Office of Tax Analysis

,U.S. Treasury Department

Washington, D.C. 20220 

Issued: May, 1976 
 

Issues in the Taxation 
 of Petroleum and Natural Gas Income 
 

Seymour Fiekowsky
 U.S. Treasury Department 
 

OTA Paper 2 September 1974 

Table of Contents 
 

Page 
 

Preface................................................ 1 
 

I. Income measurement issues.......................... 2 
 

A. A simplified description of the investment 

process....................................
 2
 

B. Complications................................ 4 
 

(1) The sequential nature of the investment 

process 4 ............................... 9 (2) Uncertainty of reservoir content........ (3) Summary................................. 11

11. Evolution of tax accounting treatment of oil and 
 gas investment and income........................ 12 
 

A. Economic policy aspects in the taxation of 
 oil and gas companies...................... 12 
 

B. The tax treatment of expenditures for the 
 discovery and development of oil and gas 
 reserves...................................15 
 C. Statutory allowances for depletion........... 20,
 

D. Summary...................................... 28 
 

111. Economics of oil and gas investment decisions and 
 the effects of taxation........................... 31 
 

A. The simplified example recast to account for 
 time and rate of return.................... 34 
 

B. Introducing taxes into the investment 
 decision................................... 37 
 

(1) Taxation with "ideal" accounting........ 38 
 

(2) Taxation with tax accounting............ 40 
 

C. Summary...................................... 42 
 

IV. 	 Slogans............................................ 45 
 

A. "Repeal of percentage depletion would deprive
 oil (hard minerals, sand, gravel, etc.)
 industry of capital needed to increase 
 domestic capacity'I......................... 48 
 

(1) The kernel of truth and its triviality.. 49 
 

B. "Repeal of percentage depletion falls 
 hardest on 'independent' oilmen who do the 

most drilling and who maintain competition 

in the industry"........................... 51

(1) Separating truth from fiction: 

"Independents drill more than 80 
 percent of all exploratory wellsr'..... 52 
 
Table of Contents continued 
 Page 
 

(2) A kernel of inconsequential truth: 

"Independents" rely on investors 

to whom oil tax deductions are 

important........................ 54 

C. 
 "Repeal of percentage depletion will 

initiate tax-minimizing sales of 

properties by independent oilmen, and 

the majors will monopolize the production of oil" ............................ 56 

(1) Analysis of the problem.............. 57 

D. 
 "Repeal of percentage depletion will make 
 the tax system fairer and make oil 
 companies pay their fair share of taxes" 60 
 
-1- 
 

Preface 
 

The design of rules for taxing oil and gas income has 

posed controversial legislative and administrative problems 

almost from the outset of Federal income taxation in 1916. 

This is not surprising, for the process by which oil and gas 

reserves are brought into productive use is more nearly akin 

to a research and development undertaking, than to a straightforward industrial project. A conceptual distinction may be 

drawn between investment in the discovery of new information 

to reduce risk, and investment in well specified items of 

plant and equipment to produce reasonably well defined 

products. Income accounting procedures for the latter kind 

of investment are not without controversy since expected 

useful lives and residual values are not certain, But the 

11 

range of difference in possible income accounting rulesis not so great as to excite heated debate. Thus, in the 

case of measurement of income from petroleum refining, 

notwithstanding the large investment in plant and equipment, 

-1/ Income accounting rules are used to synchronize flows of 

receipts and expenditures for the purpose of producing

periodic estimates of income. The receipts of a particular

time period have to be attributed to activities of the 

current, future, and past periods; and expenditures of the 

present period have to be similarly attributed, It is the 

excess of current period receipts (and claims) over current 

period expenditure of resources (whether "paid" in the 

current period or not) which is "income" of the current 

period. 
-2- 
 

there has been no history of Congressional and administrative 
 

controversy over refinery-specific income accounting rules. 
 

But the tax treatment of investment in discovery and 
 

development of petroleum has been, and continues to be, the 
 

subject of bitter controversy. And, as frequently happens in 
 

the course of tax controversies that spill over into popular 
 

debate, mythology comes to replace fact, and sloganeering 
 

supplants analysis. It is a mark of the deplorable state of 
 

public discussion that most of the debate has centered on 
 

"percentage depletion", although percentage depletion is 
 

scarcely the most significant rule for measuring taxable 
 

income from investment in oil and gas reserves. These notes 
 

attempt to puncture prevailing myths by identifying the 
 

issues of income measurement and by examining the slogans 
 

offered by proponents and opponents of percentage depletion. 
 

I. Income measurement issues. 
 

A. A simplified description of the investment process. 
 

For expository purposes, suppose investment in 
 

discovery and development of petroleum and natural gas 
 

reserves, and a given productive capacity, takes the following 
 

form. Someone makes outlays of $20 million over a period of 
 

10 years. These outlays are for geological and geophysical 
 

survey work, for drilling test cores and wells, for equipping 
 

those wells which are productive, and for installing storage 
 
-3-

and related facilities. At the completion of this investment 

program, it is established that the field will produce 10 

million barrels of oil. Under these simplified assumptions, 

and ignoring the mathematics of comparing present and future 

values, each barrel of oil "costs" the investor $2; this is 

the capital cost per barrel which should be accounted for in 

determining the investor's income as the oil is extracted and 

sold. For example, if in a subsequent year 1,000barrels are 

pumped-out at an additional cost of $2,000 and sold for $5,000, 

the income for that year would be $1,000 ($5,000less $2,000 

production cost and less $2,000 "depletion" of investment cost 

at $2 per barrel for the 1,000barrels extracted). 

In sum, the rules used for income accounting in this 

simplified description of the investment process were: (1) 

Capitalize all costs connected with discovering and developing 

the reserves of oil; (2) divide this cost by the total quantity 

of recoverable minerals discovered, the quotient being the 

capital cost, or depletion charge, per unit of the mineral; 

(3) subtract this depletion charge, plus any additional costs 

of extracting the mineral, from gross receipts attributable 

to extraction to derive net income. Obviously, if it costs 

$2 per barrel to discover and develop oil and another $1 to 

lift it, still ignoring the mathematics of discounting, the 

price of oil will have to be at least $3 per barrel, else 
-4-

investors will not devote their resources to the search. If 

the price is expected to rise substantially above $3, more 

resources will be invested, more oil found, and the price will 

be driven down to the normal rate of return level, $3 in the 

example just described. 

B. Complications. 
 

There were two critical elements in this simplified 

example which gave rise to a correspondingly simple (and 

fundamentally correct) income measurement rule: (1) The 

investment process has an easi.ly identifiable beginning and 

end; (2) after the investment period has ended, the amount of 

extractable mineral is known with certainty. Unfortunately, 

the actual conditions of investment and the search for reserves 

so greatly differ from these simplifying assumptions that the 

simple income measurement rule is not operational. 

(1) The sequential nature of the investment process. 
 

Imagine a geographic region in which there has 
 

been no previous discovery of petroleum and gas reservoirs. 
 

Suppose that a skilled prospecting company makes preliminary 
 

observations and concludes there is a reasonable probability 
 

that subsurface petroleum and gas reserves may be found. The 
 

would-be prospecting company must then purchase exploratory 
 

rights from the landowner, and this purchase of mineral rights 
 

usually takes the form of a mineral lease wherein the owner 
 
-5- 
 

(who becomes the lessor) exacts the highest possible cash 
 

payment (called a "bonus") plus a share of future minerals 
 

which may be discovered (called a I'royalty"). 
 

In negotiating a mineral lease, the would-be 
 

prospector faces a serious problem: though he suspects the 
 

existence of underground reservoirs, he can be sure neither 
 

of its exact location nor of its geographic extent. The 
 

larger the surface acreage for which he purchases rights, 

the greater his expense, particularly if, as in the United 

States, surface rights may be privately held in small plots. 

On the other hand, if a prospector does not secure rights 

to a large acreage, the reservoir he may find could extend 

beyond the boundaries of his lease, and he will fail to 

capture the full value of the mineral he is principally 

responsible for discovering. The prospector must, therefore, 

make a difficult decision, the quality of which will determine 

his ultimate gain. If, as in the case of auctions of leases 

on public lands, the total acreage offered for exploration 

and development is large, individual companies may pool their 

initial risk (uncertainty about the precise location and 

extent of underground reservoirs) by jointly bidding on 

several parcels, and they may engage in similar loss hedging 
 

arrangements with neighboring lease holders on private lands. 
 
-6-

In any event, from the point of view of potential 
 

oil discoverers, the initial outlay for rights to explore is a 
 

"capital" expenditure, part of the cost to be cumulated as the 
 

ultimate capital cost of a discovery, if any. Under all con­
 

ventional rules of income accounting, these initial outlays to 
 

purchase mineral rights should be capitalized. This is also 
 

the case under tax accounting rules by which lease bonuses are 
 

capitalized as part of the "depletable basis" of a mineral 
 

property, to be recovered by depletion allowances whenever 
 

mineral production occurs. 
 

Once mineral rights have been secured, the 
 

discovery process entails further expenditures for geological 
 

and geophysical surveys and tests to select a likely site for 
 

drilling a ''new field wildcat," a well to discover a new 
 

reservoir. These expenditures are not unlike expenditures 
 

made by industrial firms in connection with the design and 
 

development of a new product or industrial process: they are 
 

generalized expenditures on scientific research intended to 
 

produce information of future value. The accounting treat­
 

ment of this class of expenditures is not universally agreed 
 

on, however, Some managements regard research and develop­
 

ment as ephemeral outlays, a current cost of doing business 
 

deductible from current gross income; others regard them as 
 

capital expenditures, to be cumulated as the investment cost 
 
-7-

of an ongoing project. Although the tax law generally permits 
 

current deduction of research and development expenditures, 
 

these outlays with respect to oil and gas discovery projects 
 

must be capitalized and become a part of the depletable basis 
 

of mineral properties. 
 

