Report No. 12061-AZ
Azerbaijan
Energy Sector Review
December 27, 1993
Infrastructure, Energy and Environment Division
Country Department Illi
Europe and Central Asia Region
FOR OFFICIAL USE ONLY
U
MI CROGRAPHICS
Report No:            12061  AZ
Type: SEC
Document of the World Bank
This document has a restricted distribution and may be used by recipients
only in the performance of their official duties. Its contents may not otherwise
be disclosed without World Bank authorization.



Fiscal Year of Borrower          Weights and Measures
January 1st - December 31st            Metric System
ACRONYMS
ABEDA              Arab Bank for Economic Development in Africa
ASAC               kgricultural Sector Adjustmcnt Credil
BADEA              Banque arahe pour le ddveloppement economique en Afrique
(Arab Bank for Economic Development in Africa - ABEDA)
BPPA               Antananarivo Plain Development Project Authority
BTM                National Rural Development Bank
CASA               Credit a !'ajus!ement du secteur agricole
(Agricultural Sector Adjustment Credit)
CASEP              Credit a l'ajustement du seateur public
(Public Sector Adjustment Credit)
CASPIC             Credit a l'ajustement du secteur des politiques industrielles et commerciales
(Industry and Trade Policy Adjustment Credit)
CCCE               Caisse Centrale pour ia Cooperation Economique
CFDT               French Textile Development Company
CIRIR              Rural Irrigation District
CIRVA              Agricultural Extension District
CVA                Centre de la vulgarisation agricole
ERR                Economic Rate of Return
FAC                Aid and Cooperation Fund (French Government)
FANAMALANGA   Mangoro Forest Company
FAO                United Nations Food and Agriculture Organization
FED                European Development Fund
FOFIFA             Agricultural Research Agency
GDP                Gross Domestic Product
HASYMA             Cotton Marketing Parastatal
IDA                International Development Association
IFAD               International Fund for Agricultural Development
ITPAC              Industrial and Trade Policy Adjustment
MPAEF              Ministry of Animal Production, Fisheries and Forests
MPARA              Ministry of Agricult.Production and Agrarian Reform
OED                Operations Evaluation Department
O&M                Operation and Maintenance
PCR                Project Completion Report
PASAGE             Projet d'action sociale et d'appui a la gestion
(Economic Management and Social Action Project)
PSAC               Public Sector Adjustment
SAMANGOKY          Development Agency for the Lower Mangoky Valley
SAL                Structural Adjustment Loan
SECAL              Sectoral Adjustment Loan
SAR                Staff Appraisal Report
SOMALAC            Development Agency for the Lac Alaotra Region
UNDP               United Nations Development Programme
WUA                Water User Association



FOR OMCLFCL USE ONLY
Preface
The Republic of Azerbaijan became a member of the World Bank on September 18, 1992. This
report is based upon the work of missiors which visited Balu in July and October 1992. These missions
would like to thank the Azerbaijani authorities for their warm hospitality, excellent cooperation, and for
the openness of the discussions.
The report was prepared by Michael Levitsky (the main author). Contributions on particular
topics were provided by: Miguel Montes, Fernando Zuniga-Rivero, Humayoon Ansari and Thomas
O'Connor (petroleum exploration and production), Hiroki Okimi and Howard Ash (natural gas), N.C.
Krishnamurthi (pet,oleum refining and marketing), Salem Oushes (elecWtricity and district heating),
Suzanne Barnes (energy pricing and trade), Gary Nicholson (petroleum equipment industry), James
Greenlee (oil field environmental issues), and Robert Asher (petroleum law). Brenda Manuel provided
data and graphics support, and the report was processed by Banu Setlur.
This document has a restricted distribution and may be used by recipients only in the perfor.-
of their official duties. its contents may not otherwise be discloed without W. orld Bank authorization.



Table of Contents
Executive Summary       .....           ....... I                                          iii
Energy Policy Matrix.                                                                    xvii
Chapter 1:    Energy Sector Developments and Outlook ...................... 1
Current Situation ................................ 1
Energy Trade Outlook ............................. 7
Chapter 2:     Oil Exploration and Production - Current Status ......       ............ 9
Historical Perspective . ............................. 9
Current Reserves and Production  ........         ............. 11
Oil Production in the Mature Fields .....     .......  ....... 13
Oil Field Environmental Issues .........        .............. 18
The Petroleum Equipment ndustry  .......          ............. 21
Chapter 3:     Oil Exploraticn and Production - New Developments .....         ......... 24
Field Development Issues ............          .............. 24
Future Production Prospects  ..........         .............. 29
Oil Export Pipeline . ............................ 36
Chapter 4:    Petroleum Refining and Products Marketing .39
Chapter 5: Natura Gas .49
Current Status .49
Outlook for Natural Gas Supply and Demand .55
Chapter 6: Electricity .61
The System .61
Sectoral Organization and Management .62
Electricity Supply and Demand .65
District Heating .65
Regional Trading of Power .66
Environmental Aspects .66
Chapter 7:  Energy Sector Institutional Reform .67
Energy Sector Governance .67
Energy Enterprise Reform .69
Chapter 8:     Energy Pricing Policy ........................                             75
Energy Pricing Framework  ...........          .............. 75
Recent Pricing Trends .     ........................... 76
Energy Price Reform .............................. 78
Chapter 9:    Energy Sector Investments and Technical Assistance  .....        ......... 85
Energy Sector Challenges .                                         85
Investment Plans .86
Energy Sector Technical Assistance Strategy .88
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FIGURES
Figure 1.1    Primary Energy Consumption, 1991
Figure 1.2    Energy Intensity of Economy, 1990
Figure 1.3    Projected Energy Trade Balance
Figure 2.1    Azerbaijan Oil Production (Total and Percentage of FSU Production)
Figure 2.2    Offshore and Onshore Oil Production, Selected Years, 1940-90
Figure 2.3    Cumulative Oil Production and Remaining Reserves
Figure 2.4    Oil Production - Guneshli and Other Fields
Figure 3.1    Oil Production Prospects
Figure 3.2    Division of Oil Production Alternative Scenarios
Figure 4.1    Relative Economics of Crude and Product Exports from Azerbaijan
Figure 5.1    Natural Gas Production
Figure 8.1    Energy Prices Azerbaijan vs. Russia and Kazakhstan (February 1993)
Figure 8.2    Petroleum Value Shares
ANNEXES
Annex 1.1    Energy Sector Investment Financing Requirements
Annex 1.2    Energy Sector Technical Assistance - Summary Priority Components
Annex 1.3    Azerbaijan Energy Trade (Volume & Value)
Annex 1.4    Energy Balance 1990
Annex 1.5    Energy Trade Scenarios
Annex 2.1    Azerbaijan Oil and Gas Fields
Annex 3.1    Petroleum Production and Investment Projections
Annex 3.2    Oil Supply-Demand Balance Scenarios
Annex 4.1    Consumption & Export of Refined Products (1990-91)
Annex 4.2    New Baku Refinery, Physical Facilities
Azneftyag Refinery, Physical Facilities
Annex 4.3    Refineries Crude Tbroughput and Production of Main Products, 1981-92
Annex 4.4    Typical Characteristics of Crude Oil and of Mixtures Charged to Refinery Units, 1991
Annex 5.1    Azerigas Acquisition Prices, Retail Prices
Annex 5.2    Household Gas Tariffs (Monthly), January 1, 1993
Annex 5.3    Gas Supply-Demand Scenarios
Annex 5.4    Pricing of Domestic Natural Gas Production
Annex 6.1    Existing Generating Plants
Annex 6.2    Existing and Projected Generating Capacity, 1991-2005
Annex 6.3    Electricity Tariffs
Annex 7.1    Energy Sector Institutions
MAPS
Azerbaijan Oilfields and Oil Infrastructure
Caucasus Region: Potential Export Pipeline Routes
Azerbaijan Natural Gas System
Azerbaijan Electricity Grid
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EXECUrIVE SUMMARY
Key Conclusions and Recommendations
i.    In order to bring about the most effective contribution of the energy sector to the country's
transition to a market economy, the Govermnent should pursue the following policies:
*  Final production agreements with international oil companies, leading to the exploitation of the
country's undeveloped offshore oil fields, should be concluded as soon as possible. Rapid and
efficient development of the oil fields is essential to economic recovery. The Government should
take an integrated view of the development of the large offshore fields, working with the oil
companies to optimize investment planning. Negotiations need to be carefully structured and the
mnmber of separate agreements should be kept to a minimum, possibly by combining negotions
on the three major oil field developments. It is ;mportant that consistency and contimnity of
policy is maintained to ensure rapid progress with the agreements, and to strengthen investor
confidence. Retaining suitable highly ualified advisors to &he Government and the State Oil
Company (SOCAR) in negotiations with the foreign companies should be a top priority. In order
to attract foreign investment, the Government should pass legislation to provide a legal
franework for investment in petroleum. It would probably be inadvisable for Azerbaijan to
attempt to assume a large role in financing the first generation of field developments, in view of
the major exposure involved and the need to raise credit for other purposes.
*  Rehabilitation of the producing portion of the Guneshli field, which is in danger of a rapid
decline in the short term, is the most urgent priority. A substantial decline in oil productibn
from Guneshli would undermine the prospects for economic recovery.
* The Government should continue with its cooperative approach to the development of an oil
export pipeline, and related common petroleum infrastructure. Open cooperation with the foreign
companies investing in production, with Governments of countries lying along the pipeline route
and with international financial institutions is essential if the financing for this large project is to
be raised on reasonable terms. In the medium term, there may be a need to seek other options
for exporting oil, such as swaps with Russia, in order to ensure an outlet for early production
increases.
*  The Government should encourage the maintenance of a competitive petroleum equipment
industry in Azerbaijan, to capitalize on the country's potential advantage as a supplier to the
growing market in other FSU countries, and in order to ensure supplies to local industry at least
cost. A comprehensive development strategy for the industry, including joint venmes with
foreign companies and participation of private capital should be elaborated. Planning for local
participation in the offshore investments should also commence immediately, if the benefits of
the oil projects to Azerbaijan are to be maximized. A program to develop local mafacuing
of offshore platforms and equipment, and for services, should be developed, in partnership with
foreign companies and within a commercial and competitive regime.
*  7%.e economics of production in the older oil fields need to be approached in a realistic manner.
Wells which are uneconomic should be shut down, and field production systems which cannot
be maintained economically, probably including the Oil Rocks field, should be restructured. Ihe
reduction in employment in the oil fields can be handled both through retraining and within the
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-iv-
process of social protection during the economic transition. Fields should be put out to tender
for joint ventures with private companies within a structured contractual and technical
framework. Investment to reduce environmental contamination in the oil fields should be
integrated into a restructuring strategy.
*  The prospects for oil refining in Azerbaijan need to be examined within a market pricing
envirornent. A substantial part of ihe older capacity will probably have to be closed down.
New investment in refining should be assessed realistically against the option of direct crude oil
export by pipeline, with the latter option likely to be the most economic.
*  Greater emphasis should be g.ven to the natural gas sub-sector, as this is the main fXel used
within Azerbaijan. Improvement in gas usage and exploitation should be a key aim, so as to
reduce the rising burden of gas imports. Losses of gas should be reduced through pipeline
rehabilitation investment, and urgent implementation of the project to capture gas vented
offshore. Gas meters, if possible produced with private participation within Azerbaijan, should
be introduced rapidly to improve end usage and allow gas prices to be raised substantially.
* Power sector investment should be based upon a least-coa plan, which should be undertaken as
soon as possible. New capacity may not be needed for several years as demand falls, and
investment should focus on rehabilitation of existing capaciy and systems. The prospects for
district heating should be assessed against expanded use of natural gas.
* Energy prices should be raised towards zonomic levels, according to a structured program of
price increases. The aim should be to raise energy prices to economic levels, or international
levels where appropriate, as rapidly as possible, conceivably within one year of the
implementation of an economic stabilization program. This program should take account of the
social and economic impact of price rises. A system of taxation to capture excess profits should
be put in place.
- Ihe Government should establish an effective agency responsible for energy policy making and
implementation. Such an agency, or Energy Ministry, should be small but capable of providing
leadership in national policy and in energy sector relations with foreign Governments and
companies. Regulatory agencies should be set up for oil licensing and for gas and power utilities,
which would work in a transparent manner and allow efficient functioning of the entities under
their control.
* The integrated energy companies in oil, gas and power need to develop along commercial lines.
Clear commercial interfaces need to be established between the different stages of energy supply
(production/generation, processing, transmission, distribution), which reflect the economics of
different business units. Management and financial systems need to be strengthened, and staff
trained in modern business practices. The companies should be restructured to eliminate
ancillary activities, and internal service units should be made competitive with external suppliers.
Restructuring and strengthening of institutional capability is especially urgent for SOCAR. to
allow it to deal effectively with the very large program of investnent in oil development.
* In order to restructure its energy sector in a coherent manner, and develop a viable investment
program, the government should seek a comprehensive program of technical assistance from
international donors and financial institutions. Both grant and loan financing may be required



to implement the program promptly. Implementation of such a program will ensure that the full
potential of the energy sector to contribute to economic recovery is realized.
ii.    The Energy Policy Matrix on page xvii summarizes the policy priorities for the energy sector,
together with the steps already taken, and the suggested next steps and timing. It is designed to serve
as a reference for the policy priorities discussed in this report, and as a tool for planning implementation.
The Historical Legacy of Petroleum
iii.   Energy has historically played a key role in shaping Azerbaijan's economy, and will continue to
do so in future. Azerbaijan is one of the oldest oil producing regions in the world, and supplied most
of the requirements of the Soviet Union until World War II. After WW U, Azerbaijan was eclipsed by
new oil producing regions in Russia, and investment in the courstry lagged behind other regions. Oil
production fell from 20 million tons (mt) in 1970, to 11 mt in 1992, just 2 percent of Former Soviet
Union (FSU) production. As oil production has fallen, Azerbaijan's importance as an oil exporter has
declined, with net exports falling from 8 mt in 1981 to 3 mt in 1991. Most importantly, the Soviet
industry failed to exploit the large resources under the Caspian Sea efficiently, due to shortcomings in
technology and insifficient investment funds. As a result, large offshore oil deposits still await
deveopment. Undeveloped reserves in discovered fields total some 650 mt, while even larger reserves
may exist in unexplored structures. The potential production from these deposits holds the key to the
development of Azerbaijan's energy sector and of its economy.
iv.    As a result of its unusual history, Azerbaijan's upstream oil industry now presents two very
contrasting aspects: On the one hand, the older producing fields onshore and offshore are mostly in a
state of advanced decline, with old and dilapidated infrastructure. On the other hand, the large new
offshore fields represent some of the major undeveloped petroleum resources in the world, susceptible
to development through state-of the-art offshore technology. This creates a need for a wide range of
policies and decisions within the industry, aimed both at exploiting new reserves efficiently, and at
restructuring production in the mature areas.
The Need for Restructuring
v.    Oil production in the oider oilfields has been declining for many years, and average productivity
per well is only 0.7 tons/day onshore. The largest mature offshore field, Oil Rocks, sustains a sizeable
infrastructure and manpower base on very little production, and is probably no longer economic to
operate. It is likely that a large number of the onshore producing wells are uneconomic at international
costs and prices, and should be shut down. There is substantial environmental pollution from the oil
fields, through oil spills and inappropriate disposal of formation water.
vi.    Total oil production has been sustained by development of the large offshore Guneshli field, found
in 1979, which now accounts for 60 percent of national oil output. Yet this field has been developed in
a sub-optimal manner, using obsolete technology. Reservoir management and production practices have
been poor, and the field is in danger of entering a premature decline. A fall in production from Guneshli
would have serious effects on Azerbaijan's oil export revenues, with each 10 percent decline cutting
Azerbaijan's potential oil exports by 25 percent, or US$75 million per year.
vii.   While oil has been a key export item for Azerbaijan, natural gas has been the main fuel for
domestic use. Gas consumption, at around 13 billion cubic meters (1,cm) in 1991, normally accounts for



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60 percent of primary energy use (with oil making up most of the remainder). Gas production has fallen
aiong with oil production, from 14 bcm in 1980, to 10 bcm in 1991. For many years, insufficient
attention has been given to system maintenance and to development of gas reserves. In addition, gas
usage is extremely wasteful, due to large losses in the transmission and distribution system (over 15
percent of supplies), an almost complete lack of customer metering and inefficient gas-using equipmept.
About 15 percent of gas production is also vented offsh, e. Total annual losses thus amoun: to about 4
bcm.
viii.  As a result, Azerbaijan has become a large net importer of natural gas, with net imports (mostly
from Turkmenistan) totalling 8.2 bcm in 1991. Under the previous FSU regime such trade
interdependency between republics was encouraged, without regard to efficiency considerations and acta
resource transfers. Following the break-up of the Soviet Union, the scale of inefficiency and transfers
have become apparent, and the cost of gas imports to Azerbaijan is rising very rapidly as Turkmenistan
attempts to raise gas prices to world levels. Due to price disputes, net imports from Turkmenistan were
greatly reduced in 1992, to only 4.2 bcm. At world prices gas imports could cost, Arerbaijan about $600
million per year, or 35 percent of total import costs.
ix.    Because qf its large gas imports, Azerbaijan is only about 90 percent self-sufficient in energy.
In financial terms, however, it may continue to run a small trade surplus over the next one or two years
as long as gas import prices remain significantly below the equivalent value of oil product exports.
Azerbaijan's energy trade balance is adversely affected by its inefficient energy usage, which makes it
one of the least efficient of the FSU Republics. Energy consumption per unit of Gross Domestic Product
(GDP) in Rubles in Azerbaijan is 20 percent above the average for Russia. Comparisons using US Dollar
GDP figures, while inevitably inexact, suggest that Azerbaijan is at least 50 percent less efficient than
even the least efficient Eastern European countries (e.g. Bulgaria), and many times less efficient tham
Western European countries.
X.    Most oil exports from Azerbaijan have been in the form of oil products, processed in the two
large refineries located near Baku, and transported either by rail or by Caspian tanker. The capacity of
these refineries, at 20 mt per year, has exceeded Azerbaijan's diminished oil production for many years,
and the spare capacity was used to process imported crude from Russia and Kazakhstan. This inward
processing was probably uneconomic and has largely ceased as prices in FSU oil trade move to world
levels. Moreover, the facilities at these refineries are old and lacking in upgrading capacity. The
continued viability of much of the current capacity within a market pricing environment must be in
question.
xi.    Azerbaijan's long history of oil production helped to make it the major center of petroleum
equipment manufacturing in the FSU. The industry supplied 65 percent of FSU requirements of most
types of production equipment. Since the break up of the Soviet Union, the industry has suffered from
a lack of investment funds, a collapse in trading arrangements for inputs and increased competition in the
FSU market both from foreign suppliers and from new local manufacturers. The petroleum equipment
industry is a key part of Azerbaijan's industrial base, and represents a potential source of hard currency
exports. Its continued viability is also important in maintaining competitive low cost supplies to the FSU
oil industry, especially in Russia. A comprehensive development strategy for the industry, including joint
ventures with foreign companies and participation of private capital, should be elaborated.
xii. Azerbaijan's power capacity is designed to run largely on natural gas, with a modest contribution
(about 7 percent) from hydro. Over the last year power stations have been forced to switch to fuel oil,



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as gas imports from Turkmenistan have been restricted. The use of fuel oil aggravates the already highly
inefficient operation of these stations, some of which are nearing the end of their useful life. The
transmission and distribution system is also in need of large scale rehabilitation.  Azerbaijan has a
significant district heating sub-sector, -'hich is extremely run-down and in need of refurbishment.
xiii.   Azerbaijan inherited from the Soviet Union a highly distorted system of energy pricing. Price
policy over the past two years, however, has been ad-hoc, and energy price rises have tended to lag
behind those in other FSU countries. Producer and product prices for oil remain well below international
parities (about 10 percent and 20 to 30 percent of parity respectively). Natural gas producer prices have
been kept low to offset the rising cost of imports from Turkmenistan, and prices are now only about 3
percent of import parity. Both gas and electricity prices to residential consumers have been kept low
relative to prices to industry, with growing cross-subsidization. The slow pace of price increases has led
to rising financial deficits in all the major energy enterprises, which has aggravated the long term problem
of inadequate investment in plant maintenance and replacement.
xiv,   Azerbaijan's energy sector institutions have begun the process of reorganization, although
enterprises continue to operate in much the same manner as before. The oil Producing Associations from
the FSU have been abolished, and an integrated State Oil Company (SOCAR) has been formed, including
both oil and gas production and the refineries. Gas distribution and transmission have been merged into
a single state company, Azerigaz, while the power sector is under the control of Azenergo. Government
coordination of the energy sector is weak, with no energy ministry and a lack of high level policy making
staff.
Conditions Favoring Energy Sector Restructuring
xv.   While Azerbaijan faces significant challenges in restructuring its energy sector to conform to the
requirements of a market economy, it also has a number of advantages that make it capable of achieving
such a restructuring more easily than many other FSU countries:
*  Azerbaijan is a net oil exporter and has substantial oil resources which will make it a much larger
exporter in future,
*  The country has a simple fuel supply structure (oil and gas), without the large nuclear, coal and
hydro sources that can greatly complicate energy policy making in other republics,
*  Azerbaijan is relatively compact in area, making internal energy transport and distribution easier
than in the large PSU countries (although a new pipeline will be needed for large scale oil
exports),
* The institutional structure of the energy sector is relatively simple, with centralized oil, natural
gas and electricity companies accounting for most sector activity, while such activity is often
highly decentralized and more difficult to control in other FSU countries,
* There is a large base of skilled manpower which, following some emigration over the last few
years, is likely to remain stable in future,
*  The country opened up to foreign investment relatively early, particularly in the petroleum
sector, where foreign oil companies have established a substantial presence in the country,



-viii-
* The government has been committed to rapid economic reform, and has been willing to change
entrenched sector institutions and business practices.
xvi.   All of these factors suggest that Azerbaijan has a good chance of achieving a rapid transformation
in its energy sector. However, this will require openness to teO2nical assistance and a willingness to take
hard decisions on pricing, institutional reform, and the restructuring of infrastructure.
hnpact of Oil Development - Base Case
xvii.  Development of Azerbaijan's offshore oil resources will have a profound impact on the country's
energy sector, and represents the key to economic transformation. Growing oil production can generate
the revenues required to finance restructuring, infrastructure investment and social policies during and
after the transition to a market economy. However, the nature of offshore oil development means that
the major rewards from oil production are some years away, and the government will have to move
quicldy to reach agreements on oil development with foreign companies if the benefits are to come when
most needed.
xviii. In the short term, Azerbaijan faces a difficult energy situation as oil and gas production continues
to decline, and gas import prices rise rapidly. As long as gas import prices remain significantly below
the export value of oil products, the country is likely to continue to run a trade surplus in energy.
However, the level of this surplus will be modest, amounting to at most US$90 million in 1995. Any
delay in the development of the offshore fields, or adverse development in gas import prices or
availability, could push Azerbaijan into an energy trade deficit. Since Azerbaijan appears to rely on its
trade surplus in energy to offset a deficit on other products, a loss of the energy surplus would represent
a serious economic setback.
xix.   The development of Azerbaijan's undeveloped offshore fields will require an investment of some
$10 bn over the next ten years. Under a Base-Case scenario (which assumes investments proceed as
currently planned by the oil companies) this investment will allow production to rise from 11 nmt in 1992
to 45 mt in the year 2005. Oil exports will rise from 4.0 mt in 1992, to 40 mt in 2005, making
Azerbaijan an exporter equivalent in scale to Nigeria today. The total value of exports will be some $3
bn in 2000 and $5 bn in 2005, representing about 60 percent of total exports.
xx.   The growth of production and exports alone provide an incomplete picture of the impact of oil
development on Azerbaijan's economy. In the early years of development, much of the impact will come
from the large flows of inward invezstment (about $1.5 bn per year) and from the manner in which this
is spent. A large part of the investment will go to import equipment for the offshore projects. Yet
because of Azerbaijan's landlocked location, and its capacity to manufacture a wide range of equipment,
about 30 percent to 45 percent of investment may go to enterprises in Azerbaijan, resulting in a very
large boost to domestic industry. In particular the jackets for offshore platforms are planned to be
constructed at a yard outside Baku. Local sources are also likely to supply much of the labor and
offshore services, and some 50 percent of annual operating expenditure (reaching about $500 million by
2000) is likely to stay in Azerbaijan. Careful planning will be needed to ensure that Azerbaijan's share
in oil investment and operations is maximized while providing competitive supplies to the offshore
developments, and avoiding inflationary bottlenecks in the economy.
xxi.  Involvement of major foreign oil companies is the only means by which Azerbaijan will obtain
the technology, financing and project organization to develop its offshore fields. However, the terms of



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the agreements with the oil companies on oil production will have a large effect on net revenues to
Azerbaijan. In the Base Case, for example, foreign company oil exports (for investment recovery,
operating cost recovery aad profit) could amount to $2.2 bn in 2005 (42 percent of total oil exports)
under standard production sharing terms. TF  balance of exports will accrue to the Government,
amounting to some US$1.4 bn in 2000, and constituting a major source of revenue for the Government.
In addition, Azerbaijan will have to decide on the best means of financing the oil developments. The oil
companies may be willing to carry all the costs of the offshore fields, in return for a relatively rapid cost
re -,.-<ry schedule. The timing of revenues to Azerbaijan can also be adjusted through adjusting the
shares of revenues received by the Government and companies under the production sharing formulas,
to suit Azerbaijan's requirement for earliet revenue. Given the very large sums involved, it is vital that
Azerbaijan obtains the best possible advice in its negotiations with the foreign oil companies, and that the
assessment of agreements is integrated into an overall macroeconomic framework.
Export Pipeline and Common Infrastructure Requirements
xxii.  Development of oi for export will require construction of a crude oil export pipeline with access
to world markets, at a cost of at least $1.5 bn. This pipeline would have to cross at least one other
country. SOCAR has been assessing the options for the routing of this pipeline together with the foreign
oil companies 'hat plan to invest in oil production. The preferred route at present lies across Iran or
Armenia and T'urkey to the Turkish Mediterranean port of Ceyhan. However, in view of the
uncertainties surrounding this project, it would be advisable for Azerbaijan to keep other options open,
such as routes across Georgia or Russia to the Black Sea. The commitment to developing the pipeline
jointly with the oil producers, as a means of carrying oil to market on a least-cost basis, represents a good
star to such a venture. Oil companies represent the most effective means of mobilizing capital for a
pipeline, although other agents such as export credit agencies and multilateral institutions may also be
involved. Open agreements on tariffs, and reliable and strong project partners with a stake in least-cost
operation, are the best guarantees of stable tariff and transport arrangements to future investors in
Azerbaijan's oil fields. This, in turn, will ensure that Azerbaijan receives oil investment on the most
favorable terms. It is also important for Azerbaijan to maintain a dialogue with its Caspian neighbors
(especially Kazakhstan), so as to integrate regional oil exports if this can lead to cost savings.
xxiii. A further issue affecting the offshore developments is the need for common infrastructure and
an integrated development strategy. The three major undeveloped oil fields (the undeveloped portion of
Guneshli and the Chirag and Azeri fields) all lie in close proximity and may well share reservoirs in
common. Hence joint infrastructure (offshore pipelines, terminals, marine fleet, construction yards etc.)
would optimize development, while production planning must take account of all field operations.
Azerbaijan has begun work on joint infrastructure planning with the oil companies and is fostering a joint
approach to field development through uniization - these are steps in the right direction. Azerbaijan
might reasonably expect to take a share in financing the joint infrastructure, and the export pipeline,
where its participation may be needed to generate confidence among other investors. The organizational
and financing arrangements for the joint infrastructure and for the export pipeline, and for the operating
structures for the oilfields, are critical issues on which Azerbaijan should seek expert advice.
Impact of Oil Development - Alternative Scenarios and Issues
xxiv. A number of alternative scenarios could alter Azerbaijan's revenues from oil development. If
production from the fields is delayed (from the Base Case assumption which assumes large scale foreig
investment starting in 1994), this would greatly aggravate the problems of economic adjustment - a delay



of two years would lead to $2 bn less investment before 2000 and an energy trade surplus of $l.2 bn (55
percent) below the Base Case in 2000. Government revenues in the year 2000 would also be about $700
million less. If oil development does not start until after 2000, Azerbaijan is likely to suffer a severe
economic decline; in this case the energy trade deficit by 2000 will be about $600 million, compared with
a surplus of $2.1 bn in the Base Case. An alternative possibility is that Azerbaijan may pursue a policy
of restricting production levels in an attempt to "conserve" oil for "future generations", yet such
conservation is likely to be sub-optimal, since it delays the benefits of oil exports and reduces projects
to below optimum scale. Lower oil prices would also clearly reduce Azerbaijan's future earnings from
oil production - a fall of 15 percent in oil prices would reduce the Government's share of oil exports in
2000 by about 25 percent and cut the energy trade surplus by 20 percent to $1.7 bn. Azerbaijan could,
of course, gain even larger revenues from oil development if oil prices are above the Base Case, although
past experience of the oil market shows that it would be unwise to plan for this case. It may also be
possible to accelerate the pace of development from that shown in the Base case. The gap between the
development of the three offshore fields, of around three years, is determined by the capacity of
Azerbaijan's construction facilities and support services - a more rapid development program may be
possible but would require very large investments to increase local capacity.
xxv.  Exploration of the Caspian Sea, and the onshore areas, for new petroleum fields should also be
a priority. It is important that this activity is carried out within a coherent legal, commercial and strategic
framework. A Petroleum Law should clarify responsibilities and rights of foreign companies, and should
also set up a licensing agency. A licensing strategy would involve division of the prospective areas into
blocks, structured promotion tc the international industry, and possibly licensing rounds designed to
ensure orderly and progressive exploration of key areas. In the short term, however, it is important to
ensure drilling of the large but unexplored Shach Deniz structure, since this is ready for drilling and
knowledge of its contents could allow its development to be integrated into that of the Inown fields.
Azerbaijan's energy sector planning should take into account the high probability that as a result of
successful exploration of the Caspian Sea, a "second generation' of new fields will be developed after
2000, to sustain production and investment levels.
Alternatve Ol Development Scenarios
Bue Case                      Delayed nwestment
1992   1995    2000      2005     1995    2000      2005
Oil Production (mt)              11.1    9.7      25.6     45.2      9.1     17.4     39.3
Net Oil Exports (mt)              2.6    4.7      20.8     39.7      4.1     12.6     33.8
Net Gas Import (bem)              4.3    8.0      10.5      9.2      9.6     11.3     10.6
Energy Tide Balance (US$bn)       0.05    0.09    2.09      4.71    -0.10     0.92     3.80
Cum. Oil investment (USSbn)       0.0    1.5      9.6      12.2      0.6      7.5     11.6
Gov. Oil Exports (US$bn)          n.a.    0.4      1.4      2.8      0.4      0.7      2.0
Source: MirSion estbmates.
xxvi.  A key issue for Azerbaijan is the type of financing to be adopted for the offshore field
developments. In financing the "first generation" of fields, the Government must take account of the fact
that SOCAR and Azerbaijan are financially constrained, with limited ability to raise funds on commercial
teams, and that there will be substantial calls upon state resources for non-oil investment. The alternative
to SOCAR funding its own share of costs is to be "carried" by the foreign companies (i.e. to have its



-xi-
share of costs paid by the companies). In deciding on the level of SOCAR's participation, the relative
costs of funding through a "carry" by the companies and through the financial markets needs to be
examined. It may, however, be inadvisable for SOCAR to assume a large role in financing the first
generation of fields, since this would both expose Azerbaijan to a large element of project risk and limit
the country's financing capacity for other purposes. Macro-economic projections show that Azerbaijan
will need to borrow between $400 million and $500 million per year from 1995 to 1999 to meet its
funding requirements in the Base Case scenario, even if SOCAR only funds 25 percent of the oil export
pipeline and 50 percent of the offshore infrastructure (and is carried by the oil companies for field
investments). Until the late 1990s, when oil exports have been established, and Azerbaijan has developed
a credit track record, Azerbaijan may not be able to borrow the funds required for development of the
first generation of fields on reas  nable terms. It may be therefore be more appropriate for Azerbaijan
to aim to fund a share of the second generation fields after 2000.
Encouraging Foreign Petroleum Investment
xxvii. While Azerbaijan's resource base presents attractive potential exploration and production
opportunities for international petroleum companies, it is important that an appropriate business
environment Is created to encourage actual investment. To date, Azerbaijan has been successful in
building on the interest shown by many foreign companies in the country, although achievement of final
agreements and investment has been slow. In order to speed up foreign investment on the most suitable
terms, a number of initiatives need to be pursued. Creation of an appropriate legal and contacal
fraiework, development of a Petroleum Law and standard contracts, and resolution of related legal and
fiscal Issues is a major priority. It is also important that suitable advisors, with the capacity and
experience to advise Azerbaijan on all commercial, financial and legal aspects of petroleum negotiation
be recruited from the start. Strengthening of local capacity, through training and assignment of the most
capable staff to this area is vital. The organization of negotiations is key to making rapid progress:
procedures and documentation of negotiations should be clarified and public and confidential
communications well organized. In addition, the number of negotiations being undertaken should be
limited to what can be handled by SOCAR and the Government effectively; in the case of the offshore
projects, unitization of the fields and negotiations on a single set of agreements with all companies could
gready simplify and speed up agreements. The presentation of data in a manner which is useful and
accessible to foreign companies is likely to increase interest and reduce delays in reaching agreements.
Finally, it must be emphasized that continuity of commercial approach and negotiations is vital:
Azerbaijan has persuaded major petroleum companies to make a considerable commitment to plan
investments in the country, and fundamental changes of course or of companies at this stage carries the
risk of delaying these investments considerably. Such changes will also reduce the confidence of future
investors in the stability of commercial agreements reached with Azerbaijan.
Restructuring Existing Oil Infrastructure
xxviii. While dealing with its large undeveloped fields, Azerbaijan must also focus on restructuring
production in the mature fields onshore and offshore. The remaining reserve base in the older fields, at
around 300 mt, represents a large resource base which should be accessed efficiently. This will require
the shutting-in of a large number of uneconomic wells, and abandonment of non-viable infrastructure (for
example in the Oil Rocks field). New investment should focus on the most productive areas. Investment
in improved production should be a priority to moderate the production decline until the new offshore
fields are brought on stream. Initial investment could utilize resources from multilateral financing
agencies, while carrying out a thorough survey of field restructuring requirements. Once a structured



-xii-
contract and technical framework is in place, the fields should be put out to tender for joint ventures with
private companies. A reduction in employment in the oil fields (currently 40,000), will also be required,
and should be effected through retraining and within the process of social protection during the economic
transition. Investment to reduce environmental contamination in the oil fields should be integrated into
a restructuring strategy.
xxix. In restructuring its oil industry, Azerbaijan will also have to address the problems of its
refineries. In the medium term, it is highly unlikely that large scale imports of crude oil for export
processing would be economic. In the longer term, Azerbaijan will almost certainly be better off
exporting crude oil to world markets (via an export pipeline), than processing its crude oil and exporting
products. Domestic requirements, as well as modest regional export needs, should probably continue to
be met from local refineries. Refinery capacity should be restructured on the basis of an optimization
study, which will probably show that a substantial part of the older capacity should be closed down, and
the remaining capacity upgraded.
The Petroleum Equipment Industry
xxx.  In order to prevent a decline of the petroleum equipment industry, and capture emerging
opportunities within the FSU, Azerbaijan must move rapidly to elaborate a comprehensive development
suateg for the industry. Joint ventures with foreign companies and participation of private capital should
be a key part of this strategy, to provide Azneftekhimmash with needed capital, technology and
management expertise. To maintain viability Azneftekhimmash needs to focus on its core markets in the
FSU, where other suppliers are maling inroads and production is commencing from new local factories
(especially former defence suppliers). Access to large contracts, some of which will be financed by
multilateral organizations (World Bank, EBRD) will be important. Products should be upgraded to
American Petroleum Institute (API) standards so as to be able to compete internationally. Improved
marketing, and development of maintenance and service centers are also vital. Azneftekhimmash should
be able to supply a greater share of the local Azerbaijan market by targeting its specific product
requirements, and manufacturing new products for the offshore developments. Finally, cautious moves
should be made to strengthen Aznefthia's position in certain countries in the world market,
particularly where Soviet products already have some track record.
The Importance of Natural Gas
xxxi. A focus on the efficient development and use of natural gas resources is vital if the domestic
energy sector in Azerbaijan is to contribute positively towards economic recovery. Future associated gas
production from the new oil fields may only just offset the rapid decline in production from existing large
gas fields. Hence Azerbaijan could continue to require substantial gas imports beyond the year 2000, at
a cost of around $600 million per year, or some 20 percent of the value of oil exports.
xxxii. An emphasis on economy of gas utilization will thus be the key to containing import costs. A
first step in this direction is the implementation of the project to reduce venting of associated natural gas
offshore, which could save Azerbaijan around $100 million per year at international gas prices (about 4
percent of total imports). This project has been started by a foreign petroleum company, and is likely
to be integrated with the Guneshli field re-development.
xxxiii. The second priority is to reduce the large losses of gas through the transmission and distribution
pipelines, which cost Azerbaijan up to $170 million per year at international prices. This will require



-xiii-
major investments in rebabilitation and reconstruction of pipelines, and general improvement to pipeline
and storage networks. Gas processing will also require major investments, since at present only 50
percent of the domestically produced gas entering the system is processed to extract liquids and water,
causing a loss of valuable liquid petroleum gasses and aggravated pipeline corrosion.
xxxiv. The third priority is to improve the end-use efficiency of gas, through installation of meters and
provision of more efficient gas using equipment. Local manufacture of meters and appliances, using
Azerbaijan's considerable light engineering resources combined with private investment, should be a
priority, provided of course that the output can be sold at competitive prices.
xxxv. A further priority is to ensure effective development of Azerbaijan's gas resources. It may be
possible to develop existing fields more effectively, as well as to develop some modest undeveloped free-
gas fields. The large new offshore fields contain both associated and non-associated gas and it will be
important to integrate gas properly into the field development agreements to ensure its full and efficient
exploitation by the foreign oil companies.
Electricity
xxxvi. The power sector is closely integrated with the gas using infrastructure, since gas capacity
accounts for almost 90 percent of total generation capacity (although at present fuel oil is being used).
Because power demand has Ibeen depressed by around 15 percent over the past two years by the economic
decline, new generating capa-ity is unlikely to be needed before the late 1990s. However, improvements
in the gas using efficiency of existing steam plants should be explored, as should rehabilitation of the
transmission and distribution infrastructure and improvements in the efficiency of end-use. There is also
a need to improve maintenance practices, which are currently poor. A proper customer management and
billing system needs to be introduced to reduce non-technical lQsses. In the longer term, combined cycle
power plants using natural gas are likely to prove the most economical option for large scale power
generanion in Azerbaijan. There is also considerable potential for small scale hydro and wind power
applications. The forward investment program for the power sector should be developed on the basis of
a least-cost planning study. The district heating sub-sector should also be the subject of a rehabilitation
study, to assess its future investment needs and viability.
Environmental Issues
xxxvii. The major environmental problems in the energy sector in Azerbaijan result from pollution
associated with oil production. This is particularly the case in the onshore oil fields, which are mostly
located in heavily populated areas. Onshore oil pollution results from oil spills, inappropriate disposal
of formation water and drilling wastes, and il-conceived production pit construction. This has caused
serious contamination of groundwater resources, which presents a danger to the health of the population.
Improved production practices are urgently needed to reduce pollution. In addition, repair and
replacement of faulty and corroded equipment will help to reduce leakage of oil and other pollutants.
Remediatdon of polluted areas wiUl require considerable investment, and it is recommended that this be
undertaken in 'onjunction with foreign investors where possib'e. Improvements in the environmental
conditions of the onshore fields should be linked to the wider studies of the restrucuring of production
along economic lines.
xxxviii. In offshore areas, better controls should be established on the disposal of produced water
contining toxic metals and oil. Offshore field rehabilitation should emphasize the reduction of oil leaks,



-xiv-
and there should be better control of the disposal of general waste from offshore production sites.
Regional initiatives to establish an oil spill response center for the Caspian Sea should be explored. Some
of the pollution in the sea around Baku could also be due to poor waste management by sea-going vessels,
which should be assessed and controlled.  The venting of large quantities of gas offshore is
environmentally as well as economically damaging, particularly as methane is a powerful greenhouse gas.
xxxix. Environmental standards at the oil refineries in Baku are also relatively poor. Inadequate
treatment and inappropriate disposal of effluent waters results in sea and land pollution. There is also
considerable seepage of hydrocarbons around the refinery sites. There is no monitoring of aerial
pollution, which is probably excessive. Improvement of the environmental standards at the refineries,
and remediation of polluted areas, should be an important part of the recommended refinery restructuring
study.
xl.   In the power sub-sector, the major environmental problems arise from the burning of fuel oil in
place of natural gas, without adequate environmental controls at the power stations. Improved access to
natural gas supplies would greatly reduce the environmental impact of power generation. Greater use
of renewable resources (particularly small scale hydro and wind power) will also help to lessen the
environmental impact of the power sub-sector.
xli.   Proper enforcement of Azerbaijan's existing environmental standards would in many cases greatly
reduce the problems described above. Unfortunately, enforcement is hampered by a lack of resources
within the Government departments concerned. Moreover, fines are often very low, and are not always
enforced. A strengthening of institutions dealing with environmental problems in the energy sector (in
conjunction with the wider aspects of environmental regulation) is strongly recommended.
Energy Pricing Reform
xlii.   Azerbaijan's energy pricing policy has been slow and uncoordinated in making the transition from
the extreme distortion of the Soviet system to an economic basis. Pricing changes, as in most other FSU
countries, have been ad-hoc responses to external or internal developmenu, and have not exhibited a
structured move towards economic levels.
xliii. Azerbaijan possesses a greater capacity than many other republics to control the rate of transition
of internal oil prices to world market levels. As a net oil exporter, Azerbaijan does not have to atake'
price changes in other republics (e.g. Russia) into its internal market. In addition, control of oil
production, processing and trade in Azerbaijan is highly centralized and flows are relatively easy to
monitor, hence there are fewer of the informal market problems that are present in other FSU countries.
xliv. Moves to world price levels can thus be established in a structured manner, with the internal price
of crude and oil products progressing to world parities over a suitable time-frame. It is important that
this time *ame is sufficiently short to play a positive role in economic restructring through sending more
meaningful price signals to producers and consumers. As prices rise towards world-levels, the
Government will need to regulate SOCAR's profits through petroleum taxation. IThis will, in urn
provide revenue to the Government which can be used to mitigate the adverse social effects of energy
price rises.
xlv. For natural gas, Azerbaijan is essentially a price "taker" from Turkmenistan. Attempts to offset
the rise in the price of Turkmenistan's gas with low prices for domestic gas are self defeating, since they



-xv-
reduce the incentives to produce more gas domestically and to use gas efficiently. Producer prices for
natural gas should be raised to an economic level, which will in general. be set by the cost of
Turkmenistan imports. Prices to gas consumers should be set by adding to the producer price the
appropriate transmission and distribution tariffs, whXch should be set by an independent regulator.
xlvi.  The gas price will form a key input into the electricity price, which in addition has to allow for
the long run marginal cost of system capacity. The electricity price will be set in the same way as the
gas price, through addition of transmission and distribution tariffs to the generators' price.
xlvii. An important aspect of price reform is the need for internal price transparency within the
integrated energy enterprises. Thus within SOCAR, the production unit should sell to the refineries at
a crude price which approaches the world level over time. Within Azerigaz, the cost of gas purchases,
transmission, distribution and storage should be separately identified to the business units and to
customers. In power generation, sales by generators, transmission and distribution charges should be
similarly itemized. This will help to ensure that the commercial performance and viability of each unit
within the .companies is properly established.
xlviii. Price reform must take place within the context of macroeconomic restructuring. Energy prices
should be targeted to reach world or economic levels within a relatively short period (for examrle, one
year), and should be coordinated with a program of economic and monetary reform. Such a program
should also help to stabilize the exchange rate for the national currency at an equilibrium level, which
will assist in setting realistic energy price objectives. In order to ensure that the full economic costs of
pricing policies are made clear, any subsidies to energy prices, which may be required during a
transitional period, should be explicitly identified in the Government's budget.
Institutional Reform
xlix.  Institutional reform in the energy sector should focus on three areas:  strengthening the
Government's coordinating and policy-making role, creation of a suitable legal framework, and enterprise
restructuring and reform.
1.     The government's role in the energy sector in Azerbaijan is unusual in that there is no energy
ministry or similar body with a unique and overriding policy role. This can result in a lack of
coordination and forward vision in energy sector planning. Oversight of the activities of the large energy
enterprises is also weak. It is therefore important that an Energy Ministry (or similar body) be
established, to: set overall energy sector priorities, advise the government on energy issues, establish
energy pricing and taxation policy, act as an umbrella body for energy regulators, coordinate information
and standards in the sector and represent the country internationally. Such a body could be quite small,
but should be sufficiently well-staffed to provide leadership on critical issues.
Hi.    Implementation of energy sector legislation is needed to ensure that investment takes place within
a structured framework. Regulatory structures for electricity, natural gas and district heating need to be
developed, within a legal structure, that define the rights and responsibilities of the energy utilities, as
well as of consumers. Regulation is also needed for petroleum licensing, which should also be carried
out separately from SOCAR. More broadly, a petroleum law is required which would set out dte
framework for investment in exploration and production.



