Power up on energy industry tax strategy


2024 energy tax planning guide


The Inflation Reduction Act (IRA) is the gift that keeps giving. Originally estimated by government scorekeepers to offer nearly $300 billion in energy tax incentives, that figure has risen to well over $500 billion, thanks to favorable interpretations from the IRS.


The IRA is clearly a boon for renewables, but political considerations forced lawmakers to spread the benefits even more broadly. There are significant incentives geared toward traditional energy.


“Energy companies of all stripes will benefit from the IRA,” Grant Thornton Global Head of Energy and Natural Resources Bryan Benoit said. “There are valuable new opportunities for all types of players in renewables and oil and gas on everything from storage and transportation to generation, extraction and refining.”


The IRA gave taxpayers novel new ways to monetize credits so that energy companies don’t need to be taxable to benefit. Some of the credits are refundable, while others can be sold to other taxpayers. The rules are complex, however, and there are important restrictions on the ability to transfer credits. This can complicate financing projects and create risks.


Headshot of Bryan Benoit

“There are several different options for utilizing the credits, all of which have advantages and disadvantages.”

Bryan Benoit

Grant Thornton Global Head of Energy and Natural Resources

“There are several different options for utilizing the credits, all of which have advantages and disadvantages,” Benoit said. “Traditional tax equity financing structures may still provide the most benefits on some projects. It’s important to understand all the options and model out the various scenarios.”


It’s not all good news. The new energy credits also come with significant new requirements, including prevailing wage and apprenticeship rules that have never before been applied to tax credits. Financing decisions will also be affected by macroeconomic factors and several related tax changes. Money isn’t cheap anymore. High interest rates, a byproduct of efforts to battle persistent inflation, can change the economics of some energy projects and investments.

On top of that, changes built into the tax code created a stricter limit on the ability of energy companies to deduct interest from their debt. And that’s not the only deduction that became less favorable. Energy companies are now required to capitalize and amortize research costs. In addition, bonus depreciation fell to 80% for property placed in service in 2023, which means taxpayers can no longer fully expense investments in new equipment.


“Energy companies need to look at the whole picture when making financing and investment decisions,” said Grant Thornton Partner, Tax Services Michael Osina. “The recent tax changes interact with each other and other items on the tax return in important ways and can really affect the return on investment.”


The IRS is also pursuing compliance initiatives, with an unprecedented $60 billion in special funding that it’s planning to use to step up enforcement efforts, and it could target many of the tax structures commonly used in energy projects.


As 2023 closes and the new year begins, it’s an ideal time for energy companies to assess their business plans and identify key tax planning considerations.


Cost of borrowing


The era of cheap money is over. Although inflation has eased, debt is still significantly more expensive than many investors in the oil and gas and alternative energy sectors have become accustomed to over the last several years. Interest rates are changing how energy companies think about funding investments with borrowed money and the tax implications should be part of that assessment.


Investments in oil and gas ventures have their own unique options for financing, including using equity in a publicly traded partnership structure.


The rising interest rates, in combination with a change in tax law, are making it more difficult for energy companies to get a deduction for their interest expenses. The deduction for net interest expense was generally limited to 30% of adjusted taxable income under Section 163(j) of the Tax Cuts and Jobs Act. Previously, adjusted taxable income was similar to earnings before interest, taxes, depreciation and amortization (EBITDA). For tax years beginning in 2022 or later, depreciation and amortization must be included, lowering adjusted taxable income to an amount more similar to EBIT. The change can be particularly relevant for companies pursuing capital-intensive energy projects. Although taxpayers can carry forward their unused interest deductions, the 30% limit will continue to apply, so projections can be effectively permanent for some companies.


Headshot of Michael Osina

“The interest deduction and its limit can affect many other items on the return. Modeling is the key to unlocking planning opportunities.”

Michael Osina

Grant Thornton Partner, Tax Services

“You can’t look at the cap on interest deductions in a vacuum,” Osina said. “The interest deduction and its limit can affect many other items on the return. Modeling is the key to unlocking planning opportunities.”


There is some bipartisan interest in reversing the new tax rules legislatively, so pay attention to Congress this winter. Assuming legislative efforts fail, there may be planning alternatives. Taxpayers may have opportunities to reduce the amount of interest expense subject to Section 163(j) by allocating interest to the research and development, production, construction or acquisition of a wide range of tangible and intangible property. Once recharacterized to another asset, the interest becomes part of the cost of that asset and is recovered using the accounting method applicable to that item. For example, if interest is recharacterized to a fixed asset, it would be recovered through depreciation deductions. See our previous article for a more detailed discussion.