After one or more drilling sites have been 
 

selected, the process next entails drilling of wells. 
 

Experience with wildcat well-drilling is highly variable, 
 

but overall statistics on domestic drilling indicate that 
 

only one of ten or eleven wildcat wells will strike oil or 
 

gas and be completed as a productive well; the others will 
 

be "dry-holes." It is clear that the cost of drilling all 
 

wells, the dry-holes along with the successful discovery 
 

well, should be capitalized as part of the investment cost, 
 

for even the drilling of a dry-hole yields information of 
 

value. In principle, there is no difference between the cost 
 

of scrappage inevitably encountered in the manufacture of a 
 

machine or other capital asset and the cost of drilling dry-
 

holes; both are a social and private cost of creating pro­
 

ductive capital assets and both should be accounted for in 
 

that way. 
 

But the completion of a successful new field 
 

wildcat does not end the investment process, even if oil and 
 

gas begin to flow. It is further necessary to define the 
 
-8- 
 

size and characteristics of the reservoir, and this requires 
 

additional wells. Once the existence of a field has been 
 

established, a much higher fraction of the subsequent wells 
 

drilled will be successful, perhaps 60 percent. In a real 
 

sense, part of the cost of the succeeding wells, which may 
 

be called "development" wells, is further investment cost 
 

designed to provide additional information about the oil and 
 

gas field, little different from prior expenditures with which 
 

they should be cumulated. But, in another sense, these 
 

additional wells are closely related to current costs of 
 

production, for they make possible a higher current rate of -I/

production from the reservoir. 

-1/ Readers unfamiliar with the nuances of tax accounting may

wonder at the need for a distinction between the cost of 

investment in the "mineral" and investment in "productive

capacity." While this distinction has no particular utility

from the point of view of investment decisions or mine management, it is critical to tax accounting because property

rights in minerals are separable from rights in "movables" 

under the law, and being separable, they may be exchanged

independently. In the event there is an exchange, it becomes necessary to account for gain, or loss, realized by

the seller which requires that his "adjusted basis"--

original cost of the property right, less allowances for 

depletion or depreciation--be continuously accounted for. 

Moreover, the cost of the mineral rights, as distinguished

from other property purchased by the new owner, must be 

established so that tax income accounting for capital consumption may proceed. Since there is no functional economic 

distinction between the two kinds of rights corresponding to 

the property law distinctions, an infinite number of 

strategies may be devised which will outwit the tax 

collector. A similar need to artificially value "land" and 

"buildings" bedevils administration of the tax laws with 

respect to real property. 
-9- 
 

(2) Uncertainty of reservoir content. 

The indeterminate shading between investment in 

additional knowledge of reserves and investment in productive 

capacity from known reserves poses the problem that, if income 

from current production is to be measured, the cumulative prior 

cost of establishing the reserves must be divided by the 

quantity of reserves to derive an appropriate "depletion" 

charge. But if the very act of producing from an underground 

reservoir adds to knowledge of recoverable reserves, it is 

obviously impossible to distinguish further investment in 

reserves from mere costs of production. Lacking a definite 

end of the investment process, when all "reasonable" men, 

including the tax collector, can agree that a specific quantity 

of recoverable reserves is in place, the only unambiguous 

measure of income from the reservoir is the measure that 

would be derived when production from the reservoir ceases. 

At that point, the cumulated expenditures of all kinds, from 

the initial bonus, through geological and geophysical surveys, 

drilling, pumping, secondary and tertiary recovery, and for 

labor and materials could be subtracted from cumulative sales 

to determine aggregate income derived from the field. But a 

delayed accounting would satisfy neither stockholders and 

creditors of oil companies, nor the tax collector, all of 
- 12 -

rules, are equally difficult to make. Nevertheless, some 
 

useful conclusions can be drawn from a critical examination 
 

of the battery of tax accounting rules that have evolved. 
 

11. Evolution of tax accounting treatment of oil and gas
 investment and income. 
 

A. Economic policy aspects in the taxation of oil and 

gas .companies. 

From an economic policy point of view, tax rules must 

be evaluated in terms of their impact on investment decisions, 
 

for in the long run tax policies determine the relative size 
 

of the private capital stock invested in oil and gas capacity 
 

and hence the price of these resources. 
 The investment impact 
 

evaluation is complicated, because taxes are paid by enter­
 

prises which are simultaneously engaged in one or more stages 
 

of the investment process: 
 they may be currently producing 
 

only from fields discovered and developed long before, or 
 

they may be maintaining, or adding to, existing productive 
 

capacity by additional exploration arid development, or they 
 

may be newly entering the oil business, discovering and 
 

developing their first field. Depending on their circumstances 
 

when the income tax law was first enacted, or now when changes 
 

in tax rules may be enacted, different firms will experience 
 

different immediate effects in their tax returns, just as 
 

these firms have fared differently since 1973 when oil prices 
 

have risen sharply. Obviously, a firm producing from existing 
 
- 13 -

reserves will immediately benefit more from an oil investment tax 
 

reduction or an oil price increase than will a firm heavily engaged 
 

in a large investment program; and all firms presently in the oil 
 

business will benefit more than those newly attracted to the 
 

industry by the tax reduction or price increase. 
 

Rewards from oil and gas discovery are highly variable. 

Most firms in the oil business, as in any industry, enjoy 

modest success; their capital earns little more than it might 

earn if invested in any other industry. Many firms, attracted 

by the possibility of riches, are probably net losers; their 

capital would earn more if invested in government bonds. A 

few firms; either through luck or a "nose" for oil, are 
 

exceptionally prosperous even though the industry-wide 
 

average return in the oil business is no higher than the 
 

average for all industries. 
 Firms at the margin of profitability 
 

will be more immediately affected by adverse tax or price 

movements; and since they are always more numerous than the 

few highly profitable firms, they will raise loud cries of 

"unfair destruction of competition" whenever taxes are 

raised or prices fall. Ironically, the fact that changes -do 
 

affect numerous marginal firms is proof that the industry is 
 

competitive, and that compensatory changes in invesltment will 
 

occur in response to tax and price changes. But not only are 
 

company financial records highly variable, the ventures 
 
- 14 -

undertaken by a single company are also highly variable. 
 

For a cross-section of producing oil properties at some point 
 

in time, the implicit rates of return on those properties will 
 

be far above average simply because they represent the 
 

successful ventures whose returns must offset numerous but 
 

uncounted unsucessful ventures. Every industrial firm has 
 

produced its share of duds, but only in the minerals industry 
 

is the individual "property" an invariant accounting unit; an 
 

oil company l'consolidatesl'its properties in its tax returns, 
 

but capital accounts, depletion, and abandonment losses are 
 11 

recorded by "property1'-. Thus as a statistical anomaly, 

it will appear that the "va1ue"of mineral deposits in use 

greatly exceeds the "costll of discovery and developing those 

properties. 

-1/ An industrial firm can group its assets in depreciation classes 

without regard to geographic location, and it need not 

associate depreciation allowances with any particular kind 

of business it carries on, or with any administrative 

division of the enterprise itself. But an oil producer

must aggregate its operational data by property so that it 

can compute the "income from each property" separately.

In industrial enterprises, particular investment "mistakes" 

are typically consolidated with 'Isuccesses"; in mineral 

enterprises "mistakes" are segregated from "successesII. 
- 15 -
 

B. The tax treatment of expenditures for the discovery 
 

and development of oil and gas reserves. 
 

Present income tax rules applicable to oil and gas 

properties are fundamentally irrational because the rules for 

classifying investment expenditures evolved separately from 

the rules governing capital recovery (or depletion). Detailed 

rules for classifying outlays made in connectionwith taxing a trade 

or business are usually developed administratively, and this 

was the case with oil and gas investment. Meanwhile, Congress 

independently legislated capital recovery rules with respect 

to minerals as early as 1916, and specifically with respect to 

oil and gas in 1926. Normally, the administrative determination of which kinds of expenditure are regarded as "capital" 

and are classified as "current expenses" would display 

little if any inconsistency with separately legislated capital 

recovery rules. But, in the present instance, definitional 

compromises promulgated by first-generation income tax 

administrators produced a public policy disaster when they were 

mixed with the independent legislative decisions regarding 

cost recovery, or depletion. 

Even before Congress invented percentage depletion in 

1926, the Treasury and then Bureau of Internal Revenue were 

settled on a course which ultimately yielded the conclusion 

that approximately 70 percent of the outlays for discovery and 
- 16 -
 

development of oil and natural gas productive capacity are 

classified as current expense, about 20 percent are capitalized 

as "depletable basis", and 10 percent are capitalized as 

"depreciable basis", that is, expenditures for machinery and 

equipment, largely pumps, pipes and the like, which are 

replaceable (subject to wear-and-tear and obsolescence) but 

which are separable from the oil and gas extraction operation 

-11 

itself. 

The 70 percent of total oil and gas investment outlays 

allowed as a current deduction includes some 40 percent related 

to dry-holes--outlays for drilling and a pro-rata share of 

geological and geophysical expenses. Our earlier discussion 

of the investment process concluded that dry-hole costs should 

be aggregated by project. In the interests of administrative 

convenience, however, the view was taken that each well 

These figures are nationwide averages reflecting pre-1970 

experience. For some investment projects, such as those 

undertaken near prior discoveries, the percentage of total 

investment cost currently expensed may exceed 70 percent. 

