THE COMPETITIVE FLOOR TO WORLD OIL PRICES
M.A. Adelman
Revised July 1986
MIT Energy Laboratory
Working Paper No. MIT-EL 86-011WP
THE VIEWS EXPRESSED HEREIN ARE THE AUTHORIS RESPONSIBILITY
AND DO NOT NECESSARILY REFLECT THOSE OF THE MT
ENERGY
LABORATORY OR THE MASSACHUSETTS INSTITUTE OF TECHNOLOGY.
THE COMPETITIVE
FLOOR TO WORLD OIL PRICES
M.A. Adelman
Department of Economics and Energy Laboratory
Massachusetts Institute of Technology
Cambridge, Mass. USA 02139
This paper
is a revision
of MIT
Energy
Lekboratory Working
Paper
No. MIT-EL
86-011WP. It relies in par t on three forthcoming
Working Papers: "Finding & Developing Cos ts in the USA 1947-85";
"Discount
Rates for Oil Producing LDCs", and "A Restatement of
Mineral Depletion Theory"; also on a past Working Paper,
"Scarcity
and World
Oil Prices",
to appear
Review of Economics & Statistics.
ongoing research project
Foundation,
Center for
Cavoulacos,
Michael
leger
C.
Jr.,
grant
supported by
#SES-8412971,
Energy Policy
J.
E. Hartshorn,
Lynch,
Geoffrey
for comments
James
L.
They
in
the
all
are
parts
the National
an
Science
and by the Energy Laboratory
Research. I
am indebted to Panos
Henry D. Jace)by, Gordon M. Kaufman,
Paddock,
Thoma s
N eff,
Phili p
Ward, G. Campbell Wati
cins , and Davi d
on earlier
of
K.
O.
VerWood
versions. But any opinions, findings,
conclusions or recommendations
expressed herein are those of the
author, and do not necessarily reflect the views of the NSF or
any other person or group.
Abstract
In this OPEC crisis or the next,
competitive floor.
oil prices may fall to the
At the high-cost end of the spectrum, it would
take a price as low as $4 to produce
half of capacity
in the United
same in the North Sea.
investment
an immediate
States,
shutdown
of nearly
and as low as $2 to do the
A price of $10 would stop development
for the bulk of U.S. oil and over a third
of North
Sea
Capacity would therefore decline by roughly 6 percent per year.
oil.
At the low-cost end, assuming continued competition and completely
independent decision-making, a price of $5 would make it profitable
for the OPEC nations to expand output to about 60 million barrels
daily.
This price would be sustainable past 1995.
is not a forecast, however.
This projection
Years
ago,
the author
suggested
that there was
oil
no
shortage current or impending. Growing consumption, static U. S.
U. S.
production,
imp ly
rising
fai 1
ir ng
ri s inc I
and other rea sons
prices. There
fruits
i s)
(and
pressure on reserves, signaledI by rising
ut
the
output. T here wa!s no sign
oil-exporting
of collusion
bottl e."
prem i se,
a hidden major
the conclusion makes no sense. One must
which
tai ni n g and expanding
B
was
ofrfered then and now, did not
They would
naitions
on a modest
had
scale
"The genie
success
of
tasted
the
is out of the
[Adelman
1972]
but overreached.
,
m ain-
this.
in 1970-71
try harder to get more.
The cartel was a great
of
costs
as sume
Lower
consumer demand and rising non-carte'I output cut their exp orts
drasticallly. In theory,
the
members
cciuld
have
agreed--can
s till
agree--on sharing the smaller pie, to leave them all better off.
In practic ce, they have not been able tco
The
ass is
member,
Asian
burden
of output
usual
in coalitions.
defeense is another
near zero last summer,
threats.
They began
cutbacks
example.)
they
agree.
wa s shoved
(ThEe United
When
had to mEake
on
to
States
big
gest
in NATO and
Saudi export s fell
good
on
to
their repeated
to sell under netback contracts,
no bottom iat al 1 to prices.
the
which set
3
The Saudis may be able, by judicious
rally
the
troops
to get
the price
back
$20. If so, then barri ng mill tary action
remove productive capeicity
byy
force,
1infliction
pain
to
of pain of
infliction
to the neighborhood
by producing
the underlying
of
nations,
to
surplus will
remain indefinitely as con sumption stagnates and non-cartel
TheI
output creeps up.
At
some
competitive
approximately,
We look
areas.
a
as
floor. It is
at
low
the
trying
may
fall
to
the
to loca te, however
as
two
e nds
of the spectrum
in brief: at the high-cost
$4
to produce
an immediate
end,
of
producing
i t would
take
shutdown of nearly
in the United States, and as low as $2 to do the
same in the North
for
worth
the price
the sho rt- and long-term competitive price level.
half of capacity
investment
bump from crisis t o crisis.
concei vably,
point,
Our results
price
cartel
will
Sea. A price of $10 would stop development
the bulk of U. S. oil and
over a third
of North
Sea oil. Capacity would therefore decline.
At the low-cost
end, assuming
competition and completely
independent decision-making, a price of $5 would make it profitable
for the OPEC
barrels
daily.
nations to expand output to over 60 million
The price would be sustainable
past 1995 at
the
1
It is hard to imagine any greater encouragement than to
hear from the Vice President of the United States how much pain
they are inflicting.
One is reminded of how an Undersecretary of
State was despatched
inform
the producers
by an embargo.
to the Persian
there
Gulf in January
of how much damage
These lessons are learned.
they would
1971 to
inflict
4
least.
Shutdown- Costs --far -North
We take account
Sea -and USA
only of strictly
economic costs,
disregarding taxes, royalties, and other charges, which vary from
country
to country.
in response
penalized
They
can and will be changed
to the bad news. Those
by governments,
to adapt will be
quicker
less than the more stubborn.
[TABLE I HERE]
Operatin-g --costs
costs
operating
in the British
$2 per barrel.
those
costs
From what
[OGJ, 1986a],
oil is produced
produced
As Table
shows,
price as low as $4 to reduce
1983-84,
a little
over
about the distribution of
approximately
twice
during
North Sea averaged
is known
at or below
at or below
I
60 percent
average
of North Sea
cost, and 80 percent is
the average.
Hence
it would
take a
North Sea output by 20 percent.
[TABLE II HERE]
In the United
operating
costs were
$4 to take account
El]
North
$4.84,
as Table
which
of a decline
II shows,
we have reduced
since
1982
average
to just under
then.[DOE/EIA
1986,
table
Since they include some allocation of overhead, they
overstate
well
States,
true variable
costs
Sea.
average
seemed
About
cost,
costs. In the 1960s,
to have a longer
65 percent
and another
the distribution
thinner
of production
30 percent
"tail"
than
of
in the
was at or below
at or below
twice
the
5
1972 ].
average. [Adelman,
price of $8 would
This
have little
be
still
may
effect,
but
true. 2
a price
a
so,
If
of $4 would
suppress more than one third of U. S. production,
practically
overnight
Thus
even
a very low price would
production, even in the highest-cost
that
it
wa
no
t ere
capacity,
longer
would
profitable
no longer
not quickly
shut down oil
areas.
to the extent
But
i nve st in additional
to
be any
o ffse t to
the
natural
decline rate in all reservoirs, which would red uce production.
the fraction
general,
would
be developec
the price wh ch would
There
falls
to
by 1995
s,
with
the price.
at least maintain
however,
a
We
[API 1986].
20 percent
like
S uppo
qualification
For an average develolped
and perhaps
w ould
to know
dev el op men t.
and an operator expects that it
$8,
to produce,
that would continue to
of known reservoirs
vary
In
i 11
se the price
revive
barre
1,
I
to
$29
costing
$4
of the price in roylaties
and
state and local taxes, the gross return would then be as follows:
Year
Price
Cost
Taxes, Royalties
Net
1986
$8
$4
$1.60
$2.40
1995
$29
$4
$5.80
$19 .20
2
For
example,
the
Kern River
field
in 1985 had
6254 wells
producing 139 thousand barrels daily. [Oil & Gas Journal, January
27, 1986,
p. 104]
Average
output
was
thus 22 bd per well.
In
early 1986, 1500 wells were closed, which had produced 17 tbd, an
average of 11 bd per well. [Wall Street Journal, March 12,
1986, p. 5] Thus the highest-cost 12 percent of output was
produced
at a cost about
twice the
average
for the field.
