Accurate and Honest Tax Accounting for Oil and Gas

Tax accounting for the oil and gas industry does not describe the economic income from the investment. Indeed, for a broad range of reasonable assumptions, oil and gas accounting delivers anti-tax or subsidies to profitable investments. The combination of four important tax preferences generates a subsidy that is a negative 42 percent of real income. The four preferences are the expensing of intangible drilling costs, the pool of capital doctrine, the percentage depletion allowance, and the domestic manufacturing deduction. The subsidy from the combination means that an oil and gas investment can in reality lose more than half of its cost of capital before tax and still be profitable after tax.

Uncle Sam is going to need significant revenue. The Obama administration estimates that the federal budget deficit for 2009 will total $1.4 trillion, or 9.9 percent of gross domestic product.[1] Once the need for short-term stimulus has passed, that deficit must be closed. In the impending revenue crisis, base-protecting revenue provisions that were not possible under ordinary politics become political necessities.

In raising revenue, it is better to go after the low tax and anti-tax transactions before raising tax rates. A tax system does the least harm to the private economy if it is broad, unavoidable, and neutral between investment choices. A broad, healthy tax base allows us to raise the necessary revenue at the lowest feasible tax rates. A broad, least-damaging tax would impose uniform effective tax rates on all alternative investment choices. Investment decisions should be governed, not by tax accounting, but by the real nontax merits of the investments. We need to get the tax accounting right to describe real economic income. Tax accounting is like lab data. We need to keep our laboratory data honest and accurate, no matter how important the experiment.

No one has made a plausible case that a subsidy is needed for oil and gas beyond the wisdom of the laws of supply and demand. The price of oil and gas is high enough to provide sufficient incentive. If more incentive is needed, the price will adjust. Indeed, an increase in the price of oil and gas, if any, would help us conserve energy, and adjust to alternative energy sources and high energy prices in the future. The government should get out of the business of subsidizing oil and gas via the tax system.

None of the tax advantages accorded to oil and gas have ever been subjected even to the scrutiny that we give to government spending. The competitive federal budget is the primary mechanism by which the government applies rationality to the choices of use of resources. Budgeted spending is subject to discipline because government spending is widely criticized. When items are off budget, however, as when they are accomplished through the tax system, the subsidies avoid the budget competition for resources. When Congress allows tax advantages, it does not think of the burdens on the deficit as real money, and the costs incurred, including the tax expenditures for oil and gas, turn out to be irrational. Tax advantages are stealth subsidies and have never been justified by budget analysis or political legitimacy.

The proposal would:

1. Repeal the expensing of intangible drilling costs. Drilling for oil or gas is an investment, properly treated as a capital expenditure. But under current law, the investment is treated as a worthless expense and is deductible when made. Immediate expensing for an investment means that tax does not reduce the pretax internal rate of return (IRR) from the investment. The economic or effective tax rate on a drilling investment has an expected value of zero.

2. Repeal the pool of capital doctrine. Under the pool of capital doctrine, a drilling enterprise may pay many of the costs of drilling by giving out an economic interest in the well, without either the enterprise or the provider of goods or services paying tax. An accounting system can describe real IRR and impose tax at the statutory tax rates only if the adjusted basis of the investment is equal to discounted present value of the investment. Paying for royalties and goods and services with carried interests should be considered to be a taxable exchange of the underlying assets, both to the payer and to the recipient.

3. Repeal the working interest exemption from passive activity loss (PAL) limitations. The Tax Reform Act of 1986 was able to reduce maximum tax rates from 50 percent to 28 percent, but only because the PAL limitations so effectively attacked tax shelters as they were then known. The passive activity limitations remain the most effective of the antishelter tools. The exemption for working interests in oil and gas property should be ended.

4. Limit percentage depletion to basis. Percentage depletion allows the deduction of imaginary costs because it continues even after real costs have been fully deducted. This accounting error was adopted because of an error in identifying ‘‘capital’’ to be recovered as the value of a gold mine when discovered, rather than its much lower cost.

5. Repeal the exclusion for domestic production. Six percent of income from oil and gas extracted in the United States or the continental shelf is excluded from tax. The exclusion is part of the reason why the tax rate on oil and gas investments is negative and why money-losing investments are entered into for the tax benefits.

6. Recover geological and geophysical (G&G) costs under cost depletion. Current law allows the G&G costs of identifying promising properties over two years, but a producing oil deposit found by the surveys can last for 30 years.

7. Repeal the last-in, first-out inventory accounting. LIFO accounting allows a taxpayer to keep in basis the oldest and lowest costs since the inventory accounts began. To reflect economic income, basis should come as close to fair market value as possible. First-in, first-out should be mandated for oil and gas inventories. The Obama administration has proposed eliminating LIFO accounting in its 2010 proposed budget.

8. Repeal the tax credits. There is a 15 percent tax credit for enhanced oil recovery projects and a tax credit of $3 per barrel for marginal wells. Neither credit is now available because the price of oil has risen high enough to give adequate incentive. The credits should be repealed while they have no effect. Indeed the lesson extends beyond the credits: The price of oil is high enough to give adequate incentive. No tax advantages are needed or appropriate.

A. Fundamentals of Tax Economics for Oil and Gas[2]

Oil and gas transactions commonly benefit from a negative tax or subsidy — that is, the IRR is higher for the investment after tax than before tax. This section presents a simple illustration that takes into account four tax preferences: expensing of intangible drilling costs, the pool of capital doctrine, percentage depletion, and domestic production exclusions. In the illustrative investment, tax adds 41 percent to the value of the investment and also allows investments to go forward that destroy over half their cost of capital. All of the tax advantages are subject to conditions and restrictions, which are discussed in the section that follows the example.

1. Soft money investing means tax exemption for drilling. The ability to deduct an investment immediately ordinarily means that tax does not reduce the taxpayer’s pretax return from the investment. Getting into an investment with a deduction or exclusion is ‘‘soft money investing’’ and it means tax does not reduce the amount available. Soft money investing is ordinarily of the same value as the exemption from tax for the profit or gain. This concept is routine to tax economics but is not commonly evident in statutory or judicial decisionmaking.

Assume a taxpayer, described in Table 1, has $100 of income that will be invested in drilling for oil. The investment will triple in some unstated period. The assumed tax rate is 33.3 percent. Exemption of the return is described in Column A of Table 1, and soft money investing is described in Column B.

