solar industry Archives

Every year, we put pen to paper to share our thoughts on the direction our industry is headed. In previous years we focused on opportunities: reduced module costs resulting from underlying shifts in manufacturing and commodity prices, the long-term promise of solar energy indicated by strong demand from corporate customers, and the need for the federal government to focus on pragmatic approaches to scaling American transmission infrastructure. This year we focus on current risks we think are critical for our industry to understand.

Background

There is overwhelming and increasing demand for renewable energy in the United States, and for solar energy in particular. A majority of Americans, independent of political affiliation, support renewable energy. Leading this demand are large corporations that are transitioning to renewable energy on behalf of their employees, their customers, and their shareholders. Solar is now the least expensive form of electricity in the world, and it is the single largest source of new electrical capacity installed in the United States.[1]

Today, the solar industry won a huge victory when the Biden administration announced a two-year pause on new tariffs against solar modules imported from Southeast Asia. Details about the policy are still developing, but the move is viewed as a response to concerns about the Department of Commerce’s ongoing anti‑dumping and countervailing duty (AD/CVD) investigation into the same products. The change is prophylactic—regardless of the outcome of the AD/CVD investigation, any resulting tariffs will not impact modules imported during the next 24 months. It is also narrow, leaving Section 201 and other existing tariffs and trade restrictions unaffected. In the same announcement, the administration also said it will invoke the Defense Production Act to support the long-term development of domestic solar manufacturing capacity.

The administration’s announcement signals exactly the long-term policy strategy that many of us have been advocating for years, and it’s a massive win for the industry. But important challenges remain: (1) supply-chain disruptions caused by COVID‑19 and forced-labor concerns; (2) a suspension of new interconnection in PJM, one of the country’s most important markets; and (3) an inflationary environment that increases the cost of capital for renewable energy infrastructure.

1. Supply-Chain Issues

Across almost every sector, COVID-19 has dramatically reduced available labor and industrial manufacturing capacity since 2020, especially in Southeast Asia and China. Production of solar modules, trackers, and other critical equipment was no exception.

The price of polysilicon, the raw material used to produce solar modules, has tripled in the last 24 months. Shipping costs have increased by $20,000 per container, or around 600 percent, during the same period. Shortages of semiconductor chips, which are critical for a wide variety of modern goods including for electrical inverters, have increased delivery lead times by six months. (Anyone looking to buy or sell a car has noticed this shortage.) And of course, the rising prices of steel, aluminum, and copper have hampered the entire global economy, increasing balance-of-system costs by 6 cents/watt, or 30 percent.

Another important, and complicating factor, is the Uyghur Forced Labor Prevention Act (UFLPA) which was signed into law on December 23, 2021. The UFLPA was designed to prevent the import of products made with forced labor in China by establishing a rebuttable presumption that any goods mined, produced, or manufactured, even in part, in the Xinjiang Region of China are prohibited from entering the United States.

The UFLPA could apply to many of the materials used to manufacture solar modules, including glass, aluminum frames, and other components. Because implementation guidance remains outstanding, uncertainty remains due to traceability risk exists, further driving up costs and limiting availability. This uncertainty, combined with the risk of new tariffs and the effects of COVID-related shutdowns, has frozen the supply of Chinese and Southeast Asian solar modules bound for the US market.

2. Interconnection in PJM

In addition to significant tariff risks and price increases, the solar industry must also grapple with interconnection delays. PJM is the largest Regional Transmission Organization (“RTO”) in the U.S., spanning from New Jersey to parts of Illinois and down through North Carolina. PJM also includes the largest concentration of data centers in the world. This makes PJM the single most important electricity market for corporate customers globally, which in turn drive demand for over 25 percent of the utility-scale solar projects in the country.

PJM is in charge of grid interconnection for the many electric generators located throughout its territory. Over the last five years, the number of applications for interconnection in PJM has grown exponentially, primarily driven by applications from new solar projects. During that time, PJM has failed to adopt procedures common in other regions capable of accommodating the increased demand. As a result, the RTO’s interconnection process, originally designed to serve a relatively small number of new and very large coal and natural gas plants per year, has collapsed. In response, PJM has been forced to declare a moratorium on new interconnection applications for nearly two years while it transitions processes. This will affect over 1,000 projects, 95 percent of them solar, for years.

