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Figure 5.6 Share of renewables in electricity generation in IEA countries, 2018

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IEA (2019). All rights reserved.

The US share of renewable energy in electricity generation has increased from 8% to 17% in ten years, but it is still the eighth-lowest among IEA member countries.

*Includes solid biofuels, renewable waste, liquid biofuels and biogases.

**Includes hydropower (excluding pumped storage), tidal, wave and ocean energy. Source: IEA (2019), World Energy Balances 2019, www.iea.org/statistics/.

Policies and measures

Federal tax credits

Aside from innovative clean energy technology research and development (R&D) efforts, the main policy tool at the federal level to support the growth of renewables are tax credits, which can be used to offset income tax obligations for households and companies. The tax credits are administered by the Internal Revenue Service (IRS), which issues implementing guidance to recipients.

For solar, the primary policy support is a 30% investment tax credit (ITC) for residential, commercial and utility-scale solar installations. Congress established the 30% ITC under the Energy Policy Act of 2005. The original 30% credit was valid for two years, but Congress subsequently extended it, most recently as a multi-year extension under the Omnibus Appropriations Act of 2015 (SEIA, 2019b). The latest extension was achieved through a bipartisan compromise that included lifting the US ban on crude oil exports. Despite some discussion of revising the tax credits to fund a corporate income tax reduction as part of the Tax Cuts and Jobs Act of 2017, Congress decided to leave the credits intact, which will continue to provide support for renewables energy expansion throughout the United States.

The most recent changes extend the solar ITC through 2023, though phase down its rate over that time frame. The ITC will fall to 26% in 2020 and 22% in 2021. After 2021, residential tax credits fall to zero, while commercial and utility-scale projects will fall to 10%. The legislation also changed the qualification of projects from those in service to those that begin construction, allowing more projects to qualify for the credits.

Policy support for wind energy has been in place since 1992 (and extended multiple times) in the form of the renewable electricity production tax credit (PTC), valid for ten

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years after a project goes into service (DOE, 2019a). Though wind producers can opt instead for an ITC, the PTC has proven more attractive for wind investments. The ITC is generally expected to be more valuable to US offshore developers, however. As part of the 2015 legislation that extended the solar ITC, Congress also agreed to phase out the PTC by the end of 2019 (AWEA, 2019b). Projects that started construction before 2017 qualified for a PTC of USD 0.023 per kilowatt, adjusted for inflation; the PTC ratchets down by 20% in 2017, 40% in 2018 and 60% in 2019, until it expires entirely for projects beginning construction after 2019.

Public Utility Regulatory Policies Act

Amid an energy crisis, the United States passed the Public Utility Regulatory Policies Act (PURPA) in 1978 in order to promote the use of alternative energy sources and to establish a marketplace for non-utility power producers. Under the law, regulated utilities are obliged to purchase power from “qualified facilities” at a rate equal to the utility’s cost to produce the power, or at the utilities’ so-called “avoided cost” (FERC, 2019).

With the emergence of competitive wholesale markets, the Federal Energy Regulatory Commission (FERC) has applied a waiver to the purchase obligations under PURPA in most states (under the Energy Policy Act of 2005). It found several regional electricity markets (PJM, the New York Independent System Operator [NYISO], ISO New England [ISO-NE], the California Independent System Operator [CAISO], the Midcontinent Independent System Operator [MISO], the Electric Reliability Council of Texas [ERCOT], and the Southwest Power Pool [SPP]) to be sufficiently competitive for non-utility power producers to enter these markets on their own. FERC waived the mandatory purchase obligation in those regions with respect to projects between 20 megawatts (MW) and 80 MW. However, in states not governed by regional transmission organisations, which include Idaho, Utah, Wyoming, North Carolina and Montana, PURPA has become a significant driver for renewables buildouts as cost reductions for wind and solar (especially utility-scale solar) have allowed them to clear the PURPA threshold for avoided cost (EIA, 2018). Yet there remains a considerable degree of disagreement between utilities on the one hand, which contend that they cannot manage the influx of renewables they are forced to take, and renewable power developers on the other hand, who worry that changes to PURPA terms will chill investment. In response, a number of these states have introduced changes to contract length, eligibility and remuneration, which will slow the buildout of renewables (Utility Dive, 2018a).

In 2016, FERC began a review of PURPA, along five main areas: i) whether the mandatory purchase obligation PURPA places on utilities with respect to qualified facilities under 20 MW in organised, competitive markets should be retained; ii) whether FERC’s “one-mile rule”, which provides that projects that are at least one mile from each other are separate for purposes of determining whether they meet the 20 MW threshold, should be reconsidered; iii) when power generated by qualified facilities may be curtailed; iv) potential improvements to the avoided cost analysis; and v) whether there are minimum contract terms and conditions necessary for developers to secure financing (Utility Dive, 2018b). FERC committed to revisiting the review in 2018, but the commission has not announced any additional steps yet.

Renewable portfolio standards

The federal government does not have an RPS policy in place, though several proposals have been introduced in Congress at various times. However, a number of US states

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have adopted RPS policies, which require retail electricity providers to source a certain share of supply from qualified renewable sources (National Conference of State Legislators, 2019). Twenty-nine states plus the District of Columbia currently have RPS policies in place (eight states have voluntary targets), and they have been an important driver of renewable technology deployment in the United States, estimated to account for around half of renewables generation and capacity growth in the electricity sector since 2000 (Lawrence Berkeley National Laboratory, 2019). RPS plans have been particularly important in driving renewable energy growth in the Northeast, Mid-Atlantic and West. While emissions reduction goals are a driver of state RPS policies, they are also enacted to harness local energy resources, diversify the fuel mix and support local economic activity.