Column A describes the after-tax result if the investment is capitalized, but the gain from the investment is exempt from tax. Capitalization of the investment is normal in an income tax because an investment is not a loss. Because of capitalization, there is immediate tax on the $100 of income, which reduces the amount available for investment to two-thirds. The amount invested then triples to $200. Our assumption in Column A, however, is that there is no tax on the tripling so that the end result capitalization and exemption in Column A is $200.

An income tax would also ordinarily tax the gain in Column A. Under normal income tax rules, the gain in the tripling, $133.33, would be subject to a one-third tax (or $44.44), which would reduce the after-tax proceeds to

implied by our treatment of debt financing, which gives both a deduction for interest and basis or exclusion for principal. Within an income tax, avoiding the tax on gain is recognized as a benefit.

Table 1. Tripling Is Tax Exempt
(A) Capitalized Investment (B)

Soft Money

Expensed or


1. Income at $100 $100 $100
2. Tax on row 1 at 35 percent -$33 $0
3. Investable amount

(row 1 row 2)

$67 $100
4. Investment (row 3)


$200 $300
5. Basis $67 $0
6. Taxable amount $133 $300
7. Tax at one-third of row 6 Tax exempt -$100
8. End result

(row 4 row 7)

$200 $200

In Column B, the $100 is an intangible drilling cost and the taxpayer is able to deduct the entire cost immediately. Because of the deduction, none of the $100 of income is taxed. The full income of $100 may thus be invested. In Column B there is no exemption for the tripling. Still, the result in Column B is the same, $200, as in Column A with no tax on the profit. Therefore, the ability to expense the investment immediately is as valuable as a privilege of paying no tax on the gain.

Effective tax rate measures how much tax reduces the pretax IRR from the investment.[3] The effective tax rate in Column A is zero because tax does not reduce the tripling before tax, and the effective tax rate in Column B is zero because tax has the same impact as in Column A.

The results of Table 1 can be generalized by algebra, provided the tax rate at the start of the investment (row 2) is the same as at the end (row 7), the pretax return (tripling here) is the same on both columns, and the amount invested is sensitive to the upfront tax cost in row 2:


The equivalence is an application of the commutative law of the multiplication, which says that the order in which (1-t) and (1-0) appear does not matter. The equivalence of yield exemption and expensing is often called the Cary Brown thesis.[4]

The Column B model was set up to describe the portion of the investment qualifying as intangible drilling cost. Column B, however, also describes the results of the pool of capital doctrine, or the results of a mixture of the pool of capital doctrine and expensing of intangible drilling costs. The pool of capital doctrine, as discussed below, allows an enterprise to pay for goods and services put into a drilling venture by giving factor suppliers an economic interest in the well. If the supplier or royalty receiver is willing to take payment for value delivered in the form of an interest in the outcome of the oil well, there is no tax on the venture at row 2, before investment. Capitalized investments, under an income tax regime, require a reduction by tax before the investment may be made (row 2 of Column A, Table 1), but paying with untaxed interests allows enterprise to invest without tax (row 2 of Column B).

A corollary of the Cary Brown thesis is that you can deduce how much tax reduces the pretax interest or IRR by looking to the ratio of adjusted basis to nontax fair market value.[5] Some companies have a tax basis near or above their FMV and thus they pay effective tax rates at or above statutory tax rates. Companies, including oil companies have a basis that is a small fraction of their value and so have modest effective tax rates. The impact of the differential real tax rates throughout the tax system is that tax warps the pretax value of an investment derived from real customer demand, and shifts investment to lower utility projects. The wide divergence in real tax rates, across the system, means that tax is damaging the allocation of capital unnecessarily.

2. Finding economic income.[6] A tax system that imposed the same economic effective tax rate on all investments would reduce the harm that the current system now does to the private economy. Investment decisions should be driven by the real demand and by costs outside the tax system and not by differential tax treatment or tax accounting misdescriptions. ‘‘Effective tax rate’’ is the measure of the impact of tax on IRR7:


IRR is a universal yardstick for comparing diverse investments. It is the interest rate on a hypothetical bank account that is like the investment under examination. The impact of tax on that interest-like IRR is the measure of the real impact of tax, whatever the nature of the investment and whatever the manner or time of computation of the tax or the nominal statutory tax rate. The formula for effective tax rate, above, asks how much tax has dropped the IRR and then takes that drop as a percentage of the pretax IRR. Imposing the same effective tax rate on investments across the economy prevents property from being worth more to highbracket taxpayers than low-bracket taxpayers, and prevents tax from distorting the pretax choice of what is a good investment.

To impose a uniform effective tax rate, accounting must identify the interest-like IRR from the investment and subject it to tax. Tax accounting identifying IRR is forced, for instance, by our treatment of debt, which allows a deduction of interest and respect for the principal of the debt, which is the mirror image of treating the investment as a bank account. A neutral tax accounting that describes and taxes economic income would keep the adjusted basis for an investment equal to the net present value of the investment, using IRR as the discount rate to determine net present value.

Assume, for example, an oil and gas venture has cash flows set to give a 10 percent return over five years in the absence of tax.


The investment gives a 10 percent interest-like IRR per year before tax because the $379 is the present value of the five $100 cash flows at 10 percent under the standard formula for present value of an annuity:


using i (discount rate) of 10 percent and n (number of years) of 5.8

The Cary Brown thesis that expensing is equivalent to no tax reduction of the pretax return can be restated

simply from equation (1) because expensing would both reduce the after-tax cost of the $379 investment by rate T, and tax would also reduce the $100 revenue by T:


Equation (2), the expensing case, becomes identical to the pretax situation, equation (1), when the tax of (1 T) is factored out of both sides of equation (2). The return rate i is the same 10 percent both pretax (equation (1)) and post tax (equation (2)).

If we are to tax the 10 percent return in the investment, by contrast, and reduce the interest by the statutory tax rate, we would have to identify the interest earned every period. Table 2 on the following page analyzes the illustrated investment as if it were a bank account, giving the 10 percent interest rate. All investments are measured as if they were bank accounts because that is the universal yardstick by which very diverse investments are measured.

To identify the interest or IRR, it is necessary to identify the bank account balance on which the interest is calculated and keep that balance as part of adjusted basis. Table 2 assumes an investment of $379 in an oil and gas operation that returns pretax $100 or 10 percent interest a year for five years.

