Tax Equity in 2018: What to Watch For

Posted on January 31, 2018January 25, 2023 by Lauren Miller

Tax Equity in 2018: What to Watch For

2018 | 31 Jan 2018

By Lauren Miller

This is an excerpt from the January 2018 edition of The SOL SOURCE, a monthly electronic newsletter analyzing the latest trends in renewable energy based on our unique position in the solar industry. To receive future editions of the journal, please subscribe.

2017 was a year of challenges to the tax equity status quo. The market faced several uncertainties, largely because of the looming potential for tax reform. In early 2017, many investors took to the sidelines, uncertain of when and how tax reform would affect their tax appetite and returns. However, as the year progressed, these concerns cooled, and investors returned to the market in force – some entering for the first time - creating a shortage in projects available to meet tax equity demand.

While this shortage progressed – exacerbated by the Section 201 trade case – tax reform picked up speed in Congress, and the industry faced a new set of potential threats. To start, the new law’s reduced corporate tax rate will reduce the overall tax equity supply available in the market. At the deal level, it causes depreciation to become less valuable and forces tax equity investors to either take a lower return, or reduce their pricing to sponsors.

The base erosion and anti-abuse tax (BEAT) posed another threat to investors with large cross-border payments, in that it could potentially prevent investors from benefiting from those credits. However, Congress's final version reduced some of BEAT's blow by retaining the ability to use 80 percent of the investment tax credit (ITC) and production tax credit (PTC). Nevertheless, it will cause issues for some investors, which we will discuss below.

All told, the tax equity market will see changes in 2018; and here some potential impacts we may see in the space:

Multinational Investors Leaving the Space

The retention of BEAT in the final version of tax reform may lead some multinational investors to leave the solar tax equity market in 2018. In situations where the BEAT is projected to exceed the regular tax liability of a multinational corporation, it could force companies to re-evaluate their potential investments in the renewable energy space or exit some of their current investments entirely. These multinational corporations have historically dominated the tax equity market used to finance many renewable projects; however, solar investments have been less dominated by these corporations. Even though the final bill lessened the provision on BEAT, it will not be enough to retain all multinational investors in the US. With these investors leaving this space, there could be a reduction in the capital available in the market, making it harder for developers to raise capital.

Pricing May Decline Due to Basic Mechanics

Tax equity pricing is expected to drop as the lost value of depreciation is taken into account from the reduction of the maximum corporate tax rate to 21% from 35%. Given that the tax losses are now worth less to the investors, investors will reduce their upfront capital contribution to projects – resulting in tax equity comprising slightly less of the capital stack. Debt can bridge the remainder but requires a higher cash-on-cash return. Depending on the deal and sponsor return requirements, this could cause some pain, especially if investors are unable to or unwilling to elect 100% bonus depreciation.

Conclusion

Tax reform has certainly and will continue to pose challenges to the industry, but it is by no means an end to the solar market. As the new policies come into effect, 2018 will be a year of adaptation to the new tax laws. Under these laws, there is still a lot of room to execute tax equity deals and invest in solar projects, and the industry has already started doing the work to adjust. To help offset lower pricing and reduced upfront capital, we may see developers adopt the more efficient inverted lease in structuring their deals instead of a partnership flip, for example. Long-term, we expect this market to stabilize as investors get more familiar with the impact of tax reform. Sol worked with its investors proactively to address some of these issues in 2017. Please reach out to Jessica Robbins at our team (jessie@solsystems.com) if this is of interest to your company.

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. Sol is backed by Sempra Energy, a $25+ billion energy company.

Over the last eight years, Sol Systems has delivered 650MW 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.

Tax Reform and the Solar Industry: What’s the BEAT?

Posted on December 15, 2017January 25, 2023 by Lauren Miller

Blog

Tax Reform and the Solar Industry: What’s the BEAT?

2017 | 15 Dec 2017

By Lauren Miller

This is an excerpt from the December 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 receive future editions of the journal, please subscribe.

With December 31, 2017 quickly approaching and an end to President Trump’s first year in office, the President, alongside House and Senate Republicans, is looking to make good on a campaign-trail promise of tax reform. Back in November, the House passed the Tax Cuts and Jobs Act and was soon followed by the Senate, which passed its bill at the beginning of December. Now that both houses have passed their respective bills, each with their own edits, the solar industry is taking a deeper look at the provisions and beginning to dig into potential industry impacts. As such, we would be remiss if we didn’t cover what we’re seeing and hearing in regards to tax reform and its potential effects.