-xvi-
lii.    Azerbaijan has chosen to establish integrated national companies for oil, gas and electricity.
Enterprise restructuring and strengthening should thus focus on internal structures that ensure commercial
transparency. Such structures will help to prevent internal inefficiencies and cross subsidization. This
will require a system of internal charges and financial controls related to the real costs of supplying goods
and services, and to rates established in competition with eternal agents. Such internal segmentation of
activities is essential as an alternative to splitting up the integrated companies into different units. In
general, the segmentation of existing companies may be less disruptive than splitting up recently formed
entities. Ancillary units of the enterprises which are not part of the core business (eg. construction,
housing, transport etc.) should be spun-off or privatized. A general strengthening of capacity will also
be needed through large scale training programs, and the installation of modern financial and management
systems.
Role of Technical Assistance
liii.   As stated above, Azerbaijan has a number of natural advantages, which should allow it nake a
transition to an efficient, market-based energy system more easily than many other FSU countries.
However, the Government and the energy sector enterprises will require substantial technical assistance
to make the transition rapidly, and without costly mistakes. This technical assistance should be seen as
a short or medium term transitional aid, to ensure that the sector evolves a modern and efficient structure,
which is able to sustain its own skill base.
liv.   Technical assistance should focus on three main areas:
*  Advice to enterprises and the government on negotiations with foreign companies on petroleum
and other energy related contracts,
*  Investment planning in the petroleum, natural gas and power sub-sectors, to identify priority
investments and put in place long-term investment and financing plans,
3  Institutional strengthening through training and financial and management systems development.
lv.    Such technical assistance should focus on all energy enterprises. Because of the relative cohesion
of the Azerbaijani energy sector, it would be best if the technical assistance was handled in a coordinated
manner by the Government. This would ensure consistency between enterprises, efficient allocation of
resources across the enterprises and effective liaison with international providers of funding and technical
assistance services. The funding of technical assistance on the scale required may need to involve
borrowing, since sufficient grant funds may not be forthcoming. This is particularly the case for the
petroleum sub-sector, where rapid mobilization of advisors for negotiations, together with staff training
and investment studies, are needed to implement large-scale foreign investment. Borrowing for such
technical assistance can be justified since rapid execution of appropriate energy investments will lead to
large foreign exchange benefits. For example, up to $250 million per year of gas import savings can be
achieved through improved utilization of domestic gas resources, while accelerating development of the
offshore oil fields by one year will generate additional government revmuus of some $1.0 bn before the
year 2000. In order to assist in mobilizing the required technical assistance, the World Bank has
discussed an integrated energy technical assistance project with the Government and enterprises in
Azerbaijan.



Energy Policy Matrix
I Policy Action                   Steps Already Taken            Next Steps                    IndicativeTlmInWStatus
1.  Upsream Peroleum
A.  Conclude agreements for        Preliminary unitizatlon         Negotlate final production     By 10 94. Financing for
offshore oil field             agreement. Financial and legal  agreements. Initiate unified   advisors possible from TA funds
developments. Give priority to  advisors engaged. Technical   development plan fot new
preventing decline of Guneshil.  studies with foreign companies.  offshore fleids.
B.  Conclude agreement for oil     Preliminary studies with oil    Devweop commerclal structure.  Commercial structure by 10 94.
export pipeine construction.   company partners completed.    Finalize agreement on route.    Final route by 10 94. Start
Outline agreement with Turkey  Commence detailed engineering.    engineering by 20 94. Financing
signed. Contacts with World    Seek financing. Plan fo early  possible from TA funds.
Bank, EBRD.                    export options (eg. via Russia)
C. Conclude agreements for common   Preliminary studies with oil  Develop commercial structure.   Commercial structure by 10 94.
offshore Infrastructure        company partners completed.    Commence detailed engineering.    Start engineering by 20 94.
(offshore pipeline, terminal,  Joint venture with construction  Seek financing. Study option  Financing for advisors possible
construction yard, marlne      company for platforms.         for local competitive supplies.  from TA funds.
feet, supply base).            Contacts with World Bank, EBRD.
D.  Initiate restructuring of      Initial discussions and        Undertake studles to determine  Studies by 20 94 (using TA
production In the older oil    contracts with foreign         restructuring options - nd     funding). Project by 40 94.
fields (including Oil Rocks)   companies. World Bank field    strategy. Prepare project.
restructuring project discussed.  Initlal promotion to foreign
companies.
E   Measures to Improve            Oil sludge clean up contract   Undertake studies of options    Studies by 20 94 (using TA
environmental situation in oil  wHh foreign company InHitated.  (with D. above). Incorporate  funding). Project by 1Q 95.
fields.                                                       into field investment plans and
Insttutlonal reform.
F.  Ucensing of ofshore and        initial agreement wih BP .o    Undertake study of licensing    Studies and Initial packages by
onshore areas for exploration.  explore Shach Deniz ructure.  and exploration strategy.      20 94 (using TA funding).
Discussions with foreigvn      Develop license plan and data
companies on exploration.      packages, initiate lIensing.



Policy Action                   Steps Aready Taken               Nedt Steps                      Indicative TminglStatus
I1  Peroreum Equipment
A.  Develop short term marketing to  Advisors engaged with WB        Assess bidding strategies for   Initial bidding in 3Q & 40
gain share of Russian purchases  funding, promotional visit to   projects. Engage foreign        93. Use TA funding
incl. under WB Loans).          US.                              partners. Bid on contracts.     for lollow on work.
B.  Develop business strategy to     Advisors engaged with WB        Recruit advisors to develop      By 2Q 94, using TA funding.
Improve marketing, rationalize  funding, promotional visit to    business plan. Find partners
production, target local market.  US.                            and agree joint ventures.
III. Oil Refining and Marketing
A   Improve refinery efficiency and  Investment contracts with       Undertake studies to assess      Studies by 2Q 94 (using EC
economics through restructuring  foreign companies (economic    least cost options. Initiate     Technical Assistance and other
and selective investment.       basis not clear).                discussions with potential      sources).
investors. Plan for likely                                           x
reduction in capacity.
B.  Improve refinery environmental                                   Formulate and enact              New standards by 20 94 (using
standards.                                                      environmental standards in line  EC Technical Assistance and
with OECD. Improve enforcement.   other sources).
IV. Natural Gas
A.  Capture gas vented offshore.     Project initiated with Pennzoil.  Complete Pennzoil project,    By 30 94.
integrate with unitized
offshore ollfield investments.
B.  Reconstruct transmission and    World Bank project proposed.     Initiate PHRD project           PHRD study by 30 94. World
distribution system to reduce   Initial Azerigaz studies done.   preparation study. Initiate     Bank project proposed ior 1995
losses.                         Japanese PHRD grant available   World Bank project.              or 1996.
for project preparation.
C.  Install gas meters for large    Initial discussions with         Scudy with;n PHRD project       PHRD study by 30 94.
consumers.                      potential meter manufacturers    preparation. Initiate
held.                           prioritized meter Installation.



PolicyActionL  Steps Already Taken                             Ned Steps                       IndKicativefTimlnglStahts
D.  Improve gas end-use efficiency                                 Study within PHRD project       PHRiD study by 30 94.
through replacement of                                         preparation. Initiate pilot
ineficient appliances.                                         program.
E   Improve gas processing through  Initial discussions with       Study options for constructing  Studies by 20 94 (using TA
plant reconstruction, gas      potential foreign partner for   new gas processing plant.      funding). Start investment in
gathering.                     minor upgrading of gas plant.   Initiate investment, with       1995.
foreign partners if possible.
F.  Increase domestic gas           Terms for natural gas          Agres terms for gas (price,     Agree terms by 10 94.
production capacity through    development being discussed     contracts) with foreign
rehabilitation and development  with foreign oil companies.    companies. Study restructuring
of gas fields and associated                                   of existing gas fields,
gas.                                                           development of new fields.
Initiate foreign Investment.
G.  Regularize price and volumes of  Negotiations and temporary    Conclude negotiations for       By 10 94. Possible TA funding
gas imports from Turkmenistan  agreements with Turkmenistan    adequate volumes on favourable    for Gas Development Strategy.
and Iran in line with domestic  and Iran.                     terms relative to fuel oil
needs.                                                         exports. Initiate Gas                                               X
Development Strategy.
H.  Positlon Azerbaijan to benefit  Preliminary gas transit        Continue contacts with Iran and  Ongoing (long term objective).
from future gas transit trade.  agreement reached with Iran and  Ukraine. Initiate cooperation  Possible TA funding for Gas
Ukraine.                       with Turkmenistan and Turkey.   Development Strategy.
Initiate Gas Development
Strategy.
1.  improve LPG availability to     Program to substitute LPG for  Study within PHRD project       PHRD study by 30 94. Possible
rural areas (possibly in place  gas In rural areas initiated.  preparation and gas plant      TA funding for study.
of natural gas).                                               Investment options.



Palicy Action                     Steps Already Taken          |NMt Steps                         Indicte Tminml us
V.  Beticity
A.  Improve efficlency of existing  Grant Technical Assistance via  Initiate further proJect        Conclude studies by 20 94.
power plants.                   EBRD for efficiency study       preparation. Substitute natural  Project In 1995.
undeay.                         gas for fuel oil in power.
B.  Improve efficiency of           Grant Technical Assistance via  Initiate further efficiency     Conclude studies by 20 94.
transmission and distribution   EBRD for efficiency study      Improvement studies and project  Project in 1995.
system.                         underway.                       preparation.
C.  Improve efficiency of                                           Initlate efficiency improvement  Conclude study by 20 94. Grant
electricity end-use.                                            study. Initiate pilot program.  technical assistance available
_________________________                                      from   EC.
D.  Replace obsolete power stations  Discussions held with potential  Initiate power least cost     Least Cost study by 30 94,
with gas combined cycle.        plant suppliers.               investment plan to assess        using TA funding.
timing. Continue contacts with
potential investors and
suppliers.
E.  Assess potential for increased  Azenergo Initial studies done.  Initiate power least cost       Least Cost study by 30 94,
use of hydro (esp. small hydro)                                 Investment plan to assess costs  using TA funding.
and wind power resources.                                       and options.
F.  Investigate revived regional                                    Continue contacts with Georgia  EC technical assistance
power trade.                                                    to Improve links and with       available by end-93.
Armenia (taking account of
regional conflict).
G. Improve power stations                                           Substitute natural gas for fuel  Least Cost study by 30 94,
environmental performance.                                      oil, undertake plant            using TA funding.
Improvements.



Policy Action                    Steps Already Taken              Next Steps                     I nrdicative liming/Status
VI. District Heating
A.  Improve district heating system                                   Initiate district heating        Study by 3Q 94. using TA
efficiency.                                                      Investment and rehabilitation     funding.
study. Initlate Investment
project.
B.  Assess district heating                                           Initiate district heating        Study by 30 94, using TA
economics against gas                                             investment and rehabilitation    funding.
distribution.                                                     study.
Vi. Energy Sector Institutions
A.  Increase central Government      Formation of part-time Energy    Create small Energy Commission   EC technical assistance
energy policy leadership and    Commission proposed.             or Ministry with energy policy   available by end-93.
coordination.                                                     responslbilitles. Develop                                             x
capacity with foreign advisors.                 _       _               .
B.  Develop Petroleum Law to govern    Work initiated with UK Grant.  Finalize draft law, consult      Parliament to pass by 20 94
SOCAR and foreign oil                                            with ali involved, propose to    (coordinate with offshore oil
investment.                                                      Parliarnent.                     agreements).
C.  Develop Laws for Natural Gas,                                     Initiate drafting of laws.       By 20 94. EC Technical
Electricity and District                                         draft laws and propose to        Assistance available for
Heating utilities, set up                                        Parliament.                      electricity, TA required for
regulatory structures.                                                                            natural gas and district
heating.
D.  Restructure and corporatize      SOCAR reorganization Initiated.  Prepare plan for second level    By 20 94. EC Technical
SOCAR as a commercial state                                      SOCAR organi ation, implement    Assistance available for
company. Privatize retail                                        plan. Plan for retail            advisors.
stations.                                                        privatization.



Policy Action                   Steps Aeady Taken               Net Steps                       IndicatieTinintaLus
E   Improve SOCAR financial and     Some assistance obtained from   Prepare plan for Improved       By 20 94 using possible TA
Information systems.            foreiGn oil companies.         financial systems and            funding.
information management.
Initlate Implementatlon.
F.  Undertake training for SOCAR    Some assistance obtained from   Prepare training plan and       By 20 94 using possible TA
staff In commercial areas.      foreign oil companies.          initiate in-house program.      funding.
Continue cooperation with
foreign companies.
G.  Improve Azerigaz organization,  Azerigaz reorganization         Prepare training plan and       By 20 94 using possible TA
train staff.                    continuing.                     initiate reorganization.        funding. Possibly include in
World Bank project in 1995196.
H. Corporatize Azenergo and         Some experiments with           Prepare institutional           By 20 94. EC Technical
Improve organization.           worker-ownership.               restructuring plan. Initiate    Assistance available for
corporatization.                advisors.
x
1.  Improve financial management                                    Prepare plans for improved      By 30 94. Use TA funding             x
and information systems.                                        systems. Initiate investment    Possibly include in future WB
and training.                   and EBRD energy sector projects.
Vill. Energy Pricing
A.  Develop and implement energy    Initial energy price            Assess economic and world price    Study by 20 94 using TA
price adjustment framework.     adjustments made (but not       targets for energy prices.     funding. Adjustment possibly
within comprehensive framework).   Formulate adjustment plan.   within one year of start of
Initiate coordinated adjustment.  economic stabilization plan.
B.  Develop petroleum revenue                                       Assess SOCAR's financial        Study by 20 94. using TA
taxation system for SOCAR.                                      position at world prices.      funding.
Develop taxation system.
Implement system.
C.  Design and implement social                                     Calculate impact of energy      Study by 20 94. using TA
protection scheme to cushion                                    prices on consumers. Propose   funding.
_   impact of energy price rises.                                   social safety net scheme.



CHAPTER 1
ENERGY SECTOR DEVELOPMENTS AND OUTL OOK
1.1          The energy sector has played a key role in the development of Azerbaijan's economy.
As one of the largest oil exporters in the first decades of this century, Azerbaijan's initial economic
growth was largely driven by oil. However, oil production has fallen sharply since 1970, and the growth
of other industries since World War II has greatly reduced the relative impormace of this sector.
1.2          Despite its long history of oil production Azerbaijan has large remaining oil resources in
newly discovered fields, and the oil sector is poised again lo dominate the country's future economic
development. The key challenge for Azerbaijan is to develop its resources as rapidly and efficiently as
possible, and to restructure its economy to absorb the resulting financial surplus effectively.
Current Situation
Maoecn nomic Developments and Background'
1.3          Azerbaijan lies on the southeastern flanks of the Caucasus mountains. It is one of the
smallest of the Republics of the Former Soviet Union (FSU), covering an area of 86,000 square
kilometers, similar to that of Austria. Over half of its 7.2 million population is urbanized; the capital,
Baku, has about 2 million inhabitants and is a major harbor on the Caspian Sea. The country is endowed
with fertile agricultural land, and ample natural resources. It also has a diversified Industrial structure
and a relatively well educated labor force.
1.4          Azerbaijan was among the first of the FSU republics to adopt a resolution of sovereignty,
in September 1989. The constitution was amended to legitimize the independence of the Azerbaijani
Republic, in August 1991. Azerbaijan chose not to become a member of the Commonwealth of
Independeat States, preferring instead to maintain its relations with the other FSU republics through
bilateral agreements. Notwithstanding its political independence, Azerbaijan has continued to be an
integral part of the FSU economy, since the deeply entrenched economic interdependence with the other
republics has remained in place.
1.5          As in the other countries of the FSU, 1992 was characterized by a drastic fai in economic
activity, and a large scale increase in prices. These trends folowed moderate output declines in the
previous three years, so that by 1993 Gross Domestic Product (GDP) was only 60 percent of that in
1988. Both consumption and investment were severely hit. Although adverse weather conditions and
the unsettled situation in Nagorno-Karabakh contributed to the output decline, the main factor was the
transformation process that accelerated in late 1991. The collapse of central planning was rapid, while
the emergence of a substitute market-based economic order was slow. Despite the large output drop and
high inflation, the macroeconomic imbalances in Azerbaijan appeared to be lower than in most other FSU
I This sub-secton is based upon the A=64an Counlry Economic Memorandum, May 1993.
-1-



-2-
countries. In 1992, the Government managed to keep the budget deficit under control, at about 4 percent
of GDP. At the same time, the country registered an overall trade surplus, but at lower import and
export levels than in 1991. Although trade with FSU counitries contracted drastically in 1992, Azerbaijan
managed to expand its export markets outside the FSU, primarily for petroleum. As a growing share of
exports was diverted to non-FSU markets, the country may have benefitted from an improvement in the
terms of trade.
Energy in the Economy
1.6          It is difficult to measure the relative contribution of oil, gas and other energy activities
to the economy of Azerbaijan, since Soviet statistics were calculated at highly distorted prices. Thus the
energy sector is estimated to have contributed less than 10 percent of GDP in 1991, whereas the actual
contribution was probably much higher. In terms of employment, the energy enterprises account for
around 120,000 people, or 13 per cent of industrial employment. In terms of investment, the energy
sector accounted for 25 percent of all investment in the economy in 1991, of which about 22 percent was
attributable to oil and gas production.
1.7          A better measure of the remaining importance of oil to Azerbaijan's economy can be
gained from the trade data, which are estimated at 'foreign trade' prices as well as domestic prices. At
foreign trade prices, oil accounted for 39 percent of total exports in 1990 (compared with 12 percent at
domestic prices), and for 26 percent of imports (8 percent at domestic prices). Significantdy, the oil and
gas trade surplus at foreign prices in 1990 was 605 million Rubles, which almost offset a deficit of 740
million Rubles on industrial products, raw materials and food. Thus the economy continues to depend
upon its net oil exports to a significant extent.
Bnrg  Balance
1.8          The structure of Azerbaijan's energy balance is relatively straightforward in comparison
with that of many other FSU Countries. Oil and gas account for about 99 percent of primary energy use,
with hydropower supplying the r0mainder. The large coal, nuclear and hydro power supplies which
gready complicate the energy situation in other FSU countries are absent in Azerbaijan. Given the
abundance of petroleum, there was no need to develop or import these other fuels. Even in sectoral
tems, the structure of fuel consumption is relatively simple, with most non-transport energy supplied
from natural gas or fuel oil. Power stations are largely designed to use gas, but have dual fueled boilers
and therefore can use fuel oil as well. In 1990, natural gas accounted for 64 percent of power and district
heating fuel use. Industrial boilers are nearly all designed to use natural gas, which made up 89 percent
of industrial primary fuel supplies in 1990. Households rely on natual gas for a significant proportion
of their energy requirements, although district heating also plays an important role in certain regions.



-3-
Figure 1.1 Primary Ener jy Consumption, 1991
(millon tons of oll equivalent)
Totab 26.87
Natural Gas 
16.04
Oil
8.8e
Hydro-electrIcity
0.14
1%
Source: Mislion estimates.
1.9            The economy of Azerbaijan is highly energy intensive, even by the standards of the
Former Soviet Union. In 1990 its energy intensity was the third highest of the FSU Republics (excluding
the Baltic states), in terms of fuel use per unit of GDP. This is probably due to the concentration of
inefficient fuel production and processing in the country, as well as the large amount of medum and
heavy industry. In terms of fuel use per capita, Azerbaijan stands in the middle of the range of use
within the FSU.
Figure 1.2 Energy Intensity of Eoonomy 1990
(thouand ton stnard fuel pwr milon rubies)
, ......   F.|..................  .............  .........
. ............   ... ...I.......... -11 .......I
S~~
4. .. .... .... .. ........ ...... ........ .... ......
2-.  ^   . .......   ................. ..
AZE ARM  1L KI  KYR MSL SWE  VW  TMi  UKR U
Sowrce: Mssion estates.



-4-
1.10          International comparisons show that Azerbaijan's energy consumption in per capita terms
is within the range seen in most central and southern wPst European countries. In the Northern counties
of Scandinavia, consumption is higher due to the co' vr weather. Consumption in Azerbaijan is below
that in such extremely inefficient East European countr es as Bulgaria and Czechoslovakia. Comparisons
taking account of international GDP relativities are inevitably less reliable, since it is extremely difficult
to measure GDP in the FSU countries on a comparable basis. However, using World Bank estmes of
GDP shows that energy consumption in Azerbaijan is probably extremely high per unit of output, in
comparison with other industrialized countries. Improving energy efficiency, through implementation
of economic pricing and replacement of wasteful en;rgy transporting and processing infrastructure is
clearly a priority.
Tabk 1.1: Ewxj Intensy - Inenatnal Comparions 1991192
1                 2                 3
GDP/Cap         Energy/GDP         Energy/Cap
Azerbaian                     870               3770              3356
Poalnd                       1690               2021              3416
Turkey                       1630                525               857
Bulgara                      2250               2198              4945
Czechodovakia                3140               1618              5081
Yugoslavia                   3060                787              2409
Portugal                     4900                308              1507
Spain                       11020                200              2201
Itly                        16830                164              27S4
France                      19490                197              3845
GbMnany                     22320                156              3491
Sweden                      26524                239              6347
Finland                     27540                206              5650
Source: MLuion eshnawes.
1. USS GDP per capka.
2. Kg oil equivalet per US$Th GDP.
3. Kg oil equivalnt per capita.
1.11          Despite its net oil exports, Azerbaijan was only 88 percent self sufficient in energy overall
in 1990. Azerbaijan's energy self sufficiency deteriorated markedly during the 1980's. Combined output
of oil and natural gas fell by 22 percent, while energy consumption rose by 19 percent. The deficit in
energy in 1990 compares with a large surplus (self sufficiency of 133 percent) in 1980, and a rough
balance in 1985.



-5-
Tabe 1.2: Azerba  Energ Balance
(rh. tons sadard fiA eqduvaksa)
1980          1985          1990
Total Supply                   49665         56107         52462
Oil & Gas Production          37571         35209         29310
Hydro Production               358            427           539
Impots                        11589         20471         22613
Other                           147           NA            NA
Domestic Consumption           28456         33797          33858
Conversion                    9926          11543         10540
Direct Use*                   18530         22254         23318
Exports                        20887         22926          18276
Stock Change                     322          -616           328
Self Sufficienoy %            133.3%        105.4%         88.2%
*Note: Incldes losses and sWastical discrepaw.es
Source: Gokomstat
1.12          The most marked manifestation of Azerbaijan's energy deficit has been the large growth
of natural gas imports. In 1980, Azerbaijan was a net exporter of natural gas. By 1991, natural gas
imports accounted for about 29 percent of total energy requirements. This shift in the pattern of
Azerbaijan's fuel supplies was dictated by the logic of supply within the FSU, where resources from
surplus producing republics were transported long distances to consuming areas. The emphasis was on
the development of large scale supply and transport systems, rather than on efficiency in end use and
development of smaller scale local supplies. In the case of Azerbaijan, gas use was allowed to become
extremely wasteful, while a large number of modest but important local resources of gas and other energy
sources (mainly hydro) were left undeveloped. The true cost of this policy to Azerbaijan and the other
Republics was masked by the extremely low price of gas. Redressing this imbalance in its energy
development is one of the key problems confronting Azerbaijan in the coming years.
1.13          The last two years have seen significant changes in the structure of Azerbaijan's energy
balance, as a result of the economic decline and changing trade relations within the FSU. The economic
contracion has led to an estimated fall of about 18 percent in the combined consumption of oil and
natural gas, due to a fall in fuel use for power, industry and transport. This large fall in consumption
did not lead to a return to energy self-sufficiency in 1992, due to a fall in production of oil and gas of
around 15 percent. At the same time, there has been a significant shift in fuel use from gas to oil, since
difficulties in meeting gas import targets have led to a large scale substitution of fuel oil for natural gas
in power generation. The share of gas in total primary energy demand fell from about 67 percent in 1990
to 55 percent in 1992 (see table 1.4).
Energy Trade
1.14          The pattern of Azerbaijan's energy trade reflects its strong links with the other FSU
countries, as well as its geographical position on the Caspian Sea, but without a seaport with access to
world markets. The lack of access to a seaport limited Azerbaijan's ability to export crude oil to world
markets, in the absence of a long export pipeline. Azerbaijan's oil exports thus took the form of oil



-6-
products, mostly traded within the Caspian and Caucasus region (including Northern Iran).
1.15         Another feature of Azerbaijan's energy trade has been the republic's importance as a
transit point and processing center. In the case of oil, Azerbaijan's refining capacity, which became
surplus to domestic requirements as oil production fell, served to process imported crude oil from Russia
and Kazakhstan (brought respectively by pipeline and Caspian tankers), with the oil products exported.
In the case of natural gas, Azerbai3an served as the main transit route for gas from Russia and
Turkmenistan to Georgia and Armenia. Azerbaijan was also an important part of the integrated Caucasus
electricity grid.
1.16         These trading links have been breaking down over the last two years. The imports of oil
from Russia and Kazakhstan virtually ceased by late 1992, as the poor economics of this trade at
Intemational prices has become apparent. In the case of natural gas, much of the drastic decline in transit
trade has been due to the regional conflict with Armenia. Imports of gas to Azerbaijan, however, have
also declined due to disagreements with Turkmenistan over pricing and payments, and difficulty in
arranging reliable transit through Russia. Regional electricity trade has also collapsed as a result of the
regional conflict and difficulties over payment.
1.17         As it moves towards economic independence from the links established within the FSU,
Azerbaijan will have to orient its energy trade according to market forces. This is likely to mean an
increased orientation towards the world market, particularly for oil, since Azerbaijan will have to compete
with Russia and other suppliers within the FSU. Statistics for 1992 show that an increased proportion
of oil exports went outside the FSU, probably because of the higher prices which could be obtained in
those markets.
Table 1.3: Abzen BaeWD Trade (h. tens)
1991
1 992
Total     Total   Non-CIS        Tot=l  Total    Non-as
cud Oil                  4301         0         0         1355      1056        1056
Gasonem                    0         66         0            0       168          32
Dioud                      1       2279       1232           0      2742        2058
Jet Romine                  1       747         0           12        187         57
Fuel Oil                   0       2304       442            0       352         260
Diod lLubes                4        338         0            2       S62         263
Other Oil Prod.           10         11         0            4       144          51
NAL Gas (MMCM)          14170      5996         0         5263       951           0
LPG                       99          0         0           1S         0           0
EIeor.U.TKHWH              0          2         0            0       495           0
Cod                      101          0         0           11         0           0
Jt4Ags  all fim CIS republics.
Sotawre: Mission escnas.



-7-
Energy Trade Outlook
1.18          Dtspite its recent problems, Azerbaijan's long term energy outlook is bright, providing
suitable policies are put in. place. The key to improving the situation of the energy sector will be to
combine the development the new offshore oil fields with suitable restructuring of the domestic energy
industry (both the physical infrastructure and the institutional framework).
1.19          Through attracting large investments from international companies to develop its offshore
fields, Azerbaijan will be able to increase its oil production, as well as eventually stemming the rapid
decline in gas production. Table 1.4 shows the long term supply-demand outlook for energy in
Azerbaijan. The energy consumption projections are based upon an economic outlook in which GDP
continues to decline slightly until 1995, before rebounding to show fairly strong growth (up to 10 percent
per annum) in the late 1990s. Much of this growth will be driven by the expected upsurge in oil
investment and production. As the table shows, however, total energy demand is expected to be roughly
stable to 2000, and to rise only modestly thereafter, since energy prices are assumed to rise steadily to
economic levels over the next few years, while the economy should evolve towards a less energy
intensive industrial structure. The higher prices should encourage conservation, with efficiency of use
also improving through a reduction in transmission and distribution losses following system
reconstruction. It is likely that a marked reduction in energy intensity in industry will occur through
rationalization of such heavy energy-using industries as metallurgy and chemicals. Overall, the
energy/GDP ratio should decline by about 30 percent between 1992 and 2000, under a Base Case
scenario. It can be seen that while Azerbaijan is expected to continue to show a net deficit in energy
trade in volume terms until the mid-1990s, by 2000 this will have turned into a large surplus due to the
rise in oil production and exports. In a Base Case scenario, total net oil exports could rise from about
$173 million in 1992, to $610 million in 1995 and reach $5.3 billion in 2005. The rapid growth in oil
exports under the Base Case scenario will allow Azerbaijan to meet its external financing requirements
through foreign private investment and borowing from multi-lateral institutions.
Table 1.4: Enesr Sappy - Demand Outloolc Base Case
(mon tons oll equivaent)
1990          1992          1995          2000           2005
Production*               21.5           18.2          16.2           30.9          52.4
Oil                     12.5           11.1           9.7          25.6           45.2
Natural Gas              8.9           7.1            6.5           5.3            7.3
IMports                    16.3           6.1           8.2           9.4            8.3
Oil                      4.5           1.4            1.0           0.0           0.0
Naural Gas              11.8           4.7            7.2           9.4            8.3
Expoits                    13.8           4.9           5.7          20.8           39.7
Oil                      9.0           4.0            5.7          20.8          39.7
Natual Gas               4.9           1.0            0.0           0.0           0.0
Domestic Use*             23.9           19.7          18.7          19.5           21.0
Oil                      8.1           8.8            5.0           4.8           5.5
Narl Gas                15.9          10.8           13.7          14.7          15.5
*Notc: Includes 0.14 million tons oil equivalent hydro per year. Gas excludes venting.
Source: Mission estmates.



-8-
1.20          Azerbaijan will, however, remain a gas importer unless large new gas fields are
discovered and developed rapidly. The cost of gas imports is expected to rise rapidly, to about $560
million in 1995 and some $730 million in 2000, as Turkmenistan raises its prices towards world levels.
In the medium term this rise in gas import costs would probably limit any increase in Azerbaijan's trade
surplus in energy, although in the longer term the rise in oil exports will be the dominant factor.
1.21          Any delay in the development of the new offshore fields will have serious adverse
consequences for Azerbaijan's energy trade in the medium term. Thus, if the field developments are
delayed two years from the Base Case (the 'Delay"case), the energy trade balance in 1996 moves from
a surplus of $130 million to a deficit of $170 million. This is due to sharply lower oil exports and higher
gas imports as gas production and recovery decline sharply. Even such a modest delay in the
development of oil production will cause great difficulties for Azerbaijan in meeting its external financing
needs for imports and investments. Debt would grow much more rapidly than under the Base case, and
the inability to finance all required imports would reduce economic growth. A further delay in the
development of the new fields to beyond 2000 (a "Status-Quo Case") will result in a continued worsening
of the trade deficit in energy to US$550 million in 2000.2 Moreover, Azerbaijan would not benefit from
the inflow of US$ 4 to 6 billion of oil related foreign investment. In this case the external financing
requirements to maintain economic stability are likely to be wholly unsustainable, and a severe economic
decline would be precipitated.
1.22          As a net oil exporter, Azerbaijan's trade surplus in energy would also suffer from lower
oil prices. In the medium term, however, the lower revenues from oil exports could be pardy offset by
reduced gas import costs. This would be the case if gas import prices are linked to oil prices (as is the
case m the European gas trade). Thus, at an oil price 15 percent below the Base ($17/barrel versus
$20/barrel) the energy trade surplus in 1995 falls only slightly, from $89 million to $72 million, despite
a fall in oil export value of $120 million. In the longer term, the energy trade surplus would fall roughly
in proportion to the fall in oil prices. Such a scenario, while reducing Government revenues significantly,
would not fundamentally alter the positive economic oudook arising from prompt development of the
oilfields.
Figure 1.3 Projected Energy Trade Balance
CASES
-  Base  -4- L*ow  -lE*- Delay  -C- Low Oil Price  -*- Status -uo
Pro4uc-on
USS B3illion
4  _-*-*------------.................................................
1993    1995    1997    1999       2001    2003    2005
sourc.e: Mission estimates
2This scenario has not been exwended beyond 2000 as it is likely to be unsustainable and the economic consequences are
unclear.