6
return
Whether the eight-fold
in nine years (26 percent per
year) is "good enough" depends of course on the risk
it.
it
how much would
1995 as an option,
in
production
considering
differently:
Or to state the problem a little
attached to
be worth
in the market?
is more important
The need to ask these questions
market has long been plagued with
Discussion of the oil
answer.
as the alleged
such confusions
if
marginal costs";
"wide
cripples
assumption
A false
which
thought is that the price floor is "the out-of-pocket
cost of the last barrels",
cost".
and
gap between full
cost" means average cost, then marginal
"full
may be much more or much less.
cost
than any
because investment is a "sunken
If this were true, nearly every single industry would
showwild price gyrations at all times,
have no effect
But in oil
on price.
because investment would
as elsewhere, the statement
is untrue under any conditions.
Oil development
money
or shopkeeper
stock-in-trade
replace.
will
awray his
is a "sunk cost".
and will pay their replacement
cost.
give
What
Even if he is going out of busi ness,
In oil
T he
large
sums
a shelf inventory, "proved reserves".
to build
manufacturer
in spending
consists
too, the
problem
in
cost for
true price
world
oil
of
No
wares because his
he
sells
he
m ust
others are stayi ng,
his inventory.
fl oor includes replacement
is
the excess
of price
over
7
cost for the great bulk of the world's
operating-plus-replacement
reserves.
Development
Table I shows that oil development
cost
in the U.K. North
investment
about
Sea was
$5.5
a net capacity
barrels daily represented
But since
reservoirs,
the capacity
be
added
back.
as would
lost and replaced
be true
conditions
under
period.3
b/d over
decline
in old
those two years
by assuming
that
is about equal to the decline
to reserves
for an unlimited
decline
during
can be approximated
This
the ratio of production
rate,
gain of 420,000
there was a continuing
two years.
must
from 2.029 to 2.449 million
the increase
to capacity,
equal
in
Since output
1983-84 (converting the pound sterling at $1.50).
was
billion
of constant
There is reason
exponential
to think
this
the decline rate for 1984, but the error is offset by
exaggerates
an error in the opposite direction. (See next paragraph.)
North
The
daily
barrel
Sea development
outlay
is for a diminishing
of about $5600 per initial
flow.
The amount
per barrel
which would
make production just barely worthwhile is found by
multiplying
the
Thus
rate = a,
R =
Q
by the sum of the depletion/decline
investment
if initial
output = Q, and
output in any year t = Q=
e-
a
t dt
= Q/a
or
a
= Q/R.
the annual
decline
Q e-at, and proved reserves
rate and the minimum acceptable
U. S. capital
market
on U. S. Treasury
because
of lower
rate of return.4
I
in early 1986, the riskless
bonds,
was
inflation,
about
and may
t
h e
rate of return,
8 percent.
decline
n
It has declined
further.
Adding
the
risk premium on oil operations, which according to various
researchers
total
rate
seems historically to be about 8 percent, yields a
16 percent.
Added
(which constitutes
percent
is necessary:
to the apparent 13.5 percent decline
the offset),
initial year
a total return
of 29.5
cash flow as percent
of
up-front investment.5
In the United
calculated
by using
States,
the
development
expenditures
1984 Joint Association
Survey
to update
what is unfortunately
the last
(1982) issue of the Census
Survey- of Oil & Gas.
Division
of total development
That
Then
is,
NPV = PQ S 00 e-(a+i)t
PQ/(a+i)
= K
dt
-
were
Annual
expenditures
K = 0
P = (K/Q)(a+i) = supply price
and
5
The risk premium on oil operations is a thorny question, of course.
Recent price declines might be a reason for
increasing
it.
Yet
since
1973,
oil price
changes
have
been
if
anything negatively correlated with changes in incomes and asset
values generally.
Hence the covariance with the general asset
market may not be much more
share ownership.
than that of other
kinds of company
If we could assume that oil prices will henceforth move
approximately with the general price level, we would use the
real not the nominal cost of capital, not 16 percent but 10
percent. Then the total required return would be 23.5 percent.
The same is true
forth below.
for
the United
States
and
other
areas,
as set
9
between
oil and gas was made
in proportion
drilling development expenditures.
to capacity
would
be a much
to the respective
An estimate of the increment
less reliable
number
than the gross
addition to reserves, which in 1984 was 3748 million barrels, or
$3.78
per barrel
natural
in the ground.
6
We are forced to exclude
gas liquids (from associated-dissolved gas production),
since this number
is no longer compiled
1984]
in a small cost overstatement.
This results
The
in-ground
cost per barrel
cost
per barrel
of
varies
holding
directly
hold.
a=the
with
In the
If
rate;
the
= 2.39.
multiplier
real
is
This would
barrel
the quicker
United
is reckoned
States,
into a wellhead
1986, Appendix
until
produced
and
and inversely
it is produced,
where
i=the discount
to
A]
The
sold
off
with the
the
Hence the average development
cheaper
rate
and
cost at the
at $9.04.
not
the
nominal
(1+(.10/.115))=1.87,
be relevant
discount
and
if and when one
gone to competitive
6
fortuitous
Another
equivalent
rate, the multiplier (1+(i/a)) =
had really
down.
[Adelman
the cost of capital,
depletion/decline
(1+(.16/.115))
wellhead
Sea.
the reserve
depletion/decline
to
is converted
by a method which is mathematically
the one used for the North
cost
by DOE/EIA. [DOE/EIA
wellhead
thought
equilibrium
resemblance:
rate
is used,
cost
the
= $7.07.
the price of oil
levels, and would
3.78 is not 3748 scaled
10
fluctuate
henceforth
with
the general
price
level,
modified
by
its own supply and demand.
In the North
Summary:- UK & USA
operating
barrel.
plus development
Therefore
continued
costs
twice the average,
is a bit less than
net of all
a $7 price,
development
Sea, the sum of average
of about
half
taxes,
would
$7 per
support
the U.K. fields. At $14,
nearly all fields would still be worth
or
further
development. In the United States, average development-plus-
operating
development
cost is about $13, so a $14 price would
in fields
accounting
for
nearly
price
of $10 per barrel would stop development
bulk
of U. S. oil and over
effects
on exploration,
At this point,
a third
half
the
total.
investment
of North
stop
A
for the
Sea oil.7
(For
see below, p. 11.)
we must digress
to deal with a widely-cited
estimate which cannot be reconciled with the real world.
The myth of "$70,000 per daily barrel in non-OPEC'
A little mental
twelve
times
arithmetic
the 1983-84
would therefore
require
shows
average
this is impossible.
for the British
It is
North Sea, and
a price of over $85, after taxes, to
break even. (That is, ($70,000/$5300)*($4.43+$2.12)=$86.51.) In
The distribution of development costs probably has not
as long a tail as operating costs, because development costs are
a larger portion of the total. Hence a price double the average
of development cost would preclude a somewhat higher portion of
the total than a price double the average
of operating
cost.
11
the United States,
price would be even higher.
the breakeven
Not long ago, most oilmen doubtless believed such a price
was coming--some
at this rate,
day. But to suppose they spent billions
for years
companies
their jobs, or their
firms
predicting
were
losing their shirts,
or stockholders'
to takeovers
Even in 1982, when reputable
is not credible.
suits,
on end, without
$200
consulting
Sea development
a North
per barrel,
up front
was cancelled because it would have cost $4 billion to develop
about 300 million barrels [NYT 1982], very roughly $44,000 per
barrel. 8
daily
investment
Thus even around
the height
of the delusion, an
only 63 percent of the supposed average cost was ruled
out.
We
Finding cost (resource value)
the decline
rate would
stay
assumed
have
That
constant.
up
is not
to now
that
true.
Without newly found reservoirs to "freshen up the mix",
increasingly intensive development is bound to increase
percent
of reserves
production decline.
every
depleted
year,
the rate
and
the
of
That is what happened in the United States
after about 1965.
A price double
the average
development
cost supplies an
incentive for exploration to find low-cost fields.
.
There
is some
.~~~~~~~~~~~~
Let K=investment, Q= initial daily output, R= reserves,
Then as shown earlier, Q=Ra/365. Then
decline rate.
and
a=the
K/Q
is equal
to
(365/a)*(K/R).
I
a is
tken
as
approximately
percent, then K/Q=(365/.11)($4*10 /300*10 )=$44,231.
