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.

Formation of the Project Company

The first question is who should be a party to these agreements on behalf of the project.  The best practice is to have each project owned by its own special purpose limited liability company.  That permits transfer of the project by way of assigning the membership interests in the limited liability company.  Such an “upstream” equity transfer is often viewed in a more accommodating matter in project documents than an assignment of the actual project.

Some developers, in the interest of saving costs with respect to the formation and maintenance of limited liability companies, will have a single limited liability company (“LLC”) own the rights to multiple smaller projects.  This strategy is often pennywise and pound-foolish as the lawyers then have to draft and negotiate mechanics to address what happens if one project owned by the LLC is placed in service, and thus needing to be owned by the tax equity vehicle, prior to the other project(s) being placed in service.  If the lawyers’ solution is to transfer the LLC before some of its projects are ready for the tax equity vehicle, the lawyers then have the pleasure of drafting and negotiating the mechanics of what happens if a project included the project company never reaches the point of being placed in service by the deadline agreed to by the tax equity investor.  The several thousand dollars saved by using a single LLC for multiple projects is quickly spent on legal fees.

Site Lease

The first step in the project development process is often obtaining land rights to build the project.  The best practice for the site lease is to provide the LLC with the ability to use the site for the useful life of the project, whether the original PPA continues to be in effect or not.

If it is difficult or unappealing to agree with the landlord as to the amount of the ground rent for the full useful life of the project, the rent beyond the initial term could be described in the site lease as the fair market rental value as the parties agree at the time the renewal is exercised, or, if they are unable to agree, as determined by an independent qualified appraiser selected by the landlord and reasonably satisfactory to the LLC (or vice versa).

For instance, let’s assume a ground-mounted solar project has a 35-year economic useful life and there is a 20-year PPA.  The ground rent could be a specified amount for the 20-year term.  After the 20-year term, whether the PPA is renewed or not, the project company could have three five-year renewal options exercisable in its discretion with the rent to be the then “fair market value” (as described in the preceding paragraph).

The other issue to look out for in a ground lease is a provision that provides that the project (i.e., the equipment) automatically reverts to the landlord at the end of the ground lease term, whether the LLC is prepared to remove the equipment or not.  Such a provision could possibly be viewed by tax counsel as depriving the LLC’s ultimate owner of the “residual value” of the equipment, which is often inconsistent with the tax analysis.

Often, the landlord will request a base fixed rent amount, plus a share of the profits.  Such a profit sharing can raise questions as to whether the landlord could be characterized by the IRS as a “partner” in the project who should be allocated a portion of the tax credits.  It is best to avoid tax counsel having to spend hours grappling with the issue and have any such payment to the landlord be based on “revenue” (i.e., before expenses, in contrast to “profit” which is after expenses).[1]

Interconnection Agreement

Typically, the next step in the project development process is entering into the interconnection agreement, which allows the project’s electricity to reach the grid.  Like the ground lease, the LLC should have the right to access the electric grid for the economic useful life of the project (if not longer).

A tax issue that sometimes arises in interconnection agreements is that the utility requires either a (i) payment (i.e., a contribution of cash) from the LLC to pay the utility for network upgrades necessitated by the project or (ii) the LLC to construct the network upgrade and contribute the upgrade to the utility.  Some interconnection agreements require the LLC to indemnify the utility for taxes imposed on the utility’s receipt of the cash or the upgrade.  There is IRS guidance that such contributions do not result in taxable income for the utility, so long as various requirements are met.[2] If the utility negotiates for a tax indemnity, the developer should ensure compliance with this IRS guidance when the interconnection agreement is signed. Otherwise, during due diligence, the tax equity counsel may raise questions about the LLC owing the utility a tax indemnity.


The PPA provides the project with its source of revenue, so the PPA justifiably often receives the most attention.  For any transaction involving the investment tax credit (“ITC”) or accelerated depreciation in which the project company’s customer is a tax-exempt entity, the revenue contract (e.g., the PPA) cannot be a “lease” because neither ITC nor accelerated depreciation is available with respect to property leased to tax-exempt entities; there are certain narrow exceptions which are generally not applicable in project finance transactions.

For a wind project that is intended to generate production tax credits (“PTCs”), the PPA cannot be characterized as a “lease” because the PTC statute effectively precludes leases.  The preclusion stems from the fact that the PTC statute provides that the “operator” of a wind project is the taxpayer eligible for the PTC.[3]  In a lease transaction, the owner/lessor is not the “operator,” and thus a lessor would be ineligible for the PTC.

Fortunately, there is a statute that provides rules for distinguishing between “leases” and “service contracts.[4]  The term “service contract” is effectively the Code’s designation for a revenue contract that is not a lease.  Hence, in any transaction involving (i) PTCs or (ii) a tax-exempt offtaker in transaction in which the ITC or accelerated depreciation is contemplated, the revenue contract needs to be characterized as a “service contract” under this statute.

The first requirement is the contract must “purport” to be a “service contract.”[5]  It is not entirely clear what that means, particularly in the context of a PPA in which the project company is selling kilowatt hours of electricity, rather than providing a “service” (e.g., a bus company providing transportation services).

Rather than having tax counsel pontificate on the meaning of “purports,” the best practice is to include a provision in the PPA along the lines of the following: “This Agreement purports to be a “service contract” within the meaning of Section 7701(e) of the Code; further, each party hereto agrees to report payments made and received hereunder in a manner consistent with this Agreement being a “service contract” for all income tax purposes.”

Once a PPA successfully navigates the “purports” hurdle, there is a safe harbor for alternative energy projects that has four elements that if failed disqualify a project for the safe harbor[6] and require it to meet a six factor balancing test.[7]  The easiest route is for the PPA to meet the safe harbor and avoid challenging six factor balancing test.[8]

A purported “service contract” will be characterized as such (rather than a lease), so long as each of the following four requirements are complied with:

  • First, the offtaker may not operate the project.
  • Second, the offtaker may not bear any significant financial burden if there is a non-performance under the PPA, unless the burden is due to (i) reasons beyond the control of the project company, (ii) a temporary shutdown of the project for maintenance repairs or capital improvements or (iii) the bankruptcy or other financial difficulty of the project company.
  • Third, the offtaker may not receive any significant financial benefit if the operating costs are less then expected.
  • Fourth, the offtaker may not have an option or obligation to purchase all or part of the project at a fixed and determinable price, other than for the fair market value of the project.

The first three prongs are usually not problematic in a typical PPA.  The fourth prong, addressing purchase options, is difficult to parse.  One of the questions it raises, is whether the last clause (“other than for fair market value”) would permit a fixed price purchase option of, for instance, $10 million exercisable in ten years that an appraiser opines is a reasonable estimate of the fair market value of the project in ten years.  Or must the price be fair market value as “determined at the time” (i.e., as negotiated by the parties or determined by an appraiser in ten years) as required by the loss trapping rules for certain leases with tax-exempt lessees[9] and the IRS’s guidelines for advance rulings for leveraged leases?[10]

Given these ambiguities, purchase option analysis comes down to best practices, rather than black and white rules.  The best practice is to limit the purchase option in a PPA to either (a) fair market value as determined at the time of exercise or (b) the higher of (i) the fair market value as determined at the time of exercise and (ii) a fixed price set by an appraiser today to be less than projected fair market value.  It is a best practice to set the “floor” referred to in clause (ii) at less than the projected fair market value to avoid the “floor” exceeding fair market value and effectively making the option price “fixed and determinable.”  For instance, if fair market value was $10 million and the floor was $15 million, then the floor would in all likelihood apply and the price could be viewed by the IRS as “fixed and determinable” (i.e., $15 million) but not “fair market value” (i.e., $10 million).

Finally, we come down to the question of the number of purchase options.  The safe harbor is silent on the number of purchase options that is permissible, so that could lead to a reasonable conclusion that there is no limit.  However, tax lore has frowned on excessive purchase options and tax lawyers prefer fewer.  The best practice (but not black letter law) is to limit it to two purchase options; PPAs with more than two purchase options lead to tax lawyer handwringing and the need to add several pages of analysis to the tax opinion; both of which add to the legal bill.

Operations and Maintenance Contract

Operations and maintenance (“O&M) contracts are typically not that tax sensitive.  They are also, typically, not that difficult to obtain as there are often multiple contractors interested in such work.

The O&M contractor in some transactions is related to a partner in the partnership that owns the project company.  In that scenario, the parties would be well-served to ensure that the O&M fees are established under arm’s length principles (i.e., consistent with market practice for O&M contract between unrelated parties), so that they have a response if the IRS tries to recharacterize the economics of the O&M contract in a manner that allocates the sharing of the tax attributes from the project in a manner that varies from what the parties contemplated.

As was the case with the ground lease, if the O&M provider wants some sort of incentive fee, that fee should not be based on “profits”.  Basing it on kilowatt hours produced within a period of time or project revenue would be acceptable alternatives.

Construction Contract

The construction contract, which is typically titled the engineering, procurement and construction agreement (“EPC”), is usually not that tax sensitive.  An exception is if the EPC is being used to “start construction” before a deadline after which the tax credit in question decreases pursuant to its enabling statute.[11]  Such specialized situations are beyond the scope of this article.

EPCs can raise a host of sales and use tax issues.  Those depend on the jurisdictions in question and are beyond the scope of this article.

It is often important to be confident in your determination of when a project will be placed in service in order to be sure that the contemplated tax attributes accrue to the intended party.  In an ITC transaction (other than a sale-leaseback for which the Code generously gives taxpayers a three month window),[12] the placed in service date should be after the project is owned by the intended “taxpayer”[13] and before the end of the year in which the ITC arises.  The pertinent cases and rulings regarding when an electrical generating project is placed in service have established a five factor test.[14]  The five factors are:

  • First, all required licenses and permits have been approved.
  • Second, legal ownership and control of the project must be transferred from the EPC contractor to the project company.
  • Third, the project must be synched to the power grid.[15]
  • Fourth, the critical tests of the various components must be complete.
  • Fifth, daily or regular operation of the project must have started.

In light of the second factor, careful consideration must be given to when legal title, risk of loss, the obligation to insure and physical control of the project passes from the EPC contractor to the project company.  From a tax perspective, its ideal to transfer all of the foregoing rights and obligations on or before the date the project is placed in service; however, there may be commercial considerations that may merit being weighed against the cleanliness of application of this five factor test.

Another tax issue in EPCs for ITC eligible projects is liquidated damages.  Many contracts arising in project finance and other industries provide that liquidated damages are a purchase price reduction.  That is often desirable as it causes the buyer to reduce its tax/basis in the purchased asst, rather than recognizing taxable income.  However, for an ITC eligible project, the reduction in basis or recapture resulting from a purchase price adjustment has a greater cost than the taxable income.  In this situation, it is preferable to put the best foot forward and stipulate in the EPC that liquidated damages are compensation for lost profits.  Such language does not bind the IRS or a court to follow that treatment, but it is a good start.


Obtaining key project documents, like a PPA, can make or break a project.  Therefore, developers are often motivated to accommodate counter-parties’ drafting requests, so long as a satisfactory payment stream is expected.  However, drafting requests that have tax implications, as described above, will lead to other costs once tax equity and its tax counsel join the transaction.  Thus, what may seem like an easy drafting concession may trigger other challenges later in the project finance process.  Developers at least need to be cognizant of the challenges ahead of them when agreeing to such drafting concessions.

This article was originally published in Law360:

[1] See Treas. Reg. § 301. 7701-1(a)(2) (“the participants carry on a trade, business, financial operation, or venture and divide the profits therefrom”).

[2] See IRS Notice 2016-35, which is discussed at  June 2016 | Tax Equity Times.

[3] I.R.C. § 45(a)(2)(A) (“produced by the taxpayer”).  Note, for closed and open-loop biomass  “the lessee or the operator” is permitted to claim the PTC. I.R.C. § 45(d)(2)(C)(ii), (3)(C).

[4] See, generally, I.R.C. § 7701(e).

[5] I.R.C. §§ 7701(e)(1), (3)((A)(ii).

[6] I.R.C. §§ 7701(e)(3), (4).

[7] See I.R.C. § 7701(e)(1).

[8] See I.R.C. § 7701(e)(1) for the balancing test.

[9] See I.R.C. § 470(d)(4)(B).

[10] Cf. Rev. Proc. 2001-28 (the successor to Rev. Proc. 75-21) which addresses, inter alia, purchase option in leveraged lease transactions an advance ruling is sought for.

[11] A discussion and analysis of these rules is available at  Dec 19, 2016 and May 27, 2016 /Tax Equity Times and Mayer Brown’s Aug. 8, 2014 legal update (and the updates referenced therein).

[12] See I.R.C. § 50(d)(4).

[13] If that taxpayer is a partnership, it is a best practice for each partner to have unconditionally contributed at least 20 percent of its total capital contribution prior to the placed-in-service date.  Cf. Rev. Proc. 2004-12, § 4.03 (providing a safe harbor for rehabilitation tax credit (i.e., historic tax credit) transactions).

[14] See, e.g., Rev. Rul. 76-256; P.LR. 201326008 (Jun. 28, 2013); P.L.R. 201326009 (Jun. 28, 2013).

[15] A recent Tax Court case arguably suggests, without meaningful analysis or reference to this five factor test, that this prong is the only test for a residential solar project to be placed in service.  Golan v. Commissioner, T.C. Memo. 2018-76 (“the solar equipment was not ready and available for full operation on a regular basis for its intended use until it was connected to the electric grid.  [W]e hold that [the taxpayer]  placed the solar equipment in service in 2011” when the interconnection with the grid occurred.).