CHAPTER 2
OIL EXPLORATION AND PRODUCTION - CURRENT STATUS
Historical Perspective
2.1          Azerbaijan is one of the oldest oil producing regions in the world, and in order to analyze
its present problems, it is necessary to understand some aspects of its history. Many of the current
problems of the petroleum Industry have their roots in its historical development. Small scale oh
production, through wells dug to access oil near the surface, was first practiced in the Baku region several
centuries ago'. The modern industry, however, sred in the late 19th century, when Azerbaijan rapidly
became one of the major world oil suppliers. By 1905 the Russian empire, due to the growth of
production in Azerbaijan, accounted for 25 percent of world oil production, second only to the United
States. Foreign capital, through such firms as Nobel, Rothschilds and Royal Dutch, accounted for a large
part of the investment at the time.
2.2          This early development was concentrated in a relatively small region on the Apsheron
peninsula around Baku, which owes its modern growth largely to the oil industry. Most of the oil fields
developed in the early phase of the industry remain in production. This long history has left a legacy of
exceptionally old oil fields and infrastructure in Azerbaijan, as well as considerable environmental
damage.
Figure 2.1 Azerbaijan Oil Production
(Total and Percentage of FSU Production)
(million tons)                              Percentage
I -  Azrbaiasn  "*- %of Total   -90
200 . .
*  ~~~~~~~~~~~~~~~-T
-                                  7 \ .... 90
\ -~~~~~~~~~5
1 /1                                                  60016  90 170 18  9O 1N
10/4
830
-20
0*                                                      0
1913   1040   1050   1960   1970   1980   1990   1992
Source: Soviet sutLsUl.
'Even in 1991, 1460 tons of oil was produced from oil-pits.
-9-



-10-
2.3          Azerbaijan remained the main source of supply for the Soviet Union through the Second
World War, and rapid development of the fields around Baku was a key part of the Soviet
industrialization campaign. Production reached 22.2 mt in 1940, before being disrupted by the War.
However, after the War, a larger oil region was discovered in the Volga-Urals area of Russia (centered
on the super-giant Romashinko field), and the focus of the Soviet industry shifted away from Baku. The
massive development the Volga-Urals in the 1950s and 1960s was followed by that of Western Siberia
in the 1970s (centered on the Samotlor field).
2.4          The shift in the focus of the oil industry within the Soviet Union had important
implications for Azerbaijan. While it remained an important center of the petroleum industry, including
in the areas of exploration and production research and equipment manufacturing, Azerbaijan's industry
was probably for a long time deprived of the full investment resources required to maintain output and
exploration. This has led to the particularly poor condition of facilities today. Due to the combination
of the natural decline of mature fields, and the lack of investment, production has fallen rapidly, from
17.2 mt in 1975 to 11. limt in 1992. Azerbaijan's share of total production in the FSU, fell from 3.5
percent in 1975, to 2.3 percent in 19912.
Recent Trenci
2.5          A key factor in the recent history of production of oil in Azerbaijan has been the shift
from onshore to offshore production. The initial oil field developments were all onshore, although
reserves in very shallow offshore areas were exploited from the early part of the century (mostly through
landfill techniques). However, the turning point for Azerbaijan's production came with the development
of the giant Oil Rocks (Neft Dashlari) field in 1949. This was followed by the development of furher
small fields until in 1980 another giant, Guneshli, was brought on stream.
2.6          The development of the large offshore fields helped to arrest the decline in overall output
as the old onshore fields faded. From only 33 percent of production in 1959, offshore production rose
to 82 percent of the total in 1992. However, Azerbaijan's development probably suffered from the fact
that most of its new potential lay offshore. The investments required for exploring and developing oil
offshore are far larger that for most onshore areas, and the technology is more complicated. With the
bulk of the Soviet industry focussed on onshore areas (offshore production accounted for only 1.5 percent
of FSU production in 1985), the few offshore regions such as Azerbaijan on the Caspian and Sakhalin
in the Far East, suffered from inadequate research and development in offshore technology and a lack
of investment. The lags in developing offshore resources and technology within the FSU condition the
requirement for massive infusions of foreign investment and technology today.
2.7          Very large discovered reserves remain undeveloped offshore, due to the limitations of the
FSU industry. Around half of the reserves of the Guneshli field lie in deeper waters (over 200 meters)
and have not been developed. In addition, drilling during the 1980s identified three further very large
fields (Chirag, Azeri and Kapaz). The water depths at which these fields lie (100 m to 300 m) were
beyond the reach of Soviet production technology, although the international oil industry has been
developing such fields in the Gulf of Mexico and the North Sea since the late-1970s.
2The masive shift in the focus of the industry during the first half of this century is demonstated by historical stbtistics
showing that the share of Azetbaijan in total Soviet oil investment fell from 45 percent in 1935 to 9 percent in 1955.



-11-
Figure 2.2 Offshore and Onshore Oil
Production, Selected Years 1940-90
Million tons
25
FEE Onshor  91 Offshore
20- . @       .............. ...................... 1... .....................I.....
0-
1940        1969         1975        1985         1990
Source. SOCAR, Soviet st: stcs.
2.8           As a result of its unusual history, Azerbaijan's upstream oil industry now presents two
very contrasting aspects: On the one hand, the older producing fields onshore and offshore are mostly
in a state of advanced depletion, with old and dilapidated infrastructure. On the other hand, the larg
new offshore fields represent some of the major undeveloped petoleum resources in the world,
susceptible to development through state-ofte-,art offshore technology. This creates a need for a wide
range of policies and decisions within the industry, aimed both at exploiting new reserves efficienty, and
at restructuring production in the mature areas. ln both cases access to foreig  capital and twmlogy
wil be needed, calling for a large scale effort to reach agreements with foreign companies on investment
and joint ventures with widely differing technical and investment characteristics.
Current Reserves and Production
2.9           Despite its long production history, Azerbaijan has considerable remaining petroleum
reserves and exploration potential. Cumulative oil production from Azerbaijan's fields (to end-1992) can
be put at around 1295 Mt, of which 922 Mt has come from the onshore fields, and 373 Mt from offshore.
Remaining reserves re subject to considerable uncertainty, although it is clear that at least as much oil
remains to be recovered economically as has been recovered in the past century. However, this oil will
be considerably more difficult and expensive to produce than that in the easily accessible, shallow onshore
and offthore fields exploited to date.
2.10          All of the oi and gas fields, as well as the sole exploration rights in Azerbaijan belong
to the State Oil Company of the Azerbaijan Republic (SOCAR), which is the sole licensor. SOCAR was



-12-
formed in September 1992 from the two producing associations in Azerbaijan, Kaspormneftegas
(offshore) and Azneft (onshore). SOCAR's precise legal status as licensor awaits clarification through
a petroleum law.
2.11          For the purposes of policy formulation in exploration and production, Azerbaijan's
remaining oil reserves can be classified as follows:
(a)    Mature Fields: Proven reserves          Figure 2.3 CuTulative Ol Production
in fields which have a long             and Rereining Reserves (million tons)
production history can be
assessed with a reasonable degree          Onshore               Olishore
of certainty. Proven reserves are
put at 361 Mt, of which 48
percent lie offshore. As shown
in Figure 2.3, most of originally
recoverable  reserves  in  the
onshore  fields  have  been
produced, although  significant
quantities remain.
(b)    Guneshli:  The Guneshli field  1 2' Ir   ti:Rd      a
has a much shorter production
history than most of the other
producing oil fields. With proven reserves of 155 Mt, the field accounts for 43 percent
of remaining proven reserves. However, substantial proven and probable reserves in
deeper waters, perhaps totalling over 100 Mt, remain undeveloped.
(c)    Newly Discovered Fields: The three newly discovered fields offshore (Chirag, Azeri,
Kapaz) contain reserves estimated at about 500 mt (these are shown as "Probable in
Figure 2.3). However, only about 10 discovery and appraisal wells have been drilled on
these fields by Azerbaijan exploration rigs, and proven reserves are substantially less.
2.12          it can be inferred that most of Azerbaijan's offshore reserves are subject to considerable
uncertainty, and will require detailed geophysical studies and considerable exploratory drilling to be
confirmed. The proportion of reserves in the "probable" category is unusually large for a relatively
mature province such as Azerbaijan, reflecting the past under-investment in drilling. However, the
substantial producing history of Azerbaijan, which has shown itself to be a very prospective petroleum
province, gives considerable confidence in the effectiveness of investment to convert probable into proven
reserves. The key issue for Azerbaijan is to attract the investment needed to make its probable reserves
available for production, as rapidly and effectively as possible.
Exploration Potential
2.13          In addition to producing and discovered oil fields, Azerbaijan also possesses a large
number of undrilled structures which are highly prospective for petroleum. Most of these lie offshore,
in water deeper than 200m, and reaching up to 800m in the central part of the Southern Caspian Sea,
which represents the limit of current technology. In general these structures represent a continuation of
proven hydrocarbon bearing formations onshore and in shallower offshore water, and the probability of



-13-
further large discoveries must be considered high. At least 24 significant prospective structures have been
mapped by seismic, spread out over most of the southern half of Azerbaijan's sector of the Caspiand.
Any estimate of the reserves of these structures must be highly speculative, however a very preliminary
indication is that they could contain about 2.5 billion tons of recoverable oil. Some of the structures
could, however, turn out to be primarily gas-bearing (with oil and condensate), as is the case with some
of the existing producing fields.
2.14          Onshore exploration prospects are generally smaller - the largest and most obvious
structures having been drilled many years ago. However, a number of significant discoveries have been
made outside the Apsheron peninsula, but have not been developed as the structures are deep and at high
pressure. New field onshore exploration in recent years has yielded negative results. Nonetheless,
although the 13 wells drilled since 1981 resulted in no new field discoveries, this represents a very low
level of exploration, which may also not have been targeted at prospects identifiable through high
technology search techniques. Several new structures remain untested, which could also have total
recoverable reserves of over 150 mt. In addition, there may be significant prospects for additional oil
reserves below currently producing fields, at depths of over 3,OOOm (current average production depth
is 1,800m) - until now these horizons have not been properly tested due to a lack of finance.
2.15          The existence of this substantial prospectivity means that Azerbaijan's planning horizons
for oil development must be substantially longer than implied by present discoveries. Moreover, the scale
of the technical challenge, the large expenditure and long leads times involved in the exploration of the
offshore and deep onshore structures, make it essential to initiate a long term coordinated exploration
program as soon as possible.
Oil Production in the Mature Fields
2.16          In general, the mature onshore and offshore oil fields of Azerbaijan are in an advanced
state of depletion, with old and dilapidated infrastructure and rapidly falling output. Production from
these fields has been falling at an annual rate of 10 percent.
Onshore Areas
2.17          In the onshore areas (which includes some very shallow offshore fields), there are around
9,700 wells which are classified as "active" (i.e. capable of producing petroleum), located on some 35
fields. Of these, however, up to 2,000 are inoperative due to a lack of spare parts, sand problems or
need for repairs. The producing wells yield on average 0.7 tons/day of oil, with individual well rates
varying from 20 tons/day (t/day) to 0.1 t/day. Wells produce on average between 94 percent and 98
percent water.
2.18          The production plans of SOCAR for the onshore areas focus in the short term upon the
reactvation of currently idle wells. It is estimated that bringing on stream the 2,000 idle wells could add
around 700 t/day to production. In addition, there are proposals to drill a substantial number of new
'The precise teitorial waters of the Caspian have not been interaionally agreed following the break-up of the Soviet
Union. Existng boundaries are based on deterinons made before the break-up. It is assumed that any re-deterwination Wll
not greatly affect Azerbaijan's share of Caspian rserves.



-14-
wells so as to maintain production. New wells usually yield at rates of 5 t/day, with a 93-94 percent
water cut.
2.19           In this context, the key issues for SOCAR center on the economics of such marginal
onshore wells. Estimates presented by SOCAR suggest that the economic cut-off for producing wells is
0.15-0.2 t/day, with a 98-99 percent water cut. Around 1,200 wells produce at or below this level.
However, such estimates are based upon the prevailing local costs, and probably do not reflect the full
economic cost of resources used for producing the oil. For example, most wells require artificial lift,
and the energy for running the pumps is costed at the very low prices prevailing in Azerbaijan.
Production in the onshore fields is extremely labor-intensive. The total number of people employed in
the onshore fields is 30,500, which is at least two to three tin:es the level which would be used in North
America. It is likely that the economic threshold of production is above the limit estimated by SOCAR.
2.20           The problems of the onshore fields can be seen by examining the recent operations of
three of the larger fields in the Apsheron (Balachani, Bibi-Eybat and Tagiev -which account for 25
percent of onshore output). The data for these fields, which is shown in Table 2. 1, demonstrates that
the fields had substantial negative funds flows (i.e. a deficit after allowance for capital investment), even
at the artificially low cost of local inputs. This highlights the central problem of very low domestic oil
prices, which have for many years been insufficient to cover the real costs of maintaining production (this
is discussed further in Chapter 8). If the various inputs are valued at international parities, it can be seen
that the cost per ton of oil produced is well above the international value of the oil. The largest cost is
for workovers, which greatly inflate the costs if valued at international prices.
Table 2.1: Production Costs In Three Large Apsheron Oil Fields 1/
(Data for Jlnuarj -March 1993)
Operational Data
Oil Sales (TM. tons)          139.6
Number of Workles             5,091
Electricity Consumption (Tb. Kwh)  64,232
Number of Operating Wells     3,500
Local Costs    International Costs
(Mn. Rubles)   (TM. US$)
Fiancial Data
Oil Sales Revenues                   1691.6         13,960
Labor Costs                          430.8           3,818
Electricity Costs                    338.5           1,927
Production Materials                 300.8           3,008
Workovers and drilling               732.1          21,875
Other Capital Investment              83.1            831
Net Funds Plow                       -193.7         -17,499
1. Balachani, Bibi Eibat and Tagiev.
Source: SOCAR. Mission estones.
2.21          The restructuring of onshore production will clearly require a substantial number of wells
to be abandoned. The equipment from such wells would either be sold for scrap, or reapplied to more
productive wells, while the land should be reclaimed for housing or agricultural use. Such a process is
inevitable as cil fields reach the end of their natural productive life. This process is already underway,
but in an erratic fashion.



-15-
2.22         In the case of many of Azerbaijan's onshore fields, however, the process of orderly
abandonment must be supplemented by assessment of the potential for applying more efficient investment
and new techniques to the mature fields. Part of the decline in production is attributable to insufficient
suitable production drilling, due to a lack of rigs and a shortage of finance. Field infrastructure, such
as pipelines and storage tanks, are also in poor condition, which limits production capacity and increases
losses. In many cases application of more modern drilling techniques, including horizontal drilling,
multiple completions, and use of more suitable drilling muds and proper tools (including modern logging
equipment) could greatly improve drilling and well productivity. A number of fields also utilize air-lift
technology, reportedly with good results, but a substantial proportion of the pumps are inoperative due
to a lack of spare parts. Modern seismic and other techniques can be used to identify bypassed pools of
oil. Selective investment, if combined with improved management practices which focus workovers and
repairs on the most productive wells, could result in improved field performance and economics. The
resources and technology involved in carrying out such a program call for developing a framework for
investment by foreign companies in these fields.
2.23         As far as the onshore fields are concerned, these issues need to be addressed in a
comprehensive manner, taking account of the geological characteristics of each field, its production
history, remaining reserves and economic cost of production. For each field an outline economic
assessment and restructuring strategy should be developed. Based upon this assessment, a comprehensive
production restructuring program for the onshore areas needs to be elaborated, involving selective
investment by foreign companies in collaboration with SOCAR.
Offshore Fields
2.24         There are some 17 active offshore fields in Azerbaijan. The major producing oil fields
are Oil Rocks and Guneshli4. Both Oil Rocks and Guneshli present major problems for SOCAP.,
requiring urgent investment decisions.
2.25         Oil Rocks was the first major field developed in the Caspian Sea. The field is located
about 50 kilometers (km) offshore, in relatively shallow waters (6-25 m). Development started in 1949,
and at the time Oil Rocks represented one of the most advanced offshore ventures in the world.
Development involved using fixed production platforms linked by some 300 km of causeways
("Estacada"), which serve both to support pipelines and to carry supplies with vehicles. In other respects
the production systems used were very similar to those in the onshore fields.
2.26         At its peak in 1964-65, the Oil Rocks field produced 21,000 t/day. Production has now
fallen to under 2,000 t/day from about 700 wells (a further 400 wells are idle for lack of equipment).
In addition to natural depletion, the field has suffered from poor maintenance, with a lack of adequate
corrosion protection on the structures, and from the 1.5 m rise in the level of the Caspian Sea over the
past 20 years, which has led to major storm damage to the offshore structures. Much of the Estacada
has already collapsed, or is in danger of doing so in the near future. There is substantial ancillary
infrastructure associated with the field, including a 48 MW gas turbine station, which was built only 10
years ago, but is used at only 15 percent of capacity. Housing and communal buildings for over 1000
people are also built on natural and artificial islands.
4 Another major offshore field, Bakhar, is primarily a gas-condensate field and is discused in the secdon on Gas Supply.



-16-
2.27         Overall, the economics of continuing field production must be seriously in question. Per
well productivity is only 3 t/day. Despite the fact that the field is producing only 10 percent of its peak
production, field activities continue on a very large scale. Attempts are constantly underway to rebuild
damaged sections of the causeway and repair producing structures. The field is also the largest single
employing unit within SOCAR, with 5,000 workers directly employed in field operations (2,500 offshore
per shift).
2.28         About 88 percent of original reserves have been produced and remaining recoverable
reserves are estimated by SOCAR at 32 mt. Although this is a significant amount, it is not clear that
these reserves are economically recoverable using the existing infrastructure and production arrangements.
At present, production per worker is only 146 tons/year, which is worth about $15,000 at international
prices. Although offshore wages (which are about 50 percent higher than those onshore) are at present
about $4,000 per year (at an 'equilibrium' exchange rate of around R100/$), the margin left for all other
costs is low by the standards of the oil industry. An assessment based on international costs and prices
suggests that the field had a funds flow deficit of around $1 million in the first quarter of 1993. A major
review of the field is required to assess whether remaining reserves would not be best recovered using
a redesigned production system, a limited amount of new infrastructure, and with much of the existing
infrastructure abandoned. This assessment could serve as a model for the restructuring of the other
mature offshore fields, many of which suffer the same problems as Oil Rocks, albeit on a smaller scale.
Attracting Foreign Investment to tko Mature Fields
2.29         The restructuring of the mature fields, and enhancement of their production, is best
carried out through investment by international companies experienced in this type of work. This type
of investment may be suitable for smaller companies used to working mature onshore areas, such as the
medium and small indepvndents present in North America. The rewards of such work will in general
be modest in relation to development of the large offshore fields, although returns to investment can be
extremely high given the lower costs of operating onshore.
2.30         A number of specific issues need to be, resolved in reaching such agreements:
*   Sharing of rewards: If investment is to be rewarded by results, some determination of the
incremental production which has been achieved by the investment will usually be required. This
needs some agreement on what production would have been in the absence of the investment.
Since the technologies which would have been applied by SOCAR differ from those applied by
a foreign company, such determination is not always easy. A more straightforward system of
sharing rewards on a predetermined basis (for example by sharing total production 50/50) can
result in indeterminate returns to the producer, and secondary income or profit taxation may be
needed.
*   Definition of Incremental reserves: Within a single field additional production may be obtained
both from enhancing the performance of wells in an existing producing horizon (or by drilling
new wells in such an horizon), or by locating new horizons (for example by drilling to greater
depth). The risk profiles and rewards of the two activities are very different, the former being
a low risk and lower cost activity with modest but rapid returns, the latter a much higher risk
and cost investment but with larger returns through additional delineation drilling (essentially a
form of exploration).



-17-
0   Sodal Issues: The contractor may be unwilling to bear the continuing costs of existing excessive
employment and social liabilities. Where it does not interfere with efficient operations, such
costs may have to continue to be borne by SOCAR. A major restructuring of the mature oil
fields would have a substantial impact on employment. At present SOCAR employs about
58,000 people, of whom 40,000 are employed directly in oil and gas production. Any
restructuring plan would have a large impact on employment, reducing it by at least 50 percent
in the medium term. In addition, much of the communal and social infrastructure around Baku
(eg. hospitals, schools) is associated with the oil fields. A program to mitigate the social impact
of employment reductions from restructuring will be needed, including reassignment of staff to
the new offshore oil projects and retraining, and the handing over of responsibility for social
infrastructure to the appropriate local government authorities.
*   Environmental liability: Contractors may be reluctant to invest in fields where there is
substantial environmental damage, out of concern that they will be held liable for this.
Moreover, lack of clarity about the standards which will have to be met for new investmnent can
result in uncertainty over the future costs and production regime to be assumed. Pre-contract
agreements on environmental remediation which SOCAR intends to undertake may be needed.
The Problems of the Guneshli Field
2.31         The Guneshli field accounts for 59 percent of current oil production in Azerbaijan, and
It is thus the largest single influence on Azerbaijan's oil output in the near and medium terms. Production
from the field started in 1980, and rose rapidly until 1990 to 6.6 mt, as a total of 11 producing platforms
were put in place in the shallower part of the field. However, since 1990 production has stopped
growing, largely due to the rapid decline in per well productivity, which fell from 115 t/day in 1985 to
59 t/day in 1991.
2.32         The key problem affecting the field has been the failure to implement an adequate water
injection program. This has created a dangerous situation, where reservoir pressure has dropped rapidly
and there is a significant risk of a substantial loss of recoverable reserves. The problem is compounded
by a lack of production separation facilities in the field (to separate oil, gas, water and sand). Redressing
this situation is urgent, in view of the possibility of a rapid decline in production, and of a large economic
loss to the country.
2.33         A program to address this situation has been proposed by foreign companies (Pennzoil
and Ramco), which have been in negotiations with SOCAR. Their plan would involve implementing
water injection and an appropriate production regime in the developed part of the field, and producing
the undeveloped portion in an optimal manner. The project also involves the capturing of the gas from
Guneshli, which is currently vented. Overall investment would be about $650 million in the first stage
and $1.0 billion in the second stage.



-18-
2.34         The agreement with foreign companies, involving the taking of responsibility for a large
offshore producing field, much of which is undeveloped, has few precedents in the international
petroleum industry. Key issues which have been addressed in the negotiations include: the definition of
"incremental' production from which the foreign investors would be rewarded, the procedure for joint
management of the field, the responsibility of the foreign companies for the existing staff and concerns
among international companies about liability for safety and environmental shortcomings. A further key
issue for Azerbaijan is the need to retain a high share of production in the early years, to avoid a sudden
fall in SOCAR's crude availability as the contractor begins to take rewards for investment (this is
addressed further in Chapter 3 below).
Figure 2.4 Oil Production - Guneshli
and Other Fields
Million tne
14 -.g   ............................I.............................................
12    --...........
10-
1980  1985  1986  1987  1988  1989  1990  1991  1992
Guneshil   M  Other fields
Source: SOCAR.
Oil Field Environmental Issues
2.35          Current environrmental problems connected with the oil industry in Azerbaijan are the
result of decades of mismanagement under the old USSR system which emphasized oil production at any
cost. The scale of oil-related pollution is extremely severe by comparison with similar producing areas
in North America and there is a clear potential danger to human health in the affected areas. Immediate
action is recommended to reverse the continuing environmental damage. This action should be
coordinated with development of management systems and refurbishment of the industry infrastructure.
The primary causes of pollution are oil spills and unsound disposal of formation water and oil field
wastes.



-19-
Offshore Oil Pollution
2.36         Small and large oil sheens can be seen in the Caspian Sea near oil production facilities
and natural seeps. About 95,000 cubic meters/day (m3/day) produced water are discharged to the
Caspian Sea by SOCAR. Most discharges contain 2 to 4 times the legal content of oil and metals. The
shoreline around Baku is black with oil. Although most of the oil pollution there probably results from
discharges of oily produced brines as well as natural seepage, some of the pollution in Baku Bay could
result from poor waste management by sea-going vessels.
2.37         Air pollution from upstream petroleum production results primarily from the wasteful
venting of around 1.4 billion cubic meters (Bcm) of wet gas annually offshore. Venting methane is a
powerful contributor to the greenhouse effect, and may also contribute to the formation of ozone and
smog. The practice is also extremely dangerous, given the risk of fire and explosion.
2.38         The contribution of Azerbaijan to the general pollution problem in the Caspian Sea is
difficult to estimate. Natural oil seeps located in and near the sea result in uncontrolled oil pollution;
however, no action is recommended regarding such natural occurrences at this time. Man-made pollution
in the sea includes industrial waste from all countries bordering the Caspian Sea. Sound source
reduction, waste minimization and pollution prevention policies should be implemented regionally to
reduce the contaminant loading on sea life.
Onshore Oil Pollution
2.39         Onshore oil-related pollution results from faulty equipment, inappropriate disposal of
formation water and wastes and ill-conceived production pit construction. The problem is greatly
aggravated by the location of many of the oldest oil producing facilities in heavily populated areas around
Baku. The most serious impact is probably on groundwater resources. Surface and groundwater in Baku
are now too polluted with oil and chemical wastes to drink. Local inhabitants rely mostly on bottled
mineral water obtained from less polluted mountainous regions. There is also air pollution from the
venting of methane and volatile compounds onshore, although the windy conditions around Baku limit
the impact of this problem.
2.40         Approximately 7400 hectares are oil- and brine-soaked with severe short- and moderate-
term consequences to local plant and animal life. Restoration of 2400 hectares of this total is underway.
It is recommended that unlined production pits should be phased out to protect groundwater resources.
Ihe rising level of the Caspian Sea has caused flooding of oil and brine pits, leaving large numbers of
stagnant oil-filled ponds. Pits vulnerable to flooding should be drained and closed down, while dikes and
dams should be constructed to control flood waters. Produced-brine lakes should in general be drained,
and the water filtered and re-injected. Alternatively the brine could be treated to remove metals and
discharged to the Caspian Sea. The polluted soil should then be restored using chemicals and bio-
remediation.
2.41         Most produced brines are re-injected for oil reservoir pressure maintenance; however,
improperly plugged boreholes near injection wells may present a significant danger to fresh water
resources. Analysis of the mechanical condition of each wellbore located in the immediate area
surrounding each injection well is recommended. Currently, used drilling mud is de-watered and
landfilled, but controls on seepage of toxic pollutants are inadequate. It is recommended that the landfill



-20-
should be constructed with redundant safety features to prevent groundwater contamination by heavy
metals. Groundwater monitoring wells and dust control measures should be implemented.
2.42         The impact of oil-related pollution on the health of the population arises mainly from
exposure to heavy metals from formation water and drilling muds. Exposure to crude oil itself is less
harmful, although some carcinogens can occur in oil which has been exposed to solar heat. Small
quantities of ingested heavy metals can have severely detrimental medium-term and long-term effects on
human health, including digestive tract and neurological disorders. While immediate comprehensive
environmental remediation will prevent further deterioration, the long term adverse health effects resulting
from decades of exposure to poliutants will continue to be felt.
2.43         The discharge of oil-related sewage containing excess heavy metals such as chromium,
lead and mercury into the Caspian Sea is also dangerous to health, and should cease. There is a risk of
exposure to toxic pollutants through the food chain, since seafood represents a significant portion of the
average Azerbaijani diet. Steady reductions in sturgeon and caviar production are probably due in part
to Caspian Sea pollution, although over-fishing is suspected also. It is recommended that livestock
grazing near contaminated areas should be restricted to reduce the accumulation of pollutants in the food
chain.
Institutional Issues
2.44         Current environmental codes, laws and institutions in Azerbaijan need continued
development. The State committee on Ecology and Use of Natural Resources is responsible for
environmental enforcement, but enforcement is limited by the availability of trained specialists and
anatytical Instrumentation. The level of fines set is also very low, for example the fine for discharging
liquid wastes (including produced oil brines) to the Caspian Sea was equivalent to only US$1.00 per
100,000 barrels in mid-1992.
2.45         Government plans and policies seem focused on controlling pollution through setting
emission limits at source. It is recommended that careful consideration should be given to development
of technology- and market-based environmental policies. These policies could stimulate development of
pollution control equipment manufacturers and the inclusion of environmental costs in product pricing.
2.46         Efforts and costs to mitigate existing pollution are related to those to upgrade production
equipment. New equipment and technologies reduce emissions, leaks and spills. However, an
environmentally-conscious attitude in labor and management is required to maintain a clean environment.
Such an attitude requires personnel training, and both positive and negative feedback. Workers should
be rewarded for increased productivity, including avoidance of costly spills and leaks.  Good
housekeeping should be emphasized and effective training programs established.
2.47         The costs of onshore remediation could reach several hundred million dollars. Because
of this large cost, it is necessary to consider commercial arrangements to encourage remediation. In the
case of the onshore areas, SOCAR reached agreement with a foreign private company in 1990 to recover
oil from certain polluted areas, which was then exported to pay for the work. This practice could be
extended. In addition, there may be commercial interest in recovery of the large amounts of scrap metal
which lie in the oilffields, both onshore and offshore.



-21-
2.48         As concerns Caspian Sea pollution, regional initiatives are important. In the specific case
of oil, it is recommended that consideration be given to establishing a regional oil spill response center,
with costs shared among the Caspian Sea countries. Dedicated regional emergency response equipment
could cost up to $150 million, including fire fighting ships.
The Petroleum Equipment Industry
2.49         As a result of its early development as an oil producing center, Azerbaijan was the major
center for the manufacture of oil field equipment in the Soviet Union. About 65 percent of well service,
production and workover equipment for the FSU originated in Azerbaijan. Next to the industry of the
United States, which leads the world in oil field equipment, Azerbaijan's industry represents the largest
concentration of such manufacturing enterprises in the world. However, only a small part (ca. 3 percent)
of Azerbaijan's output of such equipment was exported outside the FSU (chiefly to countries aligned with
the Soviet Union). Moreover, the industry was not oriented towards the needs of the Azerbaijan oil
industry, since only 6 percent of production went to Azerbaijan, and many important components needed
by the local industry, particularly offshore, were not manufactured in Azerbaijan.
2.50         Given the high level of development, and diversification, of industry in the country, the
overall economic significance of this industry to Azerbaijan is limited: the industry employs 13,000
people (3 percent of the industrial workforce) and accounts for 4 percent of manufacturing output by
value (albeit under the previous distorted pricing scheme). The petroleum equipment industry is
nonetheless one of the most important in Azerbaijan for two reasons: firstly, it represents a potential
source of substantial hard currency exports as trade in oil equipment shifts to a world price basis, and
secondly its continued viability is vital to the maintenance of production in the other Republics
(particularly Russia). Although the equipment used in the other Republics could in principle be sourced
elsewhere, it will be some time before this can occur for very large volumes, due to the higher cost of
equipment from the US, the different standards of non-FSU equipment as well as the sheer volumes of
equipment involved. The last point is particularly important: the severe rationalization of capacity in the
petroleum equipment industry in the US over the past decade means that there is probably insufficient
capacity to replace the production of Azerbaijan, should that be disrupted. The petroleum equipment
industry consists of 14 plants, producing hundreds of different products. These plants are all organized
within a single holding company, Azneftekhimmash5, which centralizes key executive functions, while
leaving most operational functions entirely a the plant level. Azneftekhinmash also includes three
engineering and design institutes, employing over 600 engineers and scientists on research and
development.
2.51         The strategic importance of the petroleum equipment industry to the other FSU countries
has maintained orders for this branch of Azerbaijan's industry, even as demand for many other industrial
products has declined sharply. Nonetheless, the industry faces a number of serious difficulties:
*   The system of specialization within the Former Soviet Union made Azneftekhimmash highly
dependent on raw materials and finished parts from other Republics. At present 90 percent of
the steel used by the industry comes from Russia or the Ukraine. This has led both to
' Azncftehimmsh was created in April 1993 thugh the addition of several plants producing equipment for the chemical
md refinig industies to the previous company, Azreftemash, which was solely dedicated to oil field equipment.



-22-
disruptions in production and to an inability of the industry to negotiate more favorable prices
with FSU countries which are also suppliers of raw materials to the industry.
* The design and quality standards of the equipment manufactured in Azerbaijan correspond to the
previous Soviet norms. The international petroleum industry, however, generally uses products
conforming to the American Petroleum Institute (API) standards, which are different from those
used in the FSU. Azneftekhimmash's former clients in the other FSU countries are gradually
switching to API standards, under the influence of foreign investors and financiers. In addition,
Azerbaijan's non-standard equipment is not readily acceptable on the world market. In general,
Azerbaijan's designs are less advanced than those available internationally and in the past the
reputation of this equipment has suffered from a lack of adequate quality control.
*   The production facilities of Azneftekhimmash are mostly old and in need of replacement: 30
percent of the machinery is over 25 years old and another 30 percent is 10 to 25 years old.
There is also a shortage of measuring and testing equipment. This makes it difficult to maintain
either a steady volume, or a consistent quality of production. On the labor front, the industry
has been weakened by an exodus of skilled non-Azeri workers in recent years.
*   Because its previous production was carried out under the centralized ordering and planning
system of the Soviet Union, Azneftekhimmash has no marketing capability, and little knowledge
of its customer base. Moreover, the company never built up a network of repair and
maintenance centers close to its main customers, as is common for such companies in other parts
of the world.
*   The Azerbaijani industry faces potential competition from new plants in other Republics,
especially Russia, where the drive to convert former defense factories to production of petroleum
equipment is particularly strong.
*   Due to its isolation from the world market and foreign investors, Azneftekhimmash has little
experience of how to develop joint ventures with foreign partners.
2.52         Overcoming these difficulties will not be easy. Nonetheless, the maintenance of a
substantial and viable petroleum equipment industry in Azerbaijan is in the interests both of Azerbaijan
(as a potential source of foreign exchange and equipment for the local industry), and of the other FSU
countries (as a competitive source of equipment at affordable prices). Azneftekhimmash needs to follow
a number of strategies to maintain viability:
*   In its core markets in the FSU (especially Russia): (i) increase production capacity for key
products which are currently in excess demand as well as add certain new products so as to fill
gaps in its product range, (ii) upgrade the design of products to API standards (where this can
be done at acceptable cost), (iii) develop a service, maintenance and repair after-sales service in
major customer locations, and (iv) improve marketing and gain access to major competitive
contracts, including those financed by multi-lateral institutions (such as the World Bank and
EBRD). Maintaining a large share of the FSU markets is critical to the continued viability of
a large scale equipment industry in Azerbaijan.



-23-
*   In the local market in Azerbaijan: (i) Selectively design and produce products which are currently
not produced by Azneftekhimmash for the local market, and (ii) focus upon developing products
to serve the new offshore developments, to the requirements of the foreign operators.
*   In the world market, Azneftekhimmash needs to focus on developing a marketing and
representative network, focused on those narkets where it previously had a presence.
2.53         In carrying out this strategy, Azneftekhimnash will need to enter into joint ventures with
foreign oil field equipment companies, in order to gain access to their expertise in technology, quality
control, management and marketing, as well as to their investment capital. It is also probable that in
order to ensure its long term survival and viability, Azneftekhimmash will need to be restructured, to
eliminate unnecessary ancillary activities and to focus on its most productive units. In the medium or
longer term, the successful development of Azneftekhimmash will make it a good candidate for
privatization. In order to ensure that this strategy can be identified and pursued efficiently, a full review
of the company is recommended, accompanied by a training program for managers in business practices
in the OECD.



CHAPTER 3
OIL EXPLORATION AND PRODUCTION - NEW DEVELOPMENTS
3.1          The undeveloped offshore fields of Azerbaijan (Guneshli undeveloped portion, Chirag,
Azeri and Kapaz), whose reserves are estimated at about 600 mt, represent one of the major undeveloped
accumulations of petroleum in the world. In addition, Azerbaijan's sector of the Caspian Is one of the
world's most promising exploration areas. The investment and revenue from the development of these
resources hold the key to the future of Azerbaijan's economy.
Fleld Development Issues
3.2          Several fundamental technical issues need to be taken into account in assessing the
potential development of the-se fields and their impact on Azerbaijan's economy. Firstly, the location of
the fields, in water depths of lOOm to 300m, requires relatively sophisticated production technology,
which is widely used in the North Sea and the US Gulf but has not been available to SOCAR or its
predecessors. This type of development calls for construction of large offshore platforms, which serve
as bases for drilling, production, gathering and processing and staff accommodation. Each finished
platform can cost from $250m to $500m and take 1-2 years to construct. There are very considerable
economies of scale in this type of development. In addition, in order to position the platforms so as to
produce the reservoir optimally, a thorough delineation of the field is required before production starts.
There is thus a lead time of 3 to 5 years between the decision to proceed with development and the start
of production, during which time delineation drilling, engineering design, platform construction and
installation must take place. The optimal field production program thus usually requires very large up-
front costs, and a corresponding rapid build up of production to recoup these costs. A gradual or
incremental approach to development, which can be implemented with onshore fields, is usually sub-
optmal.
3.3          A second issue which applies particularly in the case of the Guneshli, Chirag and Azeri
fields, is the needs for common infrastructure and for a coordinated approach to development. The
geological and drilling evidence suggests that these fields are probably part of a single structure, and have
been separated over time by faulting and volcanic activity. The reservoirs may therefore still be in
communication, requiring careful coordination of production drilling at the field boundaries. Crude
qualities and other characteristics are also extremely similar, allowing commingling and joint processing
configurations. The physical proximity and alignment of the fields makes a common gathering and
processing infrastructure optimal. In addition, considerable economies ca'n be achieved through the
sharing of construction, marine fleet and supply facilities1.
3.4          A third issue is the need for a common crude export pipeline, given the landlocked nature
of Azerbaijan. This is addressed separately below.
' 7he Kapaz field appears to be a sepsrate stucture, with different crude chaacteristics, which nonetheless would have to
share infrastructure with the other fields for optimal economics.
-24-



-25-
Role of Foreign Companies
3.5          The estimated investments required for the development of the Guneshli, Chirag, Azeri
and Kapaz fields over the next 12 years total US$12 bn. lhis level of investment can only be obtained
by Azerbaijan through the participation of the major international petroleum companies. In addition,
these companies bring the necessary technology and project execution experience to these projects.
3.6           SOCAR and the Govermment have reached preliminary agreements with several groups
of companies to participate in the development of the offshore fields. At present, these take the form of
exclusive technical study agreements, and a unitization agreement, with negotiations underway for full
development agreements.
3.7          A number of issues need to be considered by Azerbaijan in reaching agreement with
foreign companies on the development of the offshore fields:
0   Need for unified development: Although the initial awards of rights to these fields were done
separately, there is a need for coordination of development between the fields, and for a unified
infrastructure and support system. This is an extremely complex issue, involving a balancing
of technical, managerial and financial considerations. Factors to be considered include:
*    Unitization: Should the companies retain different shares in the fields, or should the
existing field shares be pro-rated across all the fields on some agreed basis (eg.
preliminary reserves estimates)? The former case avoids difficulties over the share-out
of the fields, and allows the government to vary terms by field; however, it makes
rewards for the companies contingent upon the sequence of field development thus
creating a divergence between the national interest (optimal overall development) and
individual company priorities; the latter case avoids conflicts over field sequencing, but
raises the possibility of having to reach a single agreement with all the companies (which
increases the negotiating risks to Azerbaijan). SOCAR signed a Declaration of
Unitization with the foreign oil companies involved in the country in June 1993, outlining
plans to unitize the fields.
?    Operatorship: Should the fields be operated separately by different companies, or
jointly by a single joint operating company ? The former model maximies the desirable
effects of competition through benchmarking, but can create redundant parallel structures
and may make coordinated development more difficult. The latter arrangement may allow
better coordination in development, and a sharing of facilities and personnel; however,
this may be offset by removal of benchmark competition among operators and by creation
of a bureaucratic and unwieldy monopoly.
*    Ownership/operation of infrastructure: Should the joint infrastructure form a part of
the overall field development package, or should it be a separate project? The former
case could create a simpler project structure, since the companies would take joint
responsibility for construction and operation, with costs and revenues rolled into the field
agreements. The latter case, however, allows a more transparent division of the
revenues, creates additional financing possibilities for the infrastructure and, most
importantly, facilitates access to the infrastructure by additional oil and gas producers on
properly regulated terms.
1'



-26-
* Role of SOCAR: In general, it is expected that SOCAR would retain a stake in the oil fields,
even if these are developed and operated by the foreign companies. SOCAR would thus
represent Azerbaijan's interests in the fields, but its involvement should be as a quasi-
commercial company. The Government's licensing and fiscal role should be kept separate from
SOCAR's role as a participant in the field developments. SOCAR's precise role can be
considered on two levels - its technical and operational involvement in the fields, and its
involvement in the financing of the developments:
*    Technical and Operational Role: Unlike the state companies of many countries with
new oil fields, SOCAR has very considerable experience of oil and gas exploration and
production. However, SOCAR has little experience of modern offshore project design
and execution. Some participation by SOCAR in project design and operation is
desirable if transfer of technology and skills is to take place, and the economic benefits
of employment of local staff (in place of higher cost expatriates) are to be maximized.
*    iSnandal Role: SOCAR and Azerbaijan are financially constrained, with limited ability
to raise funds on commercial terms in international markets, and substantial calls upon
state resources for non-oil investment. 'Me alternative to SOCAR funding its own share
of costs is to be 'carried" by the foreign companies (i.e. have its share of costs paid by
the companies). In deciding on the level of SOCAR's participation the relative cost of
funding through a 'carry" by the companies and through the financial markets needs to
be examined. Azerbaijan must also consider the degree of project risk which it wishes
to take upon itself, as opposed to putting this risk mainly on the foreign companies. It
would probably be inadvisable for SOCAR to assume a large role in financing the first
generation of fields, as this would represent a very large financial exposure for the
Azerbaijan economy. SOCAR may, however, need to take a larger financial share in the
joint infrastructure and export pipeline to inspire confidence among foreign investors.
Moreover, SOCAR could take a larger role in "second generation' fields, basing the
financing upon the cash flow from the first generation of fields.
*   Type of Agreement to be Reached: Agreements under which foreign companies take on the
development of very large discovered, but only partially delineated oil fields, are somewhat
unusual in the international oil industry. It is more common for a single company as operator
to take a field through from the exploration phase to development (although it may bring in
other partners). Two basic types of agreement are in use by countries with large offshore od
resources - the Production Sharing Contract (PSC) and the Tax and Royalty systems. The issues
involved in choosing an appropriate system are complex. However, it is important that the full
cash flow and financial implications of the agreement are known to the Azerbaijani authorities
and can be tested against different oil production, oil price and macroeconomic assumptions.
Azerbaijan has generally opted for the PSC model in its discussions with foreign companies.
The nature of the developments in Azerbaijan pose a number of critical issues in negotiating
agreements:
*    Historic Costs: It is usual in the international oil industry for the discoverer of a field
to receive compensation for his costs in discovering the field, as well as some "bonus'
in recognition of the risk taken. In the case of Azerbaijan, the use of Soviet pricing in
previous exploration work makes calculation of acuWal costs incurred difficult, and resort
to international priciDg aniogies may be necessary. The bonus payments are a complex



-27-
issue for negotiation, although the Government should assess whether high bonuses will
be traded off by companies against better terms on subsequent developments.
*    Natural Gas: The requirement to dispose of associated gas, and Azerbaijan's need for
additional gas supplies, makes clarity of terms for natural gas particularly important.
aTis is addressed further in Chapter 5).
*    Related Provisions: Many petroleum agreements contain clauses relating to employment
and training of local staff, as well as provisions for investment in areas other than the oil
development itself In the case of Azerbaijan, arrangements for training local staff to
international standards are particularly important. Azerbaijan may also wish to use oil
companies as investors in areas related to the oil industry (petroleum equipment, refining
etc.) or in less related areas (eg. housing, social facilities). In addition, Azerbaijan may
look to the developers of the new fields to assist in rehabilitation of older fields.
However, it is not clear that linking agreements for offshore field development with other
investments brings a long term gain to Azerbaijan, since companies will often discount
such costs heavily in negotiations, and may not always be best suited to providing the
services in question. On the other hand, oil companies will often invest substantial sums
in the country in the interest of public relations alone, and such "non price" compe6ition
may bring real benefits to Azerbaijan.
*    Choice of International Companies: Countries which are awarding licenses to
companies to explore for and develop oil fields often select these companies with a range
of criteria in mind. This is particularly the case for offshore oil fields, where the
technical and financial challenges are usually greater. Criteria which can be taken into
account include: (i) The experience of the company with similar projects, (ii) The
company's financial capacity to undertake investments, (iii) The quality of the company's
project proposal, (iv) Ability to work with and to train local staff, (v) Likely long term
commitment to Azerbaijan. In addition, countries will often look to the mix of oil
companies involved in their offshore developments. Thus, some countries might wish
to have a variety of nationalities represented to take account of general international
trading and investment relationships. In some cases countries wish to have a mix of
major companies represented, with no particular company being dominant, so as to
maximize competition and access to capital and technology. Countries may also develop
a special relationship with one or more companies, with benefits in terms of long term
commitment. In general, when developments reach the scale of those in Azerbaijan,
careful attention to having a suitable variety of companies represented is probably
preferable to working exclusively with a single company.
Encouraing Foreign Petroleum Investment
3.8          While Azerbaijan's resource base presents attractive potential exploration and production
opporunities for international petroleum companies, it is important that an appropriate business
enmironment is created to encourage actual investment. To date, Azerbaijan has been successful in
building on the interest shown by many foreign companies in the country, although achievement of final
agreements and investment has been slow. In order to speed up foreign investment on the most suitable
tems, a number of initiatives need to be pursued:



-28-
*     Creation of Legal Framework: Azerbaijan needs to establish an appropriate legal
structure for petroleum resource ownership and investment, both by domestic companies
(eg. SOCAR) and foreign companies. To date no such specific framework exists. Work
on a Petroleum Law, which should be passed by the legislature and executive at the
highest level, is an urgent priority (see also Chapter 7, paragraph 11). Agreement on a
Petroleum Law is usually accompanied by development of standard contracts for
exploration and development, which clarify the fiscal and practical terms of access to
foreign companies and greatly simplify the process of negotiations. Azerbaijan should
seek the assistance of international advisors in developing its legal and contractual
framnework for petroleum. It is important that all associated legal and fiscal provisions
which might impinge on petroleum investnents are also clarified, to prevent delays due
to inappropriate regulations in such areas as company taxation, foreign exchange,
customs, labor law etc.
*     Consistency of Commercial Approach: Negotiation of major petroleum agreements is
of necessity a complex and often prolonged process. Continuity of negotiating stance and
commercial relations is important. In the case of Azerbaijan, considerable momentum
and understanding has already been achieved with a set of major companies, and turning
back on the progress to date could delay considerably the start of investments, without
a corresponding commercial gain to Azerbaijan.
e     Use of Suitable Advisors: It is usual in major commercial negotiations, including
petroleum negotiations, for Governments to employ financial and legal advisors. In the
case of Azerbaijan and the other FSU countries, the lack of previous experience of such
negotiations makes this particularly important. The scale and complexity of the projects
in Azetbaijan are likely to require the support of advisors with a substantial capacity for
such work, as well as relevant experience. Selection of advisors through open
competition is to be advised wherever possible, to ensure that the best advice is obtained.
Since Azerbaijan's petroleum industry is likely to generate many sub-projects, the use of
more than one set of advisors is probably desirable to ensure some diversity of advice
and maximum effort. While such advice is relatively high cost, the total costs involved
are modest in relation to the revenues which are at stake for the Government.
*     Strengthening of Local Capacity: While advisors can provide invaluable assistance in
reaching agreements, key decisions will remain in the hands of the local officials of the
Government and SOCAR. It is thus vital that the commercial skills of Azerbaijani staff
are developed as rapidly as possible, and that the most capable local staff are assigned
to the petroleum negotiations. Training can be provided through access to foreign
financial assistance (grants and technical assistance loans) and also through assistance
from the international companies working within the country (who have an interest in