How interest is allocated can affect how quickly the cost is recovered. It’s important to model out interactions to see what levers can be pulled to achieve the best tax result. 



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Research and equipment recovery


The bigger challenge for both traditional and renewable energy investments may be the changes to deductions for research and tangible property. For tax years beginning in 2022 and later, domestic R&E costs under Section 174 must now be amortized over five years instead of expensed. Since a midyear convention must be used, this effectively reduced the deduction for these domestic R&E costs in 2022 by 90%. Foreign R&E must be amortized over 15 years.


Many taxpayers hesitated to address the change in the hope that Congress would reverse it legislatively. Congress may make another attempt at legislation before year-end, but most taxpayers were finally forced to implement the changes when filing 2022 returns. So energy companies should have completed the significant work of identifying R&E costs under Section 174. With compliance out of the way and assuming no further law changes, it’s time to go from defense to offense and look for planning opportunities.


The IRS released important guidance on how to apply these rules just weeks before tax returns were due for many 2023 calendar-year taxpayers. The guidance offered insight into several important areas, including the interaction with long-term contracts under Section 460, the definition of software development, the treatment of research performed under contract, and cost-sharing arrangements. Taxpayers should analyze the new rules, which are proposed to be applicable for tax years beginning after Sept. 8, 2023. Some of the rules provide favorable results, while others could present challenges and compliance burdens.


Even more painful for energy companies, the ability to deduct their substantial investment in new projects using bonus depreciation is also shrinking. Property placed in service this year can no longer be fully expensed and is instead eligible only for 80% bonus depreciation, with the rest of the cost recoverable over the normal depreciable period. This treatment is scheduled to worsen over time and is scheduled to disappear entirely in 2027.


“Losing the ability to immediately deduct 40% of the cost of investments can change the economics of some energy projects, particularly with financing structures that seek to monetize depreciation,” said Grant Thornton Managing Director, Strategic Federal Tax Services Tracey Baird. “Fortunately, there are tax planning opportunities to mitigate the impact.”


An analysis to identify costs that can be considered repairs has always been valuable when looking at structural property that doesn’t qualify for bonus depreciation. With bonus depreciation at 60% next year, this repairs analysis could also significantly accelerate the cost recovery of other types of property. Energy companies can also consider a broader cost segregation analysis, which identifies costs eligible for recovery as property with a shorter depreciable period. This effort can be paired with Section 163(j) planning to accelerate the recovery of any related interest expense.



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Credits and incentives

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“The credit rules are complex and overlapping. It’s critical for energy companies to understand the broader picture.”

Tracey Baird

Grant Thornton Managing Director, Strategic Federal Tax Services

More than $500 billion in energy incentives are available for a broad range of activities throughout both the oil and gas and renewable sectors. The opportunity is unprecedented, but it does not come without challenges. There are many restrictions and requirements that companies must meet to enjoy the full benefits offered by the credits, and substantiation and documentation will be important.


“The credit rules are complex and overlapping,” Baird said. “It’s critical for energy companies to understand the broader picture and evaluate different options for claiming and monetizing energy-related tax credits.”



Carbon capture credit


The IRA supercharged a credit for capturing and permanently sequestering carbon oxide under Section 45Q. The credit rate is based on the amount of carbon captured during the 12 years after the capture equipment is placed in service. The rate depends on how the carbon is sequestered, which can include use as tertiary injectant in a qualified enhanced oil or natural gas recovery project, permanent geologic storage, or another commercial use or process that permanently prevents it from escaping as emissions.


“The credit may be a valuable incentive for a variety of businesses with different roles in the oil and gas sector, including refineries, pipelines and wells where the carbon can be stored,” Baird said.


Only the taxpayer that captures the carbon and has physical or contractual responsibility to ensure the disposal or utilization of the carbon can claim the credit. So taxpayers participating in the process chain of capturing, compressing, treating, processing, liquefying or pumping the carbon emissions should ensure the economics of the tax benefit are reflected in their agreements.


The credit is generally refundable for the first five years, and afterward can be transferred to an unrelated party for cash.



Clean hydrogen production credit


New Section 45V offers a tax credit for the production of clean hydrogen at rates on a sliding scale based on an analysis of the lifecycle emissions. The energy industry is already making significant investments into hydrogen production in anticipation of the credit, but major questions remain on how the IRS will apply the lifecycle emissions analysis.


There is debate over the concept of “additionality” and how producers can offset any emissions created during the production process. The industry is pushing for flexibility to use energy certificates or power purchase agreements, while some environmental groups are arguing for more stringent requirements that would only allow clean electricity from newly built plants or some time and geographic matching mechanism. Energy companies in this space should make sure they are pushing regulators for the most beneficial and appropriate result.


