The U.S. Department of Energy recently released its 2016 Wind Technologies Market Report (available here). The 94-page report provides an in-depth review of the current health and direction of the wind industry, replete with data, analysis and projections. Below are quotes from the report that are of particular interest to participants in tax equity transaction.
Tax Equity Economics in 2016
• [According to AWEA in U.S. Wind Industry Annual Market Report: Year Ending 2016], [t]he U.S. wind market raised more than $6 billion of new tax equity in 2016, on par with the two previous years. Debt finance increased slightly to $3.4 billion. Tax equity yields drifted slightly higher to just below 8% (in unlevered, after-tax terms), while the cost of term debt fell below 4% for much of the year, before rising back above that threshold towards the end of the year.
• According to AWEA [in U.S. Wind Industry Annual Market Report: Year Ending 2016], roughly $6.4 billion in third-party tax equity was committed in 2016 to finance 5,538 MW of new wind projects. This total dollar amount is slightly higher than, but largely on par with, the amount of tax equity raised in both 2014 and 2015. Partnership flip structures remained the dominant tax equity vehicle, with indicative tax equity yields drifting slightly higher in 2016, to just below 8% on an after-tax unlevered basis.
Debt Markets in 2016
• On the debt side, AWEA [in U.S. Wind Industry Annual Market Report: Year Ending 2016] reports that 2,677 MW of new and existing wind capacity raised $3.4 billion in debt in 2016, up from the $2.9 billion raised in 2015. As they have in recent years, banks continued to focus more on shorter-duration loans (7–10 year mini-perms remained the norm), leaving longer-duration, fully amortizing loans to institutional lenders. [A]ll-in interest rates on benchmark 15-year debt were below 4% through most of 2016—a level not previously breached in the prior 11 years of the graph—before rising by roughly 50 basis points to back above 4%. Short-term interest rates have also begun to rise, as the U.S. Federal Reserve Bank has ratcheted up the federal funds rate by 25 basis points on four separate occasions since mid-December of 2015 (after seven straight years of holding it at 0%). For the most part, long-term interest rates seem to have shrugged off the Federal Reserve’s rate hikes to date, with the Fed’s rate-hikes not flowing through one-for-one to benchmark all-in interest rates for long-term debt.
• [Editor’s note: The report does not speculate as to why tax equity returns edged up while debt returns held relatively steady at historic lows. A possible explanation could be that the large demand for solar tax equity in 2016 drove up the cost of wind tax equity as solar and wind projects were competing for investment from the same publicly traded tax-paying corporations.]
Emerging Industry Trends
• Supported by favorable tax policy and other drivers, cumulative wind power capacity grew by 11% [from the average over the previous 5 years (2011–2015)], bringing the total to 82,143 MW.
• The average rotor diameter in 2016 was 108 meters, a 13% increase over the previous 5-year average, while the average hub height in 2016 was 83 meters, up just 1% over the previous 5-year average
• The nation’s first offshore project was also commissioned in 2016, the 30 MW Block Island project in Rhode Island.
• Looking ahead, large numbers of safe-harbored wind turbines seeking deployment in viable projects will keep financiers busy for the foreseeable future. One potential wrinkle involves the prospect of federal tax reform, which (among other things) could alter both the availability and returns of third-party tax equity, depending on the nature of any such reforms. Financiers have reportedly been modifying term sheets to include indemnities, cash sweeps, and other documentation that allocates the risk of tax reform among the various parties.
• Wind power capacity in the United States experienced strong growth in 2016. Recent and projected near-term growth is supported by the industry’s primary federal incentive—the production tax credit —as well as a myriad of state-level policies. Wind additions have also been driven by improvements in the cost and performance of wind power technologies, yielding low power sales prices for utility, corporate, and other purchasers. At the same time, the prospects for growth beyond the current PTC cycle remain uncertain, given declining federal tax support, expectations for low natural gas prices, and modest electricity demand growth.
• Analysts project that annual wind power capacity additions will continue at a rapid clip for the next several years, before declining, driven by the 5-year extension of the PTC signed in December 2015 and the progressive reduction in the value of the credit over time.
• As a result [of the extension of the PTC and its phaseout], various forecasts for the domestic market show expected capacity additions averaging more than 9,000 MW/year from 2017 to 2020 (a pace that is supported by the amount of PTC-qualified wind turbine capacity that was reportedly safe-harbored by the end of 2016). Forecasts for 2021 to 2025, on the other hand, show a downturn in part due to the PTC phase-out.
• As a result [of the extension of the PTC and its phaseout], though some manufacturers increased the size of their U.S. workforce in 2016, market expectations for significant supply-chain expansion are less optimistic.
