Developer fees are in less favor after a decision by the US claims court in June to bar a wind developer from adding developer fees to the tax basis it used to calculate Treasury cash grants on two wind farms.
The decision has been appealed.
The developer’s brief in the appeal is due on September 6.
In the meantime, developers have shifted to selling the project company at mechanical completion to the tax equity partnership for the projected value at the end of construction as determined by an appraiser. The developer remains obligated to finish the remaining construction.
Most renewable energy projects owned by larger developers are financed in the tax equity market. The amount of tax equity that can be raised is a function partly of the tax benefits that can be claimed on the projects. Investment tax credits and depreciation are calculated on the tax basis the tax equity entity has in the project. The higher the tax basis, the higher these tax benefits.
Most developers have been required to represent to the tax basis that can be used to calculate tax benefits after the US Treasury began questioning the tax bases claimed on some solar projects in 2010.
Tax insurance is sometimes purchased to cover basis risk. Insurance premiums have inched up in the wake of the US claims court decision. They had fallen to as low as 2% to 3% of the potential insurance payout as the market became more comfortable with risk, but are back to 3% to 4%.
US wind developer Invenergy paid itself a developer fee of $50 million on the 200-megawatt California Ridge project in Illinois at project completion in late 2012. The fee was about 12.3% on top of construction cost. The company applied to the US Treasury for a cash grant for 30% of its tax basis in lieu of claiming federal tax credits on the project. It asked for a grant of $136.9 million on a tax basis, including the developer fee, of $456.2 million. The Treasury paid $9.2 million less after reducing the developer fee to 4.8% of construction cost.
Invenergy sued for the difference.
The government then filed a counterclaim urging the court to deny any developer fee. (For earlier coverage of the case, see “Treasury Cash Grant Update” in the February 2016 NewsWire and “PPAs and Developer Fees” in the February 2018 NewsWire.)
The claims court said that developer fees are allowed to be added to tax basis, but the fee in this case lacked substance.
Invenergy made a capital contribution to the project company that the project company used to pay Invenergy the fee. The court called the fee a “round-trip wire transfer that began and ended in the same bank account, on the same day.”
Invenergy went to the trouble of putting a development services agreement in place between the project company and its subsidiary that received the fee. However, the court said that while the development services agreement listed work that Invenergy did to earn the fee, none of services had a specific charge next to it as would have been true had an independent contractor been hired to do the same work. The fee was the difference between the construction cost and the appraised market value.
Invenergy suffered the same result in a second wind project called Bishop Hill. The claims court consolidated the two cases under the name California Ridge Wind Energy v. United States. The Bishop Hill facts were similar, with slight variations in dates and dollar amounts.
Developers are drawing a number of lessons from the decision.
There is a danger of coming out in a worse position than before by suing the Treasury for a cash grant shortfall.
Any developer fee should be paid out of capital contributed by the tax equity investor or remaining construction loan proceeds at the end of construction: for example, as a reward for bringing the project in under budget.
The amount should reflect the capital the developer had at stake and the time and difficulty it took to develop the project. The Treasury suggested in 2010 that developer fees should not normally exceed 10% to 20% of the cost of a solar project, but quickly backed away from that number, coming eventually to believe that such fees should normally be in the 3% to 5% range absent unusual circumstances. Many tax equity investors have been placing a cap on the permitted step up in tax basis above construction cost of 15% to 20%.
Developer fees have become less common in the last 18 months. The market had already moved by the spring 2018 to sales of project companies as a better way to step up tax basis. Inverted leases have also made a comeback in the solar market. In an inverted lease, the tax equity investor leases the project from the sponsor. The sponsor keeps the depreciation, but makes an election to let the lessee claim the investment tax credit on the project. IRS regulations allow the tax credit to be claimed in such cases on the fair market value of the project.
Separately, WestRock, a paper and packaging company, lost an appeal in late June in another Treasury cash grant case called WestRock Virginia Corp. v. United States.
The company built a new cogeneration facility in 2013 to serve a paper mill in Covington, Virginia. The company retained one of eight boilers it had used previously to supply energy to the mill and added one new boiler. The new boiler burned biomass. The older, retained boiler burned fossil fuel and black liquor, a by-product of papermaking. Steam from both boilers was then run through a steam turbine to generate electricity for use in the mill. Some of the steam exiting the turbine was used as process heat in the mill.
The company applied for a Treasury cash grant of $85.9 million, or 30% of its $286.2 million tax basis in the facility. The Treasury paid a grant of only $38.9 million.
The Treasury’s position is that any power plant that produces both steam and electricity must allocate the cost between the two functions. A grant is paid only on the electric generating equipment. A further allocation must be made between the biomass and fossil fuels since tax credits may only be claimed on electricity generated from biomass.
Two other cases have upheld this principle. (See discussion of W.E. Partners in “Treasury Cash Grants” in the February 2015 NewsWire and of GUSC Energy in “Treasury Loses Key Case” in the December 2016 NewsWire.)
The Treasury determined that only 49.1% of the WestRock plant costs were tied to electricity produced rather than steam. It reduced the basis by another 0.22% because the plant uses fossil fuel for startup and flame stabilization. Black liquor is considered biomass.