Renewable Spend & Tax (Credit)

For developers of renewable power projects, the regulatory landscape is always shifting. The American Recovery and Reinvestment Act of 2009, for example, added the option of a cash grant in lieu of an investment tax credit—a provision that was set to expire at the end of 2010, but that received an 11^th hour extension during the lame duck Congressional session. Keith Martin, a tax lawyer at Chadbourne & Parke who is co-head of the firm’s project finance group, describes why the cash grant was enacted, how long it will last, and its context in the current slate of tax incentives available to utilities.

GU: Why was the cash grant created, and how does it fit in with U.S. renewal incentive policies overall?

KM: There are two subsidies for renewable energy in the United States. They’re both provided through the tax code. One is a tax credit of some kind and the other is accelerated depreciation. The accelerated depreciation on most renewables is worth about 26 cents per dollar of capital cost in terms of the value the tax savings one gets from claiming it. The tax credit varies in value, but for most projects it’s a minimum of 30 cents per dollar capital cost.

The problem that most [non-utility] developers have is they don’t have enough tax base to use the tax subsidies, and so they have to enter into complicated tax equity transactions—essentially to barter the tax subsidies in exchange for capital to build their projects. [EDITOR’S NOTE: In the video above, Martin tells Steven Andersen why utilities don’t face the same constraints that have kept many IPPs from financing renewable projects.] There are 16 active tax equity investors in the current market, there are three structures in use. The market has largely recovered from its collapse in late 2008. After Lehman went bankrupt, the tax equity market largely disappeared. That’s one reason why in the 2009 economic stimulus bill, Congress directed the Treasury Department to pay owners of new renewable energy products that are completed in 2009 and 2010—or that start construction in those two years—30 percent of the project cost in cash, in exchange for which the developers would forgo any tax credit. They’d still be left with depreciation.

The tax equity market in 2010 came back pretty much to the same volume it had in 2007. But the cost of capital was much higher. Tax equity was running 270 to 400 basis points more than it cost developers in 2007. That’s a sign of a supply and demand imbalance compared to 2007. There’s just a lot more demand on the market than there has been increase in supply. This is pretty important to that market. Fortunately Congress extended [the cash grant] for another year in December, but when it goes away, and I think most people should assume it won’t be extended again, the tax equity market will have to double in size in order to cover the same volume of projects that it covered in the last year.

GU: So in all likelihood there won’t be another extension for the cash grants?

KM: It has the potential in theory to be extended again. The Democrats have been keener on it than the Republicans. Particularly in the House, the Democrats felt that a cash grant is a better way of subsidizing renewables than tax subsidies, because they’re equivalent in dollar value. Less than 100 percent of the tax subsidy ends up with the project if its in the form of a tax credit, because the developer has to barter with Wall Street, and ends up having to give part of it away. Republicans though, in both the House and Senate, view the cash grant program as part of the Obama stimulus package. They voted en masse against the stimulus. They don’t want to see any part of it extended.

GU: For the rest of 2011, which type of subsidy is generally most advantageous to utilities?

KM: If you think of the subsidy as consisting of two parts, the tax credit and depreciation, developers have a choice of three versions: One is a production tax credit. That is 2.2 cents per kWh on the electricity output for 10 years. That’s for wind, geothermal and closed-loop biomass. For other types of renewables it’s 1.1 cent. An alternative is an investment tax credit, currently 30 percent of the capital cost. And then the third choice is to forgo both of those and instead just get a check from the Treasury for 30 percent of the capital cost.

There are two significant factors in choosing which is best. One is the cost of the project. The more it costs, the more likely the developer would do better to take the tax subsidy that is a function of the cost of the project. The higher the output, the higher the capacity factor, the more likely the developer would do better to choose production tax credits. That’s in theory. In practice most people in the independent power sector have been choosing cash grants lately, just because it’s still pretty difficult to convert tax subsidies into capital in the tax equity market, not withstanding that the volume has largely recovered. Regulated utilities, however, have a preference for investment tax credits, because they get the benefit earlier. The Treasury cash grant is paid—at the earliest—60 days after a project is completed, whereas the investment credit can be taken into account as the quarterly estimated tax filing during the year in which the project is expected to be completed.

When the cash grant was first enacted in February 2009, a number of utilities called. They wanted not to qualify for the cash grant. It is surprisingly hard to be ineligible for it. The reason they wanted to get out was that at the time the accounting firms were telling utilities that the accounting treatment for cash grant deals would be worse than for investment credit deals. The accounting firms have since backed off.

GU: How have the ongoing changes in renewable incentives affected utilities’ share of the market?

KM: There are some interesting trends in the renewable sector involving regulated utilities. One is that, in general, independent generators had been getting a larger and larger market share of generating capacity in the United States. Up until when Enron went bankrupt, just for maybe a year after, the independent generators were gaining market share and utilities were losing it. Since about 2003, it’s been a plateau. And neither is gaining market share. If you look at capacity additions, they’ve been pretty low through the last decade, but most of the new capacity additions have been renewables.

There was a slowdown the last couple of years, when the economy was so weak, but the trend we’re seeing now is that more utilities are again looking at renewables.

GU: Does that mean utilities have gained some advantage over independent developers?

KM: Utilities can play an important role in the renewables sector because they have tax capacity.

Number one, that gives them an edge over independents competing for opportunities in the sector. Number two, if they want to use their tax base and earn a return on it, they could invest as tax equity participants. Several utilities have started to do that. And number three, they may be able to barter their use of their tax base as a way of getting a lower electricity price.