The impacts of these delays are significant. Every year, solar developers invest millions of dollars of at-risk capital with landowners, utilities, regulators, and other stakeholders with the expectation of eventually bringing their projects online. These developers must now wait until at least 2025 to find out whether their projects will be allowed to interconnect, and at what cost. Corporate customers working with these developers are similarly struggling to understand whether the projects they have contracted power from will be built, and whether these corporations will have access to the clean energy they had planned for.

Developers should ensure that they have appropriate liquidity to manage portfolios that may now take longer to develop. To adjust, some developers may have to sell portions of their portfolios or partner with those that have access to longer-dated capital.

The impact of these delays on customers will also be significant. Data centers consume between three and four percent of the electricity generated in the United States, and over 90 percent of all internet traffic flows through data centers located in PJM. Corporate customers targeting 2025 to meet their renewable electricity goals, and those with 24/7 goals in particular, will have to collaborate with developers as to how to mitigate these delays.

3. Inflation

For over a decade, the US has benefited from a combination of historically low interest rates and historic economic growth. In the last 24 months, governments have made significant capital injections into the global economy to incentivize growth and protect against a downturn during the COVID-19 pandemic. This has enabled corporations and investors to secure substantial amounts of low-cost debt to scale their businesses and investments, in turn enabling long-term growth in equity markets. There is no question that this environment has helped to power the development and construction of renewable energy assets, which have significant upfront costs but long-duration financial benefits.

Unfortunately, that same environment, together with pandemic-led disruptions and Russia’s invasion of Ukraine, has triggered inflation not seen in the United States in 30 years. Gasoline prices are now floating above $5 per gallon, and general staples have experienced price increases of up to 10 percent. In response, the Federal Reserve is doing what it’s supposed to—raising interest rates to tamp down inflation. The Fed raised rates by 50 basis points (bps) (0.5 percent) in May, and it is poised to raise them again two or three times in the next 18 months.

As interest rates rise, so too will the blended cost of capital for infrastructure projects. We estimate that every 100-bps increase in interest rates equates to around a 10 cent/watt increase in capital costs, or a 125–150 bp reduction in returns. This estimate does not account for the increase we will very likely see in investors’ expected returns on equity. This dynamic will put additional pressure on leveraged transactions as well as on long-dated infrastructure generally.

Projects with thin cash flows, significant leverage, or floating interest rates will be challenged, because their debt-to-service ratios will shrink. Sponsor equity, where return expectations may increase as well, will have to fill the gap. Solar developers and independent power producers (“IPPs”) whose businesses are supported by corporate debt facilities will be challenged.

But while inflation certainly poses challenges for our industry, it also presents opportunities.

Operational solar projects with long-term contracts are relatively inflation-insulated, non-correlated assets with limited ongoing operation and maintenance requirements. These projects are generally positioned to weather an economic downturn better than natural gas or wind generation facilities because of their low operational expenses and zero fuel costs. Most operational solar projects will actually increase in value because their “tail value” will increase in tandem with long-term natural gas and electricity price curves.

Operational assets that are merchant (like a number of wind and hydroelectric projects are) will benefit tremendously, because they can sell into high-priced markets immediately. To take one example, pricing in PJM now regularly averages $60/MWh—that’s not peak, that’s currently average. Pricing that high is unheard of in recent history, but it will become increasingly common. If an IPP purchased a solar energy asset expecting $30/MWh, its investors are doing well.

Developers may also benefit from an inflationary environment in certain respects. An increase in power prices will accelerate the ongoing increase in PPA rates. Developers on the right side of interconnection reform in PJM or with near-term assets in their portfolio will benefit from scarcity value.

