Each year we share our thoughts on the evolution and promise of the solar industry. The last 12 months included the introduction of import tariffs from a president who reiterated his doubts about manmade climate change while championing coal. Even amid these challenges, the solar industry expanded and matured, as it will in 2019.
As solar technology becomes more efficient, costs continue to fall, which is rapidly making solar the most cost-competitive source of energy in the country. Despite a lack off federal policy action on climate change and renewable energy, Americans have created and strengthened networks and opportunities to advance renewable energy. State policies have rapidly shifted further in favor of renewable energy, and corporate demand continues to drive procurement.
The solar industry remains a growing multibillion-dollar market for investors, customers, and entrepreneurs. But it is also a complex one. New investors and developers must be strategic with how they approach the market. Here’s one perspective from the front lines that may help along the way.
America still has our back…
America overwhelmingly supports renewable energy. As of January 2019, 73 percent of Americans support the further development of renewable energy, according to The Pew Research Center, which is one of the largest pluralities in history. The United States has the largest electricity load in the world, and these same Americans are electricity customers who support both policy initiatives for renewable energy and who will create the demand for renewables in the next decade. In 2018, we noted that Americans overwhelmingly support our industry, but we did not anticipate how rapidly this would translate into renewable support at the state level.
In 2018, New Jersey passed a renewable portfolio standard (RPS) with a goal of 50 percent renewables by 2030, and the governor has stated his goal for reaching 100 percent renewable energy by 2050. The District of Columbia passed a 100 percent renewable energy goal by 2032.* In September 2018, the California state legislature passed SB 100, which requires the state to generate 100% percent of electricity from carbon-free sources, with a 60 percent renewable portfolio standard built in.
New Mexico Gov. Michelle Lujan Grisham signed an executive order in January 2019 that commits the state to reduce carbon emissions by at least 45 percent below 2005 levels by 2030. Governors in Maine, New York, Colorado and Illinois have all set 100 percent targets for renewable energy.
These policies have broad and significant impacts on solar regionally, since RPS legislation generally enables both in-state and out-of-state development. Climate change has become one of the most important issues for younger generations, as it should be. These generations are actively changing the prioritization of policy across the political divide. Given the recent Democratic takeovers of six state legislative houses, as well as six governorships, expect additional legislative support for renewables in 2019.
…as do corporate customers
As we anticipated, corporate customers continue to move into direct renewable energy procurement based on corporate sustainability goals and cost savings. In 2018, there were 75 new corporate renewable deals, supporting almost 7 gigawatts of new projects. This is twice as much as 2015, the former record year. Expect this trend to continue in 2019, especially in the PJM Interconnection territory where there is tremendous demand from customers, a very large and dynamic market to support solar, pending RPS change, and a federal Investment Tax Credit (ITC) that drives urgency.
How corporate customers acquire solar energy will be the biggest change over the coming year. The corporate customer has evolved from buying voluntary renewable energy certificates (RECs), to buying compliance RECs, to actually contracting for the output of electricity from a specific renewable energy project. This evolution has largely been driven by the concept of additionality. Corporates want to know that there is a causal relationship between their efforts to procure renewable energy and new builds.
The primary instrument for customers who wanted to procure electricity from offsite projects in the last three to four years was the contract for difference (CFD). A customer purchases energy from a project at a set price at a set node. The CFD is an elegant solution but it can be baffling for customers. Increasingly, these customers will look to utilities and retail electricity suppliers to sleeve electricity for them and to integrate renewable energy purchases into their bills.
NRG and Engie are leading this effort now. Expect new entrants and creative developers to expand this trend in 2019. The suppliers can shape and firm electricity to offer 24/7 electricity to customers. Some corporates, like Google, are doing this on their own.
Costs continue to fall and efficiency continues to rise
Costs are driving this rapid change in the industry. All-in costs for solar projects have fallen around 80 percent since we started our business in 2008. They continue to fall today. A year ago, we projected that the industry would have a low-30-cent module by year-end 2019. At the time, module manufacturers visiting our offices said we were crazy. That was understandable when modules were 50 cents.
