Energy Department Paper No. 10
Marginal Cost of Natural Gas in
Developing Countries:
Concepts and Applications
August 1983
World Bank Energy Department


MARGINAL COST OF NATURAL GAS IN DEVELOPING COUNTRIES:
CONCEPTS AND APPLICATIONS
Afsaneh Mashayekhi
Energy Department
Augu3t 1983
Copyright (C) 1983
The World Bank
1818 H Street, N.W.
Washington, D.C. 20433
U.S.A.
This paper is one of a series issued by the Energy Department for the informa-
tion and guidance of Bank staff. The paper may not be published or quoted as
representing the views of the Bank Group, and the Bank Group does not accept
responsibility for its accuracy or completeness.


*     MARGINAL COST OF NATURAL GAS IN DEVELOPING COUNTRIES:
CONCEPTS AND APPLICATIONS
ABSTRACT
The uncertain supply and rising cost of petroleum products since
1973 has spurred the development of alternative sources of primary energy.
Natural gas is a major source of energy in over 50 developing countries.    In
these countries natural gas has many applications with a high value in use
both as a substitute for other fuels and as a feedstock. Many countries are
on the verge of embarking upon gas development and face complex questions of
strategy for gas development. The World Bank has addressed these questions in
a series of studies on the cost and prices of gas and its optimal allocation
among different uses. The results of these studies are expected to be useful
to project staff, energy economists, and policy makers concerned with natural
gas development in developing countries.
This paper defines the concept of marginal costs and applies it to
estimate the economic cost of natural gas in ten developing countries with a
wide range of conditions. The marginal cost of natural gas estimated for the
ten countries, using the average incremental method, is far below the border
price of competing fuels in these countries. The cost of natural gas supply
is not expected to rise in these countries within the next two decades as they
tap their proven gas reserves. The sample of ten countries includes a variety
of natural gas characteristics and these results are representative of costs
in many developing countries.    These natural gas cost estimates support a
strategy of gas development to substitute for petroleum fuels in a large
number of developing countries.


Table of Contents
Page
Executive Summary and Conclusions                                         i
I. INTRODUCTION
I.1    Background.....................                               1
1.2    Objectives...........                                .....    2
II. METHODOLOGY
II.1   Technical Characteristics of Natural Gas Production
and Transport...............4........................       4
11.2   Charac,eristics of Natural Gas Marginal Costs........     ...  4
11.3   The Average Incremental Cost (AIC) Concept.............       8
11.4   Pricing of Natural Gas...........                    ...      9
III. APPLICATIONS OF THE AIC METHODOLOGY TO NATURAL GAS
III.1 Country Sample..............................      ...........  10
111.2  Costs..................................................     10
111.3 Expected Demand and Production Profiles................       12
IV. RESULTS
IV.1   Average Incremental Costs..............................      14
IV.2   Comparative Analysis......................................   15
IV.3   Conclusions...............................................  20
Tables
1      Cost Build-up for Natural Gas Supply.........    ......      11
2      Average Incremental Cost of Natural Gas................      14
Figures
1      An Illustrative Schedule of Activities and Cashflow....       5
2      Gas Production Costs     .........................            6
3      Cost and Output with Capital Indivisibilities..........       7
4      The Average Cost of Gas by Field in Pakistan...........     16
5      The Average Incremental Cost of Natural Gas in Pakistan      17
6      The Average Incremental Cost of Natural Gas in
Tanzania....                                   ........      18
Annexes
Annex I:    Natural Gas and Gas Liquids Definitions and Conversions      21


EXECUTIVE SUMMARY AND CONCLUSIONS
The analysis of natural gas delivery costs to domestic markets in
developing countries has been limited. This paper uses the information avail-
able in the Bank to address the economic cost of natural gas. It defines the
concept of marginal cost and applies it to estimate the cost of gas supply to
major domestic markets in ten developing countries. 1/    Marginal cost theory
has been widely applied by many public utilities such as water and power to
set prices for their services.    This, however, is a first known attempt to
apply a consistent economic methodology to estimate natural gas costs in
developing countries.   Marginal costs are necessary but not sufficient for
setting gas prices due to the exhaustible nature of this resource. They are
also useful in interfuel cost comparisons and provide an explicit framework
for investment decisions regarding gas supply.
The result of the study is that the long-run marginal cost of gas
delivered to the city-gate in these countries is $0.61 to $1.79 per thousand
cubic feet (MCF) or $3.59 to $10.54 per barrel of oil equivalent (boe). These
figures are far below the economic value of natural gas in many countries as
measured by its opportunity cost as a substitute for other fuels or feedstock
even with the current depressed oil prices.      The sample of ten countries
includes a variety of natural gas characteristics.     Although costs in some
countries may not lie within this range, these sample results are representa-
tive'of costs in a large number of countries.
Further, the marginal cost of natural gas production and transport
is expected not to rise in many countries in the next two decades as they tap
their proven stock of reserves and maintain high reserve to production
ratios.  Potential economies of scale remain to be captured in the supply of
gas.  This could result in a fall in the marginal cost of gas in some coun-
tries over a period of time; as proven reserves decline and diminishing re-
turns set it, if there are no major new discoveries the marginal cost of gas
supply may increase in some developing countries.     These results support a
more rapid program of gas development to satisfy domestic energy needs in
developing countries and to alleviate balance of payment difficulties.
1/   The ten countries are Bangladesh, Cameroon, Egypt, India, Morocco,
Nigeria, Pakistan, Tanzania, Thailand, and Tunisia.


