Tax-equity financing broadly encompasses investment structures in which a passive equity investor looks to achieve a target internal rate of return based primarily on United States federal income tax benefits that are expected to be available to it with respect to an investment in a particular asset. Tax-equity investors are typically profitable, tax-paying entities such as banks, insurance companies, certain utilities and general corporate entities. As discussed in greater detail below, tax-equity investors typically invest alongside a developer who cannot make efficient use of the tax benefits associated with the underlying asset. Tax-equity financing structures are driven by tax laws that are unique to the United States; accordingly, this chapter focuses specifically on the US project finance market.
The US government subsidises the cost of many renewable power projects with federal income tax benefits. These subsidies primarily include tax credits and the ability to write off the cost of a project on an accelerated basis. There are two general classes of tax credits available for renewable projects: investment tax credits and production tax credits. The type of credit available for any particular project largely depends on the technology involved.
The first type of credit available for renewable projects are investment tax credits, which are available for investments in solar equipment, fuel cells, small wind energy property (i.e., 100kW or less), fibre-optic solar, geothermal projects, combined heat and power property, geothermal heat pump property and microturbines.2 The credits are calculated as a percentage of a project's cost, and are available in their entirety in the year the equipment is placed into operation.
The credit amount varies depending on the technology and the year in which the project begins construction. Under the current framework, solar projects that begin construction by the end of 2019 qualify for a 30 per cent investment tax credit. The credit phases down to 26 per cent for projects beginning construction in 2020 and 22 per cent for projects beginning construction in 2021. Projects meeting these deadlines must be placed in service by the end of 2023 to qualify for a credit above 10 per cent.3
The credit drops to a permanent 10 per cent level for projects that begin construction in 2022 or later. The credit for fuel cells, small wind energy and fibre-optic solar is subject to a similar phase-down schedule, such that the credit expires if construction does not begin until 2022 or later, or if the project fails to be placed in service before 2024.4 Combined heat and power, geothermal heat pump and microturbine projects qualify for a 10 per cent credit as long as construction begins before 2022. Geothermal projects benefit from a permanent 10 per cent credit.5
The second type of tax credit for renewables projects is the production tax credit. The production tax credit is available for investments in wind, biomass, geothermal, landfill gas, municipal solid waste, hydropower, and marine and hydrokinetic facilities. Unlike the investment tax credit, the production tax credit is claimed over a 10-year period beginning on the date the project is placed in service. The amount of the credit depends on the amount of energy produced, and is adjusted annually for inflation.6
The value of production tax credits similarly varies depending on the asset class and year in which construction begins. For wind projects, the full value of the credit is available if construction started before 2017. The credit phases down by 20 per cent for each year thereafter, bottoming out at 40 per cent for projects that do not begin construction before 2020. The credit expires for projects that do not begin construction until after 2019.7 The production tax credit is only available for the other eligible technologies if construction began before 2018.8
Apart from tax credits, most of the equipment used in renewables projects qualifies for depreciation over an accelerated five-year period.9 Depreciation is an annual tax deduction for the wear and tear associated with equipment used in a trade or business. Certain renewable energy assets may alternatively qualify for immediate (i.e., 100 per cent) depreciation in the year in which the equipment is placed in service.10
One major structural limitation of the US tax subsidy regime for renewables is that the tax benefits are useless to someone who does not owe taxes. Further, special rules make it harder for wealthy individuals, S corporations and closely held C corporations (i.e., a corporation in which five or fewer individuals own more than half of the value of the stock) to claim tax credits and accelerated depreciation.11
Developers are rarely able to make efficient use of tax benefits, so they enter into what is effectively a bartering transaction with a tax-efficient investor (called a 'tax-equity investor') to whom the developer will allocate nearly all of the tax benefits in exchange for cash capital contributions for the project.
There are three primary tax-equity financing structures in the US renewables market. They are the partnership flip, the inverted lease and the sale-leaseback.
i Partnership flip
Partnership flips are the most common structure in the US renewables market. In a typical deal, the developer either contributes a project or sells it to a partnership formed between it and the tax-equity investor, to which the tax-equity investor contributes cash. The tax-equity investor is typically allocated 99 per cent of the tax benefits and some portion of the cash (usually around 30 per cent or less, depending on the project) until the tax-equity investor reaches a target yield or a fixed date passes. The fixed date will be no earlier than five years after the project is put in service. Once tax-equity reaches the applicable benchmark, its share of tax items will decrease (usually down to 5 per cent), along with its share of cash. The developer will get the bulk of the cash and tax items for the remaining life of the partnership.
