease term, the developer must return the system to the investor or buy it back from the investor.

Simply transferring title to the solar system is not enough to enable an investor to claim the tax benefits. The investor must be the “tax owner” of the system. To be the tax owner, the investor must generally have what the tax law calls the “benefits and burdens of ownership.” The lease term must not run longer than 80% of the expected life and value of the solar system. The developer must not have a purchase option to repurchase the system at a bargain price.

Choosing Between Structures

There are at least nine factors that drive the choice of structure.

First, the partnership model is preferable if the parties want flexibility in tailoring the size of the cash investment by the investor. In a partnership, the larger the cash investment, the greater percentage of the system the investor ends up purchasing. Where the investor is able to use the tax benefits more efficiently than the developer, then the parties will want the investor to contribute an amount at least large enough to absorb all the tax benefits in its preferred-return calculation. If the investor makes a larger cash investment than the minimum required to absorb all the tax benefits, then it will probably demand a larger residual interest after the preferred return has been achieved.

A sale-leaseback does not offer this flexibility. In a sale-leaseback, the investor purchases the entire system for its full fair value. Thus, the investor must pay 100% of the system cost. A developer that otherwise has a cheap source of capital will prefer to use the investor’s capital only to monetize the tax subsidy portion of the system and might, therefore, prefer the more flexible partnership arrangement.

Second, the partnership model allows the developer to retain a portion of the system economics — both tax benefits and operating cash flow — during and following the period when the investor is earning a preferred return. If the developer expects to have at least some tax base, it might do better to use a partnership and retain a share of the tax benefits. The developer can also negotiate for a share of the residual value after the power purchase agreement expires.

The sale-leaseback arrangement is far less flexible in this regard. The investor receives 100% of the tax benefits. There is no residual value retained by the developer. The developer retains a portion of the economics during the lease term by earning a “spread,” or the difference between the amount it receives from the power purchaser and the amount it remits to the investor as rent under the lease. There is no corollary in a lease to the “flip” in a partnership arrangements. At the end of the lease, the equipment belongs to the investor. If the developer wants the equipment back, it must pay full value for it at the end of the lease term.

Third, it is easier to monetize the tax benefits through a lease. There are no complicated partnership tax accounting rules. In a partnership, 99% of the tax benefits at most can be transferred to the investor, but the investor may not be able to absorb a full 99% share depending on the cash investment he makes. He may not have enough capital account and outside basis to absorb them.

Fourth, a lease allows up to three months after a solar system is completed to bring in the investor. With a partnership flip, the investor must be a partner in the partnership that owns the system before it is placed in service. Determining the exact day that a solar system is placed in service is not an exact science. Placed in service is generally thought to coincide with the time that the system owner is authorized to sell power and actually begins to sell the power from the system. Many investors understandably want to hold off making their investments until they can be sure that the equipment works properly. This concern leads many investors to prefer the sale-leaseback structure where they wait up to three months to invest after the system becomes operable.

Fifth, a lease differs from a partnership in another very important respect. In a lease, the sponsor will be locked into making fixed rental payments for the entire term of the lease, regardless of the performance of the equipment. If electricity revenues fall short of what is required to pay rent, then the developer will have to top up these payments or risk defaulting and losing the system to the investor. The investor may also impose financial covenants and indemnity obligations on the developer. These restrictions can limit the flexibility of the developer during the lease term.

In the partnership structure, the developer has not contractually promised the investor a fixed revenue stream. While the investor is generally entitled to take almost all the profits until it reaches its preferred return, its profits are limited to the cash and tax subsidies that come from the project. If the system underperforms expectations, the investor does not have a contractual claim against the developer, and it must wait longer to reach its preferred return. There is a flip side to this as well: if the power purchase agreement produces more revenue than the rent required under the lease, the developer using a lease structure keeps the entire upside. In the partnership model, increased performance benefits the developer in that it shortens the time period until the investor reaches its preferred return and the developer can begin to share meaningfully in the profits, but the upside is shared with the investor.

Sixth, US GAAP accounting may also motivate an investor to pick one structure over the other. Lease accounting is governed by FAS 13, which generally allows the lessor in a “direct finance lease” to report income from the lease on a front-loaded basis using a constant yield method. Investors who are sensitive to the GAAP income profile of an investment may prefer a lease structure that enables book income to be front loaded into the early years of the investment. GAAP for partnership investments generally results in a more levelized income profile using the hypothetical liquidation book value method, which allows the investor to report income each period in the amount of money the investor would receive if the investor liquidated its partnership investment in that period.

Seventh, the partnership flip structure offers slightly less flexibility to the developer in the pricing of a buyout option, but generally will allow the buyout price to be set at a lower price. Internal Revenue Service guidelines for partnership flip deals prohibit a purchase option within the first five years of the investment and require the eventual buyout price to be the market value of the equipment at time of buyout. The inability of a developer to negotiate a fixed price for the eventual buyout at the onset of the transaction deprives the developer of the ability to solve to an all-in yield that it must pay the investor for the use of its capital. The effect of the no-fixed-price-buyout rule in the partnership structure is somewhat mitigated. After the preferred return period, the investor’s interest can be reduced all the way down to 5% of its previous size. Although it cannot be fixed beforehand, the buyout price for the investor’s diminished interest should be relatively low at that point.

When compared to the partnership on this score, the sale-leaseback has one advantage and one disadvantage. The IRS has not restricted the use of a fixed price buyout in a lease. Therefore, a developer can negotiate a buyout price with the investor at inception of the lease. The all-in cost of the financing can then be calculated as the discounted value of the rental payments plus the buyout price, assuming the developer is inclined to buy the system when the buyout is exercisable. The tax rules for leasing place a limit on this flexibility through the interaction of two rules: First, the purchase option must be a good faith estimate of what the value will be when the option is exercised. Second, the system must be projected to be worth at least 20% of its starting value when the lease ends. This means the purchase price at any time during the lease must be no less than 20% of the price the investor paid for the system. This price is likely to be significantly higher that the 5% required in the partnership structure.

Eighth, most states exempt solar equipment from sales taxes. However, not all do so. Sales taxes are normally collected on rents over the lease term rather than on the purchase price of the equipment at the start of the lease. Thus, in jurisdictions that collect sales taxes on solar equipment, the sale-leaseback structure may have the beneficial effect of deferring the sales tax liability.

Finally, often the decision about which structure to use comes down to the familiarity of the investor group with one structure over the other. Traditional leasing companies, now expanding their investment services to solar equipment, will gravitate towards the sale-leaseback structure. The lease structure is perceived to offer a fixed stream of cash payments and a set residual value that should provide the investor with its desired return. Partnership flip transactions are viewed as more esoteric and require an understanding of complex modeling and partnership tax rules, offer no fixed stream of payments, and give the investor less control over the system and the developer.