Moreover, because of the multiplicity of mineral interests, 

it is possible for mineral rights owners to "package" 

property rights in such a way that more of the "deductible" 

investment costs accrue to one class of investor than another. 

Thus, even though the average deductible investment cost 

may be 70 cents to $1total investment, some investors may 

be provided the legal opportunity to deduct as much as 90 

cents of each dollar they su~p1.y. Of course, they pay for 

this privilege by accepting less of any future income produced 

by the property, just as creditors who demand substantial 

collaterial ''pay" for this lessening of lenders' risk by 

accepting a lower rate of interest from the borrower. 
- 17 -

constitutes a single project; and since investment in an 

unsuccessful venture is customarily considered a "loss", that 

loss should be deductible from gross income when recognized. 

It is unclear why a lease-aggregation rule was not imposed 

on each taxpayer, since lease bonuses and other mineral rights 

acquisition costs have always been capitalized. 

Perhaps the reason why dry-hole write-offs continue to be 

tolerated is that, for reasons that defy rationalization, it 

was also ruled that "intangible drilling" costs are deductible 

when incurred: 

I/ 

Since the bulk of the cost of dry-holes was 

already allowed as current deductions, the write-off of some 

little geological and geophysical expense seemed not worth 

contesting. But current deductibility of drilling costs for 

wells completed as productive now accounts for the remaining 

30 of the 70 percent of investment cost currently deductible. 

This provision must be regarded as an unnecessarily generous 

compromise with the vicissitudes of oil and gas investment 

-1/ The "intangibility" of the drilling costs presumably was 

inferred from the fact that labor and contractor services 

were hired to drill the hole, and since the product of all 

this expenditure was a "hole" nothing "tangible" resulted. 

Fortunately, income tax accounting has not eenerally

followed this tortured reasoning in other circumstances; 

apart from the incentive provisions for research and 

development expenditure, it is seldom held that the cost 

of "intangible" capital assets can be expensed. Indeed lease 

acquisition costs, which are "intangible" when purchased

must be capitalized, along with geological and geophysical 

survey expenditures, which are also "intangibles." 
- 18 -

accounting. However uncertain may be the result of drilling a 
 

particular well, the cost of drilling a productive well cannot, 
 

by any standards of income accounting, be considered a current 
 

expense of income production. Nor can such expenditures be 
 

compared with industrial research and development outlays. A 
 

reasonable compromise with the inherent uncertainties would have 
 

provided some guidelines formula permitting a pattern of write-
 

offs over the expected life of at least the cost of completing 
 

productive wells. 
 

The implications of this tax treatment of investment 

outlays may be illustrated by reference to the simplified 

example presented earlier. Again setting aside the mathematics 

of discounting, the firm spending an illustrative $20 million 

to discover and develop an oil field with total recoverable 

reserves of 10 million barrels would have been allowed to 

deduct currently $14 million of that amount during the investment period under tax accounting rules. If the firm was then 

operating other fields, engaged in transportation, refining, 

or marketing, or any other economic activity producing taxable 

income during the period of its investment in a new oil field 

it would have aggregated these deductions (called "net operating 

losses") relating to the property being developed with the 

otherwise taxable income, thereby reducing its taxable income 

by $14million, and saving $7 million in current tax payments 
- 19 -
 

(assuming a 50 percent income tax rate). Of the remaining 

$6 million of capital outlays, about $4 million would be 

the "depletable basis", or 40 cents per barrel, while $2 million 

would be the depreciable basis which might be written-off 

over 11 years by any allowable depreciation method. Assuming 

an annual production of about 600,000 barrels in the early 

years of this hypothetical field, and a price of $5 per 

barrel produced and sold, the comparative income measures 

are shown in Table 1. 

Table 1 

Effect of Investment Cost Accounting on Annual Income 

: Income Accounting Methods 

: "Ideal" rules : Tax rules -a/ -

Gross income (600,000 bbls . at $5) . . . . . . . . . . . $3,000,000 $3,000,000 

Less: Lifting costs, total . . . 600,000 600,000 

Capital cost depletion . . 1,000,000 b/ - 240,000 c/

360,000 a/

-

Annual income, early years . . . 1,200,000 1,800,000 -e/ 

-a/ This is not taxable income; percentage depletion exceeds 

cost depletion and would be taken. See the example in the 

next section. 

-b/ $2 per barrel. 

-c/ $0.40 per the barrel. 

-d/ Assumed depreciation allowance. 

e/ In the event the taxpayer had been unable to deduct the 

$14 million of pre-production "tax losses", these would 

be carried forward to reduce income during the period 

until they had been used up. 
- 20 -

In this example, income measured under tax rules results 

in a $600,000excess comparison with income measured under 

ideal rules. -1/ The ideal rules start measuring income 

when oil starts flowing, not when the first dollar is 

spent on discovering the field. Whereas, the tax method 

shows "losses" during the investment period, the ideal 

method produces lower incomes during the productive period. 

In both cases no more than $20 million will be deducted from 

gross receipts as capital cost. But the tax accounting 

rules grossly misallocate income from oil and gas invest­
 

ment over time; they may be said to ''defer" recognition of 
 

income due to premature deduction (recognition) of cost. 
 

C. Statutory allowances for depletion. 
 

It is difficult at this late date in the history 
 

of income taxation to appreciate how difficult it must 
 

'i/ - The reader will notethat under "ideal" rules there is

only one figure for capital consumption, $1,200,000,

whereas both depletion and depreciation cost are shown 

under tax rules , a total of $600,000. In this simplified example, the total investment cost of $20,000,000

is attributed to the mineral whose extraction occasioned 

the investment. When the 10 million barrels have been 

extracted, the total investment will be worthless, and 

since we are not here concerned with discounting, the 

extraction of each barrel represents a t'consumption't

of $2 of capital. It should also be remembered that 

lifting costs shown are total costs of operating the 

field, including repairs to machinery and equipment,

assumed to be. adequate to carry the whole investment 

project to its productive end. 
- 21 -

have been to manage the introduction of a net income tax 
 

applicable to businesses already in existence. Today, 
 

virtually all assets held by enterprises have been acquired 
 

since March 1, 1913, the starting date for the present income 
 

tax. But the Revenue Act of 1913 imposed an income tax on 
 

enterprises employing assets which were acquired before tax 
 

accounting rules had to be applied. 
 Capital consumption 
 

allowances had to be based on March 1, 1913 asset values, or 
 

cost if acquired on or after that date. 
 For pre-existing 
 

assets, this requirement entailed a massive valuation task. 

This same requirement was imposed on owners of mineral properties in the Revenue Act of 1916, and if this had been the 

final word of Congress, much of the controversy that has ensued would not have occurred. 

It is important to understand how the 1916 rule applied. 
 

Again referring to the simplified example previously described, 
 

suppose that the $20 million investment had been completed 
 

before March 1, 1913, and the oil field had begun operations 
 

January 1, 1913. 
 On March 1, given the facts previously des­
 

cribed, and still ignoring the effects of discounting for sim­
 

plicity, the value 
 of the property would have been $40 million 

or $4 per barrel for 10 million barrels. As the comparative 

income statistics in the previous section indicate, the net 
 
- 22 -

income per barrel (at a market price of $5) was $2 and in 

addition there was a capital recovery allowance of $2 per 

barrel. For such a firm in production before March 1, the 

depletion allowance under the 1916 rule would have been 

$4 per barrel, and it would have had a taxable income per 

barrel of zero. Now suppose the same firm with the same set 
 

of facts starts operations with post-1913 investment. In 
 

this case the cost of acquiring the 10 million barrels of 

oil would have been $20 million, (ignoring administrative 

rules for the treatment of investment expenditures) and the 

proper depletion allowance would have been $2 per barrel, 

leaving a taxable income of $2 per barrel. (Of course, 
 

had the tax treatment of investment expenditures been used, taxable income would have been $3 per barrel unless the prior deduction of investment costs had resulted in a net loss carryforward). 

At first glance, these disparate results seem unfair. Two 

identical firms, one which found and developed an oil field 

before March 1, 1913, the other some time later, are assessed 

radically different tax bills: the early firm pays no income 

tax; the later firms pays a tax on $2 per barrel. But recall 

that the former firm found its oil before there was an income 

tax: it spent $20 million to find oil worth $40 million in the 

ground and, on this account earned $20 million, or $2 per barrel, 
- 23 -

before the income tax was enacted. This firm should not 

retroactively be assessed an income tax simply because, under 

the conventional rules of income accounting, the income is not 

"recognized" until received. In contrast, the other firm engaged in its activity after the income tax was imposed, and if 

it spent $20 million to find $40 million worth of oil, it earned 

$20 million, or $2 per barrel, under the aegis of an income tax 

and should pay tax accordingly. Salaries earned in 1912 were 

not taxable; the same salaries earned before March 1, 1913 were. 

Thus, whether by chance or by deliberate thought, Congress 
 

promugated the correct rule in 1916. Subsequent events suggest 
 

that Congress hit on the right rule by chance, for within two 
 

years they succumbed to the argument that "discovery value" 
 

depletion, namely a depletion allowance based on the value of 
 

the deposit discovered, would yield equitable treatment as be-
 

tween post-1913 and pre-1913 oil field production. In effect, 
 

Congress agreed in 1918 that the income from investment in oil 
 

and gas should be exempt from tax. But, when depletion "dis­
 

covery value" was coupled with the administrative rules re­
 

garding investment outlays then being developed, the result was 
 

more than complete exemption of oil and gas income from tax. If 
 

adding the $40 million of total "discovery value" depletion 

allowances to the $14 million of expensed exploration and development outlays and the $2 million of depreciation deductions, net 
- 24 -

taxable income would be negative over the life of the project. 
 