The IRS missed a statutory Aug. 16, 2023, deadline to issue guidance, which could now come at any time. Energy companies considering a project should monitor the situation closely. There may also be opportunities to segregate production “facility” from hydrogen storage property and separately claim the Section 48 credit for hydrogen storage. The credit is generally refundable for the first five years and afterward, it can be transferred to an unrelated party for cash.



Renewable credits under Sections 45 and 48


Investment in renewables is exploding. The IRA enhanced and extended the two tax credits generally available for projects generating energy from renewable sources such as wind, solar, geothermal, biomass, solid waste, hydropower, waste energy recovery and biogas. For most types of property, taxpayers can choose between the two credits. The production tax credit under Section 45 offers a credit based on the amount of electricity produced for the first 10 years after the property is placed in service. The investment tax credit under Section 48 allows taxpayers a credit based on the cost of placing property in service.


“It’s important to understand which types of projects qualify for which tax credits and to model out the alternatives,” Baird said. “Section 48 has also been expanded to include new categories such as biogas property and stand-alone thermal or energy storage.”


Bonus credit rates are available for projects in certain geographic locations or for projects that meet domestic sourcing thresholds. The domestic sourcing rules are complex and will require taxpayers to obtain detailed information from suppliers on direct costs.


Neither credit is refundable except for tax-exempts, though taxpayers can sell the credits to unrelated parties for cash. Taxpayers may also have opportunities to monetize renewable sources through renewable energy certificates or other agreements with businesses that need to certify or establish clean energy use.



Section 48C and 45X credits


The IRA expanded the credit landscape to offer new participants with different roles in energy projects direct benefits for the first time. Section 45X offers a new credit for manufacturers that make wind, solar and battery components in the U.S. or refine a long list of minerals. The credit is available for 10 years after a facility is placed in service and is refundable for five years.


The Section 48C credit is available for an even broader range of activities across both the traditional and renewable energy sectors, including for placing in service or manufacturing components of energy and fuel storage systems, carbon capture equipment, clean vehicle parts and charging infrastructure, grid modernization property, energy and thermal storage systems, critical minerals, and other conservation technologies.


Headshot of Mike Eickhoff

“Companies that believe they have a qualifying project [for Section 48C credits] should study the criteria and collect the material, as commercial viability and speed to market are important priorities.”

Mike Eickhoff

Grant Thornton Managing Principal, Credits & Incentives

Unfortunately, taxpayers must apply to receive a portion of a limited allocation of Section 48C credits, and the first round of allocations is already in process.


“The next round of applications will likely open up sometime in 2024,” said Grant Thornton Managing Principal, Credits & Incentives Mike Eickhoff. “Companies who believe they have a qualifying project should study the criteria and collect material, as commercial viability and speed to market are important priorities. In the 2023 round, competition for funding remains fierce, and the same is expected for 2024.”


Prevailing wage and apprenticeship rules


All the credits generally require taxpayers to satisfy prevailing wage and apprenticeship rules or forfeit 80% of the maximum allowable credit. The rules generally require a minimum wage for certain workers on a project and a minimum percentage of hours to be performed by qualified apprentices. Similar rules have long been imposed on infrastructure projects receiving federal funding but have never before been applied to tax credits. There are exceptions for some projects under 1 megawatt or that began construction before Jan. 29, 2023.


The rules will add significant costs to projects and impose major compliance burdens. Taxpayers will not need to submit certified payroll records, as required by the DOL for infrastructure projects, but they should have a similar process to track and monitor compliance and incorporate substantiation requirements into agreements with contractors and subcontractors. Penalties for any failures can be steep.



Monetizing energy credits


Energy companies will be able to benefit from the credits regardless of whether they are in losses or have tax to pay. Three of the new energy credits are fully refundable for three years, while the rest can be transferred to unrelated parties for cash. The ability to sell credits is a novel concept in the federal tax space, and the market will be large and active. There are significant restrictions on transfer transactions that can limit flexibility and create risk. The payment for a credit transfer must be made between the first day of the tax year in which the seller transfers the credit and the due date for making the transfer election. This means taxpayers can’t “pre-sell” the credits for upfront financing. Energy companies should evaluate and model various transfer options against tax equity financing arrangements.


Traditional tax equity financing structures may still provide more benefits on some projects because of the ability to offer the money up front, monetize depreciation, and achieve a step-up in basis to fair market value. But a transfer may be an easier and more cost-effective transaction in some cases.