In Table 2, each year the bank account earns interest at the built-in 10 percent interest rate (identified in row 3). But the interest is not enough to cover the withdrawals from the bank account — that is, the cash flow revenue in row 1 — so some part of each withdrawal is a reduction of the bank account balance by the amount of row 4. The row 4 withdrawals in excess of interest reduce the bank account balance to zero at the end of the term. The bank account balance (row 2) is always net present value of remaining revenue at the 10 percent IRR. Depreciation or recovery of basis is the drop in the bank account balance shown by row 4. If we tax the interest income identified in row 2 at 35 percent, the tax system will reduce the IRR from 10 percent to 10% * (1 35%) or 6.5 percent, which is the after-tax income implied by a 35 percent tax on 10 percent interest income. The present values of the aftertax cash flows (row 7) sum to zero showing that the investment, under the tax of row 6, is like a bank account giving IRR or interest of 6.5 percent. Different investments will have different row 1 pretax cash flows, but if the depreciation and adjusted basis describe the income from the investment, the adjusted basis will equal net present value of the future cash flows from the investment at the IRR.

The adjusted basis that will identify the IRR can be calculated from net present value when future cash flows are assumed, as in the illustration, or when there is a broad market that sets a market price using estimates of fundamental value like the Table 2 analysis. More generally, however, the future cannot be known. Tax accounting must use conventions approximating FMV basis to be administrable on a national basis with low audit rates. Still, the theoretical norm of what tax accounting would look like if we did tax the economic income provides a purpose or goal for tax accounting. Accounting rules and

Table 2. Economic Depreciation — Five-Year, 10 Percent Investment
Year 0 1 2 3 4 5
1. Revenue to give 10 percent IRR -$379 $100 $100 $100 $100 $100
2. Adjusted basis, bank account balance, net present value of future revenue at IRR $379 $317 $249 $174 $91 $0
3. Interest at 10 percent on bank account (prior year row

2), also income

$37.91 $31.70 $24.87 $17.36 $9.09
4. Withdrawal in excess of interest earned (aka recovery of basis or depreciation) (row 1 minus row 3) $62.09 $68.30 $75.13 $82.64 $90.91
5. New bank account balance (row 2 minus row 4) $317 $249 $174 $91 $0
6. Tax on row 3 at 35 percent $13.27 $11.09 $8.70 $6.07 $3.18
7. After-tax cash flow (row 1 minus row 6) $86.73 $88.91 $91.30 $93.93 $96.82
8. Present value at found 6.5 percent [row 6/(1 + 6.5%)n]. Row 7 sums to zero at 6.5 percent -$379.08 $81.44 $78.38 $75.58 $73.01 $70.67
Table 3. Internal Rate of Return After Four Tax Preferences

(Intangible Drilling Costs, Pool of Capital, Percentage Depletion, and Domestic Production)

Year 0 1 2 3 4 5
1. Pretax cash flows, set up to give 10 percent IRR -$379 $100 $100 $100 $100 $100
2. Row 1 minus 15 percent depletion allowance $85 $85 $85 $85 $85
3. Row 1 minus 6 percent of row 2 for domestic manufacturing exclusion $80 $80 $80 $80 $80
4. Tax on row 3 at 35 percent $28 $28 $28 $28 $28
5. Expensing of row 1 saving tax at 35 percent -$133
6. After-tax cash flow (row 1 minus row 4 or row 5) -$246 $72 $72 $72 $72 $72
7. Present value at found 14.2 percent IRR (row 6 / (1 + IRR)n). Row 7 sums to zero at found 14.2 percent rate -$246 $63 $55 $48 $42 $37

conventions that leave the taxpayer with an adjusted basis closer to net present value of future cash flows are more accurate than accounting rules and conventions that leave the adjusted basis further away from net present value. The pool of capital doctrine and intangible drilling expensing fail to reflect economic income because they drop the taxpayer’s basis in the investment before the net present value of future cash flows.

3. Combining subsidies: negative tax. Investments in oil and gas can sometimes qualify not only for the upfront soft money investing benefits of expensing and pool of capital doctrine, but also for subsequent exclusions of revenue under percentage depletion and domestic production allowances. As discussed below, section 613 allows independent oil companies to exclude 15 percent of revenues from oil, and section 199 allows taxpayers to exclude 6 percent of earnings from domestic oil and gas production. Assume for Table 3, above, the same pretax investment discussed in Table 2 but assume soft money investing at the outset and the exclusions for percentage depletion and domestic production.

The after-tax cash flows in row 6 of Table 3 have an IRR of 14.2 percent because 14.2 percent will sum the net present value of all the cash flows to zero. The 14.2 percent figure is the interest on a bank account that could give the cash flows equal to those in row 6. Tax has improved the investment from 10 percent before tax to 14.2 percent after tax. The improvement is a negative tax rate or a subsidy of 42 percent of the original income.

Table 3 is undoubtedly a temporary advantage because competitors will move in when the return rate is so high. In equilibrium, returns drop on investments in a competitive economy, so that they have an annual return after tax equal to the cost of capital. Assume some competitor can borrow at 10 percent (same as return rate) and deduct the interest so that after-tax cost of interest is 10% * (1 35%) or 6.5 percent. Table 4, on the following page, shows that given the tax benefits, the competitor can make as little as $87 a year or 4.9 percent return and still have enough to bear the costs of interest. The pretax cash flows in row 1 of Table 4 yield a return of only 4.9 percent annually.9 The investment in Table 4 in making 4.9 percent, loses 51 percent of its real interest cost at 10 percent in the absence of tax. Tax policy has given sufficient incentive to allow a wasteful investment.

Allowing an investment like that shown in Table 4 wastes capital. The assumed cost of capital is 10 percent and the annual return of 4.9 percent wastes 51 percent of the cost. Absent showing of special merit in the budget process, a pretax money-losing investment is a bad investment that should not be made.

