Cost Basis for the ITC and 1603 Applications

Tax Basis for the ITC and 1603 Applications  

Overview and Disclaimer

The Section 48 commercial solar investment tax credit (“ITC”) provides for a credit equal to 30 percent of the “basis” of eligible property that a company places in service during the period 2006 through 2016. A tax credit is a dollar-for-dollar reduction in the income taxes that the person claiming the credit would otherwise have to pay the federal government. Determining the basis in the property is among the keys to accurately calculating the value of both the ITC and grant in lieu of credits provided under the Section 1603 Treasury Program (“1603”). It is incumbent on every member of the U.S. solar industry to be mindful of applicable tax laws and remain fully compliant with all statutory and regulatory requirements of the ITC and 1603.

This fact sheet is intended to provide a general overview of issues that SEIA members should be mindful of pertaining to the ITC and 1603. You should not rely upon or construe the information in this fact sheet as legal advice or guidance, and you should not act or fail to act based upon the information herein without also seeking professional counsel from a competent specialist.  Reliance on this fact sheet will not prevent the Internal Revenue Service (“IRS”) from imposing penalties if it takes a different view of the law. Given the complexities of the U.S. tax code, readers are strongly urged to obtain specific advice from a tax specialist. Interpretations of the tax law’s application to specific projects frequently turn on factual differences in individual cases. Please also note that, by providing this information, SEIA is not providing, or intending to provide, you or any other reader of this fact sheet with legal advice or to establish an attorney-client relationship with you or any other reader of this document. To the extent you have questions concerning any legal issues, you should consult a lawyer. Neither SEIA, nor any member of SEIA shall be responsible for your use of this information or for any damages resulting therefrom.  

Tax Basis and Tax Equity Structures

A company’s “basis” is the portion of its investment in eligible property upon which the ITC can be claimed. Basis is generally the cost of the property and, in certain circumstances, may also include a capitalized portion of other costs related to buying or producing the property (e.g., permitting, engineering, and interest during construction). In a simple example, if equipment costs $100,000, the solar credit  would be 30 percent of the cost basis of $100,000, or $30,000. If the taxpayer elects to receive a 1603 grant in lieu of the ITC, the 1603 award is calculated on the ITC tax basis. 

In many cases, a solar project developer will not have sufficient tax liability to make immediate use of the ITC. In order to get value for the tax benefits associated with the project, the developer may engage in a ‘tax equity’ transaction. Such transactions involve a partnership or lease between the developer and tax equity investor. In some cases, basis for the ITC or 1603 award is calculated on the fair market value of the project. For example, a taxpayer that buys a project from a developer in an arm’s-length ‘sale-leaseback’ transaction may ordinarily use the purchase price as its basis. In some leasing structures, such as the so-called ‘inverted lease,’ a tax equity investor leases the solar project from the developer. As provided by Treasury Regulation Section 1.48-4, the developer may elect to pass through to the lessee the ITC or 1603 award with a basis calculated on the fair market value of the project. Tax equity investors usually insist that the market value be confimed by an independent appraisal; such an appraisal is required under 1603. Part of the purchase price may have to be allocated to other assets, like a power purchase or interconnection agreement or favorable site lease, that do not qualify for ITC or 1603 payments. 

Interest paid during construction of larger solar projects that take more than a year to build and cost more than $1 million is added to the basis of the equipment. Interest paid on loans to acquire other solar equipment is normally deducted when paid and does not add to the basis. However, an election can be made under Section 266 of the tax code to fold the interest payment into the basis. Sales and use taxes are normally considered a cost of the equipment purchased and are added to basis. Items that are added to basis have to be deducted over time through depreciation, but they also enter into calculation of the ITC. 

Effect of Grants, Utility Rebates, RECs and Other Incentives

State rebates, buydowns, grants or other incentives do not decrease the amount eligible for the ITC if the company is required to pay federal income tax on the incentive. The majority of incentives must be reported as income for federal income tax purposes and, therefore, do not decrease the basis for the ITC. However, a limited class of incentives is not taxable; for these incentives, the tax basis must be reduced prior to calculating the credit.

