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Avoiding project development pitfalls: Solar M&A

By: Mark Vitello,

Brendan Beasley serves as senior counsel of Klavens Law Group, P.C.  Having previously served as in-house counsel to solar project developers and module manufacturers, as well as in operations supporting the expansion of a nonprofit residential solar developer, Brendan’s practice combines broad industry expertise with a practical business-oriented sensibility.  

Brendan Beasley
08.13.20

Read this if you are a renewable energy developer.

Key areas in which developers face critical solar project development stumbling blocks include permitting and environmental matters, site control, interconnection, and preparation for project sale. Here, Mark Vitello and guest co-author Brendan Beasley of Klavens Law Group, P.C. look at preparing for project sale.   

Common pitfalls renewable energy developers encounter when selling projects

Starting from infancy of a project through negotiation of an exit transaction, there are some common―and preventable―missteps developers need to avoid. These include corporate housekeeping and contract missteps; underestimating time to obtain third-party items; striking the wrong balance in a letter of intent; over-reliance on a develop-and-flip business model; undue optimism regarding project assumptions; inadequate protection against payment risk; and not covering bases with a co-developer.

Staying on top of corporate housekeeping

To a developer, the corporate side of project development is low risk and unexciting. Perhaps because of this, developers often neglect corporate matters. This is particularly common for developers without a full-time in-house counsel. Small mistakes can add up. Steps like forming a special purpose project company early in the development process and assigning any pre-existing project contracts or entitlements to the project company can be overlooked or postponed (and eventually forgotten) as a cost-saving measure.  

Here are six common mistakes we see: 

  1. the wrong entity executing a project contract;
  2. misspelling the project company name;
  3. unauthorized signatories (or incorrect title for the right signatory); 
  4. failure to pay state corporate franchise fees; 
  5. losing project documents and signature pages, or not fully compiling project documents; and 
  6. inadvertently allowing liens against a project company or project assets.

These and similar issues can be resolved during the due diligence process, but this typically comes with additional legal costs and delay, is inefficient from a capital perspective, and can jeopardize a buyer’s confidence. There are various approaches to prevent issues and help spot issues in advance. For example, forming a project company is a fairly simple and repeatable process that a good set of forms and checklist can address. As a project moves to development-stage, periodic audits of your organizational and project documents by, for example, maintaining a living data room, will support a smooth transition to marketing your project.

Obtaining third-party items early in the process

Third-party items always take longer to secure than you expect. For example, if you are selling a solar project, you will likely need landlord and offtaker estoppels and, if the deal is structured as a sale of assets, consents to assignment. You will likely need a title commitment and survey. A ground mount project will need a Phase I environmental site assessment, and, often, some sort of permitting report or opinion. An independent engineer report may be required. These are just a few examples of numerous third-party items that are common conditions to closing a sale transaction or part of due diligence. 

Lessen the impact of third-party items, and avoid surprises by attacking these items early. Securing estoppels, consents, reports, and opinions early, even if it becomes necessary to “bring down” or refresh them for the closing date, is immensely better than not initially securing them and leaving your project exposed to third-party risk. It is never too soon to raise third-party estoppels, as that sets expectations. If possible, create incentives or penalties tied to delivery by the third party. For example, estoppels can be addressed in some capacity in your project documents by establishing a covenant to deliver an estoppel within a certain number of days of request and including a form of agreed-upon estoppel. For consents, a project document can identify certain instances where consent is automatic, such as assignment of the document to affiliates, or to third parties meeting certain credit or experience thresholds.

Right sizing the letter of intent (LOI)

Developers should avoid following the middle path in negotiating a letter of intent. Typically, the only two binding terms in an LOI relate to the exclusivity period and confidentiality. Nevertheless, there can be a lot of LOI deal term stickiness when it comes to drafting the definitive purchase agreement. As a result, we usually recommend one of two approaches: (1) no LOI or a very skinny one; or (2) detailed LOIs. 

Factors such as transaction complexity, counterparty risk, potential repetition of transactions, and internal approval processes tend to dictate the right approach in any particular situation. A skinny LOI might have a shorter exclusivity period to extend as the parties coalesce on terms and due diligence progresses. This approach establishes momentum toward due diligence and negotiation of a definitive agreement. One place to avoid ending up, however, is with an LOI that was only lightly negotiated yet covers many deal terms. This scenario can leave a developer (or buyer) in a lurch if certain expected terms of a purchase agreement cannot be agreed upon and were not covered in the LOI or, worse, negotiated deal terms in the LOI are not agreeable to the developer’s management or investors. A project with a commercial operation date deadline, permitting deadlines, and/or a fixed incentive period can ill afford to be stuck in exclusivity with a counterparty unwilling to budge from agreed LOI deal terms.  

Maintaining a Plan B―and a Plan C

Sure, most developers have no tax appetite, limited capital, and want to sell at the first possible opportunity. That’s fine. However, until that exit transaction occurs, the developer owns the project and should have an ownership mentality toward the project. Taking this approach can set the developer in the driver’s seat in purchase agreement negotiations by creating a viable, and perhaps even more valuable alternative path if negotiations stall. Over-reliance on a prospective purchaser that intends to finance construction or insists on procuring key equipment can result in a situation where the buyer exerts leverage if a developer has no Plan B in place. 

