The Economics of Petroleum Exploration and Development in Viet Nam

By H. Luong Lien

A thesis submitted to The University of New South Wales in partial fulfilment of the requirements for the Degree of Master of Engineering

December, 1998

School of Petroleum Engineering The University of New South Wales, Sydney, NSW, AUSTRALIA ACKNOWLEDGEMENTS

My sincerest thanks go to Mr. Guy Allinson and Associated Professor Sheik Rahman from the School of Petroleum Engineering, University of New South Wales, for their supervision and supports. Without their encouragement, support, flexibility and guidance, this thesis could never have become reality. My special thanks to Mr. Guy Allinson for making time for me despite his busy schedules. Guy gave me my first break by agreeing to supervise my research and giving me directions. Guy also gave me the opportunity to work at Petroconsultants and Cairn Energy. I thank him for his invaluable guidance and feedback, and his patient reading of my write-ups.

I am also indebted to Petroconsultants Australasia in Sydney for permission to use their library and other data belong to the company. I wish to thank Mark Elliston from Petroconsultants Australasia for his advises and helps in building the cashflow models. Many thanks to Jenny, Rebecca and Kim from Petroconsultants Australasia for their assistance in helping me finding the data and information incorporated in this thesis.

I would like to thank all the people that I met in PetroVietnam last year for their willingness to help me understand various aspects of the petroleum industry in Viet Nam.

I thank my parents for their love and supports through the years, and for encouraging me to stay in Australia two more years to take this Master research course. They are my motivation when I lost interests in studying. I thank my Khanh for his love and patience and for always being there for me through good times and bad. Warmest thanks to my house-mates Uyen, Binh, Due, Tuan for their friendship. They were my second family when I was miles away from home. ABSTRACT

When international oil companies make investment decisions to explore for and develop petroleum resources in a particular country, they need to examine many aspects of that country to assess the opportunities and risks associated with the new market. The main objective of this thesis is to provide a detailed assessment of various factors affecting the economics of petroleum exploration and development in Viet Nam from the investors’ point of view.

The thesis includes information and analyses on geography, business environment, infrastructure, and the energy market in Viet Nam. The country’s petroleum exploration performance and field developments are also discussed in detail. Exploration and development costs are estimated for different areas of Viet Nam. The structure and components of Vietnamese fiscal regime are examined and analysed to gain a better understanding of the current forms of petroleum arrangement in Viet Nam. Most importantly, the economic and sensitivity analyses are carried out to demonstrate the profitability of exploring for and developing representative oil and gas discoveries in different physical and geological conditions. In addition, fiscal analyses are conducted to assess the economic effects of the government take on marginal projects. Contents Page 1

The economics of petroleum exploration and development in Vietnam

Contents

Acknowledgments

Abstract

Chapter 1. Introduction Page 1.1

Chapter 2. Summary and conclusions Page 2.1

Chapter 3. Geography

3.1 Petroleum activities Page 3.1 3.2 Climate Page 3.4 3.3 Topography Page 3.8 3.4 Vegetation Page 3.10 3.5 Bathymetry Page 3.10 3.6 Sea conditions Page 3.11 3.7 Population Page 3.12

Chapter 4. Infrastructure

4.1 The economy Page 4.1 4.2 The oil and gas industry Page 4.2 4.3 The labour market Page 4.3 4.4 Roads Page 4.3 4.5 Railways Page 4.4 4.6 Inland waterways Page 4.4 4.7 Ports and shipping Page 4.7 4.8 Airports Page 4.10 4.9 Electricity distribution Page 4.10 4.10 Telecommunications Page 4.11 4.11 Financial services Page 4.12 4.12 Pipelines Page 4.13 4.13 Shipping and shipbuilding Page 4.15 4.14 LPG facilities Page 4.15 4.15 Liquids distribution Page 4.17 4.16 Refineries Page 4.18 4.17 Petrochemical plants Page 4.19 4.18 Power generation from gas Page 4.21

Author: Huong Luong Lien December 1998 Contents Page 2

Chapter 5. The energy market

5.1 Crude oil Page 5.2 5.1.1 Crude oil reserves and production Page 5.2 5.1.2 Crude oil quality Page 5.3 5.1.3 Crude oil price Page 5.4 5.2 Petroleum products Page 5.5 5.2.1 Petroleum product supply Page 5.5 5.2.2 Petroleum product demand Page 5.5 5.2.3 Petroleum product quality Page 5.7 5.3 Natural gas Page 5.8 5.3.1 Natural gas supply Page 5.8 5.3.2 Natural gas demand Page 5.10 5.3.3 Natural gas price Page 5.11 5.4 Liquefied petroleum gas (LPG) Page 5.12 5.4.1 LPG supply Page 5.12 5.4.2 LPG demand Page 5.14 5.4.3 LPG price Page 5.15 5.5 Coal Page 5.16 5.5.1 Coal supply Page 5.16 5.5.2 Coal demand Page 5.17 5.6 Electricity Page 5.18 5.6.1 Electricity supply Page 5.18 5.6.2 Electricity demand Page 5.21 5.6.3 Electricity price Page 5.22

Chapter 6. Exploration performance

6.1 Definitions Page 6.1 6.2 Exploratory drilling Page 6.3 6.3 Exploration history Page 6.14 6.4 Reserves Page 6.21 6.5 Geophysical surveys Page 6.24 6.6 Malaysia - Viet Nam Commercial Arrangement Area Page 6.28

Author: Huong Luong Lien December 1998 Contents Page 3

Chapter 7. Existing and future field developments

7.1 General field characteristics Page 7.1 7.2 General field development styles Page 7.2 7.3 The Bach Ho offshore oil field Page 7.3 7.4 The Rong offshore oil field Page 7.8 7.5 The Dai Hung offshore oil field Page 7.10 7.6 The offshore oil field at Malaysia - Viet Nam Commercial Arrangement Area Page 7.13 7.7 Some future field developments Page 7.17 7.7.1 Rang Dong offshore oil field Page 7.17 7.7.2 Ruby offshore oil field and other discoveries in Block 01 Page 7.21 7.7.3 Lan Tay/Lan Do offshore gas discoveries Page 7.25 7.7.4 Hai Thach offshore gas & condensate discovery Page 7.26

Chapter 8. Exploration and development costs

8.1 Exploration cost estimates Page 8.2 8.2 Offshore field development cost estimates Page 8.4 8.2.1 Fixed platform oil field development cost estimates Page 8.7 8.2.2 Fixed platform gas field development cost estimates Page 8.10 8.2.3 FPSO tanker oil field development cost estimates Page 8.13 8.3 Onshore field development cost estimates Page 8.15 8.3.1 Onshore oil field development cost estimates Page 8.15 8.3.2 Onshore gas field development cost estimates Page 8.17

Chapter 9. Fiscal Regime

9.1 Structure of Vietnamese PSCs Page 9.1 9.2 Illustration of workings of Vietnamese PSCs Page 9.5 9.3 Components of Vietnamese PSCs Page 9.7 9.3.1 Royalty Page 9.7 9.3.2 Cost recovery Page 9.8 9.3.3 Income tax Page 9.11 9.3.4 Profit sharing Page 9.11 9.3.5 Transfer tax Page 9.12 9.3.6 Export duty Page 9.12 9.3.7 Bonuses and Fees Page 9.13 9.3.8 State Participation Page 9.14 9.4 Recent development in Vietnamese fiscal regime Page 9.15 9.5 Worked example of a Vietnamese PSC Page 9.16

Author: Huong Luong Lien December 1998 Contents Page 4

Chapter 10. Fiscal analyses 10.1 Government Take Page 10.1 10.2 Impact of individual fiscal components Page 10.3 10.3 Fiscal comparison Page 10.8 10.4 Reserves made uneconomic because of Government Take Page 10.9

Chapter 11. Economics 11.1 Objectives Page 11.1 11.2 Cases analysed Page 11.1 11.3 Approach Page 11.2 11.4 Net Present Value per barrel or per million cubic feet graphs Page 11.3 11.5 Minimum prospect reserves graphs Page 11.5 11.6 Economic assumptions Page 11.7 11.7 Market assumptions Page 11.8 11.8 Development assumptions Page 11.8 11.9 Onshore north Viet Nam - oil exploration and field development economics Page 11.12 11.10 Onshore north Viet Nam - gas exploration and field development economics Page 11.17 11.11 Offshore shallow water north Viet Nam - oil exploration and field development economics Page 11.22 11.12 Offshore shallow water north Viet Nam - gas exploration and field development economics Page 11.27 11.13 Offshore shallow water south Viet Nam - oil exploration and field development economics Page 11.32 11.14 Offshore shallow water south Viet Nam - gas exploration and field development economics Page 11.37 11.15 Offshore deep water south Viet Nam - oil exploration and field development economics Page 11.42

Appendix A - Reserves Definitions Page A. 1

Appendix B - Conversion factors Page B. 1

Appendix C - Abbreviations Page C. 1

References Page R. 1

Author: Huong Luong Lien December 1998 Contents Page 5

The economics of petroleum exploration and development in Vietnam

Contents

List of figures

Figure 3.1 Viet Nam location map Page 3.2 Figure 3.2 Viet Nam petroleum activity map Page 3.3 Figure 3.3 Prevailing winds in northern monsoon, October to April Page 3.5 Figure 3.4 Prevailing winds in southern monsoon, May to September Page 3.6 Figure 4.1 Viet Nam’s GDP growth rate Page 4.1 Figure 4.2 Viet Nam’s Inflation Page 4.1 Figure 4.3 Viet Nam’s crude oil production Page 4.2 Figure 4.4 Economic infrastructure in North Viet Nam Page 4.5 Figure 4.5 Economic infrastructure in South Viet Nam Page 4.6 Figure 4.6 Main cities and ports Page 4.9 Figure 4.7 Southern Viet Nam gas pipelines Page 4.14 Figure 4.8 Gas-fired power plants in southern Viet Nam Page 4.22 Figure 5.1 Viet Nam’s energy flow chart for 1997 Page 5.1 Figure 5.2 Viet Nam’s crude oil daily production Page 5.3 Figure 5.3 Viet Nam’s coal production Page 5.16 Figure 5.4 Viet Nam’s coal exports Page 5.17 Figure 5.5 Viet Nam’s electricity output Page 5.18 Figure 5.6 Current and planned fuel shares of electricity generation Page 5.19 Figure 6.1 Tertiary basins in Viet Nam Page 6.5 Figure 6.2 Drilling statistics by area Page 6.11 Figure 6.3 Historical drilling statistics Page 6.13 Figure 6.4 Reserves distribution Page 6.23 Figure 7.1 Bach Ho development scheme Page 7.6 Figure 7.2 Rong possible full field development plan Page 7.9 Figure 7.3 Dai Hung development scheme Page 7.12 Figure 7.4 Rang Dong Phase 1 development scheme Page 7.18 Figure 7.5 Rang Dong possible full field development plan Page 7.20 Figure 7.6 Ruby Phase 1 development scheme Page 7.22 Figure 7.7 Ruby full field development plan Page 7.24 Figure 7.8 Hai Thach field development plan with PDQ platform Page 7.27 Figure 9.1 General structure of production sharing contracts in Viet Nam Page 9.4 Figure 10.1 Impact of individual fiscal components Page 10.4 Figure 10.2 Fiscal components as a percentage of Project NPV Page 10.5

Author: Huong Luong Lien December 1998 Contents Page 6

Figure 10.3 Economic effects of Vietnamese fiscal regime Page 10.7 Figure 10.4 Probability distribution for oil reserves in offshore south Viet Nam basins Page 10.12 Figure 10.5 Field size versus Portion of total reserves Page 10.13 Figure 11.1 An example of net present value per barrel graphs Page 11.4 Figure 11.2 An example of minimum prospect reserves graphs Page 11.6 Figure 11.3 Base case oil field development economics for onshore north Viet Nam Page 11.14 Figure 11.4 Base case oil exploration economics for onshore north Viet Nam Page 11.14 Figure 11.5 Sensitivity of oil field development economics for onshore north VietNam Page 11.15 Figure 11.6 Sensitivity of oil exploration economics for onshore north Viet Nam Page 11.16 Figure 11.7 Base case gas field development economics for onshore north Viet Nam Page 11.19 Figure 11.8 Base case gas exploration economics for onshore north Viet Nam Page 11.19 Figure 11.9 Sensitivity of gas field development economics for onshore north Viet Nam Page 11.20 Figure 11.10 Sensitivity of gas exploration economics for onshore north Viet Nam Page 11.21 Figure 11.11 Base case oil field development economics for shallow water north Viet Nam Page 11.24 Figure 11.12 Base case oil exploration economics for shallow water north Viet Nam Page 11.24 Figure 11.13 Sensitivity of oil field development economics for shallow water north Viet Nam Page 11.25 Figure 11.14 Sensitivity of oil exploration economics for shallow water north Viet Nam Page 11.26 Figure 11.15 Base case gas field development economics for shallow water north Viet Nam Page 11.29 Figure 11.16 Base case gas exploration economics for shallow water north Viet Nam Page 11.29 Figure 11.17 Sensitivity of gas field development economics for shallow water north Viet Nam Page 11.30 Figure 11.18 Sensitivity of gas exploration economics for shallow water north Viet Nam Page 11.31 Figure 11.19 Base case oil field development economics for shallow water south Viet Nam Page 11.34 Figure 11.20 Base case oil exploration economics for shallow water south Viet Nam Page 11.34 Author: Huong Luong Lien December 1998 Contents Page 7

Figure 11.21 Sensitivity of oil field development economics for shallow water south Viet Nam Page 11.35 Figure 11.22 Sensitivity of oil exploration economics for shallow water south Viet Nam Page 11.36 Figure 11.23 Base case gas field development economics for shallow water south Viet Nam Page 11.39 Figure 11.24 Base case gas exploration economics for shallow water south Viet Nam Page 11.39 Figure 11.25 Sensitivity of gas field development economics for shallow water south Viet Nam Page 11.40 Figure 11.26 Sensitivity of gas exploration economics for shallow water south Viet Nam Page 11.41 Figure 11.27 Base case oil field development economics for deep water south Viet Nam Page 11.44 Figure 11.28 Base case oil exploration economics for deep water south Viet Nam Page 11.44 Figure 11.29 Sensitivity of oil field development economics for deep water south Viet Nam Page 11.45 Figure 11.30 Sensitivity of oil exploration economics for deep water south Viet Nam Page 11.46

Author: Huong Luong Lien December 1998 Contents Page 8

The economics of petroleum exploration and development in Vietnam

Contents

List of tables

Table 2.1 Oil and gas discoveries Page 2.3 Table 2.2 Summary of results Page 2.6 Table 3.1 Temperature comparisons Page 3.8 Table 4.1 Crude oil exports and Petroleum product imports Page 4.2 Table 5.1 Significant oil discoveries in Viet Nam Page 5.2 Table 5.2 Vietnamese crude oil quality Page 5.3 Table 5.3 Petroleum products consumption from 1990 to 1997 Page 5.6 Table 5.4 Forecast of domestic demand for petroleum products to 2020 Page 5.6 Table 5.5 Potential gas resources Page 5.9 Table 5.6 Gas demand forecast in billion cubic feet per year Page 5.10 Table 5.7 LPG storage and bottling capacity Page 5.13 Table 5.8 Forecast LPG demand in Viet Nam 2000-2020 in thousand tonnes Page 5.14 Table 5.9 Viet Nam’s existing and planned additional electricity generation facilities Page 5.21 Table 6.1 Statistics of wildcat wells drilled from 1974 to 1997 inclusive Page 6.6 Table 6.2 Drilling statistics by area Page 6.10 Table 6.3 Historical drilling statistics Page 6.12 Table 6.4 Viet Nam oil and gas field/discovery statistics by area Page 6.15 Table 6.5 Commercial oil and gas reserves Page 6.21 Table 6.6 Geophysical surveys in Viet Nam Page 6.25 Table 6.7 Results of PM-3 well tests Page 6.29 Table 6.8 PM-3 original recoverable reserves Page 6.29 Table 7.1 Distribution of oil production from 1994 to 1997 (barrels of oil per day) Page 7.1 Table 8.1 Assumptions for oil and gas field developments in Viet Nam Page 8.4 Table 8.2 Summary of estimated base-case oil and gas field development costs Page 8.5 Table 8.3 Unit development costs for offshore oil and gas fields Page 8.6 Table 8.4 Detailed development cost estimates for base case hypothetical oil fields - shallow water/fixed platform north Viet Nam Page 8.8 Table 8.5 Detailed development cost estimates for base case hypothetical oil fields - shallow water/fixed platform south Viet Nam Page 8.9 Table 8.6 Detailed development cost estimates for base case hypothetical gas fields - shallow water/fixed platform north Viet Nam Page 8.11 Author: Huong Luong Lien December 1998 Contents Page 9

Table 8.7 Detailed development cost estimates for base case hypothetical gas fields - shallow water/fixed platform south Viet Nam Page 8.12 Table 8.8 Detailed development cost estimates for base case hypothetical oil fields - deep water/FPSO tanker south Viet Nam Page 8.14 Table 8.9 Unit development costs for onshore oil and gas fields Page 8.15 Table 8.10 Detailed development cost estimates for base case hypothetical oil fields - onshore north Viet Nam Page 8.16 Table 8.11 Detailed development cost estimates for base case hypothetical gas fields - onshore north Viet Nam Page 8.18 Table 9.1 Royalty scale for crude oil in Vietnamese PSCs Page 9.7 Table 9.2 Royalty scale for natural gas in Vietnamese PSCs Page 9.8 Table 9.3 Profit Oil Sharing under typical Vietnamese PSCs Page 9.11 Table 9.4 Export duty rates in Vietnamese PSCs Page 9.13 Table 9.5 Possible bonus payments in Vietnamese PSCs Page 9.13 Table 10.1 The effect of each fiscal component on the minimum developable field size Page 10.6 Table 10.2 Fiscal ranking for oil Page 10.8 Table 10.3 Oil discoveries offshore south Viet Nam basins Page 10.10 Table 10.4 Prospect reserves not drilled due to Government Take Page 10.14 Table 11.1 Cases analysed Page 11.1 Table 11.2 Exploration and field development timing assumptions Page 11.8 Table 11.3 Appraisal, production and development cost phasing-Oil fields Page 11.10 Table 11.3 (continued) Appraisal, production and development cost phasing - Gas fields Page 11.11 Table 11.4 Results of economic analyses for base case - oil onshore north Viet Nam Page 11.12 Table 11.5 Results of economic analyses for base case - gas onshore north Viet Nam Page 11.17 Table 11.6 Results of economic analyses for base case - oil shallow water north Viet Nam Page 11.22 Table 11.7 Results of economic analyses for base case - gas shallow water north Viet Nam Page 11.27 Table 11.8 Results of economic analyses for base case - oil shallow water south Viet Nam Page 11.32 Table 11.9 Results of economic analyses for base case - gas shallow water south Viet Nam Page 11.37 Table 11.10 Results of economic analyses for base case - oil deep water south Viet Nam Page 11.42

Author: Huong Luong Lien December 1998 Chapter 1

Introduction The economics of petroleum exploration and development in Viet Nam Page 1.1

The contents are summarised as follows:-

Chapter 3 presents a description of the country’s climate, land and sea conditions, population as well as a brief summary of the petroleum activities in Viet Nam.

Chapter 4 gives a description of Viet Nam’s economy, economic infrastructure and more importantly the oil and gas infrastructure available in the country.

Chapter 5 discusses issues such as supply, demand, quality and price of oil, gas, petroleum products, coal and electricity.

Chapter 6 includes a statistical analysis of historical exploration performance and gives past drilling success ratios and field size distributions.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 1.2

Chapter 7 shows how a number of oil and gas fields have been or are being developed as well as their general field characteristics.

Chapter 8 gives detailed estimates of representative exploration and development costs for a range of conditions and field sizes.

Chapter 9 describes the fiscal terms as would apply to the Vietnamese petroleum industry and recent developments in business policy.

Chapter 10 presents an analysis of the impact individual fiscal components have on the economics of oil and gas fields in Viet Nam. It also contains a fiscal comparison to other countries in the region and an estimate of the reserves not being developed or drilled because of the government take from a petroleum contract.

Chapter 11 shows the results of economic and sensitivity analyses of exploration and field development in Viet Nam, using the cost estimates in Chapter 8 and the relevant fiscal terms in Chapter 9. The economics are carried out from the investors’ point of view.

Author: Huong Luong Lien December 1998 Chapter 2

Summary and conclusions The economics of petroleum exploration and development in Viet Nam Page 2.1

Geography The climate in Viet Nam is tropical in the south, monsoonal in the north. The hot, rainy season is from mid-May to mid-September. The warm and dry season is from mid- October to mid-March. There are occasional typhoons with extensive flooding. The terrain consists of low flat deltas in the south and north, highlands in the central areas, and hilly mountainous areas in the far north and north-west.

North Viet Nam and the Gulf of Tonkin are subject to frequent cyclonic activity in the period from July to November. This can adversely affect petroleum exploration and development. However, the offshore south Viet Nam basins experience relatively infrequent cyclonic activity.

Onshore, access and environmental obstacles to exploration and field development may occur in remote lowland swamp and highland areas.

Environmental issues Companies investing in the oil and gas industry in Viet Nam should be aware that their activities at all times must take into account environmental protection. The Law on Environmental Protection lays down obligations in strengthening salvage service preparations over coastal areas, waters and rivers, especially areas involved oil and gas developments.

Infrastructure Viet Nam has about 105,000 kilometres of roads, 2,600 kilometres of railway, 11,000 kilometres of inland waterways, seven national seaports, 20 provincial seaports, three international airports and a number of domestic airports. The country’s infrastructure is gradually improving as investment is made through special incentive plans and international aid programs. However, it will be some time before the infrastructure is on a par with even minimal international standards.

Many oil and gas infrastructure projects are either being proposed or are under construction. Viet Nam’s first oil refinery at Dung Quat is now in the first stage of construction. The country also took the first steps to develop its gas industry by bringing associated gas from the Bach Ho oil field ashore to fuel power plants in southern Viet Nam. A gas master plan through to 2010 has been completed and is now under review. Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 2.2

Viet Nam’s poor infrastructure in areas such as transportation, communication networks and public utilities can make doing business difficult. Investors and traders have a tendency to treat the north, south and central parts of the country as separate areas logistically. Within these areas, the established infrastructure is in large cities, export processing zones and industrial zones. Otherwise, large-project investors have built or supplied their own infrastructure such as stand-by generators, water supply systems or roads. Such investment often attracts preferential treatment and tax incentives.

The energy market Viet Nam’s rapid economic development has brought with it an increasing demand for energy. The country has large energy resources including coal, hydro, oil and gas. Viet Nam’s total indigenous energy production has been estimated to be 19.31 million tonnes of oil equivalent (MMtoe) for 1997. However, having no indigenous refinery capacity, the country is currently exporting most of its crude oil production and imports almost all of its refined petroleum products.

Exploration performance Since exploration drilling began in Viet Nam, 26 (that is, 20.8 percent) of the 125 wildcat wells drilled have discovered oil and gas accumulations which are currently under appraisal or currently under development or already developed. Approximately 15.2 percent (that is, 19 wells) have encountered significant oil and 5.6 percent (that is, 7 wells) have encountered significant gas.

The most intensive exploration has taken place offshore Cuu Long and Nam Con Son basins where the oil and gas commercial drilling success ratio is 18.9 percent. Out of 26 discoveries, 17 are in the Cuu Long and Nam Con Son basins. These two basins account for 72 percent of all wildcat wells drilled in Viet Nam to the end of 1997.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 2.3

Table 2.1 - Oil and gas discoveries Oil discoveries Gas discoveries Discovery name Reserves Discovery name Reserves (million barrels) (billion cubic feet) Bach Ho 1 500.00 Bach Ho 1 (associated gas) 682.28 Diamond 1 13.20 Emerald 1 45.65 Emerald 1 (associated gas) 235.98 Pearl 1 31.80 Phuong Dong 1 22.40 Phuong Dong 1 (assoc, gas) 38.85 Rang Dong 1 220.00 Rang Dong 1 (assoc, gas) 236.96 Rong 1 85.00 Rong 1 (associated gas) 42.00 Rong 14 21.64 Ruby 1 150.19 Ruby 1 (associated gas) 176.57 Topaz 1 4.49 Vung Dong 73.30 Vung Dong 1 (assoc, gas) 52.97 Song Thai Binh 1 17.00 Tien Hai C 53.00 Cai Nuoc 1 _ Song Tra Ly 1 360.00 Dam Doi 1 30.00 Kim Long 1 _ Nam Can 1 13.00 Lan Do 1 425.00 Ngoc Hien 1 _ Lan Tay 1 1,625.00 Phu Tan 1 9.00 Phu Tan 1 (associated gas) 72.00 U Minh 1 55.00 Moc Tinh 1 600.00 Dai Hung 1 100.00 Dai Hung 1 (associated gas) 400.00 Hai Thach 1 (condensate) 150.00 Hai Thach 1 556.00 Rong Doi 1 (condensate) 21.00 Rong Doi 1 809.00 Total 1,562.67 Total 6,365.61 Footnote: Two oil accumulations (Cai Nuoc 1 and Ngoc Hien 1) and one gas accumulation (Kim Long 1) were discovered by Fina and Unocal in 1997 and their estimated reserves have not yet been known.

Table 2.1 gives a list of discoveries and their estimated recoverable reserves (if available). On average, approximately 12.5 million barrels of commercial recoverable oil/condensate and 50.9 billion cubic feet of commercial recoverable gas/associated gas have been discovered for every wildcat well drilled in the country.

The largest oil discovery is the Bach Ho field with proven reserves of 500 million barrels of crude oil and 700 billion cubic feet of gas. Other significant oil discoveries are Dai Hung, Rong, Bunga Kekwa, Rang Dong and Ruby fields. In addition, significant quantities of gas have been found at Lan Tay/Lan Do, Hai Thach, Moc Tinh and Rong Doi discoveries.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 2.4

Field developments All existing or currently planned offshore field developments are located in shallow water (less than 200 metres). The Bach Ho and Rong fields have been developed using fixed production platforms and floating storage tankers. The remaining field developments rely on floating production facility as their first stage of development. For instance, the first stage of the Dai Hung field development has used semi-submersible production platform, offshore storage and subsea well completions. Recent field developments like Bunga Kekwa, Rang Dong and Ruby fields use wellhead platforms and floating production, storage and offloading (FPSO) tankers for their first phase development. However, the conceptual plans for the later phases of these fields involve fixed platforms and floating storage offloading (FSO) vessels.

Exploration costs The large variation in geological and physical conditions across Viet Nam lead to considerable differences in cost of exploration and field development. Conventional 2D seismic surveys are likely to cost from US$1,000 per kilometre offshore to over US$10,000 per kilometre onshore. An exploration well could cost from US$3 million onshore to US$10 million in shallow water and over US$14 million in deep water.

Field development costs Within any one area, the major single determinant of the costs of field development is individual well productivity. The higher the peak production from the average well in the area, the fewer wells are needed to achieve a given peak field rate. This considerably reduces drilling, subsea and surface capital costs as well as operating costs once the field has been developed.