If you are uncertain which category your particular rebate program falls under, contact a tax attorney for project-specific clarification. 

Borrowed Money

Generally, borrowing money does not adversely affect the taxpayer’s basis in solar equipment. It does not matter whether the owner of a solar project pays for the project entirely out of his own pocket or borrows part of the cost from a bank or other lender. The basis on which the ITC is calculated is what the owner paid for the equipment. Two exceptions to this general rule are:

• For investments made prior to January 1, 2009, basis had to be reduced to the extent subsidized borrowing in the form of “tax-exempt financing” or “subsidized energy financing” was used to pay the equipment cost; and
   
• At-risk limitations under Code section 465 could come into play to limit the credit that can be claimed in situations where the owner borrows to pay for the equipment cost on a nonrecourse basis, meaning on terms where the lender has no claim against the borrower if he fails to repay the loan. The only recourse of the lender is to foreclose on the equipment.  

Tax-Exempt and Subsidized Energy Financing

If either tax-exempt financing or subsidized energy financing was used to pay equipment costs that were incurred before 2009, the tax basis in the equipment must be reduced for the ITC. Basis is not reduced for depreciation. However, if tax-exempt financing is used, the project, to the extent of such financing, will have to be depreciated more slowly –over 12 years on a straight-line basis.

The basis reduction for the ITC is calculated by putting the cost of the equipment in the denominator of a fraction. The numerator is the amount of subsidized or tax-exempt financing used to pay such costs. The fraction is the percentage reduction in the tax basis. 

The IRS defines “tax-exempt financing” as borrowing through bonds issued by a state or local government.  The holders of such bonds do not have to pay taxes on the interest they receive. This means a borrower benefitting from such bonds does not have to pay as high an interest rate as he or she would otherwise. Tax-exempt financing can usually be used only for schools, roads, hospitals and other public facilities. However, the U.S. tax code makes 15 exceptions where such financing can be used for private projects that Congress believes create public benefits (e.g., privately-owned sewage treatment plants or sports stadiums). Smaller projects may also qualify for financing using “small-issue” bonds. 

The IRS defines subsidized energy financing as “financing provided under a federal, state or local program a principal purpose of which is to provide subsidized financing for projects designed to conserve or produce energy.” An example of such financing is where a state offers low-interest loans directly to help pay for renewable energy projects or where the state makes payments to a bank to buy down the interest rate on loans that the bank makes to finance such projects. 

It is important to note that the “subsidized energy financing” is the full financing extended under a government program, not just the cost to the government of the subsidy. The IRS took this position in regulations under the residential energy credit that used to be on the statute books from 1977 to 1990. For example, if a commercial customer built a $100,000 project prior to 2009, borrowed $80,000 and benefited from an interest rate subsidy on the loan funded out of a state energy program, then the basis eligible for the tax credit would be reduced by $80,000 and the credit would only apply to the remaining $20,000. No basis reduction is required for spending on a project after 2008.

Developer Fees

Developer fees are common in renewable energy projects and often included in the project’s basis. 

In the typical arrangement, the project company that owns the project pays the company that did the actual development work a fee at the end of construction. Fees of 8% to 15% on top of project cost are not unusual. Officials overseeing 1603 award applications at the U.S. Department of the Treasury indicated in 2011 that the agency focuses more on whether the final basis claimed is reasonable than on the amount of any developer fee. However, more recently, the agency has been taking a harder line on developer fees paid by project companies to affiliated development companies. The amount it will allow is a function of how much time and effort the developer put into the project and the amount of capital the developer had at risk during that period. A fee above 3% to 5% of project cost would be unusual.   

The words “developer fee” are often misused. The traditional meaning is a success fee paid by a project company to an affiliated development company that has the employees who did the development work as a reward for having pushed the project across the finish line. People also sometimes refer to the gain that a developer earns from selling a project to someone else as a “developer fee.” Many solar companies finance their projects in a way that allows the ITC or 1603 payment to be calculated on the market value of the project rather than its cost. The Treasury prefers a cost-plus approach to determine market value. It suggested in a paper posted to its website in June 2011 that it is generally prepared to accept markups in project sales of 10 to 20 percent.