11
12
indirect evidence bearing on this question: the per-barrel value
of a reserve
sold in the ground.
late
In
was
reserve
1985,
price
the
a
barrel
of
$6, give or take $1. [OGJ 1985]
ance for the tax benefits
to about
cost
of
of undeveloped
oil in
of oil prices
Except
expected finding cost (excluding development) can be
where
this low, or lower, it does not pay to explore.
brought
in the ground
with
the cost
of finding
it. There
are no
to estimate finding costs per unit. There are
data from which
expenditures,
data on exploration
are
the value of an undeveloped
we cannot compare
Unfortunately,
there
an allow-
this value must today be much lower.
since late 1985,
barrel
developed
2 is correct,
per barrel. With the collapse
was $3.50
a
However,
in Table
this divides neatly in half, and the value
the ground
in
of drilling would raise the pre-tax
If our estimate
$7.
oil
no data
on the amount
from 1982.
the most recent
of newly
found
oil,
aside
But
from
the usual meaningless "finding" which lumps together development
and discovery.
The
published
masquerading
EIA statistics
as data.
are only a minor
on "discoveries"
This is because
fraction
of what will
are fragments
the initial-year
ultimately
estimates
be credited
to
a new field or pool. Through 1979, the American Petroleum
Institute and American Gas Association published a valuable
series
of backdated
oil
and
gas discovery
estimates,
but
this
13
no information
we have
Hence
on finding
gas
per
costs
can be found even at
that not enough
it seems plausible
However,
and
under that heading are meaningless.
published
unit. Estimates
oil
1985]
Academy of Sciences
[Cf. National
industry.
to the
hostility
of mindless
a casualty
lished,
their series ceased to be pub-
else) was lost when
(and much
$3.50 to maintain the reservoirs. In fact, for many years, most
recovery and by adding to the known oil in place.
by improved
To
both
have come from the old fields,
to reserves
of the additions
Profits
the Windfall
price
(at which
Sea, a $20 price
the North
in the USA and
sum up:
Tax becomes irrelevant)
would make the continued development of known prospects profitable, except for extremely high cost wells. It would also supply
an
for
incentive
of good
exploration
cost
whose
combined
would
not be worth
prospects,
investment,
further
leases
But many
$20.
not exceed
would
those
i. e.,
and production
would
decline slowly, unless costs were sharply reduced.
offshore
deepwater
(June 1986)
do not
come
have of course
Costs
reported
mean
far down,
have been dramatic.
cutbacks
Hence
in oil production
great
an equally
and reductions
a cutback
in
the currently
capital
spending
in real effort
and
investment. Morever, efficiency is rising steeply, both because
of better
use of equipment,
cut first. The
collapse
and because
in drilling
the poorer
prospects
has not been matched
are
by the
14
number of wells drilled and feet drilled.
January-February
1985
[MER 1986],
a little
dust
a third less than
but well completions
higher.
and drilling
the
1986 were
[OGJ
1986d]
cutbacks
settles.
Rigs operating during
In the
of
and footage were actually
Moreover,
have been
the same months
much
precautionary,
North Sea and
of the
spending
a waiting
elsewhere,
until
lower
taxes
will restore profitability to some projects currently uneconomic.
Other non-cartel areas areas
U. K. because
where
Some
they are competitive,
incremental
resemble
the U. S. and
and production
is carried
to
cost equals price. Here lower prices would
force cutbacks.
But many and probably most non-cartel countries have been
explored and developed below their potential.
reserves
public
illusion
the
opinion
will
increase
as appreciating
Thi s illusion
is
ic",
heirlooms not
whiEatever
of prices a!s
they
For ex ample,
abandonment
that means;
vu Igar commodities
return. The!y will
begin
Ireally
assets, worth keeping
powerfully
so vague as to defy analysis
"strateg
because government and
are, with agonizing slowness, shedding the
of oil an,I gas
ground
notions,
is
and production
In such countries,
reinforced
and common
sense,
that oil deposits
to be managed
to negotiate
and
to tax
by
in
the
that oil
are family
for maximum
on the basis
are.
the world
price
of the National
decline
Energy
after 1981
Program
caused
in Canada,
the
other
15
back
an investment
and
reforms,
Dutch
turned
to accept
led Norway
1986
a P rice
gas fields [OGJ 1986c] which wias half
Sleipner
they had previously
been demanding.
from
for
the Troll
in order
The de velopment is the
the loss
to minimize
and
(or les s ) of what
result of lower prices. The probabililty of revis ing
policy,
cutting
The price collapse
to actively seeking customers.
exports
of early
surge. The
direct
govlernment
revenue, is wha t makes
of
pre-tax calculations relevant.
to $20,
back
raised
areas
the non-cartel
Taking
i group, if the price is
as
is no basis
there
for
suppos ing
that they
will have lower reserves and produc:tion in 19 95 than they
do
the oil
in the $4--$8
But a price
today.
industry
rrange would
An intermediate
there.
indeed
shrink
price is much harder
to
read.
We
under
turn
therefore
competitive
to the low-cost
conditions,
areas,
would be available
to see what,
at such a range
of prices.
The Supply Function
The competitive
price
was $1.20,
be about
$3.
to decline
which
in the OPEC Areas
floor price
at present-day
In 1970, the Persian Gulf
drilling
cost levels would
Supply was ample, and the price was stable, tending
very
1980s and 1990s?
slowly.
How different
would
things
be in the
16
each producing nation would become a
With no cartel,
To maximize returns, they would increase output to
price-taker.
where the incremental
They
price.
market
cost of more
production
yearn
the good
might
for
approached the
old
days
of the
but that would not matter so long as they could do no
cartel,
more than yearn.
the
As with
Sea
North
and
to obtain a barrel of daily capacity, to
money must be spent
into a cost per barrel.
be translated
[FIGURE 1 HERE]
[TABLE III HERE]
Table III shows the calculations underlying
their proved
depletion,
depletion
Our
were
output
rates are above 10 percent.
radically
year
distorted
cutbacks.
that year,
shows
average
the
depth.
For
line
cost
conditions.
I and II.)
is 1978, the
last year
by the second
price
2 the average
of an
Iran and Nigeria,
value but the maximum,
drilling
(Cf. Tables
Line 1 shows the number
completed
is 1/15th
In the U. S. A. and the U. K.,
or 6.7 percent.
reference
rule of thumb
The industry
reserves.
ten years
up to 5 percent of
to build capacity
for some of the OPEC nations
Figure 1.
1995, allowing
curve for the year
We have the estimated
annual
how much
to know
we need
USA,
onshore
however,
to allow
explosion
of wells
depth
well
before
and
data
the
of all types
of well. Line 3a
in the USA at that
we choose
not the average
for exceptionally
difficult
For countries which produce both onshore
17
and offshore,
calculated from the Joint
by the ratio
Survey, of well costs for all wells to well costs of
Association
onshore
we multiply
alone, yielding the adjusted average
well
cost
in line
3b.
In addition
also
the
outlays
over head,
and
to
on lease equipment, improved recovery systems,
other
have historically
little variation.
Multiplying
drilling and equipping wells, there are
portions of total development cost.
a veraged
66 percent of drilling costs, with
Wel 1 cost must be scaled up by that percentage.
(a) the number of wells
plus non-d rilling
drilling
drilling-
These
cost for each well,
related e xpenditures,
wells and equipment
drilled
by (b) the
yields
total
in line 4. This includes gas
and exploratory
drilling
(but not geo-
logical- geophysical work), which ought to be excluded; but the
total
is considered
Operations
expensive
o il
development expenditure.
oultside
where there is
the
no
United
infrastructure
and service industries, and supplies
producers.
ties,
public
Furthermore,
or private,
States
But
in
tend to be more
place,
increiise the
people
these are all mature
we take no account of local
which
of
peculiari-
expense, but are not
necessary.
New capacity
production
average
is calculated by taking the adjusted average
per well per day
new well
produces
(line 7b),
as much
and assuming
as the average
that
the
old well.
18
This
is multiplied
average
oil wells,
by new successful
country
was
to yield
gross
but only
drilled,
added,
new capacity
(line 9b). There is a factor
by country
of overstatement
some successful oil wells are exploratory holes,
here, because
do not add to capacity.
in themselves
which
not by total wells
at a low
in these
level
a fact
countries,
exploration
However,
to be discussed
more fully below.
Dividing
added by
(line 4) by new capacity
investment
total
drilling (line 9b) yields investment per additional daily barrel
(line
We must
1ob).
the same method
We
as was applied
the
assume
true of exponential
gross
arithmetic
easy.
is one thousand
However,
=$1.)
in nominal
what it would
5 percent,
1995
as would
dollars,
which
if the investment
be
makes
total
mental
per daily barrel
then unit cost=$1000*(.05+.07+.245)/365
this is fortuitous.
