The National Renewable Energy Laboratory (NREL), a federally-owned laboratory that is funded through the U.S. Department of Energy, recently released a report titled Wind Energy Finance in the United States: Current Practice and Opportunities. The report provides a thorough overview of the capital sources and financing structures commonly used in wind energy finance. Below are quotes from the report that are of particular interest to tax equity market participants. We applaud the authors for writing a comprehensive report on a topic that is extremely technical. Also, below we include comments clarifying certain tax or legal concepts referenced in particular quotes.
Wind Expansion in 2016
• By the end of 2016, cumulative U.S. wind generation capacity stood at 82.2 gigawatts (GW), expanding by 8.7 GW from 2015 installations levels. Wind energy added the most utility-scale electricity generation capacity to the U.S. grid in 2015 and the second most in 2016. Project investment in wind in the United States has averaged $13.6 billion annually since 2006 with a cumulative investment total of $149 billion over this time period. The investment activity demonstrates the persistent appeal of wind energy and its significant role in the overall market for electricity generation in the United States.
• Looking ahead, the near-term outlook for wind energy reported previously suggests a continued need for capital availability at levels consistent with deployment seen in 2015 and 2016. The market has shown the capacity to finance projects at this level using current mechanisms at economically viable rates; however, increased deployment could necessitate new sources of capital. Broad changes to the financial industry—such as the possibility of major corporate tax reform, the currently scheduled phase out of the PTC and ITC for wind, and, specifically, a change in the role of tax equity—could fundamentally reshape the predominant mechanism for wind energy investment. It is possible that financing practices may need to evolve, while the growing body of wind energy deployment and operational experiences could help to attract new market participants.
PTC and Accelerated Tax Depreciation
• The United States Federal Government incentivizes renewable energy projects principally through the tax code. As of this writing, wind technologies are eligible to receive either the production tax credit (PTC) or the investment tax credit (ITC) (one or the other, but not both) as well as accelerated depreciation tax offsets through the Modified Accelerated Cost Recovery System (MACRS).
• The tax credit incentives (the PTC and ITC) provide an after-tax credit on tax liabilities (i.e., the taxes paid) and thus are often described as dollar-for-dollar tax incentives. As of this writing the PTC is currently worth $0.024 for every kWh generated over a 10-year period while the ITC is structured as a one-time credit valued at 30% of eligible system costs. For projects to claim the aforementioned full PTC or ITC values, however, the project is required to have begun construction prior to December 31, 2016. Projects that begin construction in 2017 through 2019 are available for a reduced-value PTC or ITC.
• [The report includes a table on the PTC and ITC phaseout which is excerpted below:]
[Comments: The table has several computational errors that we have shared with one of the authors and have not yet received a response. Specifically:
• The PTC under Section 45 of the Internal Revenue Code (“Code”) for 2017 should be listed as 1.9¢/kWh rather than 1.8¢/kWh.
• The report’s authors appear to assume a rounding convention. Section 45(a)(2) of the Code has a rounding convention of the closest tenth of a cent for purposes of the inflation adjustment in Section 45(a)(2) of the Code, but there is no similar rounding convention for purposes of the PTC phaseout in Section 45(a)(5) of the Code. Therefore, it appears the PTC amounts will be 1.92 cents (2017), 1.44 cents (2018) and .96 cents (2019).
• However, even if the rounding convention of Section 45(a)(2) of the Code would apply to the PTC phaseout calculation, the PTC for 2019 would be .96 cents which would be rounded to 1.0 cent, not .9 cent as stated in the table.]
• Accelerated depreciation, by contrast, provides a reduction in taxable income against which the tax rate is subsequently applied, and so is described as a before-tax incentive. In addition to the five-year MACRS schedule, qualifying renewable energy projects have the option to depreciate 50% of an investment operation under a so-called “bonus” depreciation scheme. Bonus depreciation can generate sizable tax losses in the first year of the project and thus requires an entity with a significant tax liability to make efficient use of it. Moreover, high tax losses will decrease the tax equity partner’s capital account, which can introduce complications and risks into the financial structure of the project. For this reason, tax equity investors may forgo the use of bonus depreciation in wind deals.
