There is likely no more misunderstood or misrepresented issue in the petroleum industry than the existing tax treatment for oil and gas producers. To better understand the existing tax structure; here is a breakdown of each mechanism working to incentivize drilling for sustainable domestic energy, jobs, and much needed revenue.
Last year marked the 100th birthday of a tax treatment that allows companies to attract capital and recoup investments in oil and gas exploration and production, similar to R&D deductions for every other industry in the marketplace.
Intangible Drilling Costs, or IDCs, are an accelerated deduction that applies to 60-80 percent of the costs an operator incurs on the development a well. Those costs include surveying, site preparation, repairs, and labor costs; everything put into the ground, and not relating to benefits reaped from the ground. Generally, IDCs do not include items which are part of the acquisition price of an interest in the property. IDCs apply to producers, royalty owners, and all parties with a working interest in the tract or parcel of land under lease, who invest in the development of a well.
Typically, for income tax purposes, costs that yield benefits over time are not capitalized and recovered in the year they are incurred, but over periods when revenue is generated; in the petroleum industry, the revenue generation period occurs when a well produces oil or natural gas. IDCs are treated differently because not all wells drilled produce a return, and in some cases, drilling yields only a dry hole.
Investors’ ability to either expense or capitalize IDCs makes formation capital available for new exploration and production. Drilling is always a gamble, even with the best available information from geologists and geophysicists. The treatment of IDCs incentivizes continued investments in an otherwise risky business.
If an election to expense IDCs is made, the taxpayer deducts the amount of the IDCs as an expense in the taxable year the cost is paid or incurred. If IDCs are not expensed, but are capitalized, they may be recovered through depletion or depreciation, as appropriate. The election to deduct IDCs applies only to those IDCs associated with American properties.
E&P companies can claim up to 100 percent of costs spent during the year, but integrated companies are only allowed to deduct 70 percent of IDCs initially, with the remainder covered over the subsequent five years. This treatment favors smaller companies, those who rely largely on outside investments, more so than larger companies. Independent producers drill 90 percent of American natural gas and oil wells, and the top 50 companies reinvest 150 percent of their cash flow back into American projects.
IDCs are not a tax credit, a public expenditure, or government spending outlay.
Eliminating the ability to deduct expenses which are a part of the necessary start-up costs would put the brakes on economic recovery through energy expansion, while increasing taxes, thwarting investments, reducing payments to royalty owners, decreasing federal revenue, and killing thousands of American jobs.
In 1926, Congress passed an accounting standard to address the closure of oil and gas businesses across the country, and to spur investment in the robust development of American natural resources. Prior to this, the only deduction for mineral resources was cost depletion, which did not provide sufficient opportunity for smaller, independent businesses to retain revenues to keep up with well costs. What Congress created was in essence value depletion, known today as the Percentage Depletion deduction.
Percentage depletion is a tax allowance that honors the recovery of monetary investment over time. Not a subsidy or a tax credit, this cost recovery mechanism extends beyond oil companies as a deduction for investors and royalty owners to incentivize capital formation. Similar to depreciation, percentage depletion allows an owner or operator to account for the reduction of a product’s reserves. Like a cup of coffee, wherein with each sip the drink becomes less valuable, a well too depreciates as fluid minerals are extracted.
The costs associated with maintaining wells is high, including maintenance, disposal of water, and electricity costs to run pumping units. The revenue retained by the percentage depletion deduction is essential to meeting costs. For larger wells, percentage depletion provides more revenue to be used on exploration and development of new wells.
The recovery standard is figured using a rate of 15% of the gross income from the property based on average daily production of domestic crude oil or natural gas up to the depletable quanitity; generally 1,000 barrels of oil, or 6,000 mcf of natural gas multiplied by the number of barrels of depletable oil quantity. To claim depletion on both oil and natural gas, depletable oil quantity (1,000 barrels) must be reduced by the number of barrels used to figure depletable natural gas quantity.
The depletion deduction is limited to 65% of net taxable income. Taxable income from the property is gross income from the property minus all allowable deductions (except any deduction for depletion or domestic production activities). Gross income from the property does not include lease bonuses, advance royalties, or other amounts payable without regard to production from the property. Percentage depletion in excess of the 65% limit may be carried over to future years until it is fully utilized. The net income limitation requires percentage depletion to be calculated on a property-by-property basis, and prohibits percentage depletion to the extent it exceeds the net income from a particular property.
Anyone with an economic interest in mineral property, either through an investment in mineral deposits, a contractual relationship, or by legal right to income from extraction, can take a deduction for depletion. A production payment retained on the sale of mineral property does not qualify as an economic interest. More than one person can have an interest in the same mineral deposit, and this is nearly always the case. The depletion deduction is divided between the lessor and the lessee (mineral owner and producer). It may be taken only by independent producers and royalty owners, and not by integrated oil companies.
Integrated companies are engaged in many facets of the industry, including exploration, production, refinement and distribution of oil and gas. Integrated companies typically have global operations. Many of the largest oil and gas companies are integrated.
Nearly all of America’s oil and natural gas wells (90%) are developed by independent petroleum producers like those keeping Montana’s Hi-line energized in the North Central part of the state. The majority of America’s oil wells produce less that 15 barrels per day, classifying them as marginal wells or “stripper” wells. Yet these wells account for a fifth of total American oil production. Nearly 75% percent of American natural gas wells are marginal wells, producing approximately 12% of domestic natural gas.