Reduction in Tax Equity Investments

The most obvious of the solar industry’s negative exposure to tax reform is the reduction of the corporate tax rate. Both House and Senate versions of the bill reduce the corporate tax rate to 21 percent. This lower corporate tax rate would decrease tax liability for entities like banks and insurance companies, resulting in a smaller tax liability to offset through solar’s 30 percent federal investment tax credit (ITC). This would shrink the total pool of potential solar investors and capital to be deployed for projects. Equally important, a reduction in the effective tax rate substantially reduces the value of depreciation, which offsets income (not tax liability).

While tax appetite will likely shrink under a lower corporate tax rate, the potential removal of other tax credits from the tax code may push those investors still looking to leverage tax credit investments toward solar. While the Low-Income Housing Tax credit is preserved in both bills, albeit with some modifications to the bond markets, other prevalent tax credits like the Historic Tax Credit (HTC), or even our dear cousin wind’s Production Tax Credit (PTC) are facing tax reform threats.

For both the HTC and the PTC, what’s in store for them is largely dependent on what outlasts the reconciliation process currently underway and rapidly finishing. The HTC is repealed in the House bill but faces minimal changes in the Senate bill, where the credits now have to be claimed over 5 years rather than when placed in service (which is how the law stands currently). However, even the slight changes in the Senate version make the HTC less attractive to a solar ITC investment that can be claimed all at once rather than over five years. So, either way, challenges in both bills to the HTC could push investments towards solar.

For the PTC, how reconciliation shakes out in regard to the Alternative Minimum Tax (AMT) will impact its future attractiveness. Under both House and Senate bills, the corporate tax rate is taken down to 20 percent; this reduction in the corporate tax rate takes companies down to the level of the AMT. This is potentially problematic for the PTC, as only four years of wind production credits are eligible to be claimed for companies at the level of the AMT, as opposed to the normal 10 years when above the AMT. The full ITC is still eligible to claimed against the AMT though making it more competitive in a scenario where the AMT is retained. The House bill removes the AMT thus letting the PTC stay at its full 10 years, but the Senate bill retains it and essentially shortens the PTC to only four years. How reconciliation handles the AMT will affect the attractiveness of the PTC as a corporate tax investment strategy, and thus the comparative attractiveness of solar’s ITC.

A reduced tax rate will certainly affect the outcome of tax credits and which credits, if any, investors choose to leverage. However, one silver lining is reduced tax rates could mean fewer taxes on solar project owners’ income generated from their projects.

BEAT*

In addition to traditional threats of lower tax rates, the newest threat to tax equity investment in solar appeared in the Senate version of the bill with the introduction of the base erosion and anti-abuse tax (BEAT). The BEAT targets companies that seek to reduce their tax liability through cross-border payments to affiliates and comes into effect when those investments reduce a company’s U.S. tax liability to less than 10 percent of taxable income. Under the BEAT, PTC and ITC investments cannot reduce tax liability below this minimum 10% threshold. For companies that have cross border payments and are near this 10% threshold, tax equity investments in both wind and solar will be less attractive. However, the BEAT mainly targets larger multinational corporations making payments to foreign affiliates or foreign corporations with U.S. business. These categories of investors, while a small portion of tax equity investments, are by no means the sole investors, and other potential investors can still place their investments without concern for the BEAT. Additionally, while the Senate bill introduced the BEAT, it is not present in the House bill, and therefore could potentially be removed through the reconciliation process.

Negative Impacts on Bonds

While threats to corporation’s tax liability are the most obvious dangers of tax reform, there are others lurking in the hundreds of pages that have the ability to deter future solar growth. One big one is the potential repeal of the tax-exempt status of private activity bonds (PAB) in the House version of the bill.

Hopefully this doesn't come to pass, but if it does, for municipal players looking to get involved in clean energy, it could change the cost of issuing debt to help finance projects for the worse. Municipal utilities represent a market that was recently opened to solar and has been expanding. According to GTMs Q3 2017 US Solar Market Insight report, the Midwest could experience 55% compound annual growth rate between 2017 and 2022 largely driven by investor owned utilities alongside their smaller cooperative and municipal utility partners. However, the future of tax-exempt status of bonds could change this outcome, as debt would become more expensive.