The basis used to calculate the investment tax credit is the partnership's cost to acquire or produce the project. If the partnership purchases the project from a developer, its credit-eligible basis will generally be the allocable credit percentage multiplied by the purchase price, subject to adjustment to remove items such as transmission equipment and intangibles that are not eligible for the credit. If the project is contributed to a partnership by the developer, rather than sold, the basis is the contributor's cost. The depreciable basis of the project is reduced by half of the investment tax credits claimed by the project's owner. Production tax credits do not require a basis reduction.
Partnership flip structures are largely dictated by IRS safe harbour rules for wind projects.12 If all of the rules are followed, the IRS will respect the partnership's allocation of tax credits. The IRS has technically adopted the position that the safe harbour rules only apply to wind projects, but the renewables industry largely applies the rules across technologies in the absence of any other technology-specific guidance.13
Among other rules, the safe harbour requires the tax-equity investor to invest at least 20 per cent of its total expected investment upfront. In addition, at least 75 per cent of the total amount of the expected investment must be fixed in amount and certainty of payment. The safe harbour also requires the tax-equity investor to take neither more than 99 per cent of the tax items nor less than 5 per cent of the tax items. (There are no similar restrictions on cash sharing.) Further, the developer typically has an option to buy the tax-equity investor's interest at fair market value, but the tax-equity investor cannot force the developer to buy its interest.
Tax-equity investors in partnership flips typically want indemnification for lost tax credits and depreciation, but only if there is a breach of a representation or covenant. In investment tax credit projects, developers are usually asked to represent that the project's basis for tax credit purposes is its true fair market value. The risk of losses owing to structural risks, such as non-compliance with the safe harbour rules, is generally borne by the tax-equity investor.
ii Inverted lease
Inverted leases are another common financing structure, though they are only available for projects that qualify for investment tax credits. Unlike partnership flips and sale-leasebacks, where the project owner is the only party entitled to tax benefits, a special rule for inverted leases allows the lessor to pass the investment tax credit on to the lessee. The lessee claims the credit based on the project's fair market value (as opposed to the project's cost). The lessee must recognise income ratably over five years in an amount equal to one-half of the tax credits. The lessor is entitled to all of the depreciation.
There are two types of inverted leases: a basic structure where the developer is the lessor and leases the project to a tax-equity lessee, and an overlapping ownership structure where the lessee is a minority (typically up to 49 per cent) owner of the lessor. One of the benefits of the inverted lease is that it allows the parties to split up the tax benefits and allocate them among the parties who want them the most. For example, if a tax-equity investor only wants tax credits and the developer has some appetite for depreciation, the basic inverted lease structure makes more sense than a standard partnership flip. The overlapping ownership variant would be an improvement over the basic structure if the parties want some of the depreciation to go to the tax-equity investor.
Another advantage of the inverted lease is that the tax credit basis step-up to fair market value is free in the sense that entering into a lease is not a taxable event. The step up can have a tax cost in the other structures because the sale of a project to a flip partnership or to the tax-equity investor in a sale-leaseback is a taxable event for the developer.
Similar to solar partnership flips, there is no solar-specific guidance for inverted leases. The industry largely follows guidelines for historic tax credit transactions (which use inverted leases but call them 'master tenant' structures), and leasing principles from guidance for leveraged leasing transactions.14 These guidelines are conceptually similar to the wind partnership flip guidelines in that they try to put the tax-equity investor more at risk than a lender would be. For example, like the partnership flip safe harbours, the tax-equity investor needs to make at least 20 per cent of its investment up front. There are also some notable ways in which the historic tax credit guidance differs from the partnership flip guidance. One way is that the tax-equity investor may have a right to put its interest to the developer for less than fair market value, but the developer may not have a call option (i.e., the exact opposite of the flip guidelines).
In terms of indemnities, tax-equity typically expects complete coverage for lost tax credits due to anything other than a structural risk that it explicitly agrees to bear in the transaction documents. These typically cover issues such as the lease being respected as a true lease and compliance with the safe harbour guidance.
