Tag: tax credit

Renewable Energy Tax Credit Transfer Guidance Provides Both Clarity And Pitfalls

Highlights

The renewable tax credit transfer market will accelerate with new government guidance; public hearing and comments deadlines are scheduled for August

Risk allocation puts the usual premium on sponsors with a balance sheet and/or recapture insurance coverage

While the guidelines provide clear rules and examples, many foot faults are present

On June 14, 2023, the Treasury Department and Internal Revenue Service issued long-awaited guidance on the transferability of certain renewable energy-related federal tax credits. The guidance takes the form of a notice of proposed rulemaking, proposed regulations, and an online Q&A, with a public hearing to follow in August.

Under new Code Section 6418, eligible taxpayers can elect to transfer all or any specified portion of eligible tax credits to one or more unrelated buyers for cash consideration. While the tax credits can be sold to more than one buyer, subsequent transfers by the buyer are prohibited.

This alert highlights several practical issues raised by the guidance, which should allow participants waiting for more clarity to proceed.

Individual Buyers Left Out

  • The guidance applies the Code Section 49 at risk rules and Section 50(b) tax-exempt use rules, generally restricting sellers in calculating the amount of tax credits for sale, and Code Section 469 passive activity rules, generally restricting buyer’s use of such tax credits, in various contexts. On the buyer side, these rules appear to be more restrictive than the limitations that would apply to identical tax credits in an allocation, rather than sale, context. Suffice to say, this will prohibit individuals from taking part in the transfer market for practical purposes outside of fact patterns of very limited application.
  • While this result may not be surprising since such rules currently severely restrict individuals from participating in traditional federal tax credit equity structures, there was some hope for a different outcome due to the stated policy goal of increasing renewable energy investment (not to mention the Inflation Reduction Act’s general departure from decades of case law precedent and IRS enforcement action prohibiting sales of federal tax credits with the enactment of Section 6418).

Lessees Cannot Sell the Tax Credits

  • A lessee cannot transfer the credit. With the prevalence of the master lease (inverted lease) structure in tax equity transactions, this prohibition created an unexpected roadblock for deal participants who have been structuring tax equity transactions with backstop type sale provisions for almost a year now. This presents developers, at least in the inverted lease context, with a choice of utilizing a traditional tax equity structure for the purpose of obtaining a tax-free step up in basis to fair market value, or forgoing the step up for less financing but also less structure complexity. The standard partnership flip project sale into a tax equity type of holding company structure could still remain a viable alternative.
  • As the transfer is generally made on a property-by-property basis by election, creative structuring, in theory, could allow for a lessor to retain certain property and sell the related tax credits (e.g., on portfolios with more than one solar installation/project, or even with large projects that go online on a block-by-block basis assuming the “energy project” election is not made – a term that future guidance will need to provide more clarity on).
  • However, this seems to be an ivory tower conclusion currently, and the practical reality is that too many unknown issues could be raised by such out of the box structuring, including the fact that conservative institutional investors may refuse to participate in such a structure until clear objective guidance is published addressing the same.

Bonus Credits Cannot Be Sold Separately

  • Bonus credits cannot be sold separately from the underlying base credit. This is more problematic for certain adders – for example, the energy community adder rules are now out and amount to simply checking a location on a website. Others (e.g., the low-income community or domestic content adder) require more extensive and subjective application and qualification procedures which makes when and how such adders can be transferred difficult to ascertain. Projects hoping to transfer such credits may need to be creative in compensating buyers for such uncertainty and qualification risk. Tax equity transactions that closed prior to the guidance’s issuance may also need to be revisited, as provisions in such transaction documents commonly attempted to bifurcate the bonus credit away from the base credit in order to allow the sponsor to separately sell such adders.

