Tax Breaks for Oil

There is a lot of smoke being generated these days about the supposedly unfair “tax breaks” for the oil industry. A lot of this discussion is a textbook example of “spin”. And a lot of it depends for its effect on the presumed ignorance of its audience regarding the oil and gas business.

It is worth looking at the facts. Here is a summary from Associated Press, as published in the Thursday, May 12, 2011 Seattle Times:

The tax breaks at a glance

A look at the main tax breaks and how they benefit the oil-and-gas industry:

The biggest is called the domestic manufacturing deduction, a 2004 tax change meant to encourage companies to manufacture in the United States. Companies of almost any type are allowed to deduct from taxable income up to 9 percent of profits from domestic manufacturing. Oil-and-gas companies were classified as manufacturers, but their deduction was capped at 6 percent. This provision is expected to save the oil-and-gas industry $18.2 billion over 10 years.

Another subsidy, established in 1913 to encourage domestic drilling, allows oil companies to deduct more quickly all of the so-called intangible costs of preparing a site for drilling. To accountants, intangible costs are for things that have no salvage value when the well runs dry, i.e. clearing land and pouring concrete. A business ordinarily would deduct these costs over the life of the drilling site. Instead, small, independent drillers can deduct all these expenses in the first year; major, so-called integrated companies such as Exxon Mobil can deduct 70 percent in the first year. The break is worth $12.5 billion over 10 years.

A 1926 rule that establishes how oil companies can depreciate the value of their wells allows drillers to deduct 15 percent of the well’s revenue from taxable income. The cost of an oil or gas well would be depreciated over the well’s life under a more traditional depreciation scheme. The tax break was created in part to simplify accounting, so companies wouldn’t have to guess how long an oil or gas field would produce. It can be a boon: Total deductions over the life of the well sometimes can be bigger than what the company spent. This provision was eliminated for major oil companies in 1975, but it continues for independent producers. The break is worth $11 billion over 10 years

This is one of the clearest statements I have read regarding these tax rules.

First, note that the domestic manufacturing deduction, the biggest deduction of all, is not specific to the oil and gas business; in fact, the benefit to the oil business is capped at a lower rate than that for other manufacturers!

How can that be called an unfair break, unless it is actually unfair to the oil business? To call this deduction a break for the oil business is spin of the purest sort, the kind of thing which should be held up as a bad example in high school debating class.

Another key point is generally ignored in the public debate over tax breaks for the oil industry.

In both the cases of depletion and expensing of intangible drilling costs, the tax  incentives are provided for independent (i.e. not integrated) oil producers. For the major oil companies such as ExxonMobil, these incentives are not available or are capped. This point is rarely mentioned, since most consumer anger is directed at the majors. Wherever you see the phrase “integrated oil and gas producers”, read “major oil companies”.

Therefore, eliminating these “tax breaks” would hurt smaller, independent domestic producers, who produce about 1 million barrels a day, but have almost no impact on the other 19 million or so barrels of domestic US consumption.

Lastly, and most important, these tax deductions were not cooked up out of stone soup; they represent standard accounting practices as applied to mineral production.

Uncertainty

Now, before going any farther, it is worth making a point which is easily missed in the glib discussion of how many billion dollars these “breaks” are worth, and in most discussion of the oil & gas business.

The oil business is highly uncertain.

When you drill a well, you just don’t know beforehand if it is going to produce or not. Of course, there is geological data leading you to be optimistic, or you wouldn’t be drilling at all, but the reality is that up to 90% of new wells are dry. In my own company’s experience over the last decade, about half of the wells in which we have invested have come up dry, and that is in spite of a lot of factors pushing the success rate up: for example, the large number of reentries, where the odds are as good as they get. (In a reentry, you already know going in what the original driller found; there have been a lot of potential reentries in recent years, because the barrel price was so low in the 1990s that many low-producing wells were not economically viable and had to be abandoned).

Another thing you don’t know is whether the market price will be adequate to allow you to profit. Sure, these are good times now. But in the 1990s, when the barrel price was around $10, it still cost domestic producers $30-$40 to produce that barrel. There is a reason why an entire generation left the oil business.

So a lot of the criticism of oil business “tax breaks” ignores the elephant in the room – all those failed drilling attempts and all those wells which produced but were not economic at low barrel prices. It is a classic example of the “fan-in” fallacy, better known as “20/20 hindsight”. The oil business survivors have done very well indeed, but a balanced discussion must also recall those who lost everything when the market was down and/or their geological data proved incorrect.

Intangible Drilling Costs

Expensing of intangible drilling cost (IDC) is derived from the generally-accepted accounting principle that mandates an immediate write-down of costs of a failed enterprise. In the case of a dry hole, to demand anything other than immediate expensing of all unrecoverable costs (IDC) would fly in the face of such an accounting principle. That’s why IDC is often called “dry hole cost”.

I don’t know exactly how the Associated Press calculated its figures for the worth of each kind of deduction. I assume that the reporter obtained Treasury data regarding the total national amount for each type of deduction. If the data simply totalled all IDC deductions, without regard to whether the well in question produced or not, then the actual revenue which could be recovered by repeal of the IDC deduction  would be a small fraction of the amount claimed.