A third common tax-equity structure is the sale-leaseback. As its name implies, it involves the sale of a project by a developer to a tax-equity investor, who simultaneously leases the project back to the developer. This structure is only available for investment tax credit transactions.
In this structure, the tax-equity investor's basis for tax credit and depreciation purposes is the purchase price that it pays to acquire the project. Tax-equity's depreciable basis will be reduced by one-half of the amount of the tax credits.
This is the only investment tax credit structure in which the tax-equity investor does not need to fund into the transaction before the project is placed in service. A special rule permits the tax-equity to claim credits as long as the sale-leaseback happens within three months of the project's placed in service date.15
Both parts of the transaction still need to happen simultaneously. The extra three months makes sale-leasebacks an attractive option for developers who are not able to find a tax-equity investor during construction or pre-construction. The developer will recognise taxable gain on the sale of the project. Lease terms are typically 10-20 years. The developer often has a purchase option to re-acquire the project for its then-fair market value when the lease ends.
In sale-leaseback transactions, the indemnity coverage typically extends to all tax benefits, except for any loss owing to a fundamental structuring issue (e.g., the tax-equity investor not being respected as the owner of the project for tax purposes). If the sale occurs after the project is in service, the developer typically bears the risk that the transaction did not occur within the three-month deadline.
II Interplay between debt and tax-equity
There are three primary sources of financing for renewable energy projects in the United States: tax-equity (covered above), sponsor equity and debt. Generally, tax-equity will only cover around 35 to 45 per cent of the total capital cost for solar developments and 50 to 60 per cent of the total capital cost for wind developments, so sponsors need to complete the capital stack with sponsor equity or debt (or both). More credit-worthy sponsors may be able to fill the entire gap with sponsor equity or corporate (i.e., balance sheet) financing, but for many developers that is not an option. As a result, many renewable energy projects are financed by a combination of tax-equity, sponsor equity and debt.
Debt financing is a broad term that could include non-recourse construction or long-term financing, back-leverage financing, development loans, securitisations, portfolio financings, corporate (recourse) financing, etc. The renewable project debt toolkit has many options. Below, we focus on two commonly used debt structures for tax-equity projects, and the interplay between debt and tax-equity. We have not covered long-term project level debt below because, largely as a result of tax-equity investors unwillingness to permit project-level collateral, it is much less common than back-leveraging financing.
i Construction bridge facility
Tax-equity investors typically will not take construction risk. And the greatest capital expenditures for any project typically are incurred during the construction phase. As a result, project developers require significant financing before tax-equity investment becomes available. One option is to obtain a construction bridge facility. This typically would be a non-recourse fully secured loan from one or more commercial banks (or more recently, direct lenders and private debt sources) that are willing to take on construction risk. A construction bridge loan will be drawn over the course of construction of the project, as costs are incurred.
Construction debt is sized on the basis of the estimated capital costs to build the project. In addition, construction lenders typically will require the sponsor to provide a percentage (usually around 10 to 15 per cent) of the capital costs via sponsor equity (so that the sponsor is appropriately motivated to get the project built on time and on budget). Built into the capital cost estimate will be some amount of contingency, but if there are cost overruns prior to completion, ultimately the sponsor will have to fund them or will risk defaulting on its construction debt and losing its equity in the project.
Construction bridge loan lenders typically require a full security package, including security over all of the project company's assets, and the ownership interests in the project company, along with a tight covenant package. Where the construction debt will be repaid in whole or in part with tax-equity, typically the construction bridge lenders will require that the sponsor have a tax-equity commitment in-hand. In that case, the construction lender will require that such commitment forms part of the collateral package so that the project can benefit from the tax-equity commitment even if the construction lenders foreclose on the project.
The construction bridge facility will be repaid upon project completion by tax-equity financing and, if the developer wants to finance its portion of the cost of a project, by back-leverage debt. While it is not typical, in some cases, a tax-equity investor will also be a construction bridge facility lender, such that its construction bridge debt is repaid with tax-equity investment from the same provider.