Onshore oil field development costs can vary from US$0.86 to over US$12 per barrel of reserves depending on field size. Onshore gas field development costs are estimated to be in the range of US$0.24 to US$1.19 per thousand cubic feet of reserves. In contrast, offshore oil field development costs can vary from US$2.14 to US$12 per barrel of reserves. And offshore gas field development costs can vary from US$0.31 to US$0.86 per thousand cubic feet of reserves depending on field size.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 2.5

Fiscal regime The fiscal regime in Viet Nam is based on production sharing contracts (PSCs). The main components of the Vietnamese PSCs referenced in this study are summarised as follows:

• A royalty rate of between 6% to 25% of gross oil production and 0% to 10% of gross gas production • A cost recovery ceiling typically 35% of oil production and 50% of gas production • An income tax rate of 50% of taxable income • A sharing of profit oil and/or profit gas (excess revenue after royalty, cost recovery and income tax) with the Contractors’ share varying from 90% to 40% depending on the level of production • A transfer tax rate of 10% • An export duty rate of 4% of crude oil exported • Bonuses and fees - negotiable • State participation (typically 15%)

Fiscal analyses show that the Vietnamese fiscal regime would prevent the development of fields which are economic but have a low level of profitability (that is, marginal fields). Such fields are profitable before Government Take but become unprofitable after Government Take. It is estimated that a total of over 150 million barrels of oil reserves may not be developed by contractors because of the effect of the fiscal regime. The cost recovery ceiling and income tax components have a strong influence on marginal field development.

In comparison to other countries in the region, the petroleum activity takes place under the Vietnamese fiscal regime would give companies higher returns than under Indonesian or Malaysian standard fiscal terms, but less than under Philippines or Thailand standard terms.

Economics The economics of hypothetical stand-alone field developments from the point of discovery to the end of field life have been analysed for 7 cases. The analyses incorporate an oil price of US$18.00 per barrel and a gas price of US$2.50 per thousand cubic feet. Table 2.2 contains a summary of the results.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 2.6

Table 2.2 - Summary of results Minimum Upside NPV Minimum Minimum economically of prospect size prospect size developable large field for for Cases field size development 10%POS* 20% POS*

Oil million barrels US$ per barrel million barrels million barrels Onshore north Viet Nam 5 2.22 77 41 Shallow water north VN 29 1.83 75 48 Shallow water south VN 33 1.84 103 58 Deep water south VN 22 1.83 158 71

Gas billion cubic US$ per Mcf billion cubic feet billion cubic feet

feet Onshore north Viet Nam 30 0.33 736 342 Shallow water north VN 172 0.16 879 450 Shallow water south VN 162 0.21 997 475

Footnote: *POS = probability of success, VN = Viet Nam, Mcf = thousand cubic feet

The results shown in Table 2.2 are interpreted as follows:-

The minimum developable field size gives an estimate of the minimum reserves needed before it is economic to develop a new discovery from scratch on a stand alone basis.

The net present value (NPV) per barrel or per thousand cubic feet results give an estimate of the typical profitability of field development for discovery size above the minimum. While this varies depending on many factors, a maximum figure is presented. The NPV per barrel or per thousand cubic feet is the NPV of the after tax net cash flow of a development divided by the reserves.

The other columns in Table 2.2 show the minimum size required in an exploration prospect before an exploration programme (that is, a seismic survey and 2 or 3 exploration wells) is justified. It indicates the prospect size which will generate a zero expected value. The minimum size depends on the estimated probability of success in drilling the prospect. Therefore, the estimates of the minimum for probabilities of success of 10% and 20% are shown in the table. The minima for other probabilities of success are given in Chapter 11.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 2.7

Once an oil accumulation has been discovered, the minimum reserves which are required for commercial development are approximately 5 million barrels onshore north Viet Nam, approximately 29 million barrels offshore shallow water north Viet Nam and approximately 33 million barrels offshore shallow water south Viet Nam. The differences in minimum economic field sizes required for the three different areas reflect the variation in well costs, peak well rates and other development assumptions.

The minimum developable field size required for oil discoveries offshore south Viet Nam in deep water is approximately 22 million barrels and is less than that in shallow water. This is because oil discoveries in deep water (greater than 200 metres) have better fiscal terms (lower royalty rates, higher cost recovery ceiling and lower income tax rate) than those in shallow water.

Author: Huong Luong Lien December 1998 Chapter 3

Geography The economics of petroleum exploration and development in Viet Nam Page 3.1

The general location of Viet Nam is shown in Figure 3.1. As seen from the map, Viet Nam is situated on the eastern seaboard of Southeast Asia. The country is bordered by China to the north, Laos and Cambodia to the west. It has a total land area of 329,566 square kilometres. Viet Nam is a long narrow S-shaped country with a length of 1,600 kilometres north-south stretching from 6N in the south to 23.5N in the north. Two broad deltas of the Red River in the north and the Mekong in the south are linked by a narrow central section. At its widest point in the north, the country is 600 kilometres across. However, at its narrowest point in the centre, the country is only 35 kilometres wide. The South China Sea flanks the country’s entire eastern and southern sides with a long coastline of around 3,500 kilometres. The western border areas of the country are dominated by forested and remote highlands cut by numerous rivers which empty into the South China Sea. Three quarters of the country consists of hills and mountains reaching up to over 3,000 metres above sea level. Because of the country covers 12 degrees of latitude and has high mountainous regions, the climate is highly variable. Economically, the last decade of the 20th century has witnessed Viet Nam’s new period of economic reform as the government has adopted a more open door policy (Petroconsultants Australasia, 1995 and World Conservation Monitoring Centre web site, 1994).

3.1 Petroleum activities

Figure 3.2 is a petroleum activity map for Viet Nam. Since 1988, the areas which have been open for foreign oil companies include offshore South China Sea and onshore Red River Delta. The most recent operating blocks are in the Cuu Long and Nam Con Son basins located off Viet Nam’s south-eastern coast. To date, more than 30 petroleum contracts have been signed with foreign oil companies for exploration and development. Out of these, about 18 contracts are still in effect. The main foreign operators are AEDC- Teikoku, Anzoil, BP-Statoil, Canadian Petroleum, Conoco, Enterprise Oil, Fina, Japan Vietnam Petroleum Company, Mobil, NESTRO, Occidental, OMV (Vietnam) Exploration, Oil and Natural Gas Commission of India (“ONGC”), Opeco International, Pedco, Petronas Carigali, P.T. Astra Petronusa, Total Oil and Gas International, and Unocal. The Vietnamese government hopes to spur interest in the remaining, unawarded offshore and onshore blocks, many of which are located onshore, in the Gulf of Tonkin, and off the south-western coast in Malay Basin.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.2

Figure 3.1 - Viet Nam location map Source: Petroconsultants Australasia, Vietnam, 19

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.3

Figure 3.2 - Viet Nam petroleum activity map

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Source: PetroVietnam Review, page 44, Vol.l, 1997.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.4

Most of Viet Nam’s offshore international boundaries have been under dispute from neighbouring countries. Recently, Viet Nam has been able to settle its dispute with Thailand and Malaysia. Nonetheless, it continues to have territorial disputes with China including overlapping claims to the Paracel and Spratly Islands, and continental shelf areas in the South China Sea and in the Gulf of Tonkin. Six countries including China, Viet Nam, Taiwan, Malaysia, Brunei and the Philippines together claim Spratly Islands. Both oil and gas has been found in the surrounding areas of Spratly Islands. Towards the south-west of Spratly, there are a number of significant gas discoveries located in the Natuna and Nam Con Son basins. In the east, a productive lower Miocene pinnacle reef trend has been found offshore north-west Palawan island in the Philippines (Jimmie Aung Khin, 1996).

3.2 Climate

In general, the climate in Viet Nam is warm moist tropical in the south and moist subtropical in the north. Winter conditions can affect the north of the country when polar air blows south over Asia. The mean temperatures in Ha Noi vary from 16.6°C in January to 28.9°C in July. The mean annual rainfall is 1,830 millimetres (World Conservation Monitoring Centre web site, 1994).

The regional weather pattern is governed by the presence of two prevailing monsoon wind systems which pass north-south across the country every six months. The north monsoon lasts from November to March. The so called “bad weather window” is characterised by medium to strong north-east to south-west winds blowing from China, the north South China Sea and the Pacific Ocean. This period corresponds to the northern hemisphere winter. The south monsoon prevails form May to September. The generally mild weather is characterised by moderate south-west to north-east winds blowing from the South China Sea. This period corresponds to the northern hemisphere summer. In October and April, the change over periods between monsoon seasons, the winds are light and variable. Figures 3.3 and 3.4 show the dominant prevailing wind patterns affecting Viet Nam and the region for northern and southern monsoon seasons (Petroconsultants Australasia, 1995).

Author: Huong Luong Lien December 1998 Figure 3.3 - Prevailing winds in northern monsoon, October to Apri

Author: Huong Luong Lien December 1998 H 1 4 0 o c o >

Figure 3.4 - Prevailing winds in southern monsoon, May to September

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.7

Much of Viet Nam, especially south Viet Nam, is characterised by distinct periods of wet and dry under alternate monsoon seasons. In general, most areas of Viet Nam have an annual rainfall of 1 to 2 metres per year of which between 50 and 70 percent is delivered by the southern monsoon. Most rain falls in the summer or middle months of the year and is delivered from frequent thunderstorm activity. Offshore Cuu Long Basin, there are occasional heavy rain with lighting during the south monsoon. Rainfall brought by cyclones is also significant in areas north of Da Nang, particularly in August and September (Petroconsultants Australasia, 1995).

The East Viet Nam Shelf and the Hanoi Trough are considered as areas of high cyclone risk. The most frequent period of cyclones in north Viet Nam is August to December, with a peak in August and September. On the other hand, the area off Viet Nam’s southern coast experiences relatively infrequent cyclone activity. The southern cyclone limit can be regarded as a line drawn from Da Nang in central Viet Nam to the northern tip of Sabah in East Malaysia. Areas to the south of this line can still be affected by cyclones but at much lower risk (Petroconsultants Australasia, 1995).

Temperatures in Viet Nam are governed by two main criteria. These are the relative position north of the equator and the elevation. Temperatures in southern lowland Viet Nam are uniformly high throughout the year with annual mean of approximately 27 degrees Celsius. In the northern lowland, annual mean temperatures are around 23 degrees Celsius. However, in the north, there is a greater temperature range between seasons because of the higher latitudes. In the mountain regions, temperatures can fall to zero or below in winter. A comparison of temperatures in different parts of Viet Nam is shown in Table 3.1. The relative humidity is consistently high averaging between 74 and 90 percent (Petroconsultants Australasia, 1995).

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.8

Table 3.1 - Temperature comparisons in degrees Celsius Largest Lowest Highest Largest Absolute seasonal mean daily mean daily daily mean - Location range Min. Max. range Max. Min. Ha Noi (northern 13.5 13.4 33.2 8.4 42.8 5.6 lowlands) (January) (June) (May) (May) (January) Ho Chi Minh (southern 3.1 21.0 34.8 11.1 40.0 13.8 lowlands) (January) (April) (February) (April) (January) Da Nang (coast central 7.8 18.9 34.4 9.4 40.0 11.0 lowlands) (January) (June) (June) (June) (January) Lao Cai (northern 12.5 13.2 32.3 8.8 42.8 2.2 highlands) (January) (June) (May) (May) (January)

Source: Petroconsultants Australasia, South East Asia Petroleum Exploration Economics-Vietnam, 1995.

3.3 Topography

Approximately 75 percent of Viet Nam’s total land area is remote highlands covered in forests and dissected by rivers. The other 25 percent is lowland. Most of the population live in the lowland areas. Viet Nam’s topography can be broadly subdivided into four major regions

• the mountainous area which dominates the north, but which also extends the length of the country to north of Ho Chi Minh City,

• the Red River delta in the north,

• the Mekong River watershed which includes the river delta in the far south,

• the thin coastal strip which connects the northern lowlands of the Red River delta and southern lowlands of the Mekong delta (Petroconsultants Australasia, 1995).

The Highlands Northern Viet Nam is dominated by highlands where approximately 10 percent of the area is above 1,800 metres. The highest peaks in Viet Nam are located in Hoang Lien Son mountains, north-west of the country, with a maximum altitude of 3,143 metres. Much of the highlands, particularly in the northern border areas, is characterised by karst

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.9 plateaux. The highland region also extends the length of the country as far as the Mekong River flood plain. The thin mountainous band in central Viet Nam straddles the border with Laos and creates a narrow coastal plain on its eastern side. The mountainous area is generally remote with access restricted to the valleys.

Red River delta The Red River has its headwaters in southern China and cuts a steep sided valley through mountainous regions of China and Viet Nam. The river course follows a major fault line, the Red River Fault, which extends into the South China Sea. The river runs 360 kilometres southeastemly across north Viet Nam and enters the Gulf of Tokin 100 kilometres downstream from Ha Noi. Accordingly, the Red River plain descends in a south-east direction towards the Gulf of Tonkin. It extends about 240 kilometres inland. At its widest along the coast, the Red River mouth measures about 200 kilometres across. As the Red River approaches the plain, its gradient drops rapidly and large looping meanders form as a result.

Mekong Watershed Southern Viet Nam is dominated by the enormous Mekong River. The waters of the Mekong River rise from the mountains in China/Laos border and empty into the South China Sea after crossing some 1,700 kilometres of continental Asia. The Mekong River flood plain accounts for most of the land area of Cambodia and southern Viet Nam. The Mekong delta is approximately 350 kilometres wide with the actual river mouths entering the sea over a distance of 140 kilometres. Before the Mekong river enters Viet Nam, it splits into two main courses characterised by looping meanders, cut-off meanders and inter channel islands.

Coastal Plain A thin coastal plain runs the length of the country and joins the Red River plain of the north with the Mekong River flood plain in the south. The plain varies from less than 1 kilometre wide to over 60 kilometres. This narrow eastern coastal strip is crossed by short rivers which enter an arcuate coastline produced by the relative proximity of the encroaching highlands.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.10

3.4 Vegetation

The original primary vegetation over most of Viet Nam was tropical forest. However, swamp forests formerly located in the Red River and Mekong deltas have been cleared for agriculture. Nowadays, it is estimated that 75 percent of the Viet Nam land area still remains under primary or secondary forest cover. Most of this is confined to the mountainous areas which cover the majority of the country. There are five broad forest types: mixed deciduous rain forest, mangrove, pine, mossy and bamboo {Petroconsultants Australasia, 1995).

The coastal areas still support mangroves and parts of Mekong delta supports Melaleuca forests. Low lying dry land forests were semi-evergreen but are largely destroyed. In contrast, hill forests remain of both evergreen and semi-evergreen types. In some areas, karst limestone produces a distinct forest formation. The highest peaks of Hoang Lien Son mountains in the north-west of the country emerge above the cloud layer, receive very high levels of insolation and exhibit a specialised montane heath vegetation. Some parts of the central highlands support extensive areas of dry monsoon forest (World Conservation Monitoring Centre web site, 1994).

3.5 Bathymetry

Viet Nam’s long coastline is characterised by a wide range of geomorphological, climatic and hydrological conditions. A broad and shallow continental shelf follows the shape of the land, wide in the north (Gulf of Tonkin) and south (Mekong delta) and narrow in the middle. Coral reefs exist on rocky islands of Ha Long Bay, Paracel and Spratly Islands (both rocky promontories of the central coastline) and around Con Dao and Phu Quoc Islands. There are about 295 species of corals found in Viet Nam waters (World Conservation Monitoring Centre web site, 1994). Water depths in the areas of undisputed Vietnamese territory are generally below 200 metres.

The entire Gulf of Tonkin has water depths less than 100 metres, and approximately 75 percent is less than 60 metres deep. The vast majority off the Mekong delta area which covers Cuu Long and South Con Son Basins is below 100 metres. Depths increase

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.11

significantly only in the extreme eastern portion towards the open waters of the South China Sea. The maximum depths encountered in undisputed Vietnamese waters are approximately 500 metres. Ultimate depths exceed 4,000 metres in the South China Sea (Petroconsultants Australasia, 1995).

In the narrow shelf of central Viet Nam, the 200 metre isobath is between 60 and 100 kilometres offshore. Further to the East Viet Nam Shelf, the deepest waters encountered in undisputed Vietnamese territory off Nha Trang exceed 2,000 metres. Island groups off the Viet Nam coast, such as Spratly and Paracel Islands, have only small areas of water with depths less than 200 metres.

3.6 Sea conditions

In Viet Nam, the seabed is muddy in the two delta areas and sandy along the exposed central coastline. Cold sea currents sweep the coast southwards in winter and warm currents sweep north in summer (World Conservation Monitoring Centre web site, 1994). Wave height and swell generally reflect the prevailing monsoon. Therefore, the majority of wave, swell and current directions are either north-east to south-west during the north monsoon from November to March or south-west to north-east during the south monsoon from May to September.

Sea states in Viet Nam can vary considerably depending on the season and the location. In general, waters above latitude 16 degrees north are readily under the influence of cyclones whereas areas south of this parallel are much less affected. In southern Viet Nam, direct typhoon attack is very rear but sometimes the area is strongly affected by typhoons directing to central or northern Viet Nam. In the Vietnamese section of South China Sea, the most frequent cyclone period is August to December.

In Viet Nam, overall wave heights are less than 2.5 metres for 90 percent of the time and swells are slight or nil for 70 percent of the time on average. Thus prevailing sea states in Viet Nam can generally be described as benign. Off the Mekong delta, tide and swell is generally moderate to medium. The Gulf of Tonkin has the slightest sea states on average over the year. In general, winds of the northern monsoon are the strongest, hence waves

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 3.12

in the period November to April are at their highest in most areas of the Vietnamese South China Sea. During the south monsoon, there can be considerable periods of calm (no waves). In Gulf of Tonkin, May and June have zero waves for 20 to 40 percent of the time on average {Petroconsultants Australasia, 1995).

3.7 Population

Viet Nam’s population is currently estimated at 78 million and is expected to reach 82 million by the year 2000. The average population density is 227 people per square kilometre. The country’s most densely populated regions are in the Mekong River floodplain and the Red River plain. Almost 80% of the population is located in rural areas and the remaining 20% in urban areas across Viet Nam. The two largest cities are Ho Chi Minh City and Ha Noi with a population of 5 millions and 3 millions respectively. The population of Hai Phong and Da Nang City are estimated to be approximately 2 millions and 1 million. Viet Nam’s population is continuing to grow steadily at the rate of around 2.3% per year. More than half of the population is under the age of 25. Viet Nam has literacy rates of 93% for male and 82.8% for female {The Vietnam Business Journal, 1998).

Author: Huong Luong Lien December 1998 Chapter 4

Infrastructure The economics of petroleum exploration and development in Viet Nam Page 4.1

This chapter discusses those aspects of the economy and infrastructure in Viet Nam which are relevant to the petroleum industry. The economy and the level of development of the infrastructure affects the planning, time and costs of construction and operation of a new petroleum project.

4.1 The economy

Viet Nam currently has a relatively stable political environment. The country has been controlled centrally by the Vietnamese Communist Party since 1975. Since 1986, a series of structural reforms have been introduced and a legal framework gradually developed to allow a liberalisation of the economy. As a result, Viet Nam’s economy has grown rapidly. The gross domestic product (GDP) growth rate has averaged about 8.03% per annum from 1990 to 1997. Figure 4.1 shows how the growth in GDP has behaved since 1990. However the Asian economic crisis in 1998 had a severe effect and Viet Nam’s GDP is expected to grow at a much lower rates for the next few years.

One of the significant features of the country’s economic renovation has been the elimination of hyper-inflation experienced during 1980s and early 1990s (see Figure 4.2 below). The government controlled inflation rates by adopting a tight monetary policy.

Figure 4.1 - Viet Nam’s GW* growth rate Figure 42 - Viet Nam’s Inflation

1990 1991 1992 1993 1994 1995 19% 1997 1990 1991 1992 1993 1994 1995 19% 1997

Sources: The Country Economic Briefs on Vietnam 1996 and, Financial Statistics and Current Information section of The Vietnam Business Journal August 1998.

The Vietnamese government has been keen to attract foreign investment in many sectors of the economy. However, an inadequate legal framework was a stumbling block and in

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.2

1997 the government passed a revised foreign investment law in order to speed the approval process and more effectively target investment priorities.

4.2 The oil and gas industry

Viet Nam has been particularly anxious to expand its oil and gas sector and in the past 10 years, this has become the most important sector of the economy. Figure 4.3 shows Viet Nam’s crude oil production increasing from 1986 to 1997.

Figure 43 - Viet Nam’s crude oil production

10.10

Time

Source: PetroVietnam’s 97 brochure.

Crude oil and petroleum products have been the country’s leading export and leading import respectively. Viet Nam exports 9.7 million tonnes of crude oil and imports about 6 million tonnes of petroleum products in 1997 (The Vietnam Business Journal, 1998). Table 4.1 presents the country’s crude oil export turnover and refined petroleum products imports from 1990 to 1997.

Table 4.1 - Crude oil exports and Petroleum product imports Unit: US$ million Year 1990 1991 1992 1993 1994 1995 1996 1997 Crude oil exports 470.8 581.4 805.7 843.9 866.2 1,003.1 1,360.0 1,400.0 Petroleum product imports 236.0 485.0 615.0 684.0 630.0 830.0 980.0 1,100.0

Source: Lenard Tan, Assessing its oil and gas potential - Viet Nam, World Energy Yearbook, 1997 and Department of Foreign Affairs and Trade, The Country Economic Briefs - Vietnam, Commonwealth of Australia, 1996.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.3

4.3 The labour market

Viet Nam has a young work force of approximately 40 million (estimated in 1995) which is growing at the rate of 3.5% a year. A high literacy rate (87.9%) and the low wages of Vietnamese workers have been factors assisting the growth of investment and the economy. However, there is a shortage of skilled workers and qualified management personnel. It is estimated that there are approximately 10,000 well-trained professionals who understand and can meet the demands of international business practices. They are in very high demand as the right local personnel are considered to be more effective than a foreigner in the same job {Joshua Jake Levine, 1998).

4.4 Roads

The economic infrastructure in Viet Nam is shown in Figure 4.4 and 4.5. There are 105,000 kilometres of roads in the country. However, the road system has not been well developed. About 15% of the roads are paved, but most of these are narrow and of poor quality. Resurfacing, pothole repair and ditch cleaning are currently insufficient to keep up with increasing demand, resulting in rapid deterioration. The roads in the north are generally worse than those in the south. Roads in remote areas are in especially poor condition. Nevertheless, a number of the more important highways, including Highway 1 which links Ha Noi and Ho Chi Minh City, and Highway 5 which links Ha Noi and Hai Phong are being repaired and expanded with international financial assistance (Vietnamembassy-usa web site). In addition, the construction of a highway between Ho Chi Minh City and Vung Tau, the country’s oil and gas industry capital was completed in 1998.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.4

4.5 Railways

The railway network in Viet Nam consists of 2,600 kilometres of single-track line covering seven routes and 260 stations. The bridge network was severely damaged in the war and the track beds are in poor state. The standardisation of track gauge and other investments have slowly begun to improve the railway system, although much more will be needed in the future (Vietnamembassy-usa web site).

The longest and most important route is the Ha Noi - Ho Chi Minh City line of 1,730 kilometres. It takes about 34 hours with express trains to travel between these two cities. The railway system does not cover the whole country. Two new routes from Ha Noi to Quang Ninh and from Ho Chi Minh City to Vung Tau are being planned. Railway links between Viet Nam and China have also been restored. However, railways have not been extended to remote areas such as Cuu Long delta, Tay Nguyen and north Lai Chau.

4.6 Inland waterways

Viet Nam has about 11,000 kilometres of navigable inland waterways and many inland river ports. There are two major inland waterway systems which offer a cheap and flexible mode of transport. Covering a large area in the north is the Red River inland water system which stretches approximately 2,500 kilometres. Along this system there are five main ports, of which Ha Noi is the largest. Along the Mekong River and its tributaries in the south is the country’s largest inland waterway system of 4,500 kilometres. It boasts about 30 ports including Ho Chi Minh City. However, seasonal changes of the south can make navigation difficult. During the dry season channels can shrink to as little as one meter in depth. A further problem is that channels are not dredged regularly (Vietnamembassy-usa web site).

Author: Huong Luong Lien December 1998 inomics of petroleum exploration and development in Viet Nam Page 4.5 Figure 4.4 - Economic Infrastructure in North Viet Nam

Author: Huong Luong Lien December 1998 etroleum exploration and development in Viet Nam Page 4.6 Figure 4.5 - Economic Infrastructure in South Viet Nam

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.7

4.7 Ports and shipping

Viet Nam has a long coastline of 3,444 kilometres which makes marine transportation quite easy. However, ports are not well developed and facilities are generally poor. If petroleum activities increase strongly, the existing infrastructure will not be able to meet the industry’s demand.

The country has seven major seaports. These are shown in Figure 4.6. Hai Phong, just a few hours drive from Ha Noi, serves much of the north but has proved problematic as a port. The government, therefore, has begun development of a deep-water port, about 80 kilometres away at Cai Lan Bay (Quang Ninh) which can accommodate 50,000- tonne ships. Da Nang, at the mouth of the Song Han River, serves the central highlands and much of the transit traffic to and from Laos. Quy Nhon and Nha Trang are major seaports in the south-central Viet Nam. Ho Chi Minh City serves most of the south and now boasts modem container loading facilities. Vung Tau is the most important port for the oil and gas industry in the south. A deep seaport is now under construction in Ba Ria - Vung Tau.

In order to improve the shortcomings of the ports, Viet Nam has a master plan for developing its seaport system by the year 2010. This plan however was developed before the Asian financial crisis. Therefore, we could expect its targets to be down graded in current circumstances.

The plan aimed to make the Viet Nam seaport system a catalyst in the country’s drive for accelerated industrialisation by expediting seaport investment, operations and supportive infrastructure construction. The country’s sea ports were planned to have a total annual handling capacity of 106 million tonnes of cargo by the year 2000 and 268 million tonnes by the year 2010. The plan’s regional breakdown detail efforts to utilise Viet Nam’s resources in a bid to facilitate cargo generation and distribution. Efforts will be made to :

• rationalise, redevelop and modernise port infrastructure • build a number of deep water ports for vessels in excess of 30,000 deadweight tonnes (DWTs)

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.8

• concentrate on dedicated container zones and international trans-shipment facilities • construct a network of smaller satellite ports to feeder cargo local economies (Russell Barling, 1997).