• Depending on the performance of the project, the net present value of the full $0.024 value of the PTC combined with the accelerated depreciation benefits have historically provided in excess of 50% of the project’s initial capital costs in tax savings.
Tax Incentive Risk
• [A major area of risk with land-based wind energy projects] is the risk arising from the inability to predict with complete certainty if regulatory schemes supporting wind energy development will be available for the term described at the onset of the project. For example, the use of tax incentives that are recovered over a period of 10 years and green energy attributes that also may have multi-year contracts both provide a revenue source to the project, but are only valuable if they are considered secure by the investor in the project.
Single Ownership Structure
• If the sponsor of a wind project can duly fund the project with its own capital (or source sufficient debt for a portion), and also make efficient use of the federal tax benefits, then single ownership is likely the most economic option. The single ownership structure employs a single entity, to develop, finance, and operate a project themselves. With only one owner in the effort, there is no requirement for third-party tax equity and comparatively smaller transaction costs for setting up a project financial structure with an outside entity. Single ownership is also the simplest financial structure available to wind project sponsors, as it keeps control of the project, its assets, and its benefit streams wholly within their control.
• To make the most efficient use of the tax benefits—the PTC or ITC coupled with MACRS—a taxable entity must apply them to taxable income (depreciation) and tax liability (credits) in the year in which the benefits were generated. However, many sponsors or developers in the wind industry do not have enough tax capacity to do so and would otherwise have to carry the benefits forward (thus depleting their present value due to the time value of money) if it were not for the ability of outside investors to “monetize” them. These investors, known as tax equity investors, will commit capital to a project in exchange for access to the PTC or ITC and accelerated depreciation, thus providing the project with a sizable portion of its capital needs (typically 30%–50% of the total). Because this type of investment requires significant capital and tax liabilities, tax equity investors are often large financial entities such as banks and insurance funds.
• Tax equity, however, typically commands a higher return compared to term debt due to the relatively limited supply of tax equity (wind energy competes for tax equity investment with other energy technologies or alternative tax-oriented investments such as affordable housing) and return periods that extend to around ten years, typically a few years longer than current mini-perm term debt tenors. Among the equity options, tax equity typically assumes less risk than either the sponsor or developer equity (which may be one and the same) because of senior repayment structures and pre-defined yields.
• One of the reasons that the pool of tax equity investors is limited (which in turn can drive tax equity yields higher for the limited supply relative to demand) is the passive activity loss and at-risk rules in the U.S. Internal Revenue Code. Both rules effectively prevent certain entities from accessing the full value of the tax benefits available to investors in renewable energy projects.
• To access the tax benefits, investors must demonstrate ownership of the project assets for tax purposes (a determination made by the IRS). [Comment: The “determination” is not literally made by the IRS. In fact, the IRS is quite reluctant to provide advance rulings on questions of ownership for tax purposes. The determination of ownership for federal income tax purposes is made in accordance with federal income tax law. The taxpayer makes that determination when the taxpayer claims the tax benefits on its tax return. Most tax returns are not audited. If the IRS does audit the tax return, it may consider the question of “ownership.” If the IRS disagrees with the taxpayer’s determination and makes an adjustment, the taxpayer has the option of not paying the tax and filing a petition in the U.S. Tax Court or paying the tax and filing an action in the U.S. Court of Federal Claims or a U.S. district court. Then the federal courts will be the final arbiter of tax ownership.]