Having construction finance capacity or additional equity funding can markedly change the dynamics of post-LOI negotiation. If a developer does walk away from a transaction without having continued development during the period under exclusivity, the developer losses time while often increasing project risk due to outside commercial operation dates and expiring incentives and permits. On the other hand, a developer that has moved forward on a project, and even entered construction, will de-risk a project leading to potential pricing upside.

Correctly pricing transaction assumptions

A typical pre-commercial operation solar M&A transaction involves a purchase price paid in milestones. Frequently, LOI-stage assumptions based on the expected state of the project at the time of signing the definitive purchase agreement turn out not to be accurate. While certain things, such as ultimate project size or property tax burden, are often the subject of mechanisms to adjust the purchase price if later conditions vary from an assumed baseline, it can be risky not to negotiate contingencies with respect to other items, such as whether an executed site lease (still in negotiation) or a key permit (subject to upcoming local board vote) will be in hand at signing. 

Developers tend to be optimistic. However, a developer may wish to agree on pricing or milestones at the LOI stage based on conservative estimates to protect itself if the parties are otherwise ready to sign a definitive purchase agreement. Contemplating both “base case” and “ideal case” pricing and milestones in the LOI can help ensure a developer’s management and investors are on board. It also avoids over-promising and under-delivering, which can be more harmful to reputation and may result in a bigger discounts or deferrals of purchase price than if the base case were negotiated up front.

Ensuring buyer credit quality

A developer must consider the creditworthiness and reputation of a project buyer and put in place necessary protections both to ensure payment of purchase price and continued development and construction of the project. A parent guaranty can not only decrease the general credit risk of the buyer, but, depending on the buyer’s corporate structure, can also result in independent management personnel’s reviewing a milestone payment dispute with fresh eyes. This unbiased perspective may be more realistic and potentially sympathetic to a developer’s claim for payment. 

Other options to protect against risk of non-payment are project entity (or asset) buy-back rights and escrow agreements. In iterative transactions, such as ongoing sales of a portfolio of projects, a developer’s ability to offer future projects from the pipeline to the buyer on similar terms can act as a substantial incentive to the buyer to make payment. A common payment default scenario is a buyer’s unilaterally setting off against the purchase price for claims that may not have any merit. In this case, a buyer rarely has incentive to begin dispute resolution as it is holding the money. 

Developer protections to address this issue, in addition to those discussed above, include restrictions on set-off (which may include requirement of developer written approval or commencement of dispute resolution), litigation fee-shifting, and meaningful deductibles on buyer claims.

Selling co-developed projects

If you have a co-developed project, be sure your development partner is on board before signing an LOI, even if you may have exclusive authority over project sales. Better yet, ensure that each partner signs the LOI. The benefits are two-fold. First, this can protect against a later disagreement with your development partner on deal terms and kick-off discussions regarding allocation of risk between the co-developers in the event of post-closing claims. Second, this will give confidence to the prospective buyer that all necessary parties are in favor of the transaction.

For more information

If you have questions or would like more information about these matters, please contact Brendan Beasley or Mark Vitello.

Please note, this article, which may be considered advertising under the ethical rules of certain jurisdictions, is provided with the understanding that it does not constitute the rendering of legal advice or other professional advice by Klavens Law Group, P.C. or its attorneys. Please seek the services of a competent professional if you need legal or other professional assistance.
 

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Read this if you are a renewable energy producer, investor, or installer.

As Election Day approaches, much if not all of the nation’s attention is focused on the global COVID-19 pandemic, the millions of people it has affected, and its effect on the global economy. What haven’t been prominent in presidential election news are the different policy approaches of the two candidates. In the renewable energy sector, the differences are stark. Here is a brief look at those differences and tax approaches of the candidates.

General tax information: Trump 

Traditionally at this time in an election year we’re presented with tax plans from both candidates. While these are campaign promises and may not fully come to fruition after the election, they can shed light on what each candidate plans to prioritize if elected. As the incumbent candidate in this election, Donald Trump has not provided much detail on his tax plans for the next four years, as noted by the Tax Foundation’s Erica York:

“While light on detail, the agenda includes a few tax policy items like expanding existing tax breaks, creating credits for specific industries and activities, and unspecified tax cuts for individuals. The president has also expressed support for other policy changes related to capital gains and middle-class tax cuts. Of note, none of the campaign documents so far have detailed a plan for the expiring provisions under the 2017 Tax Cuts and Jobs Act (TCJA).”

The president’s main priorities have been growing the economy and creating jobs, both of which have taken a massive hit in 2020 due to the pandemic. President Trump has had little else to say on his plans for a second term other than extending the sunset of the Tax Cuts and Jobs Act (TCJA) of 2017 to 2025, or the end of this coming term. One of the items that could be considered is an expansion of the Opportunity Zone program, providing a tax deferral for investment in specified economically distressed areas.

