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).

I am pleased to announce that I will be speaking in an upcoming Strafford live webinar, “Tax Reform and Renewable Energy: Planning Techniques, 100% Expensing, BEAT, Tax Credits and Interest Deduction Limitations” scheduled for Wednesday, January 16, 1:00 pm-2:30 pm Eastern.

As a reader of this blog, you are eligible to attend this program at half off. As long as you use the links below.

Our panel will review the application and impact of tax reform on the renewable energy sector. The panel will discuss new tax law changes impacting renewable energy and provide planning strategies to optimize tax benefits, credits, deductions and avoid pitfalls.

After our presentations, we will engage in a live question and answer session with participants so we can answer your questions about these important issues directly.

I hope you’ll join us.

For more information or to register >

Or call 1-800-926-7926
Ask for Tax Reform and Renewable Energy on 1/16/2019
Mention code: ZDFCA

Below are soundbites from panel discussions at Solar Power International on September 25 and 26 in Anaheim, California. Overall the conference was well-attended and the panelists and audience seemed optimistic regarding current and future opportunities.

The soundbites are organized by topic, rather than presented chronologically.  The soundbites were prepared without the benefit of a recording or a transcript and have been edited for clarity.

Topics covered include tax equity, the solar start of construction rules, the investment tax credit (“ITC”) and tax basis risk after the Federal Circuit’s opinion in Alta Wind, the inverted lease structure, back-leverage debt, storage, community solar and merchant projects.

Macroeconomic Factors for Solar and Tax Equity

“Rising corporate profits have caused more tax equity to enter the market.  That has shifted the negotiating leverage to the sponsors.”  Managing Director, Money Center Bank

“Tax equity always needs to fund around 40 percent of the capital stack in order to use the tax benefits efficiently.”  Managing Director, Money Center Bank “Equipment costs continue to come down.  Module prices are back to where they were before the tariffs at 30 to 40 cents a Watt.”  President, Diversified Solar Services Company

“There are greater economies of scale for utility scale solar than for residential or C&I.  As module prices drop faster than that customer acquisition costs, utility scale will become a larger portion of the market.”  President, Diversified Solar Services Company

“I am very bullish on next year.  This has been the best year ever from a volume perspective, not from an income perspective, because the market is causing us to charge less.”  Managing Director, Regional Bank

“Falling electricity prices aren’t leading to sponsors raising less capital, because sponsors have been beating down lenders and service providers.”  Managing Director, Regional Bank

“Capital providers are taking more risk for less return.”  Managing Director, Regional Bank

“Residential solar debt has become an accepted asset class.” Managing Director, Regional Bank

“Soft costs, such as marketing, legal, accounting and tax advice, are five to seven percent of a solar project’s cost in Europe and Asia; they are 35 percent of solar project’s cost here; we need to attack that.”  President, Solar Developer Continue Reading Solar Power International 2018: Soundbites

Below are questions submitted by the audience during our webinar Window of Opportunity: The IRS Issues Initial Guidance on Qualified Opportunity Zone Rules.  The webinar was on November 2, 2018.  Here’s the presentation from the webinar and our whitepaper on the new regulations.

  1. If I am a partner of a partnership and want to use the gain on an individual transaction by the partnership in 2018, what information must I receive from the partnership and do I have until the end of June 2019 for my investment?

You are right, if you are going to elect to defer gain at the partner level, the 180-day period does not begin until the last day of the partnership taxable year in which the realization event occurred—which is the date on which the partner “recognizes” its allocable share of the gain absent a partnership-level election to defer.  Given that (i) the gain occurred in 2018; and (ii) if the last day of the partnership taxable year is on December 31, 2018, you would have until the end of June 2019 to make the investment into a QOF.

As an alternative, you may elect to treat your own 180-day period as being the same as the partnership’s 180-day period (thus, it would begin on the date of the realization event in 2018).  The regulations are silent as to what information the partner willing to make such an election must obtain from the partnership, but presumably you would want documentation that provides assurance as to the amount of the gain and that the partnership will characterize the gain as “capital” (as opposed to “ordinary”) on your K-1. Continue Reading Questions and Answers from our Webinar Window of Opportunity: The IRS Issues Initial Guidance on Qualified Opportunity Zone Rules

In September, the State of Hawaii Department of Taxation issued a letter ruling (Hawaii Letter Ruling No. 2018-01) that clarified the “placed in service” requirement in the application of the Renewable Energy Technologies Income Tax Credit (“RETITC”) in Hawaii.  A project was denied RETITC in the year when testing was conducted because the project had not obtained all legal permits and did not satisfy certain legal requirement.

Taxpayer contracted with an installer to build a commercial solar system.  The system was turned on for testing in 2017.  The testing was successful except that Taxpayer had not installed a fence around outdoor electrical property as required by the building and electrical codes.  The inspector refused to sign off and advised Taxpayer to build the fence.  The fence was installed in January 2018.

In Hawaii, RETITC is issued to renewable energy systems that are “installed and placed in service” during the taxable year.[i]  A system must be “ready and available for its specific use” to be considered properly “installed and placed in service.”[ii]  Citing the U.S. Tax Court’s decision on federal investment tax credits,[iii] the ruling provides that use of the system during construction generally does not satisfy the placed-in-service requirement.  The ruling provides that typically the government’s approval to operate a system indicates that the system has been placed in service.  When either facts are not clear or the taxpayer does not have all information regarding the permitting process, the Department will analyze five factors: 1) whether the necessary permits and licenses for operation have been obtained; 2) whether critical preoperational testing has been completed; 3) whether the taxpayer has control of the facility; 4) whether the unit has been synchronized with the transmission grid; and 5) whether daily or regular operation has begun.  None of the factors is dispositive.