speeding up the dialogue with their local counterparts). It is important that local
negotators are organized into effective teams and that there is continuity of staffing to
build upon experience and commercial relations.
*     Organization of Negotiations: It is important that negotiations are well organized, with
a clear plan of action and regular meetings. Communications of results of negotiating
sessions, and documentation of agreements reached is vital. Senior government officials
and management must be kept fully informed. Management of public announcements,



-29-
and control of confidentiality where necessary are also critical, to ensure both full public
understanding of the process of agreement, and preservation of commercial confidence.
Delegation of authority to reach agreements at specific levels of importance should be
clear.
0     SimpUfication and Prioritization of Negotiations: It is important that the number of
major negotiations being conducted at any one time be limited to what can be handled
effectively by local staff and institutions. In Azerbaijan, the project to develop at least
three large offshore fields in an integrated manner, as well as large associated
infrastructure and an export pipeline, can clearly lead to a large number of complex and
related negotiations proceeding at the same time. Additional discussions on other
petroleum investments in development of smaller onshore and offshore fields, exploration
and other infrastructuire and services have also been proceeding. The effective conduct
of the large number of discussions involved is probably beyond the present capacity of
SOCAR and the government, and simplification and prioritization of the negotiations is
critical. In this context, unitization of the three large offshore fields (Guneshli, Azeri,
Chirag) would make the negotiation of offshore agreements much more manageable by
allowing joint negotiations with all oil companies on a single set of agreements. As
indicated above, standardization of the basic contract terms can greatly simplify
negotiations, especially on smaller exploration and development contracts.
*     Presentation of Data: In order to allow for rapid progress in negotiations, and for the
attraction of new firms on a competitive basis, it is important that Azerbaijan presents
information about its petroleum production and resources in a consistent and accessible
manner. Preparation of data through data packages, data rooms and information seminars
is a regular part of the petroleum industry, which Azerbaijan would do well to emulate.
In the case of all the FSU republics, translation of data iL a a form accessible to foreign
companies can greatly speed up the process of agreement. Azerbaijan should seek the
assistance of foreign companies specializing in such work, possibly using international
financial assistance.
Future Production Prospects
3.9          An assessment of the likely profile of future oil production is the key ingredient in
Azerbaijan's economic and energy outlook. Projections need to be made both for the mature fields, and
for the new fields. In both cases there are significant uncertainties, although of different types. The
ucertinties on the new fields tend to overwhelm those on the mature fields due to the sheer scale of the
new developments.
3.10         An assessment of future production has been made for a Base Case scenario. However,
production projections alone are of limited interest without a link to investment flows, and to the sharing
of production between the foreign investors (or "contractors") and the host government. An attempt has
therefore been made to model the future share of production between the contractors and the Government
(including both the central Government and SOCAR). This uses standard production sharing terms to
explore the type of profiles which could result from different assumptions about development. In
practice, of course, negotiated terms may differ substantially from those used in this exercise, and the
aim of this discussion is to raise issues rather than to present precise calculations for planning purposes.
In order to assess possible variations in production and revenue profiles, a number of alternative scenarios
have been developed.



-30-
Figure 3.1 Oil Production Prospects
Million tons
80 
[mD KsPez
EM Awrl
EM Chirag
40  - 6, ,   V C.....................................                       ......,, ....g|  
E   Offshore-.xlting
-Onshore-noW
90  -  *    A< 1x4$t1AW* '*0! .................
20  ..............            ...
80
i S          |tI  Il ll|i,,,,;;,,j
) F :  ~~4 111111111 11 llilllll
1192         1996                   2000                   2005                   2010
Source: Misson estimates.
Production Prorile - Base Case
3.11           Figure 3.1 shows possible future production profiles for key fields and groups of fields
in Azerbaijan. The key factors taken into account are:
*      EExisting onshore and offshore fields: Production from fields currently producing is
expected to continue to decline at historic rates (ca. 10 percent per year) due to the
maturity of the reservoirs. There could of course be some improvement due to well
reactivation, although abandonment of uneconomic producing wells may partly offset this.
It is assumed that these fields will continue to be wholly the property of SOCAR.
*      New onshore fields: This is intended to encompass both development of currently
undeveloped structures onshore (and possibly the shallow offshore) as well as of new
horizons or pools within existing field boundaries. It is assumed that this exploration and
development is undertaken by foreign contractors, who carry SOCAR's costs.
Production climbs to 2 mtpy by 2000.



-31-
*      Guneshli, Chirag, Azeri, Kapaz:   These fields are assumed to be developed
sequentially, with Guneshli the clear priority due to its proximity to shore and critical
reservoir condition. The development of the latter fields requires a four year lead time
from first investment to production. Azeri thus comes on stream in 1998, followed by
Chirag in 2001 and Kapaz in 2003. The lag between the start-up of the fields (Azeri and
Chirag in particular) is assumed to be dictated by availability of platform construction
facilities, since the construction yard can only produce I to 2 platforms per year.2 The
order of field development could vary - a scenario giving priority to Chirag is also
plausible. The production profiles of the fields broadly reflect the optimal economic
profiles derived from feasibility studies of the fields. Joint production from these fields
reaches 21 mt in 2000 and peaks at 42 mt in 2006.
3.12           It should also be noted that these profiles do not take account of potential production from
major new discoveries. At present at least one major structure (Shach Deniz) is ready to be drilled, and
negotiations are underway with a foreign company for exploration rights. This structure is larger than
most existing offshore fields, and holds potential for several hundred million tons of oil, although there
is a strong chance of the predominant hydrocarbon phase being gas. Assuming that exploration takes
place in 1994 and 1995, production could be on stream by 2002, around the same time frame as is being
assumed for Chirag. However, bringing another field on stream at this time would require a major
expansion of the fabrication capacity of Caspian Sea yards. Given the high probability of further large
discoveries in the Caspian offshore, the fall in production after 2005 shown in Figure 3.1 should be
regarded as unlikely. Policy should not therefore be based upon the assumption that the three
undeveloped fields represent the sum total of Azerbaijan's future oil resources. Priority should be given
to reducing uncertainty for policy planning purposes through a rapid and efficient exploration of key
offshore structures 3.
Revenue Generation - Base Case
3.13           In order to assess the likely division of the benefits from  oil production between
Azerbaijan and tLa foreign oil companies, it is necessary to reproduce some of the likely features of the
production sharing contracts. Key assumptions for the PSC models are shown in Table 3.2.4 Total oil
production is divided into the following categories:
*      Oil consumption: this is a projection of likely oil consumption in Azerbaijan based upon
the trends discussed in Chapter 4. It is assumed that all of this is supplied by SOCAR
and the Government (all contractor oil is exported).
2A hser rate of development may be possible, although this could lead to bottlenecks of services and supplies in other
areas.
If Shach Deniz is gas bearing, this may make ita development a priority to meet gas requirements, see discussion of Shach
Deniz in Chapter 5.
It should be noted that the production sharing models use in this study are simnplified versions of those in prmctical use.
They captur the major feacu  of this form of agreement, but leave out such complications as sliding scales for cost recovay
and profit sharing, based upon such factors as percentage of costs recovered. The model assumes that SOCAR has a SO percent
sham of the pofits from the fields (after allowing for the sharc due to the Government islf, although this is only a working
assumption and a lower share could emerge from negotiations.



-32-
*      Contractor oil exports: this is the total revenue of the contractors as expressed in terms
of oil. Under the PSC models assumed, contractors receive all their revenues as oil for
export, in the form of Operating/Capital Cost Recovery and Profit Oil. It is assumed that
contractors sell their share of natural gas to the Government/SOCAR (at economic gas
prices) and receive in exchange an equivalent value of crude oil. It is assumed that
SOCAR is carried by the companies, who therefore recover the full investment cost of
the fields (but must share the profit oil and gas with SOCAR on a 50150 basis after
allowing for the Government share).
*      SOCAR+Govermnent exports: this is the share of SOCAR and the Government in
Profit oil, from which is deducted local demand, and the cost of paying the contractors
for their gas with oil.
Table 3.1: Producion Sharing Model
Key Assumptions (1993 USS)
Oil Price:                           $20/barmel (fob Mediterranean)
Natural Gas Price:                   Sl.90/mof (ex-gas plant)
Interest Rate:                       10% (for unrecovered costs)
SOCAR Investment:                    Fields: 0% (SOCAR Carried by Oil Cos.)
Infiastructure/Pipeline: 50%
Infrstructure Tariff:                $1.10/barrel
Export Pipeline Tariff,              $2.50/barrel
Max. Cost Recovery:                  60% of oil and gas revenues
Gov. Profit Share:                   60% to 85% (of Profits)
Foreign Co. Target IRR:              Ca. 20% (rate of return on investment)
Source: Mission estimates.
3.14           Table 3.2 shows the division of oil between the contractors and SOCAR/Government in
the Base Case. It can be seen that, due to the impact of high cost recovery in the early years (comprising
over 60 percent of oil production), contractor exports exceed SOCAR/Government exports until after
2000. Between 2000 and 2005, the decline in cost recovery oil increases the share of profit oil sharply,
and hence the share of SOCAR and the Government, who together take around 75-90 percent of profit
oil. Such a regime, which allows companies to recover their investment relatively quicldy (within about
six years of production start-up) tends to delay the benefits of oil exports to Azerbaijan. However, the
nature of offshore field development leaves companies with a large sunk investment, and the companies'
unrecovered exposure to Azerbaijan could reach $4 billion in the late 1990s - there may therefore be
limits to Azerbaijan's ability to slow down cost recovery.
Table 3.2: Division of 0i Prodaction - Base Case (illon tons)
1992            1995            2000             200S            2010
Domestic                  8.8             5.0              4.8             5.5             5.5
Consumption
Exports                   2.2             4.7             20.8            39.7            27.1
-Gov.+SOCAR              2.2              2.8             9.7            20.7             17.6
-Foteign Cos.            0.0              1.9            11.2            19.1              9.5
Total                    11.1             9.7             25.6            45.2            32.5
Soure: Mission eates.



-33-
Aftwafive Scenarios
3.15         Several alternative oil production and revenue sharing profiles can be developed, on the
basis of alternative assumptions about the key variables (see Figure 3.2):
(a)    Oil Reserves: Clearly the volume of future production could vary substantially if reserves
in the known fields turn out to be much higher or lower than the Base case. Variations
on this have not been tested, since the range of estimates may be too wide to be of
interest.
Figure 3.2 Division of Oil Production
Alternative Scenarios
| _   Dom. Cons. (SOCAR)            E3 GoY. * SOCAR Exports
|E For. Co. Exports
Million tons
60 
4  4  ..   - .  M   ......... M.....  m 
3 0    .    .. . . ..  .... . .. ..    .E  . .. .............  ....... .. .. ..
2|5 . ....        ..........     ........                   ..........
is   .......        .....        0     ..    .               ....... * .  .
2 6  -    . # *         -  .   4  44            4 .     44       . ' X. i.
Base Cse eLow Cost                        Low Oil             LOW
B    C aLowCotLow011Las e Case  Recovery   Price             Production
Source: MUsion estimtes.
(b)    Rate of Development: The Government may choose to vary the rate of development of
the oil fields. A "Low" Production scenario has been developed for the case in which
production from the offshore fields is kept at a steady level from the late 1990s, rather
than being allowed to peak. This case is based on the assumption that all field
developments are reduced in scale. The overall effect will be to reduce the rate of return
on the whole venture, due to a loss of economies of scale. It is interesting to note that



-34-
one of the possible intentions of such a production policy, to prevent a speaking' of oil
revenues, is not in fact achieved effectively - Govermnent/SOCAR oil exports are more
stable from 2000 under the Base Case than the Low Case, due to the effects of the PSC
formula. An accelerated development scenario, for example one in which Azeri and
Chirag are developed almost simultaneously, is also possible, although uncertainties on
the investments required in additional construction capacity mean that this case has not
been investigated.
(c)    Cost Recovery and Profit Share Profile: The profile of cost recovery can be altered
through tine by placing a lower ceiling on cost recovery, which can then reduce the
share of companies in the early years (while giving them more profit oil later). A slower
rate of cost recovery on Guneshli would help to increase the Government/SOCAR share
of oil before 2000. In the figures shown this is combined with a higher Government
profit share in the early years of the field. In this 'Low Cost Recovery' case
Government/SOCAR exports are generally higher in the years to 2002, but
correspondingly lower in the later years. Variations in the cost recovery and profit share
elements could be used to increase this shifting of cash flows through time. This would
allow the Government to meet early revenue requirements for macro-economic
restructuring. The calculations show that a smoothing of Government revenues can
probably more effectively be achieved through PSC terms, rather than by a sub-optimal
slowing down of oil development. However, there may be a limit to oil company
tolerance of deferred returns.
(d)    Oil Price Changes: Oil price impact could take two forms - unforeseen impacts, which
lower the rate of return to both the Government/SOCAR and contractor, and impacts
which are taken into account in negotiations (because agreement is reached after a change
in the oil price outlook). The effects of the latter case have been evaluated, with the
parameters altered to maintain the rate of return to the companies at the lower oil price.
A sensitivity test in which world oil prices are 15 percent below the base-case scenario
(world fob prices of $17/barrel rather than $20/barrel) shows that the projects would
probably still be economic, but that the return to the Government will be seriously
eroded, if company returns are to be maintained at a level which still encourages
investment. In this case, company exports could rise to 50 percent of total exports in
2005, from the Base case level of 42 percent. The offshore oil projects probably start
to become marginal at an oil price of around $15/barrel (fob Mediterranean). Azerbaijan
could of course gain even larger revenues from oil development if oil prices are above
the Base Case level. However, past experience of the oil market shows that it would be
unwise to base planning on an assumption of rising oil prices. Given the uncertaity
about future oil price levels, it is important that Azerbaijan adopt cost-efficient
development strategies for the offshore fields, as well as reaching agreements with oil
companies that allow investment to proceed even under lower oil prices.



-35-
Economic Impact of Oil Development
3.16         Policies affecting the development of oil production need to be seen within a macro-
economic context. The overall economic impact of the oil developments stretches beyond the generation
of revenue for the Government through its share of oil and gas production (including that obtained
through SOCAR). Account also needs to be taken of the impact of investment and operating costs on
the local economy and balance of payments, of the effect of alternative timing of revenue streams on the
economic adjustment process and of the costs of alternative methods of financing oil development.
3.17         The consideration of each of these issues can be summarized as follows:
*     Impact of local investment and operating costs: Azerbaijani companies have the
potential to gain a substantial share of the investment in offshore development, for two
reasons. Firstly, the landlocked location of the Caspian makes it difficult to transport
heavy equipment to the Azerbaijani offshore fields, greatly favoring local manufacturing.
Secondly, Azerbaijan has developed a significant capacity in offshore fabrication and in
petroleum equipment (see Chapter 2), as well as having a substantial engineering industry
base. As a result it is estimated that between 30 percent and 45 percent of total offshore
investments may be made within Azerbaijan. The balance will consist of imported goods.
The impact of this, in terms of total investment and imports, is shown in Table 3.3,
which demonstrates the vital role which this investment will play in the country's
economy. Operating costs will also have a substantial economic impact, with an even
larger share of the total likely to stay within Azerbaijan (perhaps 50%). Azerbaijan's
large trained workforce, which already services a large offshore industry, is expected to
provide most of the service labor, while maintenance and spare parts can also be supplied
locally. Critical issues for Azerbaijan to consider in this context include: (i) the need to
encourage the maximum local content supply of investment goods and services, on
competitive terms, (ii) the need to avoid foreign investment creating inflationary pressures
through local bottlenecks, (iii) the potential for a "creaming off" of staff from the state
sector to foreign companies.
*     Timing of Revenue Streams: This issue has been addressed above under Alternative
Scenarios. The critical issue for the Government to consider is the integration of this
analysis into the overall macro-economic policy framework. Given the difficulty of
obtaining finance from commercial sources to bridge any financing gap, the Government
may wish to give priority to early revenue generation. Foreign companies, faced with
slower recovery of their capital and hence longer exposure to Azerbaijan risk, may
demand a somewhat higher rate of return in exchange.
*     Alternative Flnancing Options: As discussed above, Azerbaijan must choose between
alternative means of financing its oil developments. The above scenario assumes a
compromise, whereby SOCAR funds its share of joint infrastructure (including the export
pipeline) from various sources (commercial credit, multilateral loans, export credit,
internal cashflow), and is "carried" by the foreign companies for the offshore fields. The
carry by foreign companies is a relatively expensive form of finance. However, it is
improbable that credit on such a large scale would be available to Azerbaijan on
commercial terms. Moreover, the impact of borrowing for oil development on access
to credit for other purposes must be taken into account.



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Tabke 3.3: Nei O Fancil Flows (US$ ml0Won)
Base Case            Low Oil Prodn.           Low Oil Pice
1995    2000    2005    1995    2000    2005   1995    2000    2005
Net Oil Trade    (+)   614   2,792   5,327    610   1,628   3,338    530   2,336    4,458
Foreign Invest.  (+)    690   1,078   346     601      821     277    690   1,078      346
Capital Imports   (-)   483   755     242     421     575      194    483     755      242
Operating Coss   (+)    144    461    652      140     294     429    144     461      652
Foreign         (-)    72     231     326      70      147     214     72     231      326
Operating Costs
Company Oil     (-)    88   1,138   2,226      88     856   1,596      70   1,060    2,236
Expouts
Net Forign     (=)    805   2,207   3,531     772   1,165   2,040    739   1,829    2,652
Exchange flow
Source: Mission essimates
Oil Export Pipele
3.18          In order for exports of crude oil to take place from Azerbaijan on a large scale, a new
dedicated pipeline must be constructed from the Caspian coast of Azerbaijan, to a port with access to the
world market. Most oil exports from Azerbaijan have in recent decades taken the form of oil products,
exported by rail car, Caspian tanker and/or river barge (see Chapter 4). In 1992 Azerbaijan exported
crude (ca. 1 million tons) by swapping crude delivered to a Russian Caspian port with Russian oil
exported through the Black Sea. However, such swaps, as well as the existing export routes, are
inadequate for the volumes of crude exports contemplated in the long term.
3.19          Four potential routes have been examined for Azerbaijani exports (see Map in annex):
(a)    Via Turkey to the Mediterranean: This route would have to cross either Iran, Armenia
or Georgia to reach Turkey. Within Turkey the line would join an existing pipeline
which was used for the export of Iraqi crude, with exports going through the existing
terminal at Ceyhan. This route has been favoured through bi-lateral agreements between
the Governments of Turkey and Azerbaijan.
(b)    Via Russia to the Black Sea: This route would follow existing pipelines to the port of
Novorossyisk (although a new terminal may need to be built nearby). Such exports could
be integrated with planned exports from Kazakhstan through Russia to the Black Sea.
(c)    Via Georgia to the Black Sea: This route is the shortest to a seaport, and could follow
the track of a pipeline which existed in the first few decades of this century, to the port
of Batumi. A pipeline to a new port at Poti, north of Batumi is probably the preferred
alternative.
(d)    Via Iran to the Persian Gulf: This route is the longest, and although it allows easier
access to Far East crude markets via the Gulf, was rejected as probably uneconomic
compared with the other options at an early stage.



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Tabk 3.4: 00 &qpo,vt leil Oioas
Baku-                             Balu-
Novorossiysk           Poti           Ceyhan
(via Russia)     (via Georgia)    (via Twkey)
Length (km)           1346               795              1608
Cost-Pipeline (US$m)    2121             1231             1793
Cost-Terminal (USSm)    283              283                 0
Total Cost (US$m)     2404               1514             1793
* Nose: Assumes all costs are borne by Azerba#an crude vxports only (fecldes poble camu
auributable to Kazakhszan or other exporters).
Source: SOCAR
A number of issues need to be taken into account in assessing the choice of route:
X      Construction Cost: An assessment is required of the cost of various routes. Since the
routes pass through different countries, with differing local cost parameters this is more
difficult than for pipelines within a single country.
*      Transit Cost: Different countries may have different expectations for transit fees, and
some form of early indication of this would help to generate confidence in a route choice.
*      Financing: This is closely related to the perception of the political risk of differen
routes, as well as the financing capacity of the countries through which the pipeline
passes.
*      Political Factors: For a multinational project of this type, political considerations canmot
be ignored. They may affect the perception of potential investors in Azerbaijan
exploration and production, who must be persuaded that their export route for crude is
secure. The risk of disruption will be closely related to that of political friction with a
country through which the pipeline may transit.
*      Shipping Issues: The final ports of loading, in the Black Sea and Mediterranean are not
comparable in terms of their crude shipping capacity and costs - Black Sea ports can only
load tankers up to 150,000 tons, which is the maximum which can transit through the
Bosphorus, while the Mediterranean port of Ceyhan can load super-tankers up to 300,000
tons. The unit cost of shipping varies almost direcdy with the size of the tanker. In
addition, there are serious environmental, safety and logistical questions over the
possibility of transiting a large increment of crude oil through the Strait of the
Bosphorus'.
5Undera 1936 Treaty, intenational shipping hs free psage* though the Boaphorus. However, thereare soamresctia
on lrger vessels. Very few large tankers pass thrugh the Bosphorus each year, and Turkey has expred seious conen
about a substantial growth in tmker traffic through the Stait.



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3.20         A further key issue which must be considered is the commercial structure of any pipeline
project. The government has indicated its intention of involving the foreign oil companies working
offshore in the project. It also intends to cooperate closely with the Governments and state companies
of the countries through which the pipeline would pass. In financing a venture such as this, it is clearly
important to involve all interested parties so as to ensure maximum access to finance and coordination
of the pipeline project with other regional projects. Involvement of multilateral banks, and export credit
agencies, may also be required to complete the financing and reassure investors. The Government should
seek suitable experienced advisors to arrange financing and the projects' commercial and legal structure.
3.21         The link with the foreign oil companies is particularly important in this respect, since they
will be financing the projects which will supply the oil to fill the pipeline. The security of their
production revenues depends upon the reliability of the pipeline. Moreover, their guarantee of throughput
to the pipeline is necessary for arranging financing. For this reason oil pipelines are often regarded as
an integral part of oil production ventures. In this case, however, it is probably best to develop a
separate company for the pipeline, given the scale of the project, and the probable need eventually to
transport oil from new oil fields.
3.22          A transparent and stable tariff and capacity allocation structure is vital in order to provide
confidence to future investors in Azerbaijan's oil fields. In this context, it is important to signal that the
pipeline is viewed as a cost-center, not as a profit-center. That is, tariffs should be transparently based
upon justifiable costs, with no excessive charges for profit beyond those needed to repay debt and reward
equity adequately. Tbis will both ensure that the full benefits of oil development remain with Azerbaijan,
and reassure future oil shippers that they will obtain fair revenue for their oil.
3.23         It is also important that the pipeline is planned within an overall regional context. Future
oil developments on the Northeastern edge of the Caspian in Kazakhstan also require access to the world
market. Production from the Tengiz, Karachaganak and other oil fields in Kazakhstan is expected to
reach 25 to 50 mtpy by 2005. Additional production may also come from the Caspian shores of
Turkmenistan. The integration of exports from these countries with those from Azerbaijan could provide
important economies of scale and scope for regional cooperation.
3.24         The political, financial and commercial difficulties to be overcome in developing the oil
export pipeline are considerable. While full development of Azerbaijan's offshore oil fields will doubtless
require a new pipeline, lower volumes could probably be exported by developing low cost options to
access the Russian oil transport system. This would allow Azerbaijan's oil to be swapped for Russian
exports from the Black Sea, or to Europe by pipeline. Such an option could allow early exports of
incremental oil from Guneshli. Agreements would need to be reached with Russia on transit fees and
especially on compensation for quality differentials between the higher quality Azeri crudes and the lower
quality Russian crude. Some investments in reversing and augmenting pipeline flows may also be
required. Assistance from multi-lateral institutions could be sought in arranging such ventures.



CHAPTER 4
PETROLEUM REFINING AND PRODUCTS MARKETING
Introduction
4.1          The petroleum refining and products trading industry in Azerbaijan dates back to the start
of oil production in late 19th century. As a part of the former Soviet Union (FSU), the industry's
development was based on its perceived comparative advantages and role within the overall Union
refining and oil transport system. Azerbaijan's importance as a refining center is due to its being the
third largest crude producer in the FSU, after Russia and Kazakhstan, and its location on the Caspian Sea
with marine transport access to republics around the Sea. Under the Soviet system, prices of crude oil
and refined products were regulated at levels far removed from international prices; inter-republican
trade, and trade with countries outside the FSU were regulated from Moscow; technology imports were
restricted; wage and employment policies did not encourage labor mobility, and there was little or no
financial performance accountability. Production and marketing agencies functioned as agents for
carrying out centrally-planned objectives and had no autonomy in carrying on business as commercial
enterprises.
4.2          The planned-economy management of the industry emphasized the increase of production
volumes without taking into account cost and efficiency. While additions to refining capacity and
marketing infrastructure took place, there was very little modernization and retirement of old facilities.
Current physical facilities are thus a combination of old and obsolete and relatively modern facilities with
low average cost efficiencies. The industry's structure and management, as well as most likely its
competitiveness, are significantly inferior to those in OECD countries.
4.3          The new oil trading environment which has arisen following the break up of the FSU has
put pressures on refineries, as trade patterns and costs adapt to world prices. The key issue for
Azerbaijan in the petroleum refining industry is the future role and economic viability of its refineries
within this market oriented trading context. While a full assessment of the future of the country's
refineries should await a detailed industry study, it is clear that substantial rationalization and
restructuring will be needed if the refineries are to operate profitably and provide least cost oil product
supplies to Azerbaijan.
Refinery Facilities
4.4           Azerbaijan has two refineries, both located on the outskirts of Baku on the Caspian Sea,
with a total refining capacity of about 20 million tons per year (mtpy). The refineries were integrated
into SOCAR in September 1992. The Azneftyag Refinery includes refining facilities which commenced
operations about 120 years ago and currently has operable capacity of about 11.7 mtpy of crude charge.
Facilities consist of several trains of crude and vacuum distillation units, and lube oil manufacturing units.
It is essentially a lubricating oilfbitumen plant, with incidental production of straight run kerosene, diesel
oil and fuel oils. The refinery's current lube production capacity at 1.0-1.2 mtpy is very large in relation
to domestic requirements and produces relatively low quality lubes which it has been exporting to other
republics of the former Soviet Union. Without even a reforming unit, the refinery does not produce
marketable gasoline, and sells the naphtha to a petrochemicals plant at Sumgait as feedstocks, and to the
New Baku refinery which upgrades the naphtha to gasoline. The technology base of all constituent
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process units and production control systems is obsolete. Physical facilities are very old, poorly
maintained, and generally run-down. Production and offsites facilities have been built over a very large
area with poor operational and control integration.
4.5          The New Baku Refinery commenced operations initially in 1965/66 with 2 mtpy crude
and vacuum distillation capacity, and with secondary processing units, consisting of a fluidized catalytic
cracker (FCC), a coker and light ends polymerization units. Crude oil distillation capacity was increased
by 6 mtpy in 1976, and a reformer was added in 1980. Refinery configuration is somewhat complex,
but hydroprocessing capacity for distillates treatment is quite limited, thereby constraining its ability to
process high (in excess of 1.7-2.0 percent) sulfur crude oils. Except for the new FCC unit under
construction, the technology base of process units is obsolete. Maintenance of facilities at the refinery
is also poor. Both the refineries purchase electric power from the State grid, steam from nearby thermal
plants, and make-up water from Baku municipality. A small part of utilities requirements is generated
within the refineries from waste heat. (A brief description of physical facilities of the refineries is in
Annex 4.)
Crude Supply and Product Output
4.6           Total refinery throughput was more or less at a constant level of 21 mtpy (range: 20.4-
22.1 mtpy) during 1981-88. Throughput has fallen rapidly since 1989, to only 12.1 mtpy in 1992.
During the 1970's an.,' 1980's there was an important shift in the pattern of crude supplies. Azerbaijan's
refineries had both originally been developed to process domestic production. In the early 1970's their
capacity was thus largely devoted to processing almost all local crude output. However, as domestic oil
production declined, the resulting refining surplus was allocated to the processing of imported crudes
from Russia and Kazakhstan. As table I shows, these crudes accounted for about 40 percent of refinery
throughput in the mid-1980s. Imports from Russia have been largely of Tyumen type crude from
W.Siberia, while those from Kazakhstan have been of poor quality (high sulphur and metals content)
Buzachi crude, for which Baku was the only direct outlet. In general both the Russian and Kazakh crudes
imported have been of substantially lower quality than domestic crudes, which have very low sulphur
contents and relatively good yield characteristics. Because of lack of secondary processing and
hydrotreating facilities at the Azneftyag refinery, available domestic crude oil was preferentially allocated
to this refinery.
4.7          The rapid decline in throughput since the late 1980s has been due mainly to the rapid fall
in imports from other republics, as well as to the continuing decline in domestic production. The fall in
imports from other republics is due to the change in trading relationships within the FSU in recent years,
with a shift away from central planning towards bilateral trade based upon negotiated prices.
4.8          Because Azerbaijan's products output until the late 1980's was 150 percent in excess of
domestic demand, the republic was a substantial exporter of products, mainly diesel oil, fuel oil and
lubricants. Products exports in recent years went back to Russia and to local Caucasus or Caspian border
republics, with Baku essentially functioning as a regional refining center. A significant proportion of
exports also went outside the FSU, with a large diesel trade to Northern Iran. Azerbaijan was one of the
most important suppliers of lubricants within the FSU, and was the main supplier of certain specialized
lubricants (such as for diesel engines and transformers).



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Table 4.1: Refineries Crude Throughpu* and Produedon, 1981-92
('000 ons)
1981       1985        1989         1990         1991         1992
Crude Oil Processed         20499      21135       18435        16331        15820        15639
Crude Oil Supply            20628      21240       18440        16342        15837        15650
- Domestic Crude          (13283)    (12387)    (12646)       (12073)      (11088)      (10549)
- Russian Crude            (5054)     (3203)      (2879)       (2515)       (2514)       (3000)
- Kazakh Crude             (2171)     (5612)      (2909)       (1754)       (2235)       (2100)
Main Products:
Automotive gasoline          1992        1898       1549         1480         1174         1265
Diesel Oil                   3534       4500        4237         3975         3635         3750
Bitumen                       188         181        167          145          113          240
Lubricating Oils             1132        1118        934          819          763         1041
Coke                          125         103        300          178          161          180
Fuel Oil                     8838       9316        9429         6579         6400         6400
Kerosene                     N/A         N/A        1539         1304         1350         1400
Source: Aznefichin and Goskomstai
4.9            The key issue now facing Azerbaijan in this sub-sector is whether its role as an exporter
of products can continue within a market oriented environment. The lack of upgrading capacity and
generally poor facilities of the refineries are clearly a disadvantage in this respect. Due to the relatively
poor processing configuration, the production of fuel oil (at 43-46% of crude charged) is very high,
resulting in low added-value in refining. Although the Azneftyag refinery produces a high percentage
of crude charged (about 8-10%) as potentially high-value lubricating oils, its lack of reforming and
secondary processing facilities limit its ability to produce high-value distillates. The low sulphur content
of domestic crude oil will favor exports to third countries of diesel oil and fuel oil wbich are processed
from domestic crude. However, there is little market internationally for the higher sulphur products
derived by Azerbaijan's refineries from imported crudes. Lube oils would need significant quality
improvements to approach international quality standards.
4.10           Domestic marketing is carried out by Goscomtopliva which operates 32 inland storage
terminals and about 500 retail stations within the country. As in other FSU republics the overall level
of coverage by service stations is inadequate, and quality of service poor. However, given ample local
production of products, supplies at the retail level are more readily available in Azerbaijan than in many
other FSU countries. The Government should examine the possibilities of privatizing retail pumping
stations in the near future, to introduce competition and improve service to consumers.
Domestic Product Consumption
4.11           Domestic consumption of refined products in the country totalled about 7.5 mtpy during
1991. Although complete historical data on consumption are not available, domestic consumption is said



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to have remained relatively flat during the 5 years to 1990. In 1991 and 1992, however, demand rose
significantly due to higher fuel oil usage. Of the total consumption, road transport fuels account for 33-
35% (equally shared between gasoline and diesel oil), fuel oils (nearly all for the power sector) for 53-
55%, and the remainder is accounted for by jet fuel, and non-energy products Oubes, bitumen). In the
short term a modest decline in transport fuel demand is likely, due to the economic decline and the
considerable fall in transit traffic through Azerbaijan. Fuel oil demand, on the other hand, will depend
upon structural changes in the user sectors (mainly power generation), and the country's ability to
maintain the levels of gas imports from Turkmenistan. As Table I shows there was a very sharp rise in
fuel use in power during 1991 and 1992, which was caused by a fall in gas availability (net gas imports
fell from 7.7 bcm in 1990 to 4.3 bcm in 1992 - see Chapter 5).
Table 4.2: Azerba&an: Crude Oil and Products Suppy-Demand Balance
(Base Case, '000 tons)
1990          1991           1992           1995           2000           2005
Production        12513          11742          11084          9700           25603          45174
Imports           4505           4516            1375           1025             0              0
- Crude           4290           4301            1350           1000             0              0
- Products         215            215             25             25              0              0
Consumption       6708           7576           7998           4292           4358           4974
- Gasoline        1260            1252           1125           1122           1432           1828
- Diesel           1271           1263           945            851            1085           1385
- Fuel Oil        3216           4185           5228            1690           1036            735
- Other            961            875            700            630            804            1026
Exports           7769           6065           3955           5719           20809          39702
- Crude              0              0            1050           S00             n.a.           na
- Diesel          2733           2279           2000             n.a.           n.a.           na
- Mawt            3594           2297            320             n.a.           n.a.           na
- Jet Kero         823            747            150             n.a.           n.a.           na
- Dieal Lubes      220            338             90             n.a.           n.a.           na
- Other            399            403            345             n.a.           n.a.           na
Refinery Fuel
& Loss            1344           1283            797            714          436             497
Unreported
Balance           1196           1334           -290             0             0               0
Source: SOCAR, Mission estimates.
4.12           Once gas imports are restored to the levels required by the power sector (imports in 1993
are expected to remain constrained), Azerbaijan's oil demand is unlikely to be above the level of 1990
at least until the year 2000. This assumes that fuel oil use in power plants is gradually phased out, since
domestic and imported gas is likely to be more economical (see Chapter 5 paragraph 27), and fuel oil
availability declines as additional cracking capacity is installed. Although the gradual economic recovery
from 1995 should lead to a rise in car numbers, and in commercial and public transport, the impact of
rising transport activity on oil demand may be offset by improvements in the average fuel efficiency of
the fleet (due to the much greater efficiency of new vehicles entering use) and to more cautious fuel use
as retail fuel prices approach economic levels.



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New Investment Plans
4.13         Despite the considerable uncertainties over the future economics of refining capacity in
Baku, both the refineries have commenced implementing physical restructuring investment projects. At
Azneftyag refinery, contracts have been entered into with US and South Korean companies, for
construction of two 2 mtpy capacity each of atmospheric and associated vacuum distillation units, each
with an investment of about $30 million equivalent (including $18-29 million in foreign exchange), and
planned to be completed by mid-1995. Upon completion, except for the largest and relatively new (1963
vintage) primary distillation unit of 6 mtpy capacity, the remaining 5 smaller distillation units are to be
scrapped. The existing vacuum unit of about 2 mtpy capacity is to be modernized under an Azeri-British
joint venture, through changes in the vacuum system internals; the incremental benefits from the
modernization are to be shared among the partners to be redeployed for further modernization of plant
facilities. Azerneftyag has not yet developed plans for rationalizing and modernizing lube oil production,
its main business. Nor does it seem to have concrete plans for producing marketable motor gasoline from
naphtha which it currently transfers in part to the New Baku refinery and in part to an olefins production
plant at Sumgait as feedstock. Lubes capacity rationalization and modernization should be based on a
realistic assessment of future export markets and on achieving international quality standards of high-value
lubricating oils in order to derive the maximum benefits from domestic crude oil. Rationalizing the lubes
production section will also have an impact on the upstream crude processing sections, and the need for
modernizing the primary crude oil distillate capacity should be assessed taking into account the possible
option of purchasing a part of the vacuum gas oil feedstocks (for lubes manufacture) or reduced crude
from the New Baku refinery.
4.14         At New Baku Refinery, the ongoing and planned future investments include a joint
venture agreement between the refinery company, a W. European company and a Russian trading
company, to recover hydrocarbon oils from the semi-solid sludge from a waste water treatment plant.
The recovery plant, with an investment of about $10-12 million has been in operation for the last 2 years
and export sales revenue from recovered oil is being shared between the partners pro-rata and the export
and excise taxes accruing to the Government. The refining company is currently evaluating two proposals
for future modernization investments. The first involves the purchase of a 6 mtpy refinery meant initially
for a W. European buyer who did not proceed with its implementation. This refinery, whose component
units were manufactured around 1985, has light ends processing units of modern technology, but lacks
heavy ends secondary processing. It is possible to match this refinery with an FCC unit under
construction for the last 8 years. With this combination, and with refurbishing and modernization of the
existing larger crude (6 mtpy) and vacuum units, the new configuration will be able to process flexibly
a wide variety of crude oils with sulphur content of up to about 1.6% and be able to produce products
of international specifications. The new 6 mtpy refinery is estimated to cost about $340 million on a
turnkey basis. However, it is recommended that a thorough process and engineering study should be
carried out to establish the -conomic and financial viability of the offered refinery in combination with
the FCC unit and modernized existing crude and vacuum capacities. The second proposal being
considered by New Baku Refinery concerns the offer from a consortium to modernize the existing
refinery over a 8-year period in 4 stages. However, major issues concerning leasing/ownership, costs
and benefits sharing and management structure are yet to be resolved. While this alternative is likely to
be less attractive compared to the proposed purchase of a new refinery mentioned above, the possibilities
of quickly implementing a flare gas reduction scheme (likely to have a quick payoft), and modernizing
the cooling water system should be evaluated.



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4.15         These physical restructuring investments do not appear to have been justified before the
investnent decisions, taking into account projected changes in policy framework, market shares, prices,
and impacts on ability to achieve competitiveness. The refineries should carry out a comprehensive study
through external consultants on the continued operation of existing physical assets, costs of operations,
and options for achieving competitiveness with identified and prioritized investments, retiring
obsolete/uneconomic plant, and modernizing technology and equipment. The study should also examine
methods for modernizing management systems. The study findings should then be used as a basis for
implementing domestic and foreign private investment.
Crude Oil and Product Transportation
4.16         The main oil pipeline in Azerbaijan is the crude oil line which is used to import oil from
Russia, which was commissioned in 1983. This line, which has a diameter of 720 mm and a total length
of 600 kms, runs south from Grozny (in the Chechen Autonomous Republic of Russia) to Baku. Its
nominal capacity is about 8 mtpy. The line is operated by the Transcaucasian Main Pipeline Association,
which is part of SOCAR. There are additional smaller lines for crude from the various oil fields to the
tank farms and ro-fineries with a total length of about 370 km. The main Grozny-Baku line and other
lines in Azer iajan htve suffered damage from the rise in the level of the Caspian Sea. Product
movement within Azerbaijan is all done by road and rail, as there are no significant product pipelines.
4.17          Azerbaijan lacks low cost access to international markets for its crude and products.
Exports of crude oil and products have historically been carried out by rail car and by Caspian Sea
tanker. The main rail lines lead north to Russia, and west to Georgia. The rail line to the Georgian
Black Sea port of Batumi provides access to non-FSU markets. Oil can also be sent via Caspian tanker
to the Russian port of Machatscshkala (in Dagestan) where it can enter the Russian pipeline system, and
similar tankers can be sent to Turkmenistan and Northern Iran. River tankers can access distant markets
in Russia and beyond via the Volga-Don canal. While freight rates were previously held at artificially
low levels, at economic prices all of these routes represent high cost transport modes for substantial crude
or product quantities.
Refinery Strategic Issues
4.18         Several questions need to be addressed in developing short term and long term strategies
for the refining sector. The common objective of the strategies would be to reduce the cost of products
supply to the domestic market through a combination of domestic refining at optimum capacity utilization,
and imports and exports of crude oil and products. An additional consideration is the profitability of
transit refining (i.e. refining imported crude for product exports). In the medium term, the country
theoretically has the option of: (i) exporting all of its domestically produced crude and importing all of
its products requirements; (ii) processing some domestic crude while exporting the balance and supplying
some local demand with products imports (iii) processing all domestic crude and exporting the products
surplus to local requirements, (iv) operating the refineries at their full capacity with domestic crude
supplemented with imported crude (until local supplies are sufficient to fill local capacity), and exporting
surplus products.
4.19         The relative evaluation of the four above-mentioned options would require realistic
estimates of the opportunity values of exported crude and products, and costs of imported crude and
products at the country border. These values and costs would depend upon the destination market for
exports, source markets for imports, and the corresponding freights between the border and the



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source/destination markets. At this time, it is difficult to identify such markets and, more importantly,
the freight costs, given the lack of direct access to open seas and the unclear economic costs of overland
haulage using the current transport infrastructures.
4.20         As concerns the first option (i above), the export of crude oil from Azerbaijan is at
present difficult due to the lack of a suitable pipeline. Moreover, transport costs of product imports
would also be high, and it is therefore attractive in principle for Azerbaijan to supply most or all of its
own product needs by refining its own crude. The precise proportion of local product supply, and of
which products, which should be met by local refineries will require careful study, taking into account
regional refinery yield patterns, crude and product quality availabilities and transport costs.
4.21         The most difficult question for Azerbaijan is whether to continue to refine substantial
quantities of oil in excess of its domestic requirements, i.e. whether to refine crude for export (options
iii and iv above). In the medium term, while production of oil remains below domestic refining capacity,
it is highly unlikely that large scale imports of crude for export processing would be economic.
Azerbaijan's refinery configuration is generally poor and the refineries are high cost. A large part of the
yield is of fuel oil, with a low market value. While there may be some limited justification for meeting
regional requirements (eg. in Georgia) until the other Republics can restructure their own facilities,
Azerbaijan wou1 seem to have little comparative advantage as an international refining location.
4.22         By the late 1990s, however, Azerbaijan's oil production could approach current refining
capacity. Nonetheless, even with crude available domestically, refining for export is unlikely to be
preferable to exporting the crude directly by pipeline. In order for product export to the world market
to be preferable, the margin from refining would have to cover the operating and capital costs of the
refinery and the additional costs of transporting products. In practice, for the major international markets
in the Mediterranean and Northern Europe, it is highly unlikely that this would be the case. As figure
4.1 shows, it will usually be preferable to export crude from Baku if the cost of shipping prodtacts to
a major market (eg. Rotterdam) exceeds the cost of shipping the crude. For the local Caucasus/Caspian
market the situation may be less clear cut, although the size of this market is likely to be limited and there
will be growing local supplies from other regional refining centers in Kazakhstan, Turkmenistan and
Russia. It is therefore important, given the rather narrow gross margins, to assess the freight costs and
operating costs with reasonable precision, under the various option scenarios.
4.23         A low-risk short-term strategy for the refinery sector would be to target the level of
refining to the level required by the domestic products market (about 5 million tons per year) while
seeking to maximize the value of the balance of domestic crude production through both product and
crude exports, based upon market conditions. SOCAR should also maximize available crude supplies to
the New Baku refinery (which can produce higher proportions of high-value fuel products), while at the
same time assuring adequate vacuum gas oil feedstock to the Azneftyag refinery for high-value added
lubricating oils. In addition, local trading opportunities for product exports should be evaluated, as should
opportunities to import crude on favorable terms (for example Buzachi crude from Kazakhstan which may
have no other acceptable outlet).
4.24         The long-term strategy for the refinery sector should be defined based on the results of
the proposed consultant study which inter-alia will examine the options discussed above, the optimal
levels and nature of investments required for efficiency, and product yield improvements at either one
or both refineries.



-46
Figure 4.1 Relative Economics of Crude
and Product Exports from Azerbaijan
.................. ./.                    ........               ....mM m
Refining
Margin
LxDer.   ... ..               .........              ....
U8$ITon
_  .. .... .... ..........  ............  .  .......... e !!RDa  ..... ..
AzerbaiJan Crude          Rotterdam            AIerbaiJan
Export                Market             Product Export
Management and Training
4.25          Awareness is limited among refinery management about international markets, prices, and
factors that influence success as a producer/marketer of petroleum products in a competitive environment,
given their historical role as agents to carry out centrally planned directives. Similarly, adequate
appreciation of the objectives, expectations, and concerns of potential private sector investors is lacking.
Refinery managers are also not familiar with modern enterprise-level systems for production,
maintenance, and marketing controls, and information systems necessary for overall general management.
Environmental pollution aspects have not received sufficient attention from refinery management.
Maintenance of effluent treatment, control, and disposal facilities are poor, even compared to process
units maintenance. Production flexibility, product quality, and environmental pollution aspects need to
be considered as an integral part of restructuring plans by refinery management. A comprehensive
training and technical assistance program  will be required to upgrade technical and commercial
management skills.
Refinery Environmental Issues
4.26          While the basic framework for enviromnental pollution policies and regulations exists,
these do not appear to be comprehensive, and are outdated, relative to those in Western countries.
Regulatory standards exist for fuels qiality, p'rmissible pollutants levels in effluents from refineries
discharged finally into water bodies, and those in ambient air both at the workplace and in habitable areas



-47-
around refineries. Institutional mechanisms for conformance enforcement, as well as penalties for non-
conformance appear to be lax. With the maximization of physical production volumes being the main
objective of refining operations, environmental pollution control has received less priority and
management attention at both the government and at enterprise levels. Refinery companies generally
agree with regulatory and enforcement authorities on standards that are less stringent than the so-culled
national applicable standards. Further, they prefer to pay penalties for non-conformance to these relaxed
standards, rather than invest in improvements for pollution monitoring and control systems. As a part
of restructuring the economy, the Goverrunent should, as a priority, reformulate its environmental
pollution control policies (including those for the refinery industry) in tune with those in W. Europe, and
strengthen the institutional arrangements for monitoring and enforcement.
4.27          A specific problem at the Azneftyag refinery, concerns the cooling water, which is drawn
from the sea and is treated primarily to reduce suspended matter, with the effluent waters gathered in
settling ponds. After decantation, most of the water is recirculated back to the cooling water system, with
a part of the water discharged into the sea without further treatment. Although detailed analysis of the
discharge waters into the sea has not been made available it is likely that pollutants levels would be much
higher than the standards. The New Baku Refinery has biological treatment of effluent waters; however,
its operation is not dependable because of design and operational deficiencies in the aeration systems.
The refineries lack aerial pollution measurement and monitoring systems. There is also a need for
establishing appropriate analytical standards and methods. It is estimated that investments in the range
of $1.5-2.0 million would be required for modernizing the aerial pollution control systems, including
training of selected personnel at each refinery. There is considerable seepage of hydrocarbons into the
soil at the Azneftyag refinery. The refinery needs to assess the impact of seepage on the underground
water table as well as on the coastal waters nearby. It is recommended that a study should be carried out
on the pollution control facilities to identify modernization options for aerial, liquid and oil seepage
pollution controls.



CHAPTER 5
NATURAL GAS
5.1           Natural gas is the major fuel for domestic use in Azerbaijan, accounting for 63 percent
of primary energy supplies in 1991. While the country has substantial gas resources, and a long history
of gas production and use matching its oil production record, production has been declining in recent
years, and gas imports have reached a high level. Gas utilization is highly inefficient, with very large
amounts wasted through venting at the field, leakage from corroded transmission and distribution
pipelines, and inefficient and largely un-metered gas using equipment and appliances. Despite the
anticipated growth in oil production, continued gas imports may be required for at least a decade, placing
a heavy burden on the economy as prices of imported gas rise to world levels. Improving the efficiency