Another item is how Net Operating Losses (see our prior blog post on this topic) will be treated and whether or not the TCJA or the Coronavirus Aid, Relief, and Economic Security (CARES) Act rules will be the ones used in the future. With the recent New York Times article detailing the president’s tax filings and showing how he took advantage of the NOL rules, it’s still a guess as to how that could impact the tax policy around NOLs going forward.  

Trump energy plan: fossil fuels first

In the energy sector, Trump’s focus has been on bolstering the oil and gas industry, while also trying to revive the flagging coal industry, and it appears his focus will continue in that vein. His proposed budget continues to provide tax breaks for fossil fuel companies, while planning to repeal renewable energy tax credits. Prior to his election in 2016, the renewable energy sector was somewhat hopeful that the benefits of increased jobs provided by the industry would be appealing to the President. This hasn’t played out over the last four years and with current energy credits scheduled to phase out and unprecedented unemployment, the jobs being provided by this sector may be part of the formula to help sway the administration to extending or expanding these programs.

General tax information: Biden 

Biden, as the challenger, has a much more detailed tax plan laid out. As expected, it is very different from the direction the Trump presidency has taken regarding taxes. A brief summary of his plan:

Raise taxes on individuals with income above $400,000, including:

  • Raising the top individual income tax bracket from 37% back to 39.6%
  • Removing the preferential treatment of long-term capital gains for taxpayers with income over $1 million
  • Creating additional phase outs of itemized and other deductions 
  • Instituting additional payroll taxes related to funding social security
  • Expanding the Child Tax Credit up to $8,000 for two or more children

Biden’s plan would also raise taxes on corporations:

  • Raising the corporate income tax rate from 21% to 28% 
  • Imposing a corporate minimum tax on corporations with book profits of $100 million or higher.

According to the Tax Foundation’s analysis of Biden’s tax plan:  

“[Expectations are that it] would raise tax revenue by $3.05 trillion over the next decade on a conventional basis. When accounting for macroeconomic feedback effects, the plan would collect about $2.65 trillion the next decade. This is lower than we originally estimated due to the revenue effects of the coronavirus pandemic and economic downturn.”…“On a conventional basis, the Biden tax plan by 2030 would lead to about 6.5 percent less after-tax income for the top 1 percent of taxpayers and about a 1.7 percent decline in after-tax income for all taxpayers on average.

Taxpayers earning more than $400,000 a year, and investors who have enjoyed preferential treatment and lower tax rates on capital gains will certainly pause at this proposal. While Trump’s tax policy has been to lower taxes in these areas to spur investment in the economy, Biden’s plan shows the need to generate tax revenue in order to cover the massive amounts spent during the COVID-19 pandemic.  

Biden energy plan: renewables first

Joe Biden’s energy policy is focused on climate change and renewable energy. In addition to ending tax subsidies for fossil fuels, his platform proposes investing $2 trillion over four years for clean energy across sectors, recommit to the Paris agreement, and achieve 100% clean energy by 2035.

Other Biden initiatives include:

  • Improving energy efficiency of four million existing buildings
  • Building one and a half million energy-efficient homes and public housing
  • Expanding several renewable-energy-related tax credits
  • Installing 500 million solar panels within five years 
  • Restoring the Energy Investment Tax Credit (ITC) and the Electric Vehicle Tax Credit

Indeed, over the past decade the Democratic Party has been a proponent of investment in and expansion of renewable energy technologies. While increased taxes will certainly cause many business owners and investors to pause, and any changes will need to be passed by Congress, it is encouraging to the renewable energy sector that Biden’s policy platform states goals related to increasing renewable energy in the United States.

As one might expect during this era of the two main political parties being so far apart from each other on policy, the proposed tax plans of both candidates also stand in fairly stark contrast, as does their approach to the United States’ energy sources in the coming decade. There are benefits and consequences to both plans, which will have an impact beyond the 2020 election.  
 

Article
The presidential election: two different approaches to energy

Read this if you are a solar developer or investor.

One of the most frequent questions we get from solar project developers is: “Will my investors be able to use the tax credits and the depreciation losses?” The answer, as with many things related to taxes, is “it depends.” One of the biggest hurdles is navigating the passive activity loss rules. While this is a fairly complicated topic, and includes a lot more of “it depends,” we’ll hit some of the major highlights here.

Passive or active?

For tax purposes, activities are grouped as either passive or active activities. Income from these activities are generally treated the same, aggregated as part of the taxpayer’s total taxable income and taxed according to the applicable tax bracket. Losses from these activities are treated very differently, though. Losses from active activities can be used to offset all taxable income, whereas losses from passive activities can only offset passive income. If there is not enough passive income in a given year to fully offset passive losses, the losses become suspended and carried forward. The losses carry forward until either there is passive income to offset or the activity is disposed of (sold or otherwise no longer owned), in which case the suspended losses release in full in that year.