The utter inanity of this state of affairs quickly became 
 

apparent in the tax returns of oil producers who were con-
 

currently engaged in any degree of discovery and development 
 

investment. The deduction of discovery value depletion in-
 

variably produced net operating "losses"; and the first "tax 
 

shelter" was born. 
 Offended by this result, Congress moved 
 

to "correct the abuse" in a manner which has since become 
 

characteristic: rather than repeal the erroneous administra­
 

tive tax treatment of investment and its own legislative mistake 

in allowing "discovery value" depletion of the Post-1913 Properties, 

Congress instead limited allowable discovery depletion to an 

amount which reduced taxable income to zero. Allowable discovery 
 

depletion could not exceed 100 percent of taxable income com­
 

puted without regard to depletion. This limitation was later 
 

stiffened to a maximum of 50 percent of taxable income computed 
 

without regard to depletion. 
 

Since this kind of response to perceived "abuses" has 
 

become characteristic, it is worth explaining why such cures are 
 

more deadly than the imagined disease. 
 In order to maximize 
 

the expected profitability of an investment under this kind of 
 

income tax constraint, discoverer-developers are driven to 
 

select investment programs conditioned by their momentary tax 
 
- 25 ­

status--whether they are currently producing oil, how much, 
 

and at what lifting costs. As a consequence, investment pro-
 

grams selected are likely to be socially inefficient. For 
 

example, investors producing little oil relative to their 
 

current investment program are forced by the income limita­
 

tion to sacrifice tax benefits as compared with investors 
 

producing large amounts of oil; thus, the former investors are 
 

confronted by effectively higher investment costs for reasons 
 

completely unrelated to their judgment or skill. Moreover, 
 

income limitations on depletion have the perverse effect of 
 

penalizing oil producers who happen to operate properties with 
 

physical characteristics that impose higher lifting costs, as 
 

commonly happens toward the end of the productive life of a 
 

field. 
 If there must be an arbitrary statutory rule for deple­
 

tion allowances, economic efficiency requires that it be made 
 

fully available to all producers, without reference to taxable 
 

income. 
 

But the demise of discovery value depletion did not come 
 

about because an enlightened Congress came to understand the 
 

error it had committed in 1918. Rather, discovery value deple­
 

tion was repealed because it proved administratively unworkable. 
 

As noted earlier, an inherent characteristic of the oil and gas 
 

investment process is great uncertainty concerning the extent 
 
- 26 -

of recoverable reserves at virtually every stage before an 

oil field is abandoned. Not only is the size of recoverable 

reserves uncertain at the time a well begins to produce, but 

the value of the reserves in place (the $4 figure in the 

example) is at least as uncertain. The value of a discovery 

depends on the expected future price of oil, on the amount of 

the recoverable reserves, and the characteristics of the field 

which determine the time pattern of recovery and how much it 

will cost to lift the oil. Absent a bona fide sale of the total 

interest in a mineral property, a rare event which almost never 

occurs immediately after a discovery, there is no easily determinable ''discovery value," plus quantity of recoverable oil, on 

which the taxpayer and revenue agent could agree. Taxpayers, 

naturally, had an interest in establishing a high lrdiscovery 

value" and low initial estimates of reserves (which could be revised upward in later years), while revenue agents were eager 

to establish lower values and higher estimates of reserves to 

''preserve the revenue." In order to put an end to the growing 

backlog of unsettled tax disputes, Congress invented percentage 

depletion in 1926 as a substitute for discovery depletion. The 

rationale for percentage depletion, if one accepts the reasoning 

of discovery depletion, was that, on the average, the value of oil 

in the ground is some fraction of market price; and since market 

price is more readily determined than the value of oil in the 
- 27 -

ground, application of the percentage depletion rate to the market price of the oil would provide a "fair" depletion allowance. 

Of course, the ''correct'' percentage depletion rate is as variable as oil field productivity and, for any given field, would 

vary as the market price of oil rose and fell with market demand. Nevertheless, Congress initially determined that 27 1/2 

percent of the market price of any oil produced anywhere in the 

world by an American taxpayer could be taken to represent depletion, provided it did not exceed 50 percent of taxable income 

computed without respect to depletion. In 1969, the percentage 

depletion rate for oil and gas was reduced to 22 percent and in 

1975, percentage depletion as a general principle was repealed, 

-I/

but an important "small producer'' exemption was preserved. 

Neither discovery depletion nor its successor, percentage 

depletion, is the exclusive allowable method; "cost depletion" 

is always permissable and is sometimes used. Occassionally, when 

a field is first brought into production, and the estimate of 

recoverable reserves is extremely low, the annual production is 

-1/ The so-called small producer exemption applies to the first 

2,080 barrels of average- daily o&l production (an 12,000,000 

cubic feet of natural gas). This figure is to be phased down 

until it reaches 1,000 barrels in 1980. The depletion rate 

is to be phased down from 22 percent to a permanent level of 

15 percent in 1984. 
- 28 .. 

a large fraction of estimated reserves, and the fraction of 

capitalized costs attributed to the well may exceed percentage depletion. Moreover, when a reasonably productive property is sold at a price which represents the present value 

of recoverable reserves, the buyer will often find cost depreciation preferable to percentage depletion, But in the over­

+' 

whelming majority of cases, including those instances when cost 

depletion allowances have exhausted the capitalized depletable 

basis, percentage depletion is taken. 

D. Summary 

Table 2 summarizes the effect of tax accounting rules on 

the amount of income which would be reported for a property 

described in the simplified reference example and compares 

these amounts with an ideal income accounting result, Clearly, 

in this example, percentage depletion yields the taxpayer a 

lower taxable income than "cost depletion." Indeed, since cost 

depletion in any year represents a pro-rata deduction of the 

beginning-of-year depletable basis reduced by -all tax depletion 

allowances taken in prior years, once the taxpayer begins to 

take percentage depletion, he rapidly exhausts the depletable 

basis thereby ensuring that percentage depletion will be taken 

in the future. Unlike conventional capital cost recovery procedures, percentage depletion is not limited to recovery of a 

fixed base. 
--- 

Table 2 

Effect of Depletion Allowances on Annual Income 

Income accounting methods 

Tax rules 

: Percentage 

: "Ideal" rules : Cost depletion : depletion 

Gross income (600,000 bbls at $5).. ...... $3,000,000 $3,000,000 $3,000,000 

Less: Lifting costs, total ............. 600,000 600,000 600,000 

Capital consumption: 

Depletion ...................... 1,200,000 240 ,000 660,000 

Depreciation ................... 360,000 360,000 

a/ a /

Annual income .......................... $1,200,000 $1,800,000-' $1,380,000-' 

-a/ In the event the taxpayer had been unable to deduct the $14 million of pre-production 

"tax losses ," these "losses" would be carried forward to reduce production period 

tax income accounting figures until exhausted. 

- 29 -

In this example, the 22 percent depletion allowance rate 
 

does not equal "discovery value" depletion, for the taxpayer 
 

ends up with taxable income of $1,380,000rather than zero. 
 

This is not surprising, for the logic of discovery value deple­
 

tion was to completely exempt the income from mineral discovery 
 

and development from tax. If it could be operationally applied, 
 

discovery value, fully reflects the natural differences in 
 

quantity and quality of minerals that would be produced by the 
 

highly uncertain investment process. The percentage depletion 
 

allowance, being a fixed percentage of selling price, does not 
 

account for these differences. And since the market price of 
 

any particular barrel of oil is independent of the lifting cost 
 

of that barrel, the expected percentage depletion allowance per 
 

barrel from prolific discoveries is substantially less generous, 
 

viewed prospectively,than for run-of-the-mill discoveries. 
 

When this aspect of percentage depletion is combined with 
 

the tax treatment of investment expenditures, under which lease 
 

bonuses and geological and geophysical expenditures must be 
 

capitalized while drilling costs are not, it becomes clear that 
 

tax rules discriminate against that kind of investment process 
 

which is likely to be most socially productive, namely the search 
 

for large and productive reservoirs, and favor the search of 
 

accessible reserves and the overdevelopment of existing reserves. 
 
- 30 -

Under our tax laws, the lesser the portion of the investment 
 

dollar devoted to extensive geological and geophysical search 
 

for good prospects, the greater the potential tax benefit per 
 

dollar spent. But the lesser the effort devoted to this funda­
 

mental mineral R&D expenditure, the more costly is the oil 
 

ultimately found. It is in this sense that percentage deple­
 

tion must be judged an inefficient tax subsidy. 
 

Finally the observation may be made that because the tax 

treatment of oil and gas investment so grossly distorts the 

timing of income for tax purposes, it wastefully distorts utilization of existing reserves. So far as the tax cost of producing 

an additional barrel of oil productive capacity is concerned, it 
 

is "cheaper1'to look for a new deposit than to adopt measures 
 

(secondary and tertiary recovery techniques) which will extract 
 

more oil from existing deposits. 
 

111. Economics of oil and gas investment decisions and the 
 

effects of taxation. 
 