24.5
The
of investment.
is 36.5 percent,
(For example,
terms,
case
to be 7 percent
of return
rate
in this
to the
to be equal
decline
decline over an infinite period. Operating
assumed
are
expenses
by
to the North Sea.
production
percent,
production/reserve
this into cost per barrel
now translate
percent.
We assume a cost of capital,
This
is half again
be for a private oil and gas operator
as high as
in the United
States or similar developed countries.9
9
In a forthcoming
paper,
it will
be explained
why the
discount rate for an oil-producing country, whose oil income is a
large part of its revenues, must be considerably higher than for
19
The
well may and usually
United
(as in the
when
the average
from
the cost per barrel
does overstate
happens
This
per barrel
the cost
On the one side,
biases.
some opposing
are costs per average well. This involves
thin tail of small wells. This
long
Second, they
costs, with no allowance for transport.
wellhead
wells.
they are strictly
Sea,
the North
the U. S. but unlike
like
First,
are several.
on these estimates
limitations
from all
there
States)
is a
for by
can be adjusted
calculating a weighted average flow rate, weighting the average
of the field.
flow rate for each field by the production
preferable
but is impossible.
7b.
It is
than the unweighted
average
in line
shown
But even an adjusted
UK,
produced
make
at costs above
an allowance
is to multiply
usually
for
average
percent
cost
than
or greater
be
flow rate is
sometimes
lower,
cost,
curve is not a supply
the USA
half,
output.
and
the
of the oil is
Hence for each country
the more expensive
the average
but
in discussing
less
average.
supply curve segment of line 11.
a 50
higher,
average
would
in line 7a.
fraction,
a substantial
of all wells
The weighted
out earlier
As we pointed
curve.
average
A weighted
1980]
& Paddock,
[Adelman
one must
Our procedure
line 10b, by 2.5, yielding
the
This adjustment in effect yields
rate of return
for more
than
half
the
existing capacity, which serves as an incentive to discovery of
a private operator.
20
new
implicit
we have a substantial
Hence
fields.
for
allowance
exploration costs.
It need not be said
for
among
Indeed,
error.
that every
the
has a wide margin
item
suppliers,
lowest-cost
the
order
tells more about our adjustment rules than about true relative
For example, Saudi expenditures were unusually high in
costs.
1978 because of a great water-injection project, and oil wells
relatively
Libya was completing an unusually large
low, while
number of oil wells
that year.
For some of these countries, going to 5 percent depletion
a very large
involves
Arabia
produced
We assume
that
depletion
the
Saudi
to the
is proportional
Saudi investment
is increased
This
or by 92 percent.
5.0/2.6,
proportion
per unit
investment
in 1978,
of its proved reserves.
only 2.6 percent
Hence
rate.
For example,
buildup.
in the
represents
a
considerable overstatement, because reserves would be increasing
with
along
to be
capacity.
consistent
We keep
with
a later
the assumption,
treatment.
however,
(See below,
in order
the
"zero
reserves-added model".)
The
supply
the
highest-cost
(at
1985
output
factor
known
2.5, reaching
cost
for the group
members,
prices)
Venezuela
in Nigeria
to be at higher
$5.00.
costs,
Producing
as a whole
and
was
Nigeria. The
$2.00. With
we multiply
at 5 percent
for
is that
1978
much
cost
of its
the average
by
of 1985 proved
21
reserves would be a slightly
1978, although
than in
higher percent of reserves
the absolute
hence the
amount would be lower,
supply price increases only slightly.
and Nigeria
Venezuela
errors
estimating
large relative
are the only
where
countries
For the others,
make any difference.
even
in absolute terms. That
errors would be negligible
is, if the true cost is twice our calculated cost, and the latter
i s 50 cents, the error is only 50 cents.
changing the conclusion:
There is
in these countries,
oil
no way of
ranges from
cheap to dirt cheap.
Declining
by lower factor
oil
prices have lowered costs greatly,
prices and by greater efficiency.
undoubtedly decline
from 1985 levels,
both
Costs will
but we cannot tell
by how
much.
How Long Can a Competitive
We have assumed that it
be Sustained?
takes a decade to reach equil-
We need to estimate rates of reserve buildup and
ibrium.
drawdown before
still
Price
we can start
to answer the ultimate
question:
assuming competition, how long can this price level
be sustained?
World non-Communist consumption in 1985 was 45.5
barrels
daily
39 mbd was
[DOE/EIA/ICID,
supplied
by crude oil
March
1986,
[OGJ
March
p. 10],
million
of which
10, 1986,
p. 80],
22
and the rest by natural gas liquids,
inventory
At much lower prices,
average
oil:GNP
ratio
annual
annual
growth
growth of 2 percent,
would increase. We
at 3 percent,
and an
for an oil consumption
10
IV shows that this consumption turnaround could
Table
entirely
supplied
1985.
consumption
economic
growth rate of 5 percent.
be
and
We focus on crude oil supply and demand.
drawdown.
assume
block exports,
Communist
from
the stock of proved
reserves
at end-
Non-cartel oil production is assumed to decline steadily
at about
8 percent per year, which is almost surely excessive,
(OPECplus Mexico) would increase by a
while output of cartel oil
factor of three. Most of the growth in cartel output would merely
reactivate capacity already in existence in 1985.
Table
of zero reserve
period
these
Nevertheless,
floor
not merely
IV is a model
price
from known fields.
additions
are always
there
of zero discoveries
In any
the great bulk of all reserve
is no problem
for a decade.
of supply
It is during
this
at the
time
but
given time
additions.
competitive
that
reserves
I think the reaction would be slow, because of (1)
10
improved technology in combustion and building; (2) the developed
countries have been approaching the North American level of
automobile saturation; (3) excise taxation of oil products by
consuming-country governments; (4) the retrofitting
asymmetry.
to higher
Part of the reaction
tion of existing
structures;
undone because of lower
out of buildings.
prices was the altera-
but the alteration
prices.
Insulation
will
will
not be
not be ripped
23
in fact
would
at the
be added,
barrel
cost per
in Table
shown
after 1995.
III, to support consumption
Sustainability after 1995
It is conservative
to assume
that enough additional reserves will be created during ten
shown in Table III, to supply the world for a
years, at the costs
few years,
at least, past 1995.
But we consider
the rate of reserve additions
estimate
of exogenous
Reserves
fact.
decisions,
which
as if they were
to
some kind
are ready shelf inventory.
The rate
from profit-maximizing investment
results
of reserve-building
it a mistake
are radically different under competition
and
monopoly.
Any monopoly must restrict output in order to maintain
price.
Hence
there
is under-investment.
With a reversion
to
competition, the rules governing investment would again be turned
upside down to be right
side up.
market,
In a competitive
faster
than high-cost.
explosion.
United
been
It was
This was true before
evident
in the bitter
States over restricting imports.
running
of four
low-cost sources of supply
uphill.
through 1985.
Drilling
the 1973
20-ye;ar
fight
grow
price
in
the
Since 1973, water
has
in the USA increa sed by a factor
In Saudi Arabia,
drilling
dropped
by two
thirds, because only sharply lower production would maintain the
price.
24
If the
and every
disappeared,
monopoly
acted
producer
independently, competition would first induce full use of their
existing
and then set them off on an investment
capacity,
hate it, of course, and some of them would
They would
boom.
have
real financial problems in raising the relatively small amounts
needed.
the
But
way
only
to save
be to explore,
the cartel would
from the wreck
something
to the
and produce
develop,
of
maximum.
The difference
After
1974,
as oil.
dingly,
years
went
1984]
the price
But
to
the
the
The
disappears;
no cartel
a massive
first
lowest
"Neff
oil and uranium
of uranium
there was
there was
after
between
We look first
will
Persian
Excluding
investment.
prices
hold also
Accor-
than five
to drop, and
began
first recorded.
[Neff
in oil if the monopoly
is how far down the price will go.
at development
the great bulk of new reserves
In 1944,
uranium
as spectacularly
in supply. Less
since they were
level
the question
almost
to restrict
increase
surge,
paradigm"
soared
is instructive.
of known fields, which
added in any time period.
a team of distinguished
Gulf oil reserves
later discoveries,
provide
calculated
geologists
at 16 billion
this has already
proved,
5 probable.
been surpassed
by a
factor of roughly 30. These geologists were neither foolish nor
conservative;
known
then.
as good scientists,
they interpreted
As more is known, reserve estimates
from the data
grow.
25
to produce 20 million barrels daily
For Saudi Arabia
requires
them only
50 commercial
to dust off
the 1973 plans
oil fields discovered
in that country,
been developed.
