Law360 has published our article How The New Tax Law Blue Book Impacts Regulated Utilities.  The article is available at here or the full text is below.

The recently released the Joint Committee on Taxation’s Blue Book explanation[1] of the Tax Cuts and Jobs Act[2] confirms that qualifying tangible property leased to a regulated public utility is eligible for the new 100 percent expensing rules, also called full expensing,[3] even if the property would not be eligible for full expensing if it were owned by the regulated utility.

As discussed below, there was some concern in the industry that an exception applicable to certain property used by a regulated utility, or the regulated utility exception,[4] might extend to an owner/lessor leasing to a regulated utility.  With the release of the Blue Book, we would expect there to be more lessors prepared to offer advantageous lease financing rates to regulated utilities, reflecting the lessor’s ability to claim full expensing. Continue Reading Blue Book Confirms Bonus Depreciation for Equipment Leased to Utilities

Here’s a presentation that Joseph Sebik, CPA of Siemens Financial Services and I gave to the Energy Subcommittee of the Equipment Leasing and Finance Association on January 22: Tax Equity Energy Subcommittee 1-22-19 of ELFA.

Despite being to a leasing trade association, the focus of the presentation is the partnership flip structure.  The presentation includes appendices on the phase down of tax credits for solar and the phase out of tax credits for wind; the “start of construction” rules; and hypothetical liquidation at book value (HLBV).

Below are answers to questions we received during our tax equity webinar of October 23.  These questions were submitted online during the webinar.  The presentation from the webinar is available here.

Question: Commercial and industrial (C&I) has higher returns but how many projects raise tax equity versus other segments of the solar market? What about the transnational/legal costs?

Answer: On a per watt basis, transaction costs are certainly higher for C&I than for utility scale or residential.  This is because C&I lacks the standardization of documentation that exists in residential.  For instance, no residential customer is able to negotiate customized PPA terms.  In contrast, C&I customers tend to be large enough and sophisticated enough to insist on bespoke documentation.  Then the project documents for each 200 kW C&I project have to be reviewed during the tax equity investor or lender’s due diligence process and, unfortunately, it takes as long to read and analyze the project documents for a 200 kW C&I project as it does a 200 MW utility scale project.  This dynamic makes the C&I diligence process expensive.  Nonetheless, C&I developers and their financiers have been finding it to be an attractive segment of the market that provides lucrative returns.

In terms of how many C&I projects are successfully financed, that is difficult question to answer due to a lack of publicly available data.  The difference in this respect between C&I and utility scale would appear to be that a utility scale project is unlikely to even reach notice to proceed (NTP) (i.e., the commencement of construction) without committed tax equity; in contrast, C&I projects are small enough that some developers will start building certain C&I projects without committed tax equity financing with the plan to raise it prior to the placed in service date; however, there is the occasional C&I project that the developer places in service without tax equity and then ends up retaining the tax benefits for its own account.  (One strategy when this happens is to execute a sale-leaseback within three-months of the original placed in service date as in such a transaction the lessor can claim the investment tax credit (ITC).)

Question: Can someone expand a bit more on the post-tax credit world. Do they see lenders stepping up to fill the gap left by tax equity? Going forward, will US renewables look more like the traditional project finance market that we see in other parts of the world?

Answer:  First for solar, there is no post-tax credit world on the horizon.  That is because even after 2023 solar has a ten percent investment tax credit.  When the solar investment tax credit declines to ten percent, it seems likely that tax equity financings will continue unless projects are so profitable (i.e., the pricing of PPAs is relatively high versus the cost of modules and construction) that the projects can efficiently use the investment tax credit and depreciation deductions themselves.  If that is not the case, project sponsors will continue to look for tax equity investors.  However, what may change is that tax equity investors may have less influence in the tri-party negotiations among sponsors, lenders and tax equity investors, as tax equity investors will be funding a smaller portion of the capital stack.  Therefore, we may see a decline in back-leverage in favor of senior-secured loans.

For wind projects that “start construction” after 2019, there will not be any tax credits, absent a legislative extension.  Once the tax credits for wind are over, it appears likely that wind financing will shift to a sale-leaseback model.  There are two reasons for this shift: the efficient monetization of deprecation and the limitation on interest deductions that was enacted in tax reform last year.

