- Economies of scale continue to reduce solar costs dramatically, leading the market to reach 25 GW in 2015.
- The recent renewal of the investment tax credit will drive continued cost innovation for solar, allowing it to achieve subsidy independence by the early 2020s.
- In total, solar power could climb from less than 1% of U.S. electricity in 2015 to as much as 10% of U.S. electricity by 2025.
- However, brewing state level policy battles around net metering and rate structures present significant challenge and uncertainty for distributed solar.
Solar Now Central to Future of U.S. Electricity
2015 may be remembered as a key turning point for solar energy in the United States. It was another record year for solar installations, with cost decreases topped off by a surprise renewal of the critical investment tax credit.
At this point, solar is on track to reach 20-30% of U.S. generation by the 2030s. The renewal of the tax credit, strengthening state renewable portfolio standards, and ongoing cost declines provide significant tail winds, particularly for utility-scale solar. The major uncertainty lies with distributed solar, where utilities are beginning to challenge favorable state policies.
These trends will define electricity in the United States for the next 20 years. In part 1 of a three-part analysis, we focus on the many factors underlying solar growth and cost innovation for both utility-scale and distributed solar. In part 2, we cover the challenges to finding successor policies to net metering. In part 3, we outline the potential impacts of solar on electricity markets and regulatory design.
Massive Cost Reductions Key to Solar Growth to Date
The most recent numbers from GTM Research and the Solar Energy Industries Association are now in, finding that the U.S. installed a record setting 7.3 GW of solar PV in 2015. This represents a 17% growth rate from 2014 and the U.S. now has more than 25 GW of residential, commercial, and utility-scale solar installations.
Further, solar generation is reaching significant levels. Through November, EIA data indicates solar was responsible for almost 0.7% of U.S. generation in 2015. Notably, this statistic may underestimate distributed solar and only includes partial-year generation from facilities installed in 2015.
With these adjustments, the solar currently installed in the U.S. will likely generate 1% of U.S. annual generation needs. Although 1% does not sound like a lot, there are two important points to keep in mind.
First, a large amount of this solar is located in or near California. Solar was responsible for 5% of instate generation in 2014 and near 10% in 2015. The impacts of solar in California will be a key bellwether for market disruptions and necessary policy responses required in the rest of the country.
Second, solar growth is likely to continue. The relationship between prices and installations illustrates why.
U.S. Utility-Scale Solar PV Prices versus Total Utility-Installed Capacity
Levelized prices for utility-scale solar fell by two thirds during the last five years, according to Lawrence Berkeley National Laboratory. Notably, these prices do not include the cost of investment tax credits, which reduce prices by 30% (a bit less when you include tax credit financing costs).
Critically, state renewable policies have provided key support for solar and will continue to do so, as have tax credits (discussed below). But to understand where solar costs will head in the future, it is important to understand the technical and market factors behind these cost declines.
Falling prices for utility-scale solar are due to several factors:
- Module costs fell significantly between 2010-2012
- Average O&M costs declined by more than half between 2011 and 2014
- Average capacity factors of installed projects are increasing, due to both geographic and technical characteristics
These trends in utility-scale solar have also been matched in distributed solar, for similar reasons. Between 2010 and 2014:
- Residential prices decreased by 40%
- Module prices decreased 59%
- Median system sizes increased 19%
- Median capacity factors increased 14%
Reports of exceptionally low solar prices are now very common. Most recently, a proposed 25-year solar contract in Palo Alto had a price of $37/MWh. Even excluding the full 30% tax credit, the cost is less than $53/MWh.
With or without the benefit of the tax credit, these are very attractive prices for utilities or companies. Solar generates electricity during peak hours, when wholesale electricity prices are the highest. Wholesale power prices suffer from volatility and can experience severe price spikes during stressed conditions.
A long term contract of $37/MWh is highly competitive on its own, but also has limited risks compared to just taking the wholesale market price. This deal is the most recent example of a very low solar price, but it is a harbinger of more to come.
Solar Cost Declines Result from Increasing Capacity
Although the specific factors driving solar cost declines vary, they all have one thing in common: economies of scale. As the solar industry grows, larger factories can produce cheaper panels, companies can streamline operations, and different cost components can be reduced. The more solar that is installed, the cheaper it becomes to install future solar.
