Tax Issues and Incentives For Windpower Projects

Tax issues and incentives for windpower projects

December 01, 2002 | By Keith Martin in Washington, DC

The US government offers two significant subsidies through the tax code for generating electricity from wind. They reduce the cost of a project by almost 65%. State incentives reduce the cost on average by another 10%.

The problem with tax subsidies is smaller developers who tend to develop wind projects often lack the tax base to use them. There are several ways for developers in this position to get value for them or — put differently — there are tax efficient ways for institutional equity participants who want to acquire windpower projects to bid on them.

The main subsidy is a tax credit of 1.8¢ a kilowatt hour for generating electricity from wind. This credit goes to the owner of the project. It can be claimed on the output for the first 10 years after the project is first put into service. It is worth about 33.5¢ for each dollar in capital cost. For example, an 80 megawatt project that cost $88 million to build might expect a subsidy on the order of $29.46 million. This is the present value of the tax savings from 10 years of credits. (The calculation assumes the typical project costs about $1.1 million per megawatt to build, and each megawatt of capacity leads to output of 3,329 megawatt hours a year. It uses a 10% discount rate to distill the tax savings to a single figure.)

The other subsidy is the ability to deduct the cost of the project over five years as tax depreciation. In addition, new projects that are completed during a “window period” running from September 11 last year through December 2004 qualify potentially for a 30% “depreciation bonus.” The depreciation without the bonus produces about 29.77¢ in tax savings for each dollar of capital cost. The depreciation bonus adds another 1.57¢.

Section 45 Credits

Wind projects have qualified for a tax credit on output since 1994. The credit was originally 1.5¢ a kilowatt hour, but has increased to 1.8¢ due to inflation adjustments. The figure 1.8¢ was the credit for electricity sold during calendar year 2001. The Internal Revenue Service will not announce the figure for 2002 sales until next spring.

Projects must go into service by December 2003 to qualify. Congress is expected to extend the deadline. Both houses of Congress voted to extend it to December 2006 as part of a national energy bill that President Bush made a priority to get through Congress this year. However, House and Senate negotiators have been unable to reach agreement on a final bill to send to the president. The deadline could still be extended this year if Congress returns after the elections for a brief “lame duck” session in late November and December. The odds of an extension next year are good if there is none this year.

New Projects

Only “new” projects qualify for tax credits. The credits run for 10 years after the project is originally placed in service.

It is possible by spending money to upgrade an existing facility to improve it so significantly that it is considered “new” with the result that another 10 years of tax credits can be claimed on output. The IRS said in a 1994 revenue ruling that it would look at each unit of a turbine, tower and pad as a separate facility, and it would treat each such unit as brand new — thus qualifying for 10 years of tax credits — if the cost of the upgrades accounted for more than 80% of the unit’s value after the renovations.


The credit is subject to a “haircut” to the extent the project benefited from tax-exempt financing, federal, state or local government grants, other tax credits, or “subsidized energy financing.” An example of subsidized energy financing is “governmental programs to compensate financial intermediaries for extending low-interest loans to taxpayers who purchase or construct qualifying facilities.” Only subsidies paid by a government in the United States are taken into account. Thus, for example, export credits from Denmark or Germany on equipment purchased in those countries would apparently not reduce the credit.

The haircut is calculated by putting in the numerator of a fraction the amount of the tax-exempt bonds, government grants or other benefits. The denominator is the total capital cost of the project.

Once tainted, a project remains tainted even in the hands of future owners. However, additional capital spending on improvements has the effect of reducing the haircut since this increases the denominator.

The wind industry has worked hard to persuade state legislatures to enact their own tax incentives, but perhaps without realizing — at least initially — that success at the state level could come at the expense of a smaller federal tax subsidy. Companies buying into existing wind projects should be sure to check during due diligence what sort of state tax incentives are offered. At last count, 11 states — Arizona, California, Hawaii, Idaho, Montana, North Carolina, North Dakota, Oregon, Rhode Island and Utah — allow a tax credit that is a percentage of the cost of a wind project. Minnesota, New Mexico and Oklahoma have tax credits that are tied to output.