If the price collapses,
is
35.
in the
other
No OPEC country
the USA in 1945.
fields
were
had been found before
20 billion
produced
barrels.
Alaska,
only 15 have
drilled
today
Proved
reserves
But in the next 40 years
as was
all the big
practically
that year.
not 20 but 100 billion
Of the
we will find out how much
is as intensively
Excluding
for 1980.
in 1945
the "lower 48"
barrels, and they still have
nearly 20 on the shelf.
Those
nature.
found,
additional
heavy investment, many small fields were
Through
and the old fields
1945, at least through
statistics,
make
but there
were greatly
expanded.
1972, there was no increase
Yet from
in finding-de-
(Great turbulence, and disappearance of some
veloping cost.
ward,
100-billion barrels plus were no gift of
it difficult
is reason
to say
just what
happened
after-
to think the cost may have doubled
in
1972-84.)
In Venezuela, another old province, reserves stagnated
until costs began
to creep up.
They
amounted
to 18 billion
barrels at end-1978.
In the next seven years, another
13 billion
were
added, without
major discoveries. A nationalized industry
does
not have the difficult problem of skimming the operator's
26
rents
the total
as to reduce
so high a percentage
taking
without
take.
In Nigeria, Indonesia, Malaysia, Egypt, and other places,
better
terms will be granted
it will minimize
industry
& Paddock
1984],
than
of
slope
the
in the
oil will
that newly-discovered
follow
the
gas fields
oil and
that the
to assume
it is prudent
smaller
on
It depends
be less.
[Smith
find
will
It does not
past.11
losses.
now to exploration:
Turning
oil
the revenue
because
companies
to local operating
size-decline
curve
of investment
and on the amount
in
exploration.
areas of the world are the least
The most promising
In Kuwait,
explored.
local
gas for
field
will
of about
replace
generation
power
part of current
Saudi
combined.
In
rigs. Saudi
Arabia
Arabia
1985,
those
Prudence
(10).
Kuwait
as Texas
Yet
that
is a tiny
Louisiana
and
an average
Saudi
it
Arabia
of 963
is a far
before.
is not necessarily truth.
It involves
the model of diminishing returns (see next page)
from a given field
world.
model's
production.
to produce
We will find out how much better when and
if the cartel disappears--not
extrapolating
so cheap
States operated
ten
of an oil
the 1983 discovery
is as large
averaged
better hunting ground.
was
barrels,
30 billion
country.
result of drilling for
the inadvertent
or "play"
to a whole country or continent
as Kaufman
The extrapolation,
legs in several ways".
has put
it,
"breaks
or
the
27
In a kind of twilight
ment
Much
at a price
is profitable
just as high prices
exploration and devel opin Canada
of heavy oil s, especially
are large resources
Venezuela.
between
be low
$10.
and low demand put the Orinoco
and
Indeed,
"belt"
on
hold, low prices and high demand would make it a major producer.
In
the evidence
short,
consumption
at the cost
accommodate
consumption
levels
the
effect
the supply
upon
A. D.
with which
The only meaningful
cope.
somehow
2000
T here is too little
price of oil
is :
change
The
buyer s and
question
to
is ample
III, which
nor is there any need to.
is an unknown
cost
to a repl acement of 1985-95
of Table
through
basis for going farther,
marginal
points
sellers
what
in
must
would
in 1986-1990
of
be
the
unknown chance of sharply rising marginal cost after 2000 A. D.?
Long run cost and price changes
that oil prices must somehow rise in
The belief
term
is grounded
nothing
assume
about
in the Earth
mineral
"exhaustible
is unknown,
long
We
need
resources". The amount
and irrelevant.
The
"limi
1
of
t
a
to
is cost at the margin.
growth"
In any mineral
industry, ceteris paribus t:he biggest
likely to be found
deposits
are more
because
they are biggest.
first.
returnis.
in the fact of diminishing
the
(Failure
first, even
by chance,
The best ones are exploited
to do so, as we saw earlier,
implies
monopoly
28
contro 1.)
Life
is one
good
slide from
long
to bad and
bad
to
Hence marginal cost must keep rising over time, and the
worse.
price with
it.
rise, consumption
As the cost and price
and
production dwindles.
Yet for nearly 30 years
it has been clear that there is
no persistent widespread upward price drift; most minerals
actually
decline
in the 1 ong run. Diminishing
prices
are opposed
returns
by increasing knowledge, both of the earth's crust and of methods
of extraction
is the uncertain I fluctuating
mineral,
Thus
of a mineral
the value
uncertainty
eral
of oil, like
The price
and use.
found
body
is subject
or
Either
of these values
present
value of the asset's
of reprodu
value
economics
is familiar
is merely
an
to economists
unity.
the problem
We
have
an
inIf
iiteresting
at its leisu re.
cost.
Q".
In
fact,
Mineral
case.
In long run equili t)rium, the fraction
es
tion
decision.
as "Tobin's
in portant special
C
but there i S no escape
iss very uncertain,
from the pain of choic(e for an investment
(a)/(b)
or non-min-
as a current cost the using-up of assets.
(b) the
revenues
to the kind of
Every mineral
That cost is the lesser of (a) the present
future
of any
result of the conflict.
in ev,ery industry.
firm must reckon
that
example
In 1976, when
(a)/(b) approach-
of a firm w,orking out
Aramco
was expropri-
in
ated, the operating
conI panies were allowed 6 cents (about
cents in 1985 prices)
for every barrel discovered.
10
29
This
us a fix on Saudi marginal
give S
to user cost )
(and probable
reserves
future
price.
in Table
III,
Were
half again as great), and current
perhaps
Ar'amco barrel
the present
was
Aramco
discounted
tiny almost
producing
development
should
V alue
1ow
(equal
of 166 bil lion barrels
proved reserves
Given
annual output of 3 billion,
incremental
revenues. The
an d marginal
not be surpris ring.
fi nding costs
cost and
without
value
r egard
of an
to the
at the levels
hypothesized
also
value
("user
an undevel oped
barrel
resource
cost") would b e much higher.
In
in
the
ground I would
revenue,
opment
in the
1976,
i.
e.
the
United
sell
States,
for
difference
several
between
dollars.
Thee future
price and oper-ating-devel-
cost, was only a small fraction of the margin
Arabia.
But
the
present
value
net
of the
smaller
margin
in Saudi
was many
times as great because it would be realized within a few years
not decades or centuries,
If current
future,
if at all.
information
then it pays to refrain
would
be
profitably
even
more
depleted
profitable
future
indicates
from investing
today,
use.
in order
The
lower the current profit, and the greater
ment. 1 2
Or, what comes
higher
to the same thing:
prices
in the
in reserves
to save
higher
which
them for
the cost,
the
the gain from postponethe lower the cost of
12
Suppose this year's price for some product is $1, the
relevant
discount rate is 10 percent, and the best estimate of
next year's price is $1.05.
If the marginal cost (bare operating
30
creating the reserves (development cost), the lower the opportunity cost
(user cost)
of producing
now rather than deferring
production.
Thus the notion that the cartel
their
oil
in the ground
for later more
nations were reserving
profitable
use
is proved
false by the fact that owners of higher-cost oil were striving
get it out more quickly,
while the owners of lower-cost
lagged far behind. This upside-down
behavior
is characteristic
to
oil
of
a non-competitive industry with a competitive fringe.
cost for fac ilities in place, development-plus-operating
cost for
facilities
pproposed) is 50 cents, production
should be postponed
to next yeaIr. That is, the net return would be 55 cents next
year, which is 10 percent above this year. Or, what comes to the
same thing, user cost is 5 cents, which added to marginal cost
makes
tions
produ ction this year unprofitable. But lower cost operashoul d not be postponed. In general, marginal cost is
correlated withFuser
cost; the higher the marginal cost the
the gain to postponement.
adds another dimension.
Suppose we have no
estimate of next year's price, but we do have some estimate of
the future variability of price.
The greater its variability,
the better the chance that some time in the future. the
rice
will be s ufficiently
higher than now to make production so much
more prol'itable as to be worth waiting for.
Thus an operation
with zero or negative current profits may have a positive present
value.
I f there
is a market
in values,
the individual needs no
discount rate to make a decision.
(But waiting may have costs
greater
Option theory
over and above mere postponement.
At the limit, it may be
impossibl(
e to resume operation
once it is halted.)
The important point for us is: The lower the current
earnings, the greater the value of variable expectations. An
operation "out of the money "is the best candidate for waiting;
one "deel in the money"
iis the poorest.