Modules are now priced at 30 cents (normalized price for power class) and below because the supply of solar modules remains vast, module production is getting cheaper, and China has slowed its procurement. We expect this trend to continue.
Additionally, and just as importantly, module efficiency is increasing. Increased adoption of PERC, N-type cells, split cell, and bifacial will drive module performance increasingly upward. A standard 350-watt module in 2018 will become a 380-watt module over the next year, increasing energy density, reducing installation costs, and increasing overall output.
To further this trend, balance-of-system costs and architectures are improving. Tracker performance at a sub-array level is increasing (for example, see the TrueCapture technology our friends at Nextracker launched recently), creating a projected 2 percent more energy. DC optimizers will create 3-5 percent more energy longer-term, while mono-PERC and bifacial modules may add up to 5 percent more efficiency. These are small changes by themselves, but create significant uplift together.
We also see the continued adoption of 1,500-volt architectures, which enable lower installed costs and higher efficiency at the system level. Additionally, string inverters, previously most common for small commercial applications, will become the predominant solution for small utility projects. String inverters can lower costs, but they also enable a system to partially operate without a “truck roll” and an O&M visit. Bringing down long-term O&M costs is one of the single best ways to create value across an operational portfolio.
Expect large solar project portfolios owners like Global Infrastructure Partners, Helios and Brookfield to focus on these costs to increase returns and financial yields over time. At some point, large portfolio owners will retrofit pre-existing systems to include string inverters.
All of this means that we’ll build vastly less expensive yet more efficient solar. Utility-scale projects are being built at 90-95 cents per watt right now. That was unthinkable two years ago. We’ll build at or below 85 cents per watt in the near future. This pricing has led to sub-3 cent PPA prices from solar projects. There is no other technology that can compete. Lazard, as they have for years, does a great job of illustrating this in their annual Levelized Cost of Energy (LCOE) Report.
Energy storage is the area in which our industry most needs to adapt, as we also noted last year. The question is not if storage will become an integral part of all utility solar projects, but when. Most discussions around storage have been around lithium-ion batteries, which are the same batteries in your phone. If you have a Tesla, you’re just driving around with 7,000-10,000 phone batteries. This technology holds tremendous promise, but as our friend Colin Murchie explained recently, we’ll likely need to integrate pumped water storage and other technologies for true load-shifting.
Use of hydro in France, where 71 percent of the electricity is produced by nuclear power plants, is a good template. Companies like Google and asset owners like Brookfield and Avangrid are already integrating hydro to firm solar and wind. It’s a tremendous differentiator, and will continue to be.
The asset class grows
Significant customer demand and falling costs continue to drive the expansion of the solar asset class. In 2018, there were around 109,000 megawatts of solar installed worldwide, with 14,000 megawatts of that capacity installed in the United States. Looking ahead, we still see a tremendous pipeline and significant investor demand. Globally, solar will become one of the dominant sources of new electricity generation, and solar and wind are expected to provide 50 percent of all electricity in the world by 2050: a roughly $10 trillion market.
Solar assets within the United States are especially attractive for investors because they are dollar-denominated, real assets, non-correlated to the stock market, and are also relatively inflation-insulated. Europe and Asia also have specific requirements for banks to invest in renewable energy, as it reduces their capital set-aside requirements. Many sovereign wealth funds and multilateral banks have a mandate to invest in renewables. As such, there continues to be a number of new investors in the market from Japan, Europe, the Middle East and China.
All of these fundamental factors have created a highly competitive and sometimes volatile market. Over the last decade we have repeatedly seen that while the market itself is expanding and solar is becoming a growing share of our electricity, strategic business success is volatile. Generally, expanding markets are complex.
In complexity is opportunity for the investor
New investor entrants into the U.S. market mean more competition, which drives down the cost of capital for projects. A lower cost of capital generally means that investors are willing to accept lower returns on their investments in solar assets because the investments are viewed as less risky than the alternatives. Because capital costs are relatively high for solar, and ongoing expenses extremely low, a lower cost of capital dramatically drives down the LCOE for solar and PPA prices for the customer.
