Renewable energy growth: What's driving the future of sustainable resources
The market trends for renewable energy keep growing, despite challenges. Experts point to policy and technological advances as the driving forces behind future expansion.
Exhibit 1: Historical renewable drivers
Federal tax credits will continue to play a critical role in the expansion of renewables, despite declining incentives. The two largest incentives are the Investment Tax Credit and Production Tax Credit (PTC), which were both renewed for five years by the Consolidated Appropriations Act of December 2015.
However, the act included a phase-out stipulation for both tax credits. Thus, by 2024, all new wind and some solar additions will no longer be subsidized.
Under the phase-out, land-based and offshore wind facilities that commence construction during 2016 will receive the full after-tax PTC value of 2.3 cents/kWh for ten years. After 2016, the value of the PTC will decrease by 20 percent per year for the subsequent three years. Once a wind project commences construction, the facility has four years to come online, per Internal Revenue Service guidance.
A wind facility may select an ITC in lieu of the PTC. The ITC provides a 30 percent tax credit off of the project’s cost in the year it comes online. For 2017, it phases down 20 percent each year through 2019, in line with the PTC phase-out. This is a crucial option of offshore wind facilities, due to the high capital costs involved.
The ITC is more closely associated with solar. For solar, the ITC declines four percent per year for projects commencing construction in 2020, before dropping to 10 percent for commercial projects starting 2022 and beyond, but falls to zero percent for distributed solar projects. The IRS recently released guidance confirming that solar facilities have four years to come online after commencing construction to claim the ITC. The only exception is facilities that commence construction in 2021—they must be online by 2024 to claim the 22 percent credit. Beginning in 2024, all commercial facilities placed in service will receive the 10 percent credit.
The ITC has also helped the nascent storage market, as developers have paired storage with solar facilities, allowing them to apply the ITC to both the solar and storage components.
Exhibit 2 and 3: PTC and ITC rolloffs
Note: ICF assumes PTC comprises 40 percent of the capital cost for a project with a 29 percent capacity factor. The reduction in PTC value would mean that projects commencing construction in 2019 would only have 16 percent of the capital cost covered by the PTC.
The Public Utilities Regulatory Policy Act has been a significant driver of solar growth in select states, most notably North Carolina. Under PURPA, utilities must buy power from “qualifying facilities” if they are developed at a cost equal to or below a utility’s avoided cost paying for a traditional power plant. Due to distinct methodologies for calculating costs, PURPA implementation varies significantly from state to state.
As the costs of solar power have come down, PURPA has driven solar installations in select states with favorable contract rates and lengths. In 2017, roughly 30 percent of utility-scale solar projects were PURPA qualifying facilities.
Due to the steep drop in solar costs, some utilities are facing an influx of interconnection requests. Given the inflexibility of PURPA, this has led some utilities to find the interconnection demand untenable and to push for reform.
The proceedings thus far have led to state-specific changes regarding implementation. Some have resulted in relatively harmless—or even favorable—changes, while others have effectively ended PURPA-driven development in states like Idaho.
Market trends lead utilities to change positions
Economics, not policy, are driving one of the largest trends in the power sector: coal retirements. This provides a big opportunity for renewables.
Facing the poor economics of aging coal plants, utilities are seeking opportunities to retire coal facilities early to take advantage of lower-cost resources. Lazard’s unsubsidized levelized cost of energy comparison depicts the competition coal and combined cycles face against cheap wind and utility-scale solar.
EXHIBIT 4: Lazard levelized cost of energy sources
This new economic reality is reflected in recent utility integrated resource plans, where they are strategizing how to manage the financial impacts of a transition away from coal. This presents an opportunity to add economic renewables to backfill coal capacity.
An example of this is Xcel Energy’s “steel for fuel” investment strategy for regulated utilities, which recognizes the financial benefit of rate-basing renewable investments to replace uneconomic coal facilities without impacting retail rates.
Some state regulators are ensuring utilities consider renewables and battery storage as replacement options, instead of only natural gas, due to long-term financial risks associated with potentially stranded fossil assets. As more states consider accounting for the price of carbon in their energy plans, these pressures will likely increase.
State clean energy policies
Putting a price on the externality of carbon emissions facilitates the development of cleaner resources by providing a more favorable economic outlook for clean energy resources. Ten states in the U.S. are currently facing a price on carbon in their decision-making processes through the California and Regional Greenhouse Gas Initiative cap-and-trade programs.
This grouping of states will grow to twelve when Virginia and New Jersey join the initiative in 2020. However, utilities in other states are taking carbon price into account in their planning processes through mechanisms other than direct state policy. States including Colorado, Minnesota, and Washington directly use an estimate of the social cost of carbon (SCC) in their integrated resource planning. Additionally, Illinois and New York both use the SCC to calculate the Zero Emission Credit subsidy given to existing nuclear facilities.