In renewable projects that qualify for an investment tax credit and utilise a partnership flip structure, the construction bridge facility will often be repaid by tax-equity invested in two phases – first, 20 per cent of the committed tax-equity is invested at mechanical completion and second, the remaining 80 per cent of the committed tax-equity is invested following substantial completion of the project. Tax-equity investors will not accept a position structurally subordinate to long-term debt, but generally will accept the project level security granted to construction bridge lenders during the period between mechanical completion and substantial completion, subject to the terms of an interparty agreement. An interparty agreement provides for certain agreements between the lenders and the tax-equity investor to address the scenario where mechanical completion is achieved, but the project never achieves substantial completion. Typical provisions in an interparty agreement include requirements for the lender's agent to provide the tax-equity investor notice of any event of default under the debt facility, cure rights on behalf of the tax-equity investor, and, where applicable, restrictions on lender foreclosure that would lead to an investment tax credit recapture (see further discussion on investment tax credit recapture below). Other than certain events of default related to bankruptcy of the project company or the invalidity of project-level security, lenders are typically restricted from foreclosing on the assets of the project company until the expiration of the investment tax credit recapture period and can foreclose on the equity in the project company subject to restrictions in the tax-equity documents or other conditions agreed with the tax-equity investors. Some interparty agreements also provide tax-equity investors with an option to purchase the debt at fair market value. The interparty agreement may also address certain rights retained by the tax-equity investor or the lenders, for example, with respect to proceeds of insurance, or claims for equity contributions or against the sponsor.
ii Back-leveraged facility
Back-leveraged debt is different from construction or term-loan debt at the project level in that it is incurred by a borrower in the ownership chain above the project company and is not secured by a security interest in the assets of the project company. This is preferable from the perspective of the tax-equity investor to project-level debt, because tax-equity investors do not want to take the risk that a secured lender would foreclose on the project assets during the operational period.
The typical parties in a back-leverage financing include:
- Project Company: A special purpose entity that is wholly owned by a tax-equity partnership. It holds no assets other than the project.
- Holdco: A tax-equity partnership owned by the tax-equity investor and the sponsor (through special purpose entities).
- Class B Member: A special purpose entity owned by the sponsor and, in some cases, sponsor equity investors.
- Class A Member: The tax-equity investor.
Given that back-leverage lenders do not have project level security, they will be highly focused on (1) the ability of borrower to get cash distributions from the project, (2) the ability to control decisions of the project company to take any action that could impair the value of the project or its ability to earn revenues sufficient to repay the back-leverage debt and pay any amounts required to be paid to the tax-equity investor, and (3) the change of control and transfer restrictions in the tax-equity documentation. If the tax-equity investor is permitted to divert cash flows for indemnification claims or other reasons without the Class B Member having priority over amounts to repay the back-leverage lenders, the back-leverage lenders may require an indemnity from the sponsor. The back-leverage lenders' collateral usually will include a pledge of the shares in the Class B Member, as well as a pledge over the Class B Member's bank accounts. In the event of a default, the back-leverage lenders may foreclose on such shares or bank accounts (or both) and look to the revenues received from the project company via distributions to be repaid. Accordingly, the back-leverage lenders generally will require change of control and transfer restrictions that provide for objective criteria that would not be triggered in the event of a foreclosure on the ownership interests in the Class B Member.
Unlike construction debt lenders, which will have significant consent rights over the actions of the project company, the back-leverage lenders will have only limited control rights indirectly through the covenants in the back-leverage financing agreement and voting rights of the Class B Member in the tax-equity documentation. If the Class B Member permits the project company to take an action that is in violation of those covenants, then it will trigger an event of default under the back-leverage financing agreement (which, if not cured, will enable the back-leverage lenders to foreclose on the shares in the Class B Member).
It is worth noting that construction bridge debt and back-leverage debt can be documented in a single loan agreement. This has the benefit of being more streamlined. The borrower under the loan agreement is the Class B Member. During construction, the project company will provide an upstream guarantee of the debt and will provide a lien on all of the project company's assets and shares. In addition, the debt will be secured by the shares in the Class B Member. Upon completion, the upstream guarantee and the lien on the project company's assets and shares will fall away.
iii A note on recapture risk
The investment tax credit vests 20 per cent per year over a period of five years. Certain events may trigger the recapture of the investment tax credit before it has fully vested, causing the tax-equity investor to lose a portion of the benefit of its investment. As a result, tax-equity investors typically require sponsors to indemnify them for recapture risk. There are two types of recapture risk. First, there is true recapture where the project company loses the unvested portion of tax credits as a result of some event that occurs after the project becomes operational. Some examples of events that can result in true recapture are certain disposals, such as taking the project out of service or selling it to a third party. Such events are largely within the control of the sponsor.