Similarly, the Investment Tax Credit (ITC) takes on the attributes of the activity in which it is being generated. So if the solar project is determined to be an active activity for the investor, the ITC would be active and available to offset tax on all sources of income. But if the activity is determined to be passive, the ITC would be limited to use against tax on passive income. For an investor that has not considered this prior to purchasing a stake in a solar project, a limitation on the credit the investor can use could mean a reduction of the expected return on investment, and an unwelcome surprise.

Portfolio income

It is also important to point out here that a third type of income, portfolio income, is a very common type of taxed income comprised of interest, dividends, and gains from investments. This falls into a separate category from the active/passive analysis, which is often misunderstood. A taxpayer with lots of dividend income who thinks it is passive income ends up with a rude awakening as that is actually portfolio income and does not allow for the offset of passive activity losses.

Material participation test

IRS Publication 925 details all of the rules surrounding passive activities and includes a set of seven tests to determine material participation. If the taxpayer satisfies at least one of the material participation tests, the taxpayer’s share of the activity is considered active and not passive. The tests are: 

  1. You participated in the activity for more than 500 hours. 
  2. Your participation was substantially all the participation in the activity of all individuals for the tax year, including the participation of individuals who didn’t own any interest in the activity.
  3. You participated in the activity for more than 100 hours during the tax year, and you participated at least as much as any other individual (including individuals who didn’t own any interest in the activity) for the year.
  4. The activity is a significant participation activity, and you participated in all significant participation activities for more than 500 hours. A significant participation activity is any trade or business activity in which you participated for more than 100 hours during the year and in which you didn’t materially participate under any of the material participation tests, other than this test.
  5. You materially participated in the activity (other than by meeting this fifth test) for any five (whether or not consecutive) of the 10 immediately preceding tax years.
  6. The activity is a personal service activity in which you materially participated for any three (whether or not consecutive) preceding tax years.
  7. Based on all the facts and circumstances, you participated in the activity on a regular, continuous, and substantial basis during the year.

Tests one through six are pretty cut and dry, but the totality of the circumstances test presented in number seven is very open to interpretation. While this allows you to make an argument in your favor, it also gives the IRS more latitude to disagree with you, making it the riskiest test to rely on.

The IRS defines “participation” as “[i]n general, any work you do in connection with an activity in which you own an interest.” This does not include work that would be considered work only done by an investor – such as reviewing operations, preparing reports for your own use, or monitoring the finances or operations of the activity. The work in consideration must also not be work that is customarily done by the owner of that type of activity, nor your only reason for doing the work being to avoid treatment of the activity as passive.

While a contemporaneous log is not required to prove material participation, it is always a good idea to keep track of the work and hours you are performing on behalf of the activity in order to substantiate material participation. This is typically the first thing the IRS asks for in the event of an audit. 

As you can see from the seven tests, there is also room to switch between active and passive treatment in any applicable year. So it is important that you take the ITC in the year the project goes in service and the ITC is generated. If you are passive in year one and end up with suspended credits and or losses, a subsequent switch to active status would not change the attributes of those suspended items―they would remain passive.

Lastly, and important to note, this determination is made at the individual taxpayer level. Project investors need to work with their tax advisors and legal counsel to understand their personal tax situation before investing in a project. Depending on the individual situation, an active or a passive treatment may be more beneficial, as everyone’s tax situation is different. The most important thing is knowing ahead of time so that planning can be done and expectations can be set. No one likes a tax surprise!

If you have any questions about your specific situation or would like to know more, please contact the team. We’re here to help. 

Article
Passive activity loss limitation rules and solar project investment

Read this if you are a solar energy investor, installer, or involved in the renewable energy sector.

One of the benefits to a tax equity investor investing in a renewable energy project is the losses generated by the depreciation of the energy equipment being placed in service. Projects qualifying for the federal Investment Tax Credit are given a five-year MACRS life, providing a cost recovery deduction over five years from the in-service date (typically six tax return filings).  

Investors with eligible income from other sources can offset that income using the losses generated by the depreciation. In some cases the investors have more losses than they can use, which results in a Net Operating Loss (NOL). The rules around NOLs have changed several times recently, and it’s important to know what steps investors should take in order to maximize the benefit from their investment in a renewable energy project.

Historically, individuals could use losses to fully offset their taxable income in the current year. Any excess loss was to be carried back two years to offset taxable income on a previously filed tax return, if available. Any excess NOL carried back and not absorbed would then be carried forward and available for 20 years. This provided a source of immediate funds for investors, as an NOL carryback typically resulted in a recovery of taxes paid in a prior year.

An election could also be made with the original loss return to forgo the carryback and elect to carry forward only. In some cases investors determined that it was more beneficial to have the loss available to offset future income―for example, in cases where the tax rates were set to increase, if the depreciation benefits from a prior project were set to expire, or an anticipated large income event was on the horizon. These losses could also be carried forward for 20 years.