• In wind projects, this ownership usually comes in the form of a partnership with the developer (unless the project is owned by a single entity that can wholly use the tax incentives themselves). [Comment: In the partnership scenario, the owner is the entity that is taxed as a partnership. The partnership’s ownership of the project is typically accomplished by the partnership holding legal title to the turbines and related equipment and having a long-term lease of the land upon which the project is located or owning the land in fee simple.] The partnership is structured as a special purpose vehicle (SPV)—either a limited liability partnership (LLP) or limited liability company (LLC) — into which each of the partners (developer and tax equity) makes a capital contribution. [Comment: In most states, the “LLP” designation is reserved for partnerships of professionals (i.e., doctors, lawyers (e.g., Mayer Brown LLP) or accountants). We do not believe a “LLP” has ever been used as a vehicle for a wind tax equity transaction. A “limited partnership” is occasionally used as a vehicle for a tax equity transaction. Typically, however, the vehicle is a multi-member LLC that is taxed as a partnership for income tax purposes.] Each partner is allocated a certain share of the project value streams—namely income (cash) and tax benefits (deductions and credits)—which change over the life of the partnership. Two criticisms of utilizing outside tax equity investments are frequently reported. First, there are relatively few active tax equity partners in the market in any given year. Because the demand for this type of capital often outpaces the available supply, the tax equity investors may require a higher return than a comparable debt product, ranging generally from 7%–10% based on the particulars of the investment and the overall supply of market tax equity.
• The second criticism to tax equity financing is also a function of the complicated structuring. Setting up a deal entails high transaction costs—e.g., fees associated with legal services, tax opinions, consultants, financial structuring, and other services. Such transactional costs reduce the nominal value of the tax incentives and can also drive deal flow to larger project sizes (which keep the more-or-less fixed transaction costs low relative to deal size). This can have the effect of limiting the competitiveness in the wind development market place, as smaller developers may not be able to access financing as readily as larger players.
• The sponsor equity (“sponsor”) in a project most closely resembles a traditional equity investor and often can be the original developer of the project. The sponsor equity is typically the ultimate financial backstop in the project, and also the last entity to receive payment in the distribution of income in the project. Because the sponsor commonly faces the highest risk in the partnership, it will often also have the highest return requirements. However, because the sponsor equity is typically either back-levered (discussed later) or is only a marginal portion of the capital stack, this highest cost equity may exert only a limited impact on the project’s weighted average cost of capital (WACC)—the combined cost of capital from all the sources in the project’s capital stack).
• If the sponsor is also the developer, it is responsible for bringing the project from initial concept through the extensive development phase all the way to construction and commercial operations. In many cases, the sponsor may ultimately manage the long-run functioning of the project, providing O&M services, fulfilling the obligations of the PPA (if there is one), or managing the dispatch of electricity into wholesale markets. In some cases, the sponsor can also be a relatively passive or non-active owner in the project and contract out the day-to-day O&M of the project. The sponsor may also receive some of the project’s income distributions as well as a “development fee” that it collects upon commercial operation of the project. This fee varies, but some report ranges from 8%–15% of the project capital costs, which can be paid from a portion of the tax equity’s initial investment in the partnership, from any leftover construction debt, or from a portion of the term debt disbursal. Sponsor equity largely receives its returns on a primarily cash basis rather than through distribution of the tax benefits.
[Comment: “Developer fees” in renewable energy finance is an area of considerable confusion. For a detailed discussion of the tax aspects of developer fees, see https://www.taxequitytimes.com/2014/11/project-finance-developer-fees-explained/.]
Tax Equity Structures
• The partnership flip structure is the predominant tax equity financial structure currently available to wind projects due to an owner-operator requirement in Section 45 of the Internal Revenue Code (that the owner of the wind project must also be the operator), among other reasons. Thus, the use of the Section 45 PTC prevents a lease arrangement for any project that elects the PTCs since the lease splits the owner and operator roles.
• If a wind developer were to elect the ITC instead of the PTC, additional financial structures could be used including a partnership flip, sale leaseback, or inverted lease (also known as a lease pass-through).
• In a partnership flip, both equity partners (i.e., the sponsor and the tax equity) contribute the upfront capital requirement to finance the wind project and, in turn, share in the project’s economic distributions. [Comment: In many PTC tax equity transactions, the sponsor’s capital contribution is of the project and rights related to the project, rather than cash, which is contributed by the tax equity.] The principal economic benefits include distributable cash and tax losses and credits. Distributable cash is the revenue earned primarily from selling energy and environmental attributes less operating expenses. Tax deductions stem from accelerated depreciation, while tax credits are claimed from the ITC and PTC.