This is perfectly
consistenI t wi th the maxim that we use the lowest-cost mineral
resources fir st, and also with our thesis that user cost is
positively correlated with development-operating cost.
31
Moreover, the increased cost of developing known reserves
more
intensively
years ago,
[Adelman
puts a limit on what
is worth finding; some
the writer called it Maximum Economic Finding Cost.
1972; and see Devarajan
and Fisher
1982]
Hence an
estimated increase in development cost is an implicit allowance
for exploration cost.
Our
only
sensing
tive market
price.
reserves
device
for future
is a competi-
Estimates and models of resources and
are inputs into price
conditions
shortages
formation.
past 2000 A. D. will
Assumptions about
be discounted
so heavily
by
rational actors that their influence is minor or imperceptible.
The price
reflects
all
the information,
models, guesses,
hypotheses, hunches, and mistakes. The fog surrounding any future
price is like Napoleon's "fog of war".
But the estimate of that
future price is subject to constant correction.
The
probability
2000 A. D.,
of marginal
whatever it
may be,
costs
rising
strongly after
will have little near-term
effect, but a substantial effect ten years hence.
It is not unreasonable
competitive
price
of oil
(even if unproved)
to increase
current competitive "shadow price".
historian
the
the long run from
the
What must forever amaze the
is that when the price of oil was raised far above that
competitive level, and was therefore
downward
over
to expect
subject
to an additional
risk, it was confidently expected to keep increasing.
32
[IIASA
1985]
is about
the most moderate
one of the most recent)
prices
of innumerable
and
cautious
analyses
(as
it is
and forecasts
of
higher than 1981 or 1985.
Price forecasts
But
even
if
the
price
reaches,
as
in 1970 it approached, a level which expresses long-run supply
and demand,
it will probably
not stay there.
need not wait for 2000 A. D. or even 1987.
directly
forced
down cartel prices.
revenues
have made them resist
if they can make,
production,
and, more
they can quickly
The cartel's
The cartel
members
Lower sales have not
It is rather than lower
the need to share burdens.
important,
keep an agreement
But
to cut
raise prices again.
basic instability is that a movement in
either direction becomes self-reinforcing and cumulative.
"The better
the financial
condition
of the sellers,...
the less pressure on them to cheat and undersell each other in
order to pay their bills...Once
the price begins to slip, the
OPEC nations will be under great pressure to produce more in
order to acquire more revenue, and the more they produce, the
further the price falls.
[Adelman
1982]
Most likely, the price will fluctuate between the monopoly
ceiling
and the competitive
floor. The ceiling seems first to
have been envisaged around $28, but more recently OPEC spokesmen
have
spoken
of $20.
$8 in the short
U. S. production,
The
run, below
and
floor as we perceive
it here
is about
which there will be large cutbacks
$5 in the longer
run, which would
in
suffice
33
to maintain a flow of investment in
the ex-cartel
be a clumsy way of raising
overshoot felt
and capacity
in
area, and elsewhere.
Concerted output cuts by the
the past
new reserves
revived
cartel would as in
the price,
with
the kind
of
in 1979-81.
What should be done to cope with this instability is
another question.
Pent-up forces often work with violence.
The
world
is both the largest
the
oil monopoly
greatest
in the divergence
The accumulated
tension
of all time, and also
of price from long-run
marginal
)st.
cc
between actual and competitive mar-ket
conditions is therefore unprecedented.
34
REFERENCES
[Adelman 19663 M. A. Adelman,
Proceedings
Areas",
"Oil
of the Council
Production
Costs
in Four
of the American
of Economics
Institute of Mining, Metallurgical, and Petroleum Engineers
[Adelman 1972) ------.
, The World Petroleum
more: Johns
for Resources
Hopkins Press
[Adelman 1982]
---------- ,
Market
For the Future,
(Balti-
1972)
"OPEC as a Cartel", in Griffin and
Teece, OPEC Behavior and World Oil Prices (London: George Allen &
Unwin,
1982), p. 55
[Adelman & Paddock 1980] ----------
Aggregate
and James
M. I. T. Energy
79-005, rev.
January 1980
Laboratory
[Adelman 1986] ----------, "Scarcity
Review of Economics & Statistics,
[API 1986]
Working
Paper
and World
Oil
No. MIT-EL
Prices",
forthcoming 1986
American Petroleum Institute, Public Affairs Group,
R-348, April
1, 1986
[Devarajan and Fisher 1982]
Shantayanan
Devarajan and Anthony
C. Fisher, "Exploration and Scarcity", Journal
Economy,
An
Model of Petroleum Production Capacity & Supply
Forecasting,
Response,
L. Paddock,
of Political
vol. 90 (1982), pp. 1279-1290
[DOE/EIA 1984] Department of Energy, Energy Information
Administration,
Liquids
U. S. Crude Oil, Natural Gas, and Natural Gas
Reserves 1984
35
[DOE/EIA 1986]
Department of Energy, Energy Information Adminis-
tration, Indexes and Estimates of Domestic Well Drilling Costs,
1984 and 19'85]
[DOE/EIA/ICID]
Department of Energy, Energy Information Adminis-
tration, International and Contingency Information Division,
International
[Gately 1984]
the World
Report, March 20, 1986, p. 10
Pe-troleum Statistics
Dermot Gately, "A Ten-Year Retrospective: OPEC and
Oil Market",
no. 3 (September
of Economic
Journal
vol. 22,
Literature,
1984), pp. 1100-1114.
****[IIASA 1985] Alan Manne and William Nordhaus, "Using Soviet
Gas
to
III, p.
Keep OPEC
Reeling,"
September
New York Times,
22,
1985,
3.
[National Academy of Sciences 1985]
Sciences,
Committee
on Natural
Environment
Thomas
chn.],
(National Academy
Neff,
Academy
of
Panel on Statistics
Statistics,
Gas [Gordon M. Kaufman,
in a Changing
[Neff 1984]
on National
National
Natural
Gas Data Needs
Press, 1985),
The International
ch. 4.
Uranium Market
(Cambridge: Ballinger Publishing Co., 1984), especially chapter
2, and
a pri vate communication
from the author
updating
the price
series.
[NYT 1982]
New York Times, May 5, 1982, p. D-3
[OGJ 1985]
Oil & Gas Journal,
November
25, 1985, p.48
[OGJ 1986a]
Oil & Gas Journal,
February
17, 1986, p. 25
[OGJ 1986b]
Oil & Gas Journal,
March 10, 1986, p. 80
36
[OGJ 1986c]
Oil & Gas Journal,
June 9, 1986, p. 19
[OGJ 1986d]
Oil & Gas Journal,
June 16, 1986, p. 131
[Smith & Paddock 1984]
James
L. Smith
of Oil Discovery
"Regional
Modelling
Economics,
vol.6, no.1, January
and James
L. Paddock,
and Production", Energy
1984, pp. 5 -
13.
TABLE
I
DEVELOPMENT & OPERATING COST, OFFSHORE U.K., 1983-84
MTY
1982
100.1
1983
110.5
1984
120.8
2 OUTPUT MBD
2.029
2.240
2.449
7237
6845
5920
0.102
0.119
0.151
- - -
0.248
0.459
0.331
0.540
1 OUTPUT
3 RESERVES
(MMBRLS)
4 ANNUAL DEPLETION/DECLINE
5 LOST CAPACITY MBD
6 GROSS GAIN MBD
7 DEVELOPMENT
IN-
- -
2727
2862
Do., $/IDB
8
9 DEVELOPMENT COST, $/BRL
- - -
5937
4.57
5300
4.43
10 PRODUCING OUTLAYS ($MM)
- -
1863
2135
- -
2.28
2.39
- -
6.85
6.82
VESTMENT, $MM
COST ($/BRL)
11 OPERATING
12 DEVELOPING PLUS OPERATING
COST ($/BRL)
SOURCE:
Development of the
U. K. Department of Energy.
Oil & Gas Resources of the United Kingdom 1985 (HMSO 1985)
and ibid (1984).
Output:
Appendix
8, p.
68
Appendix 14, p. 77
Capital expenditures:
Appendix 14, p. 78
Operating expenditures:
Sterling converted at $1.50
Discount
rate at 17 percent
nominal
Tonne=7.4 barrels
Lost output is equal to current year output multiplied
by average ratio production/reserves, given year and
preceding year.
Gross gain is sum of lost output and
net increase.
Discount
rate taken as 16 percent
projects.
nominal on development
Assumes investor has access to U. S. capital
markets.
Rate is sum of 8.0 percent riskless end-1985, and
The
8.0 percent risk premium on oil and gas operations.
riskless rate will probably decrease because of lowered
inflation expectations, and the risk premium may increase
because of the perceived greater uncertainty of oil prices.