of gas production, capture, transport, and use should thus be one of the key aims of energy sector
investment and policy in Azerbaijan.
Current Status
Natural Gas Production
5.2           Azerbaijan's gas production comes as associated gas from its oil fields, and from large
offshore gas condensate fields. The latter are by far the most important source of supply, with the large
Bakhar field accounting for about 51 percent of production in 1991. The development of the Bakhar field
and the Bulla Daniz condensate field in the 1970s allowed production to rise rapidly during the 1980s,
reaching 14 billion cubic meters (1cm) in 1982.1 Since the mid-1980s production has fallen rapidly as
all the large fields, with the exception of Guneshli, entered a rapid decline. In recent years gas
production has been falling at a rate of 8-10 percent per year, consistent with the decline of oil production
in the mature fields. Production of associated and non-associated gas from the onshore (or near-shore)
fields, which still accounted for 20 percent of supplies in 1975, has fallen rapidly and now accounts for
only 3 percent of supplies.
5.3           A substantial proportion of gas production is vented offshore, principally from the
Guneshli field. Gas production from the Guneshli field, amounting to about 1.8 Bcm per year, is mostly
transported to the Oil Rocks field, where some is used in field operations, but about 1.4 Bcm per year
is vented. Plans to install compression and build a pipeline from the Oil Rocks field to the Bakhar
complex to capture this gas were not fulfilled, and the pipeline has been only partially constructed to date.
SOCAR has sufficient processing capacity to process this associated gas; the problem is the lack of field
compression and pipelines to bring the "wet" gas onshore. This resource waste results from the low
priority given to associated gas recovery under the previous Soviet system, where gas prices to producers
were extremely low, and planning authorities emphasized inter-union energy trade over development of
local resources.
The precise definition of 'production' by SOCAR is unclear. It appears to include gas quantities which are vented or
flared, but to exclude quantities which are re-injected for pressure maintenance.
49-



-50-
Table 5.1: Natural Gas Produccdon (Bcm)
1975         1980        1985        1990        1991        1992
Total        9.89          14.00       14.07        9.93       8.62         7.84
of which:
Onshore      1.57          1.22        0.71        0.41        0.29        0.24
Offshore     8.32         12.78       13.36        9.52        8.33        7.60
Bakhar      n.a.          5.10        6.57        4.85        4.22        3.67
Other       n.a.          7.68        6.79        4.67        4.11        3.93
Note: Producton is delivered, net of venting andJfaring.
Source: SOCAR
Natural Gas Trade
5.4          In 1980, as a result of a rapid rise in associated gas production, Azerbaijan was a modest
net exporter of natural gas to neighboring republics. During the 1980s, as gas consumption grew and
production stagnated, Azerbaijan became a growing net importer of natural gas (see Figure 5.1). Most
of these imports come from Turkmenistan, the second largest gas producer in the FSU. Gas from
Turkmenistan transits Uzbekistan, Kazakhstan and Russia, arriving in Azerbaijan by way of a pipeline
following the Northern and Western shores of the Caspian sea. This line was built and reinforced during
the 1980s specifically to meet the growing gas requirements of Azerbaijan and the other Caucasus
republics.
5.5           Azerbaijan has also imported gas from Iran under an agreement signed between Iran and
the former Soviet government. The gas was supplied through the IGAT pipeline, which runs from the
main gas system in central Iran to the Azerbaijan-Iran border. This line was built specifically to supply
gas to the FSU, under an agreement involving swaps of Iranian gas for Soviet gas exports to Europe.
This trade never reached the proportions envisaged: in 1991, FSU imports of gas from Iran reached 3.0
Bcm, still far below the theoretical capacity of the IGAT system.
5.6           Azerbaijan is situated along the main route for gas exports from Turkmenistan and Iran
to Armenia and Georgia. Out of total imports of 14.4 Bcm in 1991, re-exports to Georgia and Armenia
were 6.0 Bcm. In 1992 the regional conflict resulted in a complete cut-off of supplies to Armenia and
a fall in sales to Georgia to 1.0 Bcm, with a corresponding drop in total imports by Azerbaijan.
5.7           A critical problem for Azerbaijan has been the increase in gas prices demanded by
Turkmenistan, which has stated its intention of raising prices to "world" levels. Prices of gas from
Turkmenistan rose from Rb 1,700 per thousand cubic meters (Mcm) in the first half of 1992, to Rb 2,500
in the second. However, prices in early 1993 were much higher at Rb 15,000 (including transit costs
in Kazakhstan, Uzbekistan and Russia). Eventually Turkmenistan is expected to price gas with reference
to the European border price. This could lead to prices to Azerbaijan of $70/Mcm to $80/Mcm, if
account is taken of the shorter transport cost to Azerbaijan compared with Central Europe (where border
prices are $95-100/mcm). The cost of required gas imports in 1994, at $70/Mcm, would be about $600
million/year, which represents 25 percent of the country's estimated total import cost for 1994.



-51-
Figure 6.1 Natural Gas Production
Billion oublo meters
20-
Not Exports
150…
Net Imports
|+   Dliposals
=  Productlon
0-                  l                 l                I
1975             1980              1986              1990             1992
Source: Goskomst, Azerigas
5.8          Despite the recent moves towards denomination in dollar terms, the gas trade with
Turkmenistan is mostly conducted by barter, with Azerbaijan sending manufactured goods (such as
refigerators, oilfield equipment, etc.) to Turkmenistan in exchange for the gas. Dollar values for these
products are determined from cash sales for hard currency to other customers. However, in the longer
term a move towards cash settlement can be expected.
5.9          Future gas trade policy should focus on Azerbaijan's strong position as a crossroads for
regional gas trade. Full use of the existing lines to Georgia and Armenia (assuming a cessation of
regional hostilities) could provide $35-SO million per year in transit revenues for Azerbaijan, assuming
a reun to "normal" transit volumes of about 6 Bcm per year. Azerbaijan signed an agreement with
Ukraine and Iran in 1992, providing for a joint venture to construct pipelines to export up to 75 Bcm of
gas from Iran through Azerbaijan to Ukraine. While constulction of the lines is anticipated to start in
1996, in practice the venture depends upon transit rights through Russia and may not materialize as
rapidly as proposed. However, increased availability of gas from Iran will arise with completion of the
IGAT 2 line within Iran in the next few years, which will reduce the current bottleneck on supplies from
Southern to Northern Iran. In addition, Azerbaijan provides a potential route for a new pipeline from
Turkmenistan across the Caspian to Turkey and Europe. Either of these new projects could be very
lucrative to Azerbaijan, which could receive up to $5 to $8 million per year in revenue for each Bcm



-52-
transported. Given the clear benefit to Azerbaijan of providing gas transit service, national policy should
focus upon encouraging such projects, while limiting commitments to new capital expenditure and
guarantees (which may be borne by the gas suppliers and end consumers).
Gas Pipeline System
5.10         With its long history of gas use and role in transporting gas to other republics, Azerbaijan
has a relatively large natural gas pipeline system. Pipelines total 40,000 km, of which 4,000 km are main
transmission lines (up to 1200 mm in diameter). Nearly all the country, including about 100 towns and
cities, is connected to the gas grid and some 80 percent of the population have access to piped gas
service; this figure is particularly remarkable in view of the fact that much of the population (about 50
percent) lives in rural areas. Azerbaijan must rate as one of the most thoroughly gassified countries in
the world.
5.11         Both the transmission and distribution systems are controlled by the State Gas Company,
Azerigaz. Azerigaz was formed in 1992 through the merger of the national gas transmission company
with the natural gas distribution segment of the State Fuel Committee. Azerigaz also controls gas storage
facilities and a small gas processing plant, is responsible for LPG distribution and incorporates gas
research institutes.
5.12         A key problem facing Azerbaijan in the natural gas sector is the extremely poor physical
condition of large portions of the gas infrastructure. Much of the pipeline system (including compressor
stations and pressure reducing stations) is many decades old; some of it dates from the 1920s. Routine
maintenance and replacement of older pipes has been neglected, especially in recent years, as economic
conditions have worsened. There is insufficient cathodic protection of pipelines, and such systems as
exist have been reduced in effectiveness by a shortage of spare parts and of skilled maintenance staff.
The "aggressive" soil in Azerbaijan, which is high in corrosive salts and acids, greatly contributes to the
corrosion problem. An additional problem is that in the past many large consumers, including collective
farms and industries, built their own pipelines to the gas distribution network, often to poor standards
and without adequate corrosion protection. In the adverse soil conditions some of these pipelines last for
only 5 years, instead of the intended 25 years.
5.13         It is difficult to estimate how much gas is lost through leakage, since most gas use is un-
metered (and many of the meters that are in place are of questionable accuracy). Azerigaz estimates that
around 1.4 Bcm per year escapes through leaky pipes (equivalent to around 8 percent of consumption).
The loss percentage is acknowledged to be much higher in certain regions, ranging up to 20 percent.
However, the actual figure could be even higher than these estimates. For example, the specific use
attributed by Azerigaz to households appears high, and there is in addition a large balance unaccounted
for in the gas balance statistics. On the basis of these estimates, total annual losses could be some 15 to
20 percent of domestic supply, and could be worth US$150-200 million per year in imports at world price
levels. These large methane emissions from the pipeline system also pose significant threats to public
safety and the environment.
5.14         The pipeline system includes five large compressor stations (including one in the disputed
Nagorno-Karabakh region), each with 4 to 6 turbine-compressor sets. All of the equipment is Soviet-
made, indicating that the stations are probably highly fuel-inefficient and probably present significant air
emission and noise pollution problems. With the dissolution of the Soviet Union, there has been
increasing difficulty in obtaining spare parts and necessary refurbishment materials, which could



-53-
ultimately lead to disruptions in gas service reliability.
5.15         In many areas there are two gas distribution systems laid side-by-side: one at low pressure
to serve households and one at a higher (medium) pressure to serve industrial enterprises. These
duplicate facilities reduce the system's operational efficiency, and also increase the level of pipeline
leakage. These problems could be reduced by the elimination of the low-pressure system and the
introduction of proper pressure regulators for gas delivery to households and other small consumers from
the medium pressure system. In addition, inadequate gas flow and pressure control equipment, poor
measurement devices and a lack of modem control and communications systems also limit operational
efficiency. Safety is also clearly a problem, with many pipelines having been built in unsuitable areas -
- there is no concept of a "right of way" that is clear of other activities, there are many buildings situated
over main pipelines and there is often no proper separation of pipelines from main roads, railroad
crossings, housing, etc.
5.16         Processing of associated gas volumes, to remove water, impurities, and natural gas
liquids, is the responsibility of SOCAR, but the present system is inadequate for Azerbaijan's needs.
SOCAR controls the only large gas processing plant, at Karadag near Baku (another plant controlled by
Azerigaz is very small). The Karadag plant has a design inlet capacity of 6.5 Bcm per year of wet gas
and 675,000 tons of gas condensate, and includes six gas processing trains and one condensate processing
train. However, most of the plant was built in 1961, and the equipment is old, obsolete, and generally
inefficient. Because much of the offshore gas is not delivered to the plant, capacity utilization is low;
deliveries are currently only about 2.9 Bcm per year, and annual production of liquefied petroleum gases
(LPG) is only 26,100 tons. Hence, up to 60 percent of the associated "wet" gas that is captured offshore,
most of which is produced at low pressure, is not processed before it is delivered to the gas
transmission/distribution system, primarily due to the absence of compression equipment in the field and
pipelines to bring the gas to the Karadag plant. Instead, the gas gathering lines lead directly to the
Azerigaz system. These deficiencies in associated gas capture and processing represent a significant waste
of valuable LPGs. Azerbaijan is deficient in LPG, and imported 20,000 tons from Russia in 1991 (worth
about US$4 million per year at current world prices). The introduction of unprocessed gas into the gas
transmission/distribution system also accelerates the pipeline corrosion process and damages compressor
stations, meters, and gas-using equipment.
5.17         Azerbaijan's gas storage capacity (working capacity) of about I Bcm, located in two
depleted oil/gas fields, is not adequate to cope with seasonal demand fluctuations, resulting in additional
curtailments of gas service to electric power plants with dual fuel capability. Moreover, the stored gas
absorbs water and liquid hydrocarbons from the reservoirs, but there are no gas processing/dehydration
facilities at the storage sites; thus, valuable natural gas liquids are not captured, and the introduction of
more "wet" gas into the pipeline system exa -bates the corrosion problem.
Gas Consumption
5.18         Natural gas is traditionally the main fuel in all end-use sectors in Azerbaijan (except in
transport). Gas consumption rose from 10.0 Bcm in 1980 to 13.0 Bcm in 1985 and 14.2 Bcm in 1990.
Trends in use since 1990 have been greatly influenced by the changing prices and availability of imported
supplies, and by the general decline in economic activity. In 1990 (the last year of relatively 'normal'
gas availability under the previous Soviet system) about 40 percent of Azerbaijan's gas was used for
power generation, with the remainder split fairly evenly among industry, district heating, the
commercial/public sector and household use.



-54-
Table 5.2: AzerbaUan Gas Supp& . Demand (Moion cubic meterslyr)
1990                 1991                   1992
Production              11,234.3             10,051.8                9,275.2
Venting                 1,308.9               1,430.7                1,430.7
Not Available           9,925.4               8,621.1                7,844.5
Imports                 13,114.0             14,170.0                5,263.0
Exports                 5,424.0               5,996.0                 951.0
Net Imports             7,690.0               8,174.0                4,312.0
Consumption            14,238.0              13,256.4                9,538.4
-Power+Heat             5,474.0               4,238.4                1,621.4
-Industry               3,051.0               3,118.0                2,467.0
-Commercial             3,012.0               2,730.0                2,600.0
-Distribution           2,701.0               3,170.0                2,850.0
Own Use/Losses          3,373.0               3,455.0                2,412.6
Balance                     4.4                  83.7                 205.5
Source: Azerigaz and Mission estwates
5.19          The main change in the pattern of gas consumption since 1990 has been a very sharp fall
in gas use in power generation. The availability of gas from Turkmenistan has been curtailed since early
1992, due to price disputes and changes in transit allocations to the Caucasus region by the Russian
authorities. Overall, gross imports from Turkmenistan fell from 11.9 Bcm in 1990 to 4.2 Bcm in 1992,
with a corresponding fall in re-exports to Georgia and Armenia from 5.4 Bem in 1990 to under 1.0 Bcm
in 1992. In addition, imports from Iran have dropped sharply, from 3.0 Bcm in 1991 to well under 1
Bcm in 1992, as a result of price increases. This supply disruption has forced a switch to fuel oil use
in Azerbaijan's dual fueled power plants, with the share of gas in power genera.ion falling from 62
percent in 1990, to only 21 percent in 1992, and gas consumption in power declining to 1.4 Bcm in 1992,
from 4.6 Bcm in 1990.
5.20          Gas usage by industry, where gas accounts for 90 percent of fuel supplies, fell by 21
percent in 1992, due to the decline in industrial output. Household and commercial demand has remained
relatively stable, the estimated annual fluctuations in use being partly due to the weather. Gas is used
for cooking, water heating and space heating, with most houses having some form of gas heating
appliance (for water or space). This pattern of use is different from that in most other areas of the FSU,
where a larger proportion of heating and hot water is supplied through district heating systems.
5.21          Most gas use in the country is un-metered. As shown in Table 5.3, nearly half of
industrial and power enterprises lack meters, and only 10 percent of the larger commercial/municipal
enterprises have meters. There are no meters in individual households. This lack of metering (and of
gas flow control on most heating appliances) not only causes problems of flow measurement and control,
but also prevents the implementation of an effective gas pricing policy based on actual consumption. At
present, un-metered household consumers are billed according to formulae based on household area,



-55-
persons per dwelling, and assumed usage of various gas appliances.
5.22          Azerigaz is also responsible for LPG distribution throughout the republic. Total supplies
of propane/butane in 1992 were 43,700 tons, which was supplied by the Karadag gas processing plant,
from the two Baku oil refineries, and from Russia. Azerigaz delivers these supplies by railcars (owned
by Azerigaz) to four bulk terminals, and also delivers about 99 percent of these supplies to households,
primarily in mountainous regions of the republic without piped gas service.
Table 5.3: Gas consumers and meters in Azerbaian, 1992
No. of consumers  No. with meters  Percent
Industry/power/heat              837           465            55.6
Municipal enterprises          2,341           361            15.4
Public institutions            8,325           731             8.8
Residential households      1,098,264            0             0
Source: Azerigaz
Outlook for Natural Gas Supply and Demand
5.23          The outlook for natural gas supply and demand has been examined in the same set of
scenarios used for oil supply and demand in Chapter 3. The projections suggest that it may be difficult
to increase domestic production substantially within the next decade, since production of associated gas
from the new oil fields is only likely to offset the natural decline in production from existing fields. The
new offshore fields are predominantly oil fields, with some associated and free gas, and resources are
thus not sufficient to offset the output decline from the existing large gas-condensate fields. Some of the
gas will also be needed for re-injection to maintain oil production. Continued substantial imports are
likely to be required, probably in the range of US$600-700 million per year, imposing a significant
burden on the economy. Thus, improvements in the efficiency of the entire gas system hold the best hope
of mitigating the high cost of imports.
5.24          Under the Base Case scenario, the rapid fall in oil production from existing fields leads
to a further decline in associated gas production until around 2000, when gas from Azeri and the other
new offshore oil fields begins to come on stream. By 2005, gas production would still be below the level
of 1992. Exploration of the offshore South Caspian basin can reasonably be expected to yield one or
more large gas/condensate fields that could be brought into production in the period 2000-2005.
However, the most important influence on gas supplies under this scenario is the recovery of vented gas
from the Guneshli field from 1995, which would prevent an even more rapid fall in domestic supplies
in the mid-1990's.
5.25          The venting reduction project, designed to recover about 1.3 Bcm/year of gas from the
Guneshli field that is currently vented, is particularly urgent. The project involves: (i) laying an
underwater pipeline from the Guneshli field to the Oil Rocks field; (ii) installing a gas compressor station
at the Oil Rocks field; and (iii) completing the partially built pipeline from Oil Rocks to the gas
processing plant at Karadag (via the Bakhar field). Because of the use of existing facilities and pipelines,



-56-
the total cost of this project is expected to be around $100 million. The annual saving in gas imports (or
alternatively, the gain from fuel oil exports) would also be around $100 million, suggesting that the
project is very attractive economnically. A foreign company (Pennzoil) is undertaking this project, as a
preliminary phase to the Guneshli field development project. It is important that the contractual
framework with the company set a proper precedent for future gas developments by foreign companies,
in terms of gas pricing (and liquids pricing) and contractual obligations.
5.26         Gas demand in 1993 is expected to remain constrained by limited availability of imports
from Turkmenistan. Azerbaijan's outlook for gas imports for 1994 and beyond is fraught with difficulty.
In addition to continued price increases from Turkmenistan, the transiting republics (Uzbekistan,
Kazakhstan, and Russia), joined by Chechenia and Dagestan (two autonomous regions within the Russian
Federation, through whose territory the gas pipelines pass) continue to press for higher transit fees. As
Azerbaijan has been unwilling to pay these high prices for gas imports, and has also found it difficult to
coordinate arrangements between the transit authoiities, the gas enterprise has developed, and begun to
implement, plans to reduce gas use in the country. These plans include the curtailment of gas service
to areas affected by the regional conflict, further reductions in gas deliveries to the power generation
sector (leading to higher fuel oil use), and increases in the delivery of LPG to households. In taking
these measures, Azerigaz must weigh carefully their real economic costs. For example, it is not clear
that restricting gas deliveries to the power sector is justified in terms of the cost of lost fuel oil exports,
since the export value of fuel oil in 1992/early 1993 was above the cost of gas imports. Additional
efforts to import gas supplies at a cost below the economic opportunity cost of fuel oil should be
encouraged.
5.27         From 1994, gas imports, and hence usage in the power generation sector, are expected
to return to 'normal" levels, accounting for around 70 percent of power sector fuel demand. Usage is
assumed to remain censtant in the medium term, with some of the modest increase in fuel demand for
power met by fuel oil use. The rise in gas import prices to "world levels" from 1994 would still make
gas somewhat less expensive than fuel oil in calorific terms. As shown in Table 8.1, at notional "World
Prices" imported gas from Turkmenistan would probably be up to 25 percent less expensive than fuel oil
valued at export parity. Even if the price margin in favor of gas were low or negligible, the operating
and environmental advantages of gas would still lead to its use in preference to fuel oil. Gas demand in
power could be expected to climb in 2000 and in 2004, due to the proposed construction of combined
cycle pov er plants (which further reduce fuel oil use).
5.-8         Demand in the industrial sector is expected to continue to decline in 1993, as the economy
restructures, out henceforth to remain stable. Despite the anticipated modest recovery in industrial output
from the mid-1990s no increase in gas demand is projected, due to the possible closure of some heavy
energy-intensive industries, and to an improvement in end-use efficiency in response to higher prices and
more widespread metering. Similarly in the commercial and residential sectors, demand is expected to
be constant, as higher penetration rates and household growth are offset by gradually improving
efficiency.
5.29         The net result of the projections is an increase in import demand for gas in the base case,
to 10.5 Bcm in 2000, slightly declining thereafter to 9.2 Bcm in 2005. The cost of gas imports at "world
prices" will rise from around $300 million in 1993, to $730 million in 2000.



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Tablk 5.4: Azerba#an Gas Supply - Demand (Dare Case) (Rcm)
1992     1993     1994     1995    2000      2005
Produotion          9.28     8.44     7.76     7.17     5.84     8.06
Venting             1.43     1.43     1.43     0.00     0.00     0.00
Net Available       7.84     7.00     6.33     7.17     5.84     8.06
Not Impons          4.31     4.15     9.00    8.04     10.46     9.18
Consumption         9.54     9.13     12.67   12.67    14.17    15.67
-Power++Hcat        1.62     1.45     5.00     5.00     6.50     8.00
-Industry           2.47     2.22     2.22     2.22     2.22     2.22
-Comm. +Distr.      5.45     5.45     5.45     5.45     5.45     S.45
Own Use/Losses      2.41     2.03     2.66     2.53     2.13      1.57
Source: Mission estimates
5.30          The outlook for gas imports in the other oil development scenarios is even less favorable:
*  Delay Case: If the new field development, the pipeline system rehabilitation, and the gas venting
reduction at Guneshli are delayed by two years, gas imports will rise very rapidly to 10.0 Bcm
in 1996, compared with 6.8 Bcm in the Base Case. The resulting increase in the cost of imports
by $220 million per year would represent a substantial setback to economic recovery. Imports
would remain above 11.0 Bcm from 2000 to 2004 due to the delay in production from new
fields.
- Low Production Case: The lower production of oil in the Low case leads to a lower production
of associated gas, with output in 2000 16 percent below the Base Case. Gas imports are
correspondingly much higher than in the Base Case throughout the forecast period: an additional
$70 million in the year 2000. Given the shortage of gas in Azerbaijan, there would seem litde
justification in delaying domestic production of natural gas in favor of imports.
5.31          There may be some prospects for cutting imports through higher domestic production,
but it is unlikely that imports can be eliminated before 2005 through higher output alone. Production
from the new offshore fields and Guneshli would have to be four times higher than the Base Case forecast
in 2000, and two times higher in 2005, in order to eliminate imports.
5.32          However, development of the offshore fields should emphasize gas production, in addition
to oil production, since the fields contain free gas horizons that could be independently developed. It is
important that these options be incorporated into development plans, and that agreements reached with
the oil companies provide for adequate incentives for gas development. In this connection, it should be
noted that terms which compensate foreign companies for gas production on the basis of a price related
to its economic value, and provide for them to take payment in oil for export, have proved successful in
encouraging investment in gas development elsewhere (eg. Egypt where companies have received a price
linked to world fuel oil parity). In the case of Azerbaijan, the reference price for gas purchased from
foreign companies would be the cost of gas imports, or the value of fuel oil exports. The level at which
natural gas is priced will depend upon the relationship between natural gas supply and demand. As



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discussed in Annex 5.4, domestic natural gas output displaces either imported natural gas or fuel oil (for
export), depending upon the level of domestic production, the demand for gas in power and the relative
economic value of gas imports and fuel oil exports. It is important that the gas price offered to foreign
companies be based on a relatively transparent formula, allowing them to make realistic assessments of
the costs and benefits of investt:.ent in gas production and capture. Provision for new gas processing
facilities should also be part of any integrated offshore gas investments.
5.33         Many of the undrilled structures lying in the deeper waters of the Caspian may be
predominantly gas bearing (though containing substantial quantities of oil and condensate). If this proves
to be the case, Azerbaijan could eventually become self sufficient in gas, and may even become an
exporter. For example, the Shach Deniz structure, on which exploration drilling by a foreign company
could commence in 1994 or 1995, may be a giant gas condensate field, containing over 140 Bcm of gas.
However, production, which in this case might reach 7 Bcm/year and thus greatly reduce the need for
imports, is unlikely to be significant before 2002. The scale of potential gas resources to be discovered
offshore reinforces the importance of establishing clear terms for natural gas development by foreign
companies.
5.34         There may also be scope for improved recovery of gas, and a moderation of the rate of
production decline, in the existing gas-condensate fields (such as Bakhar), possibly through joint ventures
with foreign companies. Development of these fields appears to have been undertaken primarily with a
view to recovering liquids rather than gas. There are also a number of discovered and partially developed
onshore gas fields that have not been brought into production. This was partly due to the extremely low
price of gas offered to the state producing companies, which was only 40 percent of the calorific
equivalent of the oil price until 1990. Since then the relative producer price of gas has fallen further to
only 8 percent of the oil price (at end 1992 - see Chapter 8). The price paid by Azerigaz to SOCAR
should be governed by the same principles as the price offered to foreign companies, in order to provide
economic incentives to gas exploitation.
improvements ip Gas System Efficiency
5.35         The best prospects for reducing the requirement for gas imports over the next decade are
through substantial improvements in gas system efficiency. This effort would require an investment
program on several fronts which should be made a high priority:
*  Replacement and rehabilitation of gas pipelines:  A large-scale program is required to
rehabilitate and replace corroded and leaking gas distribution pipelines throughout Azerbaijan.
As a prelude to this program a detailed study is needed to identify priority areas for investment
and the requirements of each part of the system. Azerigaz already has a reasonable inventory
of its own system and of the key problem areas, but this needs to be integrated with economic,
financial, and environmental analyses of the problem and alternative solutions, and with
consideration of the application of the latest technologies available on the international market.
Any program of rehabilitation and replacement would also consider the transmission system
(including improvement of compressor station efficiency), gas storage, associated equipment (e.g.
pressure reducing stations, SCADA systems) and gas processing facilities.
* Installation of gas meters: A pre-requisite to improving end-use efficiency is the installation
of gas meters in all industrial, commercial/institutional and residential consumers. Widespread
metering, coupled with controls for water and space heating appliances, would allow consumers



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to moderate their demand in response to higher prices. Azerigaz estimates that about 1.12
million meters of various sizes are needed for households and small commnercial establishments,
plus about7,100 larger meters for commercial/institutional and industrial users. At international
prices for such meters, the cost of this program would be some $100 million. Even with a rapid
installation program, it could take up to ten years to install meters for all consumers. While
Azerbaijan has the technical capability to manufacture gas meters domestically, the choice of
meter procurement method - imports or local manufacture - must be the result of appropriate
economic and financial analysis, including analysis of potential export markets for meters. If a
project to manufacture meters is justified, a joint venture with foreign private investors is likely
to be the most appropriate way forward.
*  Improvement in gas appliance efficiency: The installed base of gas appliances, both industrial
boilers and household cookers and heaters, is generally inefficient and obsolete. Allowing
impor;s from other countries should permit replacement of existing equipment by consumers who
can afford the new equipment. As with meters, a program to manufacture higher standard
appliances for domestic use (as a private joint venture) could well be justified, but final decisions
should not precede detailed feasibility and market studies. Depending upon the levels of saving
which might be achieved, a system to provide incentives (via rebates from Azerigaz) for
consumers to trade in particularly wasteful appliances and boilers could be introduced to
accelerate the elimination of older equipment.
*  Increased efficiency in power and heat stations: Azerbaijan's power and district heating
stations are relatively inefficient, reflecting their age (much of the capacity is over 20 years old),
the obsolete Soviet boiler designs, and the lack of combined cycle systems. A program to
improve the efficiency of these existing steam stations is urgently required. In addition,
accelerated replacement of some older steam capacity with combined cycle capacity may be
justified. Such options need to be examined within the context of a least-cost power investment
plan, taking account of the full economic costs of natural gas systems. Again, plans for
replacement of gas-using equipment and appliances must be based on appropriate economic and
financial analyses of the potential for gas savings and the costs of the new equipment.
5.36          The aggregate impact of an accelerated investment program to improve end-use efficiency
of gas will be significant, although it is difficult to estimate precisely. The Base Case projection shown
above incorporates some assumptions about increased efficiency to 2005, including a reduction in total
system use and losses to around 10 percent, improvements of about 25 percent in end-use efficiency in
the industrial, commercial/institutional and household sectors, and introduction of 800 MW of combined
cycle capacity.  This projection already assumes a substantial investment program  in pipeline
replacement/rehabilitation, metering, new appliances and power generation capacity.
5.37          A more optimistic projection of gas savings, based upon an accelerated investnent
program, could yield an additional 1.9 Bcm per year of savings by 2000, consisting of:
*     0.8 Bcm of reduced system losses through accelerated pipeline replacement (reducing
losses to the level of about 10 percent of throughput);
*     0.8 Bcm of consumer efficiency improvements (through accelerated meter and
appliance installation); and



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*     0.3 Bcm of power generation savings through replacement of an additional 400 MW of
steam capacity by combined cycle.
5.38         The annual savings in gas import costs from such an accelerated program of investment
would be about $130 million, representing a substantial return to an investment of up to $600 million
over the period 1995-2000. Coupled with the gas venting reduction program, these measures could
greatly reduce the need for gas imports, thus saving Azerbaijan up to US$250 million per year.
However, the precise scope and magnitude of investment in the sector should await the outcome of
detailed reviews of gas and power sector investment plans.



CHAPIER 6
ELECTRICITY
6.1          With an installed capacity of nearly 5,000 MW, Azerbaijan is the largest power producer
among the Caucasus republics and has played a key role in power exchanges within the region.
Azerbaijan has made impressive progress in extending electrification to the whole country and expanding
power supply to become a net exporter of electrical energy. However, a large part of its productive
assets are obsolete and require major refurbishment. Further, the disruption of trade within the FSU and
the war with Armenia are causing major constraints to this sub-sector's development. As it moves to a
market economy, Azerbaijan will have to restructure its power industry to make it more efficient. Also
energy prices will have to be adjusted to ensure cost recovery and provide incentives for end-use
efficiency. The declining demand for power will limit the need for capacity expansion in the medium
term, allowing Azerbaijan to carry out a least cost planning study before deeiding which plants to return
and rehabilitate. Further, introduction of appropriate technologies will help improve energy efficiency
and mitigate adverse impacts on the environment.
The System
6.2          Azerbaijan has an installed capacity of 4,908 MW, of which 692 MW is hydro-based and
the rest thermal, in 8 conventional steam thermal power stations and 4 hydropower stations. In 1991 the
energy generated was 23.3 TWh, of which 21.6 TWh was thermal and 1.7 TWh hydro; energy exports
were 3.3 TWh and energy imports 1.6 TWh giving a gross domestic supply of 21.6 TWh.
6.3          Of the total thermal energy generated in 1991, 49 percent was from natural gas, and 51
percent from fuel oil. However, because of constraints in natural gas supply the share of fuel oil in 1992
increased to 78 percent. Natural gas is supplied from local production and from Turkmenistan via Russia
through the Caucasian pipeline system which supplies also Georgia and Armenia. Fuel oil is supplied
from the refineries in Baku. The largest power plant is the newly constructed Azgres power station near
Mingechaur, which consists of 8 units of 300 MW, 7 of which are in operation. The turbine and
generator of one unit were completely destroyed in 1990 during an accident caused by a hydrogen
explosion and fire. Work is underway to replace the damaged equipment and to put the unit back into
service. The units were designed to burn gas as the main fuel and to use heavy fuel oil only as a back
up and, in particular, the boilers are not equipped with soot blowers. The use of heavy fuel oil as a main
fuel has, therefore, caused major operating problems including a significant drop in maximum capacity
and fuel efficiency. All other thermal power stations are also fuel oil and gas-fired since there are severe
restrictions in gas availability especially during winter. The units located at Baku, Sumgait and Gandja
provide process steam, district heating and hot water in a combined heat and power operation. The
supply of adequate quantities of natural gas is critical for the reliable operation of the power system. The
list of power plants is given in Annex 6.
6.4          The main hydropower stations are on the Kura river with the main purpose being
irrigation. The reservoir has significant sterage capacity (16 billion m3 at Mingechaur and 2.7 billion
m3 at Shamkor). Some of the equipment at Mingechaur was brought second hand from Manchuria at
the end of World War II as war reparation from Japan and has had to be retired. The installed capacity
at Mingechaur is now only 260 MW instead of 380 MW.
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6.5          A great portion of the thermal power plants are obsolete and all the units are not properly
equipped to reduce enviromnental emnissions (SO2, NOx and fly ash) especially when burning fuel oil.
Major investments would be required to refurbish the units in order to improve efficiency and reduce
environmental emissions to a level prescribed by Western standards. Most of the units are of Russian
design with a unit size varying from 20 to 300 MW. The disruption of trade within the FSU combined
with the high ruble inflation is having an adverse impact on plant maintenance. The power company
(Azenergo) is having serious difficulties with the procurement of spare parts mainly because of their high
cost and lack of financing. In 1991 the thermal plants achieved an average capacity factor of 58 percent
but power supply conditions could quickly worsen if the issue of timely supply of spare parts is not
addressed urgently. Further, the maintenance practices need to be upgraded and brought up to the
standards of a modem power utility.
6.6          High voltage transmission is provided through an extensive network of 694 km of 500
kV lines, 1,026 km of 330 kV lines, 1,331 km of 220 kV lines and 5,881 km of 110 kV lines. There
was one substation at 500 kV, 5 at 330 kV, 8 at 220 kV and 163 at 110 kV in operation as of June 1992.
The 500 kV network is part of the integrated system of the Transcaucasian interconnected system which
is controlled by a regional dispatching center at Tiblisi. Also a 330 kV line connects Azenergo's system
to the South Caucasian grid in Russia.
6.7          Subtransmission and distribution is carried out at 35 kV (6,333 km of lines and 636
substations), 6 and 10 kV (38,110 km of lines and 17,064 substations), and 0.4 kV (58,583 km of lines).
The number of customers supplied is 703,850, including 2,409 industrial, 6,065 commercial, 2,996
agricultural and 692,361 residential consumers and 3 independent distribution entities which supply the
three major cities (Baku, Sumgait and Gandja). The distribution network is generally in poor condition
and needs upgrading to reduce losses which are estimated at 20 percent.
Sectoral Organization and Managenent
6.8          The power sector is under the responsibility of a vertically integrated production Union,
Azenergo, which reports to the Cabinet of Ministers. Production units under Azenergo are organized into
53 "autonomous budget entities', whose management from the center is not well defined. Most of the
production units are experiencing serious difficulties in meeting target budgets because of the dramatic
increase in the cost of inputs (fuel, spare parts etc.), and this has led to inadequate system maintenance.
In general, Azenergo has been isolated from modem utility practices and needs to introduce modem
management and finance systems and provide extensive training in all its production units.
6.9          A key problem with the current institutional arrangement is that responsibility for policy
making and planning in the power sector is not clearly vested in any institution. Further, the Soviet
practice of planning only on the supply side persists, and there is no strategy to deal with the demand
side and end use efficiency. These key demand-side functions ought to be assumed by an independent
entity, probably linked to a Ministry of Energy, or similar institution. A related problem is the lack of
proper legislation covering the power sector. An independent regulator needs to be established to mediate
in a transparent way between the government, the power supplier and consumers, and to take account of
economic, financial, environmental and service issues. There should be a move towards corporatizing
and commercializing Azenergo, in line with its management's wishes, although account will have to be
taken of the lack of experience of such arrangements in Azerbaijan.



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Electricity Supply and Demand
6.10           Electricity consumption in Azerbaijan grew at 3.8 percent on average between 1980 and
1988. Between 1988 and 1990 consumption declined by 7 per cent. In 1991 gross supply was 21.6
TWh at about the same level as in 1990. Total domestic sales of 17.6 TWh were distributed between
industry (44%), agriculture (20%), residential (16%), commercial (7%) and distribution retailers (13%).
Internal use and losses represent 14 percent of gross supply, respectively, which is too high and reflects
the obsolescence of several power stations. However, the loss figure does not include distribution losses
below 35 kV in Baku, Gandja and Sumgait, since these networks are not managed by Azenergo, and
information is not readily available. While "non technical losses" are difficult to evaluate because there
is no customer management, they are expected to become significant as tariffs are increased. There is
a need to introduce a customer management system including proper billing and collections procedures.
Table 6.1: AzerbaUan - Ekecirk!y Balance
(GWh)
1985        1989         1990          1991        1992        percent
(1992)
Generation                20,702       23,306       23,152        23,450      19,770
+ Imports                  2,345        2,482        1,752        1,576
- Expors                   1,887       2,913        3,356         3,279
Net Exp./Imp.                458         -431       -1,604        -1,703        -633
Gross Supply              21,160       22,875       21,548        21,747      19,137
Losses &                    15%          16%          14%           13%        14%
Intemal Use                3,097        3,590        3,102        2,890       2,680
Net Consumption           18,063       19,285       18,446        18,857     16,457
-Industry                  9,437        9,150        8,482         8,873      6,972           42%
-Construction                659          640         573           558        530             3%
-Transportation            1,495        1,613        1,273         1,277       914             6%
-Agriculture               3,099        3,724        4,210         4,276      4,333           26%
-Residential &             3,374        4,157        3,901         3,872      3,708           23%
Commercial
Source: Azernergo.
6.11           The demand figures for 1992 show a significant drop in consumption for the industrial
sector, especially the chemical and metallurgical industries (where usage fell by 30 percent). The
declining trend in industrial demand is the result of the disruption in trade among the FSU countries and
is likely to continue over the next 3 to 5 years with the restructuring of industries. Demand from other
sectors is expected to soften in response to large tariff increases which need to be implemented over the
near term. From the mid-1990s, demand is expected to recover gradually as economic growth resumes.



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6.12         The current per capita consumption of electricity in Azerbaijan is about 3,080 kWh,
which is high compared to countries with similar GDP per capita. This is partly due to the large demand
from chemical industries, metallurgy and pumping for irrigation, but it also reflects the inefficient use
of energy particularly in the industrial sector. As in other FSU countries, the low price of electricity did
not provide incentives for the use of energy-efficient appliances nor for the development of energy-
efficient industrial processes. There is a substantial potential for energy savings and end-use efficiency
is an area where external assistance would be required. As a first step, however, tariffs need to be
increased and an entity in charge of energy policy, including demand management, needs to be set up.
6.13         On the supply side, although the existing installed capacity is 4,908 MW, available
capacity is only 3,821 MW due to obsolescence and various maintenance problems. About 2,000 MW
installed capacity have accumulated between 26 and 39 years of operation and may have to be retired over
the medium term. Construction of Unit-9, (300 MW), at Azgres is underway with commissioning
expected by end-1993 and Unit-1O is planned subject to availability of funds. A 75 MW hydropower
station, (2x37.5 MW), is being constructed at Yeniken on the Kura river, between Shamkor and
Mingechaur, with commissioning expected in 1995.
6.14         Power sector planning is carried out by the Energy Institute in Baku taking into account
load demand for various sectors (industry, agriculture, services, residential), availability of fuel, energy
savings and availability of funds. The hydro resources inventory has been partly completed and there
is an estimated capacity of about 1000 MW, of which 550 MW is in small units, under 10 MW unit
capacity, which could be developed competitively according to Azenergo. While limited refurbishment
of several power stations has been scheduled over the next 5 years, Azenergo is considering the
construction of 1,200 to 1,400 MW new capacity by 1998. A feasibility study of a 1,500 MW combined
cycle plant was carried out by the Rostov Institute (Moscow) in 1990. The plant would be located close
to Ali-Bairamli in a site originally earmarked for a nuclear plant. Azenergo is considering seriously
private sector participation in the project development but it has no experience in undertaking such a
scheme. While it will be necessary to justify the project with a least cost generation expansion planning
study, its implementation would allow the retirement of obsolete and inefficient capacity and would boost
power exports. Further, the project could be developed in phases (300 to 600 MW) to match the actual
demand.
6.15         The conflict with Armenia has caused major disturbances in the power supply to the
Nakhchevan province, normally fed by a 220 kV line through Armenia. A second hand diesel power
station, (4 x 16 MW), is being constructed as an emergency measure and a 4 x 35 MW combined cycle
plant is planned for the medium term provided that natural gas could be supplied from Iran.
6.16         There is a great potential for wind energy in Azerbaijan and the Baku region is well
known for its constant winds. The Energy Institute in Baku has been making wind measurement tests
in various sites and has prepared a wind map for coastal areas and rivers. A wind velocity between 4.5
and 10 meters per second is sustained over 3000 hours per year. Although some power generation
experiments were carried out with a wind mill of 4 to 6 kW, the generation cost was considered too high
compared to the low cost of fossil fuel prevalent at that time. With the increase of fossil fuel costs to
inernational levels the use of wind energy might be competitive. Further, the hinterland of Baku is
barren and hilly and would not pose any problems for installing windmills.



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6.17          Because of the dramatic equipment cost increases in rubles, the overall medium term
investment program would amount to about 120-150 billion rubles wbich would be clearly beyond
Azenergo's financial resources. Therefore, if the combined cycle project were to be implemented it
would be necessary to involve the private sector in the financing and operation. However, in view of
the uncertainty on load demand, any decision on Unit-10 at Azgres and on the combined cycle should be
deferred until a least cost generation expansion planning study has been carried out. The study should take
into account the prospects for power exports in the region.
Table 6.2: Load Forecast (GWh)
1991      1992       1993      1995       2000       2005
Gross supply*           21.7       19.2       17.4       17.7      19.8       22.9
Losses & lntenal use     14%       14%        15%       14%        13%        12%
Net Consumption          18.8      16.5       14.8       15.2      17.2       20.2
Load factor             67%        66%        61%       65%        65%        68%
Peak klod               3,700     3,310       3,250     3,130     3,480      3,850
* This does not take ito accow possible exports to Georgia
Source: Mission esimates.
District Heating
6.18          District heating is generalized in Azerbaijan and is provided by two state-owned entities:
(a) Teplokamunenergo all over Azerbaijan, except Baku; and (b) Bakteploset in Baku. Azenergo supplies
process steam to industries, heat and hot water to Bakteploset in Baku, and to Teplokamunenergo in
Sumgait and Gandja. In 1991 Azenergo supplied 15 million Gcal in process steam and hot water.
Teplokamunenergo supplied 1.6 million Gcal, of which 0.5 million were provided by Azenergo and the
rest from 850 heat-only boilers. Bakteploset supplied 2 million Gcal, of which about 1 million Gcal were
provided by Azenergo and the rest from 100 heat-only boilers. Losses in the system are high (13 to 20
percent), heat pipes are poorly insulated and water losses are significant (30 percent in Baku), mainly
because of corrosion and the lack of adequate sanitary cold water supplies in apartments.
6.19          Both Teplokamunenergo and Baktepioset provide heat at the entrance of the apartment
buildings. Municipal entities are responsible for the distribution and collection of charges from residential
consumers. There is no metering and the rates are based on the areas heated. For Azenergo the current
rates cover the current financial costs. For Teplokamunenergo and Bakteploset the current revenues for
heat sales do not cover costs and both had losses in 1991 and a greater deficit in 1992. Further, major
rehabilitation works are required to reduce water and heat losses. In view of the availability of gas in
most of the homes, the economics of district heating under the new set of relative prices will need to be
reviewed. A diagnostic study of the district heating systems to define the rehabilitation needs is also
recommended.



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Regional Trading of Power
6.20          The Azerbaijani power system is interconnected at 500 kV and 330 kV with those of
Georgia and Armenia constituting the Trancaucasian system with a regional dispatching center at Tiblisi.
There are major economic benefits associated with the combined operation of the Georgia and Armenia
systems, largely hydro-based, and the thermal based system in Azerbaijan. In view of the conflict
between Azerbaijan and Armenia, however, the regional dispatching center no longer plays its role and
acts only as a mediator on bilateral agreements between the countries. During 1991 Azenergo exported
1.7 TWh to Georgia and Armenia at a rate of 4.75 R/kWh. In 1992 there were no exports to Armenia
and exports to Georgia amounted to 633 Gwh at a rate of about US$0.04/kwh.
Environmental Aspects
6.21          There are no fly ash or SO2 emissions associated with gas fired generating plants.
However, the increasing use of heavy fuel oil with a high sulfur content in generating plants which are
not properly equipped to burn such fuel may result in localized higher harmful emissions. In 1991,
however, the figures given for the emissions of SO., NO. and V205 are within the limits imposed by the
FSU standard. As imports of crude oil declir,e, high sulphur fuel oil based upon imported Russian crude
is being replaced by lower sulphur fuel oil derived from higher quality local crudes. Nonetheless, there
is a need to increase the quantities of gas available and reduce the burning of fuel oil, since this promotes
both better plant performance and reduced environmental emissions.
Table 6.3 Annual Emissions from Existing Power Plants
(tons)
NO,                  so2                  Solid
1. Azgres (2,400 MW)                    8,802               24,323                 830
2. Ali-Bayramli (1,050 MW)             13,286                17,704                73
3. Sevemaya (300 MW)                    1,840                1,274
4. Sumgait CHP-1                        4,606                4,015
5. Sumgait CHP-2                       4,391                 2,043                 45
6. Baku CHP-1                           2,396                 934
7. Baku CHP-2                           403                   326                   12
8. Gandja CHP                           1,270                 925
Source: Azenergo



CHAPTER 7
ENERGY SECTOR INSTITUTIONAL REFORM
7.1          Upon its independence in September 1991, Azerbaijan inherited an institutional structure
in the energy sector which had formed a part of the Union-wide system under the FSU. Thus
Azerbaijan's institutions were merely branches, usually minor ones, of Union-wide institutions controlled
from Moscow. Local capacity for energy policy formulation, handling of commercial matLers and
international trading and relations was limited. Along with the general Government institutional structure,
Azerbaijan's energy sector institutions have been going through a period of rapid transition. In many
respects Azerbaijan has made important strides towards rationalizing and reorganizing its energy sector.
However this process has been hampered by the lack of experienced local staff, and by the more general
instability and lack of organization in the Government. Much therefore remains to be done to create an
efficient framework for the transformation of the energy sector within the transition to a market economy.
Energy Sector Governance
7.2          Azerbaijan's central government institutions concerned with energy are weak, even in
relation to those of other FSU republics. Under the administration of the Soviet Union, Azerbaijan had
no independent policy making and administrative capacity for energy. Such centralization as existed
within Azerbaijan was in the hands of the local State Planning Committee (Gosplan), which carried out
the republic's share of the overall Union planning effort.
7.3          Since independence, the responsibility for energy policy and coordination has become
diffused. Azerbaijan has not set up a centralized Ministry of Energy, nor any other body capable of
assuming this role, as has been done in other FSU countries. To some extent this had been due to a
general lack of clear separation of power between the legislative (Parliament, Council of Ministers) and
executive (Presidential office) branches of Government. Ministerial responsibility for energy lies with
a First Deputy Prime Minister, who has a number of other important portfolios. He is supported by a
very small staff of specialized civil servants, although in some cases their roles go beyond energy (for
example the responsibilities of the office dealing with power also cover all other branches of heavy
industry).
7.4          In addition, other Ministries play a role in the energy sector, particularly the Ministry of
External Economic Relations, which is responsible for overseeing energy trade. The Ministry of Finance
oversees and controls the revenues generated from petroleum products taxation.
7.5          Given its importance to national policy, there is also an important element of energy
policy making within the Presidential office. Thus all important decisions are taken both by the Council
of Ministers and by the President's office. The President's office also has primary responsibility for
drafting new basic legislation, including that covering the energy sector. This situation reflects some of
the continuing constitutional uncertainties affecting the Government of Azerbaijan following
independence.
7.6           The role of Gosplan has been subsumed by the Ministry of Economy, and has diminished
greatly with respect to energy, although some of the traditional reporting and target-setting systems
remain in place as formalities. The Ministry of Economy's main role appears to be in assisting with
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energy price setting, since it has the capacity to undertake the necessary cost and revenue analysis.
7.7          In the absence of a strong central coordination of energy policy, considerable power has
devolved to the heads of the key enterprises, particularly the leadership of the State Oil Company. There
is limited ability on the part of goverment to take action against the wishes of the state enterprises,
which largely control the evolution of policy in their areas. There are some advantages to this situation
in that bureaucracy is limited and little effort is dissipated in unproductive monitoring and reporting.
Recent moves to establish a part-time "Energy Commission", staffed by representatives of Govermnent
and energy enterprises, to advise the Deputy Prime Minister and other senior officials on energy policy
represent an acknowledgement of the need for stronger central coordination and oversight of policy.
However, Azerbaijan will need a more focussed and permanent institution at this level as it evolves its
mode of governance towards a more stable system.
7.8          A central body should be established to coordinate energy policy and supervise the
activities of the energy enterprises. This body should not be a large bureaucratic entity, but a smaller
policy-oriented institution, with a limited number of professional higher level staff. It may take the form
of a small Energy Ministry, under a Minister, or could be an "Energy Commission", reporting to a