• Although every project is unique, in one often-employed version for wind projects, the sponsor equity and tax equity collectively fund the entirety of the project’s upfront capital requirements. The sponsor equity receives some or all of the initial distributable cash during a predefined period. Concurrently, the tax equity investor would typically receive the majority of the project’s tax benefits including both the PTC as well as taxable losses generated from accelerated depreciation and some portion of the distributable cash. After a predefined period or a financial return threshold is met, the project allocations will “flip” and the distributions of distributable cash and tax benefits shift to a second sharing allocation. The secondary allocations will typically remain until the tax equity investor achieves their pre-determined internal rate of return (IRR), which is typically modeled to occur around the expiration of the principal tax benefits (i.e., around year 10 for the PTC). After the tax equity investors achieve their IRR, the project might “flip” for a second time, after which a majority of the project’s remaining benefits flow to the sponsor.
• In executing a partnership flip, the sponsor and the tax equity will jointly invest in a SPV (the “partnership”), which will be the project operations entity (i.e., it will hold and manage the assets). Typically, the tax equity partner will contribute up to 50%–60% of the project’s cost as an investment in the partnership, with the sponsor contributing the balance. The sponsor may also use back leveraged debt to finance the sponsor’s capital contribution.
• Debt can be—though not always with tax equity involved— a “senior” investment, meaning that debt investors are typically repaid before other investors in the capital stack (i.e., most notably sponsor equity). This means that shortfalls in project revenues from underperformance, equipment failures, force majeure events, or others could cut payments to the equity holders to allow for the full and timely repayment of the loan. In some cases, however, tax equity providers may actually have repayment seniority over debt due to the relative scarcity of tax equity compared to debt. [Comment: This so-called “seniority” is a function of the lender being collateralized by the sponsor’s interest in the partnership, rather than being collateralized by the assets of the wind project. So if the lender is not paid, it steps into the sponsor’s position in the partnership, rather than foreclosing on the wind project. This type of debt is known as “back leverage.”]• In the current market, much of the term debt extended to wind projects is structured as “mini-perms.” Mini-perms are long-term debt products (where the principal and interest are amortized over a period near the length of the contracted revenue period such as a 20-year PPA), but have shorter-dated maturities (typically 5–7 years). Due to this structuring, mini-perms will have a large balloon payment that is due when the maturity is up. This balloon payment is typically refinanced by another mini-perm loan with another principal and interest amortization schedule that extends beyond the loan’s maturity.
• At current interest rates and terms, back-leveraged debt is typically priced slightly higher than project-level debt, as it can represent a riskier loan than term debt from the perspective of the lender, particularly because tax equity may have preferred repayment rights. Developers, however, will often back-leverage their debt on a project in order to attract the limited tax equity funding. Back-leverage lenders tend to be a more limited group than term-debt lenders, consisting largely of commercial banks (though some private equity players have reportedly issued loans in the back-leverage market).
• The sponsor can raise funds for project development and investment via several sources, including their own balance sheet; funding from customers and suppliers; outside private investors; and others. More recently, companies have looked to the public capital markets, employing vehicles such as yieldcos once projects were fully developed to raise equity funds at a lower cost than other sources. Additionally, a more mature company may “go public” and issue stock in the public markets and the proceeds can be used to fund development work.
• In the last several years, renewable energy developers have turned their attention to the capital markets as a source of low-cost finance that could help to reduce project LCOE [(i.e., levelized cost of electricity)]. Two means by which developers have accomplished this are through yieldcos and asset-backed securities.
• A yieldco is a corporate entity (a limited liability corporation, limited liability partnership, or joint venture) that aggregates a portfolio of energy assets for which ownership shares—i.e., stocks—are sold. Yieldcos are commonly subsidiaries of larger parent developers that hold and generate additional value from operating assets. As such, yieldcos often get a right-of-first-offer for projects developed by their parent companies, and this in turn can give the parent a captive means to sell completed projects and redeploy capital. Yieldcos also purchase operating projects and pipelines from other developers to grow their asset-base.