TABLE
II
DEVELOPMENT & OPERATING COST, USA, 1984
DEVELOPMENT
OUTLAYS
(S$MM)
14174
DEVELOPMENT
GROSS
COST PER
RATIO
DEVELOPRESERVES BARREL IN
DEPLETION/ ABOVE- TO MENT COST
DECLINE
IN-GROUND AS PRODUCED
ADDED
GROUND
(MM BRLS)
3748
….
OPERATING
OUTLAYS
($MM)
17453
($)
RATE
3.78
VALUE
0.115
2.39
($)
9.04
1.9.8. 2…-------------------..................
OIL
OIL OPERA- PRODUCTION OPERATING ESTIMATE
COST/BRL
FRACTION TING OUTLAYS MM BRLS
0.674
($MM)
11762
2432
($)
4.84
3.87
SOURCES:
Census, Annual Survey of Oil & Gas 1982 adDEVELOPMENT:Outlays,
justed to 1984 by Joint Association Survey.
Gross reserves added, DOE/EIA
Depletion/decline rate, ratio of production to average
annual proved reserves, per DOE/EIA.
Ratio = (1+(i/a)), where i=discount
rate, taken at 16
percent, and a=depletion/decline rate.
OPERATING:
U. S. Bureau of the Census, Annual Survey of Oil & Gas 1
Production and expenditures are for the sample of compan
Oil fraction calculated by taking ratio of oil wells to
wells, and assuming gas wells cost one-third more.
Reduced by 20 percent to reflect lower costs. See
Independent Petroleum Association of America, Report of
Study Committee, May (judgmental estimate), showing much
larger decline for drilling expenditures.
TABLE III
DEVELOPMENT-OPERATItNG COSTS IN OPEC NATIONS
(1978 conditions, adjusted to 1985 drilli1ng costs)
(1 9i )
IK.U',
ait
42
36
WELLS DRILLED
1
2
3a
3b
tts
PF'PROX.
AVG. DEPTH (Tft)
9.238
AVG. COST/WELL
. 571
0. 571
1985
($MM)
Do., adjusted
.:l r
Adjustment class
4
INVESTMENT
r1
OUTFUT,
6
OPERATING
7a
AVERAGE, TBD/WELL
1 ,. 62
7b
WTD. AVG. TBD/WELL
I :. . Cq)
9_3
8
OIL
9a
NEW CAPACITY, TBD
9b
ADJ.
10a
,--
-.
...
145
0. 069
0,.069
7. 04
5.661
0. 337
0. 67
0.238
0. -51
a
c;i
($MM)
TBD
40
4
2593
1894
484
545
!02
I,!97
,,
WELLS
**
*
36
WELLS DR I LLED
NEW CAPACITY,
INVESTMENT/BD
t
. - q
4.'745
'L
Q
11.* '
L7
24
474
687
TBD
(T$)
8066
....'.'
12
.46
57
116
530
514
!. 0!84
0.049
0).342
0r.11 4
.
0. 044
0. 168
0. 1 8
=COST PER BARREL ($)
10b DJ.
INVST./BD
(T$)
=COST PER BRREL
1:L
SUPPLY PRICE
58
($)
o.145
($/BRL)
0.
11(0
12
1978
CF'APCITY, MBD
:L3.
1
RESERVES,
BE
32.
1
y
nI
.>
00
14
1985
RESERVES,
BE
44.
1
89.
15
1995
POTENTIAL
(5%),
16
CUMULATIVE POTENTIAL,
17
78
4
MBD
1995 INVESTMENT/BD (T$)
=COST
PER BARREL_ ($)
.18
i}. 159
].9
0. 334
0,,294
0.65
12
4
165.7
168 .8
0.5
6.0
MB
3.
1f9
J..
23.
42
0.556
TABLE I I I
(cont.
Indones ia
WELLS
2
3b
DRII.-L.Ei
AVG.
(Tf-ft)
COST/WELL
5
OUTFUT,
.
0. .
.1ran
.4
0.. 224
i.
:
i
'7
I1. i;,
:7
8.853
312
.....
AI -e
12.
C"
0.312
"'.
_-i
.
Do., adjusted
INVESTMENT
=5.3I101
($MM)
3c Adjustment class
4
-s
.. 7j7 C_
"AYVG. DEPTH
,tPF'PROX.
1985
. ib
,'7
1
0. 637
. .033
0.527
0. 5 27
a,b
($MM)
TBD
192
1.
13
si
I/
5 1 445
155
1164
1 :9 .3
OPERTING
U,
WELLS
("i
7a
AVERAGE, TBD/WELL
7b
WTD.
8
OIL WELLS DRILLED
9a
NEW CAFPACITY, TBD
9b
ADJ.
AVG.
1.
TBD WELL
NEW CAPF'ACITY
1
36
P 012
4 4 ..
1 13
1.782
3.515
.1.57=
TBD
INYVST./BD (T;)
1 :57
1.
16. 53
134
10a INVESTMENT/BD (T$)
=COST PER BARREL ($)
lOb ADJ.
2
f
1.736
49
!05
4 79
239
635
6,3-5
471
826
182
. 37
0. 38C
0. 339
1.339
o. 292
t0.
192
0.731
. 481
I
p
2s1
iL.
· l49
=COST PER BARREL ($)
11
SUPPLY PRICE ($/BRL)
12
1978 CAPACITY, MBD
13
1978 RESERVES,
14
1985 RESERVES, BB
15
1995
16
CUMULT IVE
17
1'95 INVESTMENT
/D
T$)
-COST PER BRREL (s)
1.8
7
24.3
BB
8.5
MBD
1.2
FPOTENT
I AL, M.,
43
POTENTIAL (5),
. 581
. .567
2I*...
59
1.
2
6.3
4.7.9
co
0. .41
2. 124
..
0. .-.
oij 74
...527
TABLE III
(cont.)
1L
n
TI I
'-I.-I
2
{,PFROX..
3b
1985 AVG. COST/WELL ($MM)
1a
Do., adjusted
DEPTH
(Tft)
3.cAdustment class
8.849
5.353
0].577
i
9. 667
". 1
,.
,s-
1.008(
114
1446
i ' .-..
-]0
'-1 sr
_ /-
7a
AVERAGE., TBD/WELL
-7b,
WTD.. AVkJE. TBD/WELL
8.
nl"L. WELLS
5. 626
i7
1 r'1
DRILLED
NEW C
-FACITY.,
TBD
ADJ. NEW CAPACITY,
SUPJFPLY PRICE
12
1978
CAPACI TY, MBD
13
1978
RESERVES,
BB
14
1985 RESERES,
EB
15
1995
16
CUMULATIVE
POTENTIAL,
t'~1r
1
fI
I st! .'::k...3)
r'l... .- .
r
surr
I.
25./
4 :L
.
E
s
1. 14
1.97
45
57
..4._4.-
1.548
9.998
4. 995
1.325
2 .4
18
-·
- .L
l
| rBD
MB
INVESTMENl/BD (T$)
=COST PER B ARREL ($)
110
0. 530
($/BRL)
OTENTIAL (5'.),
·-'u
: .Y
0.611
10a INVESTMENT/BD (T$)
=COST PER BARREL ($)
10b ADJ. INVST. /BD (T$)
=COST PER BARREL ($)
1.1
-. L
I
96
'TBD
Ii'~/
1404
.1. .1. m-l-.:, -_-
. ~.
...
1995
I
Is s-v
58
($MM)
OPERATI N" WELLS
17
-a Ni ger
i
a:
a, b
.OUTT.,,TEBD
9a
9b
eez . -l
;tED
AVG.
INVESTMENT
Ve
Dhabi
., f .7
:e.
?4
l
1'-.
18.2
16.6
1
58
64
0
I
4. 982
TABLEIIT,
NOTESAND SOURCES
NOTES:(1)The "2.5" adjustment (line 11) assumes a highly sewed
distribution of well efficiencies and costs, as is true of
an area with a very large number of mostly very small wells.
It is a substantial overstatment for other parts of the world.
(2) It is assumedthat the cost per unit is proportional to the
depletion rate. This is usually though not always an overstatment.
Reservoir development shoul, aim to stop well short of the
point
where costs
go non-linear.
t No oil well drilled in Kuwait in 1978-79.
tt Weuse data on individual fields' productions for 1975, 1977,
and 1977 to calculate the weighted average daily outputs for
Iraq, Kuwait, and Abu Dhabi respectively.