Others, in the MUSH (munis, universities, schools, and hospitals) universe that have been solar customer targets for years will also be affected, and this could shrink potential solar customer pools. Reconciliation could change this outcome, as the Senate version does not repeal the tax-exempt status of PABs. External pressures are urging House GOP members towards this outcome which would help preserve solar project funding alongside funding for many other socially beneficial projects.

Conclusion

Tax reform currently poses more questions than answers. House and Senate Republicans are frantically working through the reconciliation process and are hoping to get the bill on the President’s desk as soon as possible, especially before Senator-Elect Doug Jones (D-AL) gets into his seat, making the potential for party defectors on the bill more tenuous. Ultimately, how solar is affected will largely be dependent on this reconciliation process, and the industry should pay close attention to these key issues.

This article was written on December 15, Given the evolving nature of the bill, you can receive up-to-date news on how tax reform could affect your potential investments by reaching out to: Jessica.Robbins@solsystems.com

*UPDATE: Since the publication of this article, the tax bill has evolved regarding the BEAT's handling of the ITC. We have included SEIA's statement on the changes below:

".....the conference report changed the new Base Erosion Anti-Abuse Tax [BEAT] to allow the Investment Tax Credit to be used by solar investors. Given the complexities of the BEAT, we look forward to working with our congressional allies to modify the provision to allow unused tax credits to be used in future tax years" - SEIA, December, 18, 2017

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.

Section 201: A Look at Key Markets. As Tariff-ying as You Think?

Posted on November 20, 2017January 25, 2023 by Lauren Miller

Blog

Section 201: A Look at Key Markets. As Tariff-ying as You Think?

2017 | 20 Nov 2017

By Lauren Miller

This article was co-authored by Lauren Miller and Stephanie Sienkowski.

This is an excerpt from the November 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 receive future editions of the journal, please subscribe.

On October 31, the International Trade Commission (ITC) released their much anticipated remedy recommendations. Though the recommendations’ impacts are by no means benign, they certainly could have been far worse if Suniva and SolarWorld had their way.

The ITC has suggested three possible remedies:

Chairman Schmidtlein has suggested a 10% ad valorem tariff on the first 0.5GW of Crystalline Silicon Photovoltaic Cells (CSPV) cells increasing to 30% ad valorem after the initial quota and a 35% ad valorem tariff on CSPV modules. Each of these tariffs will incrementally decrease over 4 years and the quota will incrementally increase.
Vice Chairman Johanson alongside Commissioner Williamson has suggested a similar four-year, tariff-rate quota on CSPV cells of 30% ad valorem for imports after the first gigawatt with percentage points for the tariff decreasing by five each year and the quota increasing by 0.2GW. For CSPV modules there will also be a 30% ad valorem tariff without a quota limitation, decreasing by the same percentage points over the four years.
Commissioner Broadbent in her recommendation took a slightly different approach, most similar to SEIA’s recommendation, and recommended 8.9GW quotas each on CSPV cells and modules that would increase by 1.4GW annually. She then recommended that these quantitative restrictions be implemented by selling import licenses at public auction at a minimum price of one cent per watt with the revenue from these auctions to be used in a fund to assist the domestic CSPV industry.

In looking at these recommendations, the first two and their potential 30% or more tariff rate are the most impactful for future solar development; however, they are not likely to be deadly. To give us a better sense of these findings’ impact on the industry, we assumed the 30% tariff rate and analyzed what it might to do to PPA rates in three key markets: New Jersey, Massachusetts, and Illinois.

New Jersey

The first key solar market we will look at is New Jersey. The effects of a 30% tariff in New Jersey are harder to predict because of the state's solar renewable energy credits (SRECs) are a market-based incentive with market values that are subject to change. To keep things simple and to set a baseline for the comparisons we will draw in Massachusetts and Illinois, we looked at a 30% tariff impact on New Jersey keeping SREC prices constant. A sample pre-tariff project with a PPA rate of around $.05-.06/kWh would see a projected 10% increase.