Notwithstanding the uncertainties related to investment in 
 

oil and gas reserves, the process may be characterized in a manner 
 

which permits its analysis by the usual model of rational deci­
 

sion making. Discovery and development is neither an art nor 
 

a random process. Although "everybody" cannot expect to achieve 
 

average success in finding oil by drilling holes in the ground, 
 

neither can "everybody" achieve average success in farming, 
 
- 31 -

establishing a manufacturing business, or even a grocery 
 

store. Investment decisions require skill in assessing un­
 

certainties and specific knowledge of technology and markets. 
 

Not "everybody" is equipped to make the hard decisions called 
 

for in investment choice. But those who are equipped do make 
 

choices, and this implies the use of a rational procedure. 
 

The investor seeks to acquire those assets which promise to 
 

yield him -a rate of return which is greater than the rate of 

return he7 might earn buying other assets--not all other assets, 

but those of which he has knowledge. He is thus concerned with 

the outlays he must make to acquire assets and with the stream 

of receipts and outlays to which the purchase of the assets 

commits him. He chooses among opportunities known to him, each 

opportunity consisting of paired outlay and revenue streams. 

In the example used in previous sections, the investor who 

could earn 10 percent in the most profitable of the alternative 

investments known to him would undertake the discovery and 

development of that oil field only if his assessment of the expected costs and gains yield him a higher return. The assessment involves reducing each of the streams to a single value at a 

common date. In the following paragraphs we shall employ the 

basic methodology used by any investment decision maker, but we 

shall do so now to demonstrate how the terms of taxation affect 

the costs and benefits. 
Fundamental to this anal-ysisis the assumption that entry 
 

into the oil business is as free as entry to farming, manufac­
 

turing, or any other industry. Objective evidence suggests 
 

that this is not an heroic assumption. In the oil business a 
 

host of risk-pooling devices have evolved which make it possible 
 

for anyone with the requisite skills to enter; there need be no 
 

more risk of catastrophic failure in oil than there is in, say, 
 

farming, given the infinite divisibility of property rights in 
 

minerals. Moreover, available statistics reveal that large num­
 

bers of firms enter and leave the oil producing business in re-­
 

sponse to changes in economic conditions. Finally, there is no 
 

evidence whatever that rates of return to investment in oil and 
 

gas reserves have been higher than in other industries--although 
 

some oil firms, at some times, have earned more than average, as 
 

previously noted. 
 

The critical role of this competitive assumption arises from 
 

the approach we will take below. If the expected return from oil 
 

is above average, given a set of investment cost conditions, more 
 

investment will be made, output of oil will increase to drive the 
 

price of oil down, or investment costs will rise until the rate 
 

of return in oil is no higher than average. And if conditions 
 

change to make the expected rate of return below average for a 
 

given set of investment cost conditions, investment will be re­
 

duced, and output of oil will decline, forcing prices up, or 
 
- 33 -

investment costs will decline until the rate of return is no 

lower than average. Thus, in what follows we adopt the longrun view: rates of return are normal, and, to keep the exposition simple, cost conditions remain unchanged. Therefore, prices 

of oil will be adjusted to compensate for the rate of return 

impact of tax rules. 

A. The simplified example recast to account for time and 

rate of return. 

Investment decisions are made at some specified time with 

respect to actions that will occur over a subsequent period. 

These actions are outlays with respect to an economic activity 

and corresponding receipts. We have used the example of $20 

million expended on the discovery and development of an oil 

field which contains 10 million barrels of recoverable reserves 

extractable at some additional cost. But the $20 million will 

be expended over a span of time, and when the field begins to 

produce, its flow will also span a future number of years. To 

analyze this example, then, we must adopt a reference point in 

time and make additional assumptions necessary to relate events 

to this reference point. 

First, we will continue to use the simplifying assumption 

that investment is made over some period of time, and that when 

this period ends, production begins. The point at which production begins will be taken as the reference point. 
- -34 -
 

We assume that investment outlays are made at the rate of 

$4 million per year for 5 years. At the end of the investment 

period, using a discount rate of 10 percent, this expenditure 

has a cumulated value of $24,420,400, which is the real cost 

to the investor after 5 years. If the investor had made these 

outlays in alternative projects, his net worth at the end of 

5 years would have increased by $4,420,400. However, in accordance with conventional historic accounting rules, the total 

"basis" of this investment remains $20 million. 

We assume that the oil found will be produced by this field 

over an approximate 15 year period, and the flow will decline at 

approximately 10 percent per year. This implies the first year 

production will be about 1.2 million barrels (nearly 3,300 

barrels per day), and each succeeding year's output is 90 percent of the prior year's. 

For simplicity, we finally assume that the lifting cost per 

barrel is constant at $1per barrel. Although this is unrealistic, 

since the lifting cost per barrel tends to be low early in the 

productive life of a field and then to rise as natural reservoirs 

are depleted, it simplifies calculations and does not severely 

affect the results. 

Since, at the point production is to begin, investment cost 

is $24,420,400 and we know the pattern of output which will result, 

along with the associated lifting costs, it is a simple algebraic 
- 35 -
 

exercise to determine what the selling price per barrel must 

be so that the present value of the receipts, discounted at 

10 percent, will cover lifting costs, also discounted at 10 

percent, and be equal to $24,420,400. That price turns out to 

be $5.026 per barrel. If the future prices of oil are expected 

to be at least this high, the investment will yield at least 

10 percent. As shown in column (1) of Table 3, if all 10 million 

barrels are sold at $5.026 per barrel, the present value of 

gross receipts at the time production begins would be $30,485,560, 

and subtracting from this the present value of future lifting 

costs equal to $6,065,160 yields net future excess of receipts 

over outgo of $24,420,400. This is exactly equal to the investment cost evaluated at the same time. Thus, the investor would 

be assured a rate of return of 10 percent if the oil is sold at 

$5.026; if the expected future price were higher, the investor 

would earn more than 10 percent; if the expected future price 

were less than $5.026, he would earn less than 10 percent. 

When the entire span of investment and production is 

examined, as it must by a prospective investor, no specific 

allowance need be made for "capital consumption. 'I Capital consumption is inherent in the calculation: the investor has expended $20 million over 5 years, and he recovers his investment, 
-- 

-- 

-- -- 

Table 3 

Necessary Price Per Barrel of Oil to Yield 10 Percent, 

with Associated Financial Data 

With 50% income tax: 

. Without 

* income tax: - Tax rules 

Item : Percentage 

: "Ideal" rules : "Ideal" rules : Cost depletion : depletion 

Necessary price per bbl............................ $ 5.026 $ 7.053 $ 5.634 $ 5.110 

Discounted values, when production begins 

Gross receipts (10 million bbls) ........(a). ....... (thousands ) $30,486 $42,776 $34,173 $30,99 3 

Less: Lifting costs ...................... b) ........ 6,065 6,065 6,065 6,065 I 

Net taxes paid .................... (c) ........ 12,290 3,687 508 w 

Taxes during production .........(d) ........ 12,290 12,234 9,055 m 

Tax saving during investment.. ..(e). ....... (8,547) (8,547) I 

Investment cost = (a)-(b)-(c). ..................... $24,420 $24,420 $24,420 $24,420 

- ~~ 

Note: Individual items may not add to totals due to rounding. 
- 37 -

with interest at 10 percent, by selling 10 million barrels 

of oil over 15 years at $5.026 per barrel, after which his 

investment is worthless. He has recovered his cost, plus 

interest. 

B. Introducing taxes into the investment decision. 

Imposition of an income tax introduces an 

additional annual outlay which an investor must take into 

account when determining whether to select an investment. 

What needs to be added to the above calculations therefore, 

is a computation of the annual income tax payment which will 

be demanded if the project is undertaken, and since this 

involves a set of accounting rules to determine taxable 

income, we must explicitly set forth the income tax formula. 

As suggested above, we could apply an "ideal1'set of accounting 

rules and apportion the aggregate investment of $20 million 

(undiscounted) to the 10 million barrels of oil to 

calculate an annual depletion allowance as the oil 

is extracted. Alternatively, we could apply tax accounting 

rules, which allow the write-off of $14 million of investment cost when incurred, and then determine an annual 

depletion allowance by either ''cost depletion" (combining 

depreciable basis with depletable basis for ease of 

calculation) or percentage depletion. We take up each of 
- 38 -
 

of these variants in order. 

(1) Taxation with "ideal" accounting. 

Each year we compute a tax liability, at an 

income tax rate of 50 percent, that would be generated by 

selling the quantity of oil produced that year at a price 

such that, after allowing for the tax and the lifting costs, 

the after tax net recipts will have a present value of 

$24,420,400. Since the income tax formula is specified, 

we merely deduct from each year's gross receipts the lifting 

cost plus $2 per barrel "ideal" cost depletion and multiply 

by 50 percent to determine taxes paid. And only a slightly 

more complicated algebraic problem must be solved to 

determine the necessary selling price of oil, which is 

found to be $7.053. Why this is the necessary price to 

yield the investor a 10 percent rate of return is shown in 

column (2) of Table 3. Selling 10 million barrels of oil 

at $7.053 per barrel will yield a present value of gross 

receipts of $42,775,640, and this is sufficient to cover 

the unchanged lifting costs plus $12,290,080 in income tax 

and leave him $24,420,400 which represents a 10percent 

return on investment. 