• Yieldcos allow project developers to potentially access lower-cost equity capital, and to source capital for growth that might otherwise be difficult to come by (either through corporate bonds, stock issuance, or other means). The principal benefit of a yieldco for investors include: limited taxation (accelerated depreciation benefits can allow yieldcos to eliminate corporate-level tax for a number of years); long-term predictable cash flows; and, until recently, the promise of dividend growth. This last benefit became difficult to achieve as yieldco sponsors found the practice of continually expanding their asset bases to be difficult to sustain. This and other factors have led to a dormancy in yieldco markets that has largely persisted since late 2015. Some of the more stable yieldcos have been able to raise some equity since that time, though others have not (owing, in some cases to financial difficulties at the corporate parent).
• To date, securitization has been most effectively executed by distributed solar sponsors (namely the large third-party finance providers such as Tesla [formerly SolarCity] and Sunrun). It is theoretically possible that a wind project could securitize its cash flows, though because wind projects tend to be large, utility-scale assets, securitization is not as readily applicable to the wind asset class at this time. The technique works well in the distributed solar space in part because the high number of offtaker contracts (residential and some commercial PPAs and leases) that back a securitization pool provides diversity that can protect investors. Additionally, there is standardization among these contracts, which facilitates pooling these assets together into a trust and alleviates the diligence requirements (and therefore costs) for investors.
• There are several reasons why the financing costs for a wind project can vary from one project to the next, as well as over time. First, some financing cost variations are attributable to macroeconomic forces and reflect the changing benchmark interest rates or the market’s risk tolerance. Second, financing rates are also driven by the unique characteristics of the project itself. For example investors will look at unique project-specific factors such as the type of the specific turbine technology utilized, its performance history in the marketplace, the commercial experience of the project developer to deliver projects on time and budget, and the specific elements within the deal to mitigate and control for risks and uncertainty. Some investors will simply be more comfortable with accepting certain types of project risks while others investors will not. Finally, other hard to quantify or subjective factors also contribute towards the overall financing costs of a project. As an example of this, the history and relationship between the firms is also an important consideration: commercial lending can be a “relationship-based” business and firms may be willing to offer preferred pricing to partners who have a long, profitable, or strategic banking partnership. In reality, many if not all of these factors contributes in varying degrees to the overall investment costs for a project.
• Utilities have traditionally been the primary offtakers/buyers for electricity from wind PPAs [(i.e., power purchase agreements)], largely because of renewable portfolio standards (RPS) at the state level. The contribution of RPS purchasing to renewable energy growth, however, has declined in recent years, falling from 71% of builds in 2013 to 46% in 2015. While compliance-oriented purchasing of renewables from utilities has been decreasing in recent years, purchases of renewable energy by corporations has been on the rise. For example, the Rocky Mountain Institute reports that all corporate renewable deals rose from 50 MW in 2012 to a recent high of 3.25 GW in 2015, which fell to 1.48 GW in 2016. Nearly 1.17 GW of corporate purchases were completed in the first six months of 2017.
• The majority of onsite renewable energy corporate procurement to date has used photovoltaic (PV) technology, with 13.8 GW of non-residential distributed PV installed at the end of 2015. Large companies have contributed significantly to this deployment. However, corporations have installed other renewable technologies as well, including wind. Commercial and industrial projects represented 57% of the 28 MW of distributed wind capacity installed in 2015. Offsite procurement can also allow corporations the ability to diversify their renewable energy procurement, potentially sourcing energy that is complementary to its needs. As an example, a corporation may contract with a wind facility to offset more of its nighttime and winter energy needs (when wind resources are typically the highest) and a solar facility to offset more of its daytime and summer energy needs
• As of October 2015, virtual net metering for wind projects was available to some corporations in six states and the District of Columbia. These states include Maine, Massachusetts, New Hampshire, Pennsylvania, Vermont, and Illinois (in which utilities can choose to offer virtual net metering). An additional four states offer virtual net metering to state and local governments, multi-tenant properties, or agricultural customers.
• Virtual PPAs (also known as “financial PPAs,” “synthetic PPAs,” “contracts for differences,” or “fixed for floating swaps”) do not involve the direct purchase of energy as do onsite PPA contracts or Direct PPAs with virtual net metering. Virtual PPAs, by contrast, require the ability to sell electricity into a wholesale electricity market. As of this writing, virtual PPAs are among the most preferred form of offsite corporate renewable energy procurement in the United States.