And even successful producing wells can and often do go dry unexpectedly. This is especially true of small, marginal reservoirs. Once a well went dry, all its costs would have to be expensed.

So, yes, it would be technically possible to demand that IDC be written down over time, as opposed to expensed immediately; large, integrated producers are required to do so. However, the number of exceptions would be large and the complexity of the accounting would be daunting.

Making the accounting even more complicated is the possibility of secondary and tertiary recovery. These are technologies, such as water and CO2 flooding, and hydraulic fracturing (“fracking”), which allow additional production from a well which would otherwise have run dry.

Percentage Depletion

Let’s look at percentage depletion. When any company, oil or otherwise, pays for an asset with a useful life extending over a number of years, standard accounting practice is to write down a fraction of the cost of that asset each year. This is termed depreciation. Depletion is akin to depreciation, but applied to natural resources (the term of art is “wasting assets”).

Integrated producers (the ExxonMobils of the world) are required to use cost depletion, writing down a fraction of the original acquisition, exploration, and production cost every year, until the full original cost is written down. Independent producers are allowed to deduct 15% of revenue for production up to 1,000 barrels a day; this allowance continues indefinitely.

If such a well is operating at breakeven, it will recover its costs in approximately 7 years. Therefore, it is possible, if prices are high and a well produces for a longer time, for the producer to receive more in deductions than paid out in original costs. Sounds like a great deal, doesn’t it? Well, there are few problems.

Even if a well produces, you really don’t know how long it will produce. You also don’t know when you will need to employ secondary and tertiary recovery techniques to extend the productive life of the well. 7 years is actually a pretty good run for a small well.

And, needless to say, you don’t know what will happen to oil prices in that time.

Again, I do not know the calculation technique used in the AP report. However, it is clear that the value of the percentage depletion allowance is highly dependent on the current market price per barrel of oil and on the average lifetime of small wells. Furthermore, general accounting principles would mandate some form of cost recovery in any case. Therefore, the estimate for the amount of tax revenue which could be recovered by elimination of percentage depletion must be highly speculative.

If you mandate cost depletion for all wells, then drillers of small wells, which are more likely to go dry quickly, face a difficult business decision if well production falls before the original cost has been fully amortized. If the original costs were significant, there might be a perverse incentive to plug and abandon (“P & A”) wells which could otherwise continue to produce under secondary recovery.

There is no question that percentage depletion is a great incentive to produce marginal wells in a boom time, when the barrel  price is high. In some such cases, the value of the tax deduction may be greater than the original capital cost. However, the producer is still taxed each year based on 85% of revenue, and in a down year for barrel prices, or with a well which goes dry in less than 7 years, the  cost recovery may be less than the full original cost. It’s a risky business.

Conclusion

I hope that I have shown that the apparent “tax breaks” for the oil industry are neither as pervasive nor as arbitrary as critics have claimed. They are not as beneficial to the major oil companies as they are to small independent producers, and their replacement by different accounting methods would unquestionably increase the complexity of tax preparation and auditing, and reduce incentives for the large fraction of domestic production which comes from independent oil companies, while providing an uncertain increase in tax revenues.

Appendix: CBO Report

The following quote is from the Congressional Budget Office (CBO) 1986 Report on Reducing the Deficit (Spending and Revenue Options). Italics below are mine.

Percentage depletion allows firms to deduct a certain percentage of the gross income from a property as depletion, regardless of the firm’s actual capitalized costs. For example, nonintegrated oil and gas companies are allowed to deduct 15 percent of their gross revenue from their first 1,000 barrels per day of oil and gas production each year, regardless of their capitalized costs. (Integrated oil and gas producers are required to use cost depletion for recovering capitalized costs.)

Mine development costs and oil and gas drilling costs are also immediately deductible, except in the case of integrated producers. Under the Deficit Reduction Act of 1984, the Congress limited expensing of producing wells for integrated oil and gas producers to 80 percent of intangible drilling costs, with the remaining 20 percent deducted over a 36- month period.

The current tax treatment of mineral properties has been criticized because many of the preproduction expenses of mineral properties can be deducted faster than the value of the assets they “produce” declines. For example, drilling expenditures by oil companies produce assets (that is, producing wells) that gradually decline in value as oil reserves are depleted. The tax code, however, allows firms to deduct most of these costs in the year incurred. Moreover, percentage depletion often allows firms deductions in excess of their original investment. In some cases, percentage depletion (in present-value terms) is even more generous than immediate expensing of all depletable costs.

The result of these provisions is that mineral producers face effective tax rates that are lower than statutory tax rates and, for many producers, lower than effective tax rates on other industries. This tax advantage could be mostly eliminated by replacing the current set of provisions for mineral capital costs with a new system of cost recovery that required all expenditures on mineral rights, exploration, development, and drilling to be capitalized. Under this proposal, all producers would be allowed the option of recovering these costs through the current provisions for cost depletion or amortizing them over 10 years (using the 250 percent declining balance method, switching to straight-line depreciation after six years). Expenditures on dry holes, unproductive mines, or worthless mineral rights would, however, still be expensed.

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