If the advantage of a low tax rate or a subsidy from the oil and gas preferences is passed on to customers, customers get a false sense of the true costs of oil and they adapt to the falsely cheap prices by overconsumption. Cheap oil to consumers is especially dangerous now because we rely on foreign sources from dangerous parts makes costs and revenues have the same future value, hence 4.9 percent is the IRR from the investment:

Table 4. Break Even Pretax Cash Flows Given For Tax Preferences

(Intangible Drilling Costs, Pool of Capital, Percentage Depletion, and Domestic Production)

Year 0 1 2 3 4 5
1. Pretax cash flows with a found revenue to yield enough to pay interest cost -$379 $87 $87 $87 $87 $87
2. Row 1 minus 15 percent depletion allowance $85 $85 $85 $85 $85
3. Row 1 minus 6 percent of row 2 for domestic manufacturing exclusion $80 $80 $80 $80 $80
4. Tax on row 3 at 35 percent $28 $28 $28 $28 $28
5. Expensing of row 1 saving tax at 35 percent -$133
6. After-tax cash flow (row 1 minus rows 4 and 5) -$246 $72 $72 $72 $72 $72
7. Present value at debt cost 6.5 percent IRR (row 6 / (1 + IRR)n). Row 7 sums to zero at 6.5 percent discount rate -$246 $63 $55 $48 $42 $37

of the globe for our supply,[10] and because the overconsumption of oil contributes to global warming. Cheap oil undercuts conservation and the development of alternative energy sources. Consumers have to start to adapt to the future when oil will become very expensive, because the adaptation will take considerable time.

If the subsidy from tax preferences for oil is not passed on to customers, the subsidy just contributes to the net worth of taxpayers holding oil interests. Given the desperate need for revenue, a basic sense of fairness suggests that those with the equal ability to pay tax should pay equal taxes whether they are in oil or some other economic activity.

Ending the tax preference subsidies to the extractive industries would improve the efficiency of consumer choices because prices will then reflect real, unsubsidized costs. In a capitalist system, the decisions reached by supply and demand and evidenced in unsubsidized price are presumed to represent the best decisions about use of our limited resources. If Congress decides to subsidize oil and gas investments, it should do so only by way of a

competitive budget process for government spending.

B. Proposed Reforms of Oil and Gas Tax Preferences This section describes the most important tax preferences available for oil and gas investments under current law, the reasons for change, and the remedy proposed.

1. Soft money, upfront benefits.

a. Intangible drilling costs. Under current law, a tures.[12] Costs eligible for expensing under section 263(c) must be costs that cannot be salvaged when the drilling is over.[13] An integrated oil company must reduce its expensed intangible drilling costs by 30 percent and amortize that 30 percent over five years.[14 ] In computing alternative minimum tax, the intangible drilling cost is amortized over five years.[15]

Immediate expensing for an investment, as noted, means that tax does not reduce the pretax IRR from the investment. Combined with other preferences, the tax rate is negative or represents a subsidy. The deduction creates a tax expenditure estimated to be worth $3.5 billion for 2007-2011.[16]

Immediate expensing for drilling costs is inconsistent with generally accepted accounting principles. Under financial accounting and SEC standards, a driller capitalizes the cost of drilling, up to the value of the proven reserves determined under a mandatory standard valuation method. The taxpayer may elect ‘‘full costing’’ or

‘‘successful efforts’’ capitalization.17 Full costing is the broadest capitalization method because it treats all of the costs of program within the country as part of the same effort and ignores the unsuccessful wells within an overall successful program. Capitalized costs, however, cannot exceed the proven reserves from the program, measured by the standardized valuation process. The standardized valuation requires an assumption that the oil and gas will be worth its value at end of the reporting year when it is ultimately extracted and assumes a 10 percent discount rate to compute present value back from the time the oil and gas was extracted.18 The successful efforts method capitalizes costs not on a nationwide program basis, but by looking at each individual well, and it treats the costs of dry wells as expired cost even when the program as a whole is highly successful. Both in capitalizing costs and limiting the basis to value, current GAAP standards are superior to current tax accounting in describing the real economic income from oil and gas investments.

The American Petroleum Institute has argued that drilling costs represent the research and development costs of the oil and gas industry.[19] That position is not consistent with the industry position for GAAP. The soundest explanation for section 174, which allows expensing of research costs, is that section 174 imitates GAAP accounting.[20] Under GAAP, research costs are expensed when made because they are presumed to be worthless or expired costs[21]:

A direct relationship between research and development costs and specific future revenue generally has not been demonstrated, even with the benefit of hindsight. For example, three empirical research studies, which focus on companies in industries intensively involved in research and development activities, generally failed to find a significant correlation between research and development expenditures and increased future benefits as measured by subsequent sales,[22] earnings,[23] or share of industry sales.[24]

The oil and gas industry would have to take the position that its drilling costs are worthless expired costs when made and have no relationship to future revenue to fit within the accounting rationale for the expensing of R&D costs. In fact, drilling costs are capitalized by the industry under GAAP, either under the full costing or successful efforts method.

The proposed remedy here would capitalize the costs of drilling for oil and allow recovery of the cost by cost depletion as the barrels of oil are extracted. Costs of an entire program would be capitalized. Regulations would define the program unit, but the program has to be defined as broadly as possible so that basis comes as close to the FMV as possible. Costs of the entire program would be capitalized even if some of the wells within the program are dry.

b. Pool of capital doctrine. Oil and gas ventures benefit from a low effective tax rate in part because they are able to pay many of the costs of the drilling without capitalizing their costs. As noted, the ability to make an investment out of untaxed soft money is ordinarily equivalent to zero tax on the investment profit. Under the pool of capital doctrine, a drilling enterprise may pay many of the costs of drilling by giving out an economic interest in the well, without either the enterprise or the provider of goods or services paying tax. In 1941 the IRS ruled that when the venture pays the landowner for the rights to explore and develop the deposit and pays the drillers, equipment suppliers, and the investors who contribute materials and services in connection with the development of a mineral property by giving them an economic interest in such property, the receipt of the economic interest does not result in realization of compensation or income. The contributors are viewed as not performing services for compensation or selling goods or inputs, but as making a contribution to a common pool and receiving an interest in that pool in return.[25] The venture is not considered to have disposed of assets of value by giving up the economic interest in the successful deposit. Absent the pool of capital doctrine, receipt of the interest in payment for goods and services would be ordinary income immediately, measured by the value of the interest.[26] Without the pool of capital doctrine, the developer paying with a property interest would also have to recognize gain on the property transferred, measured by appreciation of its cost in the transferred asset over its value.[27] Under the pool of capital doctrine, paying with economic interests does not result in recognition for either the transferor or the recipient.