It is worth pausing a moment to compare the before and 

after tax result. Imposing an income tax in this illus-
- 39 ­

trative case implies that the price of oil must go up by 
 

$2.027 per barrel, if the rate of return is not to be 
 

reduced. Why would this happen? Unless one is persuaded 
 

that investors will undertake investments without regard 
 

to rates of return, one must accept the consequence that 
 

an income tax imposed on the return from reproducible 
 

capitalraises before tax rates of return - in other words, 

causes prices embodying capital costs to rise - in order to 

ensure the same after tax rate of return. -1/ 

Consider the probable response of investors to a 

situation in which the going price for oil has been $5.026 
 

and a tax is imposed. Investors need not drill for oil 
 

with the resources at hand; they could retire and convert 
 

their capital into an annuity. 
 Suppose that some of them do 
 

so. Not only will a reduction of discovery and development 
 

activity reduce future flows of oil, but also the signal 
 

provided by lesser investment activity will be observed 
 

rrThe assumption that after tax rates of return remain the 

same implies that the supply of savings for capital

formation is highly elastic. While there is no agreement 

on the likely elasticity of supply of savings, it is 

difficult to argue it is zero, that the same amount of 

saving will occur regardless of the return that may be 

earned. So long as it is not zero, the imposition of 

an income tax must cause before tax rates of return to 

be higher than rates of return would be in the absence 

of tax. That is, some of the "burden" of the income 

borne by non-capital owners, and the gist of the argument

in the text stands. 
- 40 -
 

by those who own producing fields. Anticipating that 

future prices will be higher, some of the current producers 

will conclude that oil may be worth more "in the ground'' 

than in a pipeline to the refinery. As they cut-back some 

of their current output, upward pressure on prices begins, 

and the process continues until, at a price which assures 

the necessary rate of return to investors, a sustainable 

rate of production is achieved, When the adjustment is complete, a length of time roughly proportional to the severity 

of the initial disturbance, after tax rates of return will 

have been partially or wholly restored. 

(2) Taxation with tax accounting. 

If instead of "ideal" accounting we apply tax rules for 

the treatment of investment expenditures, we may recompute 

tax liabilities with "cost depletion," when the depletable 

costs are 30 percent of the total investment, or $6 million. 

In this event, as shown in column (3) of Table 3, the necessary price of oil required to yield an unchanged 10 percent 

return to the investor is only $5.634 per barrel. Under the 

cmat tax accounting rules, almost the same amount of taxes 

are paid during the production period as under "ideal" 

accounting, but a negative tax, or "tax saving," is incurred 

during the investment period. Net taxes paid are reduced, 

and this permits the lower price to prevail. For the same 
- 41 -

reasons that imposition of a tax may be expected to raise 

prices, diminution of a tax may be expected to reduce prices. 

If percentage depletion is substituted for "cost depletion," a further diminution of tax liability results, in 

this instance during the production period. The lower tax 

makes possible a price of $5.110, which is only 7.4 cents 

higher than the necessary price without taxation. Thus, 

under the cost assumptions of this example, tax rules have 

almost succeeded in exempting oil and gas investment income 

from taxation. 

It is instructive to evaluate the relative tax benefits 

conferred by the tax treatment of expenditures and by percentage depletion. Taking the "ideal" accounting procedures - as the norm, 

I/ 

expensing of investment expenditures reduces 

the necessary price per barrel by $1.393, while substituting 

percentage depletion for ''cost depletion" reduces the necessary 

price by an additional $0.524. Thus, of the entire $1.917 

reduction in necessary price per barrel made possible by the 

package of tax rules, expensing of capital outlays accounts 

for 73 percent, percentage depletion for only 27 percent. 

-1/ The reader is reminded that only by virtue of simplifying

assumptions is it conceivable that ideal income accounting

rules might be employed. In particular, the text ignores

the effect of uncertainty and diverse property rights in 

minerals on the identification of investment outlays, and 

it assumes that the investment period is discrete and precedes the production period. 
- 42 -

As noted in the Preface, although public debate has 
 

focused on percentage depletion, percentage depletion is 
 

not the most significant element in the tax treatment of 
 

oil and gas. 
 

C. Summary 
 

Investment in oil and gas reserves and productive capa­
 

city, though it is subject to unique risks, is a rational 
 

process. Investors who are qualified by skill, training and 
 

experience make choices among known alternatives, each of 
 

which may be described as a stream of paired expected out-
 

lays and receipts. The investment decision first requires an 
 

evaluation of alternatives by converting the time streams of 
 

outlays and receipts to values at a common date (normally the 
 

decision date), and then selecting that alternative which pro­
 

mises the greatest increment in the investor's expected net 
 

worth. 
 

Income taxation affects the investment process by altering the streams of outlays and receipts. But the impact 

of a tax on income from capital depends upon the rules used 

for measuring taxable income. As it happens, the rules which 

have evolved for measuring taxable income from oil and gas 

investment effectively exempt that income from taxation, 

largely because so much investment expense is allowed as a 
- 43 -

current deduction in computing taxable income. 
 

So long as investment in oil and gas reserves and 

productive capacity is a rational process, and so long as 

entry into the industry is free, limited only by the willingness of qualified investors to undertake projects, tax burdens are ultimately reflected in the price of oil and gas. 

The presence of tax is not an "impediment" to investment; it 

merely requires that prices adjust to provide investors an 

expectation of normal return. Nor is the absence of tax burden, whether through the expensing of investment outlays or 
 

through percentage depletion an aid to financing investment; 
 

these devices merely facilitate the existence of a lower price 
 

of oil than would otherwise prevail. With or without taxation, 
 

the investor must find the financial means to carry out an in-
 

vestment project. When he is at the initial stage of invest­
 

ment evaluation, deciding whether to plunge ahead, the finan­
 

cial resources he may tap consist mainly of his credit worthi­
 

ness and his liquid assets. If the investor has a substantial 
 

net worth which generally signifies a history of successful 
 

investment decisions he can readily find coinvestors or borrow 
 

needed funds. His access to external financial resources will 
 

be enhanced if his current liquidity is high, somewhat dimi­
 

nished if his liquidity is low. But none of these determi-
 
- 44 ­

nants of an investor's access to financial resources is 
 

especially dependent on the terms of taxation. 
 

For example, assume that the data in Table 2 represents the condition of an oil producing enterprise before 

taxes are levied. The pre-tax cash flow is $2,400,000, 

no matter how "income" is accounted for: in each case, 

$600,000of $3,000,000gross income is paid out for lifting 

costs. If a 50 percent tax was then levied on each of the 

three measures of ''net income," the net cash flow would be 

reduced by $600,000in the case of "ideal" income measurement, by $900,000in the case of tax accounting with cost 

depletion, and by $690,000 in the case of tax accounting with 

percentage depletion. And explained earlier, compensating 

changes in cash flows resulting from tax and other changes may 

be expected in the price of oil, and a rational investor is 

indifferent as to whether his rate of return is generated by 

gross sales at future higher prices, or by reduced tax pay­ -I/

ments at future lower prices. In the final analysis, the 

-1/ It might be observed, however, that a businessman instinctively prefers a future state of affairs in which the prices

at which he has to sell will be lower rather than higher.

This is probably due to the widespread understanding by

businessmen (in contrast to legislators) that more can be 

sold at lower prices, and that any single business firm is 

more secure in a broader market. Even though businessmen 

know that higher costs, whether for labor, materials, or 

taxes will ultimately be reflected in higher prices, they

resist changes which force this outcome. But the narrow 

interest of businessmen is not a suitable guide to public

policy formation. 
-- 

- 45 -

terms of taxation have no significant effect on the ability 
 

and willingness of qualified investors to undertake projects 
 

provided that evaluations of future prices and outlays result 
 

in favorable profit expectations. 
 

IV. Slogans 
 

The foregoing sections have set forth the proposition 
 

that taxing the investment income from oil and gas production 
 

is not a simple exercise of taxing "oilmen." Notwithstanding 
 

the popular and fallacious notion that "income taxes'' are 
 

"direct" and hence cannot be shifted, a tax on income from 
 

capital imposes a cost like any other which must eventually be 
 

reflected in prices. Capital is mobile--it can be shifted to 
 

a wide variety of applications--and it is ultimately variable 
 

in quantity; more or less capital will be accumulated depending 
 

on the reward capital owners are provided. 
 

Without inquiring into the broader question whether a 
 

general income tax on capital is more or less absorbed by 7all 

capital owners, or partially by capital owners and partially 

by sellers of personal services (wages and differential returns 

to human capital), we may take it as incontrovertible that 

discriminatory income taxation of a particular form of capital 

will not be borne by those who own that particular form of 

capital. If, as in the case of oil and gas, the burden of tax 

has been made preferentially -low, this does not "enrich" oil 
 
- 46 -

and gas property owners. The preferential taxation will 

have served only to attract more investment, to a point 

where after -tax rates of return are no different from rates

of return in other nonpreferred investments. 