Buyers Bear Recapture Risk and Due Diligence Emphasis

  • While the Joint Committee on Taxation Bluebook indicated the buyer is responsible for recapture, industry participants were still hoping such risk would remain with the seller. Outside of the limited situation of indirect partnership dispositions (which still results in a recapture event to the transferring partner if triggered), the recapture risk is borne by the buyer, using the rationale that the buyer is the “taxpayer” for purposes of the transferred tax credits. While this is familiar territory for tax equity investors, whose allocated tax credits would be reduced in a recapture scenario, tax credit purchase transactions are now burdened with what amounts to the standard tax equity type of due diligence, including negotiation of transaction documents outside of a basic purchase agreement.
  • The guidance provides that indemnity protections between the seller and buyer are permitted. Tax equity transactions historically have had robust indemnification provisions, which should remain the case even more so in purchase/sale transactions. Tax equity investors traditionally bear “structure risk” dealing with whether the investor is a partner for tax purposes – such risk is eliminated in the purchase scenario as the purchasing investor no longer needs to be a partner (subject to the caveat of a buyer partnership discussed below).
  • If the buyer claims a larger credit amount than the seller could have, such “excessive credit transfer” will subject the buyer to a 20 percent penalty on the excess amount (in addition to the regular tax owed). All buyers are aggregated and treated as one for this purpose – if the seller retains any tax credits, the disallowance is first applied to the seller’s retained tax credits. A facts and circumstances reasonable cause exception to avoid this penalty is provided, further emphasizing the need for robust due diligence.
  • Specific non-exclusive examples that may demonstrate reasonable cause include reviewing the seller’s records with respect to determining the tax credit amount, and reasonable reliance on third-party expert reports and representations from the seller. While not unique to this new tax credit transfer regime, the subjective and circular nature of such a standard is complex – for example, when is it not “reasonable” for buyers or other professionals to rely on other board certified and licensed professionals, such as an appraiser or independent engineer with specialized knowledge?
  • Buyers thus need to remain vigilant about potential recapture causing events. For example, tax equity investors will not generally allow project level debt on investment tax credit transactions without some sort of lender forbearance agreement that provides that the lender will not cause a tax credit recapture event (such as foreclosing and taking direct ownership of the project). Buyers remain responsible for such a direct project level recapture event, which again aligns the tax credit transfer regime with tax equity due diligence and third-party negotiation requirements. The guidance is more lenient for the common back-leverage debt scenario.
  • While similar interparty agreements between back leverage lenders and the tax equity investor are required for non-project level debt facilities to address tax credit recapture among other issues, the guidance provides that a partner disposing of its indirect interest in the project (e.g., the lender foreclosing and taking ownership of a partner’s partnership interest) will remain subject to the recapture liability rather than the buyer provided that other tax-exempt use rules are not otherwise implicated. However, the need to negotiate such lender related agreements is still implicated as not all recapture risk in even this scenario was eliminated to the buyer.
  • While the recapture risk could place a premium on production tax credit deals (that are technically not subject to recapture or subjective basis risk), the burdensome process of needing to buy such tax credits on a yearly basis in line with sales of output may make such transactions more tedious.
  • The insurance industry already has products in place to alleviate buyer concerns, but this is just another transaction cost in what may be a tight pricing market. Not unlike tax equity transactions, sponsor sellers with a balance sheet to backstop indemnities may be able to demand a pricing premium; other sponsors may need to compensate buyers with lower credit pricing to reward such risk and or/to allow the purchase of recapture insurance. While this seems logical, the guidance also includes anti-abuse type rules whereby low credit pricing could be questioned in terms of whether some sort of impermissible transfer by way of other than cash occurred (e.g., a barter for some sort of other service). What the IRS subjectively views as “below market” pricing could trigger some sort of audit review based on this factor alone which further stresses the importance of appropriate due diligence.

Partnerships and Syndications

  • The guidance provides very clear rules with helpful examples, which should allow partnership sellers and buyers to proceed with very objective parameters. For example, the rules allow a partnership seller to specify which partner’s otherwise allocable share of tax credits is being sold and how to then allocate the tax-exempt income generated. The cash generated from sales can be used or distributed however the partnership chooses.
  • Similar objective rules and examples are provided for a buyer partnership. Subsequent direct and indirect allocations of a purchased tax credit do not violate the one-time transfer prohibition. Purchased tax credits are treated as “extraordinary items” that must be allocated among the partners of the buyer partnership as of the time of the transfer, which is generally deemed to occur on the first date a cash payment is made. Thus, all partners need to be in the partnership on such date to avoid an issue. Purchased tax credits are then allocated to the partners in accordance with their share of the nondeductible expenditures used to fund the purchase price.
  • What level of end-user comfort is needed in such a syndicated buyer partnership is an open question. While the rules provide objective guidelines in terms of when and how such purchased credits are allocated, subjective questions that are present in (and focused on) traditional tax equity partnerships are implicated. For example, could a syndication partnership set up for the business purpose of what amounts to selling the tax credits somehow run afoul of the subjective business purpose and disguised sale rules in tax credit case precedent, such as the Virginia Historic Tax Credit Fund state tax credit line of precedent? Will the market require a robust tax opinion in such scenario, thereby driving up transaction costs?
  • An example in the proposed regulations speaks to this sort of partnership formed for the specific purpose of buying tax credits, but leaves out of the fact pattern a syndicator partner. The example itself should go a long way towards blessing such arrangements, but the IRS taking a contrary position when dealing with such issues would not be a new situation. For example, the IRS challenged allocations of federal historic tax credits as prohibited sales of federal tax credits to the point of freezing the entire tax equity market with its positions in Historic Boardwalk Hall, which was only rectified with the release of a subsequent safe harbor revenue procedure.
  • Moreover, the guidance provides that tax credit brokers are allowed to participate in the market so long as the tax credits are not transferred to such brokers as an initial first step in the transfer process (as the subsequent transfer to an end user would violate the one-time transfer rule). Specifically, at no point can the federal “income tax ownership” be transferred to a broker. It is an open question if further distinction will be made at where this ownership line should be drawn. For example, can a third party enter into a purchase agreement with a seller and then transfer such rights prior to the transfer election being made? Does it matter under such analysis if 1) purchase price installments have been paid (which implicates rules in the buyer partnership context as noted above) and/or 2) the tax credit generating eligible property has been placed in service (which is when the investment tax credit vests for an allocated tax credit analysis; a production tax credit generally arises as electricity or the applicable source is sold)?
  • Indirectly implicated is what effect the new transfer rules will have on established case law precedent and IRS enforcement action in traditional tax equity structures. The Inflation Reduction Act and guidance dances around certain of these issues by creating a fiction where the buyer is treated as the “taxpayer” – this avoids the issue of turning a federal tax credit into “property” that can be sold similar to a certificated state tax credit. This also provides a more logical explanation as to why the buyer of these federal tax credits does not need to report any price discount as income when utilized, unlike the well-established federal tax treatment of certificated state tax credits that provides the exact opposite (e.g., a buyer of a certificated state tax credit at $0.90 has to report $0.10 of income on use of such tax credit).

