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News Analysis: The TCJA's Effects on Oil and Gas Investments

Posted on July 23, 2018

The Tax Cuts and Jobs Act contains provisions that will acutely affect oil and gas investments, given the industry’s capital-intensive nature, high leverage, practice of reinvesting earnings, and long project lead times. Future tax planning will take into account the industry’s loss-generating downturn over the past few years, and that industry participants often owed alternative minimum tax.

The corporate rate reduction from 35 percent to 21 percent starting in 2018 was a major boon for all industries, but especially for oil and gas companies because the TCJA (P.L. 115-97) left mostly intact the tax benefits they enjoyed. Key unchanged items include the election to deduct intangible drilling and development costs (IDCs), the availability of percentage depletion, and the publicly traded partnership (PTP) rules. Deduction of IDCs and percentage depletion have long been considered crucial for the oil and gas industry.

However, the TCJA often gives with one hand and takes with the other, as it did with rules forbidding net operating loss carrybacks and limiting interest expense deductions. Also, the repeal of the section 199 domestic production activities deduction, a provision used by oil and gas companies in all subsectors, will reduce the benefit of lower tax rates for companies generating qualified domestic production activity income.

The TCJA’s reduction in tax rates and repeal of the corporate alternative minimum tax will cause the oil and gas industry to reconsider how it structures its entities and revisit its practices regarding percentage depletion, tax credits, and IDC. Further, specific references to oil and gas activities in some international provisions of the TCJA could cause disparate treatment of industry participants, depending on the activities that generate their profits.

NOLs and Interest Expense

Under TCJA section 172, NOLs can no longer be carried back if generated in tax years ending after December 31, 2017. They can be carried forward indefinitely but can shelter only 80 percent of taxable income. NOLs generated in tax years ending on or before December 31, 2017, won’t be subject to the 80 percent limitation, but can be carried forward only 20 years, not indefinitely.

Oil prices declined from over $100 per barrel in late 2014 to below $30 per barrel in early 2016, so losing the ability to carry NOLs back to previous years will have a large effect on the industry. Many companies generated NOLs in the last few years, and the carryback provisions allowed some to use NOLs to get refunds of tax paid in profitable years. Prices have slowly risen and currently hover at just over $70 per barrel, which could encourage the use of indefinite NOL carryforwards allowed under the new rules.

Loss of the ability to carry back an NOL is one of the bill’s more damaging aspects and could require more analysis regarding deducting IDCs versus capitalizing them.

Section 163(j) limits the net interest expense deduction to 30 percent of adjusted taxable income, or income before interest; the NOL deduction; the section 199A passthrough deduction; and (until 2022) depreciation, amortization, and depletion. Disallowed interest is carried forward indefinitely. That change will reduce the benefit of the lower tax rate for companies with high leverage.

Beginning in 2022, adjusted taxable income will be decreased by depreciation, amortization, and depletion, thus making the 30 percent threshold lower. Disallowed interest deductions may be carried forward.

Section 199A Passthrough Deduction

Taxpayers hold oil and gas investments individually, as well as in C corporations, partnerships, and S corporations. The 20 percent deduction under section 199A for passthrough entities will affect taxpayers whose projects are structured as partnerships owned by large private equity groups, private investors, and families. Limits on the ability to take the deduction contain terms or conditions particularly relevant to the industry. For example, the deduction is limited to income from a qualified trade or business, which doesn’t include a specified service trade or business. Engineers are not considered engaged in a specified service trade or business, so petroleum engineers should qualify for the deduction.

Further, the section 199A deduction is limited to the lesser of 20 percent of qualified business income, or the greater of 50 percent of Form W-2 wages from the qualified trade or business, or the sum of 25 percent of those wages plus 2.5 percent of the unadjusted basis immediately after acquisition of all qualified property. Qualified property means tangible depreciable property, prevalent in the industry, but does not include depletable assets, which often make up a large portion of an oil and gas company’s balance sheet.

Although the TCJA doesn’t list it as excluded investment-type income, it’s reasonable to conclude that mineral royalty income is excluded from section 199A, given its classification as investment-type income in other parts of the code.

The section 199A deduction is calculated at the partner or shareholder level, not the partnership or S corporation level. Separately stated items determined at the owner level, such as IDCs and depletion, will affect the deduction. The deduction will also affect each owner’s outside basis in its partnership interest or stock.

The TCJA gives favorable treatment to PTPs, which often house energy investments. PTPs are generally treated as corporations for tax purposes. There is an exception, however, if at least 90 percent of the PTP’s income is qualifying income, defined in section 7704(d)(1)(E) and accompanying regs to include income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including via pipelines), or marketing of any mineral or natural resource, as well as the storage of oil, gas, and some other fuels.