In 1971 the IRS ruled that the pool of capital doctrine was limited to services and capital related directly to the drill site for which an economic interest was given.[28] The tax planners responded by giving out profits interests in partnerships called carried interests.[29] Giving partnership income interests continues the privileges of nonrecognition to both the transferor and recipient that was allowed under the pool of capital doctrine.30

To impose an income tax at the statutory tax rates on extractive industries, costs would have to be capitalized until the taxpayer’s basis is equal to the FMV of its investment, determined using IRR as the discount rate to calculate future cash flows. ‘‘Income’’ in financial economics is the interest on a bank account that matches the investment under examination. An income tax can identify the interest from an investment, and reduce it by the statutory tax rate, only if the balance of the bank account that describes the investment is equal to the taxpayer’s adjusted basis. Alternatively stated, a tax system can reduce an investment’s pretax income by the statutory tax rate if and only if the taxpayer has an adjusted basis at the end of each year equal to the value of the investment.31

The remedy proposed here would be to treat the exchange of economic interests for goods, services, and the right to drill as taxable to both sides, so that adjusted basis of the investment reaches its value. Paying for royalties, goods, and services with carried interests should be considered a taxable exchange of the underlying assets. Treating the exchange of goods and services for oil interests as taxable is a reform that should be extended outside the oil industry into the imitators who picked up the carried interest idea from the oil patch. But the nontaxation of paying for necessary goods and services started in the oil patch and it can be fixed first in the oil patch.

c. Working interest exemption from PAL limitations. The Tax Reform Act of 1986 reduced tax rates and attempted to end tax shelters as they were then known. In reducing rates and attacking shelters, the act improved the economic efficiency of the tax system. The act would not have been able to reduce maximum tax rates from 50 percent to 28 percent, except that the PAL limitations of new section 469 so effectively contained the use of the artificial accounting losses in tax shelters.[32] The PAL limitations suspend losses from an activity outside the taxpayer’s normal business until the taxpayer reports gain from that and similar activities or until the taxpayer abandons the investment so that the cash in and out can be totaled without relying on artificial accounting. The rule is based on skepticism that normal accounting rules are able to ensure that losses are not artificial. Counting the cash in and out at the end of the transaction measures real losses. If, however, the taxpayer materially participates in the activity, spending more than roughly a quarter of a full-time working year on it, the activity is no longer considered to be a passive activity subject to the PAL limitations.[33]

On enactment in 1986, Congress gave an exemption from the PAL limitations to working interests in oil and gas.[34] A working interest qualifying for the exemption must be burdened with the obligation to share in the expenses of drilling and operations of the oil and gas extraction.[35] The investment vehicle must be a general partnership or co-venture that does not limit the liability of the taxpayer.[36]

Under the working interest exemption, the taxpayer may use the artificial losses generated by the intangible drilling costs without putting in any of the time that material participation would require. The exemption allows outsiders with income they need to shelter, but without any oil mud on their hands, to buy into the artificial losses from oil and gas. Given the plentitude of artificial losses under our leaky tax system, outsiders can buy tax losses for a small fraction of the value of the losses on their tax return.

Tax accounting in the oil and gas area, as illustrated, can generate artificial loss deductions even for ventures that are in fact profitable. The PAL limitations remain the most effective limitations on the use of artificial accounting losses. The PAL limitations are not draconian. They allow losses to be used against the first income from any passive activity including unrelated projects. The limitations have been unexpectedly effective for the last 23 years. The special exemption from PALs for working interests was never consistent with the necessary rationale for PAL limitations. A repeal of section 469(c)(3) is proposed so that oil and gas working interests would be subject to the normal PAL rules.

d. Rapid write-offs for geological and geophysical costs. Under current law, a taxpayer may write off the G&G costs of identifying promising properties over two years.[37] The large integrated oil companies, however, must write off G&G costs over seven years. As a matter of economics, however, the deposits located by the G&G costs can last for 30 years. Using a 3-year straight-line depreciation schedule for a G&G investment on the assumption that it lasts for 30 years means that the effective tax rate (IRR-reducing tax) for the G&G investment drops from the normal 35 percent to 9.45 percent. Table 5 on the following page shows the logic.

The Table 5 spreadsheet assumes a $100 investment that gives an annuity with 10 percent return over 30 years

Table 5. Impact of Three-Year Amortization on Effective Tax Rate
Year 0 1 2 3 4... 30
1. Pretax cash flows, set up to give 10 percent IRR -$100 $10.61 $10.61 $10.61 $10.61 $10.61
2. Minus amortization of cost over three years -$33.33 -$33.33 -$33.33 0 0
3. Taxable income -$22.73 -$22.73 $22.73 $10.61 $10.61
4. Tax on row 3 at 35 percent -$7.95 -$7.95 -$7.95 $3.71 $3.71
5. After-tax cash flow (row 1 row 4) -$100 $18.56 $18.56 $18.56 $6.90 $6.90
6. Present value at found 9.05 percent IRR (sums to zero) -$100 $17.02 $15.61 $14.31 $4.87 $0.51

(row 1). The columns for years 5 through 29 are dropped out of the presentation but they are identical to the column for year 4 (except for present value).

The present values in row 7 sum to zero, proving that 9.05 percent is the after-tax discount rate on the investment. The statutory tax rate (row 4) is 35 percent, but a tax that reduces the IRR from 10 percent to 9.05 percent has an effective tax rate of (IRRpretax IRRposttax)/IRRpretax or here, (10% 9.05%)/10% or 0.95%/10% or 9.5%. The logic is the same as shown in Table 3.

Using a 7-year straight-line schedule for G&G costs that last 30 years reduces the effective tax rate from the 3 percent statutory tax rate to 15.4 percent.38 In combination with other benefits accorded to oil and gas, the short amortization schedules contribute to an increase in the negative tax subsidy or anti-tax inappropriately awarded to oil and gas.

Under the proposal, G&G costs would be allocated to the deposits of oil and gas successfully discovered by the taxpayer and affiliates over the following three years, according to the relative size of the proven reserves. No deduction would be allowed for the three years after the G&G costs are incurred, and the costs would be allocated to proven reserves of oil at that time. The point of exploration costs is not the dry wells, although they happen, but rather the successful wells. An exploratory or wild cat program might hit oil in only 1 out of 10 drillings and yet the costs of the 10 wells, including the dry attempts, are well justified by the deposits that are ultimately found. The costs allocated to a deposit would be recovered by cost depletion, which allows the recovery as barrels are extracted.