Minister or to the President directly. Creation of multiple institutions (eg. a large Ministry S a
Commission) should definitely be avoided. Similarly, it would be inappropriate to set up specialized
Ministries for each sub-sector (eg. Petroleum, Power etc), since this would create redundant parallel
structures to those in the enterprises. Small independent regulatory and supervisory bodies for the energy
enterprises could be situated under the Ministry/Commission.
7.9          The responsibilities of the Ministry/Commission would therefore include:
* Setting overall energy policy priorities on an amnual and multi-year basis;
*  Advising the Government on particular energy policy problems (eg. energy trade issues,
legislative matters, agreements with foreign companies etc.);
*  Establishing the framework for energy pricing and supervising implementation of energy pricing
by the enterprises;
*  Acting as the umbrella body for regulatory agencies covering such areas as power, natural gas,
petroleum licenising etc.;
*  Acting as a central gathering point for key statistical, operations and financial data on the energy
sector;
* Coordinating matters of enviromnent, safety, standardization etc. with other responsible
specialized agencies.
Energ Sector Legal Framework
7.10         Azerbaijan did not inherit from the Soviet Union a legal framework for energy suitable
for an independent country moving towards a market economy. Laws do not clearly establish such
matters as ownership of energy resources and the possibility of foreign participation in their development,
the legal status of the energy utilities or the regulatory framework covering energy enterprise operations.



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7.11         In the petroleum sub-sector, a Petroleum Law (covering both oil and natural gas) is
needed to establish the framework for SOCAR's operations and for investment by foreign companies in
petroleum development. Such a Law should cover the ownership of resources, the status of SOCAR, the
rights and obligations of private and foreign investors in upstream oil and gas, and arrangements for oil
and products trade, processing and marketing. It is important that this law is established separately from
that covering other mineral resources and energy sources (eg. electricity), to avoid unnecessary
complexity and ambiguity. The law should be accompanied by provisions for establishing standard
contract terms for foreign investors in petroleum exploration and production.
7.12         A regulatory framework is needed for the natural monopolies, such as power, natural gas
transmission and distribution and district heating, which establishes the duties of the utilities, the system
for price and tariff setting, the rights and obligations of consumers and the potential for participation by
private or independent operators within the system (eg. through access to the grid for independent
generators or to pipelines for gas producers). These laws would set up regulatory institutions which
would be charged with implementing the regulations for the various utilities. Such institutions should be
independent from political influence, so as to ensure fairness and consistency of application of regulatory
principles over time.  Thus they should have statutory independence, and budgets which are set
independently by parliament or through levies, even if they are situated under the umbrella of an Energy
Commission.
Energy Enterprise Reform
Petroleum
7.13         In the petroleum sub-sector, Azerbaijan has initiated a substantial process of restructuring,
which puts it among the leaders within the FSU countries in restructuring the oil industry. In September
1992, a Presidential Decree founded the State Oil Company of the Azerbaijan Republic (SOCAR) to
encompass all activities connected with exploration and production of oil and gas, refining of oil and bulk
transport and storage of crude oil. Control of internal oil product transport, distribution and marketing
remained with the State Fuel Committee (Goscomtopleva).
7.14         Prior to independence, Azerbaijan's upstream oil industry consisted of two "Production
Associations" (PAs), which were part of the network of such bodies comprising the Soviet oil industry.
Tht. Azneft PA controlled all onshore fields and some of the shallowest offshore fields, while the
Kaspmorneftegas PA controlled all the remaining offshore fields. Each of these PAs in turn ccmprised
a series of relatively autonomous units, which included the producing operating units (NGDUs), and
separate units concerned with construction, transportation, drilling, well workovers, research institutes
and administrative units for such areas as safety, marine inspections, communications, training and
environment.
7.15         This structure had two fundamental weaknesses: firstly, there was a large scale duplication
of functions as each unit had its own technical and administrative staff, secondly, there was little strategic
coordination between the units, with each unit performing a narrow function linked to certain (usually
physical) targets. The PAs and NGDUs were thus characterized by overmanning and inefficiency in
drilling and production operations. In addition all key exploration and production decisions were taken
by specialized Institutes, which handed inflexible instructions to the NGDUs. The ability of the NGDUs
to adapt these instructions to conditions encountered in the field was highly limited, while the Institutes
took too little account of the NGDU's practical experience.



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7.16         The first reform of the sector undertaken following independence was to group the PAs
together under a "State Concern", Azerineft. This Concern, however, was little more than a holding
company, and the two PAs continued to function very much as before. The main function of Azerineft
was to replace the PAs as the primary focus for high-level negotiations with foreign oil companies.
However, Azerineft had little manpower, and was dependent on the PAs for negotiations back-up.
7.17         The downstream petroleum sector prior to restructuring consisted of the two refineries
(operating as separate units), the fuels distribution organization, "Goscomtopleva" and the crude oil
pipelines company "Transcaucasian Main Pipelines Association". While nominally under the control of
various Government and Planning Committee units, the refineries in practice had some operational
latitude. The fact that the refineries accounted for all of Azerhaijan's oil trade gave them a key economic
role, which was not matched by the official oversight of their activities. After independence an attempt
was made to place the refineries, and some petrochemicals and lubricants plants under a separate holding
company, 'Azneftechim", although this seems to have had little practical effect.
7.18         At the time of SOCAR's founding, the PAs were officially dissolved, and the refineries
and crude pipelines company integrated into SOCAR. The concept behind SOCAR appears to be that
of a modem integrated petroleum company, functioning in both the upstream and downstream areas.
7.19         SOCAR's structwue has been evolving as the management seeks to adapt organization
concepts to the existing reality of the industry. SOCAR is intended to consist of a number of key
departments, each fulfilling a specific business function: Exploration and Production, Refining, Machinery
and Equipment Supply, Drilling, Planning and Construction, and Offshore Fleet Services. Each of these
departments is overseen by a Vice President, reporting to the President of the Company. The President
is advised by a Strategic Planning department reporting directly to him. The President in turn reports
to a Board, of which he is chairman. The members of this Board include both the key Vice Presidents
of SOCAR, and a number of external directors. The President of SOCAR and all members of the Board
are appointed by the President of the Republic.
7.20         SOCAR retains a virtual monopoly of petroleum trade. Some activity in petroleum
products barter and trade by other organizations has recently been permitted, but all transactions must
be physically handled by SOCAR. In circumstances where the substantial revenues generated by
petroleum trade in the pubiic sector have been difficult to control, such an emphasis upon physical checks
of all flows is understandable. However, the granting of such a monopoly of trade services should be
seen as a temporary measure, pending establishment of more reliable customs, fiscal and financial
controls.
7.21         While the establishment of SOCAR represents an important step in restructuring the
petroleum industry away from the previous Soviet model, a number of issues remain to be clarified:
*  The extent to which the second level of organization has been restructured remains unclear. It
is quite possible to reshuffle existing units between major departments without affecting the
inherent inefficiencies of the units themselves. In this respect, the inefficiencies inherent in the
Institutes and NGDU system do nJt appear to have been fundamentally altered, nor has the
internal organization of the refineries been substantially changed by their integration into
SOCAR;
* The reporting relationships between the units are undefined. Thus there appears to be little



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distinction in the hierarchy between a setvice unit such as construction (which is a cost center)
and an operating unit such as exploration and production (which is a profit center);
*  The inter-departmental charges for services have not been clarified, with the basis of internal
costing of goods and services not fully established, and transfer pricing therefore does not reflect
the true financial cost of goods and seivives provided.
7.22         At the broader institutional level, the degree of oversight of SOCAR's operations by
Government has not been well established. As stated previously, it is desirable that a policy coordinating
and regulatory body for the whole energy sector be established at national level. The creation of a large
coiu-pany, such as SOCR, with a de-facto (and possibly later de-jure) monopoly over all oil and gas
production and processing, establishes an extremely powerful economic force, accounting for a large
share of Azerbaijan's economic output, investment and trade. 'While the appointment of outside directors
to the board represents some degree of oversight, the ability of these directors to monitor the activity of
such a complex organization will necessarily be limited. It is therefore desirable that SOCAR is overseen
by a capable regulatory unit within a central Government department. This applies in particular to
agreements with foreign companies for exploration and production, where a Government licensing
authority is required.
7.23         ,t is also important to keep the finances of SOCAR separate from those of the
Government. This means that SOCAR's role in the agreements with foreign petroleum companies should
be to represent the Government, and to participate in exploration mid development as a national partner.
SOCAR may obtain its own share of production as a partner in oil and gas ventures. However, the
Government's share of petroleum production and revenues should be allocated directly to the Government
through the agreements. SOCAR should not appropriate to itself all the revenue due to the Government,
since this confuses SOCAR's role as the national oil company with the role of the state Treasury in
collecting taxes. Commercializing SOCAR means allocating to it only those revenues needed to sustain
its business efficiently, with excess profits captured through appropriate taxation. SOCAR can act as an
agent of the Government in marketing the Government's share of oil and gas production, but the accounts
for such activities should be kept separately from those of SOCAR's main activities.
7.2a         In terms of SOCAR's restructuring, the decision to proceed to form a single integrated
state oil company, with a highly centralized management, should be seen more as a pragmatic step in the
restructuring process, than as an end in itself. Within the post-Soviet disorganization of this fundamental
industry, the government's move to centralize control of oil-related activities can be justified as part of
the process of restructuring the economy and gaining full control of public finances. However, the
further evolution of SOCAR, should stress structural steps which are key to the creation of an efficient
petroleum industry:
* The role of the "center", clustered around the President and Board, should be focused on
strategic direction and major investment and policy decisions. Other decisions, including some
of great importance, should be delegated downwards through the organization on a steadily
declining and well defined scale of authority. This will help to prevent the bureaucratic paralysis
and gross ovennanning at the center which characterizes many large state oil companies.
International advisors, highly specialized in specific areas such as negotiating agreements with
foreign oil companies, should be used routinely to accelerate SOCAR's operations while its own
staff gain experience;



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* A system of internal charging for goods and services should be established, based upon true
financial costs, so as to provide a clear picture of the profitability and performance of each unit
and allow comparison with the local and international marketplace. This is important both in the
sales of crude oil by the production department to the refinery department (which should be based
upon internatienal parities) and in the provision of such services as drilling anf c,onstruction by
central ted departments;
*  As the company is commercialized, ancillary companies unconnected with core petroleum
operations (housing, tLrming etc.) should be spun-off and privatized as a priority. Increased
contracting out of services currently provided exclusively by SOCAR's internal iuits (eg.
drilling, maintenance, marine services) nicds to be introduced, to establish a sound competitive
basis for internal suppliers and to improve efficiency (OECD companies routinely contract out
most routine drilling, maintenance and support services);
*  Financial and management information systems need to be established across the company,
allowing rapid communication and consolidation of key performance data, appropriate short term
and medium term planning and budgeting, and comprehensive financial reporting on a transparent
and internationally comparable basis;
* Work to establish the need for the restructuring of producing and refining facilities (including the
older oil fields and the refineries, see Chapters 2 and 4) should commence immediately, so that
the restructuring of these facilities can be undertaken as part of the general reorganization. This
will avoid the creation of entrenched non-viable units within the new company which may be
difficult to eliminate or reduce in size;
3  A large scale training program needs to be established, to familiarize staff with all commercial,
managerial and financial aspects of the restructured company. This program should complement
the development of a comprehensive personnel system, to improve the quality of staff selection
and to create an effective system of staff incentives.
7.25         By following these principles, SOCAR could evolve in the medium term into a holding
company for a number of commercial subsidiaries (upstream oil, refining, construction, oil pipelines etc.),
or could eventually be split into separate companies. The ability of SOCAR to compete with private
companies for business within Azerbaijan and abroad will steadily grow. Privatization, in whole or in
part following an early move to joint stock status, should also be an aim.
7.26         In assessing the future of SOCAR, the increase in its scale of operations as Azerbaijan's
oil production grows must be borne in mind. With a move to world pricing, SOCAR could by the year
2005 have revenues from crude, oil product and natural sales of $1.0 billion for its own account.
Assuming SOCAR acts as the Government's agent for oil and gas sales, the amount of oil its handles
would grow from 11.1 million tons in 1992, to 26 million tons in 2005, as well as 8 Bcm of natural gas
per year. Although much of the activity and investment in Azerbaijan will be undertaken by foreign
companies, SOCAR will nonetheless have to maintain a key role as a partner in the US$12bn integrated
offshore development projects. With time, SOCAR's own investment budget will also rise to match the
growth in its cash flows and commercial capacity.
7.27         In order to address the restructuring issues raised above and prepare for the growth in
its scale of operations and role in the economy, SOCAR will need to seek advice from international



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consultants in organization, financial systems, petroleum production and refining operations. In addition,
training and human resource development wIll have to be undertaken on a large scale. This capacity
building program should be a priority within the framework of energy sector technical assistance.
7.28         As concerns petroleum product storage, distribution and marketing, this is an area suitabl--
fbr early privatization and introduction of competition. The first candidates for such privatization Coulf
be the retail oil product stations, which could be sold off to individual operators (or in modest lots - but
avoiding creation of local monopolies). Provided that construction of new stations was free!y permit!ed
(subject to reasonable local planning rules) the retail price of gasoline and diesel could be iiberalized at
an early stage to provide for both price and service competition among existing stations and new entrants.
Petroleum product tankers could be privatized (along with general trucking services), as could petroleum
storage services (based upon reasonable regulated charges).
Natural Gas, Power and District Heating
7.29         In all of the energy network sectors (natural gas, power, district heating), the key issues
concern the restructuring of sector operations along efficient lines, and the appropriate regulation of the
resulting natural monopolies.
7.30         Of these sectors, only natural gas has undergone significant organizational restructuring
since independence. Before the dissolution of the Soviet Union, gas transmission and storage was
controlled by Aztransgas, a unit of the all-Union Gazprom enterprise. Unlike many of its counterparts
in other Republics, however, Aztransgaz was a pure transmission company, without any production
operationi. Gas production and processing were the responsibility of the petroleum PA's (since the
primary purpose of this activity was the recovery of liquids). Gas distribution, along with oil product
distribution, was the responsibility of Goskomtopleva, the State Fuel Distribution Committee.
7.31         In September 1992, Aztransgaz and the gas distribution activities of Goskomtopleva were
merged into a single company, Azerigaz. The central transmission department is located at company
headquarters in Baku; distribution is divided into 5 zones (comprised mostly of small towns and rural
areas) plus 6 major cities (where most of the industrial activity is centered). The distribuftion departmens
are also responsible for Azerigaz' LPG business. Azerigaz also incorporates two research institutes on
technical gas problems (employing 560 people) as well as various construction, transport and ancillary
subsidiaries. There are in addition some subsidiaries manufacturing gas equipment and appliances
(although not on a scale to meet the country's needs).
7.32         Azerigaz buys gas from SOCAR, and also acts as the Government's agent in negotiating
gas purchases from abroad (Turkmenistan and Iran). The President of the company reports to the Council
of Ministers, which must clear price changes, gas laws, investment plans and import levels. The Ministry
of Economy (formerly Gosplan) approves and oversees Azerigaz's budgets.
7.33         The power sector is under the responsibility of a production Union, Azenergo, which
reports to the Cabinet of Ministers. All activities are vertically integrated under the General Director of
Azenergo assisted by one Chief Engineer heading generation and associated technical services and four
Deputy General Directors. Under Azenergo's supervision the production units are organized into 53
"autonomous budget entities". While the units have autonomous budget, their management and control
from the center is not well defined. At the Baku No. 1 power plant an experiment has been undertaken
in leasing out the assets to the workers, but this practice is controversial and has not been generalized.



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District heating is less centralized, with the system in Baku managed separately from that in the other
urban areas. The entities in this sub-sector remain substantially unreformed.
7.34         For natural gas, electricity and district heating, the key issues of restructuring are similar:
*  Effective regulation of these entities should be introduced, under a transparent statute setting out
clearly the functions of the company and 'he regulator. There is a need for the establishment of
an independent, arm's length, transparent regulatory process between the government, the utilities
and consumers as an intervention point for consideration of economic, financial, environmental
and service issues. This will help create transparency in the way Government interacts with the
sector and would facilitate commercialization and corporatization of the sector entities, as well
as facilitating participation by private capital;
*  Tbe vertical integration of the utilities, and their national scope, should not provide a cover for
inefficiency through cross subsidization, or a lack of transparency in costing. Tariffs should be
set for each stage of operation, from generation (in power and heat) through transmission and
distribution, so that the full costs of system operation are reflected in charges (although there may
be a need for a transitional period, see Chapter 8). This charging structure should be reflected
in an organizational structure encouraging autonomy of function
(generation/transmission/distribution) and region, within the limits set by efficiency and scale
considerations;
*  Commercialization should be a goal for all operations in this area, so as to improve efficiency
and allow utilities to raise capital from sources other than Government. This will have to include
the separation of ancillary activities (such as construction, housing and equipment manufacturing)
from the main companies, with spinning-off and privatization the preferred options where viable.
There should be a move towards a contracting out of services (eg. maintenance) currently
provided solely by in-house departments;
*  Supply-side planning needs to be supplemented by demand-side planning, so as to put in place
mechanisms to improve energy efficiency and environmental performance. Oversight of demand
side planning may need to lie outside the utilities, within the central regulatory and policy making
functions of Government. There is scope for an agency to promote energy efficiency and
conservation;
*  All utilities need to introduce modem financial, management and information technology systems,
including systems for handling customer billing. This will have to be accompanied by intensive
and large scale training of personnel in such systems and modern utility practices;
*  In the longer term, the possibility of participation by independent operators needs to be
established, including independent generators of power and heat, independent gas producers and
independent owners of power and gas transmission facilities. Although it will be some 'iqe
before a competitive system of energy supply can be introduced, the potential for participation
of independent entities should be set within the regulatory framework from the beginning.



CHAPTER 8
ENERGY PRICING POLICY
8.1           Azerbaijan's energy prices, as in other FSU republics, are substantially below world and
economic levels. While the government's policy is in general to bring prices into line with the world
market, this process has been retarded both by the rapid devaluation of the ruble, and by a reluctance to
impose very sharp price rises on consumers. The result is a system in which producer prices are too low
to permit both recovery of current operating and maintenance costs and investment in producing and
transport infrastructure, and in which there is massive cross subsidization between industry and residential
consumers. As energy prices are now the most significant prices remaining under state control (most
other prices have been freed), price policy in the energy area will be a key part of Azerbaijan's economic
reform agenda.
Energy Pricing Framework
8.2           Energy pricing policy in Azerbaijan should seek to reflect the general principles of
economic pricing. As in other FSU republics, the key issues concern the pace and pattern of the
transition towards such a pricing structure. Within the FSU Republics, the transition process has in large
part been dictated by trade patterns: Republics which are fuel exporters have tended to set prices for those
that are fuel importers. The exporters have been seeking to gain revenues from the importers and to
reflect world market realities, under which the option exists to sell at world prices rather than at artificial
iner-republican levels. The main constraint on the pace of price rises is the ability of the importers to
pay and inter-dependencies in other products, which create the possibility of trade-offs between energy
and non-energy products. For importers faced with rapidly rising fuel prices, the choice is between a
rising subsidy burden, or a deficit by fuel distributors, or passing on price rises to a population already
suffering general economic hardship. An additional important factor, particularly in the case of
petroleum, has been the often limited capacity of authorities to control trade by individual enterprises,
with a rapidly growing quasi-official and unofficial market setting prices in many regions. Finally, the
complexity of the energy sector varies greatly in different republics due to their different geographic scale
and fuel mix; fuel pricing in thP l-.ger more diverse republics is more problematic than in some of the
smaller republics.
8.3           Azerbaijan possesses a number characteristics which could help to define the pace of the
transition in prices. In general, these make energy price reform in Azerbaijan more straightforward than
in some other republics:
*   As a net exporter of oil and oil products, the country is in a position to be a price setter for oil
products -in theory it can regulate the pace at which internal prices approach "world" levels at
the ruling exchange rate, without explicit domestic subsidies to petroleum enterprises;
* As a large net importer of natural gas, the country is a price taker for this fuel - it can only
control the evolution of prices to end-consumers by explicit subsidies, however, as a large
producer it can also trade-off lower prices for domestic gas against higher import prices;
*   Azerbaijan has a single enterprise controlling all oil production, refining and trade. This allows
a much closer policy control over petroleum prices than in many other republics, where the
sector remains highly fragmented;
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* The natural gas and power sectors are organized within single vertically integrated national
companies, which facilitates an orderly process of price adjustment between various consuming
sectors and regions;
*   Azerbaijan largely depends upon two fuels, oil and natural gas, both of which are
internationally traded within the region, pre-iding market reference levels. Prices for other
final energy supplies (electricity, heat) are largely set in relation to the cost of gas or oil inputs.
In this sense Azerbaijan avoids some of the pricing difficulties experienced by Republics with
large untraded energy sources (coal, nuclear, hydro);
*   Azerbaijan is a relativeiy compact country, with good transport links which limits the need for
geographical disparities in prices;
*   Azerbaijan is a key supplier of certain industrial products (eg. petroleum equipment, air
conditioners, refrigerators) and of agricultural products to other republics, which provide some
leverage in inter-republican price negotiations.
Recent Pricing Trends
8.4           Table 8.1 shows the structure of energy prices in Azerbaijan, and recent trends of key
fuels in relation to international prices. Figure 8.1 shows prices in Azerbaijan in relation to two other
major PSU countries which are also large energy producers (Russia and Kazakhstan)'. A number of key
features stand out:
*    Azerbaijan has been relatively slow in raising its fuel prices towards international and economic
levels in comparison with other FSU countries, particularly for oil and oil products;
*   The producer price for crude oil is low in relation to that in other producing countries and has
been falling in real terms;
*    Fuel oil remains the oil product whose price is lowest in relation to interational levels;
* The price of diesel has been raised far less than that of gasoline, causing diesel prices in
Azerbaijan to lag behind prices in other FSU countries;
*    The producer price for natural gas has remained exceptionally low, and bas falen as a
proportion of the import price from Turkmenistan;
*    The price of gas from Turkmenistan increased substantially in real terms in 1993;
*    Prices of natural gas to residential consumers remain exceptionally low and have fallen in
relation to prices to industry;
'The prices shown in Table 8.1 and discussed in the text are in Rubles. In August 1992 Azerbaija introduced the
Manat, which has circulated in parallel with the Ruble (at an inital rate of 1 Manat-10 Rubles).



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*    Prices of electricity have been raised substantially, but prices to industry are much higher than
those to residential consumers, and the gap between the two has grown in relative terms.
8.5             The Government's stated policy has been to raise energy prices to economic levels as
rapidly as social and financial circumstances permit. However, the trends above demonstrate that the
process of transition to economic pricing levels in Azerbaijan has not been proceeding in a smooth or
coordinated manner. Much of recent pricing policy has reflected expediency or a delay in taking socially
contentious decisions, rather tharn a clear policy of price reform.
Tabke 8.1 Azerbajan Energy Pries
% of World
World Price          Price
August      February       February         August   February 1993
1992          1993          1993            1992
Oil
Producer Price (Rb/ton)              2197           6500         71400'          10.5%            9.1%
Fuel Oil (Rb/ton)                    1250           6830         609502           7.0%           11.2%
Gasoline
Retail (Rb/ton)                     4791         35100        124950'           13.0%          28.1%
Retail (Rb/liter)                   8.00          27.00
Diesel
Retail (Rb/ton)                     5786         22000        113050'           17.4%           19.5%
Retail (Rb/liter)                   7.00          20.00
Natural Gas
Producer Price (Rb/mom)               300            600         41650'           2.4%            1.4%
Iinports(Turkmen)(Rb/mcm)            1700          15000        416504           13.9%           36.0%
Power (Rb/mcm)                        305          18377         476005           2.2%           38.6%
Industry (Rb/mcm)                    2450          18377         595005          14.0%           30.9%
Commercial (Rb/mcm)                   305           3294
Residential (Rb/mom)                  250            720        1900005           0.4%            0.2%
Electricity
Industry (Rb/kwh)                0.24-0.38      3.85-5.70         45.06      1.8%-2.9%      8.6%-12.7%
Commercial (Rb/kwh)                  0.38           7.70
Residential (Rb/kwh)             0.04-0.06      0.50-0.80         80.06     0.2%-0.3%        0.6%-1.0%
Exchange Rate (Rb/US$)                                             595             175             595
Source: Govermnent of Azerba#jan and Mission estimaes.
1. Arab Light $130/t cif NW Europe, plus $15/t quality differential, less $25/t transport Baku-NW Europe.
2. Low Sulphur Fuel Oil $122/t cif Turkey, less $20/t transport Baku-Turkey.
3. Cif Turkey prices ($240/t gasoline, $220/t diesel, less $30/t transport Baku-Turkey).
4. Turkmen gas price based upon European border price of $95/mom, less $25 transport differential.
5. Turkmenpriceplus notional$10/mom forpower, $30/momforindustryand $200/mom forcommercial/residentialcuatomers.
6. OT.CD Europe averages of $0.08/kwh for industrial and $0.14/kwh for residential.



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Figure 8.1 Energy Prices
Azerbaijan vs. Russia and Kazakhstan
February 1993           (Russia a 100)
400
_ Azerballan   E3 Kazdkhstan   EEI1 Russia
3 b00.    
0
.220.ji-2 -
Oil      Gas      aoline   Dlel         Fuel       Oa    ElectrIcity
Producer ProN%uor   Retall    Retail       01I    Industry  Industry
Source: Govewnenm of Azerblaian. Rwsia and Katzakktan and Miwon et*nates.
Energy Price Reform
Energy Pridng and Economic Reform
8.6           Energy price reform is an important part of the economic adjustment process. Pricing
reform for energy should be coordinated with overall macroeconomic reform. It is particularly important
that energy price adjustments be accompanied by appropriate monetary, fiscal and exchange rate policies,
so as to ensure that energy price increases are not neutralized by inflation or exchange rate movements.
Appropriate fiscal measures must be in place, so that the effects of price changes on enterprise
profitability are properly offset, and the effect on the Government budget is in keeping with
macroeconomic targets.
8.7          Setting energy price targets, in terms of international parities or economic levels is thus
an essential part of an economic adjustment strategy. In Azerbaijan, because of the relatively
straightforward nature of the price transitions required, it is recommended *hat pricing reform to
economic levels be aimed to be attained in a short period (for example, one year) after the start of a
comprehensive economic stabilization program. Such a program would involve the introduction of a



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stable national currency, and of a clear plan to lower inflation and stabilize government revenues and the
external balance, probably with the assistance of international financial institutions. The range of target
price levels for each fuel is addressed in the sub-sector paragraphs below.
8.8          It is possible that some prices, for example those for natural gas and electricity to
residential consumers, may have to be adjusted over a longer time frame, to avoid an intolerable burden
on consumers. Gas price changes in paiticular will have to allow for the installation of meters, while
electricity price reform will require improved collection systems. In such cases the subsidies required
to maintain low prices should be made an explicit part of the Government budget, so that the full
economic costs of pricing policies are made clear. The government should however, limit general
subsidies to all consumers as much as possible, and should aim to cushion the effects of price rises on
consumers through targeted social payments wherever feasible.
Petroleum
8.9           As concerns oil pricing, Azerbaijan has maintained tie producer price for oil at a level
which is not sufficient to cover the increases in the cost of production incurred by SOCAR. As a result,
SOCAR was running a monthly deficit of Rubles 4 billion by the second quarter of 1993. A substantial
proportion of SOCAR's costs are of materials and services which are priced at international levels and
hence have risen rapidly in costs in Ruble terms. Wages have also been raised to keep pace with local
inflation. In order to provide SOCAR with resources for its operations (especially hard currency), the
Government has allowed it to export crude oil and oil products (processed for a fee in the local refineries)
for its own account free of taxes. This bypasses the usual channel of sales through the refineries, or at
least through the Ministry of Foreign Economic Relations.2
8.10          The maintenance of a low producer price for oil has forced SOCAR to limit investment
and essential maintenance, increasing the rate of decline of oil production. The diversion of crude and
product sales to SOCAR's account amounts to an indirect subsidy to the company, since revenues from
such exports might otherwise accrue to the Government.
8.11          In principle, SOCAR should be allowed to sell its crude oil or products direcdy onto the
international market. However, such sales would have to be accompanied by appropriate Government
taxation of SOCAR's profits, after allowance for necessary operating and investment expenses. Similarly,
prices for crude oil and products sold on the domestic market should be steadily raised towards the
international level, with a similar tax regime applied.
8.12         In this context, it is important to note that SOCAR should maintain a transparent interral
pricing system for crude oil sales to its refineries, so that the revenues from crude oil production and the
margins earned from refining are clearly distinguished. This is essential if the economics of distinct
activities (oil production and refining) are to be properly assessed, and the correct economic signals given
to producers and consumers.
8.13          For crude oil, the policy should be to raise the internal SOCAR sales price to the
refineries to the international parity level. The establishment of such a level is not simple in Azerbaijan,
I SOCAR was allocated part of the 1.05 million tons of crude exported for US$107 million in 1992, and has been allocatet
about 1 nillion tons of products in 1993.



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since its crude oil is not directly traded internationally. One option, pending completion of the export
pipeline, would be to use a crude (possibly Russian crude), which is widely traded in Europe (including
the Black Sea) as a reference. Since Azerbaijan is a net exporter of oil, the relevant price is an export
parity price. A notional transport differential between Baku and the Black Sea could be established to
fix a netback to Baku. Suitable adjustment would, of course, have to be made for the generally higher
quality of local crude (in particular its low sulphur level).
8.14           As for petroleum products, these are generally exported from Baku, and reasonable export
quotations could be used to set a target for local ex-refinery prices. Both crude and product reference
prices could be set monthly. Setting of such prices should commence as soon as mechanisms to do so
can be established, so that the gap between local and international prices can be monitored and targets
for price reforni established.
8.15           An important issue for Azerbaijan is whether to liberalize (i.e. de-control) wholesale
prices for crude oil and petroleum products. In practice the transition to liberalized trading could occur
only when suitable regional marketing and trading structures are in place. In the near future, for
example, free trading of crude will continue to be hampered by the lack of infrastructure, while product
markets are unlikely to be entirely transparent. Hence local prices for crude and products could remain
controlled, provided these are based uporx a reasonable approximation of international parities as described
above. SOCAR would ot course receive international market prices for its international sales and the
government's taxation of its revenues would reflect actual realizations from domestic and international
sales. Retail prices for gasoline and diesel could be liberalized once a privatized and competitive service
station network has been established. In the meantime, retail prices for petroleum products slhould be
adjusted to a level which provides an adequate return on the costs of distribution. 3
8.16           Adjustments to taxation systems will be required mainly in the upstream oil and gas
sector. At present the Government raises a substantial proportion of its revenue from oil (estimated at
about 40 percent of the budget for 1993). Gasoline and diesel sold on the internal market are subject to
excise taxes and VAT amounting to 50 percent and 32 percent of the retail price (fuel oil is not taxed).
In addition, SOCAR's refineries must surrender 70 percent of their hard currency revenues from oil
product exports to the National Bank, receiving in compensation local currency at an exchange rate of
about 16 percent of the market rate. The key taxation changes following a move to international prices
will be those required to recoup any excessive profits from SOCAR following the raising of domestic oil
and gas prices to international levels. This will require a study of SOCAR's finances, operating costs
and investment requirements. Under such a system, profit taxes on SOCAR would replace the current
high excise taxes on domestic sales, and heavy surrender requirements on exports. Excise taxes on oil
products (above the international wholesale parity), will still need to be determined within the overall
fiscal strategy for the Government.4 As concerns foreign companies, taxation mechanisms for "rent'
3 It should be noted that the price compatison in Table 8.1 undetstates the true gap betwen retail gasoline and diesel
prices in Azerbaijan, and their econoroic costs, since it is based upon international wholesale pries. Comparison with retail
prices in other countries shows a much larger gap - for example Azerbaijan's gasoline and diesel prices in early 1993 weic
respectively only 19 percent and 14 percent of pretx prices in Turkey.
4 Although in pnnciple taxation of energy should reflect only the additional environmnental or other costs imposed by eneWr
use (including for example road maintenance costs in the case of transport fuels), in practioe energy may be used as one means
of indirect taxation, in the case where income tax collection systems are inadequate. This requires a judgement of the relative
economic merits of different means of rising revenues in an 'imperfec eoonomic contet.



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from oil and gas production will be built into the production contracts. In addition, these companies may
be subject to the general corporate taxation levels in Azerbaijan on their profits.'
Natural Gas
8.17          Despite the fact that natural gas is the most important domestic fuel in Azerbaijan, the
Govermment has not developed a coherent gas pricing policy. In part this reflects the legacy of the
previous Soviet regime, in which the price for gas bore no relation to the cost of production or to its
economic value as an energy source. In part, however, it reflects the failure to respond promptly to the
increasing costs of gas imports.
8.18          Since the beginning of 1992, Azerbaijan has faced a dilemma on gas pricing. On the one
hand prices of imports from Turkmenistan have been rising rapidly, from Rb S'i/mcm in 1991 to
Rb2,500/mcm at end 1992 and Rb 15,000/mcm in the first quarter of 1993. At the same time, however,
the government has felt constrained in passing this cost on to consumers, mainly because over 50 percent
of gas use is unmetered, and a large rise in prices would amount to imposing a substantial fixed costs on
users, based upon somewhat arbitrary assumptions about usage levels. To offset the rise in imported gab
costs, the government kept down the producer price of domestic gas, in order to maintain the average
cost of gas to Azerigaz at a level which would keep the company solvent. Since local supplies account
for about 60 percent of total supplies, the weighted average price to Azerigaz in the final quarter of 1992
was about ruble 1360/mcm, compared with the producer price of ruble 600/mcm and the import price
of ruble 2,500/mcm. The result of this policy was an erosion in the producer price of gas relative to oil
from even the very low levels of 1990 (before which the prices had been stable for many years). In 1990
gas producer prices had been 40 percent of oil prices in thermal equivalent, while by end-1992 this ratio
had fallen to 8 percent.
8.19          As regards consumer prices, these have been maintained at an exceptionally low level to
residential users, with the prices for industry taking most of the adjustment. Since 55 percent of
industrial users have meters, and since the cost of energy to industry is often a modest proportion of total
production costs, this is the sector on which the Government has found it easiest to impose increased
charges. In the first quarter of 1993 industrial prices were 30 times the level of residential prices. In
the OECD, residential prices are usually 2 to 3 times the level of industrial prices. The Government has
also raised prices to power users to the level of industrial users, but this has been partly offset by the
substitution of fuel oil for gas in power stations. As noted in Chapter 6 the share of fuel oil in power
generation rose from 51 precent in 1991 to 78 percent in 1992. Since domestic fuel oil prices were kept
down, at only 40 percent of gas prices (in thermal equivalent), this fuel switching reduced the input costs
of Azenergo, thus keeping down pressure on electricity prices. However, as a result of this policy the
Govermment lost potential revenues from fuel oil exports, which would have amounted to an additional
US$200 million if gas usage had been maintained at the 1991 level. The corresponding saving in gas
import costs was almost certainly below US$200 million.
I Alough oil compaes are likely to be the most importaot forgn investors in Azerbaian, it is not desirable that they
receive special treatment in respet of corporate taxation, since this can create distortions and unprediecble conditions for fture
investors. Any special taxation of these companies should be includod as past of the production agrements.



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8.20          With prices of gas from Turkmenistan rising rapidly towards world levels and prices from
Iran established at world levels for some time.6 Azerbaijan's policy of attempting to absorb the pressure
from rising import. prices by keeping down domestic producer prices and raising domestic prices to
industry, is clearly unsustainable. The very low price to domestic producers puts further pressure on
SOCAR's finances (which. are then offset through oil allocations). For domestic consumers, the cost of
gas is barely keeping pace with the general rate of inflation (prices in December 1991 wsre ruble
50/mcm, while prices had risen 600 percent to ruble 300/mcm by December 1992, compared with a rise
in the retail price index of 2200 percent). The maintenance of an artificially low price of fuel oil, in part
as a subsidy to power users, creates a distorted perception that usage of domestic fuel oil is lezs costly
than imports of natural gas. The rising distortions in Azerbaijan's gas pricing system, which are linked
to distortions in fuel oil and electricity pricing, must be corrected urgently, so as to limit the economic
disruption from an eventual move to ecoromic pricing levels.
8.21          The calculation of economic gas tariffs should start from the assessment of an economic
value for gas at the inlet to the system. The level at which domestic natural gas production should be
priced will depend upon the relationship between natural gas supply and total demand. Domestic natural
gas output displaces either imported natural gas or fuel oil (for export), depending upon the level of
domestic production, the pattern of demand for gas in the country and the relative economic value of gas
imports and fuel oil exports. These relationships are somewhat compiex, and are assessed in Annex 5.4.
The current pattern of supply and demand suggests that it will usually be appropriate to price domestic
gas production according to the import price of natural gas into Azerbaijan, at least until the year 2000
(when supply and demand patterns could begin to change substantially). Accordingly it would probably
be appropriate to take the economic cost of imported gas from Turkmenistan as the relevant price-guide.
As indicated in Chapter 5, this is likeiy to be about US$70-80/mcm, based upon European border parities
for Russian gas (and transport differentials).
8.22          Once the price at the inlet to the system has been determined, appropriate charges for
transmission and distribution need to be established based upon cost of service studies, applying a suitable
rate of return to the replacement cost of the system. Tariffs should be set within Azerigaz for individual
system components (transmlsion lines, regional distribution systems etc.) so as to allow an assessment
of costs and profitability at the business unit level. It should be noted that while some aiscount from
replacement cost may sometimes be permitted to take acceunt of the depreciated life of the system, and
its long remaining life, in the case of Azerbaijan the urgent need to replace much of the pipeline system
means that tariffs will have to reflect a substantial part of system capital cost if Azerigaz is to be self-
financing. In practice, introduction of economic gas tariffs will have to keep pace with meter installation.
As noted in Chapter 5, this is likely to take some years as concerns the household sector in particular.
A coordinated program of price reform and meter installation must therefore be developed as a priority.
6 in lke 1992 Azebajan reached agreement with Iran to trade 63,000 tons of diesel for 250 million cm of gas, implying
a price of around $40/mcm, although Iran has on other oocasions demanded $75/momn.



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A........    lug SUPL US.om PETPOLHUM
aaJa s i a mjor oil and gas producer, the alPocatoin of the e io sur    or           o      u
4cio Iscicl to thie a  of Azerb4jauins economy. yAt prien, Xh dteey  tov r oducer- prtce ;o
VWer  most Of th sAurplus with eitr the users (through lo*tconsumer prines) orw.ith the govem     (
;Xpoztske pIace at world prices). It can be caiculated t*at, at December 1992 pikes and wk4l99.
atern, ocusumers would have appropriated about US$600 ia llion (46 percent of the world vaefj oi ned
Rdus outpui) In the f6nn of surplus (difference between world pnice and doinesc pto:bdu o t,
.laemmqnt would have taken some $230  million from net expon recopt and furt'er $5   ln :
e. J. ...   oil products. Same $350 million (27percentof the total) would have gone toth u
$60Q.iion to the eliners (see Figure 8.2).
.ot diatbution of the petrleum surptus (atworld p     qun) i
nthatnithproducers nor consumers are receiving ippropie eonuo price sn    lowI
vuesfrom pro leum also aggravate the problem of balaucg the public sector budigt. AsA pOt4-"
N*WArO  price levels for producers and consumers is urgently required. his would  tb .:tie
napproprat taxaaon system for upstream profts. Targeted subsidies to vulnerable cnwumes i
ikf.ferpaticular hardship may also be desirable. Such a realignment of prices woud channel ite o
V. petom revenues through tho producers, and leave a much larger sa: wi the governmei u
raxati. T.ixation of petroleum products should be put on an ex-refiniry basis for domesio consumtion (i.e as
s lexcise tax). Given the large tax revenues which could be reoeived by the govenument from   se  :.
he    yelt jtillcation for the imposWion of prolkum produet taxes other than imla
fe rasost fiuels '..--'-.:.::.  
Electricity                                                lgure 8.2  Petroleum Value Shares
8.23            The current electricity tariffs do                    (million US$)
not reflect the true cost to the consumers and the
distortion between households and industrial
tariffs has been growing. Dospite a significant
increase at the end of 1992, the average rates are    Consumers   ....Re.ners Mar.n
only a fraction of the long run marginal cost.            48$                                  4
The relative prices of electricity do not provide
the correct signals to consumers which is the main
cause for inefficient use and waste of energy.
Further, the power sector is accumulating an                                                   Producers'
increasing deficit because of the rise in costs of                                             Reoelpts
inputs and the cap put on tariffs.                                                               27X
8.24            The current cross subsidization
between industry and agriculture and residential         EGovt.                      P    tTmxens
consumers is significant. Residential consumers               18%                        4%
are paying only a fraction of the cost to industrial
users while the true cost to households is typically  * ,       sar ewoL vazlw ofpeakm and produaoxa
1.5 to 2 times that of industrial consumers. As    aedl- 9pifcesasd 1992 cc"wranond etpon kwlk.
shown in Table 8.1, prices are only a small
Sour" WoM Bm  .dxe
fraction of those typically prevailing m
industrialized OECD countries. Prices to
residential consumers need to be increased substantially to correct this distortion. Price adjustment in the
short term is less of a problem for electricity than fo. natural gas, since all consumers have meters.



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However, collection and billing systems need to be greatly improved if higher prices are to be translated
effectively into revenues. As in the natural gas sub-sector, price reform in electricity should be based
upon cost of service studies. This involves calculation of system long run marginal cost (which could be
done within the context of the proposed least cost investment study), complemented by financial analysis
of utilities.



CHAPTER 9
ENERGY SECTOR INVESTMENTS AND TECNICAL ASSISTANCE
Energy Sector Challenges
9.1          The energy sector has played a major role in Azerbaijan's modem economic development.
Azerbaijan was one of the earliest centers of the petroleum industry, and oil exports were for many years
the motor of the country's economy. Oil has declined in relative importance in recent decades. Yet
Azerbaijan still possesses very large petroleum resources, which could once again make oil the key to
economic growth. The efficient development of the large resources in the country's offshore oil fields
is the best means of generating the foreign exchange to finance economic restructuring and recovery in
the medium to long term. In the shorter term, rehabilitation of existing oilfields and a reduction of gas
imports can provide important benefits. In addition, the reform of energy institutions and the
rationalization of energy use .s essential if the transition to a market economy is to be successflly
accomplished. In order to fulfill the potential of its energy sector, Azerbaijan's government and energy
sector institutions will require technical assistance from the international community, so as to adapt their
skills and plans to a market oriented environment as rapidly as possible.
9.2          In assessing the investment and technical assistance requirements of its energy sector,
Azerbaijan must take account of the considerable challenges which it must confront:
(a)    The Government, through the State Oil Company, needs to conclude detailed agreements
with foreign companies on offshore oil field developments and construction of an oil
export pipeline, all of wbich require complex legal, financial and technical arrangements.
The Government has made encouraging progress in attracting major international oil
companies to Azerbaijan. Investment by these companies is essential to obtain the
finance, technology and project management for the development of the offshore fields.
Planning this investment and integrating the cash flows with the macroeconomic
framework is vital to ensure orderly economic development. In addition, Azerbaijan
needs to assess how it can supply the investment and operating requirements of the
offshore projects efficiently from domestic industries, so as to maximize the benefits to
the local economy and provide least-cost supplies.
(b)    The existing energy sector infrastructure is oI.en obsolete and in poor condition. In the
older oil fields production has reached levels which are probably economically marginal
and a major restructuring of production practices and facilities is needed; there is also
serious environmental pollution associated with oil production. The country's oil
refineries lack upgrading capacity, and much of their equipment is antiquated. The gas
pipeline system is corroded and losses of gas through leakage are very large. Much of
the power capacity is near the end of its useful life, and fuel usage is very wasteful. In
all of these areas a major restructuring of existing infrastructure will be needed, together
with substantial investitients in more efficient systems.
(c)    The energy sector institutions, and the experience of their staff, need to be adapted to a
market economy. There has been significant initial progress towards restructuring some
of the energy enterprises, particularly in oil and natural gas. Yet enterprise management
systems and operating structures are still geared towards a command economy.
-85-



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Enterprise structures need to he thoroughly reformed, management and staff require
training in market-oriented business practices and modern financial and informaticn
systems need to be installed, as enterprises move towards commercialization. In
addition, the Government's capacity to formulate and implement national energy policies
requires strengthening. Appropriate independent regulation of the energy enterprises and
a legal framework for petroleum should be introduced.
(d)    Azerbaijan's energy sector is oriented towards interaction with the other FSU countries
under the previous central planning system, not with the world market. Moreover, the
distinction between the market in the FSU and that in other countries is becoming less
relevant. This has a number of implications, including the need to build better transport
links with the world market, particularly a crude oil export pipeline. All energy
enterprises must interact with foreign investors to find the technical and financial
resources for future investment. In the case of the important petroleum equipment
industry, urgent action is needed to develop a commercial strategy (emphasizing quality
improvements) for retaining a substantial share of the market in other FSU countries, as
well as in the domestic market.
(e)    Domestic energy pricing and taxation policies are distorted and do not reflect current
economic realities. Energy prices are well below international and economic levels.
Producer prices are too low to provide resources for investment, while consumer prices
are subsidized, and do not provide incentives for efficiency. The problems of moving
to world price levels are significant, and reform must take account of exchange rate
distortions, the social costs involved and practical problems such as the lack of gas
meters. However, a coherent framework for moving to economic pricing for energy is
urgently required.
9.3          There is a need to move rapidly to address these problems so as to take advantage of
Azerbaijan's petroleum resources, to avoid continuing economic losses due to inefficiency, and to halt
the further deterioration of infrastructure.
Investment Plans
9.4          The Government and the energy enterprises have set out the following priority projects
in the energy sector (to the year 2000), for which international financial assistance may be required:
(a)    Oil - Rehabilitation of the old oil fields to repair infrastructure and extract
remaining reserves: The dilapidation of the infrastructure, surplus employment and
major environmental problems in these fields present obstacles to attracting foreign
investment in a comprehensive manner (in contrast to the situation with the new offshore
fields). Yet the old producing areas still contain significant resources, despite their long
producing history. Short term investment may be required to repair producing
equipment. In the medium term, international financial assistance designed to
complement private investment, and focussed on removing institutional, environmental
and social obstacles to restructuring, will probably be most effective.
(b)    Oil - Construction of a crude oil export pipeline: The development of the offshore oil
fields requires access to world markets through a new export pipeiine. Azerbaijan has



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been working with the oil companies and neighboring countries to develop this pipeline,
which is likely to cost at least US$1.5 billion. In view of the large sums involved, and
the political and commercial issues raised by this key project, financial support by multi-
lateral institutions may be required.
(c)    Natural Gas - Rehabilitation of pipelines to reduce losses caused by leakage from
corrosion, and investments in improving usage efficiency: Gas is the key fuel for the
domestic economy, and Azerbaijan is a major gas importer, despite also having large
resources. Gas losses are high, and use is extremely wasteful due to the lack of gas
