Navigant Consulting on February 19 submitted a report, Solar Project Return Analysis for Third Party Owned Solar Systems, to the Arizona Public Service. The thesis of the report is that residential solar developers are charging homeowners unnecessarily high rates given the extension of so-called bonus depreciation1 and Congress pushing out when the federal Investment Tax Credit drops down from 30 percent to 10 percent by a number of years. The implication of that thesis would seem to be that if the solar companies accepted more reasonable after-tax returns, they would be able to lower the rates charged to homeowners; then the homeowners could pay more to utilities for transmission and other infrastructure that they need access to when the sun is not shining, while still paying less overall than customers who have not adopted solar. This post is not an attempt to address the economic behavior of solar companies in setting their rates. However, it will explain how Navigant misconstrued the real-world economic value of bonus depreciation, the degree of the fair market value step-up in determining the purported tax benefits that Navigant is suggesting the solar companies use to pad their returns, and the omission of meaningful detail regarding the report’s assumed overhead and marketing costs incurred by solar companies. Navigant’s report provided the following generally accurate overview of bonus depreciation: The bonus depreciation benefit has been re-introduced and is currently 50 percent through 2017, after which it is reduced to 40 percent in 2018, 30 percent in 2019, and zero percent from 2020 onward. The benefits of bonus depreciation are similar for accelerated depreciation, except that they result in even greater depreciation of an asset in the first year of a capital investment. For instance, with 50 percent bonus depreciation, one can essentially depreciate an additional 50 percent of the asset’s value in the first year. However, Navigant’s conclusion about the consequence of bonus depreciation on solar companies’ real-world returns is flawed. Navigant wrote: The analysis above suggests that the combined impacts of the re-introduction of bonus depreciation and the increase of lease rates from 2015 to 2016 offer headroom for solar [third-party ownership] TPO providers to reduce lease rates and adjust to changing rate structures while still enjoying the same project returns achieved in 2015. For instance, in 2015 in UNS Electric, Inc.’s (UNSE) territory, SolarCity, the leading solar TPO provider, could earn a project return of 40 percent with solar TPO prices set at $0.87 per kilowatt-hour. With the re-introduction of bonus depreciation, this should permit SolarCity, the leading solar TPO provider in UNSE service territory, to earn 40 percent return with lease rates of about $0.075 per kilowatt-hour. What Navigant ignores is that bonus depreciation is only valuable if either a solar company can use it itself (few solar companies have sufficient federal income tax liability to absorb tax benefits of the magnitude of bonus depreciation and the Investment Tax Credit) or the solar company can entice a tax equity investor, typically a bank, to “monetize” it by providing more capital in a lease or a partnership structure than it otherwise would. Navigant acknowledges the need for tax equity investors in a footnote: The significant tax benefits from the lTC, accelerated, and bonus depreciation require a “tax appetite” to monetize these benefits (i.e., one must have sufficient tax liability to take advantage of these tax breaks). Thus, it is not surprising that tax equity investors (which can provide the tax appetite required) constitute a substantial portion of solar TPO providers’ financing. Implicit in this footnote is the accurate conclusion that solar companies typically lack the tax appetite to efficiently use depreciation and the investment tax credit. However, what Navigant ignores is that bonus depreciation has no value to solar companies if they cannot entice tax equity investors to monetize it. Tax equity investors are in fact quite reluctant to monetize bonus depreciation. This reluctance stems from at least two reasons. First, the partnership flip structure is the most common structure for tax equity investments in solar. As that structure involves an allocation of tax attributes that changes over the course of the transaction and the tax attributes are shared in different percentages than the distributable cash, the structure requires rigorous adherence to the maintenance of capital account rules in the income tax regulations.2 Those rules include the principle that tax depreciation is an expense that reduces the partners’ capital accounts. Due to the fact that bonus depreciation is so accelerated and that in a typical solar partnership the tax equity investor would only fund about half of the price of the project (i.e., its capital account is about half the initial tax basis of the project), those forces can result in the tax equity investor having a large negative capital account balance or, alternatively, that once the tax equity investor’s capital account reaches zero, the incremental losses are reallocated to the solar company. If the losses are reallocated to the solar company, which generally does not have a tax appetite, then the losses are usually of minimal economic value. Alternatively, one of two structuring techniques can be used to avoid the reallocation of the losses to the solar company once the tax equity investor’s capital account reaches zero: 1) have the partnership incur nonrecourse debt secured by the assets of the partnership or 2) the partner with a negative capital account agrees to make a contribution to the partnership if the partnership liquidates while such partner has a negative capital account (i.e., a deficit restoration obligation).3 Unfortunately, both of those structuring techniques involve some commercial risk for the tax equity investor. Hence, tax equity investors frequently seek to manage their commercial risk exposure by not structuring their transactions with debt at the partnership level and minimizing, if not completely avoiding, the size of its deficit restoration obligation. Further, the use of a deficit restoration obligation does not avoid the application of the outside basis rules