The New Jersey solar market has other drivers, however. The recent election of Phil Murphy as governor on November 8 bodes well forpro-solar legislation. Governor-Elect Murphy has announced that he plans to complete New Jersey's Energy Master Plan by the end of 2018, and hopes to raise the state’s renewable portfolio standard to a 100% clean energy by 2050. There is also pending legislation to increase the state’s solar carve-out, which could help SREC prices rise and soften any potential tariff’s impact. Governor Murphy would be much more likely to sign this than Governor Christie has been.

Massachusetts

In Massachusetts we compared a sample pre-tariff PPA project in the managed growth market sector that qualified for a .45 SREC II factor, with a sample post-tariff PPA project receiving $60/MWh in SMART program incentives for 20 years. The $60/MWh incentive value was calculated by assuming a $.17/kWh starting SMART rate and adding in a $.01/kWh ground mount subtractor and $.10/kWh value of energy subtractor. Keeping all other factors equal, the PPA rate increased by almost 40% form around $.04-.05/kWh in the pre-tariff scenario to $.06-.07/kWh in the post-tariff, SMART scenario.*

In Massachusetts, the potential increase from the tariff may be mitigated by the changes to Massachusetts’s incentive program. Additionally, to help ease the impacts of the tariffs in Massachusetts, it's imperative that once Massachusetts opens the initial competitive bid to help set the initial block 1 rates later this month, developers don't underbid. Pricing in a post-tariff world will be very sensitive to the clearing price of SMART and therefore honest bids will be key.

Illinois

The Illinois Power Agency released its Long-Term Renewable Resources Plan on September 29, 2017, setting up Illinois as one of the most exciting state markets to emerge in years. The plan outlines renewable energy credit (REC) procurement programs for Ameren and ComEd utilities. REC prices have been estimated based on NREL’s CREST model, but these REC prices may be refined before approval with the IL Commerce Commission (ICC). (For a refresher on the Illinois solar program, review our summary of the Long-Term Renewable Resources Procurement plan from the October SOURCE)

With this in mind, in Illinois we compared a sample 2MW, pre-tariff PPA project, assuming a spring 2017 Distributed Generation (DG) Procurement REC value of $68.56/MWh for 5 years, with a sample 2MW, post-tariff PPA project, assuming an estimate of 2018 incentives. The 2018 incentives include a $250/kW distributed generation rebate and $25/MWh incentives for 15 years, calculated as an average of Ameren and ComEd’s 2000 kW block 1 estimates found in table D-7 here.

With these numbers in mind, a project with a $.07-.08/kWh PPA rate under the spring 2017 DG procurement would actually have a 10% lower PPA rate, closer to $.07/kWh, under the proposed 2018 Adjustable Block and DG rebate, even in a 30% post-tariff world, demonstrating the potential strength of Illinois’s new renewable energy procurement program in both its REC contracting strength and because of the DG rebate.*

One point of clarification on these rates is that the REC values are not yet final. They are likely to change in final iteration. In its plan, the Illinois Power Agency wrote that it is aware of the pending tariff case, and in addition to feedback collected during the initial comment period, it may need to make further changes depending on the final ruling by the Trump Administration. It should also be noted that while fixed price RECs are set for projects under 2000kW via the Adjustable block, anything sized over 2000kW must bid for a 15-year REC contract. As always, honestly priced bids will be key to this market flourishing

Conclusion

While the potential for a 30% tariff is tarrif-ying to some, the actual impacts of this Section 201 may not be as scary as the industry feared back in June, at least for Illinois, New Jersey, and Massachusetts. However, in tighter markets state policies will certainly play a role in helping projects continue to pencil. For example, emerging solar markets in places where solar is just beginning to become cost competitive, or markets with low electricity rates, no strong state energy policy, and low solar irradiance, will be harder hit by the trade case. Pending policy and regulatory changes in places like Maryland, Connecticut, and Virginia will be important to pay attention to in the 2018 legislative session, and strong state legislation could help soften the blow.

While 30% is most likely a worst-case scenario, the President still has the final say in what remedy will be. The recommendations landed on President Trump’s desk on November 13, and from there he has 60 days to make his decision. The industry will be watching to see which of the three solutions, combination of solutions, completely new remedy, or no remedy at all that the President will end up implementing, while keeping in mind that the ITC's recommendation has typically been a ceiling for recommended tariffs.

*Please note that all PPA rates mentioned in this article are sample rates and should not be used as indicative or average rates for specific projects or markets. If you would like indicative pricing for your project, please email finance@solsystems.com.