I. INTRODUCTION
I.1   Background
The uncertain supply and rising cost of petroleum products since
1973 has spurred the development of alternative sources of primary energy. As
a group, over 50 developing countries hold almost 43 percent of currently
proven reserves which is about 1288 trillion cubic feet and equivalent to 30
billion ton of oil equivalent.   Many gas discoveries, often resulting from a
search for oil, have not been fully evaluated because of the lack of immediate
incentives to invest in their development. Reserves are being reevaluated up-
ward as governments become aware of their potential contribution to energy
supply. For many developing countries, even currently proven re8erves of gas
could supply about half of their long-term commercial energy needs.
Following gas discovery, the immediate concern in many countries has
been whether or not the gas is exportable; the domestic market has often not
been explored.   Recent studies by the Bank indicate that in developing coun-
tries natural gas has many applications with a high value in use both as a
substitute for other fuels - in industry, power and the residential and com-
mercial sectors - and as a feedstock for fertilizer industries.1/      In many
countries gas development to meet domestic uses, as compared to exports, also
has a more certain market, lower investment costs that mature more rapidly,
and direct linkages to productive sectors of the economy.
Why has natural gas development to meet domestic demand been so
slow?   The major reasons include a lack of genuine commitment as well as no
strong institutional framework to integrate the activities of production,
transmission, and distribution companies and consumers.       Exploration and
development have also often been delayed due to the lack of a pricing agree-
ment with producers. Moreover, the analysis of gas supply, demand, and deli-
very costs to domestic markets in developing countries has been limited. Few
countries have until recently appreciated that natural gas can be supplied to
domestic markets at a low cost that competes with other fuels.
The World Bank has supported and financed a number of gas explora-
tion, development, transmission and distribution projects in developing coun-
tries. Its experience has generated a substantial and reliable data base that
has made this study on natural gas costs possible. One major finding of this
work is that there is a large stock of proven undeveloped gas reserves of
natural gas in many developing countries that is sufficient to support a
significant portion of their long-term energy needs.    Another important con-
clusion is that in a large number of countries potential domestic demand is
higher and more diverse than previously believed.    As a result the cost of
producing and transporting gas to meet the potential demand in many countries
is often far below the border price of the fuels it replaces.
1/ See forthcoming papers on the value in use of gas (netback) in power,
residential and commercial markets, and LNG export.


-2-
1.2   Objectives
This paper uses the information available in the Bank to estimate
the marginal cost of natural gas. 1/      Marginal cost theory dates back to
Hotelling and Dupuit. In the 1950s, Boiteux also worked on the development of
the theory especially for application in the electric power sector.        The
theory has also been widely applied by other public utilities such as water,
and telecommunications to set prices for their services. It provides a frame-
work to analyze system costs and set prices for natural gas which shares many-
characteristics of public utilities.2/ Marginal costs, however, are necessary
but not sufficient for setting gas prices due to the exhaustible nature of gas
and this paper does not address the specific issue of pricing. They can also
be used for interfuel cost comparisons to decide whether it is economic to
develop natural gas. The LRMC approach is therefore an explicit framework for
investment decisions regarding natural gas supply. Most of the gas develop-
ment costs, following from the technology of gas recovery coupled with the
legal arrangements, are incurred at discrete stages. Because of the indivis-
ible and lumpy initial investments to produce and transport natural gas, the
average incremental cost method, already widely applied in water supply and
power projects, is generally considered to be the appropriate approach to the
costing of natural gas.3/ -
This study is a first known attempt to apply a consistent economic
methodology to estimate natural gas costs in developing countries.     It pro-
vides a set of comparable cost estimates across countries with a wide range of
conditions.     This study is part of a larger series of studies on costs,
prices of natural gas and its value in different uses. The results of these
studies are expected to be useful to project staff, energy economists, and
policymakers facing complex questions of strategy for gas development in
developing countries.    Following this introduction, the paper defines the
concept of long-run marginal cost (LRMC) in Part II and applies it in Part III
1/ It excludes profits, taxes, royalties and depletion allowance, which
require a separate discussion.
2/ To meet the criteria of economic efficiency, the delivered price of
natural gas should not be less than its marginal economic cost of
supply.  The pricing of gas, however, requires extensions to the LRMC to
allow for the exhaustible nature of natural gas and meet financial cost
coverage, and income distribution objectives.
3/ The average incremental cost concept described in Chapter II has been
widely used in Bank water supply and power projects.     See for example,
Saunders, Warford and Mann, Alternative Concepts of Marginal Cost for
Public Utility Pricing:    Problems of Application in the Water Supply
Sector, World Bank Staff Working Paper, No. 259, May 1977; also Mohan
Munasinghe and Jeremy Warford, Electricity Pricing: Theory and Case
Studies, Johns Hopkins University Press, 1982.


-3-
to estimate the economic cost of natural gas in ten developing countries.l/
The results as well as comparative analysis of the different countries are
presented in Part IV.
1/ It excludes profits, taxes, royalties and depletion allowance, which
require a separate discussion.


-4-
II. METHODOLOGY
II.1   Technical Characteristics of Natural Gas Production and Transport
Natural gas shares many characteristics of public utilities, e.g.
power, water, and telecommunications, such as (i) economies of scale, (ii)
lumpy and indivisible capital investments, (iii) need for excess capacity
to meet peak demand, reliability standards and future growth in demand, and
(iv) diversity and variability of demand.1/   Therefore, the initial capacity
for production and transport is both large and long lived, and often designed
to meet the growth in demand over a 10 to 20 year period.      The measure of
costs pertinent to supplying an incremental volume of gas is its long-run
marginal, cost, namely the change in total costs over the whole production
period as a consequence of a small addition in supply.
The rationale for the use of long-run marginal costs (LRMC) is well
established and has been widely employed for the evaluation of World Bank
water, telecommunication, and power projects.2/ The LRMC of gas is useful in
negotiating prices with producers and transmission companies and consumers.
It can be compared with alternative fuel costs to decide whether it is econo-
mic to develop and use gas. It can also be used to assess the appropriateness
of investments in gas system expansion given projected market demand.    It is
consequently a determinant of actual supply of natural gas.      LRMC is also
useful in inter-sectoral planning and provides a benchmark by which other
social and economic objectives may be evaluated.
11.2   Characteristics of Natural Gas Marginal Costs
In the abstract, LRMC is the incremental cost of optimum adjustments
in the gas system expansion plan and gas system operations to meet small
increments of demand.    This approach estimates marginal costs of serving
different consumers at different times in various regions. In practice one of
the greatest sources of difficulty in the analysis of gas costs is that the
technology of natural gas development and transport is subject to economies of
scale and requires large and indivisible investments.      Investments in gas
infrastructure, following from the technology of gas recovery coupled with
prevailing legal arrangements, are incurred at discrete stages.      Costs of
initial field development such as drilling and equipping gas fields, gas
processing facilities, and main transmission lines are a high proportion of
the overall lifetime costs.
I/  See MacAvoy, Price Formation in Natural Gas Fields, Yale University Press,
New Haven, 1976.
21  See for example, Robert Saunders, Bangkok Water Supply Tariff Study, IBRD,
PUN (23), June 1976; also Saunders and Warford, Village Water Supply
:Economics and Policy in the Developing world, Baltimore, Johns Hopkins
University Press, 1976.