Second, disallowance can result from a failure to properly calculate the tax credit benefit, often as a result of a misallocation of costs as eligible to benefit from the tax credit that later are found to be inflated or ineligible. This scenario is more challenging for a sponsor trying to quantify recapture risk. To address this concern, sponsors typically will obtain detailed appraisals on the value of the project. In addition, tax-equity investors sometimes will obtain insurance coverage for any losses resulting from investment tax credit recapture (and the costs of interest and penalties that may be assessed by the IRS in connection with such recapture).
Recapture risk is an issue for lenders to the extent that the tax-equity documentation allows cash sweeps to the tax-equity investor to cover recapture obligations ahead of scheduled principal and interest due and payable to the lenders. To address this risk, sponsors often must provide the lenders with an indemnity covering these cash diversions.
III Recent Developments in Tax-equity
As further described below, a wide variety of developments affecting the legal, commercial and technological landscape of tax-equity financings have developed in recent years.
i Federal Circuit Alta Wind decision
In July 2018, a decision from the US Court of Appeals for the Federal Circuit threw into question the widespread market practice of allocating nearly all of the purchase price paid for renewable assets to a development's investment tax credit-eligible generating equipment.16 The case, Alta Wind I Owner-Lessor C et al v. United States, relates to one of the country's largest renewable energy developments, which spans six windfarms in California each supported by long-term power purchase agreements with Southern California Edison. The project's developer financed five of the wind farms with sale-leasebacks (as described in detail in Section I.iii above) and sold one wind farm outright. At the time of the sale-leaseback financings, the federal government had made available a cash grant equal to 30 per cent of a taxpayer's basis in renewable energy generating equipment under a programme included in the post-recession stimulus spending legislation. In this case, investors in the Alta Wind projects claimed around 95 per cent of their investment was allocable to the generating equipment of the developments (and not the land, long-term power purchase agreements or interconnection assets of the business purchased), and thus eligible for case grant payments.
At issue in the case was whether transactions of this sort must abide by the rules governing the allocation of purchase price provided under Section 1060 of the Internal Revenue Code, which generally applies to acquisitions of assets that constitute a trade or business. Where it applies, Section 1060 requires the purchase price to be allocated in a waterfall fashion among seven different asset classes. Any portion of the purchase price that is not allocable to one of the tangible asset classes (e.g., costs allocable to equipment) is allocated to intangible assets and goodwill and going concern value. Cost allocable to intangible assets and goodwill and going concern value are not eligible for cash grant payments or, by analogy, investment tax credits.
The initial 2016 decision from the US Court of Federal Claims found for the tax-equity investors and determined that the Section 1060 purchase price allocation mechanics need not be applied in the case of a business that has no goodwill – such as power plant that has not yet started operation.17 The Federal Circuit overturned that decision, finding that a business – even one that is not yet operating – may have goodwill attributable to its existing assets, such as a long-term offtake agreement or the inherent 'value add' of different contracts packaged together at one project entity. It remanded the case to the Court of Claims for further factual review. Importantly, the court did not settle the question of whether an offtake agreement attached to a specific generation facility has independent value. The implication of the Federal Circuit's decision – that power purchase agreements have intangible value – conflicts with the understanding and practice of many industry participants, who will watch carefully to see how the Court of Claims ultimately settles this allocation question on remand.
ii Rise of unconventional offtake arrangements
In a typical project financing, long-term contracted cash flows payable by a creditworthy counterparty are the key element in ensuring a project's 'bankability' for lenders. Historically, such cash flows have been secured via a power purchase agreement with a utility or hedging arrangements with highly rated financial counterparties. Because of the need for credit worthy counterparties able to commit to long-term offtake arrangements, the market for such counterparties has traditionally been limited. Moreover, many of these market participants have been ill-suited to contract with renewable energy, tax-equity funded projects, which typically feature shorter debt tenors and less predictable production capacity.