The buyer of a credit retains significant risk if the IRS audits and disputes the amount of the credit or if there is recapture from a change in ownership. Buyers and sellers will need to manage risk with indemnification clauses, insurance and documentation to support the credit claim. The credits are complex and energy companies will need to substantiate the underlying qualifications, including compliance with prevailing wage and apprenticeship rules and domestic sourcing.



R&D tax credit


The R&D credit remains one of the most valuable tax incentives available to both the traditional and renewable energy sectors, particularly as new technologies emerge from the IRA.


The credit is even more valuable with the new requirement to amortize R&E costs under Section 174 because many companies discovered they had qualified activities for which they had never previously taken the credit due to not identifying the research activities. Additionally, some taxpayers may no longer need to reduce either their R&D credit or the amount recovered under Section 174.


Section 280C(c) long required taxpayers to reduce their deductions under Section 174 by the amount of any R&D credit or to reduce the R&D credit by the tax effect. The Tax Cuts and Job Act amended Section 280C(c) so taxpayers only need to reduce their capital account for future Section 174 expenditures to the extent that any R&D credit exceeds the deduction for those costs. For many energy companies, the deduction will exceed the R&D credit, meaning they can claim the full R&D credit without a reduction in the ability to recover Section 174 costs. Taxpayers should monitor this issue; however, as the IRS has not yet issued guidance on interpreting the new statutory language.


The R&D credit is one of the most heavily audited issues by the IRS, and the scrutiny underscores the need for taxpayers to properly document and substantiate their R&D credit claims. The IRS has won several recent cases based on the failure of taxpayers to establish that “substantially all” of the development activities constituted elements of the process of experimentation or that there was not sufficient uncertainty from the outset.


“Energy companies should consider a full R&D credit study,” Baird said. “Some of the taxpayers who lost recent cases could potentially have preserved partial credits under the 'shrink-back rule' if they had provided the documentation to apply their analysis to subcomponents of a project that the courts found did not qualify as a whole.”


A comprehensive R&D credit study would not only assess whether the energy company maintains detailed records to the extent available, but also explore whether there are missed opportunities in areas identified by the need to capitalize Section 174 expenditures



Fuel credits


The IRA has not yet upended the current fuel tax credit regime. The pre-existing credits for alternative fuels and for blending biodiesel remain in effect but are scheduled to be replaced by technology-neutral versions in 2025.


The IRS is actively auditing fuel credit claims and the related income tax treatment of the credits. At issue is whether taxpayers must either reduce deductions based on fuel tax liability or include their refundable fuel tax credits in their income. The IRS has generally agreed that when there is no actual excise tax liability, a purely refundable fuel tax credit does not reduce any deduction for fuel or create any addition to income. When there is actual fuel tax liability, however, the IRS argues that the credits must first offset this liability and reduce the deduction for tax expense (or cost of goods sold) or be included in income.


The IRS has won a string of cases based on its position. Taxpayers have yet to win a case on the issue despite six different courts taking it up. The good news for blenders of biodiesel is that despite the losses, there may be ways to structure around the issue. Blenders who do not incur excise tax themselves but instead sell the fuel within the system before it leaves the rack may not have excise tax to net against the credit. This means the credits potentially do not need to be included in income and would not reduce any deduction. Careful consideration of the structure and business reasons behind it may be important, as the IRS is likely to look at the issue.



IRS enforcement


Energy companies should expect elevated scrutiny from the IRS over the next few years. The IRA provided the IRS with $80 billion in new funding, and over 50% is earmarked for enforcement. The debt limit deal included a handshake agreement to reallocate $20 billion of that money to other spending priorities, but $60 billion is still a staggering sum compared to normal IRS funding. It represents more than four years of annual appropriations based on recent IRS funding levels and it comes on top of regular annual funding with no restrictions on when it can be spent.


The increased enforcement may come more quickly than some taxpayers expect. The IRS has already significantly expanded its workforce in the last two years and is actively recruiting 3,700 new auditors. Much of the activity will be focused on partnerships, which have seen a dramatic decrease in audit rates over the last several years, but it may affect many other issues and business entities.


Energy credits will be a prime target because of the monetization options. The last time the IRS offered grants in lieu of energy credits (the Section 1603 program), it became a major focus for compliance efforts.



Next Steps


The energy space is changing rapidly. Energy businesses should make sure they’re proactively addressing all the new challenges and seizing any tax planning opportunities presented by new and generous incentives. As companies close out 2023 and head into 2024, it’s the ideal time to reassess project plans and consider the tax implications and monetization options. 



Tracey Baird

Tracey Baird is a Managing Director in Grant Thornton’s Strategic Federal Tax Services (SFTS) practice, a dedicated team of experienced tax professionals who focus on certain areas of federal tax law where appropriate planning can help clients achieve significant savings.

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