Sale-leasebacks are the most efficient structure to monetize depreciation as the lessor is provided all of the depreciation (not 99 percent); there is no capital account constraint; and there is no partnership that has a short first tax year and a resulting haircut in deprecation (other than 100 percent bonus deprecation that is all deductible in the first year regardless of a short year).  There will still be 100 percent bonus depreciation until 2023 with the “bonus” percentage ratcheting down from 2023 to 2027.  Further, even without tax credit or bonus depreciation, the five-year MACRS depreciation that a wind project normally qualifies for is relatively accelerated.  For instance, rolling stock and commercial aircraft only qualify for seven-year MACRS depreciation and each of those industries have a history of tax-motivated sale-leasebacks.

Second, tax reform resulted in the expansion of Section 163(j) of the Code to limit how much interest can be deducted by taxpayers.  The full effect of this new law are still phasing in, so much of the pain is yet to come.  A discussion of the impact of tax reform’s limitation on interest deductions is available in the following blog post: https://www.taxequitytimes.com/wp-content/uploads/sites/15/2018/03/2018-and-Onward-The-Impact-of-Tax-Reform-Energy-Law-Report-tax-reform.pdf (pages 95 to 96).  However, the limitation does not apply to “rent.”  Thus, project owners are likely to opt for sale-leasebacks as all of the rent will be deductible, while interest payments may not be, and the lessor should factor the depreciation deduction it is entitled into the calculation of the rent payment, so that the lessee (i.e., the sponsor) sees the benefit of the lessor’s depreciation benefit in the form of lower rent payments.   A discussion of sale-leasebacks as a planning technique with respect to the is available in the following blog post https://www.taxequitytimes.com/wp-content/uploads/sites/15/2018/02/TaxReform_Article-for-ELFA_02162018.pdf which includes diagrams.

 Question: What is BEAT?

 BEAT stands for “base erosion anti-abuse tax.”  It was enacted as part of tax reform in 2017.  It is still being phased in.  A discussion of the implications of BEAT for the renewable energy industry is available in the following blog post  https://www.taxequitytimes.com/wp-content/uploads/sites/15/2018/03/2018-and-Onward-The-Impact-of-Tax-Reform-Energy-Law-Report-tax-reform.pdf (pages 92 to 93).  BEAT is intended to insure that multi-national corporations pay a minimum level of income tax in the US. BEAT has caused a handful of tax equity investors to either exit the tax equity market or shift to a strategy of “originate to syndicate.”  Fortunately, that slack has been picked up by new entrants who are attracted to the high returns available in tax equity transactions and the fact it is considered a socially responsible investment.

Question: Regarding the graphs on the last slide, a panelist mentioned during the call that the primary financial statement earnings from solar tax equity investment in the first year or two and driven largely by the ITC. The panelist noted that solar makes sense for a public company to make a tax equity investment in, if the public company is investing in renewables over the next 3-5 years? Would it be possible to elaborate on that?

Answer:  For a tax equity investor, the financial statement benefit of a solar tax equity investment is recognized mostly in the first year with some in the second year.  Therefore, a public corporation investing in solar one time would have a nice benefit in the first year that would not be reoccurring in subsequent years.  This could lead the Wall Street analysts that follow the corporation’s stock to ask why that earnings benefit could not be repeated, and generally Wall Street analysts place less value on a one time increase in earnings than something like a new product or strategy that will lead to higher earnings for years to come.  This dynamic can be avoided if the corporation invests in solar tax equity every year (e.g., from 2018 to 2023); however, for projects placed in service after 2023, only a ten percent ITC will be available, unless, the 30 percent ITC is extended legislatively, so then there would be a decrease in the financial statement benefit that is available.  That decrease could be addressed by a public corporation in 2024 investing a smaller dollar amount for each watt of solar but investing in many more watts (i.e., projects); however, that may be a difficult strategy to sustain over the long term.

Question: Is there any interest in tax equity investing in section 45Q carbon capture credits?