Recently, however, new and innovative offtake structures have begun to be accepted in the market. New market entrants in the 'risk solution' space have begun to provide hedging services for renewable energy projects. These products, first seen in the market in 2016 and generally described as proxy revenue swaps, provide for lump sum payments to producers regardless of generation fluctuation due to weather. New institutional capital from reinsurance providers able to underwrite weather risk presents an attractive opportunity for alternative offtake arrangements.
Corporate purchasers of electric capacity represent a fast growing portion of the offtakers in the United States. Corporate offtakers, typically motivated to purchase from renewable energy producers in order to achieve sustainability targets, have moved from simply purchasing green energy certificates or other products from conventional suppliers, to helping finance the development of assets that will provide dedicated renewable energy for their consumption needs. In a typical arrangement, corporate offtakers utilise a synthetic or virtual power purchase agreement, which provides for a long-term financial hedge for the purchase of renewable energy and the delivery of green certificates at a fixed price, demonstrating the corporate purchaser's use of renewable power. In other cases, a physical or 'sleeved' power purchase agreement may be used, where arrangements are made with grid provider or utilities to physically deliver power directly from a renewable energy producer to the corporate offtaker.
While this new source of offtake partners represents a potential boon to renewable energy developers and investors, corporate offtakers present unique challenges for project sponsors and lenders. In particular, many corporate purchasers are less creditworthy than traditional utility or commodity trading offtakers, and are unwilling or unable to commit to long-term (20-year plus) fixed-price offtake obligations. Project lenders are typically unwilling to accept material credit risk in offtake agreements, but given excess liquidity in the market, a limited universe of prime traditional offtakers, and the strength of certain corporate offtakers, an increasing number of transactions have been closed with synthetic corporate power purchase agreements. To address divergence between project debt tenor and the length of typical corporate power purchase agreements, projects have included hedged merchant tails and amortisation profiles carefully sculpted to match revenue profiles. Opportunities also exist for innovative corporate offtake arrangements in developing markets, where corporate offtakers are invested in the development of high-quality infrastructure in the relevant region.
iii Solar tariff impact
On 22 January 2018, a 30 per cent tariff was imposed on solar imports to the United States, with a 2.5 gigawatt annual exclusion.18 This tariff ramps down 5 per cent each year through 2021 and expires in 2022.19 While several developers reportedly have cancelled or postponed projects because of cost increases caused by this tariff, there are several mitigating factors which have softened the tariff's initial impact: (1) certain types of solar cells and panels, accounting for one-quarter to one-third of the US market, are not affected by the tariff; (2) manufacturers knew that the tariff was likely and imported equipment prior to the tariff taking effect (meaning that upwards of a year of supply has avoided the tariff); (3) some manufacturers, including both US-based companies such as First Solar and foreign-based companies such as JinkoSolar, moved manufacturing operations to the United States, thereby avoiding the tariff; and (4) the general decrease in the equipment and installation costs and other market factors has offset cost increases from the tariff.
iv Decreasing equipment and installation costs
Among the largest capital costs in any solar generation project is the generating equipment. The photovoltaic (PV) panels, inverters, racking hardware and associated infrastructure are a key cost consideration for each project. In recent years, the capital investment costs associated with solar infrastructure have dropped dramatically, increasing the competitiveness of solar projects as compared to conventional generation options – even before tax incentives are considered. The US Energy Information Administration found that, between 2010 and 2017, costs for utility-scale solar PV declined 10 to 15 per cent annually.20 Researchers at Lawrence Berkeley National Laboratory identified similarly positive trends, noting that, since the period 2007 to 2009, the median price of installed photovoltaic systems has fallen by two-thirds.21 These developments have helped contribute to a dramatic overall drop in the cost of renewable energy production; in its 2017 'levelized cost of energy' analysis, Lazard found that the newest solar thin-film technology could compete on price with modern combined-cycle gas generation facilities.22
Interestingly, the primary driver in cost reductions between 2012 and 2016 was not price reductions in PV panels themselves. As the market for PV panels and related infrastructure tightened, 'hard cost' equipment prices remained high and the majority of cost reductions were found in lowering 'soft costs' (installation, transaction expenses, investor returns, etc.) rather than the cost of solar generating modules.23 Since Q1 2017, however, a resurgence in PV module supply has helped lower hardware costs.24 In 2017, the National Renewable Energy Laboratory (NREL) tracked an index of solar module manufacturers and observed aggregate deliveries of over 24 per cent year over year.25 In its Q1 2018 report, the NREL found that benchmark costs for installed commercial solar generating systems had reached US$1.05 (per watt, direct current) for fixed-tilt projects and US$1.13 (per watt, direct current) for single axis tracking systems.26 As prices have declined over time, solar development has continued to grow. At the end of 2017, nearly 600 utility-scale PV projects were in commercial operation in the United States, and nearly 20 per cent of those achieved commercial operation in 2017.27 While cost reductions help drive the growth of solar installations, unpredictability in capital costs can also make project auction bids difficult. Solar investors and other market participants are likely to continue to benefit from decreased costs, even as price movement creates challenges for valuation analysis.