Impacts of Tax Cuts and Jobs Act on NOLs

With the passing of the Tax Cuts and Jobs Act (TCJA) in December of 2017, tax returns filed beginning with tax year 2018 were subject to some changes around NOLs. Some impacts:

  • Losses were no longer allowed to offset 100% of taxable income in the current year, now only being able to offset 80% of taxable income. The remainder was reserved as an NOL available on future returns 
  • The removal of the two-year carryback period 
  • The 20-year cap for NOL’s carried forward was removed, letting them carry forward indefinitely

While most investors were able to use their losses in the first several years surrounding the original loss year, removing the expiration cap on the NOL carryforwards was at least a compromise to losing the other benefits of generating a loss from the investment. The changes from the TCJA shifted the tax strategy focus, as investors who had previously been able to invest in projects and avoid paying federal income tax completely now had to budget for paying tax on at least 20% of their income. The influx of cash from carrying an NOL back to a prior year was no longer an option, as many investors factored that into their ability to repay debt or final construction invoices. While these weren’t completely devastating changes, they were ones that needed to be considered, modeled, and budgeted before any investments were made to ensure proper cash flow.

COVID-19 and its impacts

Then the COVID-19 pandemic hit, and impacted businesses in all corners of the economy. Congress passed the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) in March of 2020 with wide-sweeping incentives intended to keep cash flowing to those that needed to continue paying bills while businesses were closed. One of the major tax code changes was to the rules surrounding NOLs. The CARES Act temporarily repealed the 80% limit of the TCJA, once again allowing individuals to offset all of their taxable income with an NOL generated in 2018 through 2020.  

Actions to take

In addition, the carryback was also temporarily re-instated, and expanded to five years for losses generated in 2018-2020. Some considerations:

  • An investor who has already filed their 2018 tax return should look to see if their losses were limited on that filing. If so, an amended return should be filed to retroactively claim the full amount of the losses available in 2018 on that return.  
  • Additionally, an analysis should be done to verify the benefit of carrying back the losses to 2013-2017 returns and potentially claiming additional refunds for those years, depending on the volume of available losses and taxable income.

As the pandemic continues, and project completion is potentially delayed, it will be important for investors to monitor income and losses over the next six months to determine if they will be able to fully utilize NOLs for 2020, or if they will need to plan for a return to the TCJA 80% limitation rule in 2021.

If you have any questions or would like to know more, please contact the team. We’re here to help. 
 

Article
Net Operating Loss rules in renewable energy: COVID-19 changes

Read this if you are a solar investor, developer, or installer.

After a recent article where we highlighted some of the major points of the ITC safe harbor, we received many calls and e-mails looking for clarification on some of the related issues. In working to answer these questions we teamed up with Klavens Law Group, P.C., a Boston law firm that specializes in clean energy. Together with Brendan Beasley and Jon Klavens we have compiled a list of frequently asked questions that may be helpful as you navigate the last few weeks of the year. 

Q: My project is not ready for construction due to a pending decision on a land use permit. How can I minimize capital expenditure while still qualifying the project for the 5% safe harbor?
A: There are a couple approaches you as a taxpayer can take. First, if this project is among several in your portfolio, you can pay or incur expenses prior to December 31, 2019 for enough safe harbor equipment under a single binding contract to qualify each project in your portfolio and retain flexibility to allocate that equipment. Applying the master contract approach (per Section 7.03(2) of IRS Notice 2018-59), you would then transfer equipment, even after December 31, 2019, to affiliate special purpose entities under a second binding contract. Second, you can enter into a binding contract that is subject to a condition, applying section (ii)(B) of the “binding contract” definition at 26 CFR Section 1.168(k)-1(b)(4). In this case, the condition would be the project receiving the land use permits and clearing any related appeals period. Under this approach you would still need to pay or incur―or have your EPC contractor pay or incur under the look-through rule―at least 5% of the project’s depreciable cost basis by December 31, 2019. A limitation on this approach is that, if the condition is not likely to be satisfied within three-and-a-half months of the date of your binding contract, either you or your EPC contractor (applying the look-through rule) must take delivery of the equipment while the condition―and presumably the viability of the project―is still open and uncertain. 

Q: Can I finance a purchase of safe harbor equipment for my project?
A: Yes; however, you can’t use vendor financing. 

Q: I have a project that will be ready to construct in Q2 2020. The project company will execute a binding EPC agreement by December 31, 2019 that includes a procurement component. It will make an initial milestone payment of 7% upon execution. Does my project qualify for the 5% safe harbor?
A: Maybe. There is not enough information here to confirm. As taxpayer you must pay or incur expenses amounting to at least 5% of the total cost of the energy property prior to December 31, 2019, and must take delivery within three-and-a-half months from the date of payment under your binding contract. So the critical question here is what your EPC contractor is doing with that 7% payment. Here are some possible outcomes:

  • The EPC contractor purchases inverters on December 31, 2019 pursuant to a binding contract with a vendor. Applying the look-through rule, the safe harbor is satisfied.
  • The EPC contractor self-constructs a specialized racking system in January 2020, per your EPC agreement, and delivers it to you within three-and-a-half months of the binding contract. The safe harbor is satisfied.
  • The EPC contractor prepares 10% construction drawings and applies for a building permit, each at nominal cost, and holds your 7% payment while waiting for module prices to come down. The safe harbor is not satisfied.
  • The EPC contractor allocates its previously purchased inverters to your project, per your EPC agreement, holding them in its warehouse until May 2020 before delivering them to your site. The safe harbor is likely satisfied. Applying the look-through rule, the EPC contractor’s purchase of the inverters pursuant to a binding contract in 2019 (even if prior to the EPC agreement) will qualify the inverters for safe harbor purposes. The EPC contractor must take steps to identify and segregate the particular inverters within its warehouse.

