The provision of federal tax incentives for oil and natural gas exploration and production began almost immediately with the passage of the federal Revenue Act of 1913. The Act did not provide explicitly for "intangible drilling costs." Very soon, however, the Board of Tax Appeals determined that taxpayers could choose between capitalizing or expensing intangible drilling expenses. This was statutorily specified in 1916. This first incentive still exists today. "Intangible drilling costs" are the costs for such activities that are incurred in commencing drilling or preparing the development of a well. The purpose of expensing such costs, as opposed to capitalizing them was to attract capital to what was and still is a risky investment. Under current federal law, small independent producers are allowed to expense 100 percent of their "intangible drilling costs." Major integrated producers are allowed to expense 70 percent of the "intangible drilling costs" and to capitalize the remaining 30 percent over a 60-month period.
Over time, a number of federal tax incentives for the oil and natural gas industry have been implemented. The next major incentive (the oil depletion allowance) was instituted in 1926. Percentage depletion is the deduction from a producer's annual gross income of a legally specified percentage (currently 15 percent) of the total value of the oil deposit that was extracted in the tax year.
The following table indicates the major federal incentives and the estimated federal revenue implications of such incentives for federal fiscal 2013.
|Enhanced oil recovery credit||$0|
|Credits for oil and natural gas from marginal wells||0|
|Expensing of intangible drilling costs||3,490|
|Deduction for tertiary injectants||7|
|Passive loss exception for working interests in oil and natural gas properties||9|
|Percentage depletion for oil and natural gas wells||612|
|Domestic manufacturing deduction for oil and natural gas companies||574|
|Geological and geophysical amortization||61|
Source: Congressional Research Service, "Oil and Natural Gas Industry Tax Issues in the FY 2013 Budget Proposal," March 12, 2012
Taxation of crude oil first began in Texas in 1907 when the state imposed a 0.5 percent tax on the market value of oil produced. Taxation of natural gas began in Texas in 1931, initially at a rate of 2.0 percent of the value of production. The state of Louisiana instituted the first natural gas tax in 1910 at a rate of 1/5th of one cent per 10,000 cubic feet of natural gas.
The decision to drill and to produce is primarily based on geological considerations, the current and predicted future price of oil and natural gas, the costs of drilling and production, and the estimates of the potential reserves. Tax rates and tax incentives may also be determinants of the level of activity, or whether drilling will occur or not.
In a 2003 article published in "International Tax and Public Finance," Mitch Kunce presented the following conclusion:
In general, results show that severance tax rate reductions result in a substantial loss of tax revenue, moderate increases in drilling, but little change in reserve additions and production. A key question regarding this general result is: Why does output of oil respond so grudgingly to changes in severance taxes? There appears to be four reasons why this is so.
- First, a reduction in severance taxes offers no direct stimulus for reserve exploration.
- Second, operators do not see the full effect of state severance tax changes because of the many tax base and rate interactions at all levels.
- Third, and in a related vein, a reduction in severance tax rates by 2 percentage-points has only a small impact on the net-of-tax price received by operators.
- Fourth, and most importantly, production of (as contrasted with exploration for) oil is driven mainly by reserves, not by prices, severance tax rates, or tax discounts.
The general conclusion that severance tax changes appear to be unimportant may be problematic to public officials in oil producing states hoping to stimulate local economic activity by lowering such rates. The prospect of modest increases in exploration and production comes at a considerable cost, the loss of substantial state tax revenue that must be offset. Rather, state officials may have the incentive to raise severance tax rates risking little in the way of loss to future oil field activity3.
A January 2014 report commissioned by the State Chamber of Oklahoma Research Foundation and undertaken by the firm RegionTrack, Inc. questioned the method and certain specific findings of the Kunce report. Specifically, RegionTrack analysis found the Kunce study treated well types and well costs as uniform over time and did not differentiate between the production potential and cost-differential of older conventional wells versus modern horizontally drilled wells and deep wells. In other words, the Kunce study was based on obsolete drilling techniques not current drilling practices. However, the RegionTrack report did to some extent agree with the Kunce report on the effects of tax incentives, as shown in this passage:
In the short-run, production changes driven by changes in tax incentives are always likely to be modest. However, only going forward will we be able to form better estimates of the long-run response of oil and gas production to incentives. Although existing research suggests that incentives will produce only marginal changes in future drilling and production activity above what would have taken place otherwise, prior estimates are highly likely to understate the potential effect in the current environment4 .