meters and of efficient appliances. Gas processing is inadequate. The price of imports
from other Republics is rising rapidly, causing significant economic strains. A plan to
rehabilitate the pipeline system, improve processing, introduce meters and enhance end
use efficiency is urgently required.
(d)    Electricity - Construction of combined cycle power stations, and investments to
improve the efficiency of the system: While electricity capacity in Azerbaijan is
adequate, fuel usage is extremely wasteful, and many of the power plants are over 25
years old. The transmission and distribution system has also suffered from under-
investment and lack of maintenance. The problems of the power sector are the result of
the lack of emphasis on efficiency under the previous regime. In the short and medium
term, the investment priorities are probably the rehabilitation of the generation,
transmission and distribution infrastructure. In the longer term, replacement of obsolete
capacity by new combined cycle plant is probably justified. Power sector investment
needs to be conducted within the framework of a least cost investment plan.
(e)    Oil Field Equipment - Investment programs in the oil field equipment industry to
improve quality, restructure capacity and develop marketing: Azerbaijan supplied
65 percent of the oil fields equipment in the Former Soviet Union, and remains a vital
supplier to the other republics. The survival of this industry is important to maintaining
oil production capacity in the other FSU Countries (especially Russia) and to ensuring
the future of the i dustrial sector in Azerbaijan. Yet the industry must learn to compete
in the international marketplace. Joint ventures with foreign investors represent the best
chance of long term survival.
(f)    Oil Refining - Investments in additional and more modern refining capacity:
Azerbaijan's refining capacity is well in excess of its domestic requirements. Much of
the capacity is obsolete, some dating from the beginning of the century. In recent years
the refineries processed crude imported from Russia and Kazakhstan and exported the
products, but the economics of this trade at world prices are questionable. Older capacity
will probably have to be reduced, and the newer capacity should be restructured to
incorporate improved upgrading.
9.5          Detailed investment studies for these projects need to be carried out, utilizing methods
sf economic, financial and environmental analysis widely used in the OECD energy industry. Such
studies are essential to decide whether projects are justified and to mobilize external funding, and what
should be the project design and timing. These studies would of course make use of the high quality
technial data which is available from the energy sector in Azerbaijan. Staff from the energy enterprises
and institutes in Azerbaijan should be involved in these studies, and should be trained in the methods
used.



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9.6            The study and implementation of investment projects should be accompanied by the
strengthening of energy institutions and reform of energy policies. Only through the introduction of a
fiull range of appropriate policy measures will the benefits of energy sector investments be fully realized.
9.7            Total investment requirements for the various sub-sectors are summarized below
(additional details are in Annex 1). These figures also show investments for projects which will be
undertaken wholly or largely by the foreign oil companies, including in particular the new offshore field
developments, which are the largest element of total investment. The Guneshli gas capture project is
also being funded by foreign oil companies. In most other areas, some funding from international
financial institutions may be required. In the case of the older oil fields and refinery rehabilitation,
investment is likely to come mostly from the international oil comparies, although multilateral assistance
may be needed to mobilize fuinding In rapidly in a risky environment, and to address environmental and
social issues. It should be stressed that these figures are very preliminary estimates only, and are likely
to be substantially revised in the course of the recommended investment studies.
Table 9.1: Azerba&n Rner Seetor Inveshent Fintmcog Requirements
(V'S $ Million)
"Short Termn"     Medium Term' "Long Tenn"
TOTAL       1993-1994      1995-1996      1997-2002
Mature field rehab. (On/Offshore)   690           30            150            510
Offshore field development        6,970          310           1,530          5,130
Crude oil export pipeline         1,800            0           1,150           650
Offihore oommon infiastructure    1,600            0            650            950
Totld Upstream Petroleum         11,060          340           3,480          7,240
Total Refining                      135            0             20             115
Guneshli Field Gas Capture Project  10           100
Systm rehabilitation/meteaing       850            0            250            600
Total Natural Gas                   950          100            250            600
Generaion/System Upgrsding and Rehab.  640        40             50            550
District Heating Upgrading and Rehab.  70          5             15             50
Total Electicity/Dstrict Heating    710           45             65            6Q0
TOTAL INVESTMENT                 12,855          485           3,815          8,555
Source: Mission estimates.
Energy Sector Technical Assistance Strategy
9.8           In order to address the problems of Azerbaijan's energy sector in a comprehensive and
practical manner, and to prepare investment projects for international financing, a program of technical
assistance to the energy sector should incorporate the following types of work:



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*     Energy Policy Studies: to decide on the general directions of the Government's energy
policies;
*     Investment Studies: to assess the priority projects in each energy sub-sector using
appropriate economic, financial and environmental analysis, and to develop a scheme to
implement these projects;
*     Institutional Strengthening: to improve the organization, management, and financial
and information systems of the energy enterprises and government institutions;
*     Advisory Services: to provide the Government and the enterprises with advisors for
their dealings with foreign Investors in the energy sector;
*     Training: to train staff of the government and enterprises in economic, financial,
managerial, technical and environmental aspects of the energy sector.
9.9          A set of technical assistance components covering all these areas is shown in Annex 1.
It would clearly be desirable if the management and programming of technical assistance in this area
could take place within an integrated framework. Coordination of technical assistance to the energy
sector is one of the areas which should be handled by a strengthened central body for energy (eg. Energy
Commission) as is recommended to be established in Chapter 7. Ite funding of technical assistance on
the required scale may involve borrowing, since grant fiuds may not be forthcoming on the necessary
scale. This is particuiarly the case for the petroleum sub-sector, where rapid mobilization of advisors
for negotions, together with staff training and investment studies, are needed to mobilize large-scale
foreign investment. The World Bank has discussed an integrated energy technical assistance project with
the Government and enterprises in Azerbaijan which could provide the required financing.
9.10         It should be stressed that in the case of Azerbaijan, technical assistance in energy will lead
to concrete financial benefits in terms of foreign exchange revenues, which helps to justify any borrowing
which may be required. For example, reduction of gas venting and losses to OECD levels and
improvements in gas usage could save about $250 million per )ear in gas imports, while accelerating the
development of the offshore oil fields by one year could bring forward additional Government revenues
of over US$ 1.0 billion before the year 2000. The benefits of accelerating investment through a
comprehensive technical assistance program in energy will thus be clearly visible in improved economic
and financial performance in the years ahead.



AZERBAUAN
ENERGY SECTOR REVIEW
ANNEXES



Azerbaijan Energy Sector Investment Financing Requirements                          Annex 1.1
(US$ MILLION)
"Short Term'  'Med. Term'  "Long Term'
TOTAL         1993-         1995-        1997-
COST          1994          1996         2002
Upstream Petroleum
Mature field rehabilitation (On/Offshore)         690           30           150           510
Offshore field development                      6,970          310        1t530          5,130
Crude oil export pipeline                       1,800            0         1,150           650
Offshore common infrastructure                  1,600            0           650           950
Subtotal Upstream Petroleum                   11.060          340         3,480        7,240
Petroleum Refinina & Products Distribution
Efficiency & Process Control Improvement           20            0             5            15
Pollution Control Systems Improvement               5            0             0             5
Lube Oil Section Modernization (Azneftyag)         40            0             5            35
Other Upgrading & New Units                        70            0            10            s0
Subtotal Refining                               135             0           20           115
Natural Gas and Gas Processing
Guneshli Field Gas Capture Project                100          100             0             0
Processing System Upgrade/Expansion               300            0           100           200
Pipeline system rehabilitation                    450            0           100          350
Gas meter procurement                             100            0            S0            50
Subtotal Natural Gas                            950           100          250           600
Electricity
Generation/Transmission/Distribution Upgrade      640           40            50           550
District Heating Upgrade and Rehabilitation        70            5            15            50
Subtotal Electricity/District Heating           710            45           65           600
TOTAL INVESTMENT                               12,855          485         3,815         8,555
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Annx 1.2
AZERBAUAN ENERGXY SECTFR  ECHNICAL ASSISTANCE
Summaa Priority Components
Energy Policy Development
Energy Pricing and Taxation Strategy
To assess the economic level of prices and taxation for energy products, and recommend
a policy for price adjustment. (US$450,000)
2.    Petroleum
Contractual and Financial Advisory Services for Petroleum Neggtiations
Hiring of advisors by SOCAR to provide legal, economic and financial advice for
negotiations with foreign petroleum companies and other entities for exploration and
development and fbr the export pipeline. (US$9.9 million).
Oil Export Pipeline and Infrastructure Engineering StuAies
Detaied engineering design of oil export pipeline, including preparation of bid documents
(SOCAR share of costs). (US$3.2 million).
Advice on Orgaization and Manazement
Analysis and recommendations to SOCAR on organizational changes to adapt to the
growth of the oil industry, and related advice on management and personnel management
policies. (US$300,000).
Advice on Business Unit Structure. Budgeting and Perfbrmance Reporting
To put in place a business unit structure clarifying management accountability, with an
associated system of budgeting and performance measures. (US$600,000).
Upgradine of Financial Systems
Development and installation of modern financial systems in SOCAR. (US$2.0 million).
Management Information Sysem Development
To design, purchase and install modern computer and management information systems.
(US$3.0 million)
-95-



-96-
Rehabilitation of the Old Onshore Oil Fields
Studies of older onshore and offshore oil fields to assess economics, and best methods
of extracting remaining oil and attracting private investment for joint ventures (to be done
with SOCAR staff). Study of environmental improvements in fields. (US$1.0 million)
Oil Rocks Offshore Field Rationalization/Rehabilitation Study
Study of the Oil Rocks field to assess current economics of production and options for
future extraction of remaining reserves. (US$700,000).
Licensing and Investnent Promotion
Development of licensing franework for offshore and onshore fields and preparation of
data packages, training and promotion. (UJS$800,000)
Petroleum Refining and Products Marketing Study
Detailed techno-economic study of refineries in Azerbaijan to recommend investment and
rationalization options (including training and development of management systems),
review of petroleum distribution and marketing. (US$800,000).
Gas Processing Plant Reconstruction Sudy
Detailed assessment of investinent requirements for reconstruciton of SOCAR gas
processing plant. (US$500,000)
Training of SOCAR Staff
Training of SOCAR staff in commercial, legal, technical areas of the petroleum industry,
according to international practice. (US$1.0 million).
3.    Natural Gas
Gas Transmission and Distribution System Reconstruction and Metering Study
and Proiect Preparation
Assessment of investment priorities for rehabilitation of gas networks to reduce losses and
preparation of detailed investment plan. (US$800,000).
Development of Legal and Regulatory Framework for Natural Gas
Drafting of legal statutes governing natural gas transmission and distribution and
assistance in putting in place appropriate gas industry regulation. (US$400,000).
Azerigaz Business Unit Structure. Budgeting and Performance Reporting
To put in place a business unit structure clarifying management accountability, with an
associated system of budgeting and performance measures. (US$600,000).



-97-
Azerigaz Short Term Management Information System
Installation of system to improve provision of management information, and of enterprise
performance measures. (US.'800,000).
Azerigaz Improvement of Accounting Procedures. Systems and Control
Development and installation of modern financial systems. (US$2.0 million).
Natural Gas Development Strategy
Development of a long term strategy for gas supply and usage within the country,
especially as concerns gas trade and training of staff in gas business planning and
practices. (US$500,000).
4.    Electricity and District Heating
-     Azener=o Least Cost Power Investment Plan. 1993 - 2010
Detailed assessment of power demand and investment options using economicftecbnical
least cost analysis, preparation of detailed investment plan. (US$600,000).
-     Develogment of Power Sector Regulatory Framework
Review of power sector organization, drafting of appropriate legal statutes and assistance
in putting in place appropriate regulation. (US$400,000).
-     Azenergo Business Unit Structure. Budgeting and Performance Reporting
To put in place a business unit structure clarifying management accountability, with an
associated system of budgeting and performance measures. (US$600,000).
-     Azenergo Short Term Management Information System
Installation of system to improve provision of management information, and of enterprise
performance measures. (US$800,000).
-     Azenergo Improvement of Accounting Procedures, Systems and Controls
Development and installation of modern financial systems. (US$2.0 million).
-     District Heating Investment Strategy
Investment plan for district heating rehabilitation and restrcturing. (US$400,000).
5.    Petroleum Equipment
Petroleum Eauipment Industry Strategy
Development of a business strategy for Azneftekhimmash, including an investment
program, implementation of joint ventures, marketing and training. (US$1.0 million).



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0                                0~~~~~~~~~~~~~~~~
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Annex 1.4
ENERGY BALANCE FOR AZERBAIJAN, 1990
(Thousand tons of oil equivalent)
CDaI       Owde   Pecvk,         NeadW        Hydml    Ekctdct         Heat      TOTAL
0o1*    Prxfswt         Gas        Gco
Production                             ...     12,576          ...      8,934        143          ...        ...      21,653
Imports                                79       4,559         246      12,098         ...        151          ...     17,133
Exports                                ...         ...     (7,771)     (4,882)        ...        (289)        ...    (12,942)
Stock Change                            O        (140)         ...        (89)        ...         ...         ...       (229)
TPES                                   79      16,995       (7,526)    16,061        143        (138)         ...     25,615
Public Electricity                     ...         ...     (2,813)     (4,09S)      (143)       1,991         ...      (5.060)
Petroleum Refineries                   ...    (16,855)     15.526         ...         ...         ...         ...      (1,329)
CHP Plants                             (4)         ...        (68)     (1.061)        ...         ...      2,140       1,007
Losses                                 ...       (140)         ...       (822)        ...                               (962)
Statisfical Differences               (36)        (95)     (1,410)     (1,082)        ...       (267)        (61)      (2,951)
FINAL CONS8MPTION                      38          ...      3,710       9,001         ...       1,586      2,079      16,320
INDUSTRY                                3          ...        414       2,391         ...        841       1,541       5,190
Power                                ...         ...         ...         11         ...        129          ...        140
Fuel                                 ...                     78       1.173         ...        203         345       1,799
Iron and Steel                       ...         ...         67         139         ...         10          15         231
Non-ferrous Metals                   ...         ...         15          59         ...        103         174         351
Chemical                             ...         ...         20         260         ...        115         691       1,087
Engineering                          ...         ...          7          66         ...         34          82         189
Construction lnc.materials)           1          ...        217         559         ...         96          52         925
Other                                ...         ...         10         124         ...        151         179         464
TRANSPORTATION                         ...         ...      2,139        311          ...         69           6       2,525
Rea                                  ...         ...         25         ...         ...         45           6          76
Water                                ...         ...        133          ...        ...         ...         ...        133
Motor Vehicles                       ...         ...      1,981           1         ...          8          ...      1,990
Pipeline transmIsseon                ...         ...         ...        310         ...         16          ...        326
AGRICULTURE                             0          ...        659         91          ...        184          14         848
COMM. & PUBLIC SERVICES                 4          ...        323       3,205         ...        270         262       4,064
RESIDENTIAL                            24          ...        192       2,276         ...         92         238       2,822
NON-SPECIFIED OTHER                     2          ...         83        727          ...        130          18         960
Source: Fuel-Energy Balance, 1990, Government of Azerbaijan.
TPES - Total Primary Energy Supply.
"Including condensates.



Annex 1.5
AZERBAUAN ENERtGY TRADE                         *3ASEORGEA'                                                                                                                                 Page 1 0f3
1092             1I6S                1004              l196               1066               1097               1006              1099               2N00               2006
ORG.  'OOOS 1)  OA4G.   'OOO1) 0lt1.   'ooos    OM.   "a00               oRla.  'OOS        ORM.   '000*      OM".  '000*        OR0G.   *ODoS    010.   OOOS    OF0            '00
Cnud.0       'OOOT      13S0    0t1s5    1000    67526    1000   136050    1000   13050             0         0        0         0        0        0        0         0        0         0        0         0
DGolne .     ODOT          0         0      na         0       na         0      na         0       na         0        0         0        0        0        0         0        0         0        C         0
Dbl          'OOOT         0        0       na         0       na         0      na         0       na         0        0         0       0         0        0         0        0        0         0         0
Mamut        'OOOT         0        0       na         0       na         0      na         0       na         0        0         0       0         0        0         0        0        0         0         0
OU, P rods OO0T          26      1600      26 1S00            26      3000      2s      3000        0         0        0         0        0        0        0         0        0         0        0         0
Notrao       U MMCM     s23   18420s    4260   148750    9Os   630224    8037  s521s 6              M22    67s039    6831   618170    O1M3   840024    e213   046120   10461   7s2235           9179   0  s424
LPQ          'COOT        20      1500      20      t0OO       20      sooo      20      3O0        20      3000        0         0       0         0        0         0        0         0        0         0
Coo          '0OOT        1S      37S       iS       375       Is       750      Is       750       1s       750       16       750       IC      750       16       7s0       15      750        1s       760
Eloblft      MMkvwh        0        0        0         0        0         0       0         0        0         0        0         0       0         0        0         0        0        0         0         0
TOTAL                          27s7a9             2106s0             772024            70441s             679680             S61620            640774             646870             0S68               5438
1902              19os               1994              10S6               1096               1997              199s               1909              2000                2005
0RIM   'O0$ 1)  OAQ    'OOOS 1)  o0tl.   '000S    o0G.  '0006             OG.   loon         O00a.            'S OOOS  Om  'ODO   OM.   OOS          oRa.  '           O .    'O$
EXPORTS
Orud ODl   'COOT        1050    70441       na         0       na         0      no         0       na         0       na         0      na         0       na         0       na        0        na         0
Glasi ne     'OOOT        70      66o0      na         0       na         0      na         0       na         0       na         O      na         0       na         0       na        0        na         0
03.0         'OOOT     2000   16te00        na         0       na         0      na         0       na         0       na         0      na         0       na         O      na         0        na         0
Mazut        'OOOT      320    10720        na         0       na         0      na         0       na         0       na         0      na         0       na         0      na         0        na         0
OthnProds  'OOOT         SI1    so0o0       na         0       na         0      na         0       na         0       na         0      na         0       na         0      na         0        na         O
(rotol Ol)   'OOOT      3955   2s4168    0001   20s347    6016   607231    6710   767341    5o04   65352             7229   06s971   12050  16s1600   14843  19t6145   20800  2792040    39702  5326876
Noturas  MMCM            951    33285      10o      3500        0         0       0         0        0         0        0         0       0         0        0         0       0         0         0         0
LPG          'OOOT         0         0       0         0        0         0       0         0        0         0        0         0       0         0        0         0       0         0         0         0
Cowl         'OOOT         0        0        0         0        0         0        0        0        0         0        0         0       0         0        0         0       0         0         0         0
Eleot,cty    MMkwh       660    13200      e60    13200       60s    2840       660    2e400       60e    2S4D0       660    2e400      660    26400       060    2e400      8G6     2e400       6tD    28400
TOTAL                          330653             222047             a3361             793741             70092s            990371            1643250            2017945           2818440             5363376
BALANCE                         51914               2397             StS07              89s23            1t0234            3s461              1002476           1372075            20854S             4710131
1) 1092 AND 1993 TRADE VALUED AT 50% OF WOF1D PRICE



Annex 1.5
AZERBALJAN ENRGY TRADE                        *-.OELAYCASE                                                                                                                             Page 2 at 3
1992             1S93               1994              199               1996              1997              1998              1999              2000               2005
OM11.   '000S )  OF         0OG.  '00081)  OM1.  '000$                  Ot. '3. '000$                       OgtG. '000$    01R1GL  '0008  OM.   O000t 011G.  '000$  0S11.   00  OfitG.   '0I00
IMPWllTS
CrudeOR    '0ooT       1360    91159    1000    e7l25    1000   13050    1000   136080            0         0       0         0       0         0       0         0       0         a         0        0
Gasoline    '0O0T         0        0       na        0       na        0       na         0      na         0       0         0       0         0       0         0       0         0         o        0
Diesel      'OCOT         0        a       na        0       na        0       na         0      nOa        0       0         0       0         0       0         0       0         0         0        0
Mazut       'OOOT         0        0       na        0       na        0       na         0      "a         0       0         0       0         0       0         0       0         0        0         0
OdterProds  'OOOT        25      1800      28      1500      26      3000      25      3000       0         0       0         0       0         0       0         0       0         0         0        0
Nabnal Gas  MMCM       s263   184206    4250   148750    9087   e3soss    9638   674627   10035   702420    8831   818170    9362   655364    9727   680690   11336   793541    10S47   745304
LPG         'O0OT        20     1800       20      1500      20     30Oo       20     3000       20      3000       0         0       0         0       0         0       0         0        0         0
Coal         COOT       1i       376       1       375       15      750       15       750      15       750      15       750      15       750      15       750       iS      750        15      750
Electri     MMkwh         0        0        0        0        0        0        0        0        0        0        0         0       0         0       0         0       0         0        0         0
TOTAL                         278739            219650            777856             813s27            706179            615920            656104            681640            794291             746054
1992              1991 19                             1995               9s6              1997              19S8              1999              2000               2005
OFRG.  '000 1)  OAtG.  '0001 )  OfitG.  '0-00         O1G3.  'oooS    ORL.  '0008$    ORG.  '0008    F01.   '000o             ORIQ.  '000$      ORt4G.  '000S     OF40.    '000S
EXPORTa
Crude Oll   '000T      1050    70441       na        0       na        0       noa       0       na        0       na         0      na         0      na         0      na         0       na         0
Gasoline    '000T        70     8606       na        0       na         0      na         0      na         0      na         0      na         0      na         0      na         0       no         0
D1esol      'OOOT      2000   168500       na        0       na        0       na        0       na        0       na         0      na         0      na         0      na         0       na         0
Mazut      'COOT        320    10720       na        0       na        0       na        0       no         0      na         0      na         0      na         0      na         0       na         0
OtherProds  'OOOT       515    30900       na        0       nOa       0       na        0       na        0       na        0       na         0      na         0      na         0       na         0
(Total Oi    'COOT     3965   284168    3060   205253    8728   768495    5140   669628    3797   609512    4168   559261    6604   806130    9048  1213993   12699  1690472    33783  4632827
NaturiG as  MmCM        951    33286      100     3500        0        0        0        0        0        0        0        0        0        0        0         0       0         0        0         0
LPG        'COOT          0        0        0        0        0        0        0        0        0        0        0        0        0        0        0         0       0         0        0         0
Coal       'C00T          0        0        0        0        0        0        0        0        0        0        0         0       0         0       0         0       0         0        0         0
Eectricity    MMkwh     66     13200      660    13200      660    260        660    26         60     28400      o60    26400      660    26400      660    260        6      26400       560    26400
TOTAL                         330063            221963            794895            716028            636912             585661            912539           1240393           1716872            4SS9227
BALANCE                        S1914              2303             17040           -100299           -170267            -33289            256435            6' 3753           925se1             3613173
1)1992 AND 1993 TRADE VALUED AT 60% OF WO9LD PRICE.



Annex 1.5
AZERAtJAN ENEUK3Y TRAM .DE4m.                                                                                                                                                             Pop 3 0f3
ilS               1og              1994               t396               e9es              1907              l89o              19o               20D0               2005
0Rt    'OM I)  ON&    '00001)  OIEI    UNe            OQ9      Wm0       0Pt 'OM  006        ORta.   0OM     OMK   'OD#         0F      'COOS     ORF    .0008       0F0 W      08
Ct'ud.01    'COOT      1360    007        1000 072          1000   130444    1000   133444          0         0       0         0        0         0       0         0        0        0         0         0
Gas**        'COOT        0         0       noa       0       na         0      na         0       na         0       0                  0         0       0         0        0        0         a         0
Dbnm        'o0or         0         0       na        0       na         0      na         0       noa        0       0                  a         0       0         0        0        0         0         0
MGUt        '001          0         0       na        0       na         0      na         0       na         0       0         0        0        0        0         0        0        0         0         0
OIhPmrdad g     T        25      10w0       26      1500      28      3000      26      3000        0         0       0         0        0         0       a         a        0        0         0         a
Naunt       MUM       6S26    184206    4260   148760   0o00    630224    6007   661              228   67590    0226 e46792    0760             23    0806   692039   11404   796248    113e1   7S270l
LPG         'COOT        20      1600       20     1600       20      3000      20      8000       20      30D0       0         0        0        0        0         0        0        0         0         a
Coal         COOT        18       376       1S      076       16       780       16      70        I         60       16      70        16      780       15       760       i       70         15       760
Ekoblot*     MMkwlt       0         0        0        0        a         0        0        0        0         0       0         0        0        0        0         0        0        0         0         0
TOTAL                          277S66            218847             770418            702812             6796              64042             684673             Ł10589            709956              79St20
19S2              1983              1904               19S5              10998              107               ¶96               1009               2000               2006S
OV8    'OOOS1)    OR5.   '000 t)  065    l'000        089   O'0        OUM   O'           Oa    '0000       ORM    'M         065      '0008     OS   '000         O&        '000
C        ONf  'OOOT    1050    70068        na        0       no         0      no         0       na        0       na         0       na        0       no         0      no         0        na         0
bhon.    'COOT           70      66e0       no        0       no         0      na         0       no        0       no         0      no         0       na         0      no         0        no         0
Oil         'OOT       2000   16500         no        0       na         0      no         0       no        0       na         0      no         0       na         0      no         0        na         0
MlAt        '0T6        4       10720       no        0       no         0      no         0       na        0       na         0      no         0       na         0      no         0        no         0
Oilwprd S000T           16S    30900        no        0       no         0      na         0       no        0       na         0      no         0       no         0      na         0        na         0
(T10  06ff) 'COT       0S6t 374            061   200        6016   8          6 720   7326    696    7011    604   674390    607   8S499    N60    1076039   12198  17710    26015  0330646
_4bn        mMcM        t61    338         100     S0          a         0       0         0        0        0        0         0       0         0        0         0       0         0         a         0
LPG         'tOOT         0         0       a         0        3        0        0         0        0        0        0         0       0         0        0        0        0         0         0        0
Cow         'COT          0         0        0        0        0         0       0         0        0        0        0         0       0         0        0         0       0         0         0        0
Boolm       mkh         6         2 isO    6      13200      60    26400       66      26400      66o    2840       6t      20        60    280          6S      2f400     SW0    2640         6      2400
TOTAL                          300               22990S            6296t6             7_                70831              70                88t389            1102439            6S41110           336444
Am$gmGap6160Ł6                                                      68U78              66S74            12289                                                  40t9S              85tt6            2662
1) 1902M18UD MS TOMAVALUAT6OSOFIDP M               E.



Annex 2-1
AZERBAJAN OIL AND GM FELDS
OIL PRODUCTON (000 tonsl                                  GAS PRODUCTiON (million cubic metsa
1975   1980   1985   1990   1991         1975   1980   1985   1990   1991
ialakhany          1140    987    761    464    401
Kyurovdag           929    726    441    325    280
Bibi-Eybat         532    416    368    227    208
Kyursangya          399    29.    261    178    160
Mishovdag           306    359    326    214    177
Surakhany          405    306    251    174    153
Other             2130   1962   1501   1000    870
Onshore Total     5841   5053   3909   2582   2249          1572   1227    714    400    288
Oil Rocks                        2078   1076    779                         116     63      58
Sangachaly-Bulla                 1830    784    771                        1908    818    764
Bakhar                            736    386    310                        6565   4850   4221
Guneshil                         3106   6563   6701                         239    587    355
Other                            1483   1122    932                        4525   3207   2935
OffshoreTotai     11328   9600   9233   9931   9493         8318  12777  13353   9525   833
-107-



AzerbaiJan Petroleum  Production and Investment Projections                                  . A 8MCASE ^^'                                                             Annex 3.1
SOCARCA tM                                                                                                                                                              Page I ot4
(Production In thousand barrels per day)
AgSUMPTi1W9                  I9n2   1993    1994    1996    1996    1997    1998    1999    2000   2001    2002    2003    2004    2005    2006    2007    2008    2009    2010
FDB Oil Price (Silbbi)      20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00   20.00    20.00   20.00
Pipeline Tariff (Sbbl)       2.60    2.60    2.50    2.60    2.50    2.60    2.60    2.50    2.50    2.60    2.60    2.60    2.60    2.60    2.50    2.50    2.50    2.50    2.50
BorderOl Prie ($tbbo        18.38   18.38   18.38   18.38    18.38   18.38   '8.38    18.38   18.38    18.38   18.38   18.38   18.38   18.38   18.38    18.38   18.38   18.38   18.38
Baku Oil Price (SIbbi       17.60   17.60   17.60   17.50    17.60   17.60   17.60   17.50   17.60   17.60   17.50   17.60   17.50   17.50    17.60   17.60   17.60   17.60   17.60
lnfrastTariff(S/bbD          1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10    1.10         1.10    1.10    1.10    1.10
VWhead Oll Prioe (/bbQ      16.40   16.40    16.40   18.40    18.40   16.40    16.40    18.40    16.40   16.40   16.40   18.40   16.40    16.40   16.40   16.4    16.40   16.40    16.40
Natural Gas Price ($mci)     1.88    1.88    1.88    1.88    1.88    18        1.88    1.88    1.88    1.88    1.88    1.88    1.88    1.88    1.88    1.88    1.88    1.88    1.88
Interest Pate      10.00%
OIL PRODUTrION (rh. bpd)     1992    1993    1994    1996    1996    1997    1998    1999    2000    2001    2002    2003    2004    2005    2006    2007    2008    2009    201O
Onshore-Existing             40.2    36.2    32.6    29.3    26.4    23.7    21.4    19.2    17.3    16.6    14.0    12.6    11.3    10.2          9.2     8.3      7.4     6.7     6.0
Onshore-New                   0.0     0.0      0.0     2.0     6.0    10.0    20.0    30.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0
Offshore-ExistIng            61.4    46.8    42.6    38.7    38.2    32.1    29.2    26.6    24.2    22.0    20.0    18.2    16.6    16.1    13.7    12.6    11.4    10.3           9.4
GuneshD                     130.1   123.6   123.6   124.0   139.8   192.0   247.2   266.4   283.3   267.7   271.2   271.2   244.4   218.1   192.6   164.1   137.3   113.2    921
Chirag                        0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0    28.0   686.1   133.8   203.3   263.1   287.8   291.8   272.2   265.4   232.4
Azerl                         0.0     0.0      0.0     0.0     0.0      0.0    36.0    82.6   167.3   264.1   316.4   369.8   364.7   340.2   319.2   290.6   263.2   238.0   216.3
e  t(4Koap                    0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      6.8    13.2    26.8    40.7    50.6    57.6    68.4    64.4
°)    Other                          0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0
TOTAL                       221.7   206.5   198.7   194.0   208.4   257.8   352.7   414.8   512.1   627.4   727.7   841.3   893.6   903.6   903.2   857.7   789.0   722.0   650.7
OlL PROD. GOV. (Th. bpd)     1992    1993    1994    1996    1996    1997    1996    1999    2000    2001    2002    2003    2004    2006    2006    2007    2J08    2D09    2010
Onshore-Existing              0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0
Onshore-New                   0.0     0.0     0.0      0.8     2.0     4.0      8.0    11.9    15.9    15.9    16.9    16.9    16.9    15.9    16.9    1S.9    15.9    15.9    16.9
Offshore-Existing             0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0
G3uneshD                    130.1   123.6   106.6   101.1    96.7   108.0   117.4   128.3   176.6   191.0   200.6   206.1   184.8   163.1   142.1   118.5   103.4    83.2    65.7
Chlrag                        0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0      0.0     6.2    13.8    28.8    44.6    55.8    71.6   147.9   145.8   137.9   125.6
Azod                          0.0     0.0     0.0      0.0     0.0     0.0      6.0    16.9    33.0    51.1    63.9    82.1   169.6   167.0   158.1   143.8   129.4   116.1   106.1
Kapsz                         0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0      1.0     2.8     6.8     8.9    11.2    14.3    29.6    29.2
Other                         0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0
TOTAL                       130.1   123.6   10.8.   101.9    98.6   110.0   131.3   166.1   225.5   263.3   294.3   334.0   417.6   407.6   396.6   437.4   408.8   382.8   342.4
OIL PROD. SOCAR (Th. bpd)    1992    199     194    1995    1996    1997    1998    1999    2000    2001    2002    2003    2004    2005    206    2007    2008    2009    2010
Onshore-Existing             40.2    36.2    32.5    29.3    26.4    23.7    21.4    19.2    17.3    16.6    14.0    12.6    11.3    10.2         9.2      8.3     7.4     6.7      6.0
Onshore-New                   0.0     0.0     0.0      0.7     1.8     3.7      7.3    11.0    14.6    14.6    14.6    14.6    14.6    14.6    14.6    14.6    14.6    14.6    14.6
Offshore-Existing            61.4    48.8    42.6    38.7    36.2    32.1    29.2    26.6    24.2    22.0    20.0    18.2    16.6    16.1    13.7    12.6    11.4    10.3           9.4
Guneshli                      0.0     0.0     0.1      0.6     1.0     2.6      4.3     5.8    10.6    12.4    13.7    14.6    13.1    11.6       9.9      8.1     7.0     SA       4.1
Chirag                        0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      1.7     4.6     9.6    14.9    18.6    23.9    49.3    48.6   48.0    41.8
Azend                         0.0     0.0     0.0      0.0     0.0     0.0      2.5     6.5    13.6    20.9    26.2    33.6    69.3    68.3    64.7    58.8    62.9    47.5    43.4
Kepax                         0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.3      0.9     1.9     3.0     3.7      4.B     9.9      9.7
Other                         0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0      0.0     0.0      0.0
TOTAL                        91.6    82.9    75.2    69.3    64.4    62.0    64.5    69.0    80.2    87.2    93.1   103.5   140.7   140.2   138.9   156.3   146.7   140.4   129.1



Annex 3.1
Page 20o 4
OCL PRO M OQ   . hpd)      t99     1es    1991   tU9    1S98   t997    1996    1           20DD    20i    22    WI    004    2006   2008   207   2008   2009    2010
Onshoresdsting              0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    0.0    0.0       0.0    0.0    0.0    0.0    0.0    0.0         0.0    0.0
Onslore-new                  0.0    0.0    0.0    0.9    2.3        45      9.0    13.0    16.      9.6    9.2    9.2    9.2        92      9.2    9.2    9.2    9.2       9.2
Offal ore-datg              0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0
Gunehlh                     0.0    0.0   1t.9    22.3   42.2    3A4   125.I    122.3   78.1    64.3    6a.    sD.5   48.6   43.5    40.6   37.5   26.9    24.6   22.4
Chlag                       0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    21.0   47.0   96.4   143S   178.7  1s24    94.5   77.    714    S6.0
Azer                         0.0    0.0    0.0    0.0    0.0    0.0    28.0    60.3   120.8   182.    2263   244.2   126.8   104.6    98.5   67.S   60.9   74.4   66.
Kat                         ..0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    0.0    0.0    4.2    9.s    19.1   28.8   35.7   38.6    16.9   Is.e
Other                       0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    0.0    0.0    0.0    0.0         0.0    0.0    0.0    0.0    0.0    0.0
TOTAL                        0.0    0.0   1e.    23.2   44.4   68.0   161.2   196.1   212.0   277.2   340.1  403.4   334.9  355.3   367.4  264.7   233.2   196.5   178.9
tPROOUCfON (M )           1992    1933    1994   1ow6   1998   1997    1986    1099    200    2001   2092    2003   2004   2300    2006    2D07    2008    2009    2010
Onshore-Erielng             23.4   21.0    18.9   17.0    1.3    3.6    12.4    11.2    10.1        9.1     6.2    7.3    6.6       6.9    53      4.8     4.3    3.9    3.5
Onsh r-New                  0.0    0.0    0.0        1.2    2.9    5.8    11.6    17.6    23.3    23.3   23.3   23.3   23.3    23.3   23.3   23.3   23.3    23.3    23.3
Offshore-Exdng             703.9   633.6   670.2   513.2   4e1.9  415.7   374.1   338.7   303.0   272.7   246.6  220.9   198.8   178.9   161.0   144.9   130.4   117.4   10s.7
GuneshN                    169.7   161.2   161.2   161.3   182.4   166.6  130.1   15.4   122.1   115.0    99.8    2A4    65.9   43.1    31.9    22.8    10.8       1.1    0.0
Chlrg                       0.0    0.0    0.0       0.0    0.0    0.0    0.0        0.0     0.0    6.9    3        84.7   132.7   192.0   234.4   264.2   251.3   234.4   209.0
Azewl                       0.0    0.0    0.0    0.0    0.0    0.0   21.2   49.4   106.9   165.9   240.0  293.0   317.7   314.2   293.0   281.2   222.4   180.0   137.7
Kapaz                       0.0    0.0      0.0    0.0    0.0    0.0    0.0         0.0     0.0    0.0    0.0       3.4    7.9    16.9   26.6   38.4   46.9   50.8    50.3
Other                       0.0    0.0      0.0    0.0    0.0    0.0    0.0    0.0          0.0    0.0    0.0    0.0    0.0         0.0    0.0    0.0    0.0    0.0        0.0
TOTAL                      897.1   816.8   750.4  69.2   6S62    591.9   649.4   530.2  564.4   6o09   66.3   715.0   7529   779.4  776.5   749.6  689.5   610.9   629.4
VESTWMENT (m  anm)         1992    1993    1994    os96   1996   1997   1996    1999    2000    2001   2302    2003   2004    2005   2006    2007    2008   2009    210             t
Onshor.-dstnq      6186     5.0    10.0    1.      10.0   10.0    10.0   10.0    10.0    10.0    10.0   10.0    10.0   10.0    10.0   10.0   10.0    10.0    10.0   10.0
Oshorem-Now        S630     0.0    0.0    10.0   20.0   40.0   40.0   40.0    40.0   40.0    40.0   40.0   40.0   40.0   40.0   40.0   40.0   40.0    40.0   40.0
OtIshore-Edisting  s6W6    35.0    36.0   36.0    35.0   35.0    35.0    36.0   36.0    s50    36.0    36.0    36.0    36.0   350    38.0   35.0    35.0    35.0    35.0
CuneshU           62o77     0.0    0.0   215.3   288.5   295.8   283.0  270.6  241.9   16.3   107.6    63.6   26.1    19.4   18.0   17.8   17.0    16.3    15.6    14.9
Chirag            $2,496    0.0    0.0    0.0    0.0    0.0   22.4   269.2   49A.   476.9   219.1  259.1   237.2  164.4   150.1   83.9   5s.8    35.6    22.6    14.4
Azad              83,168    0.0    0.0   23.0   33a6   617.7   596.1  273.9   323.9   29S.6   190.0   187.6   104.9   73.5    44.5   28.2   18.0   18.0    16.0    0.0
Kapa-              8432     0.0    0.0    0.0    0.0    0.0    0.0    0.0    4.5    53.8   98.8   95.4   43.8    51.6    47.4   30.9   30.0   16.8    11.8    7.1
Othtb                s0     0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0
Pipelne          61.7"4     0.0    0.0    0.0   112.6  1026.9   62s.7    0.0    0.0         0.0    0.0    0.0    0.0       0.0    0.0    0.0    0.0    0.0    0.           0.0
Infrastructure    $t166     0.0    0.0    0.0   321.2   321.2   321.2   321.2   321.2    0.0    0.0         0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0
TOTAL(Sbn)       $61.08    40.0   450   298.3  1123.7  2346.6  1933.4  1220.1  1470.6  1077.6   703.5  690.6   497.1   384.1   345.6  245.8   208.8   171.7  152.9   121.4
Oum. Ihv. Total            40.0    6.0   363.3  1607.0  38525   785.9  7006.0  8476.6  9654.2 10267.5  Io94.4 11446.5 11529.3  121i7.2 12420.9 12629.7 12301.4 12954.3 13075.7
Cum. Inv. New Ofshore       0.0    0.0   243.3   980.6  2920.1  4447.3  S261.2  6323.6  7318.2  7936.8  8542.4  8964..6  S25.   9614.2  9674.9  9798.7  9s68.4  99s3.3  9989.7
INV. SOCAR (MS Mn)         1992    199    104    1996    199s   1997   1998    1999   2000    2001   2D02   2003    2004   2006    2006    2007   2006    2009    2010
Onshore-Eidsting            5.0    10.0   10.0    10.0   10.0    10.0   10.0    10.0   10.0   10.0    10.0   10.0    10.0   10.0   10.0   10.0   10.0    10.0   10.0
Onshore-New                 0.0    0.0      0.0    0.0    0.0    0.0    0.0         0.0    0.0    0.0       0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0
Oftshore-Exdstng           35.0   35.0    36.0    36.0    36.0    36.0   36.0    36.0   35.0   36.0    36.0   35.0   36.0    35.0   35.0   35.0    35.0    35.0   35.0
Ouneshul                    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0
Chlrag                      0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0                    0.0    0.0
Azerf                       0.0    0.0    0.0    0.0    0.0    0.0    C.0           0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0             0.0    0.0
Kat                         0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0            0.0    0.0
Other                       0.0    0.0    0.0    0.0    0,0         0.0    0.0    0.0       0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0           0.0     0.0    0.0
Pipelie                     0.0    0.0    0.0    28.1   26.5   156.4    0.0         0.0     0.0    0.0    0.0      0.0    0.0    0.0    0.0        0.0    0.0    0.0    0.0
Intrastructure              0.0    0.0    0.0  1t0.6  160.6   160.6   10.8   160.6    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0    0.0                  0.0    0.0
TOTAL                      40.0    46.0   46.0    73.1   301.5   201A    45.0    46.0    46.0   43.0   45.0    46.0   46.0    46.0   46.0   45.0    45.0   43.0   45.0



Annex 3.1
Papg 3 0t4
NV. O. (US Wnn)             16w2   1008    1904   199    1s98    1697    im          1909    206    2001    2002    2000    2004    200m    200       2007    2008    2000    2010
Onehonr*xstqng               0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0
OnehorNew                    0.0      0.0    10.0    20.0    40.0    40,0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0    40.0
Olfshore-Exeng               0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0
Guneshl                      0.0      0.0   2e8.3   288.8   296.8   283.0   270.6   241.0   165.3   107.6    83.6    28.1    19.4    18.6    17.8    17.0    16.3    16.6    14.9
ChIrag                       0.0      0.0     0.0     0.0     0.0    22.4   260.2   404.1   4769   219.1   259.1   237.2   184.4   180.1    89          s8.8    38.6    22.6    14.4
Azeri                        0.0      0.0    26.0  s36.    617.7  688.1   273.9   323.9   296.8   103.0   167.6   104.9    73.8    44.8    28.2    16.0    16.0    16.0          0.0
Kap-                         0.0      0.0     0.0     0.0     0.0      0.0     0.0     4.5    83.68    0.8    9.4    43.6    S1.8    47.4    s0.9    30.0    18 .       11.6     7.1
Othe                         0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0
Pipslne                       0.0     0.0     0.0    84.4   769.4   469.3      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0    0o0
Infrasucture                 0.0      0.0     0.0   160.6   160.6   160.0   160.6   160.6      0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0
TOTAL                         0.0     0.0   323.3   729.3  1722.9  1410.6  683.9  1104.4  102.0  688.5   646.0   462.1   339.1   300.0   200.8   163.8   126.7   107.9    76.4
NET  EV. soC  Am 3nn)    1i92    1990    1094    1095   1is9         1607    1998    1990   2000    2001    202    2003    2004    2005    2008    2007    2eo0    2009    201o
Onshore-Exdsting            267.8   226.4   200.8   178.6   1S8.9   141.0   124.9   110A      97.4    66.6    75.1    66.8    87.0    49.3    42.4    30.1    30.8    25.6    20.9
Onshore-Now                  0.0      0.0     0.0     0.2     0.6      1.1     2.1     3.2     4.8     5.8     6.0      6.o      o 0     .0     6.0     6.0      .0      6.0     6.o
Offshore-Exslng             780.1   662.4    12Z1   848.6   491.2   409.4   3M2S   380.1   311.8   .77.1   248.8   217.6   191.9   168.8   147.9   129.0   111.9    98.4    8z4
Ounse                        0.0      0.0     8.9     86      9.7    18.6    28.1    37.8    68.8    79.6    8.8    91.5    81.8    71.1    60.9    49.6    42.4    32.6    24.4
Chlrg                        0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0    11.4    29.8    62.1    96.2   121.9   167.3   327.1   328.4   306.8   278.8
Azel                          0.0     0.0     0.0     0.0     0.0     0.0    16.O    41.9    67.4   138.3   171A    221.3   480.0   486.1   431.8   39z2    380.7   311.6   261.0
Kapa                         0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     2.3    6.       12.4    19.2    24.4    31.8    68.4    64.9
Oth0                         0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0
pipelneo 0.0                          0.0     0.    -28.1  -26     -180.4    32.3    39.8    5.8    70.3    62.6    98.7   106.4   106.6   108.6   100.4    01.2    82.2    7z6
Infrastructure               0.0      0.0     0.0  -16D.0  -160.6  -122.8  -110.3  -104.2    70.6    9s.2   117.2   141.8   163.6   166.7   167.1   148.0   133.6   119.1   103.6
TOTAL                      1017.7   907.7   818.9   708.1   403.9   443.6   898.9  863.2   626.0   068.2   697.5   7629   1008.0  692.1   971.7  1084.6   986.5   928.    831.0
NETR IEV. COS (6                    lwn)  19o2 1998    109  168   196    1S97    1968    1900   2g0   2001    2002    2003    2004    2005    206    2007    2008    2009    2010
Onshoe-Esng                  0.0     0.0      0.0     0.0     0.0     0.0     0.0   0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0          0.0     0.0
Onshore-ew                   0.0     0.0   -10.0   -14.7   -26.    -13.3    16.5    40.2    46.       10.0     8.4       o     6.0      6o      eo      eo      6.0      6.0     e.0
Offshoe-EIstng               0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     0.0
GuneshIl                     0.0     0.0  -234.8  -218.0   -91.9   107.9   320.3   318.1    99    82z4    87.1    91.6    61.6    71.1    00.9    49.          42.4    32.6    24.4
ChIrag                     -30.0     0.0   460.0      0.O     0.0   -2Z4  -2692  -4041   .4769   -122Z6       4.0   291.0   663.    885.8  1033.1   414.7   333.1   307.7   278.9
Azert                        0.0     0.0   -78.0  436.8  -617.7  -896.1  -ISIA        -.6    373.8   844.6  1126.3  1318.9   60s.6   467.1   432.6   39z2   380.7   311.6   281.0
Ka. 0.0                              0.0      0.0  -20.0      0.0     0.0     0.0   -4.5   -38    -s0.8   -98.4   -24.8    -1.2    6e.2   132.7   177.2   206.6    82.9    66.
Other                        0.0     0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0
Pipeline                     0.0     0.0      0.0  -84    -769.4  -469.3    97.0   119.6   167.6   210.8   247.9   260.2   319.2   319.6   319.4   301.1   273.6   248.6   217.8
Infratrtuere                 0.0     0.0      0.0  -180.8  -1sD.S  -122.8  -110.3  -104.2    70.5   90.2   117.2   141.8   1S&   1s.7   1W7.1   148.0   133.8   119.1   103.6
TOTAL                      -W.0      0,0  -38      -831.2 -1866.2 -1116.9  -100.2  -127.8   224.1  1021.6  14836  2111.9  1792.2  1964.4  2141.9  1488.7  1346.9  1106.4   978.3



Annex 3.1
Page 4 of 4
NET ilV. GOV. OMS mt)       1002    1003    1994    19S6    1006   1t97    19SS    1999    2000    2001    2002    2003    2004    2005    20o6    2007    2008    2009    2010
Onshote-Exlsting             0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0    -0.0    -0.0
Onshore-Nevi                 0.0      0.0     0.0     7.3    18.2    36A      72.8   109.2   166.4   20t.0   204.6   204.9   204.9   204.9   204.9   204.9   204.9   204.9   204,9
Otfehore-ExlstIng            0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0     0.0   -0.0       0.0     0.0
Gunesho                      0.0    20.0   117.3    97.9   110.0   211.0   319.0   428.6   780.3   902A    984.1  1036A    923.9   805.    600.6   582.1   420.5   368.9   276.1
Chirag                      30.0      0.0    60.0     0.0     0.0     0.0      0.0     0.0     0.0    34.1    89.3   186.4   288.7   366.8   472.0   981.3   973.1   920.5   4064
Azeri                        0.0      0.0    80.0     0.0     0.0     0.0    39.0   102.4   213e   330.8   418.9   640.9  1124.4  1115.0  1064.8   958.    857.4   761.7   686.9
Kapaz                         0.0     0.0     0.0    20.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     6.8    17.9    37.3    67.7    73.1    94.4   198.3   194.6
Other                        0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0    0,0
Pipeline                      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0
Infrastructure               0.0      0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0      0.0     0.0     0.0     0.0     0.0     0.0      0.0     0.0     0.0
TOTAL                        30.0    20.0   227.3   125.2   128.2   247A    430.9    40.1  1159.3  1468.2  1698.9  197S.4  2589.8  2s28.6  2450.0  2779.8  2610.3  2452.4  2199.0
ITEms                       t0S2    1993    1904    1006    1996    1997    1908    1S99    2000    2001    2002    2003    2004    2006    2006    2007    2008    2009    2010
Oil Production (Th. bpd)    221.7   20c.6   198.7   194.0   206.4   267.8   362.7   414.8   512.1   627.4   727.7   841.3   893.6   903.6   903.2   857.7   789.0   722.0   650.7
OilConsumption (h.bpd)      175.9   185.8    98.9   100.1   104.5   113.2   111.7   117.9    95.9   103.6   111.7   120.1   100.4   100.    109.4   109.4   109.4   109.4   109.4
Oil Exports (rh. bpd)       45.8    40.7    99.8    90.9   101.9   144.6   241.0   296.9   416.2   623.7   816.0   721.2   79A.1   794.0   793.8   748.3   679.6   612.5   641.2
Co. Exports (Th. bpd)        0.0      0.0    24.4    30.9    57.8    99.8   173.3   208.9   225.4   294.7   384.6   433.9   358.0   381.8   396.8   283.8   250.0   211.6   189.7
SOCAR+4ov. Exp. (rh. bpd)   45.8    40.7    75.4    63.0    44.1    44.8    67.7    88.0   190.8   229.0   261.5   287.2   436.2   412.2   398.0   484.7   429.6   401.0   351.8
Tota Inv. (Smn)             40.0    46.0   298.3  1123.7  2345.5  1933.4  1220.1  1470.6  1077.6   703.5   80.6   497.1   384.1   346.6   246.8   208.8   171.7   152.9   121A
Domest. Inv.($mn)    40%    16.0    18.0   110.3   449.5   938.2   M.4   488.0   688.2   431.1   281.4   276.3   198.8   163.6   138.2    98.3    83.5    68.7    61.1    48.6
Tota Op.Cost mmn)           26.0    26.0   134.1   143.9   167.0   260.6   360.4   398.9   462.2   620.7   657.9   614.3   640.3   653.1   669.3   645.7   676.6  656.0   S32.3
Domes. Op.($mn)      50%    12.5    12.5    67.0    71.9    83.6   125.3   180.2   198.5   231.1   260.3   279.0   307.1   320.1   326.5   329.7   322.8   287.8   277.5   266.1
Cos. OIL Whead Prices)      1992    1S93    1994    1996   1S6    1097    1998    1999    2000    2001    2002    2003    2004    2005    2006    2007    200s    2009    2010
Cost Otit (h. bpd)           0.0      0.0     7A     11.7    34.6    66.5   120A    146.7   143.3   190.8   246.6   292.2   168.5   187.3   199.0    67.5    61.9    21.1    13.1
olw Interest Oil (Th. bpd)   0.0      0.0     0.0     3.7    13.9    28.0    40.3    46.7    66.4    64.1    62.4    54.9    38.8    31.6    20.9       6.4     3.1     0.3      0.0
ProfitOil(Th. bpd)           0.0     0.0      1.0     1.5     1.7     3.3     7.7    13.8    26.9    38.8    49.1    64.0   108.5   111.5   112.8   133.5   126.1   120.7   109.4
Operating Cost Oil (rh. bpd)  0.0     0.0    16.0    17.7    21.5    30.0    45.2    48.3    66.2    65.2    69.8    77.8    80.9    83.0    84.1    82.6    72.0    69.7    67.2
CostOll($mn)                 0.0      0.0    44.5    69.9   207.0   398.0   720.8   878.4   567.8  1142.0  1470.1  1748.9  1008.8  1121.3  1191.1   404.3   310.6   126.2    78.3
olw Interest Oil (Smn)       0.0      0.0     0.0    22.2    83.2   167.5   241.2   279.6   331.6   383.5   373.7   328.9   232.1   188.3   125.1    38.6    18.4        1.8     0.2
Profit Oil (Imn)             0.0      0.0     5.9     8.8    10.2    19.7    46.2    82.9   161.1   232.2   293.9   383.    649.7   667.5   675.0   799.1   754.9   722.4   655.0