This state of affairs is a serious cause for concern, 

not because 'loilmen'' escape taxation, which generally speaking 

they do not, but because the tax system is overtly used to 

misallocate capital from the more fully taxed sectors of the 

economy to the least taxed. For example, in the figures shown 

in Table 3, net taxes paid represent 29 percent of total payments by purchasers for oil if "ideal" income accounting 

methods are applied, only about 11 percent under tax accounting 

with cost depletion, and only 1.65 percent under tax accounting 

-1/

with percentage depletion. What all this means is that consuners are misled by the tax laws to believe that oil costs less 

-

-

1/ Using the r'ideal" data as a norm, it is apparent from

Table 3 that $42,776,000 must be equal to the present value 

of lifting costs plus capital consumption plus income on 

investment plus income taxes, all pertaining to the 15 year

production period. It may be deduced that the "proper" present value of future capital consumption allowances is 

$12,131,000, and we may therefore compute "before tax income" under the three tax regimes of Table 3 as follows: 

Income Accounting Methods 

"Ideal Tax Rules 

rules 'I cost Percentage

Gross income depletion dep1et io; 

Gross income ................. $42,776 $34,173 $30,993 

less: Lifting cost ........ 6,065 6 ,065 6, 065 

Capital consumption. ...... 12, 131 12,131 12, 131 

Before tax income ......... $24,580 15,977 $12, 797 

Net tax paid ........... 12,290 3,687 508 

After tax income ......... $12,290 12, 290 $12, 290 
- 47 -

while other products, produced by capital which is more fully 
 

taxed, cost more. Accordingly, too much oil is produced and 
 

consumed, and too little of the other goods. Everyone would 
 

be better off if this state of affairs had been avoided by 
 

better tax policy-making; Iloilmen," other owners of capital, 
 

-1/ continued from page 46 

Note: 	 It might assist readers unfamiliar with the mathematics 

of discounting to consider the analogy of an installment 

sale, or mortgage loan, The present value of compensation to the owner of the property, to equal his cost of 

$24,420 (from Table 3) and yield him a 10 percent return 

on investment, has to be a series ot payments whose pre-I1 

sent value is $24,420, "interest plus return of capital.

In this example, $12,131 is the present value of 11 the return of capital portion, $12,290 the "interest, or 

income, portion. He must "net" this regardless of the 

tax rules, and he may do so under different terms of 

relaxation if his gross receipts compensate him. 

Because "before tax" incomes are not independent of 

the terms of taxation, this example serves to illustrate 

why the popular diversion engaged in by economists and 

legislators alike, when they appeal to published financial statements to compute "effective tax rates," is so 

useless as a guide to policy formulation. Not only are 

financial statement incomes produced by rules that 

already reflect major adjustments to the effects of 

taxation, but also the results they report for a particular year show ''income" and "tax" figures which are not 

synchronized. For example, an oil company currently

investing heavily in new properties will report "low 

taxes'' that year, an irrelevant fact for any long term 

analytical purpose in view of the time span required to 

assess the outcome of this year's decisions. 
- 48 -
 

and all wage earners would have benefited. They would 

also benefit in the future if corrective action were taken 

now. 

Although this paper is now complete as a review of the 

issues which must be dealt with in the future evolution of 

tax policy in this controversial area, it may be useful to 

critically review slogans most commonly repeated both by 

those who regard efforts to correct tax policy mistakes as 

suicidal and by those who evangelically preach the gospel 

that everyone should "pay his fair share of income tax." 

A. "Repeal of percentage depletion would deprive the 

oil (hard minerals, sand, gravel, etc.) industry of 

capital needed to increase domestic capacity." 

Those who wave the banner emblazoned with this slogan 

take great pains to show that annually their firms spend 

at least as much on exploration and development as the tax 

saving from percentage depletion. If they could not take 

these deductions and thus had to "pay" higher taxes, they 

would have to cut their investment. 
- 49 -
 

(1) The kernel of truth and its triviality, 

After a set of tax rules has been in effect for a 

long period, prices of products and therefore gross receipts 

become adjusted to the tax regime and rates of return are 

normalized. Then, if the tax rules are stiffened, as by 

elimination of percentage depletion, firms currently engaged 

in producing the preferred product will immediately suffer 

a reduction in net cash flows. The same result would occur 

if wage rates, money market rates, severance and property 

tax rates, or any other cost rose. Whether any of these 

changes in the economic environment will impede investment 

is determined less by their impact on current year's cash 

flows than by their anticipated effect on the long-term profitability of investment. 

Presently, when the current and near term market price 

of oil is well above expected future levels, the impact of a 

tax or other cost increase on current cash flows of oil companies can have little consequence for investment decisions. 
- 50 -

Even with a substantial tax increase, their net cash flows 
 

after the price changes would still be far above their net 
 

cash flows before the price changes. Additionally, the 
 

increased value of existing assets provides the companies 
 

with a windfall increase in net worth that further enhances 
 

their access to capital markets. Moreover, firms not pre­
 

sently producing oil cannot be affected by a repeal of per­
 

centage depletion; they must weigh investment prospects for 
 

a future without percentage depletion in the same way present 
 

producers do. 
 And if they agree with present producers that 
 

the future price of oil will be adequate, they will invest with 
 

no more difficulty than they might if there were percentage 
 

depletion. 
 

But addressing the problem more generally, elimination 

of percentage depletion should retard investment if all 

qualified investors believe that less oil will be demanded in 

the future at higher prices. If consumers will reduce their 

demand for oil with an end of subsidized prices, it would be 

a waste of scarce social capital to invest now to produce the 

unwanted quantities. On the other hand, if the market will pay 

an unsubcridized price with no reduction in quantity purchased, 

investors will proceed, just as they would in the face of other 

rising costs of production. 
- 51 -
 

In sum, the sine qua non -of capitalism is that the 

capitalist risks his -capital for which he - earns a rate of 

return in the future. He will undertake this risk of his 

capital, when justified, whether his future return is supplied 

by tax subsidy, cash subsidy, or simply market price. There 

is no magic in percentage depletion (or in any other tax 

preference) . 

B. 	 "Repeal of percentage depletion falls hardest 

on "independent" oilmen who do the most drilling 

and who maintain competition in the industry." 

Technically, an "independent" oil producer is one who 

sells -all his output to others, -i.e., is not engaged in either 

transporting, refining, or marketing of oil products. But, in 

practice, an ''independent" is considered to be a firm producing 

less oil per day than the smallest of the oil companies whose 

names are household words because they sell branded oil products. As a consequence, many "independents" are large businesses, whether measured by assets, sales, or income, while 

others are operators of stripper wells producing a few barrels 

of oil a day, but otherwise not engaged in reserve discovery 

and development. "Independent" is the oil business euphemism 

for "small business," which often seems to mean an enterprise 

smaller than the 500th in the Fortune list of the largest 

U.S. corporations. 
- 52-

It is argued by spokesmen for this interest group that 

they drill upwards of 80 percent of "exploratory" wells, 

and that they depend heavily on capital raised from investors 

to whom the deductibility of percentage depletion, and drilling 

costs, is extremely important. Denied these preferences, the 

argument goes, the independents would be driven from the field, 

and oil production would be monopolized by a few giant oil 

companies. 

(1) Separating truth from fiction: "Independents 

drill more than 80 percent of all exploratory 

wells." 

Just as "independent" is a treacherous descriptive term, so is "exploratory well." In the discussion of 

Section I, the term llwildcat"was used to identify an exploratory well drilled to find a new reservoir. Technically, such 

other wells as lloutpost"wells--wells drilled subsequent to 

completion of a successful wildcat to establish limits of the 

field discovered--and wells drilled in existing fields to 

discover deeper or shallower pools of oil are also "exploratory" wells. But it is the successful new field wildcat that 

makes significant additions to reserves and productive capacity. 
Frickson, E.W., Economic Incentives, Industrial Structure and 

unpublished 

the Supply of Crude Oil in the United States, 

- 53-

One reason why "independents" are touted as drillers 
 

of more than 80 percent of all exploratory wells is that 
 

many of the wells they drill are not wildcats but rather 
 

"farm-outs" from companies engaged in wildcatting, or they 
 

are wells drilled in established oil-bearing regions. New 
 

reserves discovered with such wells are, more likely than 
 

not, piddling fields, barely worth commercial production. 
 

On the basis of studies concerning genuine wildcatting, 

it was concluded that "independents" and "minor" oil companies ("small" producers which also engage in other stages 

of the oil business) have accounted for no more than 75 percent of wildcat drilling. But, what is more significant, 

these "independents" and "minors" account for only about 20 

percent of geophysical and geological survey work done. As a 

consequence, their success rate is lower than that of the 

so-called "majors," and the fields they discover are less prolific. The "majors," though they account for relatively less 

drilling, have succeeded in finding more than 60 percent of 

-

11-

the recoverable reserves. As noted earlier, most firms in 

McKie, J.W., "Petroleum Conservation in Theory and Practice,"

Quarterly Journal of Economics, Vol. IXXVJ. (February, 1962).

Frickson, E.W., Economic Incentives, Industrial Strbcture and 

the Supply of Crude Oil in the United States, 1946--58/59,

unpublis Ph. D. dissertation, Vanderbilt Un:%/8t:?gb68. 
- 54 -

the oil business enjoy modest success, a few attain out-
 

standing successes. It is not surprising that the success­
 

ful grow to "major" status. Nor is it necessary that 
 

numerous moderately successful firms stay in business to 
 

assure wholesome competition. All that is necessary for 
 

competitive vigor is that entry be open to all who would 
 

venture the expense of a careful search for oil. For this, 
 

neither tax preferences nor other subsidies are necessary. 
 

(2) A kernel of inconsequential truth: "Independents" rely on investors to whom oil tax deduc­
 

tions are important. 
 

In recent years, a remarkable "growth" industry has been 
 

the marketing of shares in limited partnerships in "oil ven­
 

tures." Frequently, the general partner responsible for 
 

organizing these "ventures" is a small, "independent, oil 
 

company which utilizes the legal arrangement as a convenient 
 

device for selling to the limited partners the right to deduct 
 

immediately drilling expenses. In the event production ensues, 
 

the limited partners will have a share in production (and pro­
 

duction expense) entitling them to percentage depletion deduc­
 

tions. By aiming the distribution of such limited partner-
 

ship interests to individuals with otherwise highly taxable 
 

incomes--fromprofessional or other personal services 
 
- 55 -
 

or other investments--the general partner (I'independent") 

is able to highly advertise the resultant deductions--"you 

get back 70-90 cents for each dollar you invest and tax-sheltered income if we strike oil!" 