Q: Can I sell safe-harbored equipment?
A: The buyer of your equipment (unless it is an affiliate) may not utilize the safe harbor unless you are selling the equipment together with the solar project. If, for example, your sale also includes a site lease and a PPA, the purchaser would receive the benefit of the safe harbor. In certain circumstances, you may also be able to become an affiliate of a project LLC by acquiring a membership interest of at least 20% and make an in-kind contribution of the safe-harbored equipment to the project LLC.           

Q: Can I satisfy the physical work test by building roads within my site?
A: Yes; however, the roads must be integral to the energy property. An access road would likely not be interpreted as integral to the property. However, roads used for purposes of operations and maintenance activity―within the area of the facility itself―are considered integral to the energy property.

Q: What constitutes work of a physical nature?
A: This is really open to the facts and circumstances interpretation. The IRS notice instructions referenced previously indicate some specific activities that do not qualify, but there is no quantification of how much of a qualifying activity must be done in order to satisfy the safe harbor requirement. Preliminary planning and site work do not count. But starting construction would, so you could satisfy the requirement with excavation for a foundation, drilling for moorings, pouring concrete, etc. The best bet would be to actually put up a section of panels.

Q: What is the continuing work requirement?
A: There is an additional safe harbor that says if your project is placed in service within four years of the end of the calendar year in which you started it you will have automatically met the continuous work requirement. If your project goes beyond that you will need to show facts and circumstances showing you were taking steps to continue working towards completing the project. For example, if the delay was due to a delay in getting interconnected, be prepared to show documentation that you were continuously working towards resolving that issue.

Unless there are changes to the current tax law, these same provisions will be in effect for each step of the phase-out through the end of 2023. If you have further questions, please contact a member of our renewable energy team

Please note that this Q&A, which may be considered advertising under the ethical rules of certain jurisdictions, is provided with the understanding that it does not constitute the rendering of legal advice or other professional advice by Klavens Law Group, P.C. or its attorneys. Please seek the services of a competent professional if you need legal or other professional assistance.

Article
ITC safe harbor frequently asked questions

Read this if you are a solar investor, developer, or installer.

With December well under way, thoughts turn to year-end and tax filing preparation. While we get many questions this time of year related to changes in the tax law and what taxpayers can do before the end of the year to minimize their tax burden, different this year is the impending phase-out of the Investment Tax Credit (ITC) and Residential Energy Credit (REC) from 30% to 26%. 

Last month, we gave some pointers on the safe harbor provision available for the Investment Tax Credit which would allow qualifying projects to still be eligible for the 30% credit after the end of the year. No such provision exists for the residential credit, however, and any project not complete by 12/31/19 (and completed in 2020) will receive the reduced 26% credit.

The phase-out was designed to coincide with the projected decline in solar costs, and would help smooth the transition to a market where solar competes directly with fossil fuels for energy production. Since then, we have seen component costs increase due to artificially inflated prices resulting from the tariffs imposed on imported goods. This results in a mismatch on the timing of the phase-out to the cost of the materials, a still immature market for solar, and a missed opportunity. Enter a new bill in the House of Representatives.

Growing Renewable Energy and Efficiency Now Act

On November 19, 2019 Chairman Thompson of the House Ways and Means Subcommittee released a discussion draft of a bill titled the Growing Renewable Energy and Efficiency Now (“GREEN”) Act. This draft bill is not ready for a vote yet, but does promote an extension and/or expansion of tax incentives for taxpayers investing in cleantech. With the GREEN Act, solar investors, installers, and other related businesses would benefit from:

  • Revival and extension of the Production Tax Credit (PTC) through 2024
  • Delay of the ITC and REC phaseout until 2024
  • Expansion of the ITC to include additional technologies, most notably energy storage
  • A provision allowing the taxpayer to receive the ITC or PTC as a refund in the year it is claimed for 15% reduction in the value of the credit

A delay in the phase-out would allow time for the costs of components to return to pre-tariff levels and help achieve the original intention of the phase-out. The expansion of the ITC to include energy storage would be a huge boon to that emerging market, and provide an additional incentive for consumers to install storage on an existing project―creating a more efficient energy grid. 

Currently, due to accelerated depreciation, many taxpayers are not able to take the ITC or PTC in the first year due to not having a tax to offset. Allowing for the option to treat the ITC or PTC as a tax payment (which can be refunded) instead of a credit (which can’t) would help investors realize their return much faster and free up capital to invest in other projects. 

Some of these provisions are fairly aggressive, and it is unlikely that they will all remain as they are now in any future passed legislation. However, it is promising to see the House of Representatives considering these types of extensions and expansions when it comes to clean energy incentives. As renewable energy is still a relatively new and rapidly changing marketplace, this is a prime time for renewable energy professionals to keep representatives informed of what they need to help the industry continue to grow. 

