Tax Equity Structures: Partnership Flips, Leases, and Recapture

Tax equity structures for renewable energy are financing arrangements that pair a developer building a solar, wind, or battery storage project with a corporate investor who has a large federal tax bill. The investor funds a significant share of construction costs and earns its return primarily through federal tax credits and depreciation deductions rather than through the electricity the project sells. Three structures dominate — the partnership flip, the sale-leaseback, and the inverted lease — and a newer option under Section 6418 lets developers sell credits outright for cash. Together these arrangements move roughly $20 billion to $22 billion into U.S. renewable projects each year.

The reason these deals exist is straightforward. Federal law offers generous credits and accelerated depreciation for clean energy, but a developer that spent the year building a solar farm rarely has enough taxable income to use them. An investor with a substantial tax liability does. Tax equity is the bridge between the two.

The Credits Being Monetized

Two credits drive nearly every deal. The clean electricity investment credit under 26 U.S.C. § 48E is calculated as a percentage of the project’s cost.¹ The clean electricity production credit under 26 U.S.C. § 45Y pays out per kilowatt-hour over the facility’s first ten years of operation.² A project claims one or the other. Solar and storage typically elect the investment credit; wind generally favors production.

Base Rate Versus Full Rate

The investment credit’s base rate is 6 percent. Projects of one megawatt or more reach the full 30 percent only by paying the locally prevailing wage during construction and maintenance and ensuring that at least 15 percent of construction labor hours go to registered apprentices.¹³ Projects under one megawatt qualify for the full rate automatically. The production credit follows the same pattern: 0.3 cents per kilowatt-hour at base, rising to 1.5 cents when the labor rules are met.²

Bonus Adders

On top of the 30 percent base, a project can stack 10 percentage points for siting in an energy community (generally a census tract with historical ties to fossil fuel employment or a brownfield site) and another 10 for meeting domestic content thresholds on steel, iron, and manufactured components.¹⁴ Full rate plus both adders reaches 50 percent, and additional low-income community bonuses can push it higher. The bigger the credit, the more capital a tax equity investor will commit.

The Partnership Flip

The partnership flip is the workhorse of the market. The developer and the investor form a joint venture, almost always a limited liability company taxed as a partnership, that owns the project. The investor contributes roughly 30 to 70 percent of the capital stack depending on the credits available and target returns, while the developer handles construction and long-term operations.⁵

Economic benefits split lopsidedly. In the early years, the investor takes up to 99 percent of the tax credits, depreciation, and taxable losses, while the developer keeps a nominal 1 percent share of those items. Cash distributions from electricity sales tilt the other way, with the developer taking a disproportionately large share of operating cash flow. The investor recovers its capital through tax savings; the developer earns income from the project it built.

The Flip Point

The allocation split does not last forever. The partnership agreement defines a flip point, a milestone after which the investor’s economic interest drops sharply. The flip can trigger when the investor hits a negotiated internal rate of return (one recent industry case study used 7.25 percent) or on a fixed date, whichever the agreement specifies. It cannot occur sooner than five years after the project enters service. Once it triggers, the investor’s share of partnership income typically drops to 5 percent and the developer’s share rises to match.

Developer Buyout Rights

Most flip agreements let the developer buy out the investor’s residual interest after the flip. The price is either fair market value at the time of exercise or a fixed price representing a good-faith estimate, made when the deal was signed, of what the interest would be worth later. What the investor cannot have is a put option forcing the developer to buy. That one-way restriction is a condition of the IRS safe harbor. Some developers negotiate a purchase price high enough to let the investor avoid a book loss, which simplifies the investor’s accounting.

The IRS Safe Harbor

The IRS established a safe harbor for wind-energy partnership flips in Revenue Procedure 2007-65, later extended to solar and other technologies by Announcement 2009-69. For the partnership to be respected rather than recharacterized as a loan or an outright credit sale, both parties must meet minimum interest thresholds. The developer must hold at least a 1 percent interest in every material item of partnership income, gain, loss, deduction, and credit for the life of the venture. The investor must make an unconditional minimum investment equal to at least 20 percent of its total expected capital contributions on or before commercial operation, and cannot be shielded from the risk of losing that investment through any side arrangement with the developer or a related party.⁶

Loss Limits on the Investor Side

Investors cannot deduct unlimited losses. Under Section 704(d), a partner deducts losses only up to the adjusted basis of its partnership interest at year end. Excess losses are suspended and carried forward until basis rises through additional contributions, allocated income, or a larger share of partnership debt. This matters most in the early years when accelerated depreciation can generate large paper losses. Structuring contributions and debt allocations so the investor has enough basis to absorb anticipated losses is one of the more technical parts of a flip.

The Sale-Leaseback

In a sale-leaseback, the developer builds the project, sells it to the investor at fair market value, and immediately leases it back for a term typically running 15 to 20 years. The investor becomes the legal owner, claims 100 percent of the investment credit on the purchase price, and takes all the depreciation. The developer operates the facility and pays rent out of electricity revenue, keeping the spread as profit.

The structure is mechanically simpler than a flip. There is no ongoing allocation waterfall and no flip mechanism to negotiate. The cost is that the developer gives up legal title, which some developers find unattractive. A repurchase option at fair market value when the lease expires is common, but it cannot be a bargain purchase or the IRS may recharacterize the whole arrangement as a financing.

True Lease Requirements

For the IRS to respect the lease, and therefore the investor’s tax benefits, the deal must satisfy Revenue Procedure 2001-28. The lease term cannot exceed 80 percent of the project’s estimated useful life. The investor must show the project will retain at least 20 percent of its original cost in residual value at lease end.⁷ The investor must have a real economic stake beyond tax benefits, meaning the deal needs to make sense on its own even without the credits. Title stays with the investor throughout.

Fair market value at the sale date drives both the credit amount and the true-lease analysis, so appraisals matter. Inflated valuations invite IRS scrutiny.

The Inverted Lease

The inverted lease, sometimes called a lease pass-through, reverses the direction. The developer keeps legal title and leases the equipment to the investor. The developer then makes an election under rules preserved by 26 U.S.C. § 50(d)(5), which applies rules similar to the former Section 48(d), to pass the investment credit through to the investor-lessee.⁸ The investor makes a large upfront payment and receives the credit plus a share of operating revenue during the lease term.

The advantage for the developer is keeping both legal title and the depreciation deductions. That split matters when a developer expects taxable income in future years and wants the depreciation later, even though it lacks the tax capacity to use the credit now. Lease terms usually run at least five to seven years, after which the investor’s revenue interest ends and the developer holds the asset outright without needing to repurchase anything.

This structure appears most in portfolios of smaller projects, such as residential and commercial solar installations, where the administrative simplicity of never transferring title outweighs partnership complexity. Large utility-scale projects usually prefer the flip.

h2>Selling Credits for Cash Under Section 6418

The Inflation Reduction Act created a fundamentally different path. Section 6418 lets an eligible taxpayer sell all or part of a credit to an unrelated buyer for cash.⁹ The buyer pays the developer and claims the credit on its own return. No partnership, no lease, no shared governance.

Three rules define the mechanism:

The buyer must pay in cash. No barter, no notes, no equity swaps.
A credit can only be transferred once. The buyer cannot resell it.
The cash the developer receives is not included in gross income, and the buyer cannot deduct the purchase price.

Eligible credits include Section 48E, Section 45Y, the Section 45Q carbon capture credit, and several others.⁹ Before transferring, the developer must register through the IRS Energy Credits Online portal to get a registration number for each credit property, which must appear on the return where the transfer is reported. Registration must happen at least 120 days before the return’s due date, including extensions.¹⁰

Credit transfers do not replace traditional tax equity so much as compete with it. Selling a credit at, say, 90 to 95 cents on the dollar yields less total value than a partnership flip that also passes through depreciation and losses. But a transfer closes faster, involves far less legal paperwork, and leaves the developer in full control of the project. For smaller deals where legal costs would eat the flip’s economics, a transfer is often the better path. For a large utility-scale project with substantial depreciation to allocate, the flip usually still wins.

A Boundary: Direct Pay Is Not for For-Profit Developers

Section 6417 lets certain entities that owe no federal income tax treat a credit as a direct payment from the Treasury. Eligible entities include tax-exempt organizations, state and local governments, tribal governments, the Tennessee Valley Authority, Alaska Native Corporations, and rural electric cooperatives.¹¹ For those entities the credit is zeroed out on paper and treated as a tax payment, generating a refund.

Taxable corporations generally cannot elect direct pay. The narrow exceptions are the clean hydrogen production credit, the carbon capture credit, and the advanced manufacturing production credit.¹¹ A for-profit solar or wind developer still needs traditional tax equity or a Section 6418 transfer to monetize its credits.

Recapture Risk Runs for Five Years

Every tax equity deal has to account for the possibility that credits already claimed get clawed back. Under 26 U.S.C. § 50(a), if investment credit property is sold, disposed of, or permanently removed from service within five years of being placed in service, a percentage of the original credit is recaptured as additional tax.⁸ The percentage steps down each year:

Within year one: 100 percent of the credit is recaptured
Within year two: 80 percent
Within year three: 60 percent
Within year four: 40 percent
Within year five: 20 percent

After five full years, no recapture applies. Triggering events include an outright sale of equipment, foreclosure, permanent shutdown, and casualty damage that takes the equipment out of service. Administrative relief may be available when damaged property is repaired and returned to service promptly, or when replacement property is placed in service within six months. Tax equity agreements almost universally include indemnification clauses that shift the recapture risk to whichever party’s actions caused the trigger, usually the developer, since it controls day-to-day operations.

Depreciation Is the Second Benefit Stream

After the credit, depreciation is the other major tax benefit these structures move. Solar panels, wind turbines, and battery storage systems qualify as five-year property under the Modified Accelerated Cost Recovery System, so the owner writes off the equipment cost over five years for federal tax purposes even though the hardware itself lasts 25 to 35 years.¹² On top of that, 100 percent bonus depreciation, permanently reinstated for qualified property placed in service after January 19, 2025, lets the owner deduct the full depreciable basis in year one.

Where the depreciation lands depends on the structure. In a partnership flip, the investor takes nearly all of it during the pre-flip period. In a sale-leaseback, the investor-owner takes 100 percent. In an inverted lease, the developer keeps it. One wrinkle affects every structure: the depreciable basis is reduced by half the investment credit amount. A project costing $10 million with a 30 percent credit depreciates $8.5 million rather than the full $10 million, which is part of why financial modeling on these deals gets complicated fast.

What Closing a Deal Actually Requires

An investor will not fund without a thorough data room, and the volume of documentation is one reason these deals take months to close and carry six-figure legal costs.

The Financial Model

The pro forma projects performance over 20 to 25 years with granular assumptions on production, prices, operating costs, taxes, and debt service. The investor uses it to size its contribution and calculate its return. Aggressive or sloppy assumptions in the pro forma are where deals stall.

Site Control, Interconnection, and Offtake

The developer must show site control through recorded land leases, easements, or deeds that hold for the project’s expected life. A signed interconnection agreement confirms the project can deliver power to the grid. A power purchase agreement with a creditworthy buyer proves the project has a reliable revenue stream. Investors look hard at the buyer’s credit, because the return depends on those payments arriving on schedule for decades.

Tax Opinion and Independent Engineer

A formal tax opinion from a recognized law firm analyzes the structure against IRS rules and case law and concludes that the credits will hold up. Many institutional investors require a “should” or “will” level opinion rather than the weaker “more likely than not” standard. An independent engineer’s report, typically costing $20,000 to $60,000, verifies the technology, evaluates production estimates, and assesses useful life.

Staged Funding and Closing Timing

Funding usually happens in stages tied to construction milestones. In a partnership flip, the investor might advance 20 percent at the start of construction and release the remaining 80 percent at commercial operation once the project is generating electricity. The commercial operation date triggers everything else: full capital at risk, the credit begins to accrue, and the depreciation clock starts. From term sheet to close typically runs four to nine months, longer for portfolios or first-time developers. After closing, the investor claims the credit on IRS Form 3468.¹³ The developer must also keep records demonstrating ongoing prevailing wage and apprenticeship compliance, because a failure there can retroactively drop the credit from 30 percent to the 6 percent base.

Back-Leverage Debt

Developers often borrow against their interest in the tax equity partnership to stretch their equity, a practice called back-leverage. The loan sits upstream of the project and the tax equity structure. The lender takes a pledge of the developer’s partnership interest rather than a direct lien on the project assets, which remain encumbered by the investor’s senior position. For this to work, the partnership agreement must let the developer pledge its interest without the investor’s consent and let the lender foreclose on that interest if the developer defaults. Cash sweep provisions, which redirect partnership cash to the investor to cover shortfalls or indemnities, are the biggest source of friction. Aggressive sweeps that could take most of the developer’s expected distributions will typically block back-leverage unless scheduled debt service payments are carved out.

1
Office of the Law Revision Counsel. 26 USC 48E – Clean Electricity Investment Credit
2
Office of the Law Revision Counsel. 26 USC 45Y – Clean Electricity Production Credit
3
Apprenticeship.gov. Inflation Reduction Act Apprenticeship Resources
4
Internal Revenue Service. Domestic Content Bonus Credit
5
Deloitte. Deloitte Roadmap – Consolidation – Identifying a Controlling Financial Interest – Section: E.7.1 Overview
6
Internal Revenue Service. Rev. Proc. 2007-65
7
Internal Revenue Service. Rev. Proc. 2001-28 – Leveraged Leases
8
Office of the Law Revision Counsel. 26 USC 50 – Other Special Rules
9
Office of the Law Revision Counsel. 26 USC 6418 – Transfer of Certain Credits
10
Internal Revenue Service. Register for Elective Payment or Transfer of Credits
11
Office of the Law Revision Counsel. 26 U.S. Code 6417 – Elective Payment of Applicable Credits
12
Internal Revenue Service. Cost Recovery for Qualified Clean Energy Facilities, Property and Technology
13
Internal Revenue Service. Instructions for Form 3468