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.

The Shifting Solar Incentive Landscape

Posted on September 27, 2017January 25, 2023 by Lauren Miller

Blog

The Shifting Solar Incentive Landscape

2017 | 27 Sep 2017

By Lauren Miller

This is an excerpt from the September 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 receive future editions of the journal, please subscribe.

As the solar industry continues to grow and become cost-competitive with traditional fuel sources, how states think about incentivizing the technology has also evolved. Ten years ago, renewable portfolio standards accompanied by solar renewable energy credit (SREC) markets were a primary mechanism to grow a nascent solar industry, at least on the East Coast. In recent years, we’ve seen SREC markets remain in states with existing programs, but new domestic programs have shifted from this market-based SREC structure to other models, such as fixed-price or competitively-bid, feed-in tariffs (FiT), centralized REC procurements, and auction-like programs. Will this trend continue, and if so, what are the pros and cons of moving away from a market-based incentive model?

Who’s Switched Sides?

The most topical of East Coast markets switching sides is Massachusetts’ forthcoming switch from its SREC II program to the Solar Massachusetts Renewable Target (SMART) Program. SMART will transition the Commonwealth’s solar incentives to long-term, fixed-rate contracts that operate more like a FiT rather than relying on SRECs traded on the open market. Massachusetts follows the footsteps of its southwestern neighbor Rhode Island’s RE Growth Program which offers a competitively-bid FiT for projects.

Unlike Rhode Island, however, Massachusetts will not be fully competitively bid. Rather an auction mechanism will set the initial price for the program. After that, each “block” within the program will step-down in price and volume once all capacity in a given block is filled. Declining block incentives were made popular with the enormously successful California Solar Initiative (CSI), followed by New York’s Megawatt Block, and soon, Illinois’s new Adjustable Block Incentive for distributed generation, which will go live next summer.

Other states have kept SRECs, but embraced competitive bids for long-term SREC contracts rather than trading setting SREC pricing. States that have gone this route include Delaware, Illinois, and Connecticut with its LREC/ZREC program.

The Market-Based Strongholds

Not all states have followed this path though, and fully privately-settled SREC markets have remained in Maryland, Pennsylvania, Ohio, New Jersey, and the District of Columbia. In these states SREC markets created or are still creating meaningful revenue generation for solar facilities bringing investors and developers to the table. Some states have stayed stronger than others, however, and in Maryland, Pennsylvania, and Ohio SREC pricing has waned, changing project economics. In Maryland, we’ve still seen a strong build rate, particularly in the residential sector. However, the state’s potential C&I sector, with more demand-based rates, may see less growth and need better market incentives.

Some states have taken measures recently to improve their programs and try to further accelerate deployment and expand growth for system types which require higher prices. Maryland and D.C. both passed legislation within this past year and a half to increase their renewable portfolio standards, and in light of a shifting federal landscape, Maryland seems likely to introduce a 50 percent renewable portfolio standard (RPS) bill next year. New Jersey also has legislation on the table this year to increase its solar carve-out.

Which Side Should the Coin Land On?

Operational Continuity

There are two sides to every coin. What side is the industry hoping the proverbial coin will land on? There are arguments to be made for and against these varying incentive structures. From an operational standpoint, both have drawbacks and advantages. For bidding into SREC procurement programs, a REC auction, or FiT, the timing on this can be complicated. The program opens, and projects are bid in and then rushed to be done by the prescribed deadline before often have to wait again. There’s also the potential that a project doesn’t win a bid. What then? This leads to lumpy development cycles.

For SREC markets, on the other hand, the registration process for incentives starts only once a project is complete. This paperwork and trading can sometimes be complicated, especially for the average homeowner. Because of this, SRECs often need a third party involved (like Sol Systems) to help navigate market fundamentals, and even complex paperwork and regulations.

Investor Pricing

In regards to pricing of the incentives, there are pros and cons as well. Competitive solicitations, as we’ve touched on before with the Connecticut ZREC Program, can force project developers to bid below a financeable threshold in order to win; in this way, these solicitations are often a race to (or below) the bottom. In theory, Massachusetts’ new SMART program aims to avoid the two key issues with competitively bid programs. The first of which is administrative price-setting issues which has led to two flavors of unsuccessful programs: the too-high “binge and crash” FiT, or the too-low “failure to launch” programs like NY MW Block C&I. The second key issue with bid programs is the large amount of pricey transactional “friction” that comes when every system, no matter how small, must submit an incentive bid.