While other countries shut down smaller operations, marginal wells make up a unique and prominent sector of the oil and gas industry in Montana and the rest of America. In total, there are over 300,000 stripper gas wells, and 300,000 stripper oil wells in production.
Marginal (stripper) wells are economic multipliers for local and state budgets. For every $1 million directly generated by stripper well production, more than $2 million in economic activity is generated elsewhere. Each additional $1 million of stripper well production employs 10 workers directly and indirectly, with some producers employing as many as 15 workers. If all marginal wells were abandoned, 292,374 individuals would lose their jobs. In the oil and gas industry alone, the effect of abandonments is $5.3 billion in lost worker earnings and 83,000 potential jobs lost, according to the National Stripper Well Association.
Historically, independent producers invest more than their cash flow back into projects. And despite limitations, percentage depletion plays a significant role in keeping America’s marginal wells producing, and is a vital accounting mechanism for the country’s independent petroleum companies, investors, and mineral owners alike.
Geologic & Geophysical (G&G) costs are the expenses associated with exploring for oil and gas, including surveying. Currently, independent producers are allowed to recover domestic G&G costs over two years, though a proposal has been made to extend that period by 5 years.
Preserving the deduction for G&G costs incentivizes the use of costly technology, including 3-D seismic surveys, which improves rate of discovery for oil and gas by 50-80% (according to IPAA), and reduces surface impact significantly by providing producers with information to improve odds of drilling economic wells on the first attempt.
Tertiary injectants refer to material injected into older reservoirs to help continue production and/or revitalize dormant petroleum production. Under §193, a taxpayer is allowed to deduct qualified tertiary expenses in the year injected, as opposed to amortizing the deduction over the lifespan of the resource field. The process for which tertiary injectants are used is known as Enhanced Oil Recovery (EOR).
Montana has a CO2 EOR project currently in progress in the Belle Creek oil field, which the Dept. of Commerce claims “will add 35 million barrels and 20 years of production to the oil field,” by capturing carbon dioxide and injecting it into old, stagnant oil wells.
CO2 EOR is a cost effective means to safely and securely capture large quantities of industrial CO2, making the §193 deduction a vital incentive for high cost carbon capture projects which not only have the potential to increase our domestic oil production, but will reduce emissions of CO2 into the Earth’s atmosphere.
The Montana Department of Commerce explains, “EOR and hydraulic fracturing or frac’ing has been responsible for the recent oil boom in the Bakken shale play, creating more jobs and increased revenue for the state of Montana.”
Oil prices are volatile. These tax credits, EOR and marginal well credits, support continued domestic production when production might otherwise not be economical.
Because credits are only used when oil prices are low, there is a built in mechanism to phase out the credit when prices increase.
Eliminating these credits would disregard the cyclical nature of oil prices and penalize marginal or tertiary production when prices are depressed and domestic production (according to the American Petroleum Institute).
Petroleum manufacturers are the first to buy crude oil and natural gas from the global market, they are especially vulnerable to fuel price volatility.
The LIFO (last in, first out) accounting standard has been permitted by the IRS since 1939, and is used by nearly 40% of businesses to determine book income and tax liability. LIFO is used by a variety of industries, including publicly-traded and privately-held companies, manufacturers, wholesalers, retailers, automobile and equipment dealers, and petroleum refineries.
The Montana Petroleum Association agrees with the American Petroleum Institute, which claims that repealing the LIFO accounting standard for refiners would reduce jobs across American industry, and reduce investments in domestic energy production. This would increase U.S. reliance on imports and cause money to leave the American economy.
Businesses forced off LIFO would pay, essentially, an assessment against capital to the federal government, without regard to current earnings or other factors.
Repealing LIFO would require companies to redirect cash or sell assets in order to cover the higher tax payment. For small businesses, the LIFO reserve could exceed retained earnings, likely forcing a business to liquidate and possibly still owe taxes.
In order for U.S. companies to compete globally and develop opportunities abroad, The United States tax code affords U.S. based companies a foreign tax credit (FTC) for taxes already paid on income in another country. Simply put, this mechanism prevents double taxation on foreign profits. The credit is provided only for income taxes paid to another country, not property taxes, severance taxes, mineral royalties, or other payments.
The United States requires that the federal corporate tax rate on income earned is 35%, regardless of where income is earned – domestically or abroad.
If dual capacity provisions are repealed, 70% of corporate earnings would be claimed by the combination of U.S. and foreign corporate taxes, according to the Peterson Institute for International Economics, and the Progressive Policy Institute.
Section 199 is a deduction equal to 9% of income earned from manufacturing, producing, growing or extracting in the United States, and is available to every taxpayer who qualifies in the U.S. Petroleum is the only industry limited to a 6% deduction.
The Montana Petroleum Association is concerned about the direct impact on Montana jobs that changes to Section 199 would result in. The refining sector in Montana primarily resides in Yellowstone County, with three of the state’s four refineries located in Billings. Refining in Montana provides over 1,000 jobs, with average wages over $90,000. According to Dr. Scott Rickard at the Center for Applied Economics at MSU-Billings, refining contributes more than 50% of Montana’s entire manufacturing capabilities.