-5-
A gas supply system can be divided into four interrelated stages
(Figure 1). First, exploration which establishes the level of proven reserves
and their commerciality. Exploration costs include an estimate of the finding
cost of natural gas.1/ Second, the development and production stage requires
large indivisible investments for development drilling, field preparation,
field gathering, compression, separation of natural gas liquids and treatment
of gas to produce pipeline quality gas to meet contract volume, quality and
pressure requirements.   The third stage is the transmission of gas from the
field or gas treatment plant to the city gate.     Investments in transmission
facilities are lumpy and costs subject to significant economies of scale until
the maximum capacity of pipelines is reached.    The fourth stage is distribu-
tion to end users.    This paper covers the cost of gas up to the city gate
excluding distribution costs and assumes most major users lie on or close to
the main trunk line.2/
Figure 1
AN ILLUSTRATIVE SCHEDULE OF ACTIVITIES AND CASHFLOW
0    1   2    3    4   5    5    7   8    9   10   11  12   13  14   15
years
EXPLORATION
EVALUATION        m    N=
DEVELOPMENT
TRANSMISSION
CASHFLOW
1/ They exclude a depletion allowance for the value of the exhaustible
resource.
2/ The additional cost of natural gas distribution to the residential and
commercial sectors varies widely between about $2.5 to $10.0 per MCF. The
results of a study on residential and commercial gas distribution will be
available in a forthcoming paper.


-6-
Production of the first increment of gas thus requires a large
initial expenditure in exploration, development, and transmission. Production
of additional volumes necessitates little additional expenditure until maximum
capacity is reached.    Thereafter indivisibilities and diminishing returns in
providing gas to meet demand lead to additional discrete and discontinuous
investments and raise the marginal costs (Figure 2).     The characteristics of
investment in natural gas development and transport for a given field imply
that the marginal cost curve falls sharply for relatively low volumes of
recovery and rises as cumulative production increases to over 60 percent of
estimated recoverable reserves.1/
Figure 2
GASPRODUCT1ON C STS
MC
COST
$/MCF
Production
to reserve
ratio
1/ Therefore    -    0 for all Q;           0 for Q<Ql, where Ql is the maximum
volume of recoverable reserves before indivisibilities and diminishing
returns set in; and   -  2L270 for Q7Q1*
Q2      orQ'l


-7-
Due to the capital indivisibilities, costs will be marginal at some
time and non-marginal or discontinuous at others as illustrated in Figure 3.
Let us begin with the demand curve D1, if production from a given gas field is
below maximum capacity, the only costs immediately attributable to additional
consumption are the incremental operating and maintenance costs, i.e. short-
run marginal costs.    Once production is at capacity, and the demand curve
shifts, gas system expansion requires drilling in existing and new fields, new
gathering and perhaps pipeline facilities as well as additional operating and
maintenance costs.   The resulting large cost fluctuations could cause price
changes overtime that would not be acceptable to consumers.        Therefore, a
definition of long-run marginal costs that fits the structure of investments
in gas development and transport is required;    costs must be estimated within
a sufficiently long-run framework to incorporate the investment process.
Figure 3
COST AND OUTPUT WITH CAPITAL INDIVISIBILITIES
COSTS
SRMC
D          D2     D3
VOLUME


-8-
11.3   The Average Incremental Cost (AIC) Concept
The average incremental cost (AIC) definition of marginal cost seems
best suited to natural gas technology. The AIC smoothes out the indivisibil-
ities in expenditures. It also reflects the general level and trend of future
costs which will have to be incurred as gas consumption increases.     The AIC
takes a longer view of costs and looks beyond the next increment in
capacity. This is particularly important since many developing countries are
at an early stage of gas development and expect a large potential shift in
demand for gas.
The AIC is estimated by discounting all incremental costs that will
be incurred in future to provide and maintain the estimated amount of gas
which will be supplied over a specified period and dividing it by the dis-
counted volume of incremental output over this time. The timestream of expen-
diture for providing, ,aintaining, and running the system corresponds to a set
of outputs over time-
T
AICo =      [It + (Rt - Ro)]/(l + i)t
t=1
T
1:       (Qt - Qo)/(1 + i)t
t=1
it -   capital costs in year t
Qt - natural gas production in year t resulting from the investment
Rt -   operating and maintenance costs in year t
i   -  opportunity cost of capital
T   -  time horizon for development of the project as well as a 20 year
production life (t=o is the base year)
To determine the marginal cost of supplying gas the economist must
work closely with engineers and follow an iterative process. They must first
agree upon the production profile in the denominator based on demand forecasts
and supply potential in order to plan the least cost investment plan (See
111.3). This an"lysis is generally carried out for a 10 to 20 year period for
which relatively reliable data and forecasts exist.
1/ For producing fields with a declining production profile the formula has
to be adjusted so as to estimate the incremental production due to the
investment as the difference between the two production profiles with and
without the investment (Qt - ct ), where (t is the production without the
investment; the operating and maintenance costs should be also similarly
adjusted.