A simplification would be to allow the taxpayer to elect to recover the costs over 50 years or 2 percent of G&G costs per year. This is a longer period than the deposits found might well last, but taxpayers should be able to achieve simplicity as long as simplification is achieved without shifting the tax burden to other tax-payers.

2. Unwarranted exclusions.

a. Percentage depletion allowance.

Under the percentage depletion allowance, the holder of an economic interest in oil may exclude from tax 15 percent of its revenue from the extraction of oil. Percentage depletion is disguised as a means for recovery of capital, but the exclusion does not depend on cost or basis, and the 15 percent exclusion continues even after all the taxpayer’s basis has been fully recovered. Moreover, in oil and gas drilling, the taxpayer’s basis in the economic interest for which percentage depletion is allowed has commonly already been fully recovered or mostly recovered because of prior expensing under intangible drilling costs, the pool of capital doctrine, and short period amortization. Percentage depletion is commonly a double deduction of costs already deducted. Farmers and ranchers who allow their land to be probed in return for a royalty interest in a successful well rarely have any basis for recovery against their royalty incomes because their cost of land can be allocated against royalties only if they bought the land while knowing of and paying for the oil deposits.[39]

Service providers who receive interests not taxed under the pool of capital doctrine have no basis in the economic interest they receive for their services. A continuing 15 percent exclusion is an important part of the negative tax subsidy for oil extraction because of the already low basis and because the exclusion continues after basis has been fully recovered.

The percentage depletion allowance arose out of an early misperception that the capital that had to be recovered to calculate income was the discovery value of an oil deposit rather than its cost. Sen. David Reed of Pennsylvania was the floor manager of the 1925 act that created percentage depletion, and he argued that if he discovered a gold mine, basing depletion on cost ‘‘would not allow me an adequate return on my ‘real capital.’’’[40] ‘‘Real capital’’ meant to Reed the extraordinary value of the gold mine, not the invested costs in the gold mine. Reed’s error also fit within an existing conceptual framework early in the income tax, under which it was commonly thought that to compute income, one had to subtract the value of property as of the commencement of the period under consideration, rather than just its cost.[41] In fact, to describe economic income, only costs have to be subtracted. Percentage depletion in excess of cost allows deductions for imaginary costs. One should not be confident of the wisdom of congressional engineering when the decision to allow percentage depletion was based on erroneous understanding of capital and on imaginary costs.

The OPEC oil embargo of the 1970s quadrupled oil prices, and Congress reacted by restricting access to percentage depletion. Since 1975 the integrated oil companies that refine and retail oil must use cost depletion, which is a sensible accounting method that reasonably allocates costs to the related revenue as oil and gas are extracted. Percentage depletion is also not available for foreign production.[42] Independent domestic oil drilling, however, continues to be able to use percentage depletion, up to a level now at about $24 million per taxpayer per year.[43]

The proposal would amend section 612, which authorizes depletion, to limit total depletion deductions, whether under percentage or cost depletion, to the taxpayer’s adjusted basis. Percentage depletion in excess of cost is no more justified for minerals other than oil and gas, so the proposal would affect all depletion allowances, not just oil and gas.

b. Exclusion regarding domestic manufacturing. Current law allows a deduction of 6 percent of income from domestic oil and gas production.[44] While the deduction is 6 percent in 2009, it is scheduled to rise to 9 percent of domestic income in 2010.[45] The deduction is limited to taxable income in the year and so does not carryover to past or future tax years. The deduction is also limited to 50 percent of the domestic wages reported on W-2 forms,[46] but that ceiling is primarily of symbolic value because it will come into play only if domestic wages are under roughly 1.2 percent of total costs.[47]

The deduction of 6 percent to 9 percent of domestic production contributes to the tax subsidy accorded to oil and gas. The market price of oil will give sufficient incentive to the production of oil because it always meets supply at the market clearing price. If more incentive is needed, price will increase. The increase in price will give incentives to conservation of fuel and alternative nonfossil energy sources. The government should get out of the job of oil and gas subsidies because it gives incentive to waste capital on investments that cannot be justified without a subsidy.

Subsidy of domestic production, moreover, means that we drain domestic supply before we use cheaper oil overseas. A smart program on homeland security would punish domestic production to preserve domestic supply for some future emergency and use cheaper overseas oil while it is available.

The proposal would end the section 199 deduction for domestic oil and gas production.

c. Repeal LIFO inventory accounting for oil and gas. Inventory accounting allows the deduction of the cost of units that have been sold or lost by the taxpayer, but not the costs of units taxpayer retains on hand at the end of the year. Whether the costs are still in basis or are sold or lost deductible costs is determined by counting the units still on hand in closing inventory.

Oil and gas units extracted or bought at different times have different costs, but because the units are fungible, it makes no difference outside tax accounting whether the taxpayer is considered to have sold the old cheap units or kept the oldest and cheapest units. Costs are assigned by an arbitrary ordering convention, usually FIFO or LIFO.

The FIFO convention treats the oldest costs as sold first, so that there are no old costs left in closing inventory. FIFO accounts leave the basis of the closing inventory at levels approximately equal to the current market value that it would take to replace the inventory.

The LIFO convention, by contrast, identifies the most recent, usually higher costs with the units that are sold and deductible and identifies the lowest costs with the units that have been retained and remain as nondeductible basis. LIFO maximizes unrealized appreciation and minimizes tax, often quite dramatically.

A taxpayer that employs LIFO carries its closing inventory at the cost of units of the oldest purchases, starting when the taxpayer first adopted inventory accounting and adopted the LIFO convention. If, for instance, the taxpayer started a business 50 years ago in 1959, it would carry its oldest inventory at $3 a barrel (the 1959 price), notwithstanding that the taxpayer is now selling oil at $72 a barrel.[48] The $69 difference is treated as

unrealized appreciation and not taxed until the taxpayer shrinks its inventory to use up the last of the old costs. Shrinking inventory back to oldest price will happen only when the corporate taxpayer is contracting at the end of its life. Avoiding tax on the $69 appreciation is the point of the LIFO convention. LIFO has no nontax purpose.

