Tax Equity for Renewables, Wind: Historical Trends and Projections; Tax Equity Structures and their Complicating Factors; the View from 2008
Before I put up a more policy-oriented post about wind's expiring production tax credit (PTC), here's my attempt at a quick and dirty breakdown of this Bloomberg white paper -- "The Return - and Returns - of Tax Equity for U.S. Renewable Projects" -- focused primarily on the historical demand for tax equity and its various structures.
Background: The government offers two main tax credits for renewables. The PTC allows a qualified project owner to directly apply a credit to their tax bill for each MWh of energy generated, presently valued at ~$22/MWh. More generated MWh means more credits, but the PTC only applies for the first 10 years of a project. It is indexed to inflation and requires periodic re-approval by Congress. Lapses in 2000, 2002, and 2004 led to significant drops in the number of new wind installations.
The investment tax credit (ITC) is equal to a percentage of the project's qualified capital expenditure (30%) and can also be directly applied to an owner's tax bill. In 2008 and 2009, it was expanded to include wind, geothermal, and CHP in addition to solar, fuel cells, and microturbines.
Because most developers lack the profitability (ie: tax exposure) to make use of these credits, they have turned to third parties who invest in renewables projects in exchange for tax credits and other tax benefits. These partnerships can take a number of forms.
The Three Basic Tax Equity Structures
Partnership Flip -- In this two-phased structure, the investor retains near complete ownership (~99%) of the project until a predetermined circumstance triggers an ownership 'flip' to the project developer. These arrangements are typically "five or ten year-contingent."
In a five-year partnership, the flip is time-contingent. The investor is the primary owner through the first five years, then ownership reverts to the project developer. The investor's 45-65% of initial equity is repaid partially through a 2% preferred yield* and partially through tax-related benefits like credits, accelerated depreciation, and loss allocations. In some ITC cases, the size of this equity contribution is a multiple, or syndication rate, of the tax credit. These deals are generally leveraged at the project level.
*The report's definition of 'preferred yield' as "the yield on the upfront investment which the investor receives each year, drawn from the initial stream of cash flows," is less clear than this one: "the developer may get the initial cash but, after a certain point, all of the cash and tax benefits will go to the tax equity investors until they get their preferred yield" (30).
In a ten-year partnership, ownership changes hands once the investor has achieved a predetermined internal rate of return (IRR), typically ~8-9%. The 'ten years' in question do not set a deadline for ownership transfer, as in the five-year arrangement; rather, they are used to measure out an equity contribution that will achieve a desirable IRR. As such, there is no need for syndication rates. The investment is repaid with a minor percentage (~35%) of cash flows during the first five years, with a major percentage (~60%) in the last five or so years, and with tax credits throughout. These deals are typically "back-leveraged" with money being lent to the project developer.
Sale Leaseback -- Here the developer sells the completed project's assets to the tax equity investor then leases them back, also agreeing to cover its operating expenses. Lease payments equal 100% of project cash flows (not including operating expenses), i.e. they are not fixed. Ownership eventually reverts back to the developer, either at the lease's typically ten-year expiration date or in a predetermined 'early buyout' arrangement. This, for example, might happen between years 7 and 12 for 30-35% of the project cost. Up until this point, all project tax credits also accrue to the investor.
Inverted Lease -- The near opposite of the sale leaseback, this structure sees the developer maintain ownership of the project as it leases assets to the investor. The ITC passes through the lessor to the lessee, whose payments might include ~95% of project cash flows minus a 2% preferred yield. A key investor benefit of this structure is loss allocation; the lessee/investor may own up to 49% of the lessor/developer and thus use up to 49% of the project's loss allocation to offset tax liabilities elsewhere in its portfolio. As if it weren't complicated enough, this structure can feature different developer/investor splits for upfront investment, the ITC benefit, and any loss allocation.
An Appetite for Tax Equity
When tax liabilities decreased and tax equity capital dried up as a result of the financial crisis, the government responded through ARRA by establishing a cash grant program offering 30% of a project's qualified capex instead of the PTC or ITC. (ARRA was also responsible for extending the ITC to wind, but its adoption was minimal because the cash grant was generally more attractive.) Here is Bloomberg's estimation of how U.S. wind projects were financed between 2007 and 2011 and how the availability of a cash grant impacted the use of tax equity:
Unless a project was fairly certain to have a high capacity factor (thus generating tax credits outweighing the value of the cash grant), a developer generally chose the cash grant over either tax credit. "The 2008 and 2010 mixes present an interesting contrast – i.e. 2010’s mix is a ‘cash-grantified’ version of 2008" (6). The other exception would be a developer primarily interested in accelerated depreciation benefits.
Looking forward, they predict that the combination of mandated wind build tied with state renewable standards -- "hence the escalation in 2019 in preparation for 2020 targets" -- and autonomous wind build by those looking to hedge against increasing oil prices will push demand for tax equity to look like this:
All that results in a paucity of much needed tax equity investment.
Surely there are all sorts of variables to consider when determining A) the parameters of a developer/investor partnership and B) how equitable that partnership should or can be: PTC v. ITC; estimated capacity factor; partnership length and early buyout options; IRR v. NPV analyses; preferred yields; cash flow allocations; syndication rates; loss allocation and accelerated depreciation benefits; and on and on.
Still, this report believes that these complications are significantly outweighed by the investment opportunities created by the current void of tax equity investors.
(Tumblr coding limitations made it difficult to get the whole post to show up in the Dashboard at the same time that the graphs were fully legible, and so I settled for the former. Those graphs are much easier to read in the report itself, again here.)
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For an idea of how the tax equity markets looked just a bit after we plummeted off the cliff -- and before anyone knew what ARRA was -- take a look at this Chadbourne & Parke November 2008 newsletter beginning on page 22. The discussion covers a full range of wind-related issues: there being fewer players for fewer deals; pre-tax after-tax partnership structures (PAPS) versus PAYGO; the connection between higher yields, lower capital expenditures, policy changes regarding pass-through regulations, "small-ticket" investor syndicates, and an expanded investor pool; the eye-glazing deficit restoration obligation... but it eventually returns to a major issue that, three years later, seems largely unresolved:
We could see the demand for wind tax equity [in 2009] being on the order of $10 billion and the supply peaked in 2007 at $5 billion. Obviously, if you keep on jacking up yields, you can bring other corporate investors into the market, but we will arrive quickly at a point where tax equity is demanding a higher yield than the wind farm itself earns and that's not a sustainable business model. The bottom line is I think we are going to be talking about the ongoing demand and supply imbalance for tax equity (36).