Due to this,
the
results are then adjusted to 1978production condition.
ttZ In the calculation
of the weighted average daily
output
per well, data on individual fields' productions are taken
from the first six months of 1978. For any country whose
totalnumber of oil fields is less than 15, we calculate
the wtd. avg. daily output for all the nation' wells. Otherwise,
we only use the number of wells from its major oil fields
our calculation.
SOURCE: Wells drilled:
August !5,
"'World Oil',annual International
in
Outlook issue,
1979.
Nigeria and Abu Dhabi 'suspended' wells estimated at worldwide
percentage.
Well depth: same source, total footage divided by completions.
Daily output: same source.
Operating wells: same source, included both types: flowing and
artificial lift wells.
Drilling cost: DOE/EIA, Indexes and Estimates of Domestic Well
Drilling Costs 1984 & 1985 (DOE/EIA-0347(84-85)). These are
exclusively onshore wells. Adjustment a is average ratio of total
U.S. to onshore U.S. cost for given well depth, from 1984 Joint
Association Survey. Adjustment b is ratio of maximumto average
composite drilling cost for given depth, from DOE/EIA,op. cit.
Adjustment for non-drilling costs: Bureau of the Census,
Annual Survey of Oil & Gas discontinued after 1982).
Output of newly drilled wells assumed equal to average flow
of existing wells.
Capacity
from Petroleum
ntelligenceWeekly, April
9,
1979.
Year-end reservesfrom Oil & Gas Journal, issues of December 1978
and 1985.
Weighted average output per well using data from 0 & 6 J,
December 25, 1978, and from nternationalpetroleum
Encyclopedia,1976, 1978, and 1979.
Potentialdefined as a 5 percent depletionrate of reserves
as estimated by 0 & G J. Industryrule of thumb is onefifteenth,or 6.67 percent.
Decline assumed as percent
roduction is of reserves.
Subtracting
it from gross new capacity installed(above,line 9) implies
a net capacityincreaseof 5.6 percent for 1978.
TABLE IIIa
DEVELOPMENT-OPERATING COSTS
of Oil Fields
in Comalcalco
(1984 conditions
and in Gulf of Campeche,
Comalcalco
I
45
WELLS DRILLED
APPROX. AVG. DEPTH (Tft)
.3-^a 1984 AVG. COST/WELL ($MM)
Do., adjusted
3b
class
Adjustment
3c.
4
INVESTMENT
5
OUTPUT, TBD
6
OPERATING WELLS
7a
7b
AVERAGE, TBD/WELL
WTD. AVG. TBD/WELL ***
8
OIL WELLS DRILLED
9a
9b
NEW CAPACITY, TBD
ADJ. NEW CAPACITY, TBD
l)a
INVESTMENT/BD
($MM)
**
Mexico
and drillingcosts)
17.286
3. 697
.697
Gulf of Campeche
;5
12.622
4. 291
4.291
276
249
721
1738
357
100
2.020
5.765
17.380
18.333
30
27
61
173
469
495
4. 558
0.531
=COST PER BARREL ($)
ADJ. INVST./BD (T$)
=COST PER BARREL ($)
1.597
0.504
11
SUPPLY PRICE ($/BRL)
3.992
1.259
12
1984
13
1984 YEAR-END RESERVES, BB
14
o0b
(T$)
721
1738
9.3
31.8
1995 POTENTIAL (5%), MD
1.28
4.36
15
CUMULATIVE POTENTIAL, MB
1.28
5.64
16
1995 INVESTMENT/BD (T$)
=COST PER BARREL ($)
CAPACITY, TBD
7.071
3. 158
TABLE
NOTE: tt
a NOTES ND SOURCES in additionto Table III)
Data on the numbersof operatingwells are as of July 1, 1984.
There are 249 flowing and 108 artificiallift wells in Comalcalcoarea
and 100 flowing and zero artificiallift wells in Campechearea.
Mtd In the calculationof the weightedaverage daily productionper well,
data on individualfields' daily productionsare taken from the first
six months of 1984.
'
SOURCES:Wells drilled:"Memoriade Labores,1984 ,
del Petroleo].
1985, Instituto exicano
Well depths: same source,total footagedivided by completions.
Daily output:same source.
1984 year-endreserves:same source, included5 BB condensatein
both areas.
Drillingcost:
1984 Joint AssociationSurvey.
Since wells in each region are either all onshore or all offshore,
no adjustmentis necessary.We use the data on average drilling
cost in the U.S. for given depth in the calculations.
Operatingwells:Oil & Gas Journal,December31, 1984 issue, annual
reporton worldwideproduction.
Weightedaverage outputper well using data from the same source.
Capacityassumedequal to production.
TABLE
IV
ZERO DRILLING AND RESERVE-ADDITIONS MODEL, 1985-95
YEAR
1985
1995
------ (BILLIONS
OF BARRELS)PRODUCTION (MBD)CUMULATIVE PRODUCTION PROVED RESERVES
CARTEL NONCARTEL CARTEL
NONCARTEL CARTEL
NONCARTEL
18
54
21
9
-
144
58
1995 PRODUCTION:RESERVES ----------------------->
SOURCE:
1985,0il
& Gas Journal,
46 0
37 8
0.05 2
159
39
0.088
"World Wide Oil"
Cartel includes OPEC nations plus Mexico
Non-cartel includes all others outside Communist blocks.
For explanation
of 1995 values, see text.
FIGURE
SUPPLY CURVE: OPEC 1995
(1985
5
COST LEVELS, PROD 5%
RSVS)
._
m
I-
4
(0.
0t
z
3
Ld
oz1
n~
0
0
20
CUMULATIVE
40
PRODUCTION,
60
MBD
iif·-_
-i--l--:·
(··l_.·lr
-·-ii
'1··'.··1I'·,;-·-I
_j
1·:·
;
ii
·i
·'': · `
"'
-'
:"'
·
·`-'":I'
i"
i!''''' ""':
'.
)·_··(·
_·1
i.i..
- -: . .i
' .i
1
:.-.·
·
.·I'
(·I·
· i ·
i
'
i ·; --·
:
1
i
i':
;-;· ·i
·· . i-.
··
,-.·
i····; ;· !··
..,.··..
:··.
:···:-·· r···
,·· ·
.
·:···- ·· -··
.·.
,
-·
··;
:··
·-:··· :
;···.
I
·- · ·
: .1··
"··i!:'
i
!· : "
"·
"
·-
I
!· ' ·
·
''
__I·_;
(·: _·_
'
''·'"
r
· :l_·r~~~~~~r
,:r
··
2~~~~~~-''~~~·"r.777,:
:~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
.**,"~
' '. ~. .....
;
mv
r.'-tP
:' E.*
~-
-5:
.
*
·.
''
~~~~~~~~~~~·:.,~.
I I:7
·
.. :
·
.
·.. ..
;:
~.·.~
-
-.
,
1~~~~~~~~~~~~~.
~~" '; Le1 ;P-....·..~./..
:..-?~~
L L~;
E·;
·
i:.:ii~
; :.'
'
.
~
.
:
' '-
.
~
.
~
~:.:~;.:
:~
.,'=*-~
,'·
.
.
1·-
'.~~ ~.'?'..,.,
-:
!·l
~-.~,-.~~~..i
C . ..
:
·
.-..?:-1·
.·
i.-
~L. :-~
.,_-c.7;'
;~\·f:~
:-'
?:I
?'
:
~~~~~J~
,*
_~.,~ i·
J - .: 4::':,
....
.... ..-.
.'
"
r-7~~~~~
4
...
~-..--!!~<~.~=
.
.1-
.i-
.... ·
::q' .
:
:'.
....
:.'
,
.a
...
L
.....
:.... :.-:-:.:
'_~~?.:'
,'.--,
:."t
-.
i.
:~ -.- :-.-
;
:..'-: ':
S',~:~-
' '-·=.:.~;,',".
L'..
;.~..
.~
:,:,: .-:::. :
:~~
~~~~~~~~~~~~-:·.·
r.~f~:,
.:....:
,,.
rm~.
~
.:~-
,.
...J.-'-.4
;...
,..
;-...,.
...
.
~
-
:.
..
~.L.~...
·
.:.:. .
:'
7
:;
·.
.'. :.'
~.~ :-
..
,:::.- -'-.,' ~-. r- .. ~:
'":"''
5C:.::..?~:7 .'!""~:L:'':
~"· .'~:";.r
:~~··:
:':':: ':,~i-':.::'' iI".-'..:-~d ':?~,'. .. :
.~.:'.'
..