Operating Cost Oil ($Mft)    0.0      0.0    96.7   106.0   128.9   179.7   270.5   2a8.9   330.8   390.1   417.8   486.6   484.2   496.9   503.2   494.2   431.1   417.4   402.0
Tota Company Oil ($m)        0.0      0.0   14.2   184.8   340.2   697.4  1037.5  1250.2  1349.4  1764.3  2181.6  2697.6  2142.8  2285.7  2389.3  1697.6  1490.7  1266.1  1135.3
OIL EXP. (Border Prices)    1002    1993    1904    1096    1990    1097    1996    1099    2000    2001    2002    2003    2004    2005    2006    2007    2008    2009    2010
CostOni($mn)                 0.0      0.0    49.9    78.3   232.0   445.9   807.6   984.2   961.1  1279.6  1647.2  1959.5  1130.3  1256.3  1334.5   452.9   348.0   141.4    87.7
o/w Interest Oil mmn)        0.0      0.0     0.0    24.9    93.2   187.7   270.2   313.3   371.4   429.7   418.7   368.5   250.0   211.0   140.2    43.2    20.6       2.1      0.2
Profit Oilt (mn)             0.0      0.0     6.7     9.9    11.5    22.0    51.8    92.8   180.5   260.1   329.3   429.2   727.9   747.9   76e.3   895.3   845.9   809.4   733.9
Operating Cost Oil (8mn)     0.0      0.0   107.2   118.8   144A    201.4   303.1   323.7   370.4   437.0   467.9   521.7   642.6   556.8   563.8  563.7   483.1   467.7   450.4
Total Company Oil ($mn)      0.0      0.0   163.8   207.1   387.8   669.4  1162.5  1400.8  1611.9  1976.7  2444A   2910.4  2400.8  2561.0  26s4.e  1902.0  1676.9  1418.6  1272.0
SOCAR.Oov(Smn)              307.1   273.0   505.7   422.7   298.6   300.4   454.0   590.3  1279.4  1535.8  1687.0  1926.3  2918.7  2764.6  2669.2  3116.8  2881.1  2689.5  23S8.0



Annex 3.2
Pap I ot3
AZERAIJAN - OIL SUPPLYIDEAND BALANCE                      ^-ECAS-
Thousand Tons
Im      199t   uIM      t933    18      1S95   1SSB   1997    ISM   tl9o   2000   2001    2002   2003    2004   2006
Production         12613   11742   11084   1C327   9936    9700   10320   12889   17638  20738  25603  31368   36385   42063  44676   46174
-Onshore            2582   2249   2009    1808    1627    1564    1568    1686    2068   2461    2865    2778   2700   2830    2567   2511
-Offshore           9931    9493   9075   8519    8308    8136   8752   11203   156M9  18217  22738   28589  33684  39432   42108  42663
IrMport             4506   4816    1S76   1026   1025    1026          0       0       0       0       0       0       0        0       0       0
-Crude              4290   4301    1360    1000   1000    1000         0       0        0       0      0        0       0       0       0       0
- Products           215    215       26      25      26      26       0       0        0       0      0        0       0       0       0       0
Consumption         6708   7576   7998   7519   4207   4292   4646   4807    5078   5369   4358   4711    5078    5459   4562    4974
-Gbasone            1280    1252    1125    1069    1069    1122    1178    1237    1299   1304   1432    1604    1679    1858    1741    1826
-Dbese              1271    1263    945    851       851     851     893    938      986    1084    108S    1140    1197    1267    1319    1385
- uel Oil           3218   4186   5228    4970    1658    1690    1812    1937    2086   2196   1036   1223   1416   1614    525    735
w           - Kewosene            661     475    380    342    342    342    359          377    398    418    436    458         481     50S    531    5657
-Other               400    400    320    288        288     288    302      318     333    350    368    386        405    428    447    469
Exports             7769   6065   3955   3061    9018   6719   5094   7229   12060  14843  20809  28185  30799  36058  39657  39702
- Crude                0       0    1050    300    400       600    600      700      na      na      na      na      na      na      na      na
- moos               101      13      70      na      na      na      na      no      na      na      na      na      no      na      no      na
- Diesel            2733   2279   2000        na      na      na      no      no      na      no      na      na      na      na      na      no
-mawut              3594   2297    320        na      no      na      na      na      na      no      no      no      na      na      na      no
-Jet Kero            823    747      150      na      na      na      na      na      n       nOa     na      na      no      no      no      na
- Dieel 'jbe"        220    338       g0      na      no      na      na      na      no      no      na      na      no      na      no      na
- Other              28    300    276         na      na      na      na      na      na      noa    no       n       no      no      na      na
Refnery Fuel & Lose   1344    1283    797    m       737    714    S80       83    508    363        436    471      S0S     546    456      497
Unpored8  ne   1196   1334   -290             -0      -0      -0      -0      -0       0       0      -0       0       0      -0      -0       0



Annex 32
P.r 2012
AZERBAJAN - OIL SUPPLYWEMAND BALANCE                       ... GBAYQC9-
Thousand Tons
1990    1991    1992    1093    1994    1995   1¶98    1997    1996    1999   2000    2001    2002    2003    2004    200S
Production          12513   11742   11084   10326   9625    9077   6925    9508   12190   14948   17393   19889   24148   29884   34758   39266
- Onshore            2582    2249    2009    1808    1627    1564    1568    1666    2068    2461    2865    2776    2700    2630    2567   2511
-Offshore           9931    9463   9075    8517    7998    7513   7367    7911   10123   12482   14528   17111   21445  27253  32190   36744
Impons              4505   4516    1376    1025    1025    1026         0        0       0       0       0       0       0       0        0       0
-Crude              4290    4301    1350    1000    1000    1000         0       0       0       0       0       0       0        0       0       0
- Products           216      216      25      25      25      26       0        0       0       0       0       0       0        0       0       0
Consumption         6708    7578    7998    7519   4207    4292    4648    4807    5078    5359    4358    4711   5078    6459   4562    4974
-Gasoline            1280    1252    1125    1069    1069    1122    1178    1237    1299    1384    1432    1504    1579    1858    1741    1828
-Diese               1271    1263     945     851       1     851     893       38     9865   1034    1085    1140    1197    1257    1319    1385
- Fuel Oil          3218   4185    5228    4970    1658    1690    1812    1937   2065    2196    1038    1223    1418    1614          625    735
- Kerosene           5S1      475     380     342     342     342     359      377     396     416     436     488    481      505      531     557
- Othe               400      400     320     288     288     288     302     318      333     350     368     386     405     426     447      469
Exports             7769   8065    3955    3059    6728    5140    3797    4168   6S64   9048   12599   14707   1860   23878   29739   33783
- Crude                0        0    1050     300     400     500     SOO     700       na      na      na      na      na      na      na       na
- Mogas              101       13      70      na      na      na      na      na       na      na      na      na      na      na      na       na
- Diesel            2733    2279    2000       na      na      na      na      na       na      na      na      naf     na      na      na       na
-Mazut              3594    2297      320      na      na      na      na      na       na      na      na      na      na      na      na       na
-Jet Kero            823     747      150      na      na      na      na      na       na      na      na      na      na      na      na      na
- Diesel Lubes       220     38u       90      na      na      na      fla     na       na      na      nla     na      na      na      na       na
- Other              2s8     390      275      na      na      na      na      na      na       na      na      na      na      na      na      na
Refinery Fuel & Loss   1344    1283  797      772     716     670     583     623     508      536     436     471     508     546     456     497
Unrepofted Balance   1195    1334   -290        0       0       0      -0       0       0       0        0      -0       0       0      -0       0



Annex 3.2
Pes 43d
AZERBAUAN - OIL SUPPLYIDEMAND BALANCE                       L-CAWE
Thoucand Tons
19m0    19st    1962   1993    1994   1996   1096    1997    19I8    1ts9    2o00    2001   2002   2003   2004   2005
Producaon         12513   11742   11084   10326   9936   9701   10320   1OS50   11993   13969  16e99    20372  23207  28654   23718  30480
-Onshore           2592    2249   2009    1808    1627   1564    1S68    1686   2068   2461    28s6   2778    2700   2630   2567   2511
-Offshore          9931    9493   9075   8518    8306    8137   8752   s884   9925   11498  14127  17594  20506   23919  26149  27976
Imports            4505   4518    1375    1026    1026    1025         0       0       0       0       0       0       0       0       0       0
- Cnrde            4290   4301    1350    1000    1000    1000         0       0       0       0       0       0       0       0       0       0
- Products          215    215       25       25      25      25       0       0       0       0       0       0       0       0       0       0
Consumption        6708   7576   7998   7519   4207   4292   4645   4807   5078   5389   4388   4711    5078    54569   4662    4974
- Gashoine         1260    1252    1125    1069    1069    1122    1178    1237    1299    1384   1432    1604   1679   168    1741    1828
-Diesel            1271    1263    945    951       861    851       893    938    085    1034    1085    1140    1197   1257    1319   1385                           1
- Fuel Oil         3218   4186    6228   4670    16e8    1890    1812    1937    2086   2199    1036    1223    1418   1614    525    735
- Kerosmne          561    475    380    342        342    342    389        377    396      418    438    458    481        505     631     667                      Ln
- Oher              400    400    320    288    288    288          302      318    333    360    368    386    405    426           447    469                        1
Exports            7760   6O06    3655   3081    6016    5720    509S   5054   6407   8064   12196   15190   17621   20544  23697  25016
- Crude               a       0    1050    300      400    soo    600        700      na      na      na      na      "a      na      no      na
-Mogas              101      13      70      na      na      na      na      na       na      na      na      na      na      na      na      na
- Diesel           2733   2279   2000        na      naa  na         na      na       na     na       na     na       na      na      no      na
- Mazut            3594   2297      320      na      na      na      na       na     na       na      na      nO      na      na      na      na
-JetKero            823    747      150      na      na      na      na      na      na      NO      NO      na       "a     na       na     no
- Oie"el Lubee      220    338       90      na      na      na      na      na      na      na      na      na      na      na       na     na
-Other              298    390    275        "a      na      na      na      na      na      na      na      na      na      nO       na      na
Refnery Fuel & Los   1344   1283    797    m        737     714    680      ses     S08    s38      436    471      508    546      456     497
Uneporbtd 8Baano    1199    1334   -290      -0      -0      -0      -0      -0       0       0       0      -0       0       0      -0       0



PagelOef2
AZERBAIJAN - Consuumtlon & Export of Refined Prodticts (1990-1991)
('000 tons)
1990                                                                        1991
I ~ ~ ~ ~ ~ ~ ~ ~ ~   ~     ~    ~     ~    ~     ~    ~     ~    ~    ~    ~    ~ ~ ~ ~ ~~ ¶9                                 _ _______
Domestic           Exports           Exports to         Total Sates          Domestic           Exports          Exports to       total Sales
Sales               to CIS        Third Countries       (1 + 2 + 3)            Sales             to CIS          Third             (5 + 6 * 7)
Countrles
Aviation Gasotine                    5.8                72.4                12.0               90.2                 7.0              132.5                               139.5
Motor Gasoline                   1,278.9               100.4                                1,379.3             1,252.0                                                1,252.0
Jet Fuel                           561.0              823.1                   -             1,384.1              474.6               877.0                             1,351.6
Diesel Oil (Auto)                1,309.6            1,538.7              1,174.5            4,022.8             1,250.0            1,400.0            1,360.0          4,010.0
tndustrial & Marine Diesel          45.3              277.5                  0.6              323.4               53.5               260.9                               314.4
Stove Oit                         (32.0)            (220.3)                ( . )             (252.3)              (40.0)            (217.5)            (   )            (257.5)
Solar Oit                           (1.0)            (22.6)                (0.6)              (24.2)               (1.0)             (22.0)            ( - )             (23.0)
Fleet Fuel Oil                    (12.3)             (34.6)                (   )              (46.9)             (12.5)              (21.4)                _ )           (33.9)
Lubricating Oils                   135.2              787.5                 16.9              939.6               120.1              994.6                               1114.7
Motor Lubes (H8B1)                (17.0)            (149.9)                ( - )             (166.9)              (17.0)            (178.0)            ( - )            (195.0)
Motor Lubes (M1286)                (31.2)            (314.3)              (16.9)             (362.4)              (42.0)            (446.2)            (   )            (488.2)
Indust'l Lubes (1-40A)             (5.5)            (129.9)                                  ( )  (135.4)         (5.5)             (126.6)           (   )            (132.1)
Indust5t Lubes (1-12A)             (6.0)             (22.6)                ( - )              (28.6)              (6.0)              (92.1)            ( - )            (98.1)
Transformer Oil                    (3.0)             (52.8)                ( . )              (55.8)               (3.0)             (67.5)              - )             (785)
(T-1500)                      _70 5_
lransformer Oil                    (18.0)              (4.8)               ( - )              (22.8)
(K-12)
Turbine Oil (T-46)                 C - )              (2.6)                ( - )               (2.6)               (0.1)              (1.7)            ( - )              (1.8)
Cylinder Oil (11)                  (3.5)              (8.3)                ( - )              (11.8)               (2.5)             (10.5)            ( . )             (¶3.0)
Axte Oft (C)                          -)(1.3)                                -)                 13                   -)                 -)               -)(-)
Axle Oil (Z)                        (-)               (66.5)                C-)               (66.5)               (-)               (72.0)            C-)               (72.0)
Motor Oil (DT)                    (51.0)              (34.5)               ( - )              (85.5)              (44.0)              ( - )            ( - )             (44.0)
Fuel Oil                         4,103.3            2,453.0              1,120.0            7,676.3            4,104.0             2,800.0            500.0            7,404.0
Bitumen                            177.2                                     0.9              178.1               170.0                                                   170.0
total                            7,616.3            6,052.6              2,324.9           15,993.8            7,431.2            6,465.0           1,860.0           15,756.2
Source: Coscomtopliva
Notes:  (a)  Does not inctude coke, solvents and other specialties.
(b) There are significant differences between Total Sates shown in this table and Total Refinery Production in table etsewhere. May be due to inventory
changes, and/or statistical errors.



-118-
Anxx41
Pop 2 of2
AZERBAIJAN - Consumption & Exiport of Refined Products t1992-
('000 tons)
Exports to
Domestic   Exports to  Third
IA, KNOW",        Sales        CIS          Countries    Total Sales
Gasolines                     1096.4        154.2        -               1250.6
Diesel Oils                   1188.8        715.2        2045.3          3949.3
Fuels Oils                    4644.4         95.1         260.2          4999.7
Jet Kerosene                     4.9        145.3          48.6           198.8
Lubes                           n.a.        113.1        -                113.1
Others                         201.6        336.4         342.3           862.3
Total                         7136.1       1558.3        2678.4         11372.8



Pap 1 of 2
Azerbaijan - Novobakinskv Relinery, Physical Facslries
Capacity     Year of        Technology
'000 tons/yr    StartuD      Source                 Remarks
Crude & vacuum distillation unit (unit 16)  2,000          1963-66        USSR
Crude & vacuum distillation unit (unit 15)  6,000          1976           East Germany
Naphtha pretreat & Reformer (CCR) (unit 17)  1,000         1980           UOP
FCC-1 (unfl 31)                               750          1965           Kellogg/UOP/FSU       Will be retired after commissioning of FCC-3
FCC-2 (unit 32)                               750          1967           Kellogg/UOP/FSU       Will be retired after commissioning of FCC-3
FCC-3 (under construction)                  2,000          Scheduled 1992 UOP/FSU/Rom.
Coker-1 (unk 41)                              530          1968           USSR
Vacuum distilltion of vac. residues (unit 42)  250
Coker-2 (unit 43)                           1,500          1986           USSR
Polymerisation (C4) unit (unit 33)            75           1965           USSR
Alkylation (C4) unit (unit 35)                120          1953           Stratco, USA          Shut down, lack of acid
Gas fractionation unit                        450                                               C3-C4 recovery to Poly unfit
Kero Merox                                    160
Thermal cracker/Visbreaker                   1,700
Utilities & Offsfles
1. All electric power purchased from State Grid
2. All steam purchased from nearby power/district heating plant
3. Cooling water make up purchased from Baku municipality
4. Crude oil storage. 130,000 m3 (located 15 km for refinery); product storage: 420,000 m3.
Crude oil from: (i) eleven domestic sources delivered by pipeline to Main Storage, all mixed, transported to refinery through 10 line, preferentially processed
through the Unit 15; (ii) imported crude from Kazahkstan transported by Caspian Sea, unloaded into small storage terminal at Baku port and pumped to Main
Storage, similarly imported crude from W. Siberia.



-120-
Page 2 of 2
Azerbailan: Azneftvaq Refinery. Physical Facilities
1. Atmospheric/Vacuum Distillation: Total 11.7 mtpy, consisting of
(i) AVU      :       6.0 mtpy
(ii) ADU      :      2.0
(iii) ADU      :      1.5
(iv) AVU              1.0
(v) AVU              0.6
(vi) ADU             0.6
2. Vacuum Distillate          :  6 units of total 1.8 mtpy capacity
3. Deasphalting Units         :  (i) 200,000 tpy; (ii) 300,000 tpy
4. Furfural Extraction Unit   :  700,000 tpy
5. Dewaxing Units             :  300,000 tpy total capacity
6. Lubes and wax hydrolicating  :  1 mtpy total capacity
7. Bitumen Manufacturing         160,000 tpy



AmemL4-3
Azerbal an - Refineries crude throughaut and oroduction of gain mroducts. 1961-92
1981      1982        1983        1984      1985        1986        197        1988         1969         1990       1991      1992
Crude oil Processed   20499       20393      20980       20723     21135       22022       22101        21699,6      18435        16331,6   15820      12099.5
Crude oil Suppty       20628      20467      21000       20854     21240       22062       22383,9      21757,8      18440        16342      15837      n.a.
- Domestic Crude      (13283)   (12161)    (11887)    (11855)   (12387)    (12719)        (13320,8)    (13262,6)   (12646,6)   (t2073)   (11088)   (10584.0)
- Russian Crude        (5054)    (5249)      (5562)      (4438)    (3203)    (3759,9)    (3562,8)       (3740,0)   (2879)         (2515)    (2514)    (854.5)
- Kazakhi Crude        (2171)    (3043)      (3551)      (4548)   (5612,5)   (5578.2)   (5500,6)        (4755,2)   (2909.7)       (1754)    (2235)   (661.0)
Main Products
Automtive gasoline    1992,3    2018,7       2079,4      1909,2    1898,3      2149,6      2121,3       1742,6        1549,2       1479.6   1173.7      1250.6
Diesel oit             3534      3796,6      3902,8      4010,6    4499,8      5004,3      5158,6       5145,1       4236,9        3974,7   3634,9    3949.3
* Bitusen               187,7      176,7      198,5       199,2     181,3       185,2       194,4        185,6       167,0          145,2    113,1      862.3 jl
Lubricating Oils       1131,8    1079        1193,0      1193,5    1118,3      1130,7      1103,5       1061,1       933,8         819,0    762,5    113.1
Coke                    125,4      132.0      132,7       128,5      102,5      149,6       226,1        244        Z29,8           178,4    161,3      180
Fuel Ofl               8837,9    9058,5      9048,8      9293,6    9316,0                                           9429.0        6579.0      6400     4999.7
Kerosene                M/A         N/A        N/A        l/A        N/A         N/A         N/A          N/A        1539.0        1304.0     1350      198.8
.~~ _                     .__                                                        --.._
i/ IncLudes coke and other products
Source: A2neftchim and mission estimates.



44
Azerbaiian - Tlaical Characteristics of Crude Oils. and of Mixtures CharRed to Refinen Units. 1991
Shirvani     Surakani      Karachukur    Oil Rocks       Buzachy            Tyumen
493           482          488           479
(onshore)    (onshore)     (onshore)     (offshorel    (Khazakhistanl       W. Siberia
1. Density @200C, gm/cc    0.8802        0.8573        0.8507        0.8573        0.9140              0.8374
(0.863-      (0.851-       (0.826-       (0.851-       (0.905-              (0.831-
0.898)       0.863)        0.832)        0.864)        0.9221)              0.843)
2. Distillation, wt %
distilled
IBP, OC                35            52            30           36            35                   53
150 'C         8.6           9.0          36.9           4.7           5.0                 16.0
250 'C         23.6          28.7          51.5         14.1          13.0                 31.5
350 'C         40.0          55.7         67.3          34.5          34.0                 53.9
N.,                400 'C          52.7          66.5         74.4          46.8          46.5                 61.0
3. Kinematic viscosity
@400C mm2/sec.            43.5          13.0           7.2          13.5         157.4                 7.4
4. Water content, % wt.    0.03-1.6      0.03-0.4      0.03-0.2      0.03-0.4      0.12-1.9             0.03-0.4
5. Chlorides, mg/litre     62-482        20-50         15-52         20-100        140-435              17-40
6. Sulfur, % wt.           0.21-0.35     0.2-0.27      0.13-0.28     0.18-0.35     1.17-1.89            0.4-0.6
7. Pour point, 0C            -36           -38           -38           -38          -15                  -18
8. Acidity,mg KOH             1.2          1.7           1.9           1.3           0.1                 0.1
9. Conradson carbon, % wt.    2.9          2.7           2.5           2.9           4.8                 0.3
10. Ash, % wt.               0.01          0.008         0.005         0.01         0.06                 0.02
11. Paraffins, %wt.          NA            5.1           4.7           5.1           1.8                 2.1
12. Asphaltenes, % wt.       NA            1.1           1.0           1.2           2.8                 2.7



Annex 5-1
Azerigaz Gas Acquisition Prices
(Rubles/1000 cm)
from SOCAR's
Karadoc Gas
Processing                from
from SOCAR       Plant                 Turkmen-
(wet gas)    (dry gas)    from USSR    istan
Full year 1991                         15             35          33       N/A
January 1, 1992                      87.50            175        N/A    1,181
January 11, 1992                     87.50           175         N/A    2,926
January 1, 1993                       600            600         N/A    9,543
January5, 1993                        600            600         N/A   15,129
Azerigaz Retail Prices (rubles/Mcm)
Industrial    Commercial  Household
Full year 1991                         61             61          12
January 1992                         1,954           305         250
April 1992                           2,450           305         250
December 1992                        5,655          1,171        384
January 1993                        18,377          3,294        720
May 1993                                                         720
Source: Azerigaz, May 1993
-125-



Annex 5-2
AZERBAUAN
Household Gas tarifs (Monthly) January 1,1993
GAS                 TAFDFF
USAGE      BASE    PLUS
UNIT OF             (cub. m.    TAPRFF   20% VAT
TYPE OF APPLIANCE                   MEASUREMENT         per mord    rublm   (rub)
1. FOR HOUSEHOLDS WIO DtSTRICT HEKTING
1 Gas stove                         per person/per month   21.50     7.20        8.64
2 Continuous flow water heater                              7.00     4.20        5.04
3 Boiler-type water heater                                 10.00     6.00        7.20
Non-standard water heaters
4a Indoor                           per device/por month     200      120      144.00
4b Outdoor (summer rate)                                     300      180      216.00
Outdoor (winter rate)                                      600      360      432.00
5 Radiator-type heater              per devIcper month       320      192      230.40
6 Cornb. brick stovefspace heater   during heating season    400      240      288.00
7 Wall-unit space heater                  a                  270      162      194.40
8 Iron stove                              '                 1200      720      864.00
Boilers for space heating         cub. m of heated space
9a Indoor (non-standard)                                    2.80      1.68       2.02
9b Outdoor (non-standard)                 '                 5.00     3.00        3.60
IO Factory made                           '                 2.00     1.20        1.44
11 Private commercial greenhouses  cub. m of heated space  20.00   368OO       441.60
II.  FOR HOUSEHOLD WITH DISTRICT HEATING
1 Gas stove                         perpersonper month     18.50     4.80        5.76
2 Continuous flow water heater            '                 7.00     4.20        5.04
3 Boller-type water heater                '                21.50      7.20       864
REFERENCE GAS PRiCES (rubles per cubic mete)
Non-standard (hand-made) boilers, radiators,     0.60
and wall stoves
0.26
Factory-made stoves and boilers
18.40
Primvate commercial greenhouses
Source: Azerlgaz, May 1993
-127-



Annex 5.3
Page 1 of 3
AZERBAIJAN GAS SUPPLY-DEMAND                        'BASECASE'
(Million Cubic Meters)
1990    1991    1992    1993    1994    1995    1996    1997    1998    1999    2000    2001    2002    2003    2004    2005
Production         11234   10052    9276    8436    7769    7167    6850    6120    S681    5482    58a5    6234    678s    7393    7785    8059
-COnshore            406      292      242      218     196      188       8 9     203     249      296      345      334      325     316      309      302
- Offshore         10828    9760    9034    8218    75e3   s679    6661    5917    s432    s18s    5491    5900    6461    7077    7476    7767
Venting             1309    1431    1431    1431    1431           0        0        0        0       0        0        0        0       0        0        0
Net Aailable        0925    8621    7844    7006    6328    7187    e6so    6120    5681    5482    58a5    6234    678s    7393    7785    8059
Imports            13114   14170    5263    4250    9003    8037    8228    8831    9143    0216   10461    0920    9227    8478    9009    9179
-Turtnkmenistan    11599   11163    4583    4000    na          na       na      na       na       na       na      na       no       na       na      na
- Iran              1515    3007       6so      250    na       na       na      na       na       na       na      na       no       na       na      na
Exports             5424    6996       951     100        0        0        0        0       0        0        0        0       0        0        0        0
Net Imports         7690    8174    4312    4150    9003    8037    8228    8831    9143    9216   10461    9920    9227    8478    9009    9179
Consumption        14238   13256    9538    9125   12670   12870   12670   12670   12670   12670   14170   14170   14170   14170   15670   15670
I- Power+H5eat      6474    4238    1621    1455    60005000 00   5000  5000    5000    a0 0                            o      m      6500  8000  8000
- Industry          S051    3118    2487    2220    2220    2220    222          2220    2220    2220    2220    2220    2220    2220    2220    2220
-Commercial         3012    2730    2600      2600     2600    2600    2600    2600    2600    2600    2600    2800    2600    2600    2600    2600
- DIstribution      2701    3170    2850    2850    2850    285          2850    2850    2850    28         2850    2850    2850    2850    2850    2850
Own UsslLoeaee      3373    3455    2413    2030    2181    2534    2407    2281    2164    2027    2126    1984    1842    1700    1724    1667
Balance                4       64      206      -0        0        0        0       0        0        0        0       -0      -0       -0       -0       -O
% LoSs                       17.9%    23.0a    22.0%    21.0%    20.0%6   19.0%    18.0%    17.0%    10.0%    15.0%    14.0Sb   13.0%    12.0%    11.0%    10.0%A



Annex 5.3
Page 2 of 3
AZERBAUAN GAS SUPPLY-DEMAND                         "*DELAYCASE --
(Million Cubic Motors)
1990    1991    1992    1993    1994    1995    1990    1997    1998    1999    2000    2001    2002    2003    2004    2005
Production         11234   10052    9276    8435    7675    6999    0474    6120    5462    4971    4960    4854    4990    5343    5937    6590
-Onshore             400      292      242      218     196      188      189      203      249     296      345      334      325     316      309      302
-Offshore          10828    9760    9034    8218    7479    6811    6285    5917    5213    4875    4815    4520    4665    5027    5628    6288
Venting              1309    1431    1431    1431    1431    1431    1431            0        0       0        0        0        0       0        0        0
Net Available       9925    8621    7844    7005    6245    5568    5043    6120    5462    4971    4960    4854    4990    5343    5937    6590
Imports            13114   14170    5263    4250    9087    9836   10035    8831    9362    9727   11336   11300   11023   10527   11457   10647
- Turkmenistan     11599   11103    4583    4000    na          na       na      na       na       na       na       na      na       na       na       na
- Iran               1515    3007      680      250    na       na       na      na       na       na       na      na       na       na       na       na
Exports             5424    5996       951     100        0        0        0        0       0        0        0        0       0        0        0        0
Netimports          7690    8174    4312    4150    9087    9636   10035    8831    9362    9727   11336   11300   11023   10527   11457   10647
Consumption        14238   13256    9538    9125   12670   12670   12670   12670   12670   12670   14170   14170   14170   14170   15670   15670                         0
- Power+Heat        5474    4238    1621    1455    5000    5000    5000    5000    5000    5000    6500    6500    6500    6500    8000    8000
- Industry          3051    3118    2467    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220
- Commercial        3012    2730    2600    2600    2600    2600    2600    2600    2600    2600    2600    2600    2600    2600    2600    2600
- Distributio,      2701    31 I 3    2850    2850    2850    2850    2850    2850    2850    2850    2850    2850    2850    2850    2850    2850
Own Use/Losses      3373    3455    2413    2030    2661    2534    2407    2281    2154    2027    2126    1984    1842    1700    1724    1567
Balance                4       84      206      -0        0        0        0        0       0        0        0      -0        0        0       -0       0
% Loss                       17.9%    23.0%    22.0%    21.0%    20.0%    19.0%    18.0%    17.0%    16.0%    15.0%    14.0%    13.0%    12.0%    11.0%    10.0%



Annex 5.3
Page 3of3
AZERBAUM GAS SUPPLY-DEMAND                          'LOW CASE*
(Million Cubic Metets)
1990    1991    1992    1993    1994    1996    1996    1997    1998    1999    2000    2001    2002    2003    2004    2005
Production         11234   10062    9275    8435    7759    7167    6850    5725    5056    4800    4892    6002    5200    5489    5629    5876
- Onshore            406     292      242     218      196      188     189     203      249      298     345      334     325      316     309     302
- Offhore          10828    9760    9034    8218    7583    6979    6681    5822    4807    4504    4648    4868    4884    5153    5320    6574
Venting             1309    1431    1431    1431    1431         0        0       0        0       0        0       0        0       0        0       0
Net Available       0925    8621    7844    7005    6328    7167    6850    6726    5055    48Q0    4892    6002    5208    5489    5629    5876
Imports            13114   14170    5263    4250    9003    8037    8228    9226    9769    9898   11404   11162   10804   10401   11785   11361
-Turkmenistan      11599   11163    4583    4000    na        na       na      na       na      na       na      na       na      na       na      na
- Iran              1515    3007      680     260    na       na       na      na       na      na       na      na       na      na       na      na
Expotts             6424    5996      961     100        0       0        0       0        0       0        0       0        0       0        0       0
NetImports         7690    8174    4312    4150    9003    8037    8228    9226    9769    9898   11404   11152   10804   10401   11765   11361
Consumption        14238   13256    9638    9125   12670   12670   12670   12670   12670   12870   14170   14170   14170   14170   16670   15670
- Power+Heat        5474    4238    1621    1455    5000               50      5000    6000    6000    6500    6500    6500    6500    8000    8000
- Industry          3061    3118    2467    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220    2220
- Commercial        3012    2730    2800    2600    2600    2600    2600    2600    2600    260          26      260      2600    26       2600    2600
- Distibution       2701    3170    2850    2850    2850    2850    2850    2850    2850    285          2850    2850    2850    2850    2850    2850
Own UeeLosses      3373    3456    2413    2030    2861    2634    2407    2281    2164    2027    2128    1984    1842    1700    1724    1567
Balance               4       84     208       -0       0        0       0        0      -0        0       0       -0      -0       -0       0        0
% Loss                      17.9%   23.0%   22.0%   21.0%   20.0%   19.0%    18.0%    17.0%    16.0%    15.0%    14.0%   13.0%    12.0%    11.0%   10.0%6



Annex 5.4
Pricing of Domestic Natural Gas Production                                       Page I of 2
1.    Azerbaijan is an unusual gas market, in that domestic production is relatively large, but
insufficient to supply all domestic requirements.  Imported gas from  Turkmenistan, Russia and
(potentially) Iran is (in theory at least) readily available in large quantities. A significant part of demand
in the power sector (amounting to about 40 percent of total consumption) is directly substitutable for fuel
oil in existing dual-fired boilers, while the balance of demand (in the industrial, residential and
commercial sectors) is not easily substitutable.
2.    The level at which domestic natural gas production should be priced will depend upon the
relationship between domestic natural gas supply and total demand. Domestic natural gas output displaces
either imported natural gas or fuel oil (for export), depending upon the level of domestic production, the
demand for gas in the country and the relative economic value of gas imports and fuel oil exports
Where imported natural gas is valued below exported fuel oil, domestic natural gas should be priced to
compete with imported gas provided that its cost of supply is competitive, ie. the producer price of gas
should be based upon the import price (adjusted for transport costs). However, if imported natural gas
is priced above fuel oil export value, then domestic gas will compete with imported gas in the industrial,
commercial and residential markets (the "premium" markets where there is no possibility of substitution),
and with fuel oil in the power market (where substitution between gas and fuel oil can take place), again
provided that its cost of supply is competitive. In this case, the level of pricing will depend upon the
relationship between domestic gas output and the requirements of the "premium" markets: if domestic
output is below "premium" demand then domestic gas competes with imported gas and the price of
domestic gas should be set at the import level; however, if domestic gas output exceeds the requirements
of the "premium" market, then domestic gas competes with fuel oil in the power market, and the price
should be set at the (lower) fuel oil export parity, plus a premium to reflect the cleanliness and ease of
handling of gas.
3.    These factors are illustrated in the figure. G,, and GU are two levels of natural gas import price,
with the corresponding (flat) supply curves for imported gas. FO is the world price value of fuel oil
exports. S, and S2 are two (vertical) supply curves for domestic natural gas production, reflecting
possible alternative levels of supply. D is the demand curve for natural gas. Demand is inelastic in the
industrial, commercial and residential sectors, which account for about 10 BCM of demand. Demand
in the power sector, of about 5 BCM, is infinitely elastic at the fuel oil export parity price, since at gas
prices above this level only fuel oil is used, while at prices below this level only gas is used.
4.    With the natural gas import price level at GL2, domestic gas must be priced no higher than this
level if it is to gain a market at all, ie. at both S, and S2 the price of domestic gas production should be
the imported gas price. However, with imported gas prices at G,l and available domestic supply equal
to S2, the price for domestic gas should be equal to the fuel oil price (FO), since at such high imported
gas prices the power sector will be using fuel oil, and domestic gas will be competing with fuel oil. If
domestic supply is at SI, however, domestic gas should be priced at the imported gas price (GI,), since
at this level of supply domertic gas is competing only with imported gas.
5.    It is probable that pricing according to the import price of natural gas will tend to predominate
in Azerbaijan, at least until 2000, since domestic output will probably be below premium demand.
However, gas import prices may well be above the export value of fuel oil in the long run. In this case,
a large increase in domestic gas production, combined with stagnant or falling premium demand, could
lead to pricing of gas at fuel oil parity. If some of the dual-fired power stations are replaced by
combined cycle stations, which cannot switch to fuel oil, this will effectively increase the likelihood of
prices being set by the gas import parity.
-133-



Annx 5.4
AZERBAIJAN NATURAL GAS SUPPLY  DEMAND & PRICE  Page2of2
SI          D                       2
U~~' I
6~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ .
FO                                                   l
.........   .......................................... ...... .... ...... ...................................   ........... ,........... ....  -......|
%~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
l                                  l
'1-                                 I                                           I  §  
§   .   5                     110                          15    BCM
INDUSTRIAL, COMMERCIAL                             POWER DEMAND
& RESIDENTIAL DEMAND~~~~~~I 



Annex 6-1
AZERBAUAN
Existing Generating Plants
No. of Units x        Commissioning          Installcd              Available                Average Fuel
Unit Size              Dates                Capacity              Capacity                Consumption
A. Thermal Power Stations
1. Azgres                                 8 x 300 MW                1981-90               2,400                 1,600                   360g/kWh
2. t.fi-Bayramli Gres                      7 x 150 MW               1962-70                1,050                  950                   386g/kwH
3. Gres Scvernaya^ +                         I x 150                  1960                  150                   145                   400g/kWh
Subtotal                                                                                   3,600                2,695
B. Combined Heat and Power Stations
4. Baku CHP I CHP                            2 x 50                 1937-75                 100                 50/30                 159g/kWb and
I1Og/Gcal
S. Baku CHP 2 CHP                             4 x 6                   1953                   24                     6                 170g/kWh and
LO                                                                                                                                                   168g/Gcal
6. Sumgait CHP-I CHP                         4 x 50                   1959                  200               200/110                 365gikWh and
179g/Gcal
7. Sumgait CHP-2 CHP                         2 x 60                   1966                  220               210/110                 170g/kWh and
2 x 50                  1966                                                              168g/Gcal
8. Gandja CHP CHP                            3 x 24                   1964                   72                 40/30                 256gtkWh and
Subtotal                                                                                     616               506/286
C.  Hydro Electric Plant
9. Mingechaur H                              4 x 60                   1953                  240               240/140
10. Shamkor H                               2 x 190                  1982                   380               380/190
11. Araks H                                  2x.t1                                           22                    -
12. Ter Ter H                                                                                50                    -
Subtotal                                                                                      692               620/330
Total                                                                                       4,908         3,821/3,311 *
* Based on a reference fuel of 7,000 kcal/kg heating value.
** Available Capacity Summer/Winter
Source: Azenergo



Annex 6-2
Azerbaijan
Existing and Projected generating capacity
1991   1992   1993   1994   1995   1996   1997   1998   1999   2000   2005
(a) Hydro
-Mingechaur         240    240    240    240    240    310    380    390    400    400    400
-Shamkor            380    380    380    380    380    380    380    380    380    380    380
-Yenikand                                          75      75   110.5    150    150    150    150
-Araks*                                   (22)   (22)   (22)   (22)   (22)   (22)   (22)   (22)
-Ter Ter *                                (50)   (50)   (50)   (50)   (50)   (50)   (50)   (50)
(b) Steam
-Azgres           1,600   1,600   1,830  2,060   2,060  2,430  2,430  2,430   2,430  2,430   2,430
-All Beramli       950    950    950    810    810    81,    675    675    540    540    300
-Severnaya          145    145    125    125    125
_ ~~(c) CHF
-Baku I             50      50      50     50      50    100    100    100    100    100    100
-Baku 2               6      6                                                                  55
-Sumgait1           110    110    110    110    110       55      55      55     55      55    100
-Sumgait 2         210    210    210    210    210    150    150    150    150    150           40
-Gandja             40      40      40     40      40     40      40      40     40      40
(d) New cap.                                                                      200    200    800
(e) Total cap.      3,731   3,731   3,935  4,165   4,165  4,420  4,285  4,370  4,395  4,595  5,155
(f peak load        3,700   3,370  3,250   3,110  3,130  3,200  3,270  3,340  3,420  3,480   3,850
(g) RqeserVe(MW)       31    361    685   1055   1035   1220   1016   1030    975   1115   1305
1    10                 17      25     25      28     24      24     22      24     25
Source: Azenergo
filename: m:IsoIazb.wk1



Annex 6-3
AZERBAIJAN
Electricity Tariffs
1990        1991         1991      1992     1992     1993
1st quarter    4th quarter    01/01    05101    01101
1. Industrial (>75OkVA)
o Fixed charge R/kW      3.5          5.0         11.1      55.5    105.5    6,200
25.0     47.5
o Energy Kop/kWh          1.7         3.4          5.7      28.0     54.0      385
2.3              24.0
2. Industrial (<75OkVA)    3.0          5.4          8.9      44.4     84.4      570
Kop/kWh                                            4.0      20.0     38.0
3. Agricultural                         1.4          6.3       8.0     15.2      308
Kop/kWh                  1.8                                 5.0      9.5
4. Railway                              4.1          6.7      33.3     63.3      554
Kop/kWh                  3.0
5. Urban Transport                      5.4          4.0     20.0      38.0      400
Kop/kWh                  2.0
6. Commercial                           5.4          8.9      44.4     84.4      770
Kop/kWh                  3.0                       4.0     20.0      38.0
7. Residential (urban)     4.0          4.0          4.0      12.0     12.0       80
Kop/kWh                  2.0          2.0          2.0       6.0      6.0       50
8. Residential (rural)      1.0         1.0          1.0       8.0      8.0       70
Kop/kWh                  0.5          0.5          0.5       4.0      4.0
- Average Tariff: 4.30 R/kWh
- Export tariff to Georgia: 18 R/kWh (as of February 1993)
filename: m:ksolaztarif.wk1
-139-



Annex 7.1 Azerbaijan Energy Sector Institutions
President                                                            Parliament
Council of
Ministers
Deputy              Ministry of
Prime               Economy
Minister
I-
Stt Fue                    Stt Oil 
Otf.hor.~~~~~~~~~~~~~~~~~~~~~~~~ Fleet
Cota                       Newefin                                                 ,e
09~~~ ~ ~             Equlrnen Dept       }                                                            f
Di"utio                                                                                         5  Iotiut
Prdcto  Depat.                 fyg                                                  a
iDOii.iiiteltzones



IBRD 24912
500                                                        51°
AZERBAIJAN
OIL AND GAS FIELDS
APSHERON~~~~~~ GAS FIELDS
APSHERON                                                      OS
OIL FIELDS
RIVERS
DARWIN
MASHTAG)lBUZOVNY                                                       -       INTERNATIONAL BOUNDARIES
SURAKHANY
HALAKHANY-SAUNCHI-RAMANY, '                                   ARTEM
SUM
OAKUE
<-  Bt31EMBAr       <       s                               '- . iZ     .     GUNESHLI
RBIB EYBAT          t%rO                                       foGUOS
KARADAG                                                               OIL ROCKS
EAKHAR  ~ ~      ~       ~       ~       1NIEG\
DIUVANNYWI 
4O0 '-                                                                                      / '''                                                                            o-
iMISHOVDAG             ALLATY                                                  SHAK DANIZ ..-
SrRUCTURE-
.   .              w  2 3~~~~~UUA DANIZ
.KYUROVDAG                                                                                                                                                           .
. 'IJROL'Am                                                                                                                                      FEDERATION
7114ANGYA                                                                TM~~~~~~~~~~~~~~~~~~~~~~~~~~~i Wo b.0 000roo.d
',  C'LRSANGYA                                                                                    br ThO P   BmdbimEnn;FteHo0 rd 0                      KAZAKHSTAN
of -.d- 0 0,0   f., lb.GORI
KARABAGLY                            OTd 255
01                          25                            f0o~h Ooe,oA li. oooo
V            |                  -         t        _                    ~     ~     ~~~~~~~~~~~~~~            ~      ~~~~~~~~~~~~I  L 0010 n,pooiooof,oono,.
TOOmm onrO AI Rmook Gor T,R.Y
DUROVDAS50Oonoo
DUROYGKiLOMTERS              25               50               75                   e                                                    TURKMENISTAN
v    i  5lo          / IRA         F Q RAN
AUGUST 1993



IBRD 2491 1
CAUCASUS REGION
0           200           400           600                                             POTENTIAL EXPORT PIPELINE ROUTES
KILO METERS                                                                                   POTENTIAL EXPORT ROUTES
TANKER PORTS
0     SELECTED TOWNS
INTERNATIONAL BOUNDARIES
X   X                ~UKRAINE 
0~~~~~~~~; 2  U K R A I                                                           A   N Evro
RUSSIAN FEDERATION
ROMANIA .
8~~~~~~~~~~~~~~~~~~~                                                                                       ~        ~~~~ oNovorossiysk                  LJJ-- AHSA
KAZAKH STAN
SIOCli 9e(D r < < °~~~~~~~~Grozny 19.
1310c1\ ~~                  ~'. jCO                                                             -7
O/t&s                                                                             EO RG IA                         Caspian  Sea
jstanbul
Trobzon                                            AE AIJAN                            TURiXWENISTAN
|    RENIA
This map has bee. pmepored
bi The World Bosk's stoff     TURKEY
of =sei for the monnmnitnce ,
isnfters eusde ofTeis  forld   the
Group.Tht denonrinohnss used
and the boundaries sho
on this mo do not impk on the
pod of The World okn Group,
jomjr4ent on  the leal,
truotoytenritory or nBamn 
endorsement or occeptance                                                   _
such boundaries.
Ceyhan                                                                    ISLAMIC  REPUBLIC
J              [I     k        e     y     e u n)             (Iskenderun)                       OF  IRAN                       -
Mediterrane a           ' 1 -  Sea                   Y RE PIIP I IC              /        IRAQ
AUGUST 1993



IBRD 24906
4' This mop has been  prepared                                   4
by TheRP WyhoJrld Befoano k's staff4e                                                                                                                                                           so                            42 -
exclusrvel for the conoenience
of reders and  is for the
internal use of The Worldboek BaI[nkk1                                                                                                                                                      AZERBAiJAN
GroupThe dernominotions used                                                                                 RA /                                                                           A Z         A
and rthe boundaresshos                GEORGIA                        ;r,     Balaken                                                               Khudat                        NATURAL  GAS  SYSTEM
Part of The World BanhGop
ony judment oan the legal                                                                                 FEDERATION
status o any territory or on
endorsement r occeptsnceor                                                                                                                                                                       MAIN GASTRANSMISSION LINES
such boundonies.'                                                               '  
=-d, boundaries.                                                                                             Khachmas                                COMPRESSOR  STATIONS
Gubo  a                                                 EXISTING GAS STORAGE FIELDS
GAS PROCESSING PLANT
:1- .-.                                                                                                    .SELECTEDTOWNSAND         GE
\   /6   N ,                                                                                          *       NATIONAL CAPITAL
Tagheo4'§' ><, .......                                                                                                                                         - . .  t  \   , tINTERNATIONAL BOUNDARIES
/  ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~   ~~~~RIVERS
ARMENIA                                                                          ..                                           / jShamokhy
/                ~~~~~Yenlokh                           ~"
.t  >  holde   ,_  0  '\ - I   *  P.AKU
Berde                                                                                      % ,'
Aghiabedi         v/-                                                                                            40'-
Aghdomr                                          SabirabG                           I
TURKEY <wt9es                                       9                               /                                       ''
}  xb Sherour                                                                                                                            /                            CASPIAN  SEA
\Khojavend                                                       S ,alyan
Bilasuvar,
J 9 \ AZERBAIJAN .  X  ,> t;                                                                              .                                                            '
Mi van' Nakhchevan                                                                                                  RUSSIAN
(  t  Chulfa  \            A5iivonX                                                        i             -                                    FEDERATION
Se_  t   '   BauK                     KAZAKHSTAN
GEORGIA
ISLAMIC REPUBLIC OF IRAN                                                                                 'Lenkeron                         ARMENIA
0               25              50            75                                                                                                                             ARMENKE
KILOMETERS1                                                                                                                                                                                                      TURKMiENISTAN
ISLtAMIC REP
SI.  : . s/.                  46J                                                                                                                             IRAQ        OP IRAN
AUGUST 1993



IBRD 24970
42'
48                                                              50                            42 -
AZERBAIJAN
GEORGIA                             RUSSIAN                                                                ELECTRICITY GRID
GEORGIA                                           '                                                         Khudat
FEDERATION                          IEXISTING POWER LINESi
.   t      E D E RAT 10 N               /'                                                      500 kV
Khochmos                                    330 kV
A4                                                               t .                              }                              ii ,I Guba  220 kV
.   ,    ,   .  1'    /                                                                    EXISTING POWER SUBSTATIONS
,. . '---So 500 kV
.- >,  .   i                                                                                            t        2330 kV
220 kV
Toghuz                                                      Ismoily                                                                              HYDRO POWER PLANTS
THERMAL POWER PLANTS
ARMENIA                                                                                                                                            Shamakhy
;                                  Yewlokh                          _            ,                                   B  @g3            @3eviak
.                                                    ~~~~~~~~~       ~     ~    ~~~~~Myusyushyu  
Berde                                                                                   n
\                  ~~~~~~A Z E R B A i J A N 
g                      ..~~~~~~~~~~~~~~~~~~~~~~~~~~~
SELECTED TOWNS AND) VILLAGES
Aghiabedi                                                                      *       NATIONAL CAPITAL
.>  .  Aghdam                                   Sabirobad/             ES                               , .       INTERNATIONAL BOUNDARIES
t  t                                                                       g_    /                                              ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-' =--    RIVERS
TURKEY                                                                                                                                                                                                    PJVERS
Sherour
a        \                     /   |)                                                            /X     Blosvcr                                      - AZEo                      C A S P I A N S E A
-X--w'                 <   AZERBAIJAN                                  ---                              Af                                  Biaua                                             APA                 E
t  t  f  g  .  so~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~o
Nakhchevan
A  ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~a~~~~Msaiii                                                       RUSSIAN
Cht ulh fa}    jff                                                                       >:          Mawili                                  FEDERATION
k.                                                                                                    $ Bl -                                KAZAKHSTAN
This map has been prepared
by The World Bank's staff                                I~~A~'RP BI                                                                                                                 ERI
rclusively for the connenience                           ISLAMIC  REPUBLIC  OF  IRAN                                                                                               -GEORGIA
.   of reoders and is for the                                                                                              
intenrI uwsa of The World Rank                                                                                                                     Lenkeran
rg  Group.7he demmnobonin s- used                                                                                                                       Lnea
and the boundaries shown                                                                                                              AA>                                          ARMAENIA
on this modo not implo an th.                                            0               25              so             75                                                 TURKEY             AZERBAiJAN
part of   WoridHan. Groun.                                        MaŁ     1               I                I            II
any iudgment on the legalP 
C...    stats's of any territory or ony                                   KIIOMETERS                                                                    Ast I  X                                                       TREIA
such boundaries.                                                                   25        so       75                                                                                                     TURKMENISTAN
7   endorsement or acCeptance a    0        25        50       75                                                                                 ISLAMIC REP~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ILAMC EP
_ 2 | _ '                                                IRAQ        OF IRAN
AUGUST 1993