Most states administer their RPS targets on the basis of a percentage of retail electricity sales, though Iowa and Texas measure them based on explicit quantities of renewable capacity and Kansas as a share of peak demand. The specific rules of each RPS plan can vary widely from state to state, including the targets themselves, carve-outs for specific technologies, cost caps and rules governing the trading of renewable energy credits (NREL, 2016).

Since their adoption, many states have raised their RPS targets to encourage more uptake of renewables. More recently, in 2019, several states made significant changes to strengthen their RPS programmes, including Colorado, District of Columbia, Maryland, Maine, New Mexico, Nevada, New York and Washington. California, Hawaii and Washington are among the states that have the most ambitious targets; they have legislated that 100% of electricity will come from renewable sources by 2045 (with interim targets to inform the pathway) (Greentech Media, 2018a). Nevada in April 2019 passed legislation that targets 100% of carbon-free electricity by 2050, while New York passed legislation in June to achieve 100% carbon-free electricity by 2040 (EIA, 2019b).

Corporate tax policy

Renewables projects have enjoyed tax advantages in the form of accelerated depreciation allowances. However, recent changes in federal tax policy might have implications for financing of some renewables projects. In December 2017, the US Congress passed the Tax Cuts and Jobs Act of 2017, which reduced the maximum corporate tax rate from 35% to 21%. While the overall reduction in the corporate income tax will benefit developers’ profitability for renewable projects, the changes could have negative impacts on tax equity financing for renewables, under which returns are partially based on the value of tax credits a project can claim (Norton Rose Fullbright, 2017). A sizeable share of renewables projects is financed through tax equity (a Greentech Media study estimated 40-60%), so the reduction in the tax rate could lower the value of tax deductions and thus increase the cost of tax equity (Greentech Media, 2018b). However, developers and the financial community are working on innovative business models to minimise this impact.

In addition, the tax bill included a base erosion and anti-abuse tax (BEAT), which is a new minimum tax designed to prevent multinational companies from claiming large tax deductions through cross-border payments. Renewables developers often sell their tax credits to multinational investors to reduce their tax obligations (Bloomberg, 2018a). The final version of the legislation included a provision that still allows multinational companies to use up to 80% of the federal ITC and PTC values to offset BEAT obligations (Greentech Media, 2017).

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Trade policy

Several trade policy actions by the administration will also have implications for the renewables sector. The most direct trade action impacting renewable electricity is the January 2018 imposition of import tariffs on imported crystalline-silicon solar PV cells and panels under Section 201 of the Trade Act of 1974 (Bloomberg, 2018b). The decision followed an investigation by the US International Trade Commission based on complaints of financial distress filed by US solar producers Suniva and SolarWorld. The tariffs will be in effect for four years. They were set at 30% in the first year, falling by 5% each subsequent year, though include a 2.5 gigawatt (GW) exemption for solar cells each year. Given the US industry’s heavy dependence on imported solar cells and panels, the policy is expected to raise costs in the short-term and could have an impact on the pace of new solar capacity installations for the next few years (Reuters, 2018).

In March 2018, the administration imposed a 25% tariff on imported steel and a 10% tariff on imported aluminium on national security grounds under Section 232 of the Trade Expansion Act of 1962 (US Customs and Border Protection, 2019; White House, 2018). Though the administration offers some country-level exemptions and companyspecific exemptions, the measures could raise costs for renewables installations, such as wind turbines, which use these commodities during construction (Greentech Media, 2018c).

For biofuels, imports of biomass-based diesel were down following the imposition of antidumping and countervailing tariffs on Argentinian and Indonesian imports in March 2017. Moreover, countries importing US fuel ethanol have also raised tariffs, setting back US exports. The People’s Republic of China (hereafter “China”) raised its import tariff on fuel ethanol from 5% to 30% in 2017, while Brazil imposed a 20% tariff on US ethanol volumes of over 150 million litres per quarter.

Net metering

A number of US states have net metering laws in place, which permit residential and commercial customers who generate their own renewable power to sell surplus electricity (usually at retail rates) back to the grid (DOE, 2019a). The plans primarily apply to rooftop solar installations, and have been an important driver for the expansion of residential and commercial applications. As of July 2017, 38 states plus the District of Columbia had mandatory net metering rules in effect (SEIA, 2019c).

The success of rooftop solar policies in several states has occasionally resulted in an abundance of solar power fed into the grid, creating challenges for utilities in balancing demand with more unpredictable supply (NREL, 2019a). The issue is particularly acute during the afternoon, when the maximum amount of sunlight can generate more electricity than the load requires in some locations. Subsequently, demand tends to pick up again during the evening hours after people return home from work, when the sun is no longer shining. In states like California, the situation has created the so-called “duck curve” that highlights supply-demand imbalances that can emerge from rooftop solar generation at certain times of the year. In some cases, the amount of rooftop solar generation can result in surplus power on the grid that creates negative electricity pricing and forces curtailment. For California, in particular, which has required nearly all new homes to be fitted with rooftop solar panels starting in 2020, addressing the issue of integrating large volumes of distributed solar will become more salient in the coming years.

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