The TCJA gives PTPs more favorable section 199A treatment than other partnerships in two ways. First, as noted, to qualify for the section 199A deduction, a trade or business generally must be paying Form W-2 wages or have depreciable assets if its taxable income exceeds a threshold, but PTP income is eligible for the deduction without those requirements. Second, although it’s unclear whether section 751(a) gain on the sale of a partnership interest is eligible for the section 199A deduction for partners in partnerships other than PTPs, PTP partners can claim that benefit.

Oil and gas taxpayers must consider whether a reduced rate is best achieved by taking the section 199A deduction in a passthrough entity, or transferring their investments to a C corporation and using the 21 percent corporate rate.

Excess Business Loss Limitation

Before the TCJA, three sets of rules limited a passthrough owner’s ability to deduct business losses from other income. The aggregate amount of deductible losses for a tax year is limited by tax basis limitation rules (sections 1366 and 704), at-risk rules (section 465), and passive activity loss rules (section 469). Disallowed losses are suspended and carried forward indefinitely until the taxpayer has more amounts at risk or more passive income, or disposes of the interest in the passthrough entity. If the loss isn’t limited by those rules, it may be applied against the shareholder’s or partner’s other income.

TCJA section 461(l) imposes another loss limitation on a noncorporate taxpayer’s ability to use a passthrough loss against other income that’s applied after the basis limitation, at-risk, and passive loss rules. Section 461(l)(1)(B) limits an individual’s deduction of excess business losses, or the excess of business deductions over business income, to $250,000 (single) or $500,000 (married), with the remainder carried over as an NOL separate from other NOLs. That rule will affect individuals who actively manage their oil and gas businesses and were previously able to offset their other income with business losses. Tax planning strategies in response to section 461(l) include capitalizing IDCs or restructuring passthrough entities as C corporations.

Section 469(c)(3) specifies that a working interest (as opposed to a royalty interest) in an oil and gas well is not a passive activity. All net losses are active income and can be offset against other forms of income, subject to the limits in section 461(l).

Bonus Depreciation

Section 168(k) allows taxpayers to expense 100 percent of the cost of qualified property, which is depreciable under section 168 with recovery periods of no more than 20 years. Tangible drilling costs, lease and well equipment, pipelines, and other new or used tangible personal property can be fully deducted when acquired and placed in service after September 27, 2017, and before January 1, 2023. Full expensing is gradually phased out between 2023 and 2027, which might encourage mergers and acquisitions to be structured as asset transactions, allowing the acquirer to immediately deduct a large portion of the purchase price and generate NOLs.

As with the section 199A deduction, however, goodwill and oil and gas properties aren’t considered qualified property eligible for full expensing under section 168(k). Bonus depreciation is also disallowed for property primarily used to transport gas or steam by pipeline if its rates are subject to specific regulatory oversight (the regulated utility exception).

Repeal of Corporate AMT

Because industry-related items like IDC deductions, percentage depletion, and some tax credits were AMT preference items, many companies historically have paid corporate AMT, making its repeal highly favorable for the oil and gas industry.

Oil and gas expenditures are generally classified as IDCs or tangible drilling costs. Tangible drilling costs pertain to the salvageable actual direct cost of the drilling equipment and must be depreciated over seven years when section 168(k) bonus depreciation expires. Taxpayers can still elect to expense or capitalize IDCs over 60 months. In the past, deducting IDCs often made taxpayers liable for AMT.

Treas. reg. section 1.612-4 provides that an IDC is any cost incurred that in itself has no salvage value and is incident to and necessary to drill wells and prepare them for the production of oil and gas (such as wages, fuel, repairs, hauling, and supplies). Equipment, facilities, or structures not incident to or necessary to drill wells (such as storage, pumping equipment, and flow lines) must be capitalized and depreciated.

With corporate AMT repeal, taxpayers might be able to benefit more from deducting IDCs. Integrated oil and gas companies that have marketing or retail operations, however, will still be required to capitalize 30 percent of IDCs ratably over 60 months.

AMT repeal will also benefit taxpayers eligible for percentage depletion. Taxpayers were generally limited to cost depletion only for AMT purposes, but were allowed to deduct the higher of cost or percentage depletion for regular tax purposes. Therefore, many companies owed AMT as a result of percentage depletion being a preference item.

Percentage depletion under section 613A is a concern mainly for small oil and gas producers, because it’s allowed only for independent producers and royalty owners. It’s calculated by applying a 15 percent reduction to the taxable gross income of a productive well. The reduction is determined on a property-by-property basis and is limited to the taxpayer’s first 1,000 barrels of oil (or 6,000 mcf of natural gas) produced per day. It’s also capped at the net income of a well and limited to 65 percent of the taxpayer’s net income.

Further, taxpayers will now be able to claim a refund of 50 percent (100 percent beginning in 2021) of AMT credits if they exceed regular tax. That limit applies only to credits that exceed the corporation’s tax liability, not to their use against income tax liabilities for tax years beginning in 2018.