Notwithstanding the LIFO convention, oil firms have long ago pushed 1959 oil out of their system and they have no 1959 oil left. They sold their $3 oil for cash and realized their accession to wealth that resulted from the increase in real prices. Accession to wealth turned into cash would normally be taxed. For a firm with $10 billion in oil and gas inventory the difference between the LIFO and FIFO ordering conventions is material. One estimate

put the difference between LIFO and FIFO for publicly traded companies at $600 billion of taxable income.[49]

The function of LIFO is said to be used to adjust for inflation so that fictive inflationary gains are not taxed.50

Inflation is mostly just an excuse for oil and gas because oil and gas has benefited from real price improvements in realized wealth. The 1959 $3 price, for example, would be adjusted to $20.22 to account for inflation,[51] leading to an exclusion of $17.22, not an exclusion of the $69 that is actually allowed. The LIFO convention excludes real gains from tax on the basis of the argument that 25 percent of the gain is inflation caused.

Inflation, moreover, cannot coherently be adjusted for some kinds of investments but not others without creating distortions in the allocation of resources. Interest deductions, moreover, must symmetrically be taken away to the extent the interest just offsets inflation; to the extent of inflation, interest paid is not even a cost. Inflation exclusions for assets without adjustment concerning liabilities create artificial losses in the tax accounting.

As noted, tax accounting can identify the real interest from an investment and make the economic effective tax rate equal to the statutory tax rate only if the adjusted basis for assets is equal to the present value of the assets.[52] Reporting basis — the bank account — at 3⁄72 or 4 percent of its real value is tantamount to an effective tax rate that is only 4 percent of the statutory tax rate.[53] No justification has ever been offered for tax rates on oil gain that are a trivial percentage of the statutory tax rate.

The proposal would require that additions to closing inventory be calculated by the current replacement cost of oil and gas. Existing inventory would also be restated at current FMV prices, but the gain on existing inventory, so long delayed already, would be brought into income over four years.

3. Repeal the 1990 and 2004 tax credits. Congress provided two subsidies for oil drilling for special cases when it was perceived that market price alone might not provide sufficient incentive. In 1990 Congress enacted a

15 percent tax credit for enhanced oil recovery techniques, including preparation of Alaska natural gas, and the injections of various liquids into the deposit to help extract oil.[54] In 2004 Congress enacted a tax credit of $3 per barrel of oil for marginal wells.[55]

Both credits disappear when the market price is high enough to give sufficient incentive to undertake the higher-cost drilling. The enhanced recovery credit is phased out over a $6-per-barrel range when the price of oil exceeds a threshold originally set at $34 per barrel,[56] but with inflation adjustments is now at $41 per barrel.[57]

With oil at $72 a barrel,[58] the enhanced recovery credit is not available. The marginal well credit has never been available because the price of oil shot up above its phaseout level before it could come into effect.[59]

The price of oil provides a sufficient free-market incentive to explore for and extract oil and gas, not just when the price exceeds the phaseout line for marginal wells and enhanced recovery, but in every case. No further subsidy is needed beyond the wisdom of supply and demand.

The tax credits were never a good idea, even when they were available. The decision-making process for tax credits and other tax expenditures is inadequate.[60] Congress apparently does not consider the money in tax expenditures for oil and gas to be real money.

C. Conclusion

Congress needs to adopt the best tax accounting practices for oil and gas that will make taxable income describe real economic income. To make tax accounting for oil and gas investments describe economic income, it is proposed that Congress repeal the intangible drilling expense deduction, the pool of capital doctrine, and the exemption from PAL limitations for working oil and gas interests. Congress should also limit percentage depletion to basis, repeal the domestic production exclusion, allow recovery of G&G costs under cost depletion, repeal LIFO for oil and gas inventories, and repeal the enhanced oil recovery and marginal wells tax credits.

The government should get out of the business of giving tax preferences for oil and gas investments. The free-market laws of supply and demand will give all the incentives that are needed.

[1]For the Treasury report, see Doc 2009-22988 or 2009 TNT 200-26.

[2]This analysis of the economics of oil and gas taxation rests heavily on Calvin H. Johnson, ‘‘Capitalize Costs of Software Development,’’ Tax Notes, Aug. 10, 2009, p. 603, Doc 2009-15569, or 2009 TNT 151-9, including some identical paragraphs.

[3] Effective tax rate = (IRRpretax IRRposttax)/IRRpretax.


sometimes used to refer to the total overall tax divided by overall income, in contrast to the ‘‘marginal tax rate,’’ which looks to the tax on the next dollar of change in income. 8The standard annuity formula is a shortcut, derived by series analysis, from the separate discounting of each $100 for different year, at the standard formula for present value, e.g., $100/(1 + i)n.

clip_image011[4][9]The 4.9 percent figure is the discount rate that makes costs and revenues have the same future value, hence 4.9 percent is the IRR from the investment:

[12]F.H.E. Oil Co. v. Commissioner, 147 F.2d 1002 (5th Cir. 1945). See Boris I. Bittker and Lawrence Lokken, Federal Taxation of Income, Estates and Gifts, para. 26.1.1 (2009).

[13]Harper Oil Co. v. United States, 425 F.2d 1335 (10th Cir. 1970) (Blackmun, J.) (drilling casings held not to be intangible drilling cost); Standard Oil Co. v. Commissioner, 77 T.C. 349 (1981) (accord); Exxon Corp. v. United States, 547 F.2d 548 (Ct. Cl. 1977) (construction of offshore platforms held not to be intangible drilling cost).

[14]Section 291B.

[15]Section 56(g)(4)(D)(1); section 312(n)(2)A.

[16]Joint Committee on Taxation, ‘‘Estimates of Federal Tax Expenditures 2007-2011’’ (JCS-3-07 at 47), Doc 2007-21689, 2007 TNT 186-12.

[17]Full costing is governed by SEC Regulation S-X Rule 4-10(c) (1996), and successful efforts are now governed by

Financial Accounting Standards Board Accounting Standards Codification 932, ‘‘Extractive Industries’’ (2009).

[18]SEC reg. S-X Rule 4-10(c)(4).

[19]J. Larry Nichols on behalf of the American Petroleum Institute, ‘‘Statement at Hearings of the Senate Finance Subcommittee on Energy, Natural Resources, and Infrastructure on the Oil and Gas Provisions of the President’s FY 2010 Budget’’ at 10 (Sept. 10, 2009), Doc 2009-20278, 2009 TNT 174-31 (arguing that drilling costs are R&D ‘‘since they all relate to a trial and error experiment to discover a commercial resource’’).

