Utility-scale solar system costs have steadily declined across the U.S. in recent years, falling between 14.9% and 17.4% in 2016 alone and pushing power purchase agreements (PPAs) into a range competitive with fossil fuel generation. This downward pricing trend will continue as efficiencies increase, making the price of solar more and more competitive in U.S. power markets.
Although the impressive pricing decline of recent years is projected to slow in 2017, solar at its core is a technology, and technologies generally decrease in price over time – especially considering panel technology and costs. That means utility-scale solar’s role as a competitive and attractive energy source will keep growing as the U.S. focuses on expanded domestic energy production.
This downward pricing trend is opening up new development opportunities for the solar industry, and while challenges still exist to future projects, solar developers should continue to benefit from lower costs and industry innovations.
LCOE reflects industry improvements
As project efficiencies and output expand, the cost to build and operate projects declines, resulting in a lower levelized cost of electricity (LCOE) and more competitive pricing. LCOE is a key indicator of utility-scale solar project costs and accurately represents solar’s advantages over fossil fuel generation, as it reflects the value of long-term, fixed-rate contracts compared with commodity price volatility. For instance, 8minutenergy’s Springbok solar farms in California have LCOEs between $52/MWh and $58/MWh of electricity, which are competitive with or below traditional fossil fuel generation costs.
Viewed on the whole, utility-scale solar’s price decline looks steady over time, but it has been marked by large drop-offs, followed by leveling-off periods, followed by larger step-changes. For example, 2016 was a large step-change year. The investment tax credit (ITC) extension paired with overall panel and module pricing declines, as well as lower balance-of-system costs, to make new investment and capacity increases possible.
Overall, the downward trend has not been due to one silver bullet steadily bringing down pricing; rather, all aspects of the industry have been working to drive costs down and lock in lower project costs. For instance, as operation and maintenance (O&M) has become more efficient and technological improvements paired with lessons learned have increased capacity factors, the downward trend of utility-scale solar pricing proves to be more stable.
“Thousands of steps in the right direction”
O&M efficiency is often overlooked as an aspect of utility-scale solar’s downward price trend. As solar has increased penetration in different regions across the country, O&M providers have been able to increase their utilization rates and reduce costs alongside project proliferation. So, instead of having two people working on just a couple of plants, those same two people can cover four or five projects. Because O&M costs are reduced through more efficient scheduling, less downtime for on-the-clock O&M employees, and less travel time to reach more projects, developers can offer a lower PPA price to the customer.
Technological advances have also boosted O&M efficiency. For instance, remote monitoring now reduces on-site time requirements, and improved project engineering designs lead to more resilient projects with fewer maintenance needs.
Project megawatt-hour prices have also been driven down as solar capacity factors increase with the same fixed capital costs. Improved panel efficiency is certainly among the largest factors here, but overall cost reductions come from many small lessons learned across thousands of hours of experience building projects over the years, including the following:
•Improved inverter efficiency;
•Larger inverters leading to lower overall inverter costs per watt;
• Lower-cost but higher-quality trackers creating less downtime from mechanical breakdowns and higher capacity factors;
•Lower labor costs per megawatt through more effective use of labor; and
•Better use of data to improve foundation piles for structures.
With the industry taking thousands of small steps in the same direction, capacity factors have grown significantly over time, rising from 21% in 2010 to nearly 27% in 2014.
You might also remember how changing voltage for collection led to more efficient inverters, which improved inverter efficiency and helped projects lose less output as they went through the DC-to-AC conversion. Similarly, improving project designs to optimize spacing between panel rows, as well as using slightly different single-access tracking, has increased the amount of energy produced from the same space compared with just five years ago.
These industry trends driving prices down while increasing generation efficiency are especially promising in non-traditional markets, which have historically seen low project penetration and where utilities can now procure solar cheaper than other new generation. Just like with increased O&M efficiency and capacity factors, as projects start going into a new market, costs decline as solar expands, creating learning lessons and economies of scale that further drive down the LCOE.
Although each state’s unique environment creates different pricing scenarios, solar’s technology and hardware trends will generally remain consistent regardless of location, providing a competitive and advantageous option for utilities. In this setting, factors that account for solar’s viability include the cost of land, the cost of interconnection and the cost of labor – all of which are generally positive in non-traditional states.
For instance, across Texas and southeast states like Georgia and Alabama, land and labor are generally cheaper than in more-developed states like California or the Northeast U.S., which can make projects cheaper up front during construction. Solar demand in these traditionally underdeveloped states is often driven by utilities, making interconnection cheaper and faster, which can allow for lower cost on the back end during operation.