Under this plan, Viet Nam would have eight regional port groups. Each port group was planned to be a small and closely linked network. There would be a total of 114 seaports along the coast from the northern province of Mong Cai to the southern province of Kien Giang:-

1. The North Viet Nam port group including Hai Phong, Cua Ong, Cai Lan and 24 other seaports from Quang Ninh to Ninh Binh would serve the Ha Noi - Hai Phong - Quang Ninh economic triangle. 2. The North-central Viet Nam port group including Cua Lo port would serve the economic development of Thanh Hoa, Nghe An and Ha Tinh provinces and catering goods in transit from and to Thailand and Laos via highways No. 7 and 8. 3. The Mid-central Viet Nam port group would serve the coastal provinces from Quang Binh to Quang Ngai, some central highland provinces (Kon Turn, Gia Lai) as well as provinces in south Laos and north-east Thailand via highways No.9 and 24. Dung Quat deep water seaport would serve the Dung Quat refinery and petrochemical plants. 4. The South-central Viet Nam port group with two major ports at Qui Nhon and Nha Trang would serve the economic development of Binh Dinh, Binh Thuan, Dac Lac, Lam Dong provinces, north-east Cambodia and north-east Thailand via highways No. 19 and 24. 5. The Sai Gon, Vung Tau and Thi Vai ports would serve the key economic region of Ho Chi Minh City - Dong Nai - Vung Tau. 6. The Cuu Long Delta port group with the major port of Can Tho would serve southern provinces to export rice and other agricultural products. 7. The Phu Quoc and the west-southern islands port group would serve the oil and tourism industry. 8. The Con Dao port group would include a new port at Dam Mon bay.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.9

Figure 4.6 - Main cities and ports

Source: http .//violet, be rke ley. edu/~l 1 Oinfo/VIETNAM/mapvn. html

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.10

4.8 Airports

Viet Nam has three international airports

• Noi Bai airport in the north, • Da Nang airport in the central and • Tan Son Nhat airport in the south.

Currently, the facilities in these airports are inadequate to handle the increase in the volume of traffic associated with Viet Nam’s growing economy. The government is therefore planning major upgrades and expansions. In addition, three new international airports have been planned for the northern, central and southern airport groups:-

• Cat Bi airport in Hai Phong • Chu Lai airport in the Dung Quat oil refinery area (proposed as a regional cargo handling facility) • Long Thanh airport in Dong Nai province.

Transport by air between major cities in the north, central and south of Viet Nam is good. However, other areas are not easy to access. There are a number of small domestic airfields around the country such as Vinh, Hai Phong, Lai Chau, Hue and Da Lat (see Figure 4.4 and 4.5). However, flights from/to these small airfields are not frequent and are by small aircraft only.

4.9 Electricity distribution

As regards electricity supply and distribution, the 500 kilovolt (KV) north-south power line is the basis for the integrated national distribution network of around 8,000 kilometres of transmission lines. The system from north to south as a whole may help Viet Nam to meet its increasing energy demand for industrial developments. However, the transmission and distribution network is antiquated and continues to cause shortages and blackouts in the south. There are also electricity shortages in northern regions when the lack of rain reduces water levels in the hydroelectric plants’ reservoirs. As a result, Viet Nam has signed up loans to finance the rejuvenation of transmission and

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.11

distribution systems in Ho Chi Minh City, Hai Phong and Ha Noi. In addition, about 2,650 kilometres of high-voltage (500 kilovolts) and low-voltage (220 kilovolts) transmission lines and 530 transformer stations will be installed in the central region by the year 2000.

4.10 Telecommunications

The country’s telecommunication systems are under development. Telephone lines go to almost every main part of the country. Fax and telex services are available. Direct dialling is now easy, although the costs remain quite high. The Internet has made communications much easier communication both within Viet Nam and to other countries.

Viet Nam has direct communication channels with more than 40 countries and indirect connection with almost all other countries in the world through a number of earth satellite stations. Currently, the sea optical cable line linking Viet Nam - Thailand - Hong Kong and the inland optical cable line connecting China, Viet Nam, Laos, Thailand, Malaysia and Singapore are under construction.

Nevertheless, the growth in telecommunication is concentrated only in industrial areas such as the capital, big cities and a number of provinces in Red River and Cuu Long delta. A shortage of phone lines has led to a surge in the use of mobile phones and pagers. Viet Nam has set a target of 6 telephone lines per 100 people and telephone access to all villages in rural and remote areas by the year 2000.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.12

4.11 Financial services

The increasing inflow of foreign investments since the late 1980s has seen the demand for international banking services rise accordingly. At present, there are well over 60 foreign banks with offices in Viet Nam and over 50 domestic joint stock banks (.Jonathan Golin, 1998). Many foreign banks have branch operations in Ha Noi and Ho Chi Minh City. Services available are trade financing, retail banking as well as commercial lending. However, the financial system as a whole has not yet been fully developed. Obtaining in-country bank financing is not easy. Foreign investors tend to obtain financing though one of the foreign banks or use offshore financing to fund the project.

Under the government policy of foreign exchange controls, all foreign currency income generated in Viet Nam from exports, services and any other sources must be deposited at licensed banks in the country. The recently established inter-bank market has enabled foreign currency transactions to be made more easily. However, access to foreign currencies remains difficult for foreign businesses operating in the country ('Vietnamembassy-usa web site).

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.13

4.12 Pipelines

Figure 4.7 shows the gas pipeline system in southern Viet Nam. The country’s first submarine gas pipeline was commissioned in 1995. This gas pipeline runs 125 kilometres from the offshore Bach Ho field to Dinh Co gas processing plant and Ba Ria 185 megawatt power station. Its extension runs to the Phu My II power plant and other end-users along the Phu My - Ho Chi Minh City industrial corridor. The offshore section’s diameter is 16 inches, while the onshore section’s diameter is 17 inches. With the installation of a huge air compressor completed in July 1997, the Bach Ho-Ba Ria- Phu My pipeline has a capacity of 35 to 53 billion cubic feet per year. The central compression platform, located alongside the existing Bach Ho central processing platform, will eventually service Bach Ho, Rong, Ruby, Rang Dong fields and other potential fields nearby.

A plan to construct the pipeline bringing gas ashore from the Lan Tay and Lan Do gas fields in the Nam Con Son Basin (a length of approximately 400 kilometres) is waiting for Ministry of Planning and Investment’s approval. The Nam Con Son pipeline has 2 sections - a 365 kilometre offshore line and a 35 kilometre onshore line. The 24-inch pipeline will be laid in a maximum water depth of about 125 metres. It will have a capacity to transmit 177 to 212 billion cubic feet a year. The pipeline will also be able to accommodate gas being supplied from other discoveries in the basin, via branch lines. In addition, an onshore receiving and processing terminal, and pipeline connections to onshore purchasers are planned. The aim is to fuel power generation turbines at the Phu My Power Complex. The system will also provide power and feedstock to future urea fertiliser and petrochemical plants in the area (Vietnam oil & gas report, May 1997). Other extensions to Ho Chi Minh City and Thu Due may be possible.

Also, a proposal has been made for a 700-800 kilometre export pipeline from Vietnam to Thailand. However, this supply link will only be a possibility if Vietnam discovers large gas reserves in the Nam Con Son Basin in excess of its own domestic requirements.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.1 Source: Figure

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pipelines

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.15

4.13 Shipping and shipbuilding

There are three main import and supply points of petroleum products in the north, centre and south of Viet Nam. Bai Chay, Da Nang and Nha Be-Cat Lai have suitable jetty which can receive tankers of more than 20,000 deadweight tonnes. The Vietnam Petroleum Water Transport Co. specialises in transporting petroleum products in Vietnamese coastal water and main rivers. It has vessels from 1,000 to 10,000 deadweight tons and barges of 100 to 400 deadweight tons.

In the north, Hai Phong is the centre of large scale port facility developments. In the south, Vung Tau is the oil and gas port city handling oil and gas from the southern offshore fields. It is also the area of very large scale investments in the oil, gas, fertiliser and petrochemical sectors. The entire province of Ba Ria - Vung Tau is the back up for offshore supplies, shipping, rig repairs and shipbuilding.

The construction of a large shipbuilding and repair yard north of Nha Trang, the capital of the coastal province Khanh Hoa (northeast of Ho Chi Minh City), is under way. The Hyundai Group of South Korea also has plans to invest in new engineering and construction plants close to the shipyard site. The government is building a new oil port, and already uses facilities along the coast to transfer bulk cargoes of both refined oil products coming into Vietnam and crude for export (Vietnam oil & gas report, 1997).

4.14 LPG facilities

Most of processing facilities for the oil and gas industry are in southern Viet Nam. A gas processing plant is located at Dinh Co, approximately 10 kilometres north of the Bach Ho pipeline landfall at Long Hai-Vung Tau. The plant uses a slug catcher to remove condensed liquids. It then extracts propane, butane and stable condensate from raw gas by using a conventional auto-refrigeration process. The liquefied petroleum gas (LPG) produced from the plant is sold to domestic and export markets. While, the lean gas is piped to local power stations and industrial sites. The Dinh Co gas processing plant will probably be expanded to accommodate additional supplies of gas from offshore fields. Liquids produced from the plant are transported to the storage and export facilities at Phuoc Hoa on Thi Vai river site, 28 kilometres away from Dinh Co.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.16

The completion of Phase II - Bach Ho Gas Utilisation Project will allow Viet Nam to be in a position to export LPG.

So far, LPG imported for the southern market has been delivered to three existing storage terminals in Ho Chi Minh City. At Tan Thuan, Elf Gas Saigon has a LPG depot with storage capacity of 1,050 tonnes and a bottling line with filling capacity of 25,000 tonnes a year. At Cat Lai, there is a LPG depot and bottling plant owned by SaigonPetro with storage capacity of 1,280 tonnes and filling capacity of 45,000 tonnes a year. In 1993, an old LPG tanker terminal built before 1975 at Nha Be was restored and upgraded by Petrolimex-Wesfarmers joint venture to have a filling capacity of 6,000 tonnes a year.

In the southern province of Can Tho, the $ 10-million plant owned by a Statoil-led joint venture will start producing LPG for industrial projects based in Mekong Delta in 1999. A Total Gas Can Tho joint venture has also begun the construction of a new LPG terminal. Total’s terminal with a capacity of 20,000 tonnes a year is built on 1.7 hectares in Tra Ngoc Ward of Can Tho city and is scheduled to start production by the year 2000.

In Dong Nai province near Ho Chi Minh City, there are two LPG terminals operated by the Petroleum Authority of Thailand (PTT) and Siam Gas. These two terminals which are located at Dong Nai and Long Binh port have a storage capacity of 1,200 and 350 tonnes and a filling capacity of 60,000 tonnes and 4,000 tonnes a year respectively.

Hai Phong, the gateway to Ha Noi and other industrial zones in the north, has also attracted foreign investment in the development of LPG production, bottling and distribution, as well as port facilities for imported gas. The Chinese Petroleum Corporation-led joint venture has operated a LPG plant and distribution centre located in Hai Phong since 1995. A Total Gas Hai Phong joint venture has also constructed a receiving terminal of 1,000 tonnes storage capacity with LPG filling and bottling facilities at a cost of approximately US$17 million (Vietnam oil & gas report, May 1997). Right on the doorstep of the Total joint venture is a LPG terminal owned by Shell Gas Hai Phong. In addition, Petronas has formed a joint venture with Vietgas to build another LPG terminal and bottling facility in Hai Phong.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.17

4.15 Liquids distribution

Petechim is PetroVietnam’s trading company. The company’s activities include:-

• exporting Vietnamese crude oil and oil products; • importing foreign crude oil, oil products and materials & equipment; • supplying equipment and materials to foreign contractors; • providing consulting services on trading activities in Viet Nam; • acting as trading agencies for other subsidiaries of Petro Vietnam.

Petechim issues sell tenders for all crude oil produced in Viet Nam. To date, the country exports all of its crude oil production from four offshore fields mainly to Japan, the United States, Singapore and South Korea. On average, around 60 percent of Viet Nam’s cmde oil exports are sold to Japan. In 1996, Japanese trading houses, such as Mitsubishi, Itochu and Marubeni had fixed term contracts to purchase 100,000 barrels of Vietnamese crude oil per day. Most of this crude oil was intended for use in direct burning by Japanese power stations. During the past few years, Viet Nam has begun selling a larger percentage of its crude oil exports to independent refiners and marketers for refining and re-sale rather than direct burning (Energy Information Administration, 1996).

Viet Nam’s downstream sector is highly regulated by the government. All distribution of fuel oil, diesel, and gasoline is carried out by State controlled enterprises. The government has not issued business licences to foreign invested enterprises to operate in gasoline import and distribution because it is afraid of loosing control over price, level of service and supply of gasoline. Deregulation moves are unlikely to be seen in the near future.

Petroleum imports & exports company (Petrolimex) is a 100% state-owned distribution company. Petrolimex consists of 50 subsidiaries and 2 joint ventures in insurance and lubricant production. It holds 70% of the products markets. The company has a nation wide network of 1,500 service stations which account for about 60% of total service stations in Viet Nam. Petrolimex imports and distributes gasoline, LPG, lubricant, asphalt, chemicals, equipment and materials for trading and production purposes. It also exports to Laos, Cambodia and part of China from time to time. Petrolimex’s

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.18

priority is to provide sufficient gasoline for Viet Nam market at a price determined by the government.

Foreign companies are barred from selling gasoline and diesel fuel, the two most important refined products. However, there are some foreign companies active in marketing lubricants, liquefied petroleum gas and bitumen. BP, Castrol, Shell and Esso are now distributing lubricants in Viet Nam’s domestic market.

4.16 Refineries

At present, Viet Nam’s only refinery activity is an 800 barrels per day topping plant near Ho Chi Minh City. However, it is only to test the feasibility of producing gasoline from the Bach Ho condensate. Almost all of the country’s refined petroleum products are imported (mainly from Singapore). To meet the domestic demand for oil and gas products until 2005, the government plan to build two refineries.

The first refinery

A new US$1.5 billion oil refinery, located in the central coastal village of Dung Quat, is under construction and is expected to be in operation by the year 2003. The estimated capacity of this plant is approximately 130,000 barrels per day.

The choice of Dung Quat Bay at Quang Ngai Province as the site for the country’s first oil refinery has created many controversies. Located 970 kilometres north of Vung Tau, it is far from southern offshore fields and hence makes transportation very costly. Further, the lack of necessary infrastructure results in the need to build a new harbour and crude terminal which would increase the cost of the project by several hundred million dollars. The government, however, insists that there is a need to balance the country’s economic development by investing in the poor central part of the country. This decision follows the government’s strategy of spreading investments over the country as a whole instead of concentrating most of the new projects in the southern part (Vladimir Baum, July 1995).

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.19

The main source of crude oil for the first refinery will be Vietnamese sweet oil. In order to ensure the plant flexibility, it is also designed to use a certain amount of sour oil. The main process schemes used for the first refinery are atmospheric distillation, treating, catalytic reforming and catalytic cracking. Main outputs from the refinery will include LPG, non-lead gasoline, jet fuel, kerosene, diesel, fuel oil as well as feed stocks to petrochemical industry.

The second refinery

A second refinery project has been proposed by the Vietnamese government. It is planned to be located in the north of Viet Nam and have a capacity of 120,000 to 140,000 barrels a day. However, it will use both Vietnamese sweet oil and Middle East sour oil as inputs for its production. The aim of this refinery is to produce fuels and materials for petrochemical industry. The second refinery might take the form of a joint venture, a build-operate-transfer (BOT), a build-transfer-operate (BTO) or possibly a 100% foreign investment. The government plans to have the second refinery constructed within one or two years after the first refinery comes online.

4.17 Petrochemical plants

A lubricant and grease blending plant built and operated by BP-Petco, a joint venture between BP and Petrolimex, is located at Nha Be about 10 kilometres south of Ho Chi Minh City. It has a product capacity of 50,000 tonnes a year, some of which will be exported. Lubricants are blended to BP formulations using base oil stocks and additives. Although all materials used in production are imported, local ingredients will be increasingly employed (Vietnam oil & gas report, June 1997).

There are two other lubricant blending plants in Nha Be with capacity of 20,000 tonnes per year each. They were built before 1975 by Esso and Caltex, but now under the management of Petrolimex. Also in Nha Be, an Esso-led joint venture has a project to build and operate facilities for the distribution and marketing of petroleum products. Facilities will include a modem lube blending plant, a bulk asphalt plant and a liquefied petroleum gas bottling plant.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.20

In a joint venture with SaigonPetro, Castrol is operating a lubricant blending plant with capacity of 25,000 tonnes a year at Cat Lai, Ho Chi Minh City. In addition, there are four Vietnamese private companies (Bao Thanh, Indopetrol, Lataca and Toan Tam) with small lubricant blending plants in Ho Chi Minh City. Each of these plants has capacity from 5,000 to 10,000 tonnes a year.

In Dong Nai, there is a 25,000-ton per year lubricant plant built and operated by Shell since 1995. Vidamo, a subsidiary of PetroVietnam, also has two lubricant blending plants in Ho Chi Minh City and one in Ha Noi with total capacity of 40,000 tonnes a year.

Castrol Vietnam Ltd. has considered the construction of a plant for producing transformer oil used in electricity power supply lines. The projected plant is located at Cat Lai, Ho Chi Minh City and would produce international standard transformer oil for used in the modem transformers on the 500-kilovolt national power line and in the upgrading of various projects involved in the distribution of power in the largest urban areas of Viet Nam. Producing transformer oil locally will represent a saving on imports and the introduction of top of the line technology (Vietnam oil & gas report, June 1997).

The Vietnamese petrochemical sector is in the early stages of development. Therefore, the government is very keen to attract foreign investors with advanced technology to further develop this sector. It is proposed that at least two petrochemical complexes will be developed in the future. These include one gas-based in the south (Ba Ria - Vung Tau) and one oil-based in the central part (Dung Quat). PetroVietnam has submitted plans for a number of petrochemical projects for production of:-

• poly-vinyl-chloride (PVC) plastics with a capacity of 100,000 tonnes a year, • di octane phthalate (DOP) with a capacity of 30,000 tonnes a year, • Polystyrene (PS) with a capacity of 30,000 tonnes a year, • Polypropylene, • floating methanol and • synthetic detergent.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.21

4.18 Power generation from gas

Figure 4.8 shows the main power plants in southern Viet Nam. Located about 15 kilometres south of Ho Chi Minh City is the 375 megawatt Hiep Phuoc power generation plant where the electricity supply generated will be used in the Tan Thuan Export Processing Zone and in the 3,000 hectare Saigon South Urban ‘new city’ project. This development would ensure that all the clients using electricity in the Tan Thuan export processing zone have assured, uninterrupted supplies of electricity (Vietnam oil & gas report, June 1997).

Developing the gas industry quickly is of vital interest to all businesses in southern Viet Nam as gas-fired power plants will help ease the overburdened electricity network (Christopher Moore, 1996). The Phu My series of gas-fired power plants, Phu My 1, Phu My 2, Phu My 3 and Phu My 4, could have an eventual group generating capacity of 2,400 to 3,200 megawatts. Phu My 1 has a planned capacity of 800 megawatts. The first phase of Phu My 2 has a capacity of 300 megawatts and the second phase of Phu My 2 will add another 300 megawatts. The Phu My 3 power generation unit and urea fertiliser production plant complex will have a 600-megawatt capacity and be fuelled by natural gas. The concentration of power generation plants at Phu My, in Vung Tau-Ba Ria province 85 kilometres south-east of Ho Chi Minh City takes advantage of associated gas piped from the Bach Ho field as well as non-associated gas from the Nam Con Son Basin (Vietnam oil & gas report, June 1997).

As shown in Figure 4.8, the two fuel-oil power plants at Hiep Phuoc and Thu Due could also be converted to gas-fired plants as gas from Nam Con Son Basin becomes available. Together with the Phu My power complex, they will supply electricity to the Ho Chi Minh City - Vung Tau - Bien Hoa industrial triangle. Energy intensive industries such as fertiliser, ceramics, high quality glass, steel, white cement and other construction materials along the Highway 51 industrial corridor may also benefit by tapping directly into gas pipelines to meet their energy demand. On the route from Phu My to Ho Chi Minh City, a nitrogenous fertiliser plant is planned with a production capacity of some 1,000 tonnes per day rising to 1,750 tonnes per day. The plant will use the piped gas for feed stock and power generation (Vietnam oil & gas report, June 1997).

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 4.22

Figure 4.8 - Gas-fired power plants in southern Viet Nam

Glen Hoi m OATH OPERATOR 156 1997/S EVN

PUNT MW DATE OPERATOR 1 600 1993/9 EVN 2 600 1996/7 JV (ABB) 3 600 1396/9 JV MW DATE OPERATOR 300 2003 Hiep Phucc Power Co PboMy MW OATE OPERATOR 165 1996 EVN

Eliding Rich Ho Pipeline Proposed Nam Cun Son Pipeline Potential Pipeline Extensions

Source: The Vietnam Business Journal web site, http://www.viam.com/august96/map2.html

At Tien Hai, 90 kilometres south-east of Ha Noi, there is an idle gas fired power generation unit. This power station has a capacity of 35 megawatts and presently being renovated for its planned gas consumption of 8.5 million cubic feet per day over the next 10 years. Anzoil, a future gas producer, has also planned to construct and operate a power station with a capacity of 300-600 megawatt close to its D14 Song Tra Ly gas field.

Author: Huong Luong Lien December 1998 Chapter 5

The Energy Market The economics of petroleum exploration and development in Viet Nam Page 5.1

The discussion in this chapter focuses on the supply, demand and price of crude oil, petroleum products, natural gas, liquefied petroleum gas, coal and electricity in Viet Nam. The country’s energy flow chart for 1997 is presented in Figure 5.1. The numbers shown in the figure are estimated by using the approximate energy conversion factors in Appendix B. In Figure 5.1, it is assumed that there is no stock change or loss of production (for example, through flaring).

Figure 5.1 - Viet Nam’s energy flow chart for 1997

Energy availability 25.67 MMtoe Indigenous production Imports 19.31 MMtoe 6.36 MMtoe J l

Exports Total primary energy supply 13.48 MMtoe

12.19 MMtnp► J \ ( 1

gas

Crude oil and Coal oil power

MMtoe MMtoe

petroleum products MMtoe 5.21 MMtoe

MMtoe

6.76 MMtoe Natural 1.10 Crude 2.49 0.41 Hydro

9.7 Coal

Final energy consumption 8.43 MMtoe

Transformation

into electricity gas

4.72 MMtoe Petroleum products MMtoe MMtoe MMtoe

5.01 MMtoe Coal Electricity Natural

T & D Losses 1.31 2.06 0.05 0.33 MMtoe

According to the Oil, Gas & Coal Supply Outlook of the International Energy Agency, Viet Nam has substantial coal, hydro, oil and gas resources. Gas has recently been added to the country’s energy portfolio as an important resource. The coal and hydro resources are concentrated in northern Viet Nam, while most of the oil and gas discoveries are found in offshore southern Viet Nam. Coal, hydro and natural gas have to compete with each other as inputs for power generation.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.2

5.1 Crude oil

5.1.1 Crude oil reserves and production

According to the 1996 Country Economic Briefs of Vietnam by Australian Department of Foreign Affairs and Trade, Viet Nam’s proven crude oil reserves are estimated at 1.7 billion barrels. Table 5.1 gives the original proven reserves of some significant oil discoveries in Viet Nam.

Table 5.1 - Significant oil discoveries in Viet Nam Discovery name Proven reserves Reserves status (million barrels) Bach Ho 1 500.00 developed Bunga Kekwa 57.00 developed Dai Hung 1 100.00 developed Emerald 1 45.65 undeveloped Rang Dong 1 220.00 developed Rong 1 85.00 developed Rong 14 21.64 undeveloped Ruby 1 150.19 undeveloped Vung Dong 1 73.30 undeveloped U Minh 1 55.00 undeveloped

Note: See Appendix A for reserves definitions

The proven, probable and possible reserves from existing developments together with potential reserves in new discoveries are estimated to be 3 to 5 billion barrels (Edward A. Gargan, 1995).

The country is currently producing oil from Bach Ho (1986), Dai Hung (1994), Rong (1995), Bunga Kekwa (1997) and Rang Dong (1998) fields. The Ruby oil field is scheduled to start production before the end of 1998. Figure 5.1 shows the daily production of crude oil in Viet Nam from 1986 to 1997.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.3

Figure 5.2 - Viet Nam’s crude oil daily production

200 190.0 170.0 160.0 % 160 140.0 fc 140 127.0 109.0

Time

Source: Energy Information Administration web site, http://www.eia.doe.gov/emeu/cabs/vietnam.html.

Viet Nam has set a crude oil production target for the year 2000 of 400,000 barrels per day as Rang Dong and Ruby are brought on stream. All of the crude oil currently produced in Viet Nam is exported since it has no indigenous refinery capacity. The major export markets are in Japan, Singapore, United States and South Korea.

5.1.2 Crude oil quality

The crude oil produced from Bach Ho, Dai Hung and Rong fields are waxy and sweet. Table 5.2 gives the characteristics of crude oil from the three currently producing oil fields.

Table 5.2 - Vietnamese crude oil properties Property/field Bach Ho Dai Hung Rong

API gravity (°API) 39.85 29.06 36.15 Sulfur content (% by weight) 0.03 0.10 0.07 Paraffin content (% by weight) 29 17.8 28.9 Nickel + Vanadium content (parts per million) 2.73 2.69 1.87 Nitrogen content (% by weight) 0.04 0.036 0.05 Pour point (°C) 35 25 34

Source: Truong Dinh Hoi, The characteristics of Vietnamese crude oil, PetroVietnam Review, Vol.4,1997.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.4

In general, Vietnamese crude oil has low sulfur content (below 0.1% by weight), high paraffin content (29% by weight), high pour point (higher than 30°C) and low content of heavy metals.

5.1.3 Crude oil price

The high quality of Vietnamese crude oil gives it a premium value over Minas crude (By Van Tu, 1995) and the prices paid for Vietnamese crude oil are typically US$2 per barrel higher than those of crude oil from Middle East.

The entire production from the Bach Ho field has been sold on a term basis since 1989. The Bach Ho term contracts are reviewed every six months between Petechim (PetroVietnam trading company) and the term buyers.

Prior to October 1997, the official selling price (OSP) formula of Bach Ho crude oil used the monthly average of the bi-weekly price assessment of the Asian Petroleum Price Index (APPI) for the Indonesian Minas crude as the benchmark and then a premium was added. APPI is derived from the price quotes submitted by players across the market spectrum, including producers, refiners, consumers and traders. The Bach Ho OSP for the period April to September 1997 was set at a premium of 80 cents per barrel to the Minas APPI quotes.

However, in September 1997, the OSP formula was changed to also include the average spot price of Platt’s published assessment. The new formula takes an average of a three- week assessment of the Minas APPI and Platt’s Minas daily spot quotes and then adds a premium. The premium for the six-month period from October 1997 to March 1998 was 80 cents per barrel. The major term buyers of Bach Ho crude oil are Nissho Iwai Corp., Petrodiamond Pte., Shell International Eastern Trading Co., Sumitomo Corp. and Caltex Petroleum Corp (.Azlin Ahmad, 1997).

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.5

5.2 Petroleum products

At present, Viet Nam has no oil refinery. As a result, it exports all produced crude oil and imports all required petroleum products. The country’s first refinery is currently under construction and is expected to start operation in 2003. The refinery is planned to consume around 130,000 barrels of crude oil per day and to start supplying the domestic market with refined products.