Tax attorneys use the following rules of thumb for when to allow a developer fee to be added to  basis. Again, the following does not constitute formal tax advice or guidance, and you should contact a tax professional or counsel with regard to  the application of these principles to specific projects:

• The amount of the developer fee must be reasonable for the work done to earn it. A good guide is what a third party would have charged for the same services.
• The sum of the developer fee and the project cost should not exceed the fair market value of the project. The fee should not be paid out of “circled” cash. An example of circled cash is where the developer injects cash into the project company that is then paid back to the developer as a fee. Developer fees are common in many real estate projects, and they were common during the 1980s and 1990s in the independent power industry where a project company would pay the developer a fee that was often leftover construction loan proceeds or additional borrowing from a term lender as a reward for bringing the project across the finish line. 
• A development services agreement should be put in place as early as possible in the project development process between the company that will own the project and the development company, describing the development work to be done in exchange for the fee, the fee amount and how and when it will be paid. 
• The fee should be paid to a real development company with employees who did the work. It is best if the development company is not also a partner in any partnership that owns the project. The fee should not be paid to all the owners of the project in the same ratio as their ownership percentages or it may be viewed simply as a cash distribution that does not add to basis in the project.
   

Some developers have proposed having project companies pay a developer fee over time to the extent there is operating cash flow to cover it. Deferred fees with payments delayed up to 15 years are being proposed in some deals. A deferred fee does not go into basis for the 1603 grant unless it is a real debt of the project company that is fixed in amount. It should not be subordinated to cash distributions to tax equity investors. It should be paid with interest. The deferral period should not be longer than a few years. It should be clear from the base case model for the project that the project will have the cash to pay the fee on schedule. A fee that is contingent on future cash flow does not add to basis until it is actually paid.

Reduced 1603 Awards and Potential for Audits

Some solar companies have received smaller section 1603 payments than the amounts for which they applied. The Treasury has not hesitated to challenge the fair market values claimed in cases where the values seem significantly higher than the average values claimed by other applicants for projects in the same state. One solar developer who was denied a 1603 payment altogether brought a lawsuit against the Treasury in the U.S. Claims Court. The Justice Department moved to dismiss the case on grounds that Treasury has wide discretion to decide how much to pay, including not to pay any grant at all. The court rejected the motion to dismiss in January 2011. It said that Treasury decisions about the program are subject to review by the courts. Two other suits were filed in 2012 by developers who were paid smaller grants than for which they applied. 

Treasury posted a series of benchmarks to its website in June 2011 to clarify how much it was prepared to accept as the basis on photovoltaic solar projects eligible for the 1603 program after some companies expressed concern about the unpredictability of the final grant amounts. The benchmarks range from $7 a watt on residential installations of less than 10 kilowatts in size to $4 a watt for systems larger than one megawatt. These benchmarks reflect solar panel prices in the first quarter of 2011. Companies that claim a “materially higher” tax basis can expect more questions about their applications. There is no guarantee that Treasury will pay the full grants requested even where the bases claimed are below the benchmarks. The bases must be supported in each case by a credible state-specific appraisal. The IRS said in an internal legal memo that is has authority to audit 1603 payments received on projects. Thus, a developer could potentially have 1603 payments reviewed twice – once by the Treasury and again by the IRS several years later. There is also the potential for a separate audit by the Treasury inspector general.

SEIA’s Tax Resources

SEIA does not provide tax advice or guidance, but members have access to many educational resources that may be useful, including the SEIA Guide to Federal Tax Incentives for Solar Energy, regular webinars, and discounts to the biannual SEIA Finance & Tax Seminar. For more information, please contact Brandon Audap at baudap@seia.org.

This fact sheet draws on content from SEIA’s Guide to Federal Tax Incentives for Solar Energy and the March 2011 edition of Chadbourne & Parke’s Project Finance NewsWire.