-9-
The second crucial question is what system of expansion should be
designed to deliver gas to the consumer at the least possible cost.        The
numerator is the present value of the least cost investment stream as well as
incremental operating and maintenance costs necessary first to start pro-
duction and, later, to raise production up to capacity and maintain it at that
level.  This least cost expansion plan to meet projected demand forecasts is
determined assuming a target level of system reliability.1/ Once the price of
gas is determined and the gas system begins to operate actual consumption may
be different from demand estimates and consequently the cosLs will have to be
revised.
11.4   Pricing of Natural Gas
The discontinuities in supply costs due to the technological indivi-
sibility of gas infrastructure could result in fluctuating prices which might
cause political difficulties.   The signals provided by such a pricing system
can not be adequately interpreted and followed by users and would therefore
not encourage optimal investment in gas using equipment.2/    The AIC approach
by smoothing out the costs provides a more useful input to the pricing deci-
sion.
The AIC, however, is only one of the criteria used to determine the
price of natural gas. The appropriate pricing strategy for natural gas must
allow for distortions due to externalities, taxes, monopoly practices, duties
and subsidies as well as the objectives of financial viability and income
distribution. It must also be adjusted because gas is an exhaustible resource
and therefore has a depletion value that should be taken into account in its
pricing.3/
Marginal economic cost of supply provides a lower boundary to pri-
ces.   In countries with a large gas surplus, prices would be close to the
marginal cost while in gas deficit countries, prices would include a larger
depletion allowance.    The gas transmission and distribution services are
similar to other utility services where use of marginal costs in pricing is
prevalent. As applied to natural gas transmission and distribution, marginal
cost pricing is a viable approach in the sense of ensuring that the benefits
of expenditures in the sector exceed the costs.
1/ Reliability   should itself   be  ideally  treated as a variable     to be
optimized; this is achieved when the marginal cost of adding capacity to
improve reliability are equal to the expected value of the cost of savings
to consumers resulting from gas shortages averted by these capacity
increments.
/  A similar argument for water supply costs is presented by Robert J.
Saunders and Jeremy J. Warford, in Village Water Supply, Johns Hopkins
University Press, Baltimore, 1976.
3/  See Dasgupta and Heal, "The Optimal Depletion of Exhaustible Resources",
Review of Economic Studies Symposium, Dec. 1974.


-10-
III.   APPLICATION OF THE AIC METHODOLOGY TO NATURAL GAS
III.1   Country Sample
Exploration, development, and transport costs exhibit considerable
variability among different regions.     These costs are needed so as to be
compared with gas prices and alternative fuel prices to decide whether to
produce, transport and distribute gas.    In this study the long-run marginal
cost of gas production and transport, using the AIC approach, has been esti-
mated for 10 countries.   These countries were selected so as to cover a wide
spectrum of characteristics such as local geology, size of reserves, offshore-
onshore, associated-nonassociated, gas with different compositions, diverse
field specifications (shallow and deep structures), as well as different
distances to the market.   Generally, costs are estimated on a field by field
basis for most major fields in each country based on Bank project and assess-
ment work.     The quantity   and  quality of data varies among different
countries.  In some (e.g. Pakistan) a detailed and reliable data base exists
for every field.   In others results are based on information on one or two
fields.
To summarize, our basic approach, which was to treat output expan-
sion as occuring by discrete increments corresponding to individual fields, is
designed to permit analysis of the relation between cost and output for an
entire producing region.   Field development should ideally proceed starting
with the lower cost field and going on to more expensive fields so as to meet
growth in demand.    In practice, due to certain contractual agreements or
incomplete knowledge, this process may not take place. Discovery of new lower
cost fields through time may also change the original ordering of fields.
111.2   Costs
The present value of costs of gas production are expressed in cons-
tant 1982 dollars and include all capital and operating cost components for
exploration, and field development to provide pipeline quality gas over a 20
year production period.   The cost of natural gas delivered at city gate is
also calculated. It includes all production and transmission costs as well as
the costs of compression facilities to maintain pressure where necessary.
These costs are close approximations to the cost of gas delivered to major
industrial, power, and fertilizer users that are located on or close to the
transmission grid.   In some cases additional branching costs for secondary
lines should be separately estimated for specific users.


-11-
Table 1
Cost Build-up for Natural Gas Supply a/
Present Value
Exploration    Exploration
&          Development &    Gas
Exploration   Development   Transmission   Volumes
(in millions of US$)               (BCF)
Bangladesh         -          93.3          239.4        391.1
Cameroon         80.0        317.5          514.9        287.7
Egypt           220.2        1683.2        1847.4       2641.5
India           115.5       1190.9         2001.8       1870.1
Morocco          45.0        244.1          360.1        210.4
Nigeria            -         1126.7        1889.5       1717.7
Pakistan        211.0         992.2        1273.2       1744.4
Thailand        123.0        1988.9        3716.3       2396.8
Tanzania        104.0        108.5          184.7        175.9
Tunisia          30.0        325.5          773.4        483.3
a/ The net present value figures are discounted at 10 percent.
In this sample the exploration cost category is relatively small
compared to the development and transmission costs.    Exploration costs are
often low since gas is frequently found during the search for oil; moreover,
there is often no clear indication of actual expenditure allocated to gas. An
estimate of current and future exploration costs is included in all country
cases except for Bangladesh, and Nigeria where large reserves to last over 20
years are already proven.   These are based on the planned exploration costs
during the 20 year planning period.   In the absence of planned expenditures
historical cost data together with geologists' estimates of success ratios as
well as the new estimated probability of a successful play in future, and
average expected discovery size are used to determine future exploration
costs.
In some countries such as Tunisia and Morocco it was possible to
estimate the cost of future reserve additions based on a planned exploration
effort.  In others, for example Egypt, Pakistan, and Tanzania it was assumed
that if the past exploration effort is continued in future in the same basins,
statistically the same amount of new reserves would be discovered. After a
point in time, due to the limited nature of reserves in a basin, similar
exploration investments would lead to a declining rate of discovery. At this
point exploration costs increase. Pakistan is a case where exploration costs
are expected to increase due to a fall in success ratios.   In Pakistan, the
estimated exploration cost is based on the estimated success ratio per play,
the average discovery size, estimated production profile, and country specific
drilling and predrilling costs. In some other countries the reserve to pro-
duction ratios are higher and exploration costs are often smaller.