Tax subsidies that are tied to the cost of a project reduce the federal credit. Tax subsidies that are tied to the amount of output should not. The IRS ruled privately in 2001 that the owner of a wind project did not have to reduce his federal wind tax credit on account of receiving “renewable energy credits” — or RECs — from the state where the project is located. The state requires local utilities to accumulate a certain number of RECs each year. Generators of electricity using renewable technologies are awarded credits by the state and then sell them to utilities. The credits are based on output. In another private ruling in late 2001, the IRS said that there was no haircut in a case where a wind developer received a grant from a nonprofit entity set up and funded by an investor-owned utility. The utility formed the organization to encourage renewable energy projects. It was part of a deal with state regulators in exchange for permission to let the utility restructure. The IRS said the fact that the organization was created as part of a deal with state regulators did not transform the program into a government subsidy.

The credit begins automatically to phase out if the “reference price” for electricity ever tops 9.3¢ a kWh. It phases out as electricity prices move across the next three cents from 9.5¢ to 12.5¢ per kWh. Thus, if the reference price in 2003 is 10.5¢, then taxpayers will qualify for only two-thirds of the normal credit that year. (The 9.5¢ is adjusted for inflation. The 3¢ range is not.)

There seems little danger of a phaseout in the near term. The IRS said the reference price for wind electricity was 5.54¢ in 2001. The reference price is the average price at which such electricity was sold in the United States during the year. Only sales under post-1989 “contracts” are taken into account. Thus, spot sales through power pools are not counted.


The project must be in the United States to qualify. “United States” is defined broadly to include US possessions, like Puerto Rico, the US Virgin Islands and Guam. There is no bar against selling the electricity across the border — for example — into Canada or Mexico. However, Canada recently complained to the World Trade Organization that the United States is using so-called section 29 tax credits to reward US producers of syncoal — some of which is sold in Canada at subsidized prices that make it hard for Canadian coal companies to compete.

Whose Credit?

The credit belongs to the company that is the “owner” of the power plant and the “producer” of the electricity. It must be both. Thus, for example, if Company A owns the power plant but leases it to Company B, neither will qualify for tax credits since one is the owner and the other is the producer.

A contract operator of a power plant is not the producer. The company hiring the operator is still considered the “producer” as long as the operator contract is not recharacterized by the IRS as some other relationship due to profit sharing or other unusual contract terms.

Electricity Sales

Tax credits are triggered by sale of the electricity to an “unrelated person.” In general, the electricity purchaser must be unrelated to the owner of the power plant. The IRS has ruled privately that there can be up to 50% overlapping ownership. Thus, for example, a utility can own up to 50% of a power plant in partnership with a developer — and claim half the tax credits — and also buy all the electricity.

Congress voted in 1999, after lobbying by the California utilities, to deny section 45 tax credits to any wind project that a taxpayer places in service after June 1999 to the extent the electricity is sold under a power sales agreement with a utility signed before 1987. The only exception is if the contract is amended to limit the electricity that can be sold under the contract at above-market prices to no more than the average annual quantity of electricity supplied under the contract in the five years 1994 through 1998 or to the estimate the contract gave for electricity output. “Above market” means for more than the avoided cost of the electricity to the utility — or the amount the utility would have had to spend itself to generate the electricity — at time of delivery.

This provision could come into play if an existing wind project is sold to a new owner.

Other Rules

Tax credits cannot be used by a company to reduce its corporate income taxes below a floor. The floor is 75% of the company’s regular tax liability or the amount it would owe under the alternative minimum tax. Any credits that go unused because of this limitation can be carried back one year and forward for 20 years.