PTC and Accelerated Tax Depreciation
• The federal production tax credit remains a core motivator for wind power deployment. In December 2015, Congress passed a 5-year phased-down extension of the PTC, which provides the full PTC to projects that start construction prior to the end of 2016, before dropping in increments of 20 percentage points per year for projects starting construction in 2017 (80% PTC), 2018 (60%), and 2019 (40%). In May 2016, the IRS issued favorable guidance allowing four years for project completion after the start of construction, without the burden of having to prove continuous construction. According to various sources, 30-70 GW of wind turbine capacity had been qualified for the full PTC by the end of 2016, for deployment over the coming four years.
• In addition to the PTC, a second form of federal tax support for wind is accelerated tax depreciation, which historically has enabled wind project owners to depreciate the vast majority of their investments over a 5- to 6-year period for tax purposes. Even shorter “bonus depreciation” schedules have been periodically available, since 2008. [Editor’s note: Bonus depreciation at progressively decreasing levels (50% for projects in service this year; 40% for projects in service in 2018; and 30% for projects in service in 2019) is available under current law for wind projects that are placed in service before January 1, 2020.]
• With projects having had to start construction by the end of 2016 in order to qualify for the PTC at 100% of its nominal value, 2016 was another busy year for financiers. But with a 4-year safe harbor window in which to bring any such-qualified projects online, many of the projects financed in 2016 will achieve commercial operations in 2017 or later.
• According to various sources, 30-70 GW of wind turbine capacity had been qualified for the full PTC by the end of 2016, for deployment over the coming four years.
• Developers have reportedly qualified a significant amount of new wind turbine capacity for the full PTC by starting construction (as per the IRS safe harbor guidelines) prior to the end of 2016. [One law firm] reports two such estimates of PTC-qualified capacity—30-58 GW and 40-70 GW—while consultant MAKE pegs the number at 45 GW. A single developer/sponsor—NextEra Energy—has stated [in an analyst conference] that it qualified more than 10 GW on its own.
Effects of the PTC Phaseout in 2016
• The availability of federal tax incentives underpins recent low-priced power purchase agreements for wind energy, and is a significant contributor to the near-term expected surge in wind capacity additions. The PTC phase down, on the other hand, imposes risks to the industry’s competitiveness in the mid- to long-term.
• As wind power capacity in the United States has grown, foreign and domestic turbine equipment manufacturers have localized some operations in the United States. Yet, the wind industry’s domestic supply chain continues to deal with conflicting pressures: an upswing in near- to medium-term expected growth, but also strong international competitive pressures and expected reduced demand over time as the PTC is phased down. As a result, though some manufacturers increased the size of their U.S. workforce in 2016, market expectations for significant supply-chain expansion are less optimistic.
State Renewable Energy Portfolio Standards
• As of July 2017, mandatory RPS (renewable portfolio standard) programs existed in 29 states and Washington D.C. Attempts to weaken RPS policies have been initiated in a number of states, and in limited cases—thus far only Ohio in 2014 and Kansas in 2015—have led to a temporary freeze or repeal of RPS requirements. In contrast, other states—including, most recently, California, Hawaii, Maryland, Michigan, New York, Oregon, Rhode Island, and Washington, DC—have increased their RPS targets. Vermont has created a new RPS.
• Of all wind power capacity built in the United States from 2000 through 2016, roughly 51% is delivered to load serving entities (LSEs) with RPS obligations. In recent years, however, the role of state RPS programs in driving incremental wind power growth has diminished, at least on a national basis; 21% of U.S. wind capacity additions in 2016 serves RPS requirements. Outside of the wind-rich Interior region, however, RPS requirements continue to form a strong driver for wind growth, with 90% of 2016 wind capacity additions in those regions serving RPS demand.
• In aggregate, existing state RPS policies will require 450 terawatt-hours (TWh) of RPS-eligible renewable electricity by 2030, at which point most state RPS requirements will have reached their maximum percentage targets. Based on the mix and capacity factors of resources currently used or contracted for RPS compliance, this equates to a total of roughly 144 GW of RPS-eligible renewable generation capacity needed to meet RPS demand in 2030. Of that total, Berkeley Lab estimates that existing state RPS programs will require roughly 55 GW of renewable capacity additions by 2030, relative to the installed base at year-end 2016. This equates to an average annual build-rate of roughly 3.9 GW per year, not all of which will be wind. By comparison, over the past decade, U.S. wind power capacity additions averaged 7.1 GW per year, and total U.S. renewable capacity additions averaged 11.3 GW per year. Clearly, current RPS policies cannot—alone—support continued wind power growth at recent levels.
State Tax Incentives
• State renewable energy funds provide support (both financial and technical) for wind power projects in some jurisdictions, as do a variety of state tax incentives—though one state, Oklahoma, recently eliminated its wind power production tax credit.
• The Northeast’s Regional Greenhouse Gas Initiative (RGGI) cap-and-trade policy, for example, has been operational for a number of years, and California’s greenhouse gas cap-and-trade program commenced operation in 2012, although carbon pricing in these programs has generally been too low to drive significant wind energy growth thus far.