While promising, non-traditional solar markets also can be challenging, in that solar as an energy source is relatively unknown and may require additional partnership outreach to successfully develop a project. Working closely with utilities, landowners, local governments and environmental groups from the start can streamline development timelines, further reducing project costs and maximizing community benefits.
Public Utility Regulatory Policies Act (PURPA) contracts are also expanding solar development in non-traditional markets, but they are subject to more volatility than voluntary utility procurement based on cost. PURPA demand has been credited with a sizable percentage of the current utility-scale solar pipeline outside of state mandates, but demand is subject to state regulatory change. We’ve recently seen this impact in Idaho or Montana, where projects were no longer financeable after regulatory changes to contract length or avoided-cost rates.
Therefore, although the PURPA opportunity hasn’t passed, it’s a risk for some business models and requires strong relationships with the key stakeholders making regulatory decisions. This tension is what makes the market both interesting and challenging, and developers that decided to go long in PURPA markets should be realistic about the fact that rules can change suddenly and quickly to turn a market from hot to cold.
ITC step-down, rising interest rates
Even with these overall solar pricing trends, it’s important for utility-scale solar developers to consider the hurdles still facing our industry. The December 2015 ITC extension resolved many outstanding financing concerns, but the ITC value will begin stepping down on an annual basis after 2019.
Developers will have to continue seeking efficiency gains as the ITC step-down begins in order to stay competitive on price with other resources. Similar to the wind industry, solar projects should be able to extend the 2019 ITC rate by making capital expenditures on projects by December 2019. The Internal Revenue Service has not yet issued guidance on the 2019 ITC, but analysts expect projects could still qualify for 2019 rates even if they start construction in 2020-2021 by meeting certain requirements.
The pricing trend information we’re seeing shows that forecasted declines in technology, component and soft costs all seem to be outstripping the annual ITC value reductions. Even though the ITC value will change, cost declines through continued technology and efficiency improvements should continue to more than offset scheduled reductions.
In addition to continued cost declines, corporate demand for renewables should keep utility-scale solar competitive through the ITC’s decline. A 2016 Advanced Energy Economy report found 71 of Fortune 100 companies have set renewable energy targets, and this demand often comes from large manufacturing or shipping facilities located in rural areas – which feeds back into rising utility demand for solar in non-traditional markets.
Indeed, one of the largest factors that might slow utility-scale solar’s price decline could be completely outside industry control: interest rates. We’ve been operating in a near-zero interest rate marketplace for the majority of solar’s large-scale growth, starting in 2008 through today, and many industry analysts have feared this could change moving forward via Federal Reserve interest rate increases.
However, the Fed’s March interest rate hike ironically drove 10-year Treasury rates slightly lower, from 2.6% down to between 2.35% and 2.5%. The Fed has hinted at only one or two more potential rate increases in 2017, so we’ll likely only see minor increases in expected project returns, which is reasonable and positive for the solar industry.
As developers consider potential long-term risks, they should remember to take guaranteed longer-term contracts, as opposed to considering merchant PPAs, because they are better for raising debt. Longer-term debt increases equity returns, allowing companies to increase debt and offer lower PPAs while still achieving the same internal required equity returns.
Although energy prices have increased in value between 2% and 3% over the past 10 years, recent natural gas price declines have created financing risks among which customers push for 10- to 15-year PPAs. Utilities and end users prefer these shorter-term contracts to reduce supply-side risk, but they could be discounted toward the end of their contract terms, quickly deteriorating overall project economics if energy prices change before PPA expiration.
An undeniable outlook
In this era of rising capacities and declining costs, solar has unmatched benefits as an energy source. Not only does it provide valuable on-peak power, but it also requires a considerably smaller land footprint than wind projects, making finding suitable siting locations easier with lower property acquisition costs and minimal environmental impacts.
We’ve come a long way in solar adoption, and at less than 2% of national electricity generation, we can continue to gain market share. This outlook will only improve as solar-plus-storage hybrid projects start to spread, allowing sales to shift from peak to later parts of the day and revenue from ancillary services, with even greater capacity factor improvements. It’s exciting to contemplate what the future of America’s solar industry holds, but as a whole, the future of utility-scale solar project pricing is undeniably bright.
Kurtz Stowers is vice president of origination and David Cieminis is director of origination at independent solar power developer 8minutenergy.