Other Administrative and Foot-Fault Issues

  • The purchase price can only be paid in cash during the period commencing with the beginning of the seller’s tax year during which the applicable tax credit is generated and ending on the due date for filing the seller’s tax return with extensions. Thus, such period could be as long as 21.5 months or more (e.g., a calendar year partnership seller extending its return to Sept. 15). Tax equity transactions generally have pricing timing adjusters for failure to meet placement in service deadlines. Such mechanism will not work if advanced payments were made and then the project’s projected placement in service year changes. Tax credit purchase agreements executed prior to the June 14 guidance may require amendments or complete unwinds to line up with the rules to avoid foot faults (e.g., purchase agreements executed in 2022 where a portion of the purchase price was paid in 2022 for anticipated 2023 tax credits would not fall within the “paid in cash” safe harbor period). Advanced commitments, so long as cash is not transferred outside of the period outlined above, are permitted.
  • The typical solar equity contribution schedule of 20 percent at a project’s mechanical completion makes purchase price schedules approximating the same a reasonable adjustment for most investment tax credit energy deals in terms of the timing of financing. In addition, the advance commitment blessing of the guidance will give lender parties the comfort necessary similar to having executed tax equity documents in place. Thus, typical project construction financing mechanisms should be similar in the tax equity versus purchase agreement scenario, with projects that allow for a more delayed funding mechanism possibly obtaining a tax credit pricing premium. Production tax credit deals, for which tax credits can only be paid for on a yearly basis within the cash paid safe harbor timing window, may have more significant project financing hurdles without further tax credit transfer rule modifications.
  • Sellers can only make the transfer election on an original return, which includes extensions. Buyers, by contrast, may claim the purchased tax credit on an amended return.
  • Buyers need to be aware that usage of the purchased tax credits is tied to the tax year of the seller. For example, a fiscal year seller could cause the tax credits to be available a year later than an uninformed buyer anticipated, regardless of when the tax credit was generated using a traditional placement in service analysis. For example, a solar project placed in service during November 2023 by an August fiscal year seller would generate credits first able to be used in a calendar year buyer’s 2024, instead of 2023, tax year. A buyer can use the tax credits it intends to purchase against its estimated tax liability.
  • The pre-registration requirements, which are expansive and open-ended, are also tied to the taxable year the tax credits are generated and generally must be made on a property-by-property basis. For example, 50 rooftop installations could require 50 separate registration numbers outside of the “energy project” election. When such registration information needs updated is also not entirely clear – for example, a project is often sold into a tax equity partnership syndication structure on or before mechanical completion. Needing to update registration information could delay transactions and implicates unknown audit risk.

While these rules provide much-needed clarity, failure to adhere may be catastrophic and will require sellers and buyers to put proper administrative procedures in place to avoid foot faults. The new transfer regime will expand the market to new buyers who may have viewed tax equity as either too complex or had other reasons to avoid these transactions, such as the accounting treatment of energy tax credit structures. However, it would be prudent for such buyers to approach such transactions with eyes wide open.

© 2023 BARNES & THORNBURG LLP

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Renewable Energy Tax Credits under the Inflation Reduction Act: Opportunities for Exempt Organizations

The Inflation Reduction Act of 2022 (the “IRA” or “Act”) added and modified several renewable energy tax provisions under the Internal Revenue Code of 1986, as amended (the “IRC”).[1] These changes provide many opportunities for exempt organizations, investors, and developers in clean energy projects to lower their costs by monetizing previously unavailable tax credits and thereby increase their business. Among them:

  • Solar facilities are now eligible for the Section 45 Production Tax Credit
  • An Investment Tax Credit for stand-alone energy storage technology with a minimum capacity of 5 kWh
  • A new two-tier credit system consisting of a base credit and an additional bonus credit for eligible projects that satisfy new prevailing wage and apprenticeship requirements
  • New “domestic content,” “energy community,” and “low-income community” bonus credits
  • New “technology neutral” tax credits
  • New ways to monetize tax credits

There has been significant interest in the energy credits by tax exempt organizations, in particular by universities and hospitals. Indeed, these organizations have been looking to minimize their greenhouse gas impact or carbon footprint with the goal of achieving clean energy even prior to the enactment of the IRA. The direct pay option which is now available under the IRA has accelerated the interest in clean energy. Commentators also note that private foundations have been interested in addressing climate change and taking advantage of these newly enacted credits to help spread the use of clean technologies.

Section 6417, discussed below, could be a “game changer” in this regard. Even though certain of the credits have been in existence, unless tax exempts have had a significant amount of unrelated business income tax (“UBIT”), they previously could not avail themselves of the credits prior to the enactment of Section 6417 which provides the direct payment alternative.

The below will outline the new and modified renewable energy tax credits under the IRA, and summarize recent guidance issued by the Treasury Department.

CHANGES TO EXISTING TAX CREDITS

Section 45 Production Tax Credit

Before the enactment of the IRA, the Section 45 Production Tax Credit (“PTC”) was available to electricity produced from certain renewable resources, including wind, biomass, geothermal, hydropower, municipal solid waste, and marine and hydrokinetic energy. Under the Act, solar facilities and are now also eligible for the PTC. In order to qualify for the PTC, eligible facilities must be placed in service and start construction before the end of 2024. Facilities which begin construction after December 31, 2024, will fall under the new technology-neutral tax credit regimes (discussed below).

Section 48 Investment Tax Credit[2]

Prior to the Act, the Section 48 Investment Tax Credit (“ITC”) was not available to stand-alone energy storage projects. The IRA created an ITC for stand-alone energy storage technology with a minimum capacity of 5 kWh. The term “energy storage technology” includes any technology that receives, stores, and delivers energy for conversion to electricity, or to most technology that thermally stores energy.

Like the PTC, under the Act, eligible facilities can qualify for the ITC as long as they are placed in service and begin construction before the end of 2024. Facilities which begin construction after December 31, 2024, will fall under the new technology-neutral tax credit regimes (discussed below).