Wind credits are almost impossible for individuals, S corporations and small, “closely-held” C corporations to use. (A “closely-held” C corporation is one in which five or fewer individuals own more than half the stock.) That’s because the credits are subject to passive loss rules that limit these types of taxpayers to using them solely to offset income from other “passive” investments. To avoid this problem, the taxpayer must be involved personally in the day-to-day operation of the project in a material way. The passive loss rules do not apply to larger companies.


Project developers often have too little tax appetite to use the tax credits efficiently. There are ways to transfer tax credits to other companies that can use them.

The simplest approach is to sell the project. The developer can be hired back as the operator or in other capacities.

The IRS ruled privately in 1994 that a developer could sell interests in his project to limited partners and remain the general partner. The partnership planned to hire the developer as the operator for a fixed fee “plus a variable fee dependent on the [project’s] productivity.” It also planned to pay the developer a percentage of gross receipts under a separate contract for handling administrative chores for the partnership.

Probably the most common approach recently for financing new projects is a “partnership flip” structure. The developer and an institutional equity form a partnership to own the project. Taxable income, loss and cash are split 99.9% to 0.1% in favor of the equity until the later of 10 years or when the equity reaches its target internal rate of return. After that, the percentages flip in two stages to something like between 40% and 70% for the developer — and then again after 20 years to 80% or 90% for the developer — with the balance to the equity. There are many variations on this theme. The developer gets some return until the first flip in the form of fees for acting as the general partner and for operating the facility. The partnership borrows the project cost from a bank. The partners agree to make capital contributions when construction is completed to pay down the construction debt to the level of the permanent debt, and then to make ongoing capital contributions to the partnership in the amount of the section 45 tax credits to cover debt service on the permanent debt. In effect, the partnership is borrowing against the future tax credits. The bank will not take tax risk that the credits are not there, but it will take operating risk.

Banks typically lend 75% of the cost during the construction; the gap is closed by getting the construction contractor and turbine vendor to agree to defer 25% of their fees. The permanent debt funds at the level of 50% to 55% of capital cost. Banks insist on a 1.4 coverage ratio. About half the coverage ratio is met through the capital contributions tied to tax credits.

The IRS has approved a “pay-as-you-go” structure for the sale of existing landfill gas and synfuel projects. Under a pay-as-you-go structure, the developer sells the project to an institutional equity participant for an amount in cash plus contingent payments over time that are a percentage of the tax credits. The IRS requires that the contingent payments be no more than 50% of the total purchase price in present-value terms. The developer can be hired to operate. Institutional equity using such structures usually require the developer to get a private letter ruling on the structure from the IRS. The equity usually has an option to unwind the transaction if the developer cannot get a favorable ruling. If the project unexpectedly runs operating deficits, then tax credit payments are diverted to cover operating costs, although the equity may remain liable to the developer for the amount ultimately with interest.

A pay-as-you-go structure should also work in theory to transfer section 45 credits in wind deals. However, it has not been used to date in practice. Unlike synfuel deals, the tax subsidy for wind projects is not found money; this is not a case where $50 million in tax credits a year might easily be generated on a facility that cost as little as $3 million to build. The wind credits are needed to cover the capital cost of the project. Therefore, any sale of an existing project is more likely to be structured as a transaction in which the new equity assumes the obligations of the original equity to make ongoing capital contributions tied to tax credits.

There is growing interest in the institutional equity market in wind projects. Strategic investors who are already in the power business may be willing to take construction risk; more traditional institutional equity appear for now to want to wait to come into the deal until the project is placed in service. Current yields in wind deals are on the order of 9% unleveraged for institutional equity participants and 10.5% to 12% for strategic investors who are willing to take construction risk. Construction takes as little as six months. Leveraged equity returns are as high as 14 to 18% in the current market. Investors in synfuel projects speak in terms of the projects costing X¢ per dollar of tax credit for an investor to buy in. Investors in synfuel projects are having to pay currently as much as 90¢ to $1.25 per dollar of tax credit. For various reasons, the wind market does not speak in similar terms.