Finally, inflation might benefit corporate, municipal, and utility customers as well. An operating solar project with a PPA inked in 2020 at $35/MWh provides a significant financial hedge for these customers and supports the contention that renewable assets are cost-competitive (which they are and have been for a while). Strategic procurement leaders can quickly quantify these savings for their organizations as they also prepare them to accept higher PPA prices for new projects—which they’ll have to.

Conclusion

It would be hard to overstate these changes. Most in our industry have not experienced a prolonged macro-economic downturn, and even fewer have experienced significant inflation. Over 99 percent of the solar assets built in the United States were built in the last decade or so – and when we started Sol in 2008, less than a percent of the current national capacity was in the ground. We have built billions of dollars of infrastructure and replaced some of the most polluting coal plants in our country along the way. Lots to be proud of. But our industry is changing, and we must be ready to adapt.

Supply-chain issues have raised module prices by 10–15 cents per watt and have raised balance-of-system costs by an additional 5 cents per watt. Put another way, costs have increased by around 30 to 40 percent, while Commerce’s recent anti-circumvention investigation has reduced the availability of modules by 90 percent.

In addition, assuming an increase in interest rates by an additional 100 bps, the rising cost of debt alone will increase project costs by the equivalent of 8-10 cents per watt. In sum, developers are facing an overall capex cost increase of around 25–30 cents per watt, or around 30-40%. Smaller projects will have higher capex increases, but are their economics are less sensitive to these costs generally.

We estimate that each 5 cents/watt increase in capex equates to around $2/MWh in increased PPA rates given an unlevered after-tax full-term IRR of 6 percent. The 25–30 cents/watt increase in costs noted above translates to a $12–15/MWh increase in PPA prices, or an increase of 25 percent—which is exactly what is being reported in PJM, MISO, and other markets.

We urge customers and developers to work collaboratively to address these issues—most of which are not only beyond the control of developers, but beyond the control of the industry. It is a storm we all can – and must – navigate together.

[1] While solar accounted for 3% of U.S. electricity generation in 2020, the EIA (which has historically underestimated growth) projects this figure will be 20% by 2050. The Department of Energy, however, estimates that solar could account for upwards of 50% of all electricity by 2050.

Building off of our previous summary, of President Andrés Manuel López Obrador's (AMLO) recent Mexican energy market reforms.

As a reminder, the reforms were proposed as AMLO’s most recent attempt to reassert control over the Mexican energy landscape – a move highly criticized across the world. As a result of this criticism and opposition to the proposed reform, AMLO’s proposal is on hold for now awaiting potential governmental action and public debate.

This week, public debate began in Mexico’s Chamber of Deputies (analogous to the U.S. House of Representatives), centered on the proposed changes to the Mexican constitution that could significantly reduce competition within the Mexican energy sector. The proposed reforms would put $22 billion in clean energy investments at risk.  AMLO’s National Regeneration Movement (MORENA) is pushing the debate in what we can only gather is a hope to attempt passage of the package before the end of the current legislative session in April 2022. To pass, the package will require a two-thirds majority vote in the Chamber of Deputies, Senate, and at least 17 local congresses. Adding to the political volatility of the situation, AMLO announced that he also plans to hold a recall vote on his term in March 2022 to solidify his power and bolster his mandate to take action on the proposed reforms. Officials in MORENA believe that winning that referendum will lend legitimacy to efforts aimed at securing constitutional change.   

What seems clear is that the ALMO’s primary focus remains on fossil fuel generation as the backbone of Mexican economic development at the expense of renewable energy. This reality could set in motion one of the largest international hurdles faced by renewable energy developers and large energy buyers in 2022. 

Reform Consequences & Pushback    

The delay was driven in-part by concerns raised by many stakeholders that ALMO’s proposed reforms are likely to violate international agreements, harm domestic economic development, reduce investor confidence, and could lead to dirtier and more expensive electricity. A recent NREL draft study predicted that the reforms would increase carbon emissions between 26 and 65 percent, raise electricity generation costs between 31.2 percent to 52.5 percent, and also increase the probability of power outages by 8 percent to 35 percent. The results of the NREL study in all three scenarios offer reason for caution.