-12-
For the development and transmission costs in the ten countries a
relatively complete and reliable data base exists in the Bank. These costs are
based on actual data from project documents, sector work as well as estimates
based on unit costs developed for typical installations for specific coun-
tries.  The ongoing and future development costs for known and proven fields
in the ten countries are included in the study.   These include field prepara-
tion and drilling, flow lines to separator and treatment facilities, as well
as gas treatment and separation facilities to provide a pipeline quality
gas. The cost of future drilling and field compression to maintain the pres-
sure and volume of gas production during the    15 to 20 year period are also
included. Development costs are a function of gas volumes as well as location
and specific geological factors and quality of gas, and the rate of produc-
tion.
The transmission costs include all offshore and onshore pipelines
and related facilities (telecommunications, surveying and rights of way), to
move the pipeline quality gas to major markets (city-gate). These are based
on the country data base or estimates by our engineers. In some cases such as
Thailand, Pakistan and Nigeria, compression facilities are needed to maintain
pressure requirements at delivery during the twenty year planning period.
Costs of this activity depend on the quality and quantity of gas, type of
terrain to be crossed, distance to the market, and surveying and right of way.
These costs often overestimate the lean gas costs.    Natural gas is
generally a composite product that includes lean gas and natural gas liquids
(Annex I).   It may also be produced in association with oil as in Nigeria.
Therefore to the extent that costs are joint, individual products have no
objectively determinable separate costs.   These joint costs can be allocated
on a somewhat arbitrary basis. Once raw gas costs are estimated, the lean gas
costs can be calculated using one of several methods.1
111.3   Expected Demand and Production Profiles
In this paper energy demand scenarios for the ten countries were
estimated and the share of natural gas determined and used in the denominator
1/ First, costs can be allocated proportionately according to the heat
content (Btu/MCF) of each product.   Alternatively, when the market value
of each product is known, it can be used as the weight to allocate joint
costs. A third method, allocates all costs less the economic value of the
by products' at the point of seperation to the main product.           The
,methodology that is chosen should be linked to the purpose of cost
allocation and field characteristics.


-13-
of the AIC formula.1/   The demand projections are based on the existing na-
tural gas market, its expected growth rate, and a share of the conversion
market and future demand taking into account economic and technical cons-
traints in each country.  The share of gas depends on the natural gas supply
and demand as well as the relative gas and alternative fuel costs. The study
of potential demand indicates that gas could satisfy up to about 50 percent of
the commercial energy needs in developing countries. In Pakistan which has a
gas supply constraint the share of gas in total commercial energy is about
42 percent.   This share would increase further if more gas reserves were
developed.2/
These projections are adopted as the production profile except where
the supply constraint limits production.   In the latter case the production
profile of gas depends on the potential physical supply of gas. About half of
the countries in the group are demand constrained or gas surplus countries;
there is a positive gap between their available long-run natural gas supply
and domestic demand. Another half of the sample are supply constrained or gas
deficit countries.   Their long-term demand forecasts exceed their long-run
supply potential over the next two decades.3/      The discounted production
profiles based on demand projections or alternatively supply constraints is
summarized as the present value of gas volumes in Table 1.
1/ These demand estimates are not forecasts of actual consumption; they are
potential demand scenarios for natural gas and their realization depends
on (i) relative energy prices, (ii) the degree of government commitment to
natural gas development, (iii) a natural gas policy consistent with
industrial strategy and a general energy plan, (iv) institutional strength
of organization in charge of gas development, transport, and marketing (v)
financing  sources  t' :t  fit  the  natural  gas  investment  and   cost
characteristics.
2/ These demand estimates are based on a static analysis.       In a dynamic
system, a large gas discovery may affect GDP, and energy elasticity and
bring about a shift in the whole demand curve. Once gas is discovered in
large quantities, plans to use it in new plants also emerge. Therefore,
the estimates used in the study provide a lower boundary to potential
future demand.    Increased demand would lead to higher production in
countries with a demand constraint (gas surplus) and reduce the marginal
cost of gas supply until capacity is reached.
3/ This conclusion is based on currently known proven reserves.      Further
exploration could change this balance in some countries.


-14-
IV.   RESULTS
IV.1   Average Incremental Costs
The results presented in Table 2 indicate that in all the country
cases that were considered, the long-run marginal cost of gas delivered at the
city gate is far below its economic value as measured by its opportunity cost
as a fuel (e.g., fuel oil replacement) or as feedstock.     The sample of ten
countries includes a variety of natural gas characteristics; this enables us
to conclude that the range of gas costs covers most conditions.       Although
costs in some countries may not necessarily fall in the range of this sample,
these results are representative of costs in a large number of countries.
Moreover, the marginal cost of gas production and transport is expected not to
rise in most countries in the next two decades as they tap their proven stock
of reserves. As the reserve to production ratio becomes smaller the marginal
cost is expected to rise.
Table 2
Average Incremental Cost of Natural Gas
(in 1982 US$)
Production Cost     City Gate Delivery Cost
($/MCF)    ($/boe)     ($/MCF)     ($/boe)
Banglades      0.24       1.41        0.61        3.59
Cameroon.!    1.29       7.60        1.79       10.54
Egypt          0.65       3.81        0.71        4.18
India          0.95       5.60        1.51        8.88
Morocco        1.16       6.48        1.71       10.07
Nigeria=       0.65       3.83        1.10        6.48
Pakistan       0.36       2.12        0.46        2.71
Thailand       0.80       4.71        1.50        8.84
Tanzania       0.61       3.59        1.05        6.18
Tunisia        0.67       3.97        1.60        9.43
a/ The AICs in this table are estimated at a 10% discount rate;
they exclude all profit, tax, royalty and depletion costs.
b/ Production costs for the domestic market; exports would increase
the volume of production and reduce costs.
c/ Includes the higher cost associated gas ($0.82/MCF) and lower
cost non-associated gas ($0.44/MCF).