This results in growth for the industry but raises some challenges for certain investors. To compete, these investors must either accept lower returns, take on more operational or structural project risk to maintain their returns, or move earlier in the development cycle to secure pipeline and ensure their targeted returns (which is also a type of risk).
New and more competitive investors
This dynamic poses a tremendous opportunity for investors who have a lower cost of capital than the private equity that is currently supporting much of the solar development activity in the United States. These private equity or hedge fund investors find it increasingly difficult to compete in owning solar project assets and thus are either adapting or looking for new or less mature assets. This trend has occurred in wind a few times.
Many of these private equity investors are being displaced by insurance companies, sovereign wealth funds, and pension funds that buy new or operational assets, or buy down the equity from developers in operational assets or portfolios, in what some refer to as a recycling of capital. In a recent example, AES and its affiliate S-Power transacted with Ullico to sell down equity in their 1,300-megawatt portfolio of renewable assets. John Hancock has been actively buying down equity in portfolios, and a number of developers are actively selling down their equity.
We expect our Helios infrastructure platform to remain competitive and to be a helpful partner for developers in this environment. Also expect NextEra, Avangrid and EDF to be active participants in this market. Newcomers like Ørsted and Equinor and large Japanese players will also actively participate if they can both adapt to the more complex financial market of the United States and partner with regional firms that understand the investment landscape.
Regional or localized partners with development expertise are critical, as they enable these investors to better evaluate projects and risks, navigate a very close-knit community, and aggregate large portfolios.
Investors and independent power producers focus on development to boost returns
This shift in market participation is driving a number of investors and funds that traditionally purchased solar assets when they were complete or beginning construction, to move earlier in the development cycles. The aim is to secure a pipeline earlier so that investors don’t have to compete for more mature assets. Another way to look at this is that these investors are trying to preserve yield by investing earlier.
While this strategy makes sense in some regards, investors pursuing this strategy need to take care to evaluate the pipelines they buy. Not all projects are created equal.
This evolving investor landscape has similarly impacted independent power producers. Many IPPs that traditionally held on to the solar assets they developed are adapting their model from a develop-and-hold model into a develop-and-sell model. This is being driven by the opportunity to sell their assets at very competitive prices, and also because most developers/IPPs have a fairly high weighted average cost of capital (WACC) that accounts for the risk imbedded in their development business. This high WACC cannot compete with current institutional capital.
This process is accelerated by the fact that many of these same IPPs are also struggling to support early-stage pipeline that is taking longer than anticipated to harvest and are being forced to refinance their capital lines with investors.
Creating differentiated financial products
Other investors seek to gain an advantage through differentiated financial products in the industry. In 2019, a number of investors, including Helios, will finance partially merchant solar projects. Solar projects can either have a merchant tail (and most utility projects do) or a merchant cap, where only a portion of the overall output of the energy is contracted. To enable these projects, certain banks are beginning to offer debt products around primarily or fully merchant solar projects. Already, some banks offer debt products that amortize beyond the PPA term.
We also expect that a number of IPPs and funds will begin to safe-harbor solar projects for the 30 percent ITC by purchasing equipment equal to at least 5 percent of the eventual cost of the project. This will enable them to utilize the 30 percent ITC for projects that are operational in 2020 or 2021. We expect NextEra, Avangrid and other large developers to invest heavily in this strategy as they have in the past. While it may not seem like much, the difference between a 30 percent ITC and a 26 percent ITC will have a marked impact on investor returns and the competitiveness of investors.
Development or contracted assets? Not all assets are created equal
In 2018, we warned that assets were overvalued, value conflated and non-differentiated. Stocks, bonds and real estate were not trading on market fundamentals. That holds true today, which is why volatility in the stock market has increased rapidly. Investors are looking to reallocate their capital but are challenged to understand where to put their money.
As the broader capital markets deleverage, and investors reallocate, they are looking to park their money into stable assets to protect returns. This has been a tailwind for the solar market for the last three years as institutional capital poured into solar assets based on their stability.