Volatility

However, despite complexities, long-term contracting, whether it is through a REC procurement, declining block incentive, or feed-in tariff, provides long-term price certainty that investors prefer. SREC prices, on the other hand, can be volatile and are subject to fluctuating market conditions, oversupply, or sometimes, even a rumor. Just look at the Maryland market today, where prices have plunged from $100 to $6 over the last 18 month, or New Jersey, where prices went from a high of $700 in 2009 to $70 circa 2012.

Dynamic Flexibility

Despite their volatility, however, market-based SREC programs do have their benefits. SREC markets respond to overarching industry conditions and build rates. Put simply: an RPS requests a certain amount of its renewable energy requirement to come from solar via a solar carve-out. When there isn’t enough solar (i.e. DC), prices are high to encourage growth. When there is more solar than needed per the RPS, prices plummet (i.e. currently everywhere else besides D.C. and New Jersey).

Jobs

This method may keep costs low for ratepayers, and it’s true that solar incentives do not need to be as high as they used to in most markets. However, price suppression can lead to less build and layoffs fueled by lack of uncertainty in regards to future RPS increases. Look at Pennsylvania in 2011 versus today. In 2011 Pennsylvania had over 4700 solar jobs; however, in 2016 with continuously declining SREC rates came a decline in solar jobs and today the state only has around 3000. Nevertheless, SREC markets such as Massachusetts, New Jersey, and Maryland have been incredibly successful in generating both jobs and megawatts as can be seen in Figure 1 compared to other Northeastern states that didn’t start with SREC markets.

At the end of the day, different states will choose different policies to meet their clean energy goals, and there is room under the sun (pun intended) for all programs to be successful, if implemented thoughtfully.

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.

Getting SMARTer Still: Massachusetts Announces Final SMART Regulations

Posted on September 12, 2017January 25, 2023 by Lauren Miller

Blog

Getting SMARTer Still: Massachusetts Announces Final SMART Regulations

2017 | 12 Sep 2017

By Lauren Miller

In early 2016, Massachusetts hit its SREC II program cap and had many in the solar industry asking: what’s next for the Bay State? To help answer this question, the Massachusetts Department of Energy Resources (DOER) issued SREC II extensions and then an initial outline for the new Solar Massachusetts Renewable Target (SMART) Program in January of 2017. The initial outline confirmed that there would not be another SREC program, but rather a tariff-based incentive program. The draft design for the program was announced on June 5, 2017. On August 25, 2017, the DOER filed the final version of 225 CMR 20.00 with the Secretary of the Commonwealth’s office.

From Start to Finish: What Changed?

Much of the initially proposed mechanics of the program are still in place with slight variances in the final version. SMART will lock projects into fixed-rate contracts for either 10-year or 20-year terms. Projects ≤25kW will be locked into 10-year contracts, and projects >25kW will be locked into 20-year contracts. The program aims to award these fixed-rate contracts to a total of 1600MWAC of projects. This capacity will be allocated among eight 200MW blocks, and apportioned by the electrical distribution companies’ (EDCs) share of 2016 total electric load. An initial 100MW procurement for projects sized 1-5MW will be used to determine the Base Compensation Rate for these blocks, and from there the Base Compensation Rate will decline 4 percent per block.

While the overarching design is still the same, the most recent round of regulations revealed changes to the initial procurement and how the Base Compensation Rate will be determined. The initial procurement will now have a bid-price ceiling of $0.17/kWh rather than a $0.15/kWh price ceiling for projects 1-2MW and a $0.14/kWh price celling for projects 2-5MW. Rather than the clearing price, which is equal to the highest requested Base Compensation Rate, to set the program’s initial Base Compensation Rate, the rate for the first block of capacity will now be a calculated mean price of all proposals selected in a Distribution Company’s service territory.