-15-
IV.2   Comparative Analysis
The cost of gas production and delivery to the city-gate indicated
in Table 2 covers a wide range of $0.61 to $1.79 per MCF or $3.59 to $10.54
per barrel of oil equivalent. Since in our sample countries there is a proven
stock of gas, the exploration costs are a relatively small proportion of total
costs. The most important parameters that influence gas supply costs are (i)
field location; (ii) size of reserves and production to reserve ratio; (iii)
type of reserves (associated, non-associated); (iv) gas composition; (v) level
of demand and (vi) length of production life.
Onshore and Offshore Fields - The production cost of large onshore
fields in Bangladesh, and Pakistan lies at the lower end of the cost
spectrum.  This is because of the relatively low drilling costs attributable
to the type of formation, as well as concentration and productivity of
wells. The cost of production from onshore fields increases with the depth of
wells.   In Morocco some wells are over 13,000 feet deep; this together with
the high pressure of wells and low recoverability increases the production
costs. The reason for these higher costs is due to the greater width of the
wells which require specific equipment, the difficulty of operating in greater
depth, and the need for blow-out preventors and other equipment to operate
under great pressure.   Another factor that increases costs is the dispersion
of gas fields.   Gathering costs depend on the distance and number of wells.
In Cameroon the costs of an extensive gas gathering system from a large number
of wells over a wide area increase the costs of gas supply.
Offshore field production and transmission costs are generally far
above comparable onshore fields.     The offshore location of some fields in
India, Thailand, and Tanzania leads to more expensive drilling and operating
costs and a higher AIC of $0.61 to $0.95 per MCF.     This is due both to the
higher cost of equipment as well as the difficulties in offshore operations.
The size of reserves and productivity per well obviously affect costs. Thus,
the larger reserves, such as 4iskar in Tunisia, benefit from economies of
scale in production compared to other smaller offshore fields in Tunisia.
Offshore field transmission costs are also higher because of the expensive
offshore pipeline. These costs depend on the volume of thoroughput as well as
the distance of the field from the shore.
Size of Reserves and Production to Reserve Ratio - With a given size
of reserves, once production begins and the production-reserve ratio is low,
the marginal cost of production could fall initially (Figure 1). Compression
may be required in particular to increase the pressure of the delivery system
after the plateau production level has been reached.      Compression provides
relatively small additions to production and increases the cost of incremental
production. Further, as production increase, more expensive fields have to be
brought into operation.   Obviously, if a large new discovery is made it can
reduce costs.
In Pakistan, the large volumes of gas production and economies of
scale in production and transmission lead to low supply costs. The marginal
cost for different gas fields are presented in Table 4. Pakistan has a rela-
tively mature gas industry, and the production to reserve ratio has been


-16-
increasing.  It is now producing from its lower cost fields. As demand in-
creases and supply from these fields fall, the more expensive fields will have
to come under operation.
Figure 4
THE AVERAGE COST OF GAS BY FIELD IN PAKISTAN
hE"
JI'-Dt
8MCP
If H
"CI
Field "A"
100  200  300  400  500  600  700  800  900  1,000  1.100  1.200  1,300  1,400  MMCFO
VOLUME
The AIC over the 1982-2000 period is expected to remain low. This
is because the presently producing fields, which have a low marginal costs,
are expected to have a large share of total production. However, these fields
require compression facilities to maintain production which increases the
marginal cost of gas production.   The production cost of new fields is also
higher, and the finding costs of gas is increasing as the success ratio
falls.   Pakistan is expected to remain in the flat part of the cost curve
(Figure 5). Looking through beyond 1990, it will reach the moderately rising
part of the cost curve unless a large discovery is made.


-17-
Figure 5
THE AVERAGE INCREMENTAL COST OF
s/MCF              NATURAL GAS IN PAKISTAN
1.0-
0                    5                    10                  15
TIME
In contrast to Pakistan, Tanzania is only beginning to consider gas
development and use. It is in the early and falling portion of its cost curve
as indicated in Figure 6. This is due to the fact that exploration and devel-
opment wells already drilled in an offshore field are sufficient to meet a
demand up to 100 MMCFD for twenty years with some compressioa.1 after 1990. The
shape of the curve in Figure 6 demonstrates the sensitivity of the AIC to
demand. A higher demand and consequent larger production results in a lower
AIC. These costs are based on one field;     further exploration in other areas
such as Mnazi Bay is expected to increase the production potential of gas and
reduce costs even further.