In November, together with Cecilia Patrón, the Secretary General of the Partido Acción Nacional (PAN), the opposition party, stood firm against the reforms, stating that  PAN is “opposed to the electricity reforms as they are currently drafted and Mexican families know that, because it would cause a price spike for electricity bills by increasing state control.”  In the private sector, Pablo Zárate of FTI Consulting  said that, “the reform – which AMLO needs opposition lawmakers to approve – also puts supply chains at risk, as companies may not be able to decarbonize their operations in Mexico to meet international commitments.” In response to a question on the politics at play, Zárate said “There are [political] actors seeking to negotiate, changing a comma or something in the margins, but this is distracting from the main considerations and implications of the reform.”  

In the U.S., lawmakers in both parties have urged the Biden Administration to oppose the proposed reforms. Earlier this month, Senator Robert Menendez, Chair of the Senate Foreign Relations Committee, and three other Democratic Senators authored a letter urging Secretary of State Blinken and Secretary of Energy Granholm to oppose the reforms. The Senators not only objected to the climate implications, but argued portions of the proposal would contradict portions of the United States-Mexico-Canada Agreement (USMCA) designed to reduce national security concerns around critical mineral scarcity as well as threaten “$44 billion in private investment.” In the fall, a bipartisan group of Texas Senators and Representatives sent a letter decrying  “recent actions taken by the Mexican administration to favor state owned enterprises (SOEs) and push out American investment,” highlighting that the proposed reforms for violating the USMCA and called on the White House and U.S. Ambassador to Mexico Ken Salazar to take action.    

Outside of the United States, the Canadian Ambassador to Mexico, Graeme C. Clark  wrote a letter  to the head of Mexico’s Ministry of Energy (SENER) stating that the policy “puts at risk the operation and continuity of Canadian companies’ renewable energy projects in Mexico.”

Corporate Impact

These proposed energy reforms have unnerved foreign investors and large corporates operating in Mexico. Sarah Birke, The Economist’s Bureau Chief for Mexico, believes that the reforms will not only lead to “dirtier and more expensive power,” but that it would “damage investor confidence beyond the energy sector.” This is in part due to the damage this would do to many multinational businesses’ ESG goals. One such business is  General Motors, whose Mexico Chief  announced  the  American automaker would halt all investments in Mexico unless there were laws that promote renewable energy, threatening to claw back their announced investments of over $1 billion in electric vehicle production in Mexico beginning in 2023.  At the same time,  Fitch Ratings recently announced, “the energy initiative proposed by Mexico’s President López Obrador to amend the constitution would result in negative rating actions to private power projects were it to become law.”  It is clear the proposed energy reforms have unnerved foreign investors and large corporates operating in Mexico, and could alter business’ ability to procure clean and competitively priced electricity.

As detailed more thoroughly in Sol’s previous article on the Mexican energy market, there is tremendous opportunity for growth in the Mexican renewable energy . While at this point, new utility-scale solar and wind projects are at a standstill, the distributed generation market continues to grow given robust customer demand and a strong domestic demand for solar.  

Next Steps 

As public debate on the reforms begins, key issues to follow include:

The market structure created by the 2013 Energy Reform

The State’s role in the power sector

The goals of the 2013 reform and the results

The constitutionality of the 2021 reform

The environment and energy transition.

With the debate in full swing, U.S. Secretary of Energy, Jennifer Granholm is in Mexico meeting with her counterpart, Mexican Energy Minister Rocio Nahle on potential solutions. AMLO has publicly stated that he will meet with Secretary Granholm and, “will provide information on why we need the proposed electric power reform.” Secretary Granholm issued a statement ahead of the talks saying she sees a “great opportunity” to work “towards decarbonization as a North American block.”.

As of today, it appears robust stakeholder pushback has succeeded in preventing the quick passage of ALMO’s energy reforms. However, we will be closely monitoring developments to ensure any reforms promote, rather than hinder, decarbonization and the buildout of renewable energy.  