If the sponsoring general partner really lets all these 

passive investors who are utter strangers to him fully share 

the potential rewards for successful discovery, he obviously 

can gather capital more cheaply than if he appealed to investors for whom the value of tax deductions would be lower. 

But, as recent experience with certain oil funds amply demonstrates, general partners are content to market the deductions and retain for themselves the lion's share of the rewards, a mode of behavior which sooner or later becomes 

apparent to would-be "investors." As statistics on actual . 

subscriptions to ''funds'' registered with the SEC indicate, 

a quick peak to such marketings was reached some years ago; 

hardly enough is currently marketed each year to maintain the 

capital stock already subscribed. 

Thus, this source of "capital" for the independents, 

which never was very large in terms of annual investments made 

in the oil industry, is back to its former negligible level. 

For "independents ,I1 as for others who undertake oil ventures, 

reliance for additional capital will remain where it belongs, 

among those insiders who have demonstrated a capacity for 

undertaking such ventures and among outsiders able to carefully 
- 56 -

judge the qualifications of those with whom they invest. 

If neither depletion nor other oil tax preferences accounted 

for significant infusions of oil capital during the past 

30 years, when rates of return from oil investment were merely 

normal, their absence will not impair the flow of capital to 

this industry in the future, and particularly not in the 

immediate future when rates of return are spectacularly high. 

C. 	 "Repeal of percentage depletion will initiate taxminimizing sales of properties by independent oilmen , 

and the majors will monopolize the production of oil." 

Although this slogan is less widely disseminated, it is 

taken seriously by many because the warning comes from persons 

well-versed in the intricacies of tax law. In essence, this 

contention is based on the following chain of reasoning: 

Repeal of percentage depletion leaves "cost depletion" as the 

only allowable tax accounting procedure; since the discovererdeveloper-producer of oil from existing fields has little 

depletable basis to recover via cost depletion from future 

production, he will sell to another party because the other 

party, being able to "deplete" the purchase price over the 

remaining life of the well, can offer a price higher than the 

value of the property in the original owner's hands. 
- 57 -
 

(I) Analysis of the problem. 

Suppose that the information about a property is 

equally well-known to both the present owner and a potential 

buyer. The present owner will sell the property if, and only 

if, the price the buyer would be willing to pay, less the 

capital gains tax which the original owner would have to pay 

if he sells, exceeds the value to the original owner if he 

does not sell. The price of oil and the expected production 

pattern are data known to both the present owner and potential 

buyer. For simplicity, let us assume that both parties to the 

potential transaction are equally efficient operators, are 

in the same tax bracket, and let us ignore depreciation and 

assume that all capital recovery takes place through percentage depletion. What price would induce the present owner 

to sell when percentage depletion is abolished? 

If the present owner were to retain the property, its 

present value to him would be comprised of two parts: (a) 

the present value of the after tax stream of gross income 

receipts (in the absence of any capital recovery allowance) 

minus lifting costs, plus (b) the present value of the "cost 

depletion" tax savings he might accrue over the remaining 

life of the property. This present value equals the original 

owner's reservation price. 
-58-

If the same property were purchased by another, its present 
 

value to the new owner would be comprised of two parts: (a) the 
 

present value of the after tax stream of gross income receipts 
 

(in the absence of any capital recovery allowance) minus lifting 
 

costs, which is the same for the new owner as the original owner, 
 

plus (b) the present value of the purchaser's tax savings due 
 

to "cost depletion" of the price he would be willing to pay. 
 

Then, in order for a sale to occur, the purchaser's offer price 
 

less cap5tal gains tax.must exceed the present owner's reservation 
 

price. 
 

It can be demonstrated that the critical determinants for 
 

the occurrence of a sale are: (a) the adjusted basis of the 
 

property in the hands of the seller at the time in question; (b) 
 

the capital gains tax rate to which the presenti owner would be 
 

subject in the event of sale; and most critically, (c) the pro­
 

ducing characteristics of the property, which we may simply call 
 

the'tlecline rate," which will determine the present value of 
 

1/ cost depletion deductions.-
 

-1/ In general, the slower the production decline from an oil property, the more productive the well. Imagine that there is 

an oil well presently producing 3 barrels a day and which has 

been producing at that rate for the last 20 years. Since its 

production obviously depends on natural seepage from surrounding

formations, there is no basis for expecting the output to decline below 3 barrels for the foreseeable future. The ''cost 

depletion rate'' for such a property ought to be zero: neither 

the present owner, nor a prospective purchaser could claim 

cost depletion on the basis of a decline in productive capacity. Given its output characteristics, this is a "highly productive"

well, provided it costs less to pump up the seepage than the 

oil is worth above ground. Similarly, a large reservoir with 

highly propulsive "natural drive", if properly managed, holds 
-59-

The fears expressed that elimination of percentage depletion 

would result in the wholesale exchange of oil properties which 

would then end up in the hands of a few large oil companies are 

grossly exaggerated because: 

(a) The mathematics of the exchange strongly imply that the 

only properties likely to be sold are those which have two characteristics: they are in a sharp state of decline, and the owner 

has no depletable basis remaining. 

continued from page 58 

forth the prospect of a large yield (per day and aggregated 

over tens of thousands of days) which will decline only

slowly over many years before reaching a stage of rapid decline. In its early years, cost depletion of such a property

will be minimal, only a tiny fraction of recoverable reserves 

will be extracted each year, and only much later will annual 

output begin to markedly exhaust remaining reserves. The 

present value of this stream of depletion deductions will be 

extremely low, if evaluated at the beginning of the field's 

productive life, and almost as low as the slow producer just

described. In neither of these cases would the prospect of 

cost depletion be worth much to an owner and rightly so, for 

each, in its own way, is a veritable perpetual fountain of 

wealth. 

Ironically, only in the case of fields subject to rapid decline, 

no matter what the initial flow rate, is the present value of 

tax savings related to cost depletion of calculable significance. Obviously, such a field cannot be a prolific producer,

and each of the first years' output represents a considerable 

fraction of its lifetime output. For example, a field with 

a 10 percent per year decline rate and a life of about 15-20 

years would have produced half of its total output in a little 

more than 5 years. Even with a 25-30 year life, a field with 

a 10 percent decline rate would have produced half its output

within 6.5 years; but a field with a similar life but a decline 

rate of only 5 percent would not have produced half its output

before 9 years. 
-60-

(b) In the case of newly developed properties, only those 

axe likely to be sold to minimize taxes which have little depletable 

basis (because little more was spent than for drilling) and which 

have a short expected life (and thus a high decline rate). There 

may be large numbers of properties possessing these characteristics, 

but the total annual capacity they represent is trivial and in 

no event are they the kind of properties a large oil company would 

seek, since they are costly to manage. Indeed, one of the results 

of eliminating percentage depletion will be a more rapid divestment 

by large oil companies of many of their currently marginal properties. 

D. "Repeal of percentage depletion will make the tax system 

fairer and make oil companies pay their fair share of taxes." 

Just as the sloganeers who insist that percentage depletion is 

vital to finance investment are deluded, so are those who argue 

that ''oilmen'' somehow evade their fair share of taxes. It is 

incontrovertible that depletion deductions and other artificialities 

of the tax rules governing investment are worth more to high income investors that to low, and it is equally incontrovertible that 

the after tax rates of return in oil, like those elsewhere, are 

deterinirLedby the behavior of the marginal investor, not the 

wealthiest. It therefore follows that the net benefit conferred 

on the wealthy is the difference between their tax benefit and 

that 05 the marginal investor, not the full benefit of "nontaxability." For example, suppose that the marginal investor is 

someone with a tax rate of about 40 percent, and suppose his after 

tax rate of return is 10 percent. Prices of products are adjusted 
-61-

so that, with the battery of tax deductions, whatever they might 

be, the 40 percent taxpayer nets the 10 percent norm. A 50, 60 

or 70 percent bracket taxpayer will receive the sarreprice as the 

40 percenter, experience the same actual outlays, but his tax 

bill will be reduced more, for the artificial tax deductions 

lower his taxable income by the same amount but "save" him more. 

Instead of paying the higher tax appropriate to his income status, 

he pays no more than the 40 percenter. He is not relieved of all 

tax, but only the extra tax that would otherwise by imposed on 

him by the progressive income tax. 

From one point of view, this degradation of the progressivity 

of income tax is deplorable. It seems schizophrenic on the part 

of Congress to enact steeply progressive income taxes and then 

to proceed to enact tax subsidies which blunt the progressivity. 

The only way to avoid this result is to make all tax subsidies, 

whatever their intent, not exemptions of income from tax, but, 

rather, taxable subsidies. 

From another point of view, this result of percentage depletion 

and other artificial accounting rules is desirable. Saving and 

capital accumulation is the supply of a socially beneficial resource, no different from the supply of personal services. In 

both cases the supplier should be paid the same price for rendering 

a specified service regardless of his personal circumstances; but 

a progressive income tax precludes this result. In the absence 

of tax preferences, under a progressive income tax, the supplier 

of an additional dollar of capital nets less if he is wealthy 
-62-
 

than if he is not, just as his sale of an additional dollars' 

worth of personal service nets him less. A purely proportional 

income tax, coupled with a system of transfer payments not conditioned on economic services supplied, would avoid this inherent 

inefficiency of progressive income taxation and achieve the equity 

goals espoused by proponents of progressive income taxes.