Stay tuned, and please contact Mark Vitello if you have any questions or need more information.
 

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The GREEN Act―a ray of hope for the solar carve out and the ITC?

Read this if you are a solar investor, developer, or installer.

The solar carve out of the Investment Tax Credit (ITC) has been a great incentive for taxpayers to invest in solar assets over the last several years. It established an increased 30% tax credit for solar assets placed in service, up from the normal 10%. 

Starting January 1, 2020, the solar carve out will begin to phase out and will return to 10% by January 1, 2024. 

With the first phase-out of the ITC set to drop the credit from 30% to 26% after December 31, 2019, many taxpayers are evaluating ways to make sure their project still qualifies for the 30% credit. The IRS has issued two safe harbor provisions (IRS Notice 2018-59) to allow for projects placed in service after December 31, 2019 and before January 1, 2024 to still qualify for the 30% credit, but timing is key and certain actions must be taken before midnight on December 31, 2019.

Safe harbor methods

The two safe harbor methods are the Physical Work Test and the Five Percent of Cost Test. If a project satisfies either of these tests it can still qualify for the 30% tax credit as long as it is completed and in service before January 1, 2024.

The Physical Work Test requires that the taxpayer performs, or has performed on their behalf, “work of a significant nature” on the project prior to December 31, 2019. This is a little open to interpretation, but generally involves physical construction of the asset, such as the installation of mounting equipment, rails, racking, inverters, or even the panels themselves. Purchasing of equipment generally held in inventory by either the taxpayer or the vendor does not qualify. However, if the equipment is customized or specially designed for the specific project, it might. Preliminary activities do not qualify, which include planning, designing, surveying, and permitting. 

In general, the purpose of this test is to prove that construction has already begun, and is in place to help projects that have been started but won’t be in service before year end still maintain the 30% tax credit. Projects that are substantially complete and waiting for an interconnection or a permission to operate in order to be considered as in service will most easily qualify for this safe harbor test.

The Five Percent of Cost Test is a little more straightforward, and is likely to be more commonly used to qualify projects for the safe harbor provision as the end of the year deadline approaches. This test requires at least five percent of the total project cost be paid or incurred before December 31, 2019. It is important to note that the denominator in this test is the final total cost of the project when it goes in service. The taxpayer may wish to pay more than the five percent to account for project overruns or unanticipated changes to the project in order to make sure they maintain the qualification for safe harbor. 

Another consideration is if the taxpayer files on the cash or accrual method as to whether the project cost needs to be paid or incurred in order to satisfy the chosen filing method.

In either case, the taxpayer should also evaluate the cost of prepaying for equipment that may decrease in cost in the future, compared to the benefit they will receive in maintaining the additional four percent of the tax credit that can safe harbor from the phase out. 

Additionally, an analysis of total project costs and eligible vs. ineligible ITC costs early on in project development can help identify how best to spend the cash before the end of the year, and ensure that the taxpayer receives the return they require once the project goes into service.

Have questions?

If you have questions on these safe harbors or need more information, please contact the green tax experts on our renewable energy team

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Safe harbor options for taxpayers as the solar ITC begins to sunset

Read this is you are a new renewable energy company looking for accounting solutions.

Setting up a new company in QuickBooks can be challenging enough, but if you are a renewable energy company there are a few additional items to think about. You face unique reporting and tracking requirements for a number of reasons, including tax reporting requirements, potential and existing investors, debt requirements, and grant requirements. Renewable energy companies should take special care in setting up their QuickBooks file. Below is a top 10 list of items to consider when setting up a new company file.