This is an excerpt from the Q2 2020 edition of The SOL SOURCE, a quarterly electronic newsletter analyzing the latest trends in renewable energy development and investment based on our unique position in the solar industry. To receive future editions of the journal, please subscribe. The article was originally written for and published by Greentech Media.

The renewable energy asset class in the U.S., particularly solar and wind projects, is something of a safe haven for investors looking for non-correlated, stable, dollar-denominated long-term cash flows. But the solar market, like every sector of our economy, is changing amid the COVID-19 pandemic.

It is tempting to collapse these changes into a simple takeaway, like “tax equity is fine” or “rates haven’t changed." But the $20+ billion financial market supporting the solar industry is anything but simple, and COVID-19 will have different impacts on different segments of the industry and different players within those segments.

The investment community generally works like a waterfall where institutional investors drive investment into companies, assets or funds, which in turn often invest themselves.

Institutional investors are generally defined as pension funds, insurance companies, sovereign wealth funds, mutual funds, commercial banks and endowments investing on behalf of themselves or their members. These investors rank investment opportunities based on the underlying stability of returns, historic volatility, counterparty risk, liquidity and other factors. The different asset classes are characterized along a spectrum, running from "core" to "opportunistic."

A core investment in solar energy might be a fund or portfolio strategy focused on purchasing debt instruments on a 20-year contracted asset with an investment-grade counterparty. An example is the $2 billion in green bonds that Bank of America offered in 2019. An opportunistic investment might be a private equity firm investing in a portfolio of development assets in PJM expected to yield double-digit-percentage returns.

Both types of investments are impacted by COVID-19 — but not equally.

During times of crisis, institutional investors narrow their investment aperture, and there is a reallocation of investment from the higher-risk/higher-yield investments in opportunistic funds to lower-risk core funds. These investors immediately slow down the origination and underwriting machine until they have a better understanding of what is going on. In the last three months, a sizable number of opportunistic investments have become impaired amid the downturn. They might also set cash aside to support the investment or try to sell their interests if there is a liquid market.

Finally, the commercial paper market (debt backing corporations) is over $1 trillion in value, and this market has a massive impact on almost all institutional balance sheets because these investors hold so much of these investments. In one example, while Disney+ may be doing well, Disney itself was recently downgraded due to COVID-19’s impacts on its theme parks. Once a corporate credit rating is downgraded, an institutional investor that owns commercial paper must set aside additional capital to support the investment. This reduces liquidity.

Institutions can also sell the security, but when multiple corporates are downgraded, everyone begins to sell at the same time, and pricing declines precipitously. This is one of the most important credit markets for the economy, which is why the Federal Reserve of New York recently launched the Commercial Paper Funding Facility to support this market.

This broad reallocation of risk and investment impacts the entire solar industry, but it especially impacts those funds that support the more entrepreneurial efforts that have historically helped expand the market.

Impact on sponsor and development funds in solar

Funds that are backed by institutional capital and are structured to buy and hold assets over the long term generally target more conservative returns with long-term contracted cash flows. Assuming these funds have committed capital, they will weather the current storm. Similar funds that have not been closed and committed may take longer to close given restrictions on travel: Try closing a $500 million fund over Zoom. But this asset class was compelling prior to COVID-19, and it will continue to be in the future.

Investments in private equity funds that are seeking higher returns in exchange for risk may struggle in the current environment. Those funds that have committed capital will likely be more cautious in deploying it, and riskier assets may receive less attention. Those without committed capital are going to struggle to raise it in this environment.

This risk-off cycle will hit investments in merchant assets, development assets, aggregation facilities, non-investment-grade strategies, high-yield portfolios and developers seeking development capital. These entrepreneurial efforts are critical and sow the seeds for the industry’s future. Inevitably, these constraints will favor companies with access to larger balance sheets, and it will accelerate the developer consolidation already underway in the solar industry.