While calculations for the Base Compensation Rate changed, rate factors for systems under 1MW stayed the same and are shown below:

For systems greater than 1MW, per kWh compensation rate adders will be available based on location, off-taker, and technology to encourage the use of storage and trackers. A project can use up to one adder in each category to further supplement its Base Compensation Rate. While the initial rules placed a 320MW cap on adders available under the program this was removed under the final rules. DOER has instead established 80MW tranches of capacity for adders, and adders will decline by 4% with each tranche. The most significant adders for the locational-based adder category are for carports, and offer an additional $0.06/kWh. Combined with rooftop adders of $0.02/kWh, it’s clear that the Commonwealth aims to incentivize under-utilized spaces such as roofs and surface parking lots.

In contrast, the state is disincentivizing developers from utilizing large, open spaces, especially agricultural land. For systems larger than 500kW, subtractors to the Base Compensation Rate will come into play if the projects are classified as Category 2 or Category 3. These subtractors will range from $0.001-$0.0005/kWh per acre of land based on the acreage covered by the modules themselves. This is meant to push the Massachusetts market away from greenfield development and towards building and brownfield-sited projects. However, under the final rules, exemptions from subtractors were added for systems that had all necessary qualification documents obtained by June 5, 2017 or can demonstrate a good cause for exception.

These adders and subtractors will still be incorporated via the same formula:

𝑆𝑜𝑙𝑎𝑟 𝐼𝑛𝑐𝑒𝑛𝑡𝑖𝑣𝑒 𝑃𝑎𝑦𝑚𝑒𝑛𝑡 = (𝐵𝑎𝑠𝑒 𝐶𝑜𝑚𝑝𝑒𝑛𝑠𝑎𝑡𝑖𝑜𝑛 𝑅𝑎𝑡𝑒 + 𝐶𝑜𝑚𝑝𝑒𝑛𝑠𝑎𝑡𝑖𝑜𝑛 𝑅𝑎𝑡𝑒 𝐴𝑑𝑑𝑒𝑟𝑠 − 𝐺𝑟𝑒𝑒𝑛𝑓𝑖𝑒𝑙𝑑 𝑆𝑢𝑏𝑡𝑟𝑎𝑐𝑡𝑜𝑟) ∗ 𝑡𝑜𝑡𝑎𝑙 𝑘𝑊ℎ 𝑔𝑒𝑛𝑒𝑟𝑎𝑡𝑒𝑑 − 𝑣𝑎𝑙𝑢𝑒 𝑜𝑓 𝑒𝑛𝑒𝑟𝑔𝑦 𝑔𝑒𝑛𝑒𝑟𝑎𝑡𝑒𝑑

Another change made from the initial filing to August’s final version includes a 35 percent cap placed on systems less than or equal to 25kW per block with a 20 percent minimum. Additionally, the removal of onerous restrictions for qualification as an Agricultural Solar Tariff Generation Units were eased and will be replaced with still-to-come guidelines that will need to be complied with. Improvements were also made to restrictions placed on the usage of continuous parcels, as well as the usage of multiple parcels for one project and each of these are now allowed under specific circumstances.

One key piece still missing from the most recent release of SMART rules, is a clear path for the Alternative On-Bill Credit. This lack of clarity is exacerbated by the fact that net energy metering (NEM) caps have, for the most part, been hit in National Grid, Eversource, and WMECO territories. Seeing as SMART’s On-Bill Credit mechanism may supplant NEM, further details on the matter are anxiously awaited.

End of an Era and New Beginnings

Though final rules have been announced, the biggest question surrounding SMART remains. When will the SMART program officially begin? Based on the next steps needed by the Department of Public Utilities (DPU), mid-2018 seems likely. Utilities must file tariff proposals with the DPU by the end of September, and will have to develop auction materials by October 24^th. The initial procurement to set the Base Compensation Rate, will then likely occur the last week of October and will be announced by end of December. In addition to DPU actions, a third party administrator for the program needs to be selected. This should be done by April 2018. Finally, tariffs will be finalized between May and June 2018 which is when incentive dollars will start to flow.

So, there is still time before SMART officially kicks off; however, this doesn’t mean the market must pause during the transition. There is still space under SREC II to get projects registered until SMART is implemented, and Sol Systems is here to help you get it done. Please email us at info@solsystems.com to learn more.

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.

Tax Equity in 2017: The Capital Supply + Demand Shift

Posted on August 24, 2017January 25, 2023 by Lauren Miller

Blog

Tax Equity in 2017: The Capital Supply + Demand Shift

2017 | 24 Aug 2017

By Lauren Miller

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

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.

Author: Lauren Miller