Critically, economies of scale occur in both global and local markets.
In the late 2000’s and early 2010’s, Germany used a generous feed-in tariff to drive massive solar growth. This provided an initial boom in global solar capacity that enabled economies of scale to drive down module costs globally as companies competed to get large parts of a growing market. Although Germany’s Energiewende is often criticized, it catalyzed the growth of the entire global solar industry.
Lower module costs globally reduce solar installation costs in every country. This then allows solar to start growing in individual countries. As solar becomes more common in local markets, local economies of scale then lead to lower installation, permitting, labor, and other soft costs.
The chart below illustrates that even before the recent tax credit extension, solar prices were expected to continue declining through 2018 as the industry expanded.
Reported, Bottom-up, and Analyst Average U.S. PV System Prices
ITC Extension to Enable Continued Cost Innovation
For years, the wind industry has suffered heavily from the on-again, off-again nature of the wind production tax credit. Congress would renew the program for only 1-3 years, then let the credit almost expire or expire before renewal. This disrupted construction timelines, workforce development, and cost innovation.
Comparably, tax credit support for solar energy has been relatively steady. Originally authorized for a two-year period in the Energy Policy Act of 2005, the credit first received a one-year extension through 2008, and then an eight-year extension through 2016.
For most of 2015, the looming expiration of the credit at the end of 2016 was a major concern for industry. While industry focused on cutting costs and project timelines were accelerated to quality for the credit, there was uncertainty about what solar would look like in a post-tax credit world.
The central question: were recent cost declines enough to make up for the loss of a 30% credit?
In a move that surprised everyone, Congress renewed both the wind and solar tax credits in late 2015, as part of the most significant energy policy action from Congress in years. For solar, the tax credit was extended fully through 2019 with residential host-owned solar ramping down fully by 2022 and utility and third-party-owned solar ramping down to 10% and staying there permanently.
Renewable Tax Credits After December 2015 Extension versus Before Extension
The effect of this renewal really cannot be overstated.
GTM Research estimates that the tax credit extension will increase utility-scale installations by 17 GW between 2017 and 2020 and drive an additional 6 GW of residential installations. In total, GTM projects that the U.S. solar market will add 72 GW between 2016 and 2020, with annual solar installations reaching 20 GW a year by 2020.
In this scenario, by 2020, the U.S. will meet 4-5% of its annual generation with solar while adding enough solar each year to cover an additional 0.7-1.0% of U.S. electricity demand, depending on the location and average panel efficiency.
Critically, this large increase in solar (approximately quadrupling current installation levels) will drive further economies of scale and lead to solar costs being much lower than they would have been without the tax credit expiration.
While the expiration of the tax credit in 2016 could have killed the industry, the cost innovations likely to occur between now and 2021 mean solar should reach subsidy independence and survive the expiration of the tax credit.
Full Effects of Tax Credit Renewal May Not Be Broadly Recognized
In an important contrast, the National Renewable Energy Laboratory just released a study looking at the impact of the tax credit extension on renewable deployment. It finds that the extension will only increase solar to around 55 GW by 2020, about half of GTM Research’s estimates. (Notably, BNEF has its own solar forecast that is about halfway between NREL and GTM Research, although we do not examine that forecast here.)
NREL finds the tax credit extension only incentivizes 10 GW of additional solar by 2020, with annual solar installations only reaching 6 GW. Confusingly, NREL also finds that annual solar installations between 2023 and 2030 are near identical or lower with the tax credit extension than without it.
Solar Capacity Projections Following ITC Extension
What explains the difference between GTM Research’s and NREL’s projections? Modelling methodology.
GTM Research conducts bottom-up projections while NREL is using a top-down optimization model like those that dominate energy modelling (EIA, IEA, EPA, numerous academic/industry sources). Optimization models attempt to simulate complex grid interactions and fuel competition, but there are serious questions about whether they properly capture renewable energy characteristics and economics.
NREL’s study is transparent and outlines its limitations in Section 2.4. Coincidentally, this outline provides a great overview that hints at why some optimization models are so bad with renewable energy.