COVID-19's impact on tax equity and debt

Banks are the primary participants in both the tax equity and debt markets for solar. Bank exposure to the recent economic downturn has been driven primarily by loans, and in some cases, loans made to extractive industries and to retailers who have been hit hard by this crisis. The themes here are similar.

Debt

On the lending side, even as interest rates have fallen, the spread (generally a premium over LIBOR) has increased from 1.25 to 1.75 or 2.00, and in some cases even higher. The scale of the opportunity and the commercial weight of the lender matter. Lending fees have increased proportionately as well. Bank spreads and fees increase to compensate them for lower all-in returns on capital that results from lower interest rates. It will be interesting to see how this market changes in the next few months as the country attempts to return to normal.

Compounding this is an overarching concern around liquidity. As concerns grow around the integrity of outstanding loans, banks suffer the same capital constraints as institutional investors and funds. Further, because this is an industrywide issue, banks are struggling to syndicate loans out to other bank partners. As larger banks struggle to make money on syndicating loans, they must underwrite the entire loan to a long-term hold, all driving up the cost of capital.

Lending has always been a relationship business. It certainly is now. In the current market environment, if a developer or independent power producer doesn’t have scale or historic relationships, it can be challenging to secure loans. The stronger the relationship and the larger the opportunity, the better the terms.

Tax equity

Tax equity provides anywhere from 30 to 40 percent of the capital stack for solar. A functioning tax equity market is critical to a healthy solar industry.

From the outside, the solar tax equity market often looks monolithic, with half a dozen primary participants. The reality is that there are dozens of participants behind these entities investing in funds or through syndication structures. Some of the largest solar tax equity investors are syndicating 50 percent of their volume. This has pros and cons for the industry.

A broader population of tax equity investors means that markets are more resilient than most people assume. A significant number of investors are grocery chains and tech companies that are weathering the crisis. Syndication also means that the solar industry is incentivized to find new tax equity. That’s mission-critical for everyone.

The drawback is that syndicators don’t control or always know the profitability or commitments of their clients. This is why many of the large tax equity investors are honoring the term sheets in front of them but are slowing down new origination. Many smaller syndicators representing corporate customers are putting deals on hold. And of course, the banks themselves have their own challenges right now, and some of the largest banks have stepped out of the market as their exposure to industries like natural gas hammers their portfolios.

This is our single largest concern for the industry, which is why we're working closely with the Solar Energy Industries Association to explore whether there may be tools at the federal level (like refundability of the Investment Tax Credit) that can help address these issues.

The path forward

Anyone who has helped build a company in this industry knows the relentless struggle. The most we can do for one another is to share our experiences and perspectives. Here are a few suggestions.

First, if you’re a developer, avoid transitioning into owning assets if you don’t already. This is not the time to be initiating a new phase in your development business, and it may be a good time to consider simplifying it.

Second, if you are going to work with banks to secure long-term debt or construction debt for your projects, find a good partner and invest in that partnership. Ask about their approach and ensure you trust them. The same goes for tax equity. We’ve seen both sides, having both deployed tax equity and worked with our partners to secure it. Relationships matter.

Third, if you’re developing early-stage assets or semi-merchant assets, ensure you’re focused on quality and tenor. Also ensure that you’re capitalized to carry your assets a bit further into the development cycle than you may have planned. If you are not, prune your portfolio.

Most importantly, stay sane and stay hungry. Solar remains the future, and we’re building that future together.

ABOUT SOL SYSTEMS

Sol Systems is a leading national solar energy firm with an established reputation for integrity and reliability across its development, infrastructure and environmental commodity businesses.To date, Sol has developed and/or financed over 850 MW of solar projects valued at more than $1 billion for Fortune 100 companies, municipalities, counties, utilities, universities and schools. The company also actively shapes and trades in environmental commodity and electricity markets throughout the United States. The company was founded in 2008, is based in Washington D.C, and is led by its founder. Sol Systems works with its team, partners, and clients to create a more sustainable future we can all believe in. For more information: www.solsystems.com

[caption id="attachment_8375" align="alignright" width="300"] The Sol Systems team, "The Mad Ones", poses after completing the 200-mile relay[/caption]

Last year, I wrote about my first time participating in a Sol Systems leg-destroying tradition: the 12-person, 200-mile Ragnar relay. Twelve months rolled by and I found myself back in New Hampshire, waking up in a crammed van at five in the morning preparing to run six miles for the third time in 18 hours. Why? Because at Sol Systems, we know that to reach our goals, whether it’s taking on a Ragnar or transforming our country’s energy grid, we need to embrace the madness that comes with it.