5.2.1 Petroleum product supply

In Viet Nam, there are six state-owned companies who have been licensed to import and distribute petroleum products. These are Petrolimex and Petec (under the Ministry of Trade), Saigonpetro (under the Ho Chi Minh City’s People Committee), Petechim (under PetroVietnam), Vinapco (under Vietnam Airlines) and the Military. Foreign companies are currently restricted from participation in distribution and marketing of major petroleum products including gasoline, kerosene, jet fuel, diesel and fuel oil. However, some companies such as Castrol, BP, Shell, Caltex have been granted licenses for the manufacture and distribution of lubricants and asphalt. Petrolimex supplies approximately 70% of the country’s total petroleum products, while Petec accounts for 15% and all others about 15%.

Importers can sell their products to households or institutional customers, depending on their specific licenses and distribution channels. At present, only Petrolimex, Petec and Saigonpetro have gasoline retailing distribution networks. Other importers wholesale to institutional customers and/or distribute liquefied petroleum gas. Vinapco mainly imports diesel and jet fuel for Vietnam Airlines (Tung-Hoa Company, 1998).

5.2.2 Petroleum product demand

The consumption of petroleum products in Viet Nam since 1990 is given in Table 5.3. Figures shown in this table include the domestic consumption of liquefied petroleum gas (LPG).

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.6

Table 5.3 - Petroleum products consumption from 1990 to 1997 Year 1990 1991 1992 1993 1994 1995 1996 1997

Consumption (thousand tonnes) 2,736 2,800 3,256 4,000 4,500 5,227 5,720 6,000

Source: By Van Tu, Market for refinery and petrochemical products in Viet Nam, PetroVietnam Review Vol.3/1995 and Vietnam Business Journal web site, http://www.viam.com/august98/fyi.html.

The petroleum products consumed in Viet Nam are LPG, gasoline, kerosene, jet fuel, diesel, fuel oil, lubricants-grease and asphalt. Table 5.4 shows the history and forecast of domestic demand for each petroleum product (except LPG) to the year 2020. LPG is to be discussed later in section 5.4 of this chapter. It should be noted that the forecasts are likely to be downgraded since the Asian financial crisis in 1998.

Table 5.4 - Forecast of domestic demand for petroleum products to 2020 Annual Annual Annual Annual Product 1995 growth 2000 growth 2005 growth 2010 growth 2020 (thousand rate rate rate rate tonnes) ‘95-‘00 ‘00-‘05 ‘05-‘10 ‘10-‘20 Gasoline 1,108 11.4% 1,901 10.8% 3,175 8.0% 4,665 6.5% 8,755

Kerosene 254 6.1% 342 8.2% 506 3.0% 587 2.5% 751

Jet fuel 207 10.8% 346 10.5% 570 10.0% 917 8.0% 1,981

Diesel- 1,256 15.5% 2,585 10.0% 4,164 8.0% 6,119 6.5% 11,485 transport Diesel- 1,028 1.5% 1,109 5.0% 1,415 3.0% 1,640 3.0% 2,205 industrial Fuel oil 791 8.3% 1,179 9.1% 1,819 2.0% 2,008 0.5% 2,111

Lubricant 78 11.3% 134 10.0% 215 8.0% 316 6.5% 593

Asphalt 114 9.3% 178 8.8% 272 10.0% 438 6.5% 822

Total 4,836 10.0% 7,774 9.3% 12,136 6.6% 16,690 5.6% 28,703

Source: Vo Thi Lien, International conference on Dung Quat, Da Nang, Viet Nam, 31/3 - 2/4, 1997.

The structure of demand for petroleum products in Viet Nam is similar to other South East Asia countries with a dominance of middle distillates (kerosene, jet fuel, diesel). As seen in Table 5.4, kerosene, jet fuel and diesel together account for more than 55% of total product demand. The demand for every petroleum products is forecast to increase. Among these, jet fuel and diesel for transportation use are predicted to grow at the fastest rates. The demand for gasoline, lubricant and asphalt are also increasing significantly.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.7

Based on forecasts made before the Asian financial crisis, by the year 2010 the demand for petroleum products in Viet Nam’s southern region would account for around 60% of the country’s total demand, while northern and central region would have 30% and 10% share respectively.

Approximately 70 percent of kerosene consumption has been used for lighting and cooking. In future, kerosene will gradually be substituted by electricity and gas for lighting and cooking purposes. Diesel is used in power stations, cement factories and other industrial factories as an energy source. However, as hydroelectricity becomes available, diesel consumption for power generation has been decreasing. At the same time, diesel consumption in transportation, agriculture, forestry and fishing sectors. About half of the fuel oil consumed in Viet Nam has been used for power generation. However, existing fuel oil power plants is expected to be converted to gas-fired plants when gas supply becomes sufficient. Asphalt demand in Viet Nam grows in parallel with infrastructure development. More than 90 percent of total asphalt consumed is for road paving.

5.2.3 Petroleum product quality

There has been a growing problem of low quality petroleum products used in Viet Nam. As a result, the government has put in place quality-control measures including label, minimum quality specifications and import regulations. Product quality registrations must be logged in at the government office in all stages from import to production and sale of the products (Nguyen Thanh Hai, 1995).

Nevertheless, some private Vietnamese companies has bought lubricant of low quality from Taiwan and China and sold it in the domestic market to compete with other brand names such as Caltex, BP and Shell. The volume of low quality lubricant import has been estimated to be approximately 50% of the total lubricant market. This causes a real problem for high-quality lubricant suppliers (Tung-Hoa Company, 1998). The government has tried to solve the problem by issuing the prescribed minimum quality specifications of automotive lubricant in Viet Nam.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.8

There are two main grades of gasoline used in Viet Nam. These are octane specifications of RON-92 and RON-83. Since gasoline is used mostly for transportation, the quality of gasoline consumed depends on road net work conditions and the characteristics of existing cars. As the Law on Environmental Protection is promulgated, the octane average will improve. In addition, the lead content ceiling is targeted to decrease from 0.4 g/1 to a lower or even lead free level.

Jet A1 for civil air and TC.l for air force are the two main grades of jet fuel used in Viet Nam.

Diesel oil for transportation has a cetane number of 45 and sulfur content of 0.3% to 0.5% by weight, while industrial diesel oil has cetane number of 50 and sulfur content of 0.5% to 1% by weight. To improve diesel oil quality, the government intends to raise the cetane number and lower the sulfur content requirements.

Fuel oil used in Viet Nam has low viscosity and up to 3% by weight of sulfur content.

Asphalt is imported either by drums or bulks with quality grade of Mexphalt 60/70 and Mexphalt 80/100 (By Van Tu, 1995).

5.3 Natural gas

Viet Nam’s gas industry is still in the early stages of development. As demand for energy continues to rise, the country’s gas sector is expected to play an increasingly important role in the economy. The government of Viet Nam has completed a gas master plan including a detailed study of gas supply, transportation, domestic and export gas markets as well as pricing and regulatory policies.

5.3.1 Natural gas supply

Currently, natural gas is produced from two fields. Viet Nam has been producing non- associated gas from the Tien Hai field at a rate of 11 million cubic feet per day since 1981. Associated gas from the Bach Ho field is brought ashore at a rate of over 110 million cubic feet per day by a 125 kilometre pipeline completed in early 1995. Before the next century, gas production is scheduled to increase dramatically as gas comes ashore from gas discoveries in Nam Con Son Basin.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.9

The country’s estimated proven natural gas reserves are approximately 6 trillion cubic feet (Energy Information Administration, 1998). The proven plus probable gas reserves are 13 trillion cubic feet. Since 1988, several significant gas discoveries have been made in offshore Nam Con Son Basin and onshore Ha Noi Trough (see Table 6.4 in Chapter 6 for details).

As regards the potential for future discoveries of gas in each sedimentary basins, the results of a government study are presented in Table 5.5. Discovered reserves and potential resources quoted in the table are believed to be proven plus probable plus possible reserves.

Table 5.5 - Potential gas resources Basin Discovered reserves Potential (trillion cubic feet) resources (trillion cubic feet) Song Hong Basin (including Ha Noi Trough) low C02 gas 1-2 high C02 gas 7.35 13-17 Cuu Long Basin 1.98 3-5 Nam Con Son Basin 6.14 19-25 Malay Basin 1.06 3-5

Other basins - 19-25 Total 16.53 58-79

Source: PetroVietnam’ 97 brochure.

In addition, coal reserves found in the Quang Nam province are capable of creating 1.41 trillion cubic metres of methane. The cost of producing methane gas from this type of coal is lower than that from offshore gas fields. As such, an integrated gas-power- fertiliser project near Nong Son coal mine is currently considered by the local authorities.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.10

5.3.2 Natural gas demand

As in other countries, natural gas in Viet Nam can be used for:-

• generating electricity • producing fertiliser • producing steel mills • producing high quality glass and ceramics • producing white cement and other construction materials • supplying feed stocks for petrochemical plants • domestic heating and cooking

However, at this early stage, the domestic market for gas is mainly for power generation which consumes a stable and large amount of gas over a long period of time. Existing power plants have potential to switch from fuel oil to gas as their source of power because of the lower cost as well as the environmental cleanliness of gas. It is predicted that gas used in power generation will account for 65% to 70% of the total gas production. The production of fertiliser from natural gas is also important to the agriculture sector which dominates the Vietnamese economy.

Table 5.6 shows the forecast of gas consumption for different geographical areas in Viet Nam.

Table 5.6 - Gas demand forecast in billion cubic feet per year Area/Y ear 2000 2005 2010 North Viet Nam 0-88 141-177 212-247 Central Viet Nam 0-18 18-35 35-53 South Viet Nam 141-212 212-353 318-459

Source: PetroVietnam’ 97 brochure

The forecast figures for North Viet Nam in Table 5.6 may change considerably if more quality gas fields are found in onshore Ha Noi Trough and offshore Song Hong Basin. Gas could compete with hydro and coal for power generation, as well as being a feed stock for chemical and petrochemical industries.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.11

In central Viet Nam, solutions for high-CC>2 gas treatment may put the gas industry in a much better position.

South Viet Nam is the country’s largest market for gas as it has both the rapid growth of gas demand and potentially large reserves. The availability of associated gas from Bach Ho oil field since 1995 has stimulated the local gas market in the Ho Chi Minh City - Vung Tau area. Being used as fuel for power generation, Bach Ho gas has gradually displaced the imported refined oil products used in the local thermal power plants.

As more gas being discovered from Nam Con Son Basin, gas exports by pipeline or as liquefied natural gas (LNG) to neighbouring countries such as Thailand, southern China, Taiwan, Japan and Korea may become feasible. Viet Nam with its geographical position in the region will be able to compete in the gas exporting market.

5.3.3 Natural gas price

A key issue in determining the pace of gas field development activity in Viet Nam is the price of gas in the domestic market. In general, gas sales are governed by long term sale contracts lasting perhaps 25 years. Therefore, gas pricing policy is vitally important in developing the gas industry in Viet Nam. If gas is underpriced , wastage will lead to inefficient use of a valuable resource. On the other hand, if it is overpriced, gas will fail to compete effectively with other sources of energy like hydro and coal. Hence, Viet Nam will not be able to achieve the full benefits of gas utilisation (Ian D. Forbes, 1995).

The industrial gas price is influenced by:-

• the sale price of electricity, fertiliser and other products used gas, • the sale volumes and • the seasonal variations of gas sales.

Potential gas producers in Nam Con Son Basin are negotiating a gas price with Vietnamese government so that they can supply gas for power generation in Ba Ria - Ho Chi Minh. It is really the problem of finding a balance between a domestic gas price so that the gas producers can recover their development as well as transportation costs and make a return on capital. At the same time, the price must allow power plant

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.12

operators to sell electricity at a price acceptable to Vietnamese consumers. However, electricity prices in Viet Nam are only US5.2 cents per kilowatt hour (KWH). The price is substantially lower than those in Thailand or Indonesia (Christopher Moore, 1996). This makes it difficult to offer competitive gas prices to producers.

In July 1998, the chairman of PetroVietnam Mr. Ho Sy Thoang addressed that Viet Nam cannot afford an increase in electricity prices from US5.2 to US7 cents per KWH and it would maintain a lower gas price than other countries. It is believed that the producer price in a range of US$2.6 to US$2.8 per million British Thermal Unit (BTU) might be possible. However, exports will provide gas producers with an outlet for excess supplies and the possibility of gamering higher prices.

The government will support the fertiliser manufacturing sector by selling gas at lower price than to other sectors. In Indonesia, for instance, the price of gas for fertiliser plants is only US$1 to US$1.5 per million BTU. In some offers, the gas price requirement of an ammonia fertiliser plant project is about US$1.75 per million BTU {Nguyen Viet Hung, 1995).

5.4 Liquefied petroleum gas

5.4.1 LPG supply

Liquefied petroleum gas (LPG) has been imported into Viet Nam from Singapore, Philippines and Thailand since early 1990s. Kerogasimex state-owned company has imported small amount of ready-filled LPG cylinders from Thailand for resale in Viet Nam. However, most LPG currently imported into Viet Nam is delivered to existing storage terminals used for receiving bulk LPG. It is then either bottled to cylinders (7, 9 or 13 kilogram each) and distributed by trains, trucks to households or delivered in bulk (4 or 10 tonne each load) by tank-truck to commercial and industrial consumers. Imported LPG has a varying composition of propane and butane. The propane: butane compositions of LPG sold in Viet Nam market are 10: 90, 30: 70, 40: 60 and 50: 50 {Nguyen Quang Hap, 1996).

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.13

Table 5.7 shows the existing storage and bottling capacity of companies distributing LPG in Viet Nam market. LPG terminal owners such as Elfgas, SaigonPetro, Petrolimex and Unique Gas all have their own distribution network of dealers across the country. At present, there is a growing competition in Viet Nam market with over 15 local and foreign companies marketing and distributing LPG. The new players are entering the LPG market with lower prices, higher commissions for sale agents, higher quality and safety standards as well as better after-sale services. The existing players are trying hard to maintain their market shares.

Table 5.7 - LPG storage and bottling capacity Company name Storage capacity Bottling capacity (tonnes) (tonnes/year) Saigonpetro 1,280 45,000 Elf Gas 1,050 25,000 Petrolimex 1,000 20,000 LPG Gas 800 15,000 Unique Gas 800 10,000 Thang Long 1,000 10,000 Dong Nai 1,200 60,000 Siam Gas 350 4,000 Chinh Fong/CPC 500 _ Total 1,000 Shell Vietnam 1,000 _ Total 9,980 189,000

LPG will soon be produced locally at Dinh Co gas processing plant. As a consequence, regional LPG terminals in the whole country will receive LPG from Dinh Co. Future refineries will also supply LPG in small pressurised tankers, ferries or other means of transportation. It is estimated that Dinh Co plant will generate up to 300,000 tonnes of LPG a year. The first refinery scheduled to be completed by 2003 would add another 258,000 tonnes to the country’s LPG annual production. In addition, the Nam Con Son gas processing plant is expected to produce about 445,000 tonnes of LPG from 2005.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.14

5.4.2 LPG demand

Lacking a complete gas pipeline network, South East Asia has the fastest growth in liquefied petroleum gas consumption in the world. At present, Viet Nam market for liquefied petroleum gas (LPG) is relatively small compared to other neighbouring countries. However, over the past few years, domestic demand for LPG has increased significantly as all sectors of the economy have grown. Viet Nam imported 35,000 tonnes of LPG in 1995, compared with 18,000 tonnes in 1994. Domestic consumption of LPG in 1996 was 67,000 tonnes of which 20% was for industrial use, the rest going to households. Being used as cooking fuel for households, LPG is more efficient and more convenient than kerosene. In addition, it does not have the environmental drawbacks of traditional solid fuels such as wood and charcoal. The displacement of timber-derived products by LPG will help to reduce deforestation and atmospheric pollution.

There is an increasing preference among households, commercial and industrial consumers to use LPG due to shortages in power supply and the increase in electricity tariff. The demand of LPG is expected to continue to grow quickly as the government has no plans to establish a gas pipeline system within the next ten years. The domestic demand for LPG during the 2000 to 2005 period is estimated to be 140,000 tonnes a year of which around 43% will be used for cooking, 36% for industrial fuel and 21% for petrochemical industry and others. Nguyen Quang Hap from PetroVietnam Gas Company has done a study which was published in PetroVietnam Review Vol. 1-1996. He forecasts the potential demand for LPG in Viet Nam up to the year 2020 (see Table 5.8).

Table 5.8 - Forecast of LPG demand in Viet Nam 2000-2020 in thousand tonnes Area / Year 2000 2005 2010 2015 2020

Ha Noi 22.6 35.2 48.3 63.4 81.2 Hai Phong 12.0 19.5 26.7 35.0 50.0 Da Nang 3.5 5.5 8.0 9.6 12.2 Ho Chi Minh City area 44.0 72.0 92.0 114.0 140.0 Total 82.1 132.2 175.0 222.0 283.4

Source: Nguyen Quang Hap, Viet Nam LPG market, PetroVietnam Review, Vol.l, 1996.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.15

In this study, LPG demand is determined by taking into account the following considerations

• number of households and annual population growth rate • income of residents • the availability of LPG • LPG price compared to other fuels • consumption of other fuels such as kerosene, wood and charcoal • consumption patterns in similar markets in South East Asia.

5.4.3 LPG price

From 1990, LPG was used in Vietnam as a cooking fuel. It was imported from Thailand in ready filled cylinders which had a retail price of about US$1.50 per kilogram. There was limited supply at that time. However, competition between foreign-led LPG importers and distributors has pulled the price down for customers by about 60% over five years. In 1995, LPG price was approximately US$0.60 per kilogram in bottled cylinders for households and US$400 per ton in bulk for industries. The expansion of LPG licensing could cut profit margins still further. The increasing number of suppliers, the construction of more LPG filling stations and the expansion of retail network could result in a more competitive retail price.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.16

5.5 Coal

5.5.1 Coal supply

Vietnam National Coal Corporation (Vinacoal) estimates that coal reserves of Viet Nam may exceed 3.3 billion tonnes {Energy Information Administration, 1998). The majority of coal deposits are high quality anthracite coal, located mostly in the north-eastern province of Quang Ninh. About half of the country’s coal production comes from the Cam Pha coal mine in Quang Ninh. There are three major coal mining and processing centres. These are at Hon Gai, Cam Pha-Duong Huy and Uong Bi-Mao Khe and have a total capacity of 12 million tonnes a year. Figure 5.3 presents Viet Nam’s coal production from 1986 to 1997.

Figure 5.3 - Viet Nam’s coal production TTW

Time Source: Department of Foreign Affairs and Trade, The Country Economic Briefs - Vietnam, Commonwealth of Australia, 1996.

In the north-east of Viet Nam, Quang Ninh province has the largest deposits of coal. These account for 90 percent of the country’s total coal reserves. In Quang Ninh, coal deposits run 150 kilometres from Ke Bao island (Van Don) to Mao Khe (Dong Trieu). These deposits have a production capacity of 30 to 40 million tonnes a year. Coal found in Quang Ninh is anthracite coal which is pressed into hard, big rock with a stable carbon content of 80 to 90 percent, a high calorific value of 7,350 to 8,250 Kcal per kilogram, and a low ash and sulfur content. To the west of Quang Ninh, coal deposits are also found at Ngan Son in Bac Can province.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.17

In central Viet Nam, Quang Nam has two significant coal mines. These are Nong Son and Ngoc Linh. Approximately 0.2 million tonnes of coal are produced every year from these mines. Nong Son coal reserves is estimated at 80 million to 100 million cubic metres.

5.5.2 Coal demand

Domestic consumption of coal is currently around 7 million tonnes per year. The surplus of coal supply over domestic consumption has been exported. Figure 5.4 shows Viet Nam’s coal export from 1986 to 1997. About 40 to 45% of the coal export in 1997 went to steel mills in Japan (Russel Agle, 1998). In Viet Nam, coal is used mainly for power generation. However, demand for coal from the power sector is expected to fall as hydro and gas increasingly becomes used as a power station fuel.

Figure 5.4 - Viet Nam’s coal exports 5 ------

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 Time

Source: Department of Foreign Affairs and Trade, The Country Economic Briefs - Vietnam, Commonwealth of Australia, 1996.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.18

5.6 Electricity

For several years, demand for electricity in Viet Nam has exceeded the country’s electricity output. As Viet Nam relies mainly on hydro for generating power, the possibility of electricity shortages during the dry season is much higher than at other times of the year. It has been estimated that Viet Nam will need to achieve an annual increase of 17.5 percent in electricity production in order to keep pace with the growing demand. Natural gas has recently become preferred fuel for meeting the country’s need for additional generating capacity.

5.6.1 Electricity supply

Viet Nam’s electricity output from 1990 to 1997 are shown in Figure 5.5. Viet Nam currently has a total electricity generation capacity of 4.7 gigawatts, of which hydropower accounts for about 67 percent, thermal power 18 percent and natural gas 15 percent (.Energy Information Administration, 1998). In the north, most electricity is generated from hydro, while the south relies mainly on coal, oil and natural gas.

Figure 5.5 - Viet Nam’s electricity output

19.10 2 16.90 oa JS 14.60 13 12.47 * o 10.85 3 #oa S

Time

Source: Department of Foreign Affairs and Trade, The Country Economic Briefs - Vietnam, Commonwealth of Australia, 1996.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.19

To meet the growing demand and avoid possible shortages of electricity, Viet Nam intends to boost its electricity output to 30 billion kilowatt hours. It intends to do this by increasing its generation capacity to 7.2 gigawatts by the year 2000. The power industry has also set a target of 9 gigawatts capacity by the year 2010. In the short term, the required additional capacity would be met by expanding gas-fired and coal-fired capacity. However, over the long term, hydropower would continue to play a major role in meeting the country’s electricity need. It is planned that by the year 2005 power generated from gas may account for 35 percent of the country’s total generating capacity, while hydropower’s share will drop to 47 percent (see Figure 5.6).

Figure 5.6 - Current and planned fiiel shares of electricity generation

Current Year 2005

Natural Natural gas gas 15% 35% Thermal Hydro power power 18% 47%

power Thermal 67% power 18%

Viet Nam currently has more than fifteen power generation plants across the country. The main supply of electricity in northern Viet Nam is the 1.92 gigawatts Hoa Binh hydro-electric plant, located about 70 kilometres west of Ha Noi, which was completed in December 1994. The Hoa Binh plant has formed the basis for a national power grid. It is linked to central and southern Viet Nam by the 500 kilovolts north-south transmission line network. Tri An hydro-electric plant is the biggest power plant in southern Viet Nam. It provides electricity to Dong Nai, Ho Chi Minh City and other neighbouring provinces. The government has recently invested in other major projects including thermal power plants at Can Tho, Pha Lai, Thai Nguyen and Uong Bi, gas-fired power plants at Ba Ria and Phu My.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.20

Since 1995, Viet Nam’s electricity generation capacity has grown by 390 megawatts per annum. Nevertheless, the government estimates that an additional capacity of 400 to 500 megawatts a year is needed to ensure enough supplies in the dry seasons. The country is currently facing serious power shortage problems during the dry season. At this time of the year, the hydropower source is exhausted while the demand for electricity continues to rise. Power shortages can reach up to 300 megawatts.

Table 5.9 shows existing and future generation facilities in Viet Nam. The government has plans to construct new gas-fired plants in the south-east, new coal-fired plants near coal mines in the north-east and new hydro-electric plants in northern and central Viet Nam. Two turbine-gas generators with a combined capacity of 75 megawatts has been installed at Tra Noc power plant in Can Tho. The plant began operation at 32 megawatts capacity in 1996 and is expected to start operating at full capacity in 1999. In the south of Ho Chi Minh City, there are two oil-fired power plants at Thu Due and Hiep Phuoc which have a generating capacity of 156 megawatts and 375 megawatts respectively. These power plants will be converted from fuel-oil to gas-fired when gas supply becomes available. The Pha Lai 600-megawatt coal-fired power plant 2 will be built at Chi Linh in the northern province of Hai Duong. It is designed to generate 3.68 billion kilowatt hours each year and expected to start operation in 2001. Pha Lai 2 is located adjacent to the existing Pha Lai 1 thermal plant creating the largest thermal power complex in the north with a total capacity of 1,040 megawatts.

Electricity supply is also a matter of great concern in the central region. According to the industry ministry, five large and medium-sized hydro-electric plants are to be completed in the central highlands in the 1996-2005 period. Combined with the 720 megawatts Ya Ly plant, now under construction, these six new hydro-electric plants will have a generating capacity of 1.171 gigawatts. In addition, the government of Viet Nam has approved the 300 megawatts Dai Ninh hydro-electric plant in the southern province of Binh Thuan and the 3.6 gigawatts hydro-electric plant at Son La near Ha Noi. The two plants are expected to be completed in 2005 and 2008 respectively.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.21

Table 5.9 - Viet Nam’s existing and planned additional electricity generation facilities Existing facilities Planned additional facilities Type Location Gen. capacity Location Gen. capacity (megawatts) (megawatts) Hydro power Hoa Binh 1,920 Dai Ninh 300 Tri An 400 Ham Thuan-Da Mi 475 Thac Mo 150 Song Hinh 70 Da Nhim 100 Buon Kuop* 85 Thac Ba 100 Dong Nai 4* 280 Vinh Son 66 Se San 3* 220 Son La 3,600 Thuong Kon Turn* 260 Yali 720 Thermal power Pha Lai I 300 Pha Lai II 600 Thu Due 165 Phu My 2,400 Uong Bi 70 Uong Bi 150 Ninh Binh 40 Ninh Binh* 110 Can Tho 33 Can Tho 35 Tra Noc 32 Thai Nguyen 100 Mien Tay #1* 300 Mien Tay #2* 300 Gas turbine Ba Ria-Vung Tau 177 Ba Ria 91 Thu Due-old 165 Thu Due-new 75

Footnote: *uncommitted projects Source: Michael R. Doyle, Viet Nam: Power generation equipment and services, Trade Port on the web, (http://www. tradeport. org/ts/countries/vietnam/mrr/markOl 99. shtml), 1997.

5.6.2 Electricity demand

The total demand for electricity across Viet Nam is estimated to be 22 to 23 billion kilowatt hours in 1998. Viet Nam currently has an electricity consumption per capita of about 250 kilowatt hours per year. This compares with Malaysia’s per capita 1996 figure of 1,135 kilowatt hours or Taiwan’s 1993 figure of 4,600 kilowatt hours. However, demand for electricity in Viet Nam has been increasing for the last several years. Since the government opted for economic reform in 1986, Viet Nam has experienced rapid commercial growth and mass migration to major cities, all of which have contributed to the country’s growing demand for electricity. An increasing number of export processing zones (EPZ), industrial zones (IZ) and large industrial parks (IP) developed across the country such as Tan Thuan EPZ, Cat Lai IZ, Hai Phong IZ, Vietnam-Singapore IP and Dung Quat IP are potential large electricity consumers. Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 5.22

Between 1990 and 1997, electricity consumption increased at an average rate of 11.8% per annum. In the first half of 1998, power consumption has grown over 17%. It is predicted that demand for electricity in Viet Nam will continue to grow at a rate of 10 percent to 15 percent per year. The demand for electricity is expected to increase to 30 billion kilowatt hours by 2000 and 50 billion kilowatt hours by 2012 from its current level of 22 billion kilowatt hours.