that suspend losses in excess of a partner’s outside basis.4 Thus, even a deficit restoration obligation only enables the losses from the depreciation to be suspended and later offset future taxable income allocated by the partnership to the tax equity investor. The typical aversion of tax equity investors to being subordinated to nonrecourse debt, combined with their hesitancy with respect to deficit restoration obligations that only suspend the losses for future use, make bonus depreciation a tax attribute which often has little value in a partnership flip transaction. Lease structures avoid the unpleasant capital account rules. Despite that, investors in those structures often frown on bonus depreciation. Any investors would prefer to maximize the value of their tax appetite by offsetting it with tax credits, because tax credits from a financial statement (i.e., GAAP) perspective result in bottom-line earnings. This benefit is in contrast to accelerated depreciation (including bonus depreciation) that for financial statement purposes results in a deferred tax liability. A deferred tax liability, from a financial statement perspective, has the benefit of being equivalent to an interest-free loan from the government based on the difference between the basis of a project as calculated under tax rules and GAAP rules; as the project is depreciated for tax and GAAP purposes, respectively, eventually the basis under each regime reaches zero and the “loan” is eliminated. Such deemed free debt reduces the tax equity investor’s cost of capital. An interest-free loan is nice, but not as nice as actual earnings resulting directly from tax credits. The other tax dynamic that Navigant’s report appears to have misunderstood is the degree to which “fair market value” is used to determine the purchase price to the tax equity investment vehicle, and accordingly, that the tax attributes may exceed the cost to build the system. The report provides: We used a 35 percent markup on system cost to calculate the value of the system for the purpose of ITC and system depreciation benefits. This value is also known as the fair market value (FMV). Using FMV as the basis for tax credits and depreciation benefits would effectively result in a solar TPO developer reporting a system value of $3.74-3.87/W-DC to the Internal Revenue Service, which is still lower than observed system sales prices that typically range from $4.20-$4.75. The ability of PV providers to mark up cost to something more akin to a price, or system value, when calculating tax credits and depreciation is a key driver in the favorable economics for solar TPO providers. The solar TPO business model is able to maximize the benefits of these federal incentives, which are amplified considerably by the TPO provider's ability to use a system “value,” which is higher than the system cost, as the basis for the tax credit and asset depreciation” (citation to U.S. Treasury memo from June 30, 2011 and other materials omitted). Navigant’s report cites the U.S. Treasury’s memo from June 30, 2011 as one of the authorities for its conclusion quoted above to use a 35 percent markup in evaluating the return levels of solar companies. However, Treasury’s memo provides: “While appropriate markups are case-specific and can depend on the ultimate transaction price, the 1603 review team has found that appropriate markups typically fall in the range of 10 to 20 percent." Despite citing Treasury’s memo, Navigant’s report offers no reconciliation of Treasury’s 10 to 20 percent to its 35 percent. Is the report suggesting that solar companies are doubling the markup provided for in the Treasury’s memo? If so, how are tax equity investors and the solar companies’ accountants accepting that? Also, Navigant’s report does not provide a definition of “system cost” for the purposes of its 35 percent markup calculation. Figure 5 of the report portrays “Installed System Costs, Residential,” which according to the report comprises the cost of solar modules, direct labor, inverter, engineering, electrical balance of system, structural balance of system and supply chain. The report determines a national average in 2015 for those costs of $2.25 per watt, which would seem to suggest that “Installed System Costs” may be different than “system cost” for purposes of application of the 35 percent markup. For instance, a 35 percent markup on the “Installed System Costs, Residential” of $2.25 per watt would be only $3.04 per watt; however, the report references “a solar TPO developer reporting a system value of $3.74-$3.80 per watt-DC.” But no detail is supplied to enable the reader to reconcile these numbers. Finally, the report provides: “The cash flow streams accounted for in this analysis include: Initial capital outlay, inclusive of all system component costs, installation costs, and an allocation of overhead costs.” The report offers no detail on how it determined overhead costs, which can be a material part of solar companies’ overall costs, especially given the information technology systems necessary to bill and collect from homeowners and electronic monitoring systems for maintenance problems. Further, the report makes no reference to the substantial marketing costs that some solar companies incur in order to obtain their customers. Are those marketing costs embedded in overhead costs? For the report to have creditability, it would have needed to detail the methodology of “an allocation of overhead costs.” Below are other interesting quotes from the report that are not referred to above: 2 See, generally, Treas. Reg. § 1.704-1(b). Failure to comply with these rules could result in the IRS and the courts ignoring the stipulated allocation of the tax attributes and instead requiring the partners to share the tax attributes in accordance with each “partner’s interest in the partnership” (PIP). PIP is a subjective and vague concept the application of which could mean the tax equity investor is allocated less than the 99% of the Investment Tax Credit that it is expecting. See Treas. Reg. § 1.704-1(b)(3). 3 For a discussion of the commercial law ramifications of a deficit restoration obligation, see Burton & Fet, "Commercial Aspects of Deficit Restoration Obligations in Partnership and LLC Transactions," Project Perspectives 20 (Winter 2013).