For the unfamiliar, Ragnar relays are run by 12 brave individuals (or in some cases, six insane individuals) who each run anywhere from 12 to 26 miles over the course of three separate legs. Ragnars are run across the country, but for the past two years, our team has run Reach the Beach. Starting in Bretton Woods, and spanning most of the length of New Hampshire, the course ends at the Atlantic Ocean near Portsmouth,will where our CEO and teammate, Yuri Horwitz was raised.

[caption id="attachment_8376" align="alignright" width="300"] Krisztina Pjeczka finishes her first leg of the relay[/caption]

Running a Ragnar feels like a condensed version of working in the solar industry. Your body and mind need to be ready for the fight. When your legs are firing signals to your brain to stop (which my non-runner’s body was doing a lot of), you need to push even harder. When a fossil-fuel-powered world is trying to slow the clean energy revolution, we need to work twice as hard to fight back. Change isn’t created by people who simply clock in and clock out every day, but by dedicated individuals hell-bent on bringing that change. In the same vein, Ragnar isn’t run by folks who are set on walking.

However, I’d like to think that even in the solar industry, it’s hard to find too many companies with 12 participants who are happily willing to spend 27 hours crammed in a van with their coworkers every year. I certainly never thought I’d be running the race, much less two years in a row. However, the feeling when finishing your last leg, and cheering on your teammates as they complete theirs, is well worth the struggle, especially with the teammates I have at Sol. Some of them will even tell you they had fun running (I’m skeptical). In solar, the feeling of putting clean energy in the ground is well worth the scrapes you inevitably take along the way. Do you need to be able to run a Ragnar to be in the solar industry? Not at all. But solar professionals would have an easier time relating to these runners than most. Perhaps the most relatable thing: at the end of each success, you deserve a cold beer.

ABOUT SOL SYSTEMS

Sol Systems, a national solar finance and development firm, delivers sophisticated, customized services for institutional, corporate, and municipal customers. Sol is employee-owned, and has been profitable since inception in 2008.

Over the last ten years, Sol Systems has delivered 800 MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com

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.

ABOUT SOL SYSTEMS

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com

2017 has certainly been an interesting year for solar investments. While early policy reform uncertainty had some investors staying away, many are back at the table and wondering, where are the assets, and how can I invest?

At the beginning of the year, the prospect of tax reform under the new administration forced many tax equity investors to the sidelines. However, the market soon realized that after early setbacks in President Trump’s legislative agenda, the likelihood of tax reform occurring in 2017 quickly shrunk to zero. This general consensus on tax reform, and need to offset “business as usual” 2017 tax appetite, brought many investors back to the table midway through the year; new investors even entered the market.

While six months ago, the solar industry would have been right to gripe that insufficient capital was available to meet project demand, now we are seeing the inverse. There are currently not enough investment-grade, large projects to fill the demand of tax equity investors for third-party structured finance deals.

Where are the Projects?

Several factors contributed to this slowdown in projects available for tax equity investments.

Distributed utility projects – those that have long-term power purchase contracts with investment-grade utilities, but typically fall below 20MW in size – provide cookie-cutter development opportunities and scalable, but still bankable, portfolios for investors. However, several major state markets like North Carolina are facing challenges in utility interconnection policy, PURPA implementation, or both (it should also be noted that in the case of North Carolina, this could change shortly with renewable energy legislation recently signed by Governor Cooper). Utility queues are filling up in many established markets like Massachusetts, and Maryland, and even some relatively lower penetration states like Oregon, South Carolina, and Virginia are experiencing lags in scheduled interconnection dates. Projects struggling to get utility approval or commitments from utilities’ construction crews in large scale solar creates a slow and clunky development and financing process, and projects that would have otherwise been completed in 2017 are slipping into next year.