5.6.3 Electricity price

According to a World Bank survey of electricity tariffs in Viet Nam, the end-user tariffs for electricity in 1993 were the same for all categories of consumer except commercial users, for whom the tariff was higher. The average electricity price in Viet Nam is currently Vietnamese Dong 680, or US5 cents per kilowatt hour. However, power shortages experienced in Viet Nam especially during the dry season have put pressure on electricity consumption prices to rise.

The current selling price of electricity in Viet Nam is much lower than that of other regional countries and is therefore not attractive to foreign investors and international financial institutions. As Electricity Vietnam Corporation (EVN) needs more capital to invest in new power projects, it must seek loan from international financial institutions such as the World Bank (WB) and the Asian Development Bank (ADB). WB has formally asked the company to raise the price of electricity from US5 cents per kilowatt hour currently to US7 cents (Vietnamese Dong 910) per kilowatt hour in 1999. ADB has also recommended that EVN increases the price to US8.9 cents per kilowatt hour. Furthermore, there is also pressure from gas producers to lift electricity charges so that they can obtain higher gas prices.

According to Lam Hong Minh (1998), EVN, under the pressure from the National Assembly and the government, is unlikely to increase electricity prices before the year 2000. However, Viet Nam may consider a price increase to US7 cents per kilowatt hour after the year 2000.

Author: Huong Luong Lien December 1998 Chapter 6

Exploration Performance The economics of petroleum exploration and development in Viet Nam Page 6.1

This chapter presents a statistical analysis and interpretation of the results of historical exploration activities in Viet Nam. It includes analyses of reserves, play types, geophysical surveys and a discussion of future exploration in the country.

6.1 Definitions

The drilling statistics from Petroconsultants database and publications in Viet Nam are used to analyse historical exploration performance. These statistics include wells drilled and seismic surveys until the end of 1997.

The followings are definitions which have been used to analyse the statistics.

New field wildcat

A new field wildcat (“NFW”) well is defined as an exploration well drilled on a previously untested geological structure. New field wildcats can be categorised as follows:-

• Dry holes • Oil and/or gas shows • Oil and/or gas non-commercial discoveries • Oil and/or gas commercial discoveries

Dry holes

Dry holes are unsuccessful new field wildcat wells which fail to discover any hydrocarbons and therefore are subsequently abandoned.

Shows

Wells with shows of oil and/or gas are new field wildcat wells which has encountered oil or gas, but in quantities insufficient to warrant appraisal drilling. They only show evidence of hydrocarbons in a formation, such as fluorescence in cuttings or gas in the mud returning from down hole (An Oil and Gas Handbook of Bank of Scotland, 1992). This type of well is excluded from the definition of discoveries.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.2

Discoveries

A discovery of oil and/or gas is defined as a successful new field wildcat well which has encountered an accumulation of oil and/or gas. It is usually the first successful well on a new prospective reservoir structure {An Oil and Gas Handbook of Bank of Scotland, 1992).

An oil discovery is a new field wildcat well which discovers oil, or oil together with associated gas. A gas discovery is a new field wildcat which discovers predominantly gas, or gas together with condensate (oil may also be present). A discovery will be determined by Contractors as whether it is a commercial or non-commercial discovery. The successful new field wildcat well can be either:-

• currently under appraisal or, • currently under development or, • already developed.

In economic terms, a commercial discovery is a new field wildcat well which has already resulted in or is likely to result in a commercial development. The definition of commercial discoveries specifically excludes shows and any non-commercial discoveries which have been appraised in the past but which have been subsequently abandoned.

Fields

A field is defined as a discovery which has already been declared commercial.

Drilling success ratio

The Oil and Gas Handbook of Bank of Scotland, 1992 defines geological drilling success ratio as the proportion of exploration wells which encounter significant hydrocarbons. Similarly, an overall geological drilling success ratio used in this study is the ratio of the number of hydrocarbon discoveries (both commercial and non commercial) to the total of new field wildcat wells drilled in a period and for a given area.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.3

The commercial drilling success ratio is the portion of exploration wells which discover reservoirs of development potential. This ratio is therefore used to justify drilling decisions at the exploration phase.

Reserves

Appendix A presents the Society of Petroleum Engineers (SPE)/ World Petroleum Congress (WPC) reserves definitions. The reserves figures presented in this chapter refer to original recoverable oil, condensate or gas as quoted in public sources. In general, it is not known whether quoted reserves figures refer to proven, proven plus probable, or proven plus probable plus possible reserves. Oil-in-place or gas-in-place figures are not used for the purpose of assessing the statistics of historical exploration performance.

Reserves discovered per new field wildcat well

The reserves discovered per new field wildcat is one measure of the success of exploration drilling. It is calculated by dividing the reserves discovered during a given period by the number of new field wildcat wells drilled in the same period.

Reserves distributions

Reserves distributions are diagrams showing the distribution of original recoverable oil and gas in individual accumulations and will be presented in the latter section of this chapter. The statistics are shown for accumulations which are “discoveries” as defined above. In other words, they could be commercial or non-commercial finds. The statistics here are shown for all finds, both commercial and non-commercial.

6.2 Exploration drilling

The location of the major sedimentary basins of Viet Nam are shown in Figure 6.1. Several offshore and onshore tertiary basins have been identified:-

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.4

• Ha Noi Trough - mostly onshore the north • Song Hong Basin - offshore the north • Phu Khanh Basin - offshore the centre • Cuu Long Trough - onshore the south-east • Cuu Long Basin - offshore the south-east • Nam Con Son Basin - offshore the south-east • Malay Basin - offshore the south-west • Hoang Sa Basin, Eastern Sea Basin and Truong Sa basin - offshore the east

Almost all of these basins are underexplored. The Hoang Sa, Eastern Sea and Truong Sa basins remain unexplored because of territorial disputes between countries surrounding the South China Sea.

Table 6.1 presents the detailed statistics for wildcat wells drilled in Viet Nam from 1974 to 1997 inclusive. Wells are sorted into group by basins. It should be noted that the following exploration drilling have not been included in Table 6.1 for statistical analyses:-

• exploration drilling in Ha Noi Trough carried out by Viet Nam before 1990 • exploration drilling in Malaysia - Viet Nam Commercial Arrangement Area.

Malaysia - Viet Nam Commercial Arrangement Area is the overlapping area between the two countries and being operated under different fiscal regime. Therefore, it is discussed separately in section 6.8 of this chapter.

Since the 1960s, about 42 exploration wells have been drilled in onshore Ha Noi Trough under the technical assistance of the former Soviet Union. The drilling depth of these wells ranged from 1,200 metres to 5,000 metres. Out of the 42 exploration wells drilled, possibly four wells have encountered significant gas and many other wells have oil and gas shows in Miocene clastic. Tien Hai C, a small gas field was then discovered in 1975 in Thai Binh province. This drilling activity in Hanoi Trough has not been included in Table 6.1 as no further details are available.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.5

Figure 6.1 - Tertiary basins in Viet Nam

TERTIARY BASINS IN VIETNAM

CHINA

HANOI Tl 2o°txm 20°WN

HA I NAM IS

IfeTXFN THAILAND Ah°00*N

CAMBODIA

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Source: PetroVietnam Review Vol.2-1996, page 21.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.6

Table 6.1 - Statistics of wildcat wells drilled from 1974 to 1997 inclusive *2 1 CQ 1 1 1 I 1 W e lN l a m e on/orr T e r r a i n L o n g i t u dL e a t i t u d e 1 W e llS t a t u s 1 I

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111 Japan-Vietnam P e t r o l e uC m o III Ill 1 0 6 .3 3 3 3 3 If! in C u uL o n gT r o u g h C u uL o n g1 9 5 8 3 3 3 d r y g P lu g g e& d a b a n d o n e d 1 9 8 0 1 9 8 0PetroVietnam E & P C o C u uL o n gT r o u g h d r y H a uG i a n g1 1 0 5 .5 8 3 3 3 9 .6 6 6 6 7 P lu g g e& d a b a n d o n e d 1 9 8 0 1 9 8 0 d r y PetroVietnam E & P C o C u uL o n gT r o u g h L o n g X u 1 y c n 1 9 8 0 1 9 8 0 1 0 5 .5 1 0 .2 5 P lu g g e& d a b a n d o n e d S3* Ha N o iT r o u g h B a cS o n1 B lo c kK 2 O n s h o r e O n s h o r e 1 0 6 .2 8 4 2 2 0 6 2 2 1 7N e w - f i ew l d ild c a t P lu g g e d & a b a n d o n e d 2 0 - J u n - 9 6 5- A u g - 9A 6 n z o ( i Al s i aP ) ty L td 10,171 Ha N o iT r o u g h S o n gT h a B i in h1 B lo c kB 1 0 O n s h o r e O n s h o r e 1 0 6 .6 0 3 2 2 2 0 .5 9 9 5N 1 e w - f i ew l d ild c a t S u s p e n d e d 2 3 - A u g - 9 6 2 3 - S e p -A 9 6 n z o ( il A s i aP ) ty L td O n s h o r e 1 0 6 .5 2 7 3 3 4,757 Ha N o iT r o u g h S o n gT r aL y 1 B lo c D k 1 4 O n s h o r e 2 0 .4 6 5 0N 8 e w - f i ew l d ild c a t S u s p e n d e d

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H Author: The economics of petroleum exploration and development in Viet Nam Page 6.9

Table 6.2 and Figure 6.2 give a summary of drilling statistics and success ratios for each area of Viet Nam. Table 6.3 and Figure 6.3 give a summary of statistics and success ratios for exploration drilling in five year intervals.

As shown in Table 6.2 and 6.3, a total of 125 wildcats were drilled in Vietnam from the beginning of 1974 to the end of 1997. Out of the 125 wildcats drilled, 32 (25.6%) were commercial and non-commercial oil discoveries and 22 (17.6%) were commercial and non-commercial gas discoveries. In total therefore, 54 wildcats have encountered accumulations of oil and/or gas. This is an overall geological drilling success ratio of 43.2%. Out of the 54 discoveries, 26 are currently under appraisal, under development or already developed (Tien Hai not included, see Table 6.4). This gives us an overall commercial drilling success ratio of 20.8% of which 15.2% is the oil commercial success ratio and 5.6% is the gas commercial success ratio.

The 125 wildcats have delineated technical reserves of 1,810.02 million barrels of oil/condensate and 13,099.71 billion cubic feet of gas/associated gas in all accumulations (see Table 6.4). This is equivalent to approximately 14.5 million barrels of oil or condensate and 104.8 billion cubic feet of gas or associated gas for every wildcat drilled.

As we can see from Table 6.2, almost 60% of the oil discoveries in Viet Nam have been made in the offshore Cuu Long basin. On the other hand, over 70% of the gas discoveries in Viet Nam have been made in the offshore Nam Con Son Basin.

Table 6.3 shows that 78.4% of all wildcats drilled in Viet Nam were drilled after 1989 that is after the country adopted its open-door policy and the release of Foreign Investment Law in 1987.

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.10

Table 6.2 - Drilling statistics by area

Drilling performance (number of wildcats drilled) Oil discoveries Gas discoveries Area Dry Shows Non-com Com Non-com Com Total holes mercial mercial mercial mercial Ha Noi Trough 1 0 0 1 0 1 3 Song Hong Basin 8 5 0 0 4 0 17 Phu Khanh Basin 1 1 0 0 0 0 2 Cuu Long Trough 3 0 0 0 0 0 3 Cuu Long Basin 5 4 9 11 0 0 29 Nam Con Son Basin 31 9 4 1 11 5 61 Malay Basin 1 2 0 6 0 1 10 All areas 50 21 13 19 15 7 125

Drilling success ratios (percentage of total wildcats) Oil discoveries Gas discoveries Area Dry Shows Non-com Com Non-com Com Total holes mercial mercial mercial mercial Ha Noi Trough 33.3% 0.0% 0.0% 33.3% 0.0% 33.3% 100.0% Song Hong Basin 47.1% 29.4% 0.0% 0.0% 23.5% 0.0% 100.0% Phu Khanh Basin 50.0% 50.0% 0.0% 0.0% 0.0% 0.0% 100.0% Cuu Long Trough 100.0% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0% Cuu Long Basin 17.2% 13.8% 31.0% 37.9% 0.0% 0.0% 100.0% Nam Con Son Basin 50.8% 14.8% 6.6% 1.6% 18.0% 8.2% 100.0% Malay Basin 10.0% 20.0% 0.0% 60.0% 0.0% 10.0% 100.0% All areas 40.0% 16.8% 10.4% 15.2% 12.0% 5.6% 100.0%

Percentages of all area totals (percentage of total wildcats for each category) Oil discoveries Gas discoveries Area Dry Shows Non-com Com Non-com Com Total holes mercial mercial mercial mercial

Ha Noi Trough 2.0% 0.0% 0.0% 5.3% 0.0% 14.3% 2.4% Song Hong Basin 16.0% 23.8% 0.0% 0.0% 26.7% 0.0% 13.6% Phu Khanh Basin 2.0% 4.8% 0.0% 0.0% 0.0% 0.0% 1.6% Cuu Long Trough 6.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.4% Cuu Long Basin 10.0% 19.0% 69.2% 57.9% 0.0% 0.0% 23.2% Nam Con Son Basin 62.0% 42.9% 30.8% 5.3% 73.3% 71.4% 48.8% Malay Basin 2.0% 9.5% 0.0% 31.6% 0.0% 14.3% 8.0% All areas 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Author: Huong Luong Lien December 1998 fS 1 eg •a -o "O S 0 cx o u g § a>

Figure 6.2 - Drilling statistics by area paiiup

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Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.12

Table 6.3 - Historical drilling statistics

Drilling performance (number of wildcats drilled) Oil discoveries Gas discoveries Time Dry Shows Non-com Com Non-com Com Total holes mercial mercial mercial mercial 1970- 1974 0 1 1 0 0 0 2 1975 - 1979 4 4 1 1 1 0 11 1980- 1984 4 1 0 0 2 0 7 1985 - 1989 1 0 4 2 0 0 7 1990- 1994 24 11 3 3 7 3 51 1995 - 1997 17 4 4 13 5 4 47 All time 50 21 13 19 15 7 125

Drilling success ratios (percentage of total wildcats) Oil discoveries Gas discoveries Time Dry Shows Non-com Com Non-com Com Total holes mercial mercial mercial mercial 1970- 1974 0.0% 50.0% 50.0% 0.0% 0.0% 0.0% 100.0% 1975 - 1979 36.4% 36.4% 9.1% 9.1% 9.1% 0.0% 100.0% 1980- 1984 57.1% 14.3% 0.0% 0.0% 28.6% 0.0% 100.0% 1985 - 1989 14.3% 0.0% 57.1% 28.6% 0.0% 0.0% 100.0% 1990- 1994 47.1% 21.6% 5.9% 5.9% 13.7% 5.9% 100.0% 1995 - 1997 36.2% 8.5% 8.5% 27.7% 10.6% 8.5% 100.0% All time 40.0% 16.8% 10.4% 15.2% 12.0% 5.6% 100.0%

Percentages of all time totals (percentage of total wildcats for each category) Oil discoveries Gas discoveries Time Dry Shows Non-com Com Non-com Com Total holes mercial mercial mercial mercial 1970- 1974 0.0% 4.8% 7.7% 0.0% 0.0% 0.0% 1.6% 1975 - 1979 8.0% 19.0% 7.7% 5.3% 6.7% 0.0% 8.8% 1980- 1984 8.0% 4.8% 0.0% 0.0% 13.3% 0.0% 5.6% 1985 - 1989 2.0% 0.0% 30.8% 10.5% 0.0% 0.0% 5.6% 1990- 1994 48.0% 52.4% 23.1% 15.8% 46.7% 42.9% 40.8% 1995 - 1997 34.0% 19.0% 30.8% 68.4% 33.3% 57.1% 37.6% All time 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Note: Well completion dates are used for period grouping

Author: Huong Luong Lien December 1998 z SO m £ i The economics of petroleum exploration and development in Viet GO D

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.14

6.3 Exploration history

Table 6.4 gives details of the oil and gas discoveries made in Viet Nam. The Tien Hai C gas field has been included in Table 6.4.

Onshore

Oil and gas exploration in Viet Nam started early 1960s with extensive geological and geophysical surveys onshore in the Ha Noi Trough. The first deep wildcat well, drilled to a depth of approximately 3,000 metres, was spudded in 1969 (Ho Sy Thoang, 1995). 42 exploration wells have been drilled in the Ha Noi Trough. This exploration drilling program resulted in the discovery of Tien Hai C gas field in 1975. Tien Hai C was later brought on stream in 1981.

On 22nd July 1993, an Australian oil company Anzoil was awarded a production sharing contract for the exploration and production of hydrocarbon covering 4,750 kilometre square onshore and offshore Ha Noi Trough. Anzoil has been actively involved in conduction of geological surveys, seismic and drilling operations. The company has drilled 3 wildcat and 2 outpost wells and made 2 significant discoveries. These were Song Tra Ly 1 (gas) & Song Thai Binh 1 (oil).

In the onshore Cuu Long Trough, a limited amount of mapping and aeromagnetic data was accumulated prior to 1975 by United States government agencies. After 1975, this area had been covered by a regional geophysical surveys (seismic, magnetic, gravity). Three wildcat wells named Cuu Long 1, Hau Giang 1 and Long Xuyen 1 were drilled by PetroVietnam during 1980. However, all the three wells were reported to be dry holes.

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~~3 £ $ I 3 | ? j K | S: ior: 5 R | * a The economics of petroleum exploration and development in Viet Nam Page 6.19~~

~~Offshore~~

The first seismic survey in Nam Con Son Basin was acquired in 1968 by the British ministry of overseas development Alpive. This survey indicated the presence of a sedimentary sequence at least 2 to 3 kilometres thick. However, offshore exploration drilling carried out by international oil companies only commenced in 1974 under the former South Viet Nam government. Pre-1975 exploration activity was conducted before the end of the ~~Vietnam War and post-1975 activity has been under the current government of Viet Nam.~~

~~During the 1974-1975 period, Mobil and Pecten drilled 5 wildcat wells:~~

~~• Bach Ho 1 in Cuu Long basin • Hong 1, Dua 1, Mia 1 and Dai Hung (MOB) 1 in Nam Con Son basin.~~

Dua 1 and Bach Ho 1 encountered significant oil accumulations in Lower Miocene and Oligocene clastic formations. An appraisal well (Dua 2) was also drilled by Pecten, but did not get any encouraging result. Bach Ho 1 drilled by Mobil was the first commercial oil discovery.

After 1975, Agip, Deminex and Bow Valley were awarded production sharing contracts for offshore blocks 04 & 12, 15 and 28 & 29 respectively. From 1978 to 1980, these companies acquired seismic surveys and drilled 12 exploration wells. Two oil discoveries (15-A 1 and 04-A 1) and two gas discoveries (12-B 1 and 12-C 1) were made. However, they were considered not commercial by Agip and Deminex. All the three production sharing contracts therefore were terminated in 1980 as contractors chose not to enter into the appraisal phase.

Since its establishment in 1981, Vietsovpetro joint venture had completed 60,121 kilometres of 2D and 3D seismic surveys in Cuu Long, Nam Con Son as well as Song Hong basins. In Cuu Long and Nam Con Son basin, 27 exploration wells were drilled on 7 structures with a total 104,894 metres of drilling. So far, 196 exploration and development wells have been drilled by Vietsovpetro. Appraisal and production wells in the Bach Ho field found commercial oil in the fractured weathered Pre-Cenozoic

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.20 basement. This is an important discovery which introduced a new target for exploration in Viet Nam’s south basins. The Bach Ho field was brought on stream in 1986. (Ngo Thuong San, 1996).

There was no western company activity in Viet Nam between 1981 and 1989. However, exploration drilling by Vietsovpetro during this period resulted in two oil discoveries (Rong, Dai Hung) and four insignificant oil accumulations: Tam Dao, Ba Den, Ba Vi and Soi. In 1985, Vietsovpetro discovered oil at Rong field, about 10 kilometres south-west of Bach Ho. In 1988, the Dai Hung field in Nam Con Son Basin was discovered by Vietsovpetro, but later developed by BHP consortium.

After the Foreign Investment Law was promulgated at the end of 1987, the government opened up offshore areas for petroleum exploration to foreign companies. Exploration activity increased following a relinquishment by Vietsovpetro of acreage in the broad area surrounding Dai Hung field in Nam Con Son Basin as well as other areas in Cuu Long Basin.

Since 1988, more than 30 production sharing contracts have been signed with foreign oil companies. Contractors have conducted hundreds of thousands kilometres of 2D and several thousands square kilometres of 3D seismic surveys. Although offshore exploration drilling began in 1974, 78.4% of all wildcats were drilled after 1989. The oil and gas discoveries made after 1989 are included in Table 6.4.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.21~~

~~6.4 Reserves~~

Figure 6.4 presents reserves distributions for all accumulations, including commercial and non-commercial discoveries. Table 6.4 gives details of the reserves estimated for each discovery. Table 6.5 presents a summary of estimates of reserves in existing oil and/or gas discoveries which are already commercial or could be commercial in the future. Reserve figures in the tables are original reserves. They are either proven reserves (producing fields) or proven plus probable reserves (developing fields) or proven plus probable plus possible reserves (appraising discoveries) - see Table 6.4 for the status of existing discoveries.

Table 6.5 - Commercial oil and gas reserves Oil discoveries Gas discoveries Discovery name Reserves Discovery name Reserves (million (billion cubic feet) barrels) Bach Ho 1 500.00 Bach Ho 1 (associated gas) 682.28 Diamond 1 13.20 Emerald 1 45.65 Emerald 1 (associated gas) 235.98 Pearl 1 31.80 Phuong Dong 1 22.40 Phuong Dong 1 (assoc, gas) 38.85 Rang Dong 1 220.00 Rang Dong 1 (assoc, gas) 236.96 Rong 1 85.00 Rong 1 (associated gas) 42.00 Rong 14 21.64 Ruby 1 150.19 Ruby 1 (associated gas) 176.57 Topaz 1 4.49 Vung Dong 73.30 Vung Dong 1 (assoc, gas) 52.97 Song Thai Binh 1 17.00 Tien Hai C 53.00 Cai Nuoc 1 _ Song Tra Ly 1 360.00 Dam Doi 1 30.00 Kim Long 1 _ Nam Can 1 13.00 Lan Do 1 425.00 Ngoc Hien 1 _ Lan Tay 1 1,625.00 Phu Tan 1 9.00 Phu Tan 1 (associated gas) 72.00 U Minh 1 55.00 Moc Tinh 1 600.00 Dai Hung 1 100.00 Dai Hung 1 (associated gas) 400.00 Hai Thach 1 (condensate) 150.00 Hai Thach 1 556.00 Rong Doi 1 (condensate) 21.00 Rong Doi 1 809.00 Total 1,562.67 Total 6,365.61

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.22~~

Total original recoverable oil/condensate reserves are estimated to be approximately 1.56 billion barrels, of which 500 million barrels in Bach Ho, 107 million barrels in Rong, 100 million barrels in Dai Hung, 220 million barrels in Rang Dong, 150 million barrels in Ruby and 150 million barrels of condensate from Hai Thach.

Total original recoverable gas/associated gas reserves are estimated to be approximately 6,366 billion cubic feet. The largest individual gas reserves is 1,625 billion cubic feet in Lan Tay. Lan Do in the same block as Lan Tay has an estimated reserves of 425 billion cubic feet. Other significant gas discoveries in Nam Con Son Basin are Hai Thach of 556 billion cubic feet, Moc Tinh of 600 billion cubic feet and Rong Doi of 809 billion cubic feet. Tien Hai, the producing gas field, has reserves of approximately 53 billion cubic feet. Also in Ha Noi Trough, Anzoil has recently made a gas discovery, Song Tra Ly of 360 billion cubic feet.

A significant portion of total gas reserves is contributed by associated and non-associated gas from oil fields. Bach Ho has 700 billion cubic feet, Dai Hung 400 billion cubic feet and Rong 42 billion cubic feet of gas reserves. Other future oil developments like Rang Dong and Ruby also contain considerable volumes of gas.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.23~~

~~Figure 6.4 - Reserves distribution~~

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.24~~

~~6.5 Geophysical surveys~~

Table 6.6 lists the geophysical surveys in Viet Nam. The data for onshore surveys is incomplete as those carried out by PetroVietnam are not available. A total of 314,221 kilometres of 2D seismic surveys and 7,007 square kilometres of 3D seismic surveys have been acquired in Viet Nam. Most of the 2D seismic acquisitions are for blocks in the southern Viet Nam continental shelf. Significantly, all the 3D seismic surveys have been conducted in the Cuu Long and Nam Con Son basins where most of the country’s hydrocarbon discoveries were made. Some magnetic and gravity surveys are also listed in Table 6.6. It is reported that PetroVietnam carried out a number of seismic and gravity surveys onshore the Cuu Long Trough during the late 1970s. The company has also conducted some regional research and non-exclusive geophysical surveys on the Viet Nam continental shelf as well as a joint study to correlate South East Asia’s sedimentary basins.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam : ■i 3~~

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£££££££££££ o o,7JO,jo i C u uL o n gB a s in D c m i n c x B l o c k15 S h e l f S h e l f 2 3 - 2J 8 u - n J -u 7 l- 8 72 8D L o n g v11 a GECO A S. os 3 ,2 2 0 .0 0 C u uL o n gB a s in E n t e r pr O i sile Exploration L td B l o c k17 S h e l f 1 3J - u l- 9 4 21 - J u l- 92 4 D Z e p h y r CGG ( C ie G e n e r aGeophysique) t e os 4 2 8 .0 0 312,000 C u uL o n gB a s in E n t e r pr O i sile Exploration L td B l o c k17 S h e l f 2 D S h e l f 1 7 - J u l- 8 91 7 -O c t- 8 9 O d y s s e y CGG ( C i eG e n e r aGeophysique) t e on 2 ,4 3 3 .6 0 1.900.000 C u uL o n gB a s in E n t e r pr O i s ile Exploration L td B l o c k17 ’ S h e l f 1 5 -M a y - 9 5 J u n - 93 5 D R e f l e c t i o n O r i e nE t x p l o r e r P e t r o l e uGeo-Services m (PGS) 200 C u uL o n gB a s in E n t e r pr O i s ile Exploration L td B l o c k17 VT S h e l f 3 0S - e p - 9 5 1 5 -N o v - 93 5D R e f l e c t i o n O r i e nE t x p l o r e r P e t r o l e uGeo-Services m (PGS) o 154 C u uL o n gB a s in Japan-Vietnam P e t r o l e uC m o B lo c k1 5 -2 RD 7 - F e b - 9 3 5 - A p r - 93 3 D R e f l e c t i o n G c c R o e s o l u t i o n GECO A S. c 250 C u uL o n gB a s in Japan-Victnam P e tr o le uC m o B l o c k1 5 -2 5 - A p r - 9 3 7- F e b - 9 32 D G c c R o e s o l u t i o n GECO A S.