Predictably, the TCJA repealed the election to claim a refund of prior-year AMT credit carryovers in lieu of claiming bonus depreciation beginning in 2018. Previously, C and S corporations were allowed to claim a refundable and accelerated AMT credit under section 168(k)(4) instead of taking bonus depreciation, and taxpayers taking the credit had to recover the cost of their bonus depreciation property using the straight-line method over the modified accelerated cost recovery period.

Finally, the research and development credit could become more relevant for companies that couldn’t benefit from it because of their AMT profile. Many companies didn’t bother to identify R&D activities because the credit didn’t reduce AMT. Companies can now fully benefit from qualified activities, with a new requirement to amortize all R&D expenditures over five years, effective in 2021.

The TCJA also leaves in place the conventional energy tax credits for enhanced oil recovery and the production of oil and gas from marginal wells.

The TCJA didn’t repeal the individual AMT, so individuals who own interests through a partnership or S corporation will still need to treat IDC deductions, percentage depletion, and some tax credits as preference items, creating yet another reason to revisit entity ownership structures.

International Provisions

Oil and gas companies typically don’t have intellectual property in low-tax jurisdictions, but they could still be subject to the new tax on global intangible low-taxed income under section 951A. GILTI is gross income over a 10 percent return from tangible depreciable assets, excluding effectively connected income, subpart F income, high-taxed income, dividends from related parties, and section 907(c)(1) foreign oil and gas extraction income. If prices are high, companies could be affected because their foreign income will exceed the 10 percent return on tangible property, but only if the income is not already subject to high foreign tax.

The foreign-derived intangible income (FDII) regime in section 250 preferentially taxes profits that exceed the 10 percent return on U.S. tangible assets allocable to products or services used or consumed outside the country and could benefit U.S. companies that export oil and gas. As with GILTI, oil and gas extraction income as defined in section 907(c)(1) is exempt, but only if the extraction income is domestic, not foreign.

Section 907 contains foreign tax credit rules for foreign oil and gas income. It defines combined foreign oil and gas income as the sum of foreign oil and gas extraction income and foreign-oil-related income. It defines oil and gas extraction income to include income derived from the extraction of minerals from oil or gas wells, or the sale or exchange of assets used in the trade or business of extracting minerals from oil or gas wells.

The TCJA also removes foreign-base company oil-related income (FBCORI) from subpart F. Defined in section 954(g), FBCORI includes oil-related income described in sections 907(c)(2) and (3).

Removing FBCORI from subpart F means companies will no longer need to track FBCORI, which won’t be excluded from the GILTI regime. As noted, section 907(c)(1) oil extraction income was never included in subpart F, and is neither punished by the GILTI regime nor rewarded by the FDII regime.

Miscellaneous Changes

Effective December 31, 2017, section 1231 like-kind exchanges are limited to real property. There’s no official guidance yet, but operating and nonoperating interests in oil and gas reserves generally have qualified as real property. However, oil and gas machinery and equipment will no longer qualify, which is important because industry like-kind exchanges commonly include a mixture of real and personal property.

Domestic oil and gas companies will be largely unaffected by the transition tax, unless they earn income from foreign production by controlled foreign corporations in low-tax jurisdictions. The transition tax is 15.5 percent of earnings held in cash, cash equivalents, and other short-term assets, and 8 percent for earnings invested in illiquid assets, like property, plant, and equipment — a distinction that could affect a company’s transition tax amount in the unlikely event the tax is owed.

Oil and gas companies owned by foreign entities or with major foreign operations may be forced to pay the section 59A base erosion antiabuse tax. Base erosion payments don’t include costs of goods sold, some amounts paid for services, and some derivative payments. Excluding cost of goods sold and service amounts will exempt many of the payments made by sector companies, but the provisions governing treatment of insurance and reinsurance premiums will affect the oil and gas industry.

Conclusion

The capital-intensive nature of the oil and gas industry and its asset mix results in large bonus depreciation and depletion costs, and its highly leveraged nature yields significant interest deductions. The practice of reinvesting earnings in new projects produces balance sheets heavy on tangible, depreciable assets. Long lead times from new projects postpone positive revenue.

The business environment may generate large deductions without enough income to absorb them when oil and gas prices are low. Moreover, the environment changes depending on what activities a taxpayer conducts within the industry cycle (generally acquisition, exploration, development, production, and disposition).

All U.S. corporations engaged in oil and gas activities, whether for export or for domestic consumption, and whether U.S. or foreign owned, will benefit from AMT repeal and the corporate tax rate reduction. Whether a corporation is affected by the GILTI or FDII regime will partly depend on whether it conducts extraction versus some other oil- and gas-related activity. Investments held by individuals or passthrough entities will face limits on their section 199A deductions, excess business losses, and AMT preference items like IDC deductions, percentage depletion (for small producers), and tax credits. Both corporate and passthrough taxpayers will benefit from bonus depreciation and suffer from limits on NOL carrybacks, and interest deduction limitations.

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