According to GTM’s Q2 2017 U.S. Solar Market Insight report, 2017 was the first year that national installations fell on both a quarter-over-quarter and a year-over-year basis. In California, an established market, and Oregon, a breakout market over the last two or so years, several hundred MWs of utility scale solar will spill over into 2018 from this year. Overall, the development timeline for qualifying facilities (QFs), facilities of choice often for tax equity investors, is lengthening, even as key PURPA markets limit the capacity and term of standard PPA contracts.

Yet despite development headwinds in 2017 for utility projects, solar’s maturation as a market is creating more competition, which means thinner margins all around. GTM reported that utility scale PPAs are now between $35/MWh and $50/MWh, and getting long-term, credit-worthy PPAs with both utility and non-utility offtakers is increasingly difficult. Competitively bid PPAs and razor-thin EPC and development margins result in pressure to find the most competitive financing available, even as tax equity investors continue to seek higher returns.

The Emergence of New Tax Equity Investors

Tax-advantaged buyers entering the market also contribute to a paucity of projects for 3^rd party, structured finance deals. These investors are hungry for solar assets, but may not need the tax equity piece. For example, Florida Power & Light recently announced 250MW of utility-scale solar development, and will be rate-basing the investment instead of financing with tax equity and debt. Some southeastern investor owned utilities (IOUs) follow this trend, like Dominion Virginia and Georgia Power, who alongside FPL and five other utilities have outlined a combined 10.8 GWdc of additional utility solar planned according to GTM’s Solar Market Insight Report.

Tax Equity & the Trade Case

Finally, we would be remiss if we did not mention the Suniva and SolarWorld Section 201 filing. Rising module prices, if developers can even find modules to buy, has compounded the stresses in the market detailed above. In response, developer/sponsors looking to hedge against market uncertainty will either offload assets to entities that can finance in-house (and have the balance sheet to lock up modules early), or simply not build assets until a determination is made by the International Trade Commission, further reducing the supply of assets on the market.

Where’s the Market?

Even with setbacks, and much of the low-hanging fruit being picked off, for the determined investor wanting to make solar a part of their tax strategy there is a path to move forward.

“More tax equity players entering the market is a good thing for the solar industry,” according to Jessie Robbins, Director of Structured Finance. “For tax equity investors already in the space or thinking about entering, it’s important to identify a strategy and an approach to investing in a year where capital seems to be more plentiful than projects.”

Investors should focus on understanding what value they provide to developers in the market – attractive pricing? Certainty of execution? Flexible structure? While offering strong economics to sponsors will always be fundamentally important, sponsors also prioritize other elements of a deal that can have a material impact on their returns and strategy; for instance, accommodating project-level debt, offering various flip options, or executing quickly. (Shameless plug: Sol Systems recently closed a transaction in under four weeks to accommodate an incredibly tight utility interconnection schedule.)

Conclusion

With a quarter still to go, 2017 has been an interesting year for developers and investors alike, to say the least. For those investors already at the table, there is potential for 2017 to be a unicorn year for transactions that could benefit from a boost in returns if tax reform passes in 2018. Even for investors contemplating 2018 investments, Sol Systems sees numerous options to structure around risk of a tax rate change. Sol Systems is poised to help make those investments happen whether you are a potential investor or a developer looking for an investment.

For any tax equity related questions, please reach out to:

Jessie Robbins

Director, Structured Finance

202-588-6278

jessica.robbins@solsystems.com

This is an excerpt from the August 2017 edition of The SOL SOURCE, a monthly electronic newsletter analyzing the latest trends in renewable energy based on our unique position in the solar financing space. To view the full Journal, please subscribe or e-mail pr@solsystems.com.

ABOUT SOL SYSTEMS

Over the last eight years, Sol Systems has delivered more than 600MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com.

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