-18-
Figure 6
THE AVERAGE INCREMENTAL COST
OF NATURAL GAS IN TANZANIA
S/MCF
3.0
2.0
AIC AT CITY GATE
1.0 .
AiC AT WELL HEAD
0                 50                100                150
VOLUME OF PRODUCTION - MMCFD
Indivisibilities and increasing returns, with a high reserve to production
ratio, followed by diminishing returns in providing gas at a uniform rate as the
reserve to production declines, give rise to a U-shaped cost curve (Figure 1).
Most developing countries are in the initial stages of gas development and
therefore in the falling portion of the curve. Pakistan with a relatively
mature gas industry is in the flat or slightly rising part of the curve. Looking
through the next two decades most countries will be on the falling or


-19-
'flat part of cost curve and will reach the rising costs portion thereafter
unless more gas is discovered.
Associated and Non-associated gas - In general the cost of associa-
ted gas is presumed to be lower than non-associated gas costs.    This is be-
cause a large share of the associated gas exploration and development costs
are joint costs and are partly allocated to oil.    All the cases considered,
except for Nigeria, are based on non-associated gas fields.     It is obvious
that with e-erything else equal associated gas costs are generally lower due
to the joint exploration and development costs. In actual country cases, the
associated gas costs may be higher for several reasons.       In the case of
Nigeria, associated gas is collected at no cost at the flare point if not used
by the producer.   However, it needs to be gathered from several low volume,
widely dispersed supply points, treated, and compressed.    Although the non-
associated gas requires additional drilling, it costs about $0.44/MCF compared
to the associated gas costs of $0.82/MCF.    Further, the relative distance of
the two types of fields to the market also affects costs. In the evaluation
of the supply mix of associated and non-associated gas, however, the cost is
only one of the criteria and the depletion premium of each type of gas also
needs to be estimated.
Gas Composition - Depending on the gas composition, there may be
need for purification, processing, and separation (Annex I). This depends on
the richness of the gas as well as the impurities such as hydrogen sulphide,
nitrogen, and inerts. In some gas fields in Tunisia, for example, the gas is
of a low quality and there are additional costs in processing it before it can
be used. The estimates in Table 2 have not been adjusted to take into account
the composite nature of the natural gas which includes dry gas as well as
natural gas liquids (NGLs) in different proportions.      If joint costs were
allocated on any basis, the costs of dry gas production would fall.     In the
case of a dry gas from a specific field in Tanzania, the costs would not
require any adjustment.   Joint cost issues are more important in some fields
in Thailand, Morocco, and Tunisia which have a high NGL content. The choice
of a methodology to allocate costs in these countries should be linked to the
purpose of cost allocations as well as field characteristics.   In the case of
a field in Thailand, if costs are allocated proportionately according to heat
content of each product, the dry gas costs are about $0.20/MCF below the
unadjusted costs in Table 2.    Similarly, the lean gas costs in a field in
Tunisia are estimated at about $0.15/MCF below unadjusted costs.
Level of demand - In many developing countries with large gas re-
serves, gas production is constrained by the size of the market. The actual
production profile is therefore far below the technical potential of the
reserves.   The gas system does not benefit from economies of scale compared
to, for example, the system in Pakistan that operates close to production
capacity. Sensitivity of the costs to the size of the market is a major issue
in particular in several small African countries where the industrial market
is generally limited.    In Tanzania it is estimated that depending on the
variation in the market size the delivered gas costs could vary from about


-20-
$3.06/MCF for a limited industrial and residential market in or close to Dar
Es Salaam to about $1.69 if demand increases to include a portion of the power
sector.   Costs fall further if a fertilizer plant is also included and
production from the field reaches its capacity.      Therefore in gas surplus
countries as the market expands, the benefit of economies of scale in
production and in particular transmission become apparent. In countries that
are just starting their gas development, as demand ana production increase the
costs of gas delivered to the city-gate is expected to fall over a certain
period of time due to economies of scale and higher capacity use of the gas
infrastructure (Figure 6).
Length of Production Life. Costs are very sensitive to the length
of production life. In some fields it is possible to increase annual produc-
tion rates by large increments through shortening reserve life. Due to econo-
mies of scale in gas development and transport, costs may increase less than
proportionately with a higher production level.   There is no inherent reason
to use up gas over a twenty year period rather than a shorter or longer period
when there are users who can switch at a low conversion cost to other fuels.
The twenty-year period is often used since some users may consider it neces-
sary to make costly investments in gas using facilities with a long life
expectancy and high conversion costs to other fuels.
IV.3   Conclusions
The study of the ten countries indicates that the cost of additional
recovery declines once the major indivisible investments are made and total
production is a small proportion of the volume in place resulting in signifi-
cant scale economies.   Costs may rise sharply when total recovery is a large
proportion of the reserves in place.    This is due to high compression costs
per incremental units, the need to build a new parallel pipeline, or altern-
atively a rising finding cost to replace the gas that has been produced. Most
developing countries are in the increasing returns (falling part of U curve)
or constant returns (flat part of U curve) situation.
The level of marginal costs may differ from field to field. Deep,
low pressure reserves have higher costs than shallow, high pressure fields.
Production from onshore field for a larger market results in lower costs than
offshore production for a small market. As far as the actual level of costs
are concerned, what can be demonstrated by existing data is that the economic
cost of natural gas delivered at the city gate lies between $3.59 and $10.54
per barrel of oil equivalent over the next 15 to 20 years which is far below
the border price of most alternative fuels. This is an encouraging result for
countries embarking on the development of their gas reserves.     Moreover, as
systematic exploration proceeds, reserve and production estimates may be
revised upward.
Demand curves may also shift through time as this abundant source of
energy becomes available as shown in the case of Pakistan.     As a result of
higher production levels and capacity utilization, the marginal cost of supply
will fall.    Once the most accessible and easily exploitable reserves are
depleted and diminishing returns Lat in, the marginal cost of natural gas may
increase in some countries.    The present estimates of natural gas cost in
developing countries therefore need to be used in the context of the dynamics
of natural gas demand and supply.