  1. Equity—Have you recorded your initial equity activity?
    Do you have individual capital accounts setup by owner?
    Did some owners contribute items other than cash? Expertise or property? Have you accounted for those properly?
  2. Debt—Do you have all debt financing recorded on the books?
    Debt financing needs to be recorded even if the bank pays some construction vendors directly as part of the agreement.
    Do you have an amortization or payment schedule to assist with recording loan payments properly?
    Does your debt have financial statement reporting requirements or covenant requirements that you must meet annually?
  3. Accounting Basis—Generally Accept Accounting Principles (GAAP) or Tax basis how will you keep your books?
    More and more companies are being required by banks and investors to keep their books on GAAP basis, you should consider future planned investors or financing from the get go as there are some clear distinctions between the two and it may be easier to start with GAAP from the beginning.
    GAAP and tax basis call for some pretty drastic distinctions when it comes to treatment of grant income if they directly relate to a project under development so it’s good to get a handle on this up front.
  4. Construction Costs—Are you capitalizing all construction costs related to your project?
    All costs related to your project must be capitalized on the balance sheet until the project is placed in service at which point you can begin depreciating the value of the project over a period of years.
    Generally, we recommend tracking site work in a separate account as tax and GAAP requirements can call for different treatment of these costs depending on their nature.
    Are you applying for any special grants related to your project? There are a number of federal and state grants available to renewable energy companies which may require breaking your project into cost categories to determine what costs qualify for the grant and what do not? Do you have a mechanism for tracking these costs?
  5. Soft costs―Are you properly capitalizing or expensing soft costs related to your project?  Engineering fees, project management fees and consulting fees if directly related to the project are generally included as part of the capitalized project costs rather than expensed.
    Legal and accounting fees. even if directly related to the project accounting or structuring your project, are generally expensed.
  6. Multiple projects―How are you keeping track of your multiple projects?
    With multiple projects underway at any given time, it is imperative to track these costs by project in QuickBooks and to work with vendors to specify on invoices to what projects costs are related. This is imperative to a lot of grant applications to be able to provide this sort of detail easily and on a consistent basis.
  7. Project details/Contracts details―How are you keeping track of all those details?
    More detail is always good.  In our experience the more detail you have in your files as to cost breakdowns of EPC contracts, etc. the better. Investors and grant evaluators are going to request all this detail and it’s better to have on file than track it down months or even years later.  Vendors are much more cooperative when requesting this documentation up front.
  8. Grant fine print―Have you read the fine print of the grants you’ve received?
    Pay close attention to these green energy grants fine print. Many of the grants have repayment requirements were the project taken out of service within a certain timeframe or have repayment requirements under other circumstances. These are items that may be required to be disclosed in financial statements and are just good business to be aware of.
  9. Organizational costs―Do you know what these are and are you tracking?
    Organization costs are legal, accounting and any other costs related to the actual formation and entity structuring of a company.  In our experience, these costs can be significant with the complex equity structures of many renewable energy companies. Make sure you are tracking these costs as amounts in excess of $5,000 are required to be amortized over 15 years for tax purposes.
  10. Project budgets and overall budgets―Do you have a realistic budget?
    Use QuickBooks budgeting features to track both project budgets as well as your Company’s overall budgets. Projects can go over budget quickly and it’s critical to keep on top of it to ensure the overall mission and sustainability of the company.

Once you have looked at these questions, you will be able to to create an effective budget and financials. If you have questions about your financial operations, QuickBooks, or setting up budgets, please contact the team. We’re here to help. 
 

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Top 10 QuickBooks considerations when setting up a new renewable energy company

Read this if you are a financial manager of an ESOP.

Employee Stock Ownership Plans (ESOPs) must generally buy back, or repurchase, participants’ shares when they leave the plan or want to diversify holdings. If the ESOP does not purchase the stock the company is required to purchase the shares from the participant under the “put option” described in Internal Revenue Code (IRS) Section 409(h).These rules require the company to either provide enough cash to the ESOP to fund stock repurchases, if adequate other assets are not available within the ESOP, or to fund the repurchase of shares outside of the ESOP. Anticipating the amount and timing of these repurchases requires a lot of number crunching and assumptions to arrive at an estimated “Repurchase Obligation” at a point in time. In most cases, ESOPs enlist the help of valuation specialists, actuaries, or outsider vendors to prepare a study.

All this is done as a component of ESOP cash flow planning but also begs the question, what do you need to record or disclose in your company’s financial statements related to this obligation?

The Financial Accounting Standards Board’s guidance on the subject is contained in Accounting Standards Codification (ASC) Topic 718, Compensation - Stock Compensation. More specifically, ASC Section 718-40-50 clearly outlines the terms, allocated share and fair value information, compensation and other related disclosure requirements for ESOPs in paragraphs 1a through g. One of these requirements—paragraph f—requires disclosure of “the existence and nature of any repurchase obligation...” While the existence of a potential repurchase obligation is undeniable due to the requirements of IRC Section 409(h), disclosure of the nature of the obligation may require judgement and a careful reread of the plan documents.

Existence of the obligation

What private companies record for redemptions is straightforward. They are required to accrue obligations related to redemption events initiated on or before the balance sheet date and disclose share and obligation balance information related to those transactions of material.

Disclosures must include the number of allocated shares and the fair value of those shares as of the balance sheet date. This sounds like a general disclosure of terms, but the intention is to communicate maximum repurchase obligation exposure. If redemptions subsequent to the balance sheet date require material and imminent use of cash, the company should consider whether it is required to disclose them as a subsequent event (including amounts) under ASC Topic 855, Subsequent Events.

Nature of the obligation

So, what do you need to disclose specific to the nature of your company’s ESOP shares repurchase obligation?

Put options against the ESOP trust (i.e., rights afforded under the ESOP requiring the trust to purchase outstanding stock at given prices within specific time horizons). Plan terms allowing redemption payments in excess of a certain threshold to be made over a defined period of time (e.g., retiring employees with vested balances greater than $5,000 may receive their payments in equal installments over a five-year period, while those with lower balances may receive their benefit in a lump sum).

If your company’s ownership has an ESOP component or you are considering an ESOP as part of your exit strategy, please reach out to Linda Roberts and Estera Ciparyte-McDonald. They can help you better understand the myriad considerations to be taken into account, and the required and potential financial statement impact and disclosures.

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ESOP repurchase obligations―Planning for future pay ups