~~o 4 2 9 .0 0 C u uL o n gB a s in Japan-Victnam P e t r o l e uC m o 2 6 - J u l- 9 5~~

~~B lo c k1 5 -2 VD S h e l f 6 - J u n - 9 5 3 D R e f le c tio n W e s t e L r n e g en d W e s t e Geophysical r n o 192 C u uL o n gB a s in Japan-Victnam P e t r o l e uC m o~~

B lo c k1 5 -2 PD S h e l f 2 7 - 1 3J - u l- 9 5 3 D AR ue fg le -9 c 5 tio n W e s t e L r n e g en d W e s t e Geophysical r n S h e l f o 161 C u uL o n gB a s in Petronas-Carigali V ie tn a m B l o c 0 k 1 , 0 2 S h e l f 5 - O c t- 9 1 1 7 -J a n - 92 2 D Z e p h y r CGG ( C i eG e n e r aGeophysique) t e o 6 .9 6 0 .7 0 3.457.000 C u uL o n gB a s in Petronas-Carigali V ie tn a m B lo c 0 k 1 , 0 2 2 D S h e l f 2 4 A - p r -9 3 4 - J u n - 9 3 R o s C s h o u e s t Simon-Horizon L td . 3 .1 0 6 .5 0 £ S h e l f o' 1.941.000 C u uL o n gB a s in Petronas-Carigali V ie tn a m B lo c k 0 1 , 0R 2 u b y 1 0 - M a r - 9 59 - A p r - 93 5 D R e f le c tio n G c c E o m e r a l d GECO - P r a k la £ o* 2 .2 4 6 .5 0 262 C u uL o n gB a s in Petronas-Carigali V ie tn a m B lo c 0 k 1 , 0 2 1 0A - p r -9 5 7 - J u n - 92 5 D R o s S s e a l D ig ic oGeophysical n L td ? o C u uL o n gB a s in Petronas-Carigali V ie tn a m B l o c 0 k 1 , 0 2 ’ 2 D

S h e l f 1 0 - S c p - 9 51 4 - S c p - 9 5 R o s S s e a l D ig ic oGeophysical n L td S h e l f 8 o 2 D 4 2 9 .0 0 C u uL o n gB a s in PclroVictnam E & P C o CL M a r - 7 6 J a n - 72 7 D G c m c a u x CGG ( C i eG e n e r aGeophysique) l e £! os C u uL o n gB a s in PctroVietnam E & P C o CL S h e l f 2 8 - JM a n a - y 7 - 8 7 8 L o n g vII a GECO A S. ov 1 2 ,0 0 0 .0 0 C u uL o n gB a s in PclroVictnam E & P C o CL D e e p W a t e r F e b - 9 0 M a r - 92 0 D G c c oK a p p a GECO A S. CL E? oo 6 ,0 0 0 .0 0 C u uL o n gB a s in P c t t y - R Geophysical a y S h e l f J a n - 7 0 A u g - 7Reconnaissance 0 R o b r aI y P c t t y - R Geophysical a y 5 .1 3 7 .7 0 S h e l f on C u uL o n gB a s in Victsovpetro B l o c 0 k 9 S h e l f J u l- 9 1 A u g - 93 1 D R e f l e c t i o n G e c D o e lta GECO A S. £ on 60 C u uL o n gB a s in Victsovpetro B lo c 0 k 9 -1 BH

S h e l f 8- AJ up n r -9 23 D R e f le c tio n G e c K o a p p a GECO A S. ? Victsovpetro o\ 120 C u uL o n gB a s in B lo c 0 k 9 J a n - 9 3 M a r - 93 D R e f le c tio n S to r m y CGG ( C ie G e n e r aGeophvsiaue) l e 140 8 E H a n oT i r o u g h A n z o A il s ia P ly L td MVHN O n s h o r e 106 4 7 1- O c t- 9 42 7 - M a r -2 9 D 5 CGG ( C i eG e n e r aGeophysique) l e 7 0 3 .0 0

8 MVHN E H a n oT i r o u g h A n z o A il s ia P ly L td S h a llo W w a te r 1 0 6 .4 5 2 5M - a y - 9 52 2 - A u g -2 9 D 5 C a r i b b eH a no r iz o n 2 miiil illiifl H o r i z oExploration n L td B lo c k mini 8 0 1 2 0

2 D P in aExploration M in hH a iB V 4 6 ,5 0 ,5 1 1 0 3 .5 0 8 (X) 2 3 - O c t - 9 02 2 -J a n - 9 1 2 G c c M o y GECO A S. 1 0 ,0 7 1 .0 0 6.076.000 1 0 3 .5 0 2 D F in aExploration M in hH a iB V B l o c 4 k 6 ,5 0 ,51 8 2 5 1 0 - M a r - 9 21 0A - p r -9 2 3.600.000 2 2 D G c c K o a p p a GECO A S. 3 .9 8 9 .0 0 F in aExploration M in hH a iB V B l o c 4 k 6 ,5 0 , 5 1 1 0 3 .2 5 8 0 8 2 0 - N o v - 91 2 0 - D c c - 9 2 2 G e c D o e lla GECO A S 6 4 8 .0 0 P c t t y - R Geophysical a y B lo c 4 k 5 1 0 4 .5 0 7 .7 5 A p r -6 9 M a y - 6 9 2 ReconnaissanceR o b r aI y P c t t y - R Geophysical a y 3 ,5 0 1 .2 0 TFC Exploration In c M in hH a i 0 6 .9 8 8 .2 0 2 8 - M a r - 91 6 7A - p r -9 2 6 D 2 R o s sS e a l D ig ic oGeophysical n L td 1 ,3 5 3 .8 9 TFC Exploration In c M in hH a i 2 D 1 3A - u g - 9 62 8 - S e p - 9 6 W e s t e L r n e g e n d 2 D W e s t e Geophysical r n 4 .7 3 9 .0 0 U n o c aV l ie tn a m B lo c B k 1 0 3 .0 0 8 .5 5 1 4J - a n - 9 7 2 0 - F c b - 9 7 R o s sS e a l D i g i c oGeophysical n L td 4 ,4 6 3 .3 0

~~Author: Huong Luong Lien December 199: The economics of petroleum exploration and development in Viet Nam Page 6.26~~

T a b le 6.6 - Geophysical su rv e y in s V iet N am______11 ^ u u. O S l ! I ! I I I I I ! I ! ! I I I ! I I ! I ! I I ! l ! I ! I ! I I I I I I I I ! I ! l ! l a Cl Q l C l Q l C l O l C l Q l C l Q l C l Q l C l D f C l Q l C l Q l C l Q l C l Q l C l Q l C l D l C l Q l C l Q l a l a l C l Q l a l Q l C l Q l C s Q l C l Q l C s D l C D C D C Q C Q C Q C Q C D C Q C Q C Q C D C Q C Q C Q C D Z C Q C Q C Q Z C Q

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~~Author: Huong Luong Lien December 1998 ic economics of petroleum exploration and development in Viet Nam Page 6.27 1! u a 8 s: i I - 3~~

~~L in e a g e(In -~~

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m ' S o n gH o n gB a s in BHP P e t r o l e u(Victnam m )PtyL td B lo c k1 2 0 ,121 S h e l f 109.501 1 4 .5 0 1 7 - J u i- i y 2 8 - S e p - 92 1D Z e p h y r CGG ( C i cG c n c r aGcophysique) l c 7 .1 6 2 .0 0 S o n gH o n gB a s in BP Exploration V i e t na L m td B lo c k1 1 7 ,1 1 8 ,1 1 9 D e e pW a t e r 1 0 9 .5 0 1 5 .5 0 J u n - 8 9 3 - A u g - 82 9D G e c o K a p p a GECO A S. 6 .2 0 0 .0 0 S o n gH o n gB a s in BP Exploration V i e t na L m td 1 0 9 .5 0 2 D B lo c k1 1 7 ,1 1 8 ,1 1 9 D e e pW a t e r 1 5 .6 7 2 5 - A u g - 9 21 4 - O c t- 9 2 S to r m y CGG ( C i cG c n c r aGcophysique) l c 4 .0 3 5 .0 0 S o n gH o n gB a s in I d e m its H u a i p h o O n gil E x p l B lo c k1 0 2 S h e l f 1 0 6 .6 7 2 0 .0 8 1 5 -F c b - 9 32 3 - M a r -2 9 D 3 G e c oD e lta GECO A S. 2 .2 7 0 .6 0 S o n gH o n gB a s in S h e l f International P e tr V ie tn a L m td B l o c 115 k 1 0 9 .0 0 1 6 .7 5 l - J u l - 9 03 0 - J u l -2 9 D0 S h e l f G e c oK a p p a GECO A S. 3 ,5 0 2 .3 5 S o n gH o n gB a s in OMV ( V i e t n a Exploration m ) G m b H B lo c k1 0 4 2 D S h e l f 1 0 6 .7 5 1 8 .8 3 2 8 - 1A 3 - u N g o - 9v 3- 9 3 Z e p h y r 2 D CGG ( C i cG e n e r aGcophysique) l c 5 ,9 7 36 0 1 ,2 0 0 ,0 0 0 S o n gH o n gB a s in OMV ( V i e t n a Exploration m ) G m b H S h e l f B l o c 1 k 0 4 2 9 - M2- a y - 9 4 HRJ u n - 9 4 S h e l f R.S S. C h a l l e n g e rG a r d l iS n ue r v e yL s td 1 3 2 0 0 S o n gH o n gB a s in OMV ( V i e t n a Exploration m ) G m b H B lo c k1 0 4 1 0 6 .5 0 1 8 .9 2 5- SO e c p t- - 9 42 D HR R.S.S. C h a l l e n g e rG a r d l iS n uc r v e yL s td 6 6 8 .4 5 S o n gH o n gB a s in PctroVictnam E & P C o 1 0 7 .0 0 VBB ( B in hM in h ) 1 9 .0 0 1 9 7 8 1 9 7 92 D 1 0 7 .0 0 S o v i eC t r e w 2 2 0 .0 0 S o n gH o n gB a s in 1 9 .0 0 1 9 8 7 PctroVictnam E & P C o B a c hL o n gV i- 8 7 S h e l f 1 9 8 72 D S o v i eC t r e w 1 .0 7 8 .0 0 S o n gH o n gB a s in PctroVictnam E & P C o VBB ( V P G T - 9 3 ) S h e l f 1 0 8 .3 3 2 D 2 0 .0 0 1 9A - p r - 9 3 M a y - 9 3 G e c D o e lia GECO A S. S h e l f 2 D 3 .1 7 3 .4 0 S o n gH o n gB a s in PctroVictnam E & P C o B B -9 5 1 9 9 5 1 9 9 6 2 D DMNG 4 .6 0 0 .0 0 S o n gH o n gB a s in PctroVictnam D e e p E & P C o VBB W a t e r 1 9 8 4 1 9 8 62 D S o v i eC t r e w 4 .0 9 1 .0 0 S o n gH o n gB a s in S c e p tr e 2 D R e s o u r cV e ies tn a L m td B l o c 111 k S h e l f 1 0 7 .6 7 1 7 .7 5 2 4 - M a r - 9 !1 l - J u n - 9 1 4 .6 2 4 .0 0 2 D 2 ^ p h y r CGG ( C i eG e n e r aGcophysique) l e S o n gH o n gB a s in S h e llE& P V ie tn a B.V. m B lo c k1 1 2 ,1 1 4 ,1 1 6 S h e l f 1 0 8 .0 0 1 7 .0 0 2 6 - J a n - 8 9 3- 2 D J u n - 8 9 G e c oK a p p a GECO A S. 1 2 ,1 9 7 .0 7 S h e l f 2 D S o n gH o n gB a s in S h e llE & P V ie tn a B.V. m B l o c 1 k 1 2 ,1 1 4 ,1 1 6 1 0 7 .3 3 1 6 .2 5 S e p91 - S e p - 9 1 S h e l f G e c oK a p p a GECO A S. 3 7 0 .0 0 S o n gH o n gB a s in T o ta (O l & G) In ti V ie tn a m B lo c k1 0 3 ,1 0 6 ,1 0 7 S h e l f 1 0 7 .5 0 2 0 3 3 9 -A p r - 8 92 8 - M a y - 8 9 O d y s s e y CGG ( C i eG e n e r aGcophysique) l c 4 .0 8 7 .0 0 S o n gH o n gB a s in 1 0 7 .0 0 T o t a(O l & G) In ti V ie tn a m B lo c k1 0 3 ,1 0 6 .1 0 7 2 0 .3 3 6- 2 0F - Ac b p - r 9 - 0 9 0 O d y s s e y CGG ( C i eG e .i e r aGeophysique) l e 6 ,0 0 0 .0 0 S o n gH o n gB a s in Vietsovpctro VBB S h e l f 1 9 8 3 1 9 8 32 D I s k a ic l LD DVLTBD N g a 9 .3 9 2 .4 0 Victsovpctro S o n gH o n gB a s in VBB S h e l f 1 9 8 4 1 9 8 42 D P o is k Vietsovpctro VBB LD DVLTBD N g a 2 .0 4 7 .6 0 S o n gH o n gB a s in S h e l f 1 9 8 4 1 9 8 4 2 D BS 14 HD LD DVLTBD N g a 4 .0 4 6 8 0 O' O' O S h e l f ON

~~n 2 D N o r w e g iaP e n tr o le uExploration m Consultants S E A S - 9 5 ’~~

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~~3 1 4 ,2 2 0 .9 7~~

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A p r - 6 9 M a y - 6 9 R o b r aI y/ S e a P e t t y - R Geophysical a y N a m L o nS o nB a s in BP Exploration V ie tn a L m td B lo c 0 k 5 - 2 D e e pW a t e r 1 0 9 .0 8 M a r -9 3 'S O S O O O M a r - 9 3 S e aC h a l l e n g e r CGG ( C i eG e n e r aGeophysique) l e N a m C o nS o nB a s in PctroVictnam E & P C o NCS S h e l f 1 0 7 .5 0 1 9 8 1 1 9 8 1 S e a fill 11 Jill S h e l f BHP P e tr o le u(Victnam m )PtyL td B lo c k1 2 0 ,121 1 0 9 .5 0 S h e l f 1 4 .5 0 1 7 -J u l-9 1 2 8 - S c p - 9 1 Z e p h y r GECO A S. BP Exploration V ie tn a L m td B lo c 1 k 1 7 ,1 1 8 ,1 1 9 S h e l f 1 0 9 .3 3 1 5 .7 5 1 9 -A u g - 9 4 1- S e p - 9A 4 ir m a g n e tic A ir If S a n d eG r e o p h y sL i ctd s . 9 .6 3 5 .0 0 2 1 6(XX) , International P e tr V ie tn a L m td B lo c k115 1 0 9 .0 0 1 6 .7 5 l - J u l - 9 0 3 0 - J u l - 9 0 G e c oK a p p a GECO A S. 2 .1 8 1 .0 0

~~Victsovpctro VBB S h e l f 0 7 .0 0 1 9 .0 0 1981 1 9 8 2 S e a © 1 6 ,8 6 6 .0 0~~

~~Gravity surveys~~

Cuu Long Basin P c tty - R Geophysical a y CL S h e l f 1 0 7 0 0 8 .2 5 J a n - 7 0 A u g - 7Reconnaissance 0 R o b r aI y/ S e a P e t t y - R Geophysical a y S h e l f Malay Basin P c tty - R Geophysical a y B lo c 4 k 5 1 0 4 .5 0 7 .7 5 Reconnaissance S h e l f A p r - 6 9 M a y - 6 9 R o b r aI y/ S e a P e t t y - R Geophysical a y Nam Con Son Basin 1 0 7 .5 0 Victsovpctro NCS 7 .5 0 1981 1981 1 0 9 .5 0 S e a Song Hong Basin BHP P e tr o le u(Victnam m )PtyL td B l o c 1 k 2 0 ,121 S h e l f 1 4 .5 0 1 7 -J u l-9 1 2 8 - S c p - 9 1 Z e p h y r GECO A S. 1 £ 3 9 5 o

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.28~~

~~6.6 Malaysia - Viet Nam Commercial Arrangement Area~~

In 1989, Malaysia awarded its PM-3 Block concession to International Petroleum Corporation (IPC). A production sharing contract (PSC) was also signed between Malaysia and IPC. Following seismic acquisition, IPC carried out a successful exploration drilling program. However, operations were suspended because the PM-3 Block is situated in the overlapping area between Viet Nam and Malaysia. PM-3 was claimed by Viet Nam as part of its Block 46. In 1992, the two governments signed a memorandum of understanding (MOU) declaring the PM-3 Block a Commercial Arrangement Area (CAA) between Malaysia and Viet Nam. According to this MOU, IPC’s original PSC is maintained. The partners in the concession, after the MOU, are IPC (Operator) 26.44%, Petronas Carigali 46.06%, Sands Petroleum 15% and PetroVietnam Exploration and Production 12.5%.

Since 1991, eleven wells (out of which six are exploration wells) have been drilled in the PM-3 Block. The results are shown in Table 6.7. All wells drilled in PM-3 are successful, giving contractors a 100% geological success rate. So far, four discoveries have been made. Three are oil Bunga Kekwa, Bunga Raya, Bunga Orkid and one is gas named Bunga Pakma. Proved and proved plus probable reserves estimated for the four fields are presented in Table 6.8. IPC group commenced its first oil production from Bunga Kekwa oil field in July 1997. Bunga Kekwa’s medium, sweet, waxy crude oil is of 36.5° API gravity.

PM-3 Block is out on the margin of the North Malay Basin and is geologically complex. This basin is comprised of stacked channel sands containing oil or gas. More than 100 separate reservoirs have been identified. The shallower sands in PM-3 Block contain

~~good, low CO2 gas, but the level of CO2 increases with depth, before going into oil~~

~~bearing sands that have high CO2 associated gas (Malcolm Maclean et al, 1997).~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 6.29~~

~~Table 6.7 - Results of PM-3 well tests~~

~~Combined test flow rates Well Oil Condensate Gas~~

~~(barrels of oil per day) (barrels per day) (million cubic feet day) Bunga Kekwa - 1 8,271 1,941 179.3~~

~~Bunga Kekwa - A1 14,700 _ —~~

~~Bunga Kekwa - A2ST2 1,546 — —~~

~~Bunga Kekwa - A3 3,761 — —~~

~~Bunga Kekwa - A4 14,462 — _ Bunga Raya - 1 6,345 87 40.0~~

~~Bunga Raya - 2 11,528 — 100.1 Bunga Pakma - 1 300 770 64.9 Bunga Orkid - 1 5,150 330 75.5 East Bunga Orkid - 1 3,776 1,459 94.3~~

~~Bunga Seroja - 1 - 1,625 64.3~~

~~Table 6.8 - PM-3 original recoverable reserves~~

~~Kekwa Raya Pakma - Orkid Total~~

~~Raw gas (billion cubic feet) 780 388 803 1,971 Net gas (billion cubic feet) 566 298 489 1,353 Crude oil (million barrels) 57 26 6.9 89.9 Condensate (million barrels) 6.2 4 9.3 19.5~~

~~Source: I PC, A new face on the block, Sponsored Statement, Petroleum Economist, October 1997.~~

~~Author: Huong Luong Lien December 1998 Chapter 7~~

~~Existing and Future Field Developments The economics of petroleum exploration and development in Viet Nam Page 7.1~~

The following describes the detailed design of existing and future oil and gas field developments offshore Viet Nam. The data used in this section was obtained by interviewing industry people in Viet Nam, from Petroconsultants Australasia and various publications.

~~7.1 General field characteristics~~

Viet Nam oil production is currently from Bach Ho, Rong, Dai Hung and Bunga Kekwa. All of these oil fields are located in the South China Sea, offshore south-east of Viet Nam. Bach Ho and Rong in Cuu Long Basin are being operated by VietsoPetro, a joint venture between Viet Nam and Russia. Dai Hung in Nam Con Son Basin is being operated by Petronas. The recently discovered Bunga Kekwa oil field is located in the overlapping area between Viet Nam and Malaysia. Petroleum operations here are conducted under the commercial agreement signed by the two governments.

~~Table 7.1 - Distribution of oil production from 1994 to 1997 (barrels of oil per day)~~

~~Oil producing fields 1994 1995 1996 1997 Bach Ho 130,000 140,000 160,000 170,000~~

~~Rong _ 15,000 10,000 10,000 Dai Hung 25,000 20,000 11,000 12,000 Bunga Kekwa 16,000 - - - Total 155,000 175,000 181,000 208,000~~

Productive reservoirs in existing oil fields offshore Vietnam are from Oligocene/Miocene sandstones and carbonates as well as pre-Tertiary fractured basement (Petroconsultants Australasia, 1995). The average reservoir depth is approximately 3,500 metres for offshore discoveries. On average, individual well peak production rates are approximately 4,000 barrels of oil per day and 30 million cubic feet of gas per day. Peak field production is estimated to be 20% and 10% of reserves per year for offshore and onshore fields respectively.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.2~~

~~7.2 General field development styles~~

The Bach Ho and Rong oil fields have been developed using fixed production platforms and floating storage tankers. The Dai Hung oil field has been developed using semi- submersible production platform, offshore storage and subsea well completions. In contrast, recent field developments like Bunga Kekwa, Rang Dong and Ruby use floating production, storage and offloading (FPSO) vessel for their first phase of development.

The phased development of oil and gas fields is particularly appropriate for fields with complicated geology like those found in Viet Nam. This is not only because a phased development provides oil companies with early cash flow from the project, but also enables them to build up production history and helps reduce reservoir uncertainties. The operational experience gained in the first phase is incorporated in the planning of next development phases.

There has been no commercial oil production onshore Viet Nam. However, there is gas production. Onshore northern Viet Nam, the Tien Hai field (which was brought on stream in 1981) is being produced at a rate of 11 million cubic feet of gas per day. Tien Hai gas output is consumed by a small power station and some industrial customers nearby.

Offshore southern Viet Nam, associated gas produced from the Bach Ho oil field is currently piped onshore to the Ba Ria power plant and the Dinh Co gas processing plant. The field produces at a rate of about 110 million cubic feet per day.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.3~~

~~7.3 The Bach Ho offshore oil field~~

The Bach Ho new field wildcat in Cuu Long Basin was originally drilled and completed by Mobil in 1974 as Viet Nam’s first oil discovery. After re-unification of Viet Nam in 1975, the Bach Ho oil field has been developed and operated by a Vietnam-Russia joint venture, Vietsovpetro. The joint venture was first established in 1981 and began production from Bach Ho oil field in 1986. The joint venture also discovered the small Rong oil field about 33 kilometres south-west of Bach Ho. Rong was brought on stream in 1995. At the Bach Ho and Rong oil fields, Vietsovpetro installed a pipeline network with combined length of 210 kilometres and other production facilities to serve drilling, exploitation, processing and transportation. To the end of June 1998, Vietsovpetro pumped over 57.4 million tonnes (420 million barrels) of crude oil. The combined oil production rate from Bach Ho and Rong is currently at 230,000 barrels per day. Bach Ho also provides about 110 million cubic feet of associated gas per day to local power stations and industries.

In 1974, the Bach Ho-1 wildcat well flowed 2,419 barrels of light, waxy crude oil per day from late Oligocene and early Miocene sandstones draping a basement horst. After 1975, these oil bearing Tertiary sandstones were developed by Vietsovpetro. However, production started in 1986 at a very low rate of 800 barrels per day and built up to only 4,000 barrels a day in 1987. Continued appraisal of the field by Vietsovpetro discovered two deeper oil reservoirs in early Oligocene sandstones and pre-Tertiary granite basement (TetroconsuCtants Australasia, 1995).

In 1988, a well drilled deeper into the basement of Bach Ho was tested at about 9,500 barrels of oil per day. Further appraisal drilling found a highly fractured granite basement which is composed of three large magmatic masses of granite intruding in several phases from late Jurassic to early Cretaceous {Ian Reid, 1997). The Bach Ho structure lies on the central high zone of Cuu Long Basin running in northeast-southwest direction. Good reservoir properties related to the fractured rocks which were formed due to endogen and exogenic processes such as regional uplifting, tectonic activity, hydrothermal and weathering, are concentrated on the relative highs of basement and along the regional faults {Ngo Thuong San et al, 1996). The Bach Ho trap is a simple drape of stacked Tertiary deltaic sediments over a basement high which has been faulted and tilted.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.4~~

Oil production is predominantly from the fractured basement which is comprised of many oil bodies with net pay over 1,000 metres. In areas with prominent fracturing, porosity may range up to 15 percent. A maximum porosity of 25 percent is recorded in one interval. Most importantly, the oil water contact of oil bodies in the basement has not been determined even though some wells were drilled to the depth of 5,000 metres {Hoang Van Quy et al, 1997). Therefore, reserves estimates for the field are difficult to make. The ultimate recoverable reserves of Bach Ho field are estimated to be approximately 500 million barrels of oil. However, oil recoverable reserves might be as high as 700 million barrels, while associated gas reserves might be up to 1 trillion cubic feet.

The Bach Ho oil field lies in a water depth of 50 metres in the Cuu Long Basin, 107 kilometres south-east of Long Hai-Vung Tau. More than 170 development wells have been drilled in the field, including horizontal drilling into the Miocene clastic reservoirs and incline drilling into the basement. However, the current oil output of 220,000 barrels per day is coming from 100 producing wells. On average, the depth to top pay is around 2,700 metres. According to Ngo Thuong San et al (1996), three oil bearing zones in the form of closed blocks with hydrodynamic connections have been classified. The first zone - an artificial gas dome, lies at a depth of 3,450 metres. The second zone is to the depth of 3,900 metres. This is the main oil producing zone. The third zone is below 3,900 metres and is the water injection zone. Vietsovpetro has used a number of enhanced recovery methods such as water injection, moving production intervals according to the water invasion, horizontal drilling, hydrodynamic perforating and gas lift to increase the field’s oil recovery factor. A peak field production of over 270,000 barrels of oil per day is expected to last for 4 to 5 years. Accordingly, peak production rates from individual wells in the field are estimated at around 4,000 barrels/day on average.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.5~~

~~The Bach Ho development scheme is shown in Figure 7.1. So far, Vietsovpetro has installed the following production facilities at Bach Ho oil field :-~~

• eleven fixed production platforms, • eight light-weight wellhead platforms, • a central processing platform (CPP), • a bridge-linked riser platform located alongside the CPP, • a central gas compression platform, • a small gas compression platform, • a medium-pressure gas gathering system, • a water injection platform, • a gas lift system, • two floating storage oil tankers (CALM soft-yoke mooring system), and • over 200 kilometres of submerged pipeline network linking several platforms within the field.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.6~~

~~Figure 7.1 - Bach Ho development scheme~~

~~Storage tanker~~

~~Legend~~

~~Crude pipeline Oil flowline Gas pipeline ...... Gas flowline~~

~~Legend [------1 F~~~l Central Processing platform & Central Compression platform~~

~~Fixed production platform~~

~~To Rong field Satellite wellhead platform Source: Pham Khac Hung et al, Overview of offshore engineering development in Viet Nam, PetroVietnam Review, Vol.2, 1997.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.7~~

The central processing platform can accommodate more than 100 workers, while the accommodation available at a fixed production platform can handle 70 to 80 workers. All of the light-weight wellhead platforms are unmanned. The mono-jacket platforms weigh between 1,100 tonnes to 1,500 tonnes each. The floating storage oil tankers at Bach Ho field have an individual capacity of 1 million barrels. Each of the fixed production platforms costs US$60 to US$ 75 million and was designed to drill up to 16 wells. Crude oil is processed on the fixed production platforms and then piped directly to floating storage oil tankers. Each of the wellhead (or satellite) platforms cost US$12 to US$20 million and accommodate 9 wells. The satellite platforms are only used to gather oil which is then piped to the central processing platform for treatment. After that, processed liquids are pumped from the central processing platform to storage tankers waiting for sale. A water injection platform was also installed to drill water-injection wells for reservoir pressure maintenance. The Bach Ho field has now 30 water-injection wells each should pump about 3,000 cubic metres of water into the lower part of basement reservoir. Vietsovpetro is currently pumping water at a daily rate of 50,000 cubic metres.