-21 -                           ANNEX I
Page 1 of 1
Natural Gas and Gas Liquids
A. Definitions'
Natural gas is a simple hydrocatbon that exists in association with
oil or separately as non-associated gas. It is generally a composite
product.' The simplest member methane (C1) is by far the most abundant
component, and is always present in a gaseous form. Both associated and non-
associated gas often include a high proportion of natural gas liquids
(NGLs). These NGLs include ethane (C2) and LPGs, [propane (C3, and butane
(C4)], as well as.pentanes and natural gasoline condensate (C+5).
Terminology And Constituents Of Natural Gas
METHANE
ETHANE
PROPANE                 LPG
BUTANES
NATURAL
GAS            PENTANES and heavier
ex well          fractions also referred
to as:                       NGL
C5+
Pentanes plus
Natural gasoline
Condensate
NON HYDROCARBONS
e.g. water, carbon dioxide, etc.
LNG = liquefied natural gas
LPG = liquefied petroleum gas
NGL = natural gas liquids
SNG = synthetic (or substitute) natural gas
B.   Characteristics
Calorific Value         Barrels/Ton        Boiling Point oC at
Kcals/Cu. Metre*                           Atmospheric Pressure
Methane             9,495                 15.0                - 161.5
Ethane             16,515                 13.72               - 88.5
Propane            23,675                 12.44               - 42.2
Butane             30,690                 10.08               -   0.5
Pentane            35,685                  8.53                  36.1
C.   Conversions
1 bbl crude oil:
= 5.89 million BTU (gross calorific value)
= 5,890 cubic feet = 158 cu metres natural gas
* Measured at GoC and 760 mm hg dry (Gross).


ENERGY DEPARTMENT PAPER SERIES
EGY PAPER No. I     Energy Pricing in Developing Countries: A Review of the
Literature by DeAnne Julius (World Bank) and Meta Systems
(Consultants).    September 1981.    121 pages, includes
classified bibliography.
Reviews literature on the theory of exhaustible resources
and on sectoral, national and international models for
energy demand. Emphasis on project selection criteria and
on pricing policy as a tool of energy demand management.
EGY PAPER No. 2     Proceedings of the South-East Asian Workshop on Energy
Policy and Management edited by Michael Radnor and Atul
Wad  (Northwestern University).     September 1981.    252
pages.
Contains the edited version of the lectures and discus-
sions presented at the South-East Asian Workshop on Energy
Policy and Management held in Daedeok, South Korea,
October 27-November 1, 1980.
Topics that are addressed include: the overall problem of
energy policy and its relationship to economic develop-
ment; the management of energy demand and related data;
the role and value of models in energy planning, and the
use of energy balances.   Transport and rural sectors are
also discussed in terms of their relationship to energy
planning.
EGY PAPER No. 3     Energy Pricing in Developing Countries: Lessons from the
Egypt Study by DeAnne Julius (World Bank).        December
1981. 14 pages.
Study on the uffects of energy price change in a develop-
ing country. Provides insight into the mechanisms through
which energy prices affect other prices in the economy
and, therefore, the incomes of rich and poor consumers,
profitability of key industries, the balance of payments,
and the government budget.
EGY PAPER No. 4     Alternative Fuels for Use in Internal Combustion Engines
by G.D.C., Inc. (Consultant). November 1981.    179 pages,
includes appendices.
Presents several alternative fuels used as replacement for
conventional (gasoline and diesel) fuels in internal
combustion engines.   These alternatives, including LPG,
natural gas, alcohol and producer gas, are derivable from
natural resources that exist in so many developing coun-
tries. Also provides up-to-date information on the newest
alternative fuel option currently available and those that
are being developed and tested.


EGY PAPER No,. 5    Bangladesh:  Rural and Renewable Energy Issues and Pros-
pects by Fernando R. Manibog (World Bank).    April 1982.
64 pages, includes bibliography.
Analyzes subsector issues and recommends courses of action
for energy project possibilities; identiiies renewable
energy projects which could create a positive impact in
the short to medium term.
EGY PAPER No. 6     Energy Efficiency: Optimization of Electric Power Distri-
bution System Losses by Mohan Munasinghe (World Bank) and
Walter Scott (Consultant).    July 1982.   145 pages, in-
cludes appendices.
Discusses the reasons for high existing levels of power
distribution losses in developing countries.    Identifies
areas within a power system where loss optimization would
be most effective.    Shows that reducing losses is often
more cost effective than building more generation capa-
city.
EGY PAPER No. 7     Guidelines for the Presentation of Energy Data in Bank
Report October 1982 - 13 pages (incl. 4 Annexes), Masood
Ahmed (World Bank).
The growing importance of energy issues in national econo-
mic management has led to increased coverage of the energy
sectnr in many types of reports. However, there is still
no clear, consistent and standardized format for present-
ing energy sector information.    This paper reviews the
problem and proposes guidelines for policymakers and
operational staff who deal with energy issues. The paper
is divided into three parts: part one sets out the basic
framework for presenting aggregated energy data -- "the
national energy balance"; part two deals with the use of
appropriate units and conversion factors to construct such
a balance from raw demand and supply data for the various
fuels; and part three briefly discusses special problems
posed by:    (i)   differences in end use efficiency of
various fuels; (ii)     the inclusion of wood and other
noncommercial energy sources; and (iii) the conversion of
primary electricity into its fossil fuel equivalent.
EGY PAPER No. 8     External Financing for Energy in the Developing Countries
by Althea Duersten (World Bank).    June 1983.   66 pages,
includes appendices.
Provides an overview of energy financing in the developing
countries.  Identifies energy investment requirements and
past financing patterns. Discusses the historic roles of
multilateral and bilateral assistance programs in helping
to mobilize financing, particularly for low income oil
importers and in providing economic and sector advice.
Examines the role of official export credit, and discusses


lending by private financial institutions which has been
the predominant source of financing for energy projects in
the middle and higher income developing countries.
EGY PAPER No. 9     Guideline for Diesel Generating Plant Specification and
Bid Evaluation by C.I. Power Services Inc. (Consultant).
December 1982 - 210 pages, includes appendices.
Explains the characteristics and comparative advantages
and disadvantages of large low speed two-stroke diesel
engines intended for electric generating plant service,
and develops a bid evaluation procedure to permit compar-
ing of bids for both types.