One area of active evolution in structures in the sharing ratios among partners. Many people ask whether it is possible to share some benefits among partners in a project in a different ratio than is used for tax credits. IRS regulations require that section 45 credits must be shared among partners in the same ratio as they share in “receipts.” The regulations do not define “receipts.” The IRS ruled privately in 2001 that tax depreciation can be shared among partners in a different ratio than section 29 tax credits, which operate the same way as section 45 credits. There is room for argument about what else can be shared differently.


Most windpower projects qualify for tax depreciation over five years using the 200% declining balance method.

The month when a project is placed in service can affect the first-year depreciation allowance. Pro formas for projects sometimes overlook this. The US tax laws make an assumption that all assets put into service during a year go into service in the middle of the year (for example, on July 1 for companies paying taxes on a calendar-year basis). This means that the first-year depreciation allowance is one half what one would normally get. This “half-year convention” is built into the depreciation tables. However, if a company places more than 40% of its assets in service for a year during the last three months, then it must calculate depreciation that year using a “mid-quarter convention.” This means that assets put into service in the last three months of the year qualify for only 1/8th the normal depreciation allowance. Assets put into service during the first three months of the year qualify for 7/8ths of the normal allowance.

Many people also overlook the fact that a new partnership has a “short” tax year when it starts business. This will reduce the first-year depreciation allowance even further. This is a reason to own projects through existing entities. Where this cannot be avoided, an alternative is to have the partnership make an election under section 761 of the US tax code to treat the partners as if each owns an “undivided interest” in the wind project directly rather than through a partnership. Such elections can only be made in cases where each partner takes his share of the electricity in kind.

A short year means that the first tax year of the partnership runs only from when its principal assets went into service to the end of the year. For example, if a new partnership is formed to own a wind project that is put into service on November 1, the partnership will have a tax year of only two months — and its gets only one month worth of depreciation — or 1/12th of the normal depreciation allowance — the first year (after taking into account not only the short tax year but also the half-year convention).

Depreciation Bonus

A special 30% “depreciation bonus” is available for new windpower projects placed in service during a window period that runs from September 11, 2001 through the end of 2004. The bonus can also be claimed on improvements to existing projects during this period.

The bonus is an acceleration of tax depreciation to which the owner of a project would have been entitled anyway. The owner gets a much larger depreciation deduction the first year and smaller ones later. His depreciation allowance in the year the project is put into service is a) (30% of his “tax basis” in the project (basically the cost of the project) (plus b) depreciation for that year calculated in the regular manner on the remaining 70% of basis. For example, without the bonus, the first-year depreciation deduction on a wind project that cost $100 million to build is $20 million. With the bonus, it is $44 million. Depreciation in later years is reduced commensurately, since only $100 million in depreciation can be claimed in total.

A company will not be able to claim the bonus if it was committed to the investment before September 11 last year.

It is unclear how to apply this principle to many power projects. The IRS is expected to issue guidance by next June.

The House and Senate tax-writing committees weighed in during November with a draft technical corrections bill that the committees hope to put through Congress next year. Under this bill, a project would not qualify for the bonus if anyone had signed a binding construction contract before September 11 last year to have the project built. The committee staffs are still debating whether equity investors who form a partnership during construction with the developer of a project that does not qualify for a bonus would still be able to claim a bonus on their spending after they become partners to complete such a project.

The depreciation bonus can only be claimed on assets in the United States. Assets used in US possessions, like Puerto Rico and the US Virgin Islands, also qualify. The bonus cannot be claimed on property that has been financed with tax-exempt bonds or that is “used” by a municipality.

Only the first company to put the asset in service qualifies for a bonus. The goal is to encourage US businesses to buy new equipment — not churn used assets.

Projects that are placed in service in 2004 after September 10 that year will only qualify for the depreciation bonus if a binding contract to acquire the project is signed or — in cases where the taxpayer is building the project himself — if construction begins no later than September 10.

There has been speculation in Washington that the deadline to place projects in service will be extended. Five Republican members of the House Ways and Means Committee are already on record as in favor of making the depreciation bonus permanent.