Lobos E.,UNSE |
Occhionero M.,UNSE |
Werenitzky D.,UNSE |
Fernandez J.,National University of Tucuman |
And 5 more authors.
Neotropical Entomology | Year: 2013
Management of the South American tomato leafminer, Tuta absoluta Meyrick, with insecticides has led to the widespread development of insect resistance. Mass trapping using traps baited with the female-produced sex pheromone is an attractive alternative for the management of this pest. The current study evaluated several commercial trap designs for capture of T. absoluta. Based on its small size and ease of handling, the most effective trap is a small plastic container with entry windows cut on the sides filled with motor oil over water. These traps are most effective when placed near ground level. Tests of septa containing 0.1 or 0.2 mg of the pheromone (95:5) E4, Z8-14Ac/E4,Z8,Z11-14Ac were slightly more attractive than septa loaded with 0.5, 1.0, or 2 mg during the first week of use, but the latter three loadings were slightly more attractive than the first two loadings after 9 weeks. Ideal trap baits were loaded with 0.5 mg of pheromone. Higher numbers of T. absoluta were captured near upwind borders of tomato fields suggesting that treatments against T. absoluta should be concentrated near upwind parts of fields. Comparisons of conventional insecticide treatment versus mass trapping to manage T. absoluta damage in three different test sites showed that even when initial captures in monitoring traps were high (>35 males trap-1 day-1), mass trapping at 48 traps/ha reduced leaf damage more efficiently than conventional insecticide treatment. Based on the typical insecticide recommendations against T. absoluta, mass trapping is an economically viable alternative. © 2013 Sociedade Entomológica do Brasil. Source
Cabrera D.C.,UNT |
Sobrero M.T.,UNSE |
Chaila S.,UNT |
Planta Daninha | Year: 2015
This work aimed to study the germination of Megathyrsus maximus seeds when exposed to high temperatures, as well as to evaluate the effects of different seed planting depths and sugarcane crop residue amounts on weed emergence. In the laboratory, germination and biomass of seeds with and without glumes were determined when exposed to 0, 40, 60, 80 and 100 oC, for five minutes. Two experiments were performed in the greenhouse to assess the emergence rate in relation to different weed seed planting depths (0, 0.5, 1, 2, 3, 4, 5, 7 and 8 cm) on the one hand, and in relation to different sugarcane crop residue quantities (0.5, 8, 11, 13, 15 and 18 t ha-1) on the other. Temperature tests were analyzed by means of covariance analysis, whereas greenhouse tests were analyzed with regression. The highest germination percentages for seeds with and without glumes were 48 and 35%, respectively, and they were obtained at 40 oC. The lowest values were 28 and 7% for seeds with and without glumes, respectively, and they were obtained at 80 oC. Seed planting depth had a negative effect on weed emergence: the control led to 51% emergence, which dropped to 23.3% at 7 cm and eventually to zero at 8.0 cm. Crop residues had a negative effect on emergence as well: when residue quantities ranged from 0 to 18 t ha-1, emergence decreased from 64.8 to 0%.Thus we can conclude that sugarcane management strategies affect M. maximus germination and emergence. © 2015, Sociedade Brasileira da Ciencia das Plantas Daninha. All rights reserved. Source