States set targets for renewables
Currently, 29 states and Washington, D.C. have a version of a Renewable Portfolio Standard (RPS). An RPS requires load-serving entities to supply a certain percentage of their electricity from eligible renewable energy sources. To show compliance, these entities must retire the appropriate number of renewable energy credits (RECs), which represent one megawatt-hour of renewable energy generation.
Most of these policies were established in the early 2000s, and five states have already reached their final target years. Washington, Maryland, and New Mexico will reach their terminal year in 2020 unless the states take action this year to extend their programs.
Eleven more states will face their final year in 2025/2026, leaving just ten states with programs that will continue to increase through 2030. As such, most states with RPS policies will have to choose whether to modify their programs and aim for higher renewable goals or allow them to stagnate.
EXHIBIT 5: Continental United State RPS targets
In 2018, California, New Jersey, Connecticut, and Massachusetts all passed clean energy policy packages. Each state revised its RPS programs, creating Clean Energy Standards (CES) in place of, or in addition to, their RPS programs.
Reflecting a growing trend to align incentive policies with long-term decarbonization goals, New Jersey joined Illinois and New York in creating Zero Emission Credits to support its nuclear facilities. While CES programs include a broader group of resources than most RPS programs, such as large-scale hydro and clean energy imports, so far they have not been the policy mechanism through which states have subsidized nuclear plants.
In conjunction with its CES, Massachusetts introduced the country’s first clean peak standard, which requires utilities to procure a certain amount of clean electricity during peak demand hours. These standards, along with battery storage mandates, are also emerging trends in states that emphasize the reduction of carbon emissions.
Corporate renewable energy goals
The latest trend in renewable energy industry growth comes from corporate procurement. Renewable cost declines, aggressive sustainability goals, and fossil fuel price volatility are pushing companies towards renewables.
In 2018, corporations announced over 6.5 GW of renewable deals, representing 22 percent of all onshore wind and solar Power Purchase Agreements (PPAs) signed in 2018. By 2025, corporate demand is expected to reach 60 GW, according to the Renewable Energy Buyers Alliance.
Corporate deals are offering developers and utilities a source of long-term contracts outside of compliance RECs (i.e., to satisfy an RPS requirement). The structure of these deals is contingent on whether the demand comes from a regulated or deregulated state.
In deregulated power markets, companies have the choice between physical or virtual PPAs. Most PPAs to-date have been virtual (VPPA)—mainly for wind in Texas and Oklahoma in the Southwest Power Pool. However, the future looks bright for solar, which comprises over 40 percent of the PPA pipeline.
This forecasts growth, particularly in states like Texas, where the solar generation profile is positively correlated with load. PPAs facilitate renewable development in regions without specific policy supports. Instead, factors such as excellent resource potential and socialized transmission cost allocation—as opposed to borne by developers—spur development.
VPPAs generally take the form of hedge contracts, wherein the developer still sells the power from the project to the grid but enters into a contract-for-differences with a third party. The corporate off-taker guarantees the developer a fixed price for the electricity the developer sells in the wholesale market. If the power sells for less than the fixed amount, the off-taker pays the difference, and vice-versa.
Another option is a Sleeved PPA, where the generation owner sells RECs and electricity directly to the corporate off-taker.
Exhibit 6: Renewable project power purchase agreement constructs
VPPAs facilitate the development of renewables because the load and supply need not be co-located for corporate off-takers. While some corporate off-takers prefer to contract for renewables locally to directly supply their needs, others will sign contracts in states far from their operations if the economics are more favorable. For example, a corporation with operations in Nevada may choose to contract with renewable supply in the midlands, even though that energy will never reach its facilities.
In regulated states, corporate customers are restricted to deals with the local monopoly utility, unless they want to pay hefty fees to procure renewables on the open market. Large energy users like Microsoft and MGM Resorts have done this in Washington and Nevada, respectively.
To avoid losing large clients, regulated utilities have begun to offer green tariffs: an electricity rate structure that allows eligible customers to source their electricity from renewable only sources. Green tariffs allow corporations to purchase not only sustainable power, but also the RECs from the generators (which are required to verify they are meeting stated renewable targets).
Diving deeper into regional trends
Federal regulations helped kick off the renewable energy industry, but for the foreseeable future, states policies will be the most effective drivers of new development. Utilities are starting to innovate their practices to comply with state policies, transition away from higher emission resources, and meet corporations’ demands for a cleaner generation mix.
These trends are taking place across the country. However, there isn’t one, single renewables market in the United States. The second part of our series will focus on regional factors and the role they are playing in the outlook for renewable energy.