As well as the high rate of oil production, the Bach Ho field also produces about 150 million cubic feet per day of associated gas. This was previously flared offshore. Since May 1995, gas has been piped from Bach Ho field to local power plants in Vung Tau. The gas gathering system at Bach Ho consists of a small compression platform for gathering and compressing low pressure gas in the north area, a medium pressure gas gathering system in the south area and pipeline links. It was installed to collect associated gas from a number of remote platforms distributed throughout the field and then bring that gas to the central compression platform, located alongside the existing central processing platform. In addition, a gas lift system within the field was also installed. The gas lift pipelines were set up in parallel with those for gas gathering.

In July 1997, Vietsovpetro completed the installation of the US$123 million central compression platform which has an initial throughput capacity of 205 million cubic feet of gas per day. Ultimately, the platform’s gas throughput capacity will be increased to around 300 million cubic feet per day. The central compression platform has gas conditioning and compression facilities for transportation of gas to shore. However, it was also designed to provide Vietsovpetro with high pressure lift gas to enhance oil recovery at Bach Ho field. In order to increase the field production, associated gas is

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.8~~

pumped down into producing wells to create a secondary gas dome. It is estimated that approximately one third of gas throughput at the central compression platform has been used for gas lift (9Uan Ross Quy, 1995).

~~7 A The Rong offshore oil field~~

Vietsovpetro drilled Rong-1 new field wildcat in 1985 and discovered the Rong field, about 33 kilometres south-west of Bach Ho. Rong’s oil recoverable reserves are estimated to be approximately 100 million barrels. The Rong-9 exploration well encountered an oil accumulation in elite-basalt reservoir which is quite different to the granite of Bach Ho.

The Rong field has been in experimental production since December 1994. In early 1995, Vietsovpetro drilled Rong 14 exploration well into the fractured granite basement and produced some significant oil flow rates. Rong’s current output is approximately 10,000 barrels of oil per day. A peak field production rate of 25,000 barrels per day is predicted.

~~Being operated by Vietsovpetro, the Rong oil field has been developed in much the same style as Bach Ho. The following production facilities have been installed at Rong field:-~~

• a production, drilling and quarters (PDQ) platform, • a wellhead platform, • a floating storage oil tanker of 1 million barrels capacity and, • submerged pipelines within the field and connecting to the Bach Ho oil fields.

~~The oil produced from Rong flows through a 16-inch, 30-kilometre pipeline to the existing facilities at the Bach Ho field and to the Ba Vi on-site storage tanker.~~

The production was interrupted for some times in the first half of 1997 because the production rate was too low to be economic. However, oil production was resumed in 1998. Vietsovpetro may decide to develop the field further. A possible scheme for full field development is shown in Figure 7.2.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.9~~

~~Figure 7.2 - Rong possible full field development plan~~

~~Legend To Bach Ho field Fixed production platform~~

~~Satellite wellhead platform~~

~~Existing production facilities |~~

~~Storage tanker~~

~~Central processing platform~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.10~~

~~7.5 The Dai Hung offshore oil field~~

In 1988, Vietsovpetro discovered the Dai Hung oil field in Block 05-la, 250 kilometres south-east of Vung Tau. The field lies in a water depth of 110 metres in the Nam Con Son Basin. From 1988 to 1990, Vietsovpetro drilled one exploration well and two appraisal wells on the Dai Hung structure. Dai Hung-1 flowed 5,500 barrels of oil per day from an Oligocene sandstones formation and intersected a net oil & gas column of about 200 metres. However, one of the appraisal wells was dry. Early estimates indicated that proven and probable recoverable oil reserves might be as high as 700 million barrels.

In April 1993, a BHP-led consortium signed a production sharing contract with PetroVietnam to develop the Dai Hung field. The consortium was composed of BHP with 43.75 percent, Petronas Carigali with 20 percent, Total and Sumitomo each with 10.625 percent, and PetroVietnam with 15 percent. The Dai Hung field was brought on stream in October 1994, 18 months after award. The field started producing at an initial rate of 25,000 barrels of oil per day. During the period from August 1993 to February 1995, a total of nine wells had been drilled on the structure. The depth to top pay is approximately 2,900 metres. However, the field is seen as a complex structure with multiple oil and gas pay zones in Miocene sandstone and carbonate reservoirs. Appraisal drilling and early production lowered reserves estimates to between 100 and 200 million barrels.

The Dai Hung structure is a series of titled fault blocks running in northeast-southwest direction. The field contains three major intervals of shallow carbonates, inter-bedded sandstones and the underlying granite basement. The shallowest intersections of top pre- Tertiary basement in Dai Hung-2 well was at 2,611 metres. The elastics interval of the reservoir has a thickness of up to 900 metres. However, the structure involved is very complex and fragmented. The stacked reservoir sequence demonstrates considerable variation in depositional environment. Static pressure variations in the field relate to individual hydraulic units which has created substantial overpressure because of their rapid burial history (Perrett Tom et al, 1996).

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.11~~

By September 1995, after nearly a year of production, oil reserves were further downgraded to approximately 100 million barrels. By early 1996, oil production had dropped to a record low rate of 8,000 barrels per day. As a result, BHP pulled out of the Dai Hung project and announced the transfer of its 43.75 percent interest to Petronas Carigali in June 1997. Dai Hung is currently producing about 12,000 barrels a day.

The BHP’s initial plan was to develop Dai Hung in three phases. The first phase of development used subsea wellheads technology to accelerate oil production. An early floating production system shown in Figure 7.3 including a second-hand floating production facility from the North Sea, a storage tanker and subsea well completions were designed and installed during 1993 and 1994 (Petroconsultants Australasia, 1995). The production facility is located on a semi-submersible convertible drilling platform which is used to control wells and process crude oil. The storage tanker is a catenary anchor leg mooring (CALM) buoy type with a capacity of 1.1 million barrels. The field development of Dai Hung now includes five subsea well completions (four producing wells and one water-injection well) which are tied to the semi-submersible platform. Oil gathered from producing wells are processed on the semi-submersible platform and then piped to the storage tanker.

Because the implementation of the second and third phases of development depends largely on appraisal drilling and reservoir performance from the first phase production, it is likely that plans initially made by BHP for the last two phases will be modified. The second phase development would have included additional subsea well completions as well as a gas & water injection platform for reservoir pressure maintenance.

~~Author: Huong Luong Lien December 1998 s of petroleum exploration and development in Viet Nam Page 7.12 Figure 7.3 - Dai Hung developmentscheme~~

~~ce: Pham Khac Hung et al, Overview of offshore engineering development in Viet Nam, PetroVietnam Review, Vol.2, 1997. The economics of petroleum exploration and development in Viet Nam Page 7.13~~

~~7.6 The offshore oil fields at Malaysia - Vietnam Commercial Arrangement Area~~

International Petroleum Corporation (IPC) was first awarded the PM-3 Block offshore Malaysia in 1989 under the Malaysian production sharing contract. Partners in the PM-3 concession were IPC Malaysia as the operator, Petronas Carigali and Sands Petroleum. Since then, IPC has acquired approximately 5,000 kilometres of 2D seismic. In 1991, LPC carried out a successful exploration programme which identified three structures: Bunga Orkid, Bunga Raya and Bunga Pakma in the PM-3 block. However, operations in the block were suspended in 1992 because of overlapping boundary claims made by Viet Nam and Malaysia. Later that year, the two governments signed a memorandum of understanding which defined the overlapping area as the Commercial Arrangement Area (CAA) between Viet Nam and Malaysia. The two governments have also authorised PetroVietnam and Petronas to sign a commercial agreement for joint petroleum development within the area. As a result, the original production sharing contract awarded to IPC in 1989 is maintained, but PetroVietnam Exploration and Production (PVEP) gets a 12.5% working interest as a state participation in the block. In 1994, IPC resumed its operations in PM-3 with further exploration and appraisal work. IPC also acquired about 700 square kilometres of 3D seismic.

According to the IPC Sponsored Statement (published in the Petroleum Economist, October 1997), six new field wildcats and six appraisal wells have been drilled successfully by IPC on the PM-3 block. These are Bunga Orkid-1, Bunga Raya-1, Bunga Pakma-1, Bunga Kekwa-1, East Bunga Orkid-1 and Bunga Seroja-1. All of the exploration wells have encountered accumulations of oil and/or gas. The Bunga Kekwa- A1 appraisal well flowed at a cumulative oil and condensate rate of 14,700 barrels per day from three zones. This is a record well rate for Malay Basin. In the Bunga Kekwa-1 exploration well, gas flowed from four zones at a cumulative rate of 179.3 million cubic feet per day.

So far, three oil fields: Bunga Orkid, Bunga Raya, Bunga Kekwa and one gas field Bunga Pakma have been discovered. Oil and gas in the PM-3 block are in stacked channel sands. The shallower sands contain good quality gas with low percentage of carbon dioxide. Nevertheless, the level of carbon dioxide contamination increases with depth. Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.14

Oil bearing sands actually contain associated gas of up to 50 percent carbon dioxide. Indeed, the PM-3 block has a very complicated geology with many structures overlaying each other. More than 100 separate reservoirs have been identified and featured in the field development plan for PM-3 which was approved in February 1996 (.Malcolm Maclean et al, 1997).

~~Phase I~~

IPC adopted a two-phase development plan for the PM-3 block. Within 18 months of PetroVietnam and Petronas approving the development plan, the company successfully completed the Phase I development of the Bunga Kekwa field. Phase I consisted of four main engineering elements as follows:-

• drilling, • a unmanned wellhead platform on Bunga Kekwa, • a floating production, storage and offloading (FPSO) vessel, and • an interconnecting flowline from the wellhead platform to the FPSO.

First, four production wells were pre-drilled from a single location by using a subsea template to control the well spacing. This allowed the jacket to be installed over the wellheads at a later date. The braced monopod light-weight structure topsides were then installed at Bunga Kekwa by using the Trident 17 jack-up rig. The Bunga Kekwa wellhead platform is especially designed to accommodate six wells. Once the wellhead platform was put in place, the wells were suspended at the mud line for tying back. After that, the suspended wells were successfully completed by running a dual completion with a downhole pressure gauge and drilling a horizontal section on one of the wells. The Armada Perkasa was refitted and modified to operate as Bunga Kekwa’s FPSO which has a capacity of 350,000 barrels. However, it does not have a turret nor an offloading buoy, and so it is spread-moored like a semi-submersible rig with eight anchors and shuttle tankers come to load oil at either the stem or the bow (.Malcolm Maclean et al, 1997).

The Bunga Kekwa field was brought on stream on the 29th of July 1997 at an initial rate of 10,000 barrels of oil per day. A peak field rate of over 18,000 barrels per day is expected to last about a calendar year. After that, production from Bunga Kekwa will

Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.15 start to decline and to be replaced by oil and gas output from the Phase II development. By the end of 1999, the completion of the full development of Bunga Kekwa and Bunga Raya fields will allow oil flowing at a peak rate of 40,000 barrels per day, condensate production at 5,000 barrels per day and natural gas output reaching 250 million cubic feet a day. Next, oil from Bunga Orkid will come on stream in 2002, followed by gas from Bunga Orkid in 2005 and finally gas from Bunga Pakma in 2007.

~~Phase II~~

Phase II development is further broken down into Phase IIA (the full development of Bunga Kekwa and Bunga Raya) and Phase IIB (the full development of Bunga Orkid and Bunga Pakma). The total capital costs of Phase II development is projected to be approximately US$800 million, of which about US$550 million are related to Phase HA. The annual operating costs for the whole project may reach up to US$35 million in 2007. Twenty four new wells will be drilled on Bunga Kekwa and Bunga Raya during Phase IIA, while nine wells will be drilled on Bunga Orkid and Bunga Pakma in Phase IIB (Malcolm Maclean et al, 1997).

~~Phase IIA~~

~~Phase IIA development which is scheduled to start adding further oil and gas production in late 1999, will consist of the following production facilities:-~~

• a manned central processing platform (CPP), • a bridge-linked, minimum facilities wellhead riser platform on Bunga Kekwa, • an unmanned, minimum facilities wellhead platform on Bunga Raya, and • pipelines between CPP and Bunga Raya platform.

At the Bunga Kekwa field, the unmanned light-weight structure already installed in Phase I will be tied back to the wellhead riser platform to be installed in Phase IIA. The central processing platform is designed to be very large and complex. The CPP topsides will weigh about 11,000 tonnes and will be supported by a 4,500-ton conventional eight-leg jacket {Malcolm Maclean et al, 1997). Being an integrated oil and gas facility, the CPP will consist of processing plants for separation, carbon dioxide removal, gas compression and water injection. The facilities used for processing high-C02 gas will cost up to

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.16~~

US$70 million. Furthermore, a booster compression unit will later be installed on the CPP. After processing, oil and condensate will be piped from the CPP to a floating storage and offloading (FSO) vessel with a capacity of 1 million barrels.

In addition, a two-section gas pipeline is planned in order to bring gas ashore to the existing market by the end of 1999. A 158 kilometre pipeline will run from the CPP on Bunga Kekwa to Petronas’ Resak gas field. A second 132 kilometre pipeline will run from Resak to a gas processing plant at Kerteh in Malaysia. Gas will be piped ashore at a rate of 250 million cubic feet per day, under a 10-year sale contract.

~~Phase IIB~~

~~Phase IIB development is designed to have the following additional facilities:-~~

• an unmanned wellhead platform on Bunga Orkid • a satellite gas system at Bunga Orkid • an unmanned wellhead platform on Bunga Pakma • pipeline links from Bunga Orkid and Bunga Pakma platforms to facilities at Bunga Kekwa.

The Bunga Pakma wellhead platform will be linked to the satellite gas system at Bunga Orkid. After that, oil and gas produced from the Bunga Pakma and Bunga Orkid fields will be piped about 32 kilometres to the Bunga Kekwa wellhead riser platform and then to the CPP for processing.

The Bunga Seroja-1 exploration well (located in the west of Bunga Raya field) discovered a potentially large new gas field. Combined flow rates of the two tests carried out at Bunga Seroja-1 were 1,325 barrels per day of 56°API condensate and 64.8 million cubic feet per day of I0W-CO2 gas (less than 1 percent). This recent gas discovery, only 10 kilometres from the CPP, together with the possibility of finding additional oil reserves in Bunga Kekwa and/or Bunga Raya field could move forward the Phase IIB development plan by two or three years (.Malcolm Maclean et al, 1997).

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.17~~

~~7.7 Some future field developments~~

~~7.7.1 Rang Dong offshore oil field~~

The first exploration well on the Rang Dong prospect was drilled in 1994 by Japan Vietnam Petroleum Company (JVPC), a joint venture between Mitsubishi Oil and Japan National Oil. JVPC declared the field commercial in early 1996. The recoverable reserves of Rang Dong have been estimated to be approximately 250 million barrels of oil. Rang Dong contains high quality crude oil with a gravity of 37° API and a sulfur content of 0.05 percent. JVPC started producing oil in mid-1998. The field’s current output of slightly over 30,000 barrels of oil per day will likely increase to 45,000 barrels per day while peak field production rate can be as high as 100,000 barrels per day.

The Rang Dong field is located in Block 15-2, approximately 136 kilometres from Vung Tau and about 90 kilometres from the nearest coast. It lies in a water depth of 60 metres on Cuu Long Basin where seabed conditions are silt and sand. There are two established plays on the Rang Dong field. The top play is the Lower Miocene sandstone which flowed 4,043 barrels of oil per day in the Rang Dong-1 well. This Lower Miocene elastics play is a multi-layered reservoir with different oil water contact levels. The lower and more important play is the fractured granite basement which flowed 10,346 barrels of oil per day in Rang Dong-1. The trap for the elastics play is a drape anticline with an average porosity of 17% and a permeability of 40 milli-darcies. The reservoir for the basement play is a fracture network with porosity up to 3.5% and permeability of 1,144 milli-darcies. Block 15-2 may have another possible play in weathered basement or lower Oligocene elastics.

The Rang Dong oil field development plan was scheduled into two phases. Phase 1 development is the installation of an early production system (EPS) in the north area of the field (see Figure 7.4). The EPS consists of a 12-slot wellhead platform, a floating production, storage and offloading (FPSO) vessel with catenary anchor leg mooring (CALM) buoy and in-field pipelines. In May 1997, JVPC commissioned Japan’s Mitsubishi Heavy Industries and Single Buoy Mooring of Switzerland to construct a tanker converted FPSO vessel for developing Rang Dong field.

~~Author: Huong Luong Lien December 1998 H -C~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.19~~

The FPSO facility installed at Rang Dong provides an integrated operation for production and storage. The production facilities located on the FPSO include separators, a flare system, an oil transfer pump, a metering system, a water treatment system and a surface manifold. The storage capacity is 900,000 barrels. The FPSO vessel is linked by pipelines to the unmanned, minimum facilities wellhead platform where six surface wells are completed. Among these, four wells are pre-drilled from a 6-slot subsea template while two other wells are post-drilled. The two remote exploration wells: Rang Dong-1 and Rang Dong-2 are completed with subsea satellite wellheads. Rigid pipes with flexible jumpers are used to link these subsea wellheads to the platform. In addition, a subsea manifold is used to bundle flowlines from satellite wells. JVPC will use water injection and gas lift methods to enhance oil production.

Rang Dong full field development is scheduled for completion in 2001. JVPC will install three additional wellhead platforms, of which one will be located in the north area and the other two will be in the south area of the field. The company may choose an FPSO or the production platform to locate the additional production facilities. However, because of rough weather conditions, it is likely that a central production platform (CPP) and a storage tanker of 900,000 barrels capacity will be put in place for the second phase of production (see Figure 7.5). CPP will be located in the north area of the field and linked by a 100-foot bridge to the wellhead platform-1 which was installed during the first phase development. Approximately half of the crude oil produced from the field would be processed and stored on the existing FPSO vessel installed in the first phase. The other half will be processed on the central production platform and then piped to the stand-by storage tanker. Associated gas produced from the field will feed a gas lift system, to be installed in parallel with the in-field pipeline. As a huge gas compression platform was already installed at the nearby Bach Ho field, future gas export will be possible.

~~Author: Huong Luong Lien December 1998 H~~

~~Footnote: Plem = Pipeline end manifold Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.21~~

~~7.7.2 Ruby offshore oil field and other discoveries in Block 01~~

In 1994, the Ruby oil field was discovered by Petronas Carigali, the operator of Block 01 and 02 some 175 kilometres east of Vung Tau. Petronas declared the field commercial in July 1995. The recoverable reserves of Ruby field has been estimated to be approximately 150 million barrels of oil. The production from the field came on stream in November 1998. The initial production rate is expected to be 9,500 barrels per day and the peak field production 85,000 barrels of oil per day.

The Ruby-1 and Ruby-2 wells indicate three potential plays existing in the field. The first are the Miocene sandstones which have an effective porosity of 20% on average. The second are Oligocene or granite washed channel sands. These are relatively tight with average permeability of 2.6 milli-darcies. The third is the basement reservoir (like other fields located on the Cuu Long Basin). This basement reservoir has a complex structure. Accordingly, Petronas had planned for a two-phase development program to reduce uncertainties associated with reservoir structure and performance.

Phase I of the development of the Ruby field is illustrated in Figure 7.6. This phase started in late 1996. The facilities installed in Phase I consist of a 9-slot drilling platform, a floating production, a storage and offloading (FPSO) vessel and a connecting pipeline. The unmanned wellhead platform was designed for jack-up drilling and can handle approximately 30,000 of oil per day. It is being operated from the FPSO. A total of nine dual completion wells have been planned for Phase I. The crude oil gathered in the wellhead platform is routed via a 10-inch flexible pipeline and a riser to the FPSO vessel for treatment and storage prior to offloading. The main facilities located on FPSO are crude separators, a water treatment system, a gas flare system, power generation and accommodation. The FPSO at the Ruby field has a storage capacity of 1 million barrels and has a single point mooring (SPM) system.

The appraisal and development wells drilled in Phase I are to further delineate the field structure. The data obtained from this phase will be used to help formulate the integrated development plan for other discoveries made by Petronas in the same block. These are Pearl, Emerald, Diamond and Topaz. A number of enhanced recovery methods such as hydraulic fracturing and horizontal or multilateral wells will be used to improve recovery and reduce overall project costs on these fields.

~~Author: Huong Luong Lien December 1998 H OJ :onomics of petroleum exploration and development in Viet Nam Page 7.22 Figure 7.6 - Ruby Phase I development scheme~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.23~~

~~The Ruby full field development (see Figure 7.7) is expected to be completed in 1999. The facilities planned for Phase II development consist of the following:-~~

• a 24-slot central processing platform (CPP) • a 32-slot, minimum facilities satellite platform • a 24-slot, minimum facilities satellite platform • a water injection platform • a floating, storage and offloading tanker (FSO) • a subsea pipeline network within the field.

The satellite platform which was already installed under Phase I will be bridge connected to the central processing platform (CPP). The Ruby CPP will be an integrated modular platform with wellheads, processing facilities and accommodation. Gas lift and water injection are also planned on CPP. The two new satellite platforms are unmanned with minimum facilities.

More than 60 production wells and more than 10 water injection wells have been planned for Phase II. The use of horizontal drilling will increase production and reduce the number of production of wells needed. The crude oil produced by three satellite platforms and CPP will be processed on the CPP and then piped to the storage tanker for temporary storage. The FSO tanker will have a designed capacity of 1.5 million barrels. However, the central processing platform (CPP) and the storage tanker are especially designed for possible expansion to accommodate future production from other discoveries. As part of the integrated development plan, a gas gathering system will also be installed to collect and process associated gas for transportation to shore.

~~Author: Huong Luong Lien December 1998 Figure 7.7 - Ruby full field development plan~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.25~~

The Emerald field is expected to be developed by using a drilling platform. The production from this field will flow via a multiphase pipeline to the Ruby central processing platform. The Diamond field is located about 20 kilometres from the Ruby A platform and could be developed by using a mobile offshore production unit (MOPU). There are two development scenarios considered by Petronas for the Pearl field. One option is to use a MOPU. The other would involve the drilling of an extended reach well from Ruby. The length of this well is expected to be between 8 and 10 kilometres. Drilling an extended reach well could reduce the stand-alone development cost because it would eliminate the requirement of a MOPU or lightweight tripod and pipeline facilities. However, further detailed studies will be needed to evaluate the technical feasibility of this scenario (Amanda Battersby, 1998).

~~7.7.3 Lan Tay/Lan Do offshore gas discoveries~~

In September 1994, BP/Statoil, the operator in Block 06-1 offshore Nam Con Son Basin, announced the discovery of Lan Tay/Lan Do gas fields 370 kilometres from Long Hai- Vung Tau. The gas found is described as high quality non-associated natural gas which is low in hydrogen sulphide and carbon dioxide (less than 2%). The two fields have estimated recoverable reserves of approximately 2 trillion cubic feet. Approximately 80 percent of this figure is in Tan Tay and 20 percent in Lan Do. Lan Tay/Lan Do gas was discovered in Miocene carbonate platform deposits.

The 370-kilometre pipeline from Block 06-1 to Vung Tau has been designed to transport not only Lan Tay/Lan Do gas, but also gas from other future fields in Nam Con Son Basin such as Hai Thach-BP/Statoil, Moc Tinh-AEDC and Rong Doi-Pedco. The onshore section of the pipeline will be linked to the end-users in Vung Tau-Ho Chi Minh City area. The Nam Con Son pipeline has a designed diameter of 26 inches and a designed capacity of approximately 210 billion cubic feet per year.

The development of Lan Tay/Lan Do fields is scheduled into a number of phases so that to avoid excess development costs too early in the project life. Gas production can later be increased to meet any growth in demand. The development outline for the Lan Tay/Lan Do fields is based on a subsea development concept:-

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.26~~

• Drilling, completion and subsea facilities at Lan Tay including flowlines to a collector platform, • A compressor platform with dehydration facilities installation at Lan Tay, • an floating storage tanker at Lan Tay for condensate production, • Lan Do being tied to the main Lan Tay development infrastructure using subsea completion technology (Ian D. Forbes, 1995).

There will be five production wells at Lan Tay and two production wells at Lan Do. All production wells will be completed with subsea satellite wellheads which are then tied to the fixed production platform at Lan Tay. Lan Do is about 25 kilometres away from Lan Tay and the two fields will be connected by 10-inch submerged pipelines. Field compression for Lan Tay/Lan Do will be required in 5 to 10 years after production start up.

It is scheduled that Lan Tay/Lan Do fields will be brought on stream at the end of 2000 with a combined production capacity of 300 million standard cubic feet of gas per day. The peak well rate for Lan Tay is expected to be 56 million cubic feet of gas per day, while that for Lan Do is estimated to be 28 million cubic feet of gas a day. The fields also have a small condensate content with an estimated peak output of 3,000 barrels per day.

~~7.7.4 Hai Thach offshore gas & condensate discovery~~

In July 1995, BP/Statoil announced the discovery of the Hai Thach gas & condensate field in Block 05-2 of Nam Con Son Basin. Hai Thach is located about 55 kilometres north of Lan Tay/Lan Do gas fields, in the water depth of 140 metres. The Hai Thach-1 wildcat well encountered a substantial gas bearing interval at depth below 2,900 metres. Extensive downhole testing indicated the presence of high quality gas in good reservoirs. Reserves are estimated to be 0.6 trillion cubic feet of gas and 150 million barrels of condensate.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 7.27~~

BP/Statoil has evaluated a number of alternatives for Hai Thach field development. The most likely option would be to construct a production, drilling and quarters (PDQ) platform which can accommodate 14 to 16 wells (see Figure 7.8). After processing on the PDQ platform, condensate would be piped to a floating, storage and offloading (FSO) tanker located next to the platform, whereas gas would be transported via a 35-kilometre singlephase pipeline to join the Nam Con Son gas pipeline. The Hai Thach branch pipeline will have a designed diameter of approximately 20 inches. At the meeting point of the branch and the main pipeline, a protection structure will be put in place.

An alternative field development would be to install four 4-well templates being tied to a central manifold. In this case, production from Hai Thach will be transported via a 20- inch multiphase pipeline to Lan Tay production platform about 55 kilometres away for processing, storage and export. A 55-kilometre control umbilical pipeline will need to be installed in parallel with the multiphase pipeline. However, this development option is a significant technological challenge.