v Offshore wind
There is a tremendous buzz around offshore wind projects in the United States. 2018 was an exciting year for this developing market, wrapping up with the announcement by the Bureau of Ocean Energy Management and the US Secretary of the Interior in December 2018 that three wind energy site leases off the Massachusetts coast were awarded to three winning bidders for a total of US$405 million28 or approximately six times the revenue from all previous auctions combined.29
Many offshore wind developers are focused on the East Coast, with 23.4 gigawatts of the US offshore wind pipeline (out of approximately 25 gigawatts in total) situated there, but there are also projects in development in Hawaii, California and the Great Lakes.30
There are several market factors behind the recent uptick in this market; including the expectation of massive available resources, significant decreases in capital costs (Ørsted report a 63 per cent decrease in prices between 2010 and 2016) and new renewable energy, climate and economic development targets being set by state governments.31
This is a space to watch for 2019, particularly as only those offshore wind projects that begin construction during 2019 will be able to benefit from the investment tax credit.
vi Battery storage
Bloomberg NEF has estimated that 'the global energy storage market will grow to a cumulative 942 GW/2,857 GWh by 2040, attracting $620 billion in investment over the next 22 years.'32 When and how battery storage projects will begin to become more viable from a financing perspective is a recurring discussion topic among industry participants. Increasingly, that conversion is focused on the benefits of combining solar and storage projects. Under current IRS guidance, the storage portion of these combined projects qualifies for investment tax credits only if at least 75 per cent of the energy used to charge the battery comes from the solar generating equipment. Further, if the solar input is less than 100 per cent, the investment tax credits are reduced to the extent of the non-solar input.33 Increases in the percentage of non-solar input in subsequent years may cause the IRS to recapture a portion of previously claimed credits.
1 Scott Cockerham, Brian Greene and Kelann Stirling are partners, and Mateo Todd Aceves is an associate at Kikland & Ellis LLP.
2 See 26 U.S.C. § 48(a).
3 See 26 U.S.C. § 48(a)(6)(A)(i)-(ii).
4 See 26 U.S.C. § 48(a)(6)(B).
5 The IRS has issued multiple sets of guidance on what it means to 'begin construction.' See IRS Notice 2013-29, IRS Notice 2013-60, IRS Notice 2014-46, IRS Notice 2015-25, IRS Notice 2016-31, IRS Notice 2017-04, and IRS Notice 2018-59.
6 See 26 U.S.C. § 45.
7 See: id.
8 See 26 U.S.C. § 48(d).
9 See 26 U.S.C. § 168(g)(3)(C).
10 See 26 U.S.C. § 168(k).
11 See generally 26 U.S.C. § 465; § 469.
12 See Rev. Proc. 2007-65.
13 This approach was confirmed to an extent in a 2015 internal memo in which the IRS national office analysed a transaction using the criteria from the wind safe harbour, even though the memo formally concluded that the wind safe harbour did not apply to solar projects as a technical matter. See Chief Counsel Advice 201524024 (12 June 2015).
14 See Rev. Proc. 2014-12; Rev. Proc. 2001-28.
15 See: Treas. Reg. 1.47-3(g)(1).
16 See: Alta Wind I Owner-Lessor C et al. v. United States, 2018 U.S. App. LEXIS 20931 (Fed. Cir. 27 July 2018).
17 See: Alta Wind I Owner-Lessor C et al v. United States, 128 Fed. Cl. 702 (2016).
19 See: id.
31 See: id.
33 See: IRS Private Letter Ruling 201308005.