In 2019, the costs of capital for solid solar projects with long-term PPAs and contracted revenues will continue to fall. These are tremendous infrastructure assets. The cost of capital for projects now ranges from 6.5 to 7.75 percent unlevered after-tax, although 100-300 basis points of that return depends on assumptions and structuring.
However, expect the asset differentiation occurring in the broader market to impact what has been a relatively frothy market for solar development assets in the past. Developers with portfolios of projects without a PPA or with no offtake in sight may struggle. This will be a significant issue for the industry over the coming year.
Don’t pack peanuts
There is a huge difference between a solar project that has contracted revenue and one that does not. It’s just one more reason that the customer (and customer demand) will drive our industry.
The United States currently has around 150 gigawatts (which is insane) of solar in interconnection queues. Many of these projects are have some combination of site control and early-stage permits, but don’t have a customer offtake, and sometimes they don’t even have a strategy for securing a customer. We often refer to these portfolios as a cardboard box with packing peanuts.
We urge developers that are considering embarking on this strategy to slow down. It is a capital-intensive strategy in a highly competitive market. We urge investors to carefully value interconnection queues as a basis for pipeline availability. Many of these projects will fail or be warehoused for the future.
One additional hard lesson for the industry (ourselves included) is that many of the new markets are more complex and slower to mature than anticipated. New York, Illinois, Virginia and much of PJM remain attractive, but project development timelines are being stretched, which means developers must hold these projects either on balance sheets or in relatively expensive development facilities for longer.
Pending RPS legislation may make these markets more attractive in the next three years, but the initial timing of many development funds and the high cost of capital in these funds makes it challenging to nourish and develop multi-state portfolios with long lead times. These challenges have put significant pressure on both the developers and the financial partners that provide the capital for many developers to invest in early-stage assets.
As the broader market is deleveraging in 2019, many of the development funds that supported solar development assets from 2015 to 2018 will mature and look to protect returns to investors. These funds will look to capitalize on their investments and will force developers to either partially or fully monetize their assets, and potentially monetize their platforms. As a result, many developers have sold off or will sell off their pre-existing pipelines and development assets to source capital and repay these facilities.
Focus on core expertise
We recommend that developers pull back from a buckshot approach to markets and focus on a smaller number of states/geographies where they can create differentiated value and a competitive edge. There is a vast chasm between being a successful regional developer and being a successful national developer.
That is a journey in which developers can quickly lose capital, focus and success if they are not careful. Those solar developers that have been disciplined in their approach and focused on the fundamentals in their markets (locational marginal pricing, congestion and policy) have succeeded and will continue to do so.
Opportunity amid change
The long-term fundamentals are there for our industry to succeed, and we expect solar to continue to grow into the single largest source of electricity in the United States. There are two fundamental calibrations that are occurring in the industry right now that are important to recognize.
First, there are a large number of investors looking to enter the market or gain market share. These investors are out-competing traditional investors, who are in turn looking to secure yield by creating differentiated value through more creative financial structuring or by buying earlier stage assets.
Second, many developers have cast a wide net in the market and will be challenged to financially support these vast pipelines. The developers will either sell or refinance their portfolios, or in some cases will sell their development platform. Others will refocus their attention on a more regionalized geographic approach.
Of course, these trends naturally merge in some ways, and the investors and developers that can navigate the opportunity will create enormous value. We urge investors to dig deeply with partners to understand imbedded project risks. We urge developers to stay focused on core markets and to work to understand the fundamentals of the increasingly larger and more complex electricity market that will drive real-time locational pricing and customer demand for the coming decades.
The Sol Systems team is excited to play our part in helping this industry expand and succeed to confront the generational challenges of climate change and energy infrastructure transformation. We wouldn’t want to be doing anything else, with anyone else. Good luck to all of you who commit your lives to this industry. It is not easy; it is important.
Yuri Horwitz is the co-founder and CEO of Sol Systems. This is an edited version of his 2019 CEO outlook.
*A previous version of this story noted that DC has a 50 percent RPS. The District appoved a 100 percent RPS in December 2018.