~~Figure 7.8 - Hai Thach field development plan with PDQ platform~~

~~Production, Drilling & Quarters platform~~

~~Floating storage offloading tanker~~

~~Author: Huong Luong Lien December 1998 Chapter 8~~

~~Exploration and Development Costs The economics of petroleum exploration and development in Viet Nam Page 8.1~~

This chapter contains my cost estimates of exploring for and developing oil and gas fields in different locations in Viet Nam. These estimates are used in economic analyses to indicate the profitability of exploration and field development.

~~In order to cover the range of conditions which are likely to be met in Viet Nam, field development cost estimates have been made for 7 cases. These are as follows:-~~

Primarily oil discoveries - in shallow water (less than 200 metres) north Viet Nam in shallow water (less than 200 metres) south Viet Nam in deep water (over 200 metres) south Viet Nam onshore north Viet Nam Primarily gas discoveries - in shallow water (less than 200 metres) north Viet Nam in shallow water (less than 200 metres) south Viet Nam onshore north Viet Nam

Cost estimates have been made for exploration and field development in each of the cases. The estimates vary from case to case primarily because of differences in geological and geographical conditions such as peak well productivity, gas/oil or condensate/gas ratios, reservoir depth, water depth and whether the field is onshore or offshore.

The geographical conditions of different areas in Viet Nam are discussed in Chapter 3. Viet Nam’s continental shelf (undisputed as well as disputed areas) is about three times the size of its land area. Most of open blocks in the four main basins: Song Hong, Cuu Long, Nam Con Son and Malay are located in water depths of less than 200 metres, except some blocks in the eastern margin of Nam Con Son Basin with water depth up to 1,000 metres. Phu Khanh Basin in central Viet Nam are mainly in waters between 200 and 1,000 metres deep. Particularly, the disputed areas of Hoang Sa, Eastern Sea and Truong Sa basins lie in waters of more than 1,000 metres with limited areas surrounding Spratly Islands in waters of less than 200 metres. The existing field characteristics and development styles are presented in Chapter 7. The average reservoir depth for southern Viet Nam basins is 3,500 metres, while that for northern Viet Nam basins is around 3,000 metres. Significantly, one third of the natural gas reserves discovered in Song Hong Basin contain a high level (80%) of carbon dioxide. My estimates of the costs for petroleum exploration and development in different areas of Viet Nam are set out in the following.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 8.2~~

~~8.1 Exploration cost estimates~~

Some seismic survey costs were made available in Table 6.6 of Chapter 6. It is estimated that seismic can be acquired, processed and interpreted for approximately US$1,000 per kilometre offshore Viet Nam. In contrast, onshore seismic is more expensive and the cost of acquisition, processing and interpretation would be around US$10,000 per kilometre on average. However, onshore seismic costs are very dependent on the type of terrain and the degree of remoteness from established infrastructure. In hilly, swampy and remote areas, seismic costs may be as high as US$15,000 per kilometre. For areas with flat, well drained terrain and reasonable access like onshore Ha Noi Trough, seismic costs of US$10,000 per kilometre are used for economic analyses.

In shallow waters (less than 200 metres) offshore southern Viet Nam, costs of an exploration well drilled on a trouble-free and non-deviated basis to the depth of 3,500 metres are in the range of US$8 million to US$12 million. The average exploration well cost of US$10 million per well is used for economic analyses. Offshore well costs in Viet Nam vary mainly because of the degree of geological complexity in different basins. In Nam Con Son Basin, well costs are usually higher than other basins due to technical difficulties caused by deeper reservoir and high temperatures and pressures. Significantly, Mobil has spent as much as US$47 million for eight months drilling and testing of a single exploration well. On the Thanh Long structure of Block 05-lb, Mobil drilled a total of three wells at a cost of about US$110 million {Energy Information Administration, 1998). On the other hand, an exploration well drilled to the depth of 3,000 metres on Song Hong Basin offshore northern Viet Nam would cost about US$7 million per well on average.

In deep waters (greater than 200 metres), an exploration cost of US$14 million per well is assumed for wells drilled to 3,500 metres. However, well costs may be higher for deeper water areas or more complex geology. Anzoil, an Australian company operating in onshore Ha Noi Trough, has carried out exploration and appraisal drilling programs since 1994. Onshore exploration wells may cost US$5 million per well to drill to the depth of 3,000 metres and US$3 million per well to 1,500 metres deep.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 8.3~~

~~In general, appraisal well costs are slightly lower than exploration well costs, The following appraisal costs are assumed for economic analyses carried out in this study:~~

• US$6 million for an offshore shallow water appraisal well in north Viet Nam • US$9 million for an offshore shallow water appraisal well in south Viet Nam • US$13 million for an offshore deep water appraisal well • US$4.5 million for an onshore appraisal well at 3,000 metres • US$2.7 million for an onshore appraisal well at 1,500 metres.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 8.4~~

~~8.2 Offshore field development cost estimates~~

The field characteristics assumed for the estimates of development costs are shown in Table 8.1. A summary of estimated field development costs for representative shallow- water, deep-water and onshore oil and gas fields in Viet Nam are presented in Table 8.2. The unit development costs assumed for offshore oil and gas fields are given in Table 8.3.

Table 8.1 - Assumptions for oil and gas field developments in Viet Nam Oil field development Water Reservoir Gas/oil Peak Peak field Well Prodn Area depth depth ratio well prodn per cost dispo metres (metres) (cf/bbl) rate year* as % US$MM sal (bopd) of reserves Offshore (average) North Viet Nam floating shallow fixed 50 3,000 500 3,000 22% 5.0 storage South Viet Nam floating shallow fixed 100 3,500 800 4,000 22% 6.0 storage South Viet Nam floating deep floating 350 3,500 800 4,000 20% 10.0 storage Onshore tempo- North Viet Nam na 1,500 500 3,000 11% 2.4 rary storage

Gas field development Water Reservoir Cond/gas Peak Peak field Well Prodn Area depth depth ratio well prodn per cost dispo metres (metres) (bbl/ rate year as % US$MM sal MMcf) (MMcfd) of reserves Offshore North Viet Nam pipeline shallow fixed 50 3,000 0 10 10% 5.0 export South Viet Nam pipeline shallow fixed 100 3,000 0 30 10% 6.0 export Onshore power North Viet Nam na 3,000 0 10 10% 4.0 station

Footnote: * Oil peak field production depends on field size and location. For offshore shallow water oil fields, peak production per year varies from 20% to 24% of initial reserves. For onshore oil fields, peak production per year varies from 10% to 12% of initial reserves.

~~Author: Huong Luong Lien December 1998 H -C :onomics of petroleum exploration and development in Viet Nam Page 8.5~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 8.6~~

~~Table 8.3 - Unit development costs for offshore oil and gas fields~~

~~Items Unit cost~~

~~Total topsides - oil US$13,500 per tonne~~

~~Total topsides - gas US$22,000 per tonne~~

~~Total jacket US$3,675 per tonne~~

~~Pipeline - 25 centimetre US$250,000 per kilometre~~

~~Pipeline - 50 centimetre US$418,000 per kilometre~~

~~FPSO for 50,000 barrel of oil per day (bopd) US$50 million~~

~~or US$1,000 bopd~~

~~Development well cost - shallow water @ 3,500 metres US$6.0 million per well~~

~~Development well cost - deep water @ 3,500 metres US$10.0 million per well~~

~~Subsea well completion gear & installation - shallow US$4.3 million per well water US$8.1 million per well~~

~~Subsea well completion gear & installation - deep water~~

~~Source: Petroconsultants Australasia~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 8.7~~

~~8.2.1 Fixed platform oil field development cost estimates~~

Although most fields are developed with floating production facility as their initial phase, the main development is based on the use of fixed platforms. For the purpose of this exercise, I assume that the oil field developments in shallow water of less than 200 metres deep are based on the fixed platform development concept.

Table 8.4 and 8.5 give the detailed cost estimates of representative fixed platform oil field developments in north and south Viet Nam respectively. The estimates are based on the following field development assumptions

• Field development consists of at least one main (or central) production platform. • The main facilities for the field including production manifold, processing, utility and accommodation are located on the main production platform. • The main platform has a maximum slot capacity of 32 conductors and that, at most 20 of these are to be completed as production wells. • Where more than 20 production wells are required, one or more satellite wellhead platforms are installed. • All development wells located at satellite platforms are drilled by a tender assisted rig temporarily mounted on the platforms. • Crude oil production from satellite wellhead platforms is routed by pipeline to the main production platform for processing. • Processed oil is then piped to a storage tanker prior to export via shuttle tankers.

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~~8.2.2 Fixed platform gas field development cost estimates~~

In shallow water of less than 200 metres deep, a fixed platform development is the only option which has been considered for developing gas fields. Table 8.6 and 8.7 give the detailed cost estimates of representative fixed platform gas field developments in north and south Viet Nam respectively. The estimates are based on the following field development assumptions

• Field development consists of one central processing platform. • The main facilities for the field including production manifold, processing, utility and accommodation are located on the central processing platform. • The central processing platform has a maximum slot capacity of 10 conductors and that at most 6 of these are to be completed as production wells. • Where more than 6 production wells are required, one or more satellite wellhead platforms are installed. • All development wells located at satellite platforms are drilled by a tender assisted rig temporarily mounted on the platforms. • Gas production from each wellhead platform are gathered by subsea pipeline to the central processing platform which removes water and condensate and then sends the purified gas stream down a spur pipeline to an established trunk pipeline. • Processed gas is assumed to be routed 50 kilometres to an established existing pipeline to shore. • Gas is assumed to be sold at the point of trunk pipeline connection.

Author: Huong Luong Lien December 1998 H 3 a 8.6 - Detailed development cost estimates for base case hypothetical gas fields - shallow water/fixed platform north V iet Nam 1 d 2 1 _o 15 I (U 0 1) t 3 c 0 3 1

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~~£ 1 03 tq 03 or 3 — w x: D o a o 00 c cn 0 o a E X < K 2 o o 3 3 c bo 3 o c &o The economics of petroleum exploration and development in Viet Nam Page 8.13~~

~~8.2.3 FPSO tanker oil field development cost estimates~~

A floating production system development can be considered for oil fields lying in shallow water and deep water of greater than 200 metres. Table 8.8 gives the detailed cost estimates of representative floating production oil field developments in south Viet Nam. The estimates are based on the following field development assumptions:

• Field development consists of at least one floating production, storage and offloading (FPSO) tanker. • The main facilities for the field including production manifold, processing, utility and accommodation are located on the FPSO tanker. • Tanker moorings are assumed to be catenary anchor leg moorings (CALMs). • Each FPSO tanker has a maximum of 10 producing wells. • All development wells are pre-drilled by a drilling rig and subsea completions with flexible flowlines, umbilicals and risers. • Crude oil production begins at peak for each FPSO and all production are processed and stored on the FPSO tanker prior to offloading.

Author: Huong Luong Lien December 1998 jg H OX o c o £ H 3 Z ee le 8.8 - D etailed development cost estim ates for base case hypothetical oil fields - deep w ater/FPSO tanker south Viei £ ’ iG X 2 X T3 13 X >

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 8.15~~

~~8.3 Onshore field development cost estimates~~

The field characteristics assumed for the estimates of development costs are shown in Table 8.1. A summary of estimated field development costs for onshore oil and gas fields are presented in Table 8.2. The unit development costs assumed for offshore oil and gas fields are given in Table 8.9.

Table 8.9 - Unit development costs for onshore oil and gas fields Items Unit cost Access road US$100,000 per kilometre Land pipeline - 15 centimetre US$120,000 per kilometre Land pipeline - 40 centimetre US$290,000 per kilometre Development well cost - onshore @ 3,000 metres US$4.0 million per well Development well cost - onshore @ 1,500 metres US$2.4 million per well Source: Petroconsultants Australasia

8.3.1 Onshore oil field development cost estimates To date, there have been no onshore oil field developments in Viet Nam. The onshore cost models for oil development are based on the South East Asia data from Petroconsultants Australasia. Table 8.10 gives the detailed cost estimates for representative onshore oil field developments in north Viet Nam. The estimates are based on the following field development assumptions:-

• Field development consists of at least one central processing facility. • All development wells are drilled at the individual wellsites or at the gathering stations located around the central processing facility. • Each gathering station consists of 3 to 5 wellsites and is connected to central processing facility by a gathering flowline. Whereas, each stand-alone wellsite is linked to the central processing facility by a wellsite flowline. • Crude oil production is gathered and sent to the central processing and stabilisation facility for separation and treatment. • Processed oil is transported by a pipeline buried below the ground to a trunk pipeline or to a temporary storage facility. • Temporary storage consists of a number of 150,000 barrel floating roof tanks. One tank is required for two week’s storage at a field production rate of 10,000 barrels of oil per day. This storage capacity is expanded for higher field production rate by installing additional tanks. Export is via a single buoy mooring system.

~~Author: Huong Luong Lien December 1998 H "o b 0) £ o c o o CL o H 2 3 le 8.10 - Detailed development cost estimates for base case hypothetical oil fields - onshore north Viet Nam 2 2 X 13 X 2 2 >~~

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 8.17~~

~~8.3.2 Onshore gas field development cost estimates~~

There is only one small gas field development onshore Ha Noi Trough at Tien Hai, located about 60 kilometres south of Hai Phong port. This small gas field supplies gas to a local power station in the area. However, because the Tien Hai field has been developed by PetroVietnam, no cost details or development strategies have been made available. The onshore cost models for gas development are based on the South East Asia data from Petroconsultants Australasia. Table 8.11 gives the detailed cost estimates for representative onshore gas field developments in north Viet Nam. The estimates are based on the following field development assumptions: -

• Field development consists of at least one central processing facility. • All development wells are drilled at the individual wellsites or at the gathering stations located around the central processing facility. • Each gathering station consists of 3 to 5 wellsites and is connected to central processing facility by a gathering flowline. Whereas, each stand-alone wellsite is linked to the central processing facility by a wellsite flowline. • Gas production is gathered and sent to the central processing and stabilisation facility for separation and treatment. • After processing, refined gas is routed by a pipeline buried below the ground to a on site compressor/pump station and then to a nearby power station about 10 kilometres away where gas are sold.

~~Author: Huong Luong Lien December 1998 p "o c o 6 o Q. o o H x 8.11 - Detailed development cost estimates for base case hypothetical gas fields - onshore north Viet Nam .a 2 T3 2 is » X) T3 3 2 i" JE~~

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~~A uthor: H uong Luong L ie n December 1998 Chapter 9~~

~~Fiscal Regime The economics of petroleum exploration and development in Viet Nam Page 9.1~~

Throughout this study the term “fiscal regime” is taken to mean all economically quantifiable forms of State involvement in oil and/or gas field development. Therefore, it includes State participation, royalty, production sharing arrangements and taxes of all kinds such as income tax, transfer tax, export duty, bonuses and fees. In this chapter, the Companies are defined as all companies, except PetroVietnam, who have working interests in the contract. The Contractors are the Companies and Petro Vietnam if there is a state participation.

The basis for the petroleum fiscal regime in Viet Nam are Production Sharing Contracts signed between PetroVietnam and foreign oil companies, often referred to as the Contractors. Since 1988, the Production Sharing Contract (PSC) has been the most commonly accepted form of contractual arrangement in hydrocarbon exploration and production in Viet Nam. So far, more than 35 contracts with different PSC terms have been agreed and signed upon.

After the release of Petroleum Law dated 6 July 1993, petroleum contracts have been developed in both form and content. On the 17th of December 1996, the Vietnamese Government issued Government Decree No. 84/CP: “Decree of the government regulating details of the implementation of the Petroleum Law” which marked the latest step in developing contract negotiations.

This study uses and contains a description and analysis of PSC terms which are believed to be typical of current agreements for exploration concessions. A detailed description of the structure and components of these typical PSC provisions is given below.

~~9.1 Structure of Vietnamese PSCs~~

According to Article 17 of Petroleum Law dated 6 July 1993, the duration of a petroleum contract in Viet Nam shall not exceed 25 years, of which the exploration period is less than 5 years. However, the duration of petroleum contracts for deep water, remote offshore areas or gas production are 30 years, of which the exploration period may last for 7 years.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.2~~

The minimum work programme for the exploration period are subdivided into three phases of three-year, one-year and one-year. The first phase states the firm commitments including seismic and drilling works to be carried out by the Contractors. The following two phases of exploration which include the drilling of some additional wells are optional. Each phase of the exploration period can be subject to an extension of at most six months provided that total extension of the exploration period does not exceed one year. On the other hand, the duration of a petroleum contract as a whole may be extended for five years at most.

Figure 9.1 illustrates the general way in which the after tax net cash flow for the Contractors is derived under the Vietnamese PSC terms considered in this study. Figure 9.1 is interpreted as described below:-

~~The top left hand side of Figure 9.1 shows that the first claim on gross revenue derived from hydrocarbon sales is Royalty levied on a sliding scale basis.~~

After Royalty allocation, the Contractors can now recover the petroleum costs which has been incurred for its operations in the contract area. This is governed by the Cost Recovery provisions in the PSC.

~~After recovering their costs, the Contractors are liable to pay Income Tax. Project Income Tax is calculated on the balance of Gross Revenue after Royalty and Cost Recovery.~~

The revenue remaining after Royalty, Cost Recovery and Income Tax is Profit Oil which is then split between State and the Contractors in various proportions depending on levels of production each quarter.

The right hand side of Figure 9.1 shows that the Contractors’ revenue consists of Cost Recovery and the Contractors' share of Profit Oil. The Contractors’ outgoings consist of Transfer tax, Export Duty, Bonuses and Fees and finally Contractors’ share of capital and operating costs of exploring, developing and operating the oil and/or gas field.

~~The Contractors’ revenue remaining after deducting all of the Contractors’ outgoings is the net cash flow to the Contractors.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.3~~

~~The structure shown in Figure 9.1 is significantly different from the structure in previous contracts as follows:-~~

~~(a) In previous contracts, Royalty has typically been paid on behalf of the Companies by PetroVietnam.~~

(b) Under previous PSCs, it was agreed that PetroVietnam should pay all taxes on behalf of the Contractors and the portion of taxes paid will be taken into account while negotiating the share of Profit Oil. However, recent developments have released PetroVietnam from legal requirements of tax liability (Dinh Huu Loc, December 1996).

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.4~~

~~Figure 9.1-General structure of production sharing contracts in Vietnam Project Cash Flow State Cash Flow Contractor Cash Flow~~

~~+ Gross Revenue~~

~~- Royalty + Royalty to State~~

~~+ Contractor - Cost Recovery Cost Recovery~~

~~- Income Tax +Income Tax to State~~

~~+ State Profit Oil + Contractor = Profit Oil Profit Oil~~

~~+Transfer Tax to State - Transfer Tax~~

~~+ Export Duty to State - Export Duty~~

~~+ Bonuses and Fees -Bonuses and Fees to State~~

~~- Capital and Operating costs~~

~~=NCF to Contractor~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.5~~

~~9.2 Illustration of workings of Vietnamese PSCs~~

~~Simplified illustration of calculation of the Companies’ net cash flow in one year~~

Gross revenue Oil production (Mbopd) 34.1 Example data Oil price (US$/bbl) 18.0 Example data Oil revenue (US$MM) 224.0 Production * price * 365 days Royalty Production below 50 Mbopd 8% 2.728 Production in Tranchel*royalty rate Tranchel Production between 50 and 75 Mbopd 10% 0.000 Production in Tranche2*royalty rate Tranche2 Production between 75 and 100 Mbopd 15% 0.000 Production in Tranche3*royalty rate Tranche3 Production between 100 and 150 Mbopd 20% 0.000 Production in Tranche4*royalty rate Tranche4 Production over 150 Mbopd 25% 0.000 Production in Tranche5*royalty rate Tranche5 Oil royalty (Mbopd) 2.728 Sum of royalties calculated for Tranchel to 5 Total royalty (USSMM) 17.9 Oil royalty (Mbopd) * price * 365 days Cost recovery (US$MM) Exploration, Development & Production costs 39.8 Example data Abandonment provision 3.2 Example data Unrecovered costs from previous year 0 Example data Total costs to recover 43.0 Sum of the three costs above Maximum cost recovery (35%) 78.4 Gross revenue * cost recovery ceiling Cost recovery to Contractors 43.0 The minimum of Total costs to recover and Maximum cost recovery Income tax (US$MM) Gross revenue 224.0 Oil revenue from above Royalty 17.9 Total royalty from above Cost recovery 43.0 Cost recovery (CR) from above Project’s taxable income 163.1 Gross revenue less Royalty less Cost recovery Income tax rate (%) 50% Example data Project income tax 81.6 Project’s taxable income * income tax rate Profit sharing Contractors% Production below 15 Mbopd 90% 13.50 Production in TrancheA*Contractors% TrancheA Production between 15 and 30 Mbopd 81% 12.15 Production in TrancheB*Contractors% TrancheB Production between 30 and 75 Mbopd 60% 2.46 Production in TrancheC*Contractors% TrancheC Production between 75 and 150 Mbopd 48% Production in TrancheD*Contractors% TrancheD Production over 150 Mbopd 40% Production in TrancheE*Contractors% TrancheE Contractors’ share (Mbopd) 28.11 Sum of Contractors’ share for TrancheAtoE Contractors’ share of profit petroleum rate (%) 82.43% Contractors’ share (Mbopd) divided by the daily oil production (Mbopd) = 28.11/34.1

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.6~~

Profit petroleum (US$MM) Gross revenue 224.0 Oil revenue from above Royalty 17.9 Total royalty from above Cost recovery 43.0 Cost recovery from above Project income tax 81.6 Project income tax from above Revenue available for profit sharing 81.5 Gross revenue - Royalty - CR - Income tax Contractors’ share of profit petroleum rate (%) 82.43% As calculated above Contractors’ share of profit petroleum 67.2 Profit Petroleum * Contractors’ share Transfer tax Companies’ working interest 85% Assume 15% state participation Companies’ share of profit petroleum 57.1 Contractors’ share*Companies’ working interest Transfer tax rate (%) 10% Example data Companies’ transfer tax 5.7 Companies’ profit petroleum * transfer tax rate Export duty Companies’ share of profit petroleum 57.1 From above Companies’ transfer tax 5.7 From above Companies’ exported petroleum 51.4 Companies’ profit petroleum less transfer tax Export duty rate (%) 4% Example data Companies’ export duty 2.1 Companies’ exported petroleum*export duty rate Bonuses and fees Production bonus 0.0 Example data Training fee 0.3 Example data Companies’ net cash flow (NCF) Companies’ cost recovery 36.6 Cost recovery from above * 85% Companies’ share of profit petroleum 57.1 From above Companies’ revenue 93.7 Companies’ cost recovery plus profit petroleum Companies’ share of expl, dev & prod’n costs 33.8 Expl, dev & prod’n from above * 85% Companies’ transfer tax 5.7 From above Companies’ export duty 2.1 From above Companies’ production bonus 0.0 Production bonus from above * 85% Training fee 0.3 From above Companies’ net cash flow 51.8 Revenue less costs Calculation of State Take Project gross revenue 224.0 From above Project costs 39.8 From above Project net cash flow 184.2 Project revenue less Project costs Companies’ net cash flow 51.8 From above Difference = State Take 132.4 Equal to 72% of project net cash flow

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.7~~

~~9.3 Components of Vietnamese PSCs The main components of the Vietnamese PSCs referenced in this study are described in detail below:-~~

~~9.3.1 Royalty~~

~~As stated in the Government Decree No. 84/CP - Article 43 dated 17 December 1996, royalties are based on a sliding scale system depending on levels of production.~~

~~The royalty on Crude Oil is calculated based on the net aggregate production of Crude Oil from the entire contract area during a taxable period (usually quarter). It is levied at the following rates:-~~

Table 9.1 - Royalty scale for crude oil in Vietnamese PSCs Onshore & Under Over 200m Production 200m water depth water depth Below 50,000 barrels/day 8% 6% 50,001-75,000 barrels/day 10% 8% 75,001-100,000 barrels/day 15% 10% 100,001-150,000 barrels /day 20% 15% Over 150,000 barrels/day 25% 20%

In special cases, depending upon specific geographic, economic and technical conditions of a particular field, the royalty rate for Crude Oil may be higher or may be a fixed rate set by the Government of Vietnam.

The royalty on Natural Gas is calculated based on the net aggregate production of Natural Gas from the entire contract area during a taxable period (usually quarter). It is levied at the following rates:-

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.8~~

Table 9.2 - Royalty scale for natural gas in Vietnamese PSCs Production Onshore & Under Over 200m 200m water depth water depth Below 5 million cubic metres/day 0% 0% 5-10 million cubic metres/day 5% 3% Over 10 million cubic metres/day 10% 6%

~~In special cases, depending upon specific geographic, economic and technical conditions of a particular field, the royalty rate for Natural Gas can be a fixed rate set by the Government of Vietnam.~~

~~Royalty for condensate and liquefied petroleum gas (LPG) is calculated using the crude oil scale and natural gas scales, respectively.~~

~~9.3.2 Cost recovery~~

Under typical PSCs, the Contractors can recover capital and operating costs from the negotiated maxima of 35 percent of oil production and 50 percent of gas production. These limits may be increased to 70 percent for deep water areas. The maximum is often referred to as a cost recovery ceiling. For the purpose of economic analyses in Chapter 11, a cost recovery ceiling of 60 percent is assumed for oil discoveries in the water depth greater than 200 metres. Interest, bonuses, data acquisition fee and training fund costs are not recoverable.

Petroleum operating costs which are not recovered in any one period may be carried forward to the following periods, provided sufficient revenue is available within the cost recovery ceilings in future periods. These costs can be carried forward without interest until fully recovered.

~~Petroleum operations costs for the purpose of cost recovery can be classified as follows:~~

~~a. Exploration costs Exploration costs are expenditure incurred in the search for petroleum which may include:-~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.9~~

• geological, geophysical, geochemical and topographical data acquisition, processing and interpretation • Equipment, materials, services and labour used in drilling exploration and appraisal wells • general and administrative expenditures allocated to exploration costs b. Development costs Development costs are expenditure incurred in the development of petroleum reservoirs and all associated offtake, processing and transportation systems. These may include:-

• drilling wells for purposes of producing petroleum, including dry, producing and injection wells • completing producing and injection wells • intangible costs such as consumable material, services and labour used in drilling and completing wells • studies for field facilities • costs of the field facilities (platforms, storage tankers and other facilities) • general and administrative expenditures allocated to development costs c. Production costs Production costs are expenditure incurred in the production of petroleum. These also include the general and administrative expenditure allocated to production costs. Withholding tax of subcontractors if there is any should also be included as production costs. d. Abandonment cost According to Article 16 of Government Decree No. 84/CP dated 17 December 1996, costs and expenses of removing Fixed Installations are paid by the Contractors and included in cost recovery. There are two cases where such removals incurs. One is during the exploration period and the other is at the end of the field life upon termination of the contract. In the first case, since there is no revenue, relinquishment costs can only be carried forward and recovered if production starts.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.10~~

In the second case, the Contractors should prepare and submit an abandonment work program and budget detailing the estimated abandonment costