The One Big Beautiful Bill Act, recently signed into law, made an interesting tweak to the tax structure of energy projects: It reinstated developers’ ability to deduct the total cost of their capital expenditures from their taxable income in the year they made those expenditures. 

This provision, known as “full expensing” or “100 percent bonus depreciation,” was actually part of the 2017 Tax Cuts and Jobs Act, although subject to a phaseout schedule. Its permanent reinstatement at 100 percent allows developers to speedily write off their costs—particularly in contrast to writing off their costs using the Modified Accelerated Cost Recovery System (MACRS—pronounced “makers”) depreciation schedule, where annual deductions are either spread evenly across the project’s useful life or, for certain categories of property, frontloaded somewhat to “accelerate” the asset’s loss of value relative to its useful life. Most clean energy developers can use a truncated MACRS schedule to depreciate their assets over five years (far shorter than the useful life of an energy project).

It is generally better for developers to write off their asset completely as soon as possible through full expensing—thereby lowering their immediate tax bill and allowing them to instantly recycle more revenue—than to write off their asset piecemeal, which doesn’t allow them to recycle as much revenue. It’s also capital-efficient thanks to the “time value of money,” where market actors use a discount rate to treat future cash flows as less valuable than present ones. 

Accelerated depreciation is like an interest-free loan against a notional pot of money that represents your capital expenditures.¹ After investing in the project, you reduce your tax burdens by slowly drawing from this notional pot of value until it is “fully depreciated,” at which point your tax bill goes back to reflecting your project’s income.

It would be natural to think that power generation projects are some of the biggest beneficiaries of these policies. After all, they are large capital investments. They are big enough that the pot of money that could theoretically be expensed in a short time is huge. However, power generation developers often cannot take full advantage of these depreciation schemes because, to draw on this virtual loan, you have to deduct it against taxable income in that tax year—and many energy, infrastructure, and manufacturing projects often have little to no taxable income in their first years of operation. If you’re making no taxable revenue in the first year of your operation, you have no tax liability to write off regardless of how much you spent that year on capital expenditures. The ability to monetize depreciation thus becomes a “nonrefundable” benefit: A taxpayer cannot claim the benefit above and beyond their taxable income. This is a common problem in tax policy.

Taxpayers with more depreciation benefits than tax liabilities can get some relief by carrying forward their net operating losses (NOLs). In other words, they can apply any unused tax benefits to future tax years in which they have a positive tax liability. However, this comes with a cost. While taxpayers can carry forward their losses indefinitely, they can only apply those losses to 80 percent of the next year’s taxable income. “Time value of money” considerations mean that, even if those losses could be applied to the year’s entire income, they would still be worth less than the value of depreciation benefits monetized in the year that they occurred. 

This is why, before the Inflation Reduction Act, energy project developers had to engage in “tax equity” deals to transfer their tax benefits to entities with lots of free cash and large tax bills—usually large banks—in exchange for an injection of low cost equity into a project through a partnership structure that owned the special purpose vehicle that held the underlying asset. A tax equity investor would make a profit on the deal by making another implicit loan—they would invest less equity into the project than the total tax benefits they received.² Tax equity allowed developers to monetize their accelerated depreciation benefits alongside their tax credits. The American Council on Renewable Energy (ACORE) estimated that, in 2023, monetizing accelerated depreciation added as much as 10-20 percent to the value of a tax equity transaction.

The Inflation Reduction Act created two other mechanisms for monetizing energy tax credits that remain after OBBBA: tax credit transferability and elective pay.  Transferability allows a developer to sell their tax credits directly to third parties without relying exclusively on complex “tax equity” partnership schemes. Elective pay allows entities that do not pay taxes—governments, governmental instrumentalities, and nonprofits in particular—to receive a cash payment from the IRS for the implied value of the tax credits they would earn from an eligible energy investment. Elective pay credits are therefore akin to a “fully refundable” benefit insofar as they don’t require developers to claim any taxable income. (Private entities can access elective pay for certain tax credits—but not the tech-neutral ITC or PTC).  However, both transferability and elective pay apply only to tax credit benefits, leaving depreciation unmonetized.

The popularity of transferability transactions suggests that the various costs of tax equity (e.g., legal fees, deal structuring, potential recourse to developer long-term profits, massive investor spreads on the value of tax benefits) can be far higher than the benefits of tax equity, including the monetization of depreciation.³ (If you are a developer, the tax equity partner is essentially charging you interest to help you take out your own loan, further raising the effective interest rate on the upfront capital you’re borrowing relative to the alternative where you can claim the whole value of your credit upfront, without a discount.) By 2024, the two-year market for transferable tax credits had grown to $25 billion, relative to $20 billion in tax equity deals, precisely because these transactions were cheaper to participate in. Some energy developers have also begun to engage in “hybrid tax equity” deals where they create tax equity partnerships to monetize depreciation and then resell the tax credit on the transfer market.⁴

All of which is to say: Whether energy developers are using full expensing or the conventional five-year MACRS depreciation schedule, it is nearly impossible to capture the full value of depreciation. Full expensing is not going to be as much of a tailwind for energy project investment as it may have initially seemed. ⁵

But Congress could fix that. Legislators should make depreciation for all energy related projects both fully refundable and eligible for elective payment—making depreciation accessible in full to all energy developers regardless of their tax status.

This change allows developers to easily monetize the value of their legal tax benefits, uncorrelated to their tax liabilities, via a fiscal transfer—and allows the public to benefit from increased economic activity from more rapid capital expenditure, insofar as developers can recycle a greater portion of their tax benefits into future investment.⁶ This is exactly why some business groups advocate for full refundability in the first place! Making depreciation fully refundable and elective pay-eligible makes sense for energy assets in particular because of how important energy supply and stable electricity prices are to the overall economy—to consumers, to industrial sectors such as construction and manufacturing, and to the broader service economy, including healthcare and retail.

Beyond boosting overall investment, full refundability can significantly improve the liquidity of individual energy projects.  By putting more capital back in the hands of developers faster, it makes projects more bankable to lenders and early equity co-investors. Early cash flows from fully refundable and accelerated and/or fully expensed depreciation can provide a significant source of financial certainty and collateral value to lending institutions.

Expanding the benefits of fully refundable depreciation to elective-pay eligible entities would also reduce the discount that investors charge when monetizing elective pay for public and nonprofit energy projects.⁷ Already, public entities cannot monetize depreciation by writing it off of their taxable income, because they don’t pay taxes! At least 49 million Americans are public power customers—many of them living in rural, harder-to-service areas—and strengthening elective pay is crucial for making sure that these public developers can continue to invest in upgraded energy systems while continuing to deliver savings to consumers. It would be unfair for large swaths of Americans if their utilities and their developers had unequal access to these benefits.

Finally,  full refundability and elective pay for depreciation significantly helps clean energy projects.⁸ Clean energy projects—especially for renewable energy and battery storage, but also for grid infrastructure like transmission lines—are significantly more capital-intensive than their fossil counterparts. A large portion of the total cost of developing a clean energy project consists of upfront capital expenditures, particularly because these projects have extremely low operations and maintenance costs over their lifetimes. On the other hand, a greater share of the lifetime costs of generating electricity from oil and gas comes from operations and maintenance and fuel costs. The ratio of upfront to total costs is crucial: If you apply the same tax benefit to clean energy and fossil projects with identical total costs (and holding electricity sale prices constant), the total return to the clean energy project after the benefit is applied is far higher than its fossil counterpart. In practice, this means the clean energy project can either charge customers a lower price and make the same returns as the fossil project, or crowd in more investor capital with a promise of higher returns. 

CPE has modeled below how full refundability would help project developers. Using a sample project with $2 million in depreciable basis, no other costs, with an operating life of 20 years, with annual revenues of $150,000 that increase by 5 percent annually, and with no tax credits, we calculate the project’s post-tax internal rate of return (IRR) under three different depreciation schedules: straight-line depreciation over 20 years, 5-year accelerated depreciation as permitted under MACRS, and full expensing as reinstated by the OBBBA. Our model demonstrates that project developers’ IRRs rise noticeably when they can monetize the full value of their depreciation. Developers using 5-year accelerated depreciation would see their IRRs rise from 7.79% to 8.27% if they had access to full refundability—an increase of about 6 percent. Using full expensing, developers’ IRRs would rise from 7.72% to 8.61%—an increase of about 11.5 percent! Indeed, full expensing without full refundability has such a high absorption loss that it becomes less useful for a developer than the 5-year accelerated depreciation option! These differences might seem small at first, but even a 50-basis point difference in a project’s IRR can make or break its bankability.

In the wake of OBBBA’s energy tax credit rollbacks and the Trump administration’s regulatory attacks against clean energy project development, policymakers should look for other ways of sustaining capital investment into the clean energy sector. Improving access to the value of full expensing for energy projects is a rare policy that is bipartisan thanks to its tech-neutral application, keeps money flowing into the sector, and disproportionately benefits clean energy resources and innovative energy technologies. Climate advocates should seriously consider the political advantages of leveling the playing field through a policy that extends the full refundability and elective pay of depreciation benefits to all energy projects.

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1. Or even a loan with a negative interest rate, if you account for inflation. ↩︎
2. Typically tax equity deals also entitle the investor to some of the project’s profit, but far less than implied by the actual cash investment. ↩︎
3. Another forgone benefit of tax equity transactions is the “basis step up” which allows the project’s taxable and depreciable basis to increase via re-valuation during the transaction, raising the value of the tax benefits. ↩︎
4. The regulation, terms, and value of hybrid tax equity structures are extremely specific to certain sectors and deal types due to their nascency. ↩︎
5. The capital recycling enabled by full expensing, its primary advantage for tax payers with their own immediate tax liability, may also make it more complex and expensive to monetize depreciation under tax equity transactions due to investors’ need to maintain the value of their stake within the project partnership structure that is required to access the full value of the tax credit and depreciation benefits. Refilling this account in large upfront increments lowers the investor’s target returns, which it can compensate for by requiring a higher percentage of the project’s future post-tax income. ↩︎
6. The energy tax credits themselves created a constituency of investors and developers who advocated for their protection. This kind of expanded access to depreciation benefits could further support this constituency. ↩︎
7. A related policy proposal is to extend elective pay to private entities as well, allowing them to receive tax credit value as a cash payment independent of their tax bill. This concerns tax credit design more broadly and is thus beyond the scope of this note.  ↩︎
8. Geothermal energy has a slightly worse version of the problem we are describing. Geothermal developers have legal access to the “intangible drilling cost” deduction—made for oil and gas drillers—allowing them full expensing of “intangible” labor and services costs from their taxable income, but they cannot use it because most intangible drilling costs will be incurred years before a project is placed in service and earns taxable income. Employ America, which has described the problem with the “intangible drilling cost” deduction at length, suggested that Congress should make this deduction, too, transferable or refundable: “Making the credit transferable or refundable would allow developers with little or no current tax liability to receive a direct payment from the government, equivalent to the tax credit’s value, providing immediate cash flow when it is most necessary—during exploration and well-field development.” ↩︎