For present purposes a few points stand out.
NREL’s study models solar costs exogenously, meaning solar costs are assumed and are not influenced by previous installations. This ignores the economies of scale gained by additional solar from the ITC extension.
Some other optimization models try to capture this type of technological learning through learning curves, but still often underestimate cost declines (with such a methodology, short term misses exacerbate long term misses).
More critically, the major assumption behind optimization models is that perfect competition exists in energy and costs are the primary decision factor. The major issues with this perspective are similar to those regarding LCOE but bear repeating:
- Natural gas and power price volatility are usually ignored in these models, despite having real world impacts. Natural gas price scenarios, like those used in the NREL study, are not the same as price volatility.
- Risk and uncertainty are usually ignored in these models (ex. solar has less uncertainty due to fixed long term contracts).
- Optimization models ignore that the multiple actors in energy have multiple perspectives on future economic trends and resource values. Cost-based optimization does not equal the decisions made by many competing actors.
- There is evidence that different energy sources compete in different markets, making absolute cost comparison (complicated by above ignored factors) somewhat irrelevant.
- Finally, markets function through electricity prices, not cost. Cost does influence electricity prices but the correlation is not direct. Cost optimization models produce results through least cost calculations while markets function through market actors making decisions based on expected prices and risks.
In light of these limitations, and the continuing cost reductions in solar prices, GTM Research’s estimates are likely closer to reality. A major limitation of bottom-up models is that they do not account for market competition with other fuels, but that may be less important for renewable energy due to its fixed cost, low risk nature.
It is also important to note that GTM Research has a solid track record; check out this 2012 projection of 6.6 GW of annual solar installations in 2015 (only slightly lower than the 7.3 GW installed). It is notable that natural gas prices have been around $2-4/MMBtu (lowering wholesale electricity prices) during this 2012-2015 period and solar growth accelerated nonetheless.
It is reasonable to say that, as a result of the ITC extension, solar could reach 10% of U.S. generation by 2025 while also reaching subsidy independence.
Key Remaining Uncertainty is Net Metering
The tax credit renewal will drive continued cost declines and deployment for both utility-scale solar and distributed solar.
However, these two technology classes are different. There is little to hold back utility-scale solar projects, which are especially cheap, benefit from RPS policies, and have limited barriers to market participation.
Distributed solar, on the other hand, is highly sensitive to state policy.
The North Carolina Clean Energy Technology Center just released a report that reviewed state policy actions regarding distributed solar in 2015. It found that recent turmoil around net metering in Hawaii, Nevada, and California are part of much broader trends. Figure 4 from their report highlights some of these changes (if you are at all interested in distributed solar policy, their report is excellent – check it out).
Utilities are pushing back against net metering, either directly or through rate changes. PUCs and utilities have been as surprised as anyone at how quickly solar costs have decline and solar installations increased.
The fundamental problem is that net metering is a temporary way to encourage distributed generation but never intended as a permanent solution. Net metering works fine when distributed solar is around 0.1-0.3% but threatens utility profitability as penetration rates get much higher.
As a result of massive, rapid solar growth, state regulators are unprepared and utilities are concerned about profitability.
Worse, there is no clear successor policy to retail-rate net metering. There are potential options:
- Increased fixed charges
- Value of solar tariff
- Utility-owned rooftop solar
- Minimum bills
- Most dramatically, complete restructuring as envisioned by REV
- Indirectly, through decoupling
Unfortunately, a lot of these are untested and have limited track records, if any. Most state PUCs are not eager to be first movers, particularly if it could negatively impact ratepayers.
For better or worse, 2016 may be the year of net metering policy battles, with uncertain implications for distributed solar. In the next part of this three-part analysis, we will cover the challenges of finding successor policies to net metering in more depth.
- Good coverage of these issues from a global perspective: http://www.irena.org/rethinking/Rethinking_FullReport_web.pdf
- Suggested this in the text, but really worth checking out the report on distributed solar policy: https://nccleantech.ncsu.edu/wp-content/uploads/50sosQ4-FINAL.pdf
- A great case study of what happened in Nevada’s contentious net metering decision: http://www.vox.com/2016/1/20/10793732/nevada-solar-industry-explained