STRUCTURAL CHANGES TO THE TAX CREDIT SYSTEM

The IRA created a new two-tier credit system consisting of a base credit and an additional bonus credit that is only available for eligible projects that satisfy the new prevailing wage and apprenticeship requirements (discussed below). The new ITC base rate will be 6 percent, and the bonus rate will increase it to 30 percent. The new PTC base rate will be 0.3 cents/kwh and the bonus rate will increase it to 1.5 cents/kwh.

Prevailing Wage Requirement

Taxpayers must pay laborers, mechanics, contractors, and subcontractors a prevailing wage during the construction of the project and with respect to subsequent alterations or repairs of the project following its placement in service. The prevailing wage is based on the pay rates published by the Department of Labor (“DOL”) for the geographic areas and type of job or labor classification. If relevant pay rates are not published, the taxpayer must request a wage determination or wage rate from the DOL.[3]

Apprenticeship Requirement

Taxpayers must also ensure that, with respect to the construction of a qualified facility, no fewer than the “applicable percentage” of total labor hours are performed by qualified apprentices. The “applicable percentage” is: (i) 10 percent for projects beginning construction before 2023, (ii) 12.5 percent for projects beginning construction during 2023, and (iii) 15 percent for projects beginning construction thereafter. Each contractor and subcontractor who employs four or more individuals to perform construction on an applicable project must employ at least one qualified apprentice. A “qualified apprentice” is an individual who is employed by the taxpayer or any contractor or subcontractor and who is participating in a registered apprenticeship program.

If a taxpayer fails to satisfy the apprenticeship requirement during a particular year, the taxpayer may correct the failure by paying a penalty to the IRS equal to $50 ($500 if the apprenticeship requirement was intentionally disregarded) multiplied by the total number of labor hours that did not satisfy the apprenticeship requirement. However, the IRA also includes a “good faith effort” exception if the taxpayer requests qualified apprenticeships from a registered apprenticeship program and either the request is denied, or the program fails to respond within five business days after receiving the request.

ADDITIONAL BONUS CREDITS

The IRA established the “domestic content,” “energy community,” and “low-income community” bonus credits.

Domestic Content

Projects qualifying for certain PTC and ITC credits could qualify for a 10 percent increase to the base and bonus credits if they satisfy the IRA’s new “domestic content” requirements. To qualify for this bonus credit, all steel, iron, and manufactured products that are components of the completed facility are to be produced in the United States.

Energy Community

Facilities located in an “energy community” will also qualify for a 10 percent increase to the base and bonus credits. An “energy community” includes brownfield sites, certain areas with significant employment related to, or local tax revenues generated by, coal, oil, or natural gas, and where there is high unemployment, or a census tract where a coal mine has recently closed or a coal-fired electric plant was retired or removed.

NEW “TECHNOLOGY NEUTRAL” TAX CREDITS

The IRA added new tax credits that apply to qualified facilities placed into service after December 31, 2024, and which yield zero greenhouse gas emissions. The Section 45Y Clean Electricity Production Credit (“CEPTC”) and the Section 48E Clean Electricity Investment Credit (“CEITC”) will replace the PTC and ITC, respectively, and are intended to be technology neutral. The credit amounts for the CEPTC and CEITC are calculated similarly to the PTC and ITC and are subject to similar prevailing wage and apprenticeship bonus requirements.

NEW WAYS TO MONETIZE TAX CREDITS UNDER THE IRA

The Act established the following two novel methods to monetize energy tax credits.

Direct Pay Available to Tax Exempt Organizations

For tax years beginning after December 31, 2022, and before January 1, 2033, certain “applicable entities” can make an election to receive a cash payment equal to the value of otherwise allowable tax credits. This option allows for the applicable entities to utilize and monetize the tax credits via a refund, even though the entities generally do not incur tax liabilities. The term “applicable entities” includes tax-exempt organizations, state and local governments, tribal governments, and the Tennessee Valley Authority.

The direct pay option is also available to taxpayers claiming the Sections 45V, 45Q, and 45X credits even if they do not meet the definition of an “applicable entity.”

Third-Party Sales

For tax years beginning after December 31, 2022, taxpayers (“transferee”) that do not meet the definition of an “applicable entity” may transfer all or a part of their eligible credits to an unrelated taxpayer (“transferor”) in exchange for cash. The cash consideration is not includible in the income of the transferor and is not deductible by the transferee. Credits may not be transferred more than once. In the case of any transfer election, the transferee taxpayer will be treated as the taxpayer for all purposes under the IRC with respect to such credit. With respect to a project held by a partnership, only the partnership itself (and not its partners) can elect to transfer the eligible credits. (Emphasis added.) Then it is likely to be treated as unrelated trade or business.

All of the tax credits eligible for the direct pay option, except for the Section 45W Clean Commercial Vehicles Credit, are also eligible for sale to a third-party.

NOTICES 2023-17 AND 2023-18

On February 13, 2023, the IRS issued Notices 2023-17 and 2023-18 which provide guidance on the administration of two allocation-based renewables tax credit programs under Sections 48(e) and 48C, respectively.

Notice 2023-17

The Act amended Section 48(e) to provide an increase in the ITC for qualified solar and wind facilities which are deployed in specified low-income communities or residential developments. To receive these increased credit amounts, a taxpayer must receive an allocation of “environmental justice solar and wind capacity limitation” (“Capacity Limitation”). A “qualified solar and wind facility” is any facility that (1) generates electricity solely from a wind facility, solar energy property, or small wind energy property; (2) has a maximum net output of less than five megawatts (as measured in alternating current); and (3) is described in at least one of the four categories described in the chart below.

Notice 2023-17 established the Low-Income Communities Bonus Credit Program under Section 48(e) and provided guidance on the procedures and information required to apply for an allocation of Capacity Limitation. For each of 2023 and 2024, the annual capacity limitation is 1.8 gigawatts of direct current capacity, which will be allocated among four categories of projects as follows:

Category

Required Facility Location

Category

Required Facility Location

Capacity Limitation Allocation (MW)

Bonus Percentage

1

Low-Income Community

700 MW

10%

2

Indian Land

200 MW

10%

3

Qualified Low-Income Residential Building Project

200 MW

10%

4

Qualified Low-Income Economic Benefit Project

700 MW

10%

A taxpayer must submit an application to the IRS in order to receive a Capacity Limitation allocation. Details regarding the application process are forthcoming, however, Notice 2023-17 states that applications will be accepted in a phased approach during a 60-day application window for calendar year 2023. Applications will be accepted for Category 3 and 4 projects beginning in the third quarter of 2023, and Category 1 and 2 project applications will be accepted thereafter.

The Department of Energy (“DOE”) will review applications for statutory eligibility and any other criteria provided by the IRS. On this basis, the DOE will provide recommendations to the IRS regarding the selection of applicants for an allocation of Capacity Limitation. If the selected applications exceed the capacity limitations for a given category, the DOE will use a lottery system or some other process to allocate Capacity Limitations. If accepted, the IRS will notify the applicant of its decision and specify the amount of Capacity Limitation allocated. Within four years of receiving such notification applicants must place the eligible property in service to claim the increased credit rate.

Notice 2023-18

The Act extended the Section 48C Advanced Energy Project Credit (“48C Credit” or “AEPC”), which was originally enacted as part of the American Recovery and Reinvestment Act of 2009. Section 48C provides a credit for investments in projects that fall into one of the following three general categories: (i) clean energy manufacturing and recycling projects, (ii) greenhouse gas emission reduction projects, and (iii) critical materials projects. The AEPC is subject to an aggregate cap of $10 billion, at least $4 billion of which will be allocated to census tracts (or tracts adjacent to census tracts) in which coal mines have been closed after 1999 or coal-fired generation facilities have been retired after 2009.

Notice 2023-18 provides guidance on the process and timeline for applying for an allocation of 48C Credits. The first allocation round of $4 billion began on May 31, 2023. Outlined below is an overview of the application, review, and approval process for the first allocation round of 48C credits:

The applicant submits a “concept paper” to the DOE between May 31, 2023, and July 31, 2023.

After reviewing the concept paper, the DOE will issue a letter to the applicant either encouraging or discouraging the submission of an application. All applicants that submit a concept paper during the above period may submit an application irrespective of the DOE’s response.

The applicant submits an application to the DOE for review. If the applicant intends to apply for a bonus credit because it will satisfy the prevailing wage and apprenticeship requirements, it must confirm this in the application.

The DOE then makes a recommendation as to whether to accept or reject the application and provides a ranking of the applications.

Based on the DOE’s recommendations and rankings, the IRS will make a decision regarding the acceptance or rejection of the application and notify the applicant of its decision.

Within two years after receiving an allocation from the IRS, the applicant must provide evidence to the DOE that the certification requirements have been met.

The DOE notifies the applicant and the IRS that it has received the applicant’s notification that the certification requirements have been met.

The IRS will provide a letter to the applicant certifying the project (“Allocation Letter”).

Within two years after receiving the Allocation Letter, the applicant must notify the DOE that the project has been placed in service. The applicant may claim the 48C Credit in the year in which the property is placed in service.

Additional guidance from the Treasury Department and IRS is expected to be released throughout the year.

FOOTNOTES

[1] Unless otherwise stated, all “Section” references are to the IRC.

[2] For any investment tax credit under Section 50(b)(3), an exempt organization could only avail itself of such credit to the extent the property in question was used in unrelated business income. So in effect, prior to the enactment of IRA, any property that was used consistent with the tax exempt organization’s mission presented an obstacle which Section 6417 expressly overrides. Section 50(b)(3).

[3] If a taxpayer fails to meet the prevailing wage requirement during a particular year, the taxpayer may cure the failure by paying each worker the difference between actual wages paid and the prevailing wage, plus interest and a penalty of $5,000. If a taxpayer’s failure to pay prevailing wages was due to “intentional disregard,” then the taxpayer must pay each worker three times the difference and pay the IRS a $10,000 penalty per worker.

© 2023 Blank Rome LLP

For more tax news, click here to visit the National Law Review.

New York Lawmakers Agree on Brownfield Law Extension With Less Drastic Changes to Tax Credits

Greenberg Traurig

In a departure from his budget proposal, the Legislature negotiated changes with the Governor to extend the tax credits for New York’s Brownfield Cleanup Program (BCP) with relatively modest changes to BCP eligibility requirements.  The Governor’s budget proposal would have limited the lucrative “tangible property” tax credit, which is the credit based on a percentage of the cost of constructing a new development on a Brownfield site, to (i) properties located in an environmental zone, (ii) properties to be utilized for affordable housing, or (iii) “upside down” properties – where the remediation of the property is projected to cost more than the value of the remediated property.  Under the bill agreed to with the Legislature, however, those limits (with modifications) will apply only to properties located in New York City.  In other words, outside of New York City, eligibility for the tangible property tax credit will remain available to all developers that otherwise qualify under the BCP, as per existing law.

The news for New York City-based developments is also not all bad. The final bill adds a fourth category of properties eligible for the tangible property tax credit for “underutilized” properties – to be defined by regulation, and the criteria for upside down properties were loosened so that a property can qualify if the remediation is projected to cost over 75 percent – rather than 100 percent – of the value of the remediated property. Despite these revisions, the New York BCP will continue to provide significant tax incentives to developers seeking to clean up and redevelop contaminated sites and the extension will resolve the uncertainty over the future of the program that existed for several years.

Other changes include:

  • “Grandfathering” of Existing Tax Credits: Amendments to the law as they relate to all eligible tax credits are tied to the dates by which a Brownfield site is accepted into the BCP and obtains a Certificate of Completion (COC) from the Department of Environmental Conservation (DEC).

    • Existing provisions related to the tax credits would remain applicable to those sites that either (i) were admitted into BCP prior to June 23, 2008 and obtained their COC by December 31, 2017, or (ii) were admitted into the BCP between June 23, 2008 and July 1, 2015 (or the date by which DEC proposes regulations defining “underutilized,” whichever is later) and obtained a COC by December 31, 2019.

    • Amendments related to the tax credits are applicable to those sites that are accepted into the BCP between July 1, 2015 (or the date by which DEC proposes regulations defining “underutilized,” whichever is later) and December 31, 2022, so long as they obtain a COC on or before March 31, 2026.

  • Definition of “Brownfield Site”: The amendments redefine “Brownfield Site” to mean “any real property where a contaminant is present at levels exceeding the soil cleanup objectives or other health-based or environmental standards, criteria or guidance adopted by [DEC] that are applicable based on the reasonably anticipated use of the property.” This is a welcome change which ties eligibility to cleanup objectives and moves away from the prior vague definition that required the presence of contamination that “complicates” redevelopment.

  • Creation of a New EZ Program: The amendments empower DEC to adopt regulations to implement a program for “the expedited investigation and/or remediation” of brownfield sites (BCP-EZ program) provided the developer agrees to take no tax credits associated with the program. The EZ Program, however, appears to provide a minimal departure from existing remediation and public notice requirements, and thus may not actually provide for an expedited investigation as advertised. One area where a more expedited process may work is for Track 4 – restricted use – cleanups where the applicant the applicant would be allowed to use site-specific data to demonstrate that the concentration of the contaminant in the soils reflects background conditions and, in that case, a contaminant-specific action objective for such contaminant equal to such background concentration may be established.

  • Inclusion of Class 2 Sites: The amendments allow in class 2 Superfund sites that are being remediated by non-culpable volunteers.  Previously, such sites were deemed ineligible even if the party seeking to remediate the site had no role in the contamination.

  • Change In DEC Oversight Costs: The amendments eliminates the payment of DEC oversight costs for volunteers, and permits a flat fee charge to participants.

  • Related Service Fee: The amendments address a perceived problem related to the computation of service fees charged to the Brownfield applicant by a related party and the calculation of tax credits. The concern was that these service fees could be inflated as a way to increase the remediation or site preparation costs, and result in associated increases in the ceiling of eligible tangible property credits.  The amendments provide that such service fees cannot be claimed as eligible site preparation or remediation costs until they are earned and actually paid, and the portion of the tax credits related to such fees cannot be claimed until the taxable year when the subject property is placed into service. This limits the use of such fees as a way to inflate costs that are used to calculate the ceiling for tangible property credits. That ceiling is deemed to be the lesser of $35 million for residential/commercial projects ($45 million for industrial projects) or three times the amount of eligible site preparation and onsite groundwater remediation costs.

  • Definition of Eligible Site Preparation Costs and Groundwater Remediation Costs: The definition of eligible “site preparation” and “onsite groundwater remediation” costs is critical because these costs are eligible for tax credits that range from 28 to 50 percent of such actual costs, and, as noted, those costs are often used as the basis for calculating the ceiling for a project’s tangible property tax credits. The amendments provide a more specific and detailed description of eligible costs, requiring such costs to be necessary to implement a site investigation or remediation, or to qualify for a COC.  Eligible costs include those related to excavation, demolition, engineering and environmental consulting costs, legal costs, transportation and disposal of contaminated soil, physical support of excavation, and dewatering.

  • Increased Tangible Property Tax Credit Percentage and Changed Definition: The amendments limits the tangible property credit to only costs for tangible property with a useful life of at least fifteen years. Certain projects, however, will be eligible for a higher percentage tangible property credit, which in a general sense is a tax credit calculated based on a percentage of the cost of constructing the building on the Brownfield site.  Under existing law, that percentage is either 10 or 12 percent.  Under the amendments, that percentage can be increased in five percent increments, and total as much as 24 percent of the development costs, with five percent bonuses for sites that are cleaned up to Track 1 standards (highest level of cleanup), located in En-zones or a Brownfield Opportunity Area (BOA), or developed for manufacturing or affordable housing.

ARTICLE BY

Steven C. Russo
Robert M. Rosenthal
Greenberg Traurig, LLP

February 2015 State Tax Credit and Incentive Update

Horwood Marcus & Berk Chartered Law Firm

This is the second in a monthly series outlining updates in state tax credits and incentives, including legislative, gubernatorial and case law updates. While we recognize that tax credits and incentives are often criticized by some tax policy experts, they are a reality in today’s competitive business environment with states competing with each other for jobs and investment. The good news for both corporate taxpayers and non-profit entities is that state tax credits and incentives are available and can benefit a business in many ways.

Recent Announcements of Credit/Incentives Applications and Packages

Arizona: Just three weeks after Apple Inc. announced plans to invest $2 billion over 10 years to open a data center in Arizona, on February 25, 2015, the Arizona Legislature passed a bill (HB 2670) that would grant millions of dollars in business tax incentives to Apple. Under the bill, international operations centers, such as the 1.3-million-square-foot digital command center Apple plans to build in Mesa, would be eligible for a renewable energy tax credit worth up to $5 million. The credit could be used for up to five years.  HB 2670 would also exempt international operations centers from the transaction privilege tax, an annual tax break of $1.2 million, according to the bill.

A company would be required to make a total of $1.25 billion in capital investments over 10 years, including the cost of land, buildings, and equipment. The company would also be required to invest at least $100 million in one or more renewable energy facilities over a three-year period. A company that fails to make at least $100 million in capital investments each year could remain eligible for the tax incentives by paying to the Department of Revenue the amount of utility relief the company would have otherwise been granted for that tax year.

California: In February 2015, the California Governor’s Office of Business and Economic Development (GO-Biz) announced that it has received 253 applications with a combined tax credit amount of $289 million for the third California Competes Tax Credit Application period, which closed February 2, 2015.  The pool of credits available is $75 million and is expected to be awarded on April 16, 2015. In the first two application periods, 400 companies asked for $500 million in credits from a pool of $29 million awarded to 29 companies in June 2014, and 286 companies asked for $329 million from a pool of $31 million awarded to 56 companies in January 2015. A total of $151.1 million is available in the 2014-15 fiscal year, with one more round of applications and award of the final $31.1 million scheduled for June 18. In the next fiscal year, $200 million will be available for the credit.

New Jersey: A New York apparel company is moving from New York City to Jersey City. The retailer, Charles Komar & Sons Inc., will be moving its headquarters and 500 employees to Jersey City. In return, the state will be providing a $37.2 million tax break, including negotiated incentives.

Legislative, Regulative and Gubernatorial Update

California: On February 25, 2015, the California Legislative Analyst’s Office presented state lawmakers with options for a state earned income tax credit (“ETIC:”), including a “piggyback” on the federal EITC, a state match for the federal EITC for low-income working families, and a supplement to the federal EITC for childless adults.

Permanent regulations governing the California Competes Tax Credit program took effect February 5, 2015, to replace temporary regulations adopted Feb. 20, 2014. The final version of the regulations makes a few minor changes from the temporary regulations. One of the changes specifies that companies can apply for and win the credit multiple times, but each time they will be evaluated based on new commitments for investment and pay to workers in California. The final regulations also require applicants to assert that absent the credit award they “may” terminate or relocate employees, rather than “will” terminate or relocate.

The Franchise Tax Board (“FTB”) must review the books and records of all businesses receiving the credit that have more than $2 million in annual gross receipts to determine if they have met the milestones for employment, wages and investment required under their contracts with the state. If the FTB determines that a business has a material breach of its contract, either through failure to timely provide information for review, a material omission or incorrect information, or failure to meet milestones for employment, wages or investment, the agency will notify GO-Biz. It will be up to the five-member GO-Biz California Competes Tax Credit Committee to make a final decision whether businesses must pay back the credit due to a breach.

On February 12, 2015, the California Film Commission released draft emergency regulations to implement the state’s film and television tax credit program newly expanded under 2-14 AB 1839, which increased funding to $300 million per fiscal year, expanded eligibility, and eliminated budget caps for independent films and the state’s lottery system. The draft now goes to the governor’s Office of Administrative Law for review and final approval. The draft document is posted on the Film Commission’s website under “News & Notices.”

In related news, California will hold a final lottery under the old program on April 1. The new incentives plan will allot funds based on how many jobs productions employ, among other criteria, such as the use of California visual effects companies and production facilities.

For the first time, the program allows all new TV shows to qualify – not just on basic cable like under the current plan – as well as movies with budgets above $75 million. However, the up-to-25% credit applies only to the first $100 million of a movie’s costs, and that may cool the enthusiasm of studios when planning shoots on big budget projects. Despite the improvements, California’s incentive plan is smaller than some rival states with whom they are fighting for a slice of the production pie.

Illinois: On February 13, 2015, SB 707 was introduced which would entitle interactive digital media companies to an income tax credit in an amount of 30% of expenses incurred for an accredited production in a taxable year. The credit would be able to be carried forward or transferred.

Louisiana: On February 27, 2015, Louisiana Gov. Bobby Jindal proposed to change some of the state’s individual and business tax credits from refundable to nonrefundable, which according to his fiscal 2016 executive budget proposal would save the state $526 million. Refundable credits which would be affected include, but are limited to, inventory tax credit, research and development credit, angel investor credit and historical rehabilitation residential credit.

Louisiana: Louisiana lawmakers on February 24, 2015, released draft bills that would scale back the state’s generous film tax credit by setting clear limits on the program and making related costs to the state more predictable. Currently, the credit may be used to offset personal or corporate income tax liability in the state. The program provides a transferable tax credit of up to 35 percent of total in-state expenditures with no cap and requires a minimum of $300,000 in spending. The credit can be transferred to Louisiana taxpayers or back to the state for 85% of its face value. State Sen. Jean-Paul Morrell’s draft bill would cap the total amount of film credits allowed for one year at $300 million, but what isn’t used in that year could be carried forward to the next. Under Rep. Julie Stokes’ bill, the credit could be transferred only once, and the state’s buyback percentage would be increased from 85 cents to 90 cents on the dollar.

Michigan: In February 2015, Michigan Gov. Rick Snyder delivered his proposed 2016 budget, offered a projected budget for fiscal 2017, and signed an executive order to reduce expenditures in the fiscal 2015 budget to account for what the Governor stated is a revenue shortfall that has resulted from businesses claiming tax credits granted during the last decade.

Furthermore, the Governor indicated that he wants to renegotiate the tax incentive agreements the state has with 240 companies. It turns out the state owes about $9.4 billion in tax credits to companies that created jobs in Michigan. That liability costs the state about $500 million a year, a cost that will continue until 2029. The tax credits reduce a company’s liability under the Michigan Business Tax (MBT).  The Governor’s administration wants to negotiate with the companies the timing of the credits’ use because currently the companies can claim the credits whenever they want.  Of those companies owed the MBT tax credits, Chrysler, General Motors, and Ford alone are owed about half of the balance (over $4 billion) in MBT credits.

Texas: On January 30, 2015, the Texas Comptroller of Public Accounts proposed regulations (Prop. Tex. Admin. Code §3.599) aimed at implementing the state’s Research and Development Activities Credit, which can be applied against a taxpayer’s franchise tax. The proposed rule implements H.B. 800, which was enacted in 2013 and creates a credit for certain expenses from research and development activities. The proposed rule applies to franchise tax reports originally due on or after Jan. 1, 2014, and expires on Dec. 31, 2026.  Unused credits may be carried forward for no more than 20 consecutive reports. The total credit claimed for a report, including the amount of any carryforward credit, cannot exceed 50% of the amount of franchise tax due for the report before any other applicable tax credits. The proposed rule would prohibit the transfer of credits to another entity unless all of the assets of the taxable entity are conveyed, assigned, or transferred in the same transaction.

Utah: On February 11, 2015, the Utah Governor’s Office of Economic Development proposed to update a refundable economic development tax credit rule to reflect historic practices and provide a more comprehensive outline to the processes and procedures used in administering and awarding the tax incentive. The rule outlines how a tax incentive is granted including the criteria used in screening applicants and how the tax credit is calculated and redeemed. The rule defines key terms, provides for the application process, and provides the factors to be considered in authorizing an economic development tax increment financing (EDTIF) award. The new rule also outlines the application for and verification of information supporting an annual EDTIF payment, and how to request a modification of the EDTIF offer or contract.

Virginia: On February 9, 2015, the Virginia Senate passed legislation (SB 1447) designed to attract investments from companies that used inversions to reduce their federal tax liabilities. If passed by the House of Delegates, SB 1447 would amend the state’s corporate income tax statute to permit a $5 million exemption for companies that used an inversion transaction to lower their U.S. tax liability and that make a capital investment of at least $5 million in Virginia to open a facility or other business operation.

Case Law Update

Georgia: In LT IT-2014-03, the Georgia Department of Revenue ruled that after a company converts to a limited liability company, it can continue to claim benefits awarded to the original company under the quality jobs tax credit program, including income tax carryforwards, withholding benefit carryforwards, and remaining credit installments.

European Union v. Washington: On February 23, 2015, the World Trade Organization (“WTO”) agreed to consider a European Union (“EU”) complaint against Washington over the state’s $8.7 billion package of tax incentives approved in 2013 (SB 5292) to encourage Boeing to manufacture its 777X in the state. SB 5952 included reduced business and occupation tax rates for aerospace suppliers, a sales tax exemption for materials used in the construction of aerospace manufacturing facilities, and tax breaks for property associated with those facilities.

The EU submitted a complaint to the WTO in December 2015, saying the incentives granted by Washington to Boeing violated the WTO’s Agreement on Subsidies and Countervailing Measures (SCM agreement) which bans subsidies that are contingent on the use of domestic goods. Specifically, the allegation is linked to two sections of SB 5952 that connected the incentives to the “siting of a significant commercial airplane manufacturing program in the state of Washington.” While most of the incentives simply required that such a siting occur, RCW 82.04.260(11)(e)(ii) revokes the preferential business and occupation tax rates if Boeing relocates the 777X outside Washington.

The complaint is only the latest chapter in a saga dating back to a 2004 complaint by the United States over subsidies offered to France-based Airbus, a major competitor to Boeing in the manufacture of commercial aircraft. That complaint was countered with a complaint over U.S. subsidies to Boeing. Both companies were eventually found to have received illegal subsidies, and in 2012, the WTO ruled that a variety of state and federal subsidies to Boeing violated the SCM agreement and harmed EU interests by undercutting Airbus.

States’ Evaluation and Review of Credit and Incentive Programs

Maryland: On February 12, 2015, An economic development task force appointed by Maryland lawmakers released a report with recommendations to improve the state’s business climate that include restructuring the state’s economic development programs and business tax incentives for better program efficacy.

New York: According to a February 5, 2015, report released by New York State Comptroller Thomas DiNapoli, it is unclear whether the $1.3 billion in incentives and credits given out annually by New York is creating jobs. The report focuses on the Empire State Development Corp. (ESDC) use of tax incentives, accountability and transparency in ESDC operations, and how improvements can be made.

The Task Force on Evaluating Economic Development Tax Expenditures, comprising New York City Council members and leaders from business, labor, policy, and academic communities, is reviewing New York City’s billions of dollars in economic development tax incentives to make sure the money is being put to good use. The Task Force began meeting at the end of January 2015 and has held two meetings to date. The Task Force is expected to deliver a report on its findings by the end of 2015 to the State Legislature. The Legislature’s review is needed for final approval before the city can change any laws.

North Carolina: In response to North Carolina Republican Gov. Pat McCrory’s proposal to expand the Job Development Incentive Grants program (“Program”), the North Carolina Justice Center reported that since its inception in 2002, more than half of all firms receiving incentive awards from the Program have failed to live up to their promises of job creation, investment, or wages.  Given this report, it will be interesting if the Governor’s proposal will have any legs to stand on.

ARTICLE BY

Jennifer Zimmerman
Horwood Marcus & Berk Chartered