Answer: Section 45Q was first enacted in 2008 and was most recently amended by the Bipartisan Budget Act of 2018, P.L. 115-123 (Feb. 9, 2018).  Section 45Q now provides for a tax credit for each metric ton of qualified carbon oxide (i) sequestered (i.e., captured) by the taxpayer and (ii) (a) disposed of in secure geological storage, (b) used as a tertiary injectant in qualified enhanced oil or natural gas recovery project and disposed of  in secure geological storage or (c) used in certain other ways specified in section 45Q(f)(5).  There are formulas for calculating how much the tax credit is, but it varies from $12.83 to $50 per metric ton of sequestered carbon oxide.  Previously, section 45Q was unappealing to tax equity investors because after the EPA and the IRS determined that credits had been earned for the 75 million metric tons of captured carbon oxide the credit ended, so tax equity investors could not tell how long the credit would be available.  Thus, the credit was previously enjoyed mostly by the major oil companies who engaged in credit eligible activities in the ordinary course of business.  The 2018 amendment removed the cap on the tons of eligible captured carbon dioxide, so that obstacle to tax equity investment has been eliminated.  However, we have seen some discussion of section 45Q by tax equity investors but are not aware of any transactions that have been executed.  That could be because it is a technology and process that is neither familiar to tax equity investors nor that attracts much media attention.  Further, there are so many solar projects in need of tax equity financing, that tax equity investors may have little motivation to take a risk on something new.  That said it could be a highly lucrative area for a tax equity investor willing to invest the time in learning about it.  The credit is available for twelve years with respect to carbon oxide sequestered by each carbon oxide sequestration facility in the United States that captures carbon oxide; provided, the construction of such facility must begin construction prior to 2024 and on or after February 9, 2018.  Accordingly, this could be an area that attracts more attention from tax equity investors in future years.

Question: You mentioned the possibility of utilities rate basing wind projects using PTC.  How does a utility sponsor avoid the requirement that electricity be  “sold by the taxpayer to an unrelated person during the taxable year,” requirement under Section 45(A)(2)(B)?

Answer: The IRS, in Notice 2008-60, has stated: “Electricity . . . will be treated as sold to an unrelated person . . . if the ultimate purchaser of the electricity . . . is not related to the person that produces the electricity . . . .  The requirement of a sale to an unrelated person will be treated as satisfied in these circumstances if the producers sells the electricity . . . to a related person for resale by the related person to a person that is not related to the producer.”  The guidance was issued specifically to address the situation where a utility that owns an interest in a wind farm purchases the electricity from the wind farm, which it then sells to its customers.

Question: Do you expect the IRS to issue favorable guidance allowing a non-utility lessor to claim bonus depreciation for property leased to a utility lessee?

Answer: We are hopeful that IRS will issue favorable guidance because Congress knew how to reference other depreciation rules that limit the acceleration of depreciation deductions for lessors leasing to certain types of lessees and Congress did not make any effort to do that. If Congress wanted to exclude property leased to a utility from bonus depreciation, one would have thought that it would have provided some statutory text addressing how the rules would work, which it did not.  For instance, how much use (i.e., renting) by a utility would have to result in ineligibility for bonus depreciation.  If Hertz purchases a new car and leases it for one day to a utility, is it ineligible for bonus depreciation?  What about one week? One month?  Since Congress did not draw these lines, it appears that Congress did not intend to exclude property leased to utilities from eligibility for bonus depreciation, and given the many variations of leasing arrangements it would require considerable drafting from whole cloth for the IRS and Treasury to attempt to write regulations that limit bonus depreciation for property leased to utilities.  This issue is discussed in the article available at https://www.taxequitytimes.com/wp-content/uploads/sites/15/2018/02/TaxReform_Article-for-ELFA_02162018.pdf in the text associated with notes nine and ten.

Question: If a developer purchases equipment with the intention of satisfying the five percent start of construction safe harbor, is the developer allowed to subsequently contribute some or all of that equipment to a subsidiary and preserve the safe harbor?

Answer: According to section 4.02 of IRS Notice 2013-60, a developer may purchase equipment under a master contract with the intention of satisfying the five percent  safe harbor, subsequently assign its rights to such equipment to affiliated special purpose vehicles, and still take the costs of such equipment into account in determining whether the five percent safe harbor has been satisfied.  According to section 4.03 of IRS Notice 2014-46, if a developer transfers solely equipment to an unrelated person, the costs of such equipment incurred by the developer may not be taken into account in determining whether the five percent safe harbor has been satisfied.

David Feldman and Paul Schwabe of the National Renewable Energy Laboratory (NREL) have published their annual solar PV financing report: Terms, Trends, and Insights on PV Project Finance in the United States, 2018.  I am pleased to have been invited to comment on a draft of the report and find the final version to be a valuable reference with respect to solar project finance in the United States.

One of the most interesting features of the report is a table that provides that tax equity investors’ total after-tax returns for large distributed PV portfolios are between 7.2 percent and 18.2 percent, while the total after-tax return for tax equity investors for utility-scale PV is between 7.2 percent and 9 percent.  Here’s a table from the report with those and other financing cost data points:

For anyone in working in solar project finance, the full report is worth reading and provides important insights.

We were pleased to participate in Power Finance & Risk’s (PFR) Tax Equity Roundtable.  We were joined in the roundtable discussion by Rich Dovere of C2 Energy Capital, Marshal Salant of Citi, Kathyrn Rasmussen of Capital Dynamics Clean Energy and Infrastructure, Pedro Almeida of EDP Renewables North America and as moderator PFR’s editor, Richard Metcalf.  The topics covered included tax equity structuring, tax reform, tax equity syndication and the challenges and opportunities associated with distributed generation solar.  We are pleased to be able to make available to our readers PFR’s report: PFR Tax Equity.

Mayer Brown’s David K. Burton and Jeffrey G. Davis both Tax Transactions & Consulting partners and part of the firm’s Renewable Energy group co-hosted a heavily attended webinar on how tax reform is impacting the tax equity market and certain renewable energy structures with Vadim Ovchinnikov, CFA, CPA and Gintaras Sadauskas of Alfa Energy Advisors. Topics addressed, included: The latest industry trends such as, the feds raising interest rates; the increase in project M&A activity for both development and operating assets; plans for large offshore wind projects in several east coast states; changes in PPA’s and revenue models; compressed margins and why developers and investors are moving towards commercial and industrial (C&I) solar projects. Additional topics, included:

  • New bonus depreciation rules and impact on tax equity transactions and modeling;
  • Compressed financing margins for wind and solar;
  • Strategies for “starting construction” to qualify for the maximum investment tax credit and rules for transferring safe harbored equipment between wind projects; and,
  • An overview of HLBV GAAP accounting for tax equity investments as a challenge for public companies.

Over 480 clients and contacts registered for the co-hosted webinar. Due to the volume of interest and post-presentation questions, we would like to share the slides from the presentation: webinar presentation.

We are reviewing and preparing responses to all of the questions that were submitted electronically during the webinar.  We will be sharing those questions with our answers in a subsequent blog post.

Please join Mayer Brown and Alfa Energy Advisors for a webinar.  The webinar will address how tax reform is impacting the tax equity market and certain structures in particular.  Additional topics include:

  • The latest industry trends
  • New bonus depreciation rules and their impact on tax equity transactions and modeling
  • Compressed financing margins for wind and solar
  • Strategies for “starting construction” to qualify for the maximum investment tax credit and rules for transferring safe harbored equipment between wind projects
  • An overview of HLBV GAAP accounting for tax equity investments as a challenge for public companies

Register Here >>

CLE credit is available.

Tuesday, October 23, 2018          

United States

1:30 p.m. – 3:30 p.m. EDT

12:30 p.m. – 2:30 p.m. CDT

11:30 a.m. – 1:30 p.m. MDT

10:30 a.m. – 12:30 p.m. PDT

Europe

8:30 p.m. – 10:30 p.m. CEST

7:30 p.m. – 9:30 p.m. BST

 

Many developers of renewable energy projects have experienced higher than expected transaction costs.  There can be a wide range of reasons for such overages.  One all-too-common reason is project documents that cause tax tensions.  These tax tensions lead to more lawyer time, which leads to higher transactions costs.  Thus, developers concerned about transaction costs should negotiate “tax-friendly” project documents to streamline the tax equity investor’s diligence process.

Project documents are typically presented by the developer to the tax equity investor’s counsel in executed form.  Counsel then reviews these to ensure consistency with the tax analysis of the transaction and for other issues.  When counsel identifies an apparent glitch, she typically tries to rationalize or mitigate it without requesting an amendment to the project document in question.  That analysis can take some time.  If she cannot find another solution, she will propose an amendment.  It takes time to prepare the amendment and often more time to persuade the applicable counter-party to sign it.  That request can then lead the counter-party to propose alternative language and a time-consuming (i.e., expensive) back and forth process.

Below is a list of tax issues for developers to keep in mind as they negotiate project documents.  The list is intended to provide trail markers for the most direct path for developers who would like to streamline the tax diligence process (and the associated costs) for their project documents. The list is not intended to be all-inclusive.  Further, the list is not to suggest that missing one or more of these is necessarily fatal to the tax analysis because (i) there are often multiple paths to reach the desired tax outcome and (ii) some of these are best practices, rather than fatal flaws.  Below is generally intended for wind or ground mounted solar projects, as roof-mounted solar is a somewhat different animal.

There are typically five “project documents” (i) the power purchase agreement  (“PPA”) or other revenue contract; (ii) the site lease or other right (which is sometimes combined with the power purchase agreement) to use the ground or roof on which the project is constructed; (iii) the interconnecting agreement that enables the project to transmit its power to the grid; (iv) the operations and maintenance agreement; and (v) the construction contract. Continue Reading Lower Transaction Costs with Tax-Friendly Project Documents

In a recent case, the Tax Court ruled in the taxpayer’s favor as to three California distributed generation solar projects’ eligibility for the energy credit under Section 48 and bonus depreciation under Section 168.  However, the Tax Court did reduce the taxpayer’s basis in the projects, and the taxpayer in the case enjoyed significant procedural advantages due to mistakes by the IRS.

In Golan v. Commissioner, T.C. Memo. 2018-76 (June 5, 2018), in late 2010 a solar contractor installed solar equipment on the roofs of three host properties and entered into power purchase agreements (“PPAs”) with the property owners.  The PPAs provided that the hosts would purchase electricity generated by the solar equipment at a discount to utility rates, while the solar contractor would retain the ownership of the equipment, including the right to any tax or other financial benefits, and would service and repair the equipment.

Mr. Golan, the taxpayer, in 2011 purchased the solar equipment, subject to the PPAs, from the solar contractor for a purported purchase price of $300,000, which was the sum of a purported $90,000 down payment, a $57,750 credit for certain rebates, and a $152,250 promissory note (which the taxpayer was the obligor under but the taxpayer also provided a personal guarantee thereof).  The solar projects were not connected to the grid until after the taxpayer acquired them in 2011.  The IRS unsuccessfully sought to disallow the taxpayer from taking energy credit and depreciation deduction with respect to the solar equipment. Continue Reading Tax Court Sustains Energy Credit and Bonus Depreciation for Distributed Generation Solar Projects

Below are soundbites from panelists at Infocast’s Solar Power Finance & Investment Summit from March 19th to 22nd in Carlsbad, CA.  It was an extremely well-attended event and the mood of the participants was generally upbeat.  Many people observed that there was more capital for projects under development or to buy operating portfolios than there was such supply of projects available to meet that demand.

The soundbites are edited for clarity and are organized by topic, rather than in chronological order.  They were prepared without the benefit of a transcript or recording.

Impact of Tax Reform on the Tax Equity Market

Impact of the Corporate Tax Rate Reduction on the Supply of Tax Equity, Yields and the Capital Stack

“This year we can do $9 million in tax credits; before we could do $15 million.”  [The implication is that a 21 percent federal corporate tax rate is 40 percent less than a 35 percent corporate tax rate, so the tax appetite has declined by 40 percent.]  Vice President, Industrial Bank

“The [supply side of the] tax equity market has declined by 40 percent; some tax equity investors are taking a pause.”  Vice President, Regional Bank

“Our bank this year is slightly below the billion dollars of tax equity it originated last year for its own book.” Vice President, Midwestern Bank

Some “mainstream tax equity investors have taken a pause [from investing] to figure out what the 21 percent corporate tax rate means for them.  It is an investors’ market, but we nervously see a sponsors’ market ahead.”  Managing Director, Financial Advisory Firm

Traditionally, rates for tax equity have been a function of supply and demand, but now we are seeing real pressure on rates.”  Managing Director, Money Center Bank

[It is difficult to jibe this banker’s quote regarding pressure on tax equity rates with the quotes above regarding the supply of the tax equity market being smaller due to tax reform.  Possibly, tax equity investors are agreeing to share some of the yield detriment of the depreciation being less valuable and that has resulted in reduced after-tax yields.]

“Some utilities that had tax appetite no longer have tax appetite and need to raise tax equity for their projects.”  Director, Money Center Bank

“We are trying to get back to the same all-in return where we were before tax reform.”  [As the depreciation is less valuable at a 21 percent tax rate than it was at a 35 percent tax rate, this means either (i) contributing less for the same 99 percent allocation of the investment tax credit or (ii) contributing the same amount and requiring a distribution of a larger share of the cash.]  Vice President, Midwestern Bank

“Tax reform helped us because it means tax equity contributes less to the project, so it makes our loan product more necessary.” General Manager Renewable Energy Finance, Small Business Bank

“The debt market has come in and is filling the decline in tax equity.” Executive Director, Manufacturing Corporation

“The buyouts of [tax equity investors’ post-flip interests] are more valuable because of the lower tax rate.”  Partner, Big 4 Firm

“We see sponsors’ financial returns over a 35-year project life increase due to the tax rate reduction.”  ” Managing Director, Structuring Advisory Firm Continue Reading Infocast’s 2018 Solar Power Finance & Investment Summit Soundbites