The ruling provides that except for the fourth factor, which does not apply to Taxpayer’s system, only the second factor supports a granting of RETITC to Taxpayer’s system in 2017.  The first factor indicates that the system must be compliant with all applicable laws.  As Taxpayer’s system did not have a fence as required, this factor was only satisfied in 2018.  Taxpayer had physical control of the system after construction was completed in 2017, but the indicia of physical and legal control were enhanced in 2018 with the installation of fencing and the approval of all required permits.  Taxpayer could not establish a time when regular operation of the system started.  The ruling provides that regular operation could not legally had begun before all necessary permits were obtained.  Therefore, the system could not have commenced operation before 2018.  The ruling concludes that the second factor was outweighed by the other factors and, therefore, the system was placed in service in 2018.

The “specific use” standard provided in the Hawaii Administrative Rules and the five-factor test provided in the ruling are analogous to the standard and test the U.S. Treasury and the IRS adopted with respect to federal investment tax credits.[iv]  In the Department’s ruling, obtaining governmental approval and permits on time is critical.  Although the testing for the system was conducted in 2017 and the system was transferred to Taxpayer’s control in 2017, the Department refused to allow the RETITC with respect to the system until it satisfied the fencing requirement in 2018.

[i] Haw. Rev. Stat. § 235-12.5(a).

[ii] Haw. Admin. Rules § 18-235-12.5-01(a)(3).

[iii] See Noell v. Comm’r, 66 T.C. 718, 729 (1976).

[iv] See Treas. Reg. §§ 1.46-3(d)(1)(ii), 1.167(a)-11(e)(1)(i); see Sealy Power, Ltd. v. Comm’r, 46 F.3d 382, 395 (5th Cir. 1995), nonacq. 1996-1 C.B. 6 and A.O.D., 1995-10 (Aug. 7, 1995); Consumers Power v. Comm’r, 89 T.C. 710, 725-26 (1987); Oglethorpe Power Corp. v. Comm’r, 60 T.C.M. 850, 860 (1990).

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.

In 2017, Maryland, with Governor Larry Hogan’s (R) support, became the first state in the country to launch a tax credit program for energy storage systems.  In September, 2018, Maryland Energy Administration adopted new regulations that clarified certain qualifications of eligible systems and established procedures for individuals and businesses to apply for tax credits.

The program will grant tax credits to taxpayers that install energy storage systems between January 1, 2018 and December 31, 2022.  The amount of tax credits granted from this program will not exceed 30 percent of the total installed costs of the energy storage system.  The amount of tax credits granted for a system installed on residential property is further capped at $5,000.  The cap amount of a system installed on commercial property is $75,000.  The tax credits will be granted on a first-come, first-served basis and are subject to a maximum limit of $750,000 each year.  Unused credits from this program cannot be carried forward or backward to offset taxpayers’ tax liability in another taxable year.  Please click here to read more on the original Senate Bill and our observations about the incentive tax credit program.

The regulations clarified that an energy storage system is a system that stores electrical, mechanical, chemical or thermal energy for use as electricity at a later date or to offset electricity use at peak times.[i]

The regulations set forth certain safety and operational requirements for qualifying systems.  Qualifying systems must use equipment certified by a nationally recognized testing laboratory and must be installed in Maryland.[ii]  If the system is an electric system, it must also be installed by a licensed electrician, be in compliance with all applicable building and fire codes and, if applicable, be compliant with Maryland regulations regarding interconnection with the electric utility grid.[iii]

Qualifications for these systems may be adjusted by the Administration across program years.[iv]

Both individual and business taxpayers can participate in this program.[v]  Businesses must be formed as associations or joint-stock companies to be eligible.[vi]  Taxpayers must provide information requested by the Administration in the application process.  The Administration has the sole discretion in determining what information to request.  Taxpayers may be asked to provide their names, addresses and contact information or those of their representatives, estimated gross income or revenue, estimated tax liabilities, physical addresses of the property, proof of ownership of the property, description of the proposed energy storage systems, explanation of how the proposed systems offset electricity when discharging, information on the developers or installers, whether the proposed systems will participate in wholesale energy markets, estimated costs of the proposed systems, expected life of the proposed systems, anticipated in-service dates of the proposed systems, anticipated capacity factor of the proposed systems, energy storage duration, the amount of energy that can be stored in the proposed systems, the rate of energy flux per unit of area of the proposed systems,  documentation verifying that the proposed systems are in service, among other information.[vii]

Taxpayers that have already claimed a tax credit in this program are not eligible for additional tax credits from this program for the same taxable year.[viii]  Addresses, including multifamily properties, where tax credits were already claimed in this program are ineligible for additional tax credits from this program in all taxable years.[ix]  Electric vehicles are ineligible for this program.[x]

[i] Md. Regs. Code § 14.26.07.04(A).

[ii] Md. Regs. Code § 14.26.07.04(B), (C).

[iii] Id.

[iv] Md. Regs. Code § 14.26.07.04(D).

[v] See Md. Regs. Code § 14.26.07.01.

[vi] Md. Regs. Code § 14.26.07.03(B)(4); Md. Code Ann., Tax-General § 10-101(c).

[vii] Md. Regs. Code § 14.26.07.07(A).

[viii] Md. Regs. Code § 14.26.07.05(B).

[ix] Md. Regs. Code § 14.26.07.05(C).

[x] Md. Regs. Code § 14.26.07.05(D).

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.