[20]Johnson, ‘‘Soft Money Investing Under the Income Tax,’’ U. Ill. L. Rev. 1019, 1078-1079 (1990), argues that expensing for R&D was in fact adopted as a historical matter in reliance on an erroneous position that it did not matter whether expensing was capitalized or expensed immediately. A sounder rationale for the immediate deduction, regardless of the historical error, is that section 174 follows GAAP in presuming that research costs are a worthless or expired cost when made because no relationship can be presumed between research and future income.

[21]FASB Statement of Financial Accounting Standard No. 2, ‘‘Accounting for Research and Development Costs,’’ 8 (1974).

[22]Maurice S. Newman, ‘‘Equating Return From R&D Expenditures,’’ Financial Executive (Apr. 1968), at 26-33 (footnote is in original FAS 2 quoted in text).

[23]Orace Johnson, ‘‘A Consequential Approach to Accounting,for R&D,’’ Journal of Accounting Research (Autumn 1967) at 164-172 (footnote is in original FAS 2 quoted in text).

[24]Alex J. Milburn, ‘‘An Empirical Study of the Relationship of Research and Development Expenditures to Subsequent Benefits’’ (unpublished Research Study, Department of Accountancy of the University of Illinois, 1971) (footnote is in original FAS 2 quoted in text).

[25]GCM 22730, 1941-1 C.B. 214.

[26]The general rule is that a taxpayer who receives any oil interest as compensation must include the FMV of the interest as ordinary income. See, e.g., Leland J. Allen v. Commissioner, 5 T.C. 1232 (1945) acq. 1946-1 C.B. 1.

[27]Rev. Rul. 83-46, 1983-1 C.B. 16; Rev. Rul. 77-176, 1977-1 C.B. 77.

[28]Rev. Rul. 77-176, 1977-1 C.B. 77.’

[29]Frank M. Burke Jr., ‘‘Oil and Gas Taxation From 1972 to 1992: A Study in Questionable Tax Policy and Administration,’’ Tax Notes, Nov. 12, 1992, p. 871.

[30]Rev. Proc. 2001-43, 2001-2 C.B. 191, Doc 2001-20855, 2001 TNT 150-11 (transfer of a profits interest for services is taxable to neither new partner nor partnership); Notice 2005-43, 2005-1 C.B. 1221, Doc 2005-11236, 2005 TNT 98-37 (saying that the IRS intends to issue proposed regulations that will exempt receipt of partnership interest if the recipient would receive nothing in liquidation if the partnership were liquidated immediately).

[31]The argument arises from Paul Samuelson, ‘‘Tax Deductibility of Economic Depreciation to Insure Invariant Valuations,’’ 72 J. Pol. Econ. 604 (1964). See, e.g., Johnson, supra note 5.

[32]See, e.g., Calvin H. Johnson, ‘‘Why Have Anti-Tax-Shelter Legislation?’’ 67 Texas L. Rev. 591 (1989).

[33]Reg. section 1.469-5TA(1).

[34]Section 469(c)(3).

[35]Staff of the JCT, ‘‘General Explanation of the Tax Reform Act of 1986,’’ (JCS-10-87) at 251 (1987).


[37]Section 167(h)(1).

[38]The spreadsheet like that in Table 5, but for seven-year amortization, allows $14.29 deduction in row 2 for seven years, rather than $33.33 for three years. The found return after tax is 8.46 percent, which represents a 15.4 percent reduction in IRR from the given pretax 10 percent.

[39]See, e.g., Plow Realty Co. v. Commissioner, 4 T.C. 600 (1945).

[40]Sen. David Reed, Debate on the Revenue Act of 1926, 67 Cong. Rec. 3,766 (former Sen. David Reed of Pennsylvania).

[41]Calvin H. Johnson, ‘‘Percentage Depletion of Imaginary Costs,’’ Tax Notes, Mar. 30, 2009, p. 1620, Doc 2009-5128, 2009 TNT 59-17.

[42]Tax Reduction Act of 1975, P.L. 94-12, section 501, 89 Stat. 36.

[43]Section 613A(c) (exemption) and (c)(3) (limitation of exemption to 1,000 barrels a day or 365,000 barrels a year). At $75 per barrel for oil, the exemption allows the full 15 percent percentage depletion on up to $24 million in revenue per year.

[44]Section 199A(2).

[45]Section 199A(1)A.

[46]Section 199B.

[47]For example, assume a 10 percent income per year, so that $100 will produce $10 in income. The 6 percent of income exclusion is 60 cents. If the taxpayer pays domestic wages reported on Form W-2 of $1.20, the ceiling of half of domestic wages will allow the full 60 cents to be deducted. The $1.20 is only 1.2 percent of the $100 invested cost.

[48]For the 1959 price, see Financial Trend Forecaster, available at Historical_Oil_Prices_Table.asp. For current price, see (accessed Aug. 25, 2009).

[49]Edward D. Kleinbard et al., ‘‘Is It Time to Liquidate LIFO,’’ Tax Notes, Oct. 16, 2006, p. 237, Doc 2006-20617, 2006 TNT 200-29.

[50]See, e.g., Amity Leather Products Co. v. Commissioner, 82 T.C. 726, 732 (1984); Hamilton Industries, Inc. v. Commissioner, 97 T.C. 120, 130 (1991).

[51]Financial Trend Forecaster, available at http://www.


[52]Section IIB. See supra text accompanying note 5.

[53]Johnson, supra note 5.

[54]Section 43, added by Omnibus Budget Reconciliation Act of 1990, P.L. 101-508, section 11511.

[55]Section 45I, added by American Jobs Creation Act of 2004, P.L. 108-357, section 341.

[56]Section 43B(1).

[57]Treasury Department, General Explanations of the Administration’s Fiscal Year 2010 Revenue Proposals 60 (May 2009), Doc 2009-10664, 2009 TNT 89-44.

[58]Available at (accessed Aug. 25, 2009).

[59]Supra note 55. Section 45IB(2)A set the phaseout to begin at $18 but with inflation adjustments.

[60]For a recent criticism of the decision-making process regarding tax subsidies, see Edward D. Kleinbard, ‘‘How Tax Expenditures Distort Our Budget and Our Political Processes,’’ Tax Notes, May 18, 2009, p. 925, Doc 2009-10867, or 2009 TNT 94-40.

Previously published by the University of Texas at Austin School of Law

Andrews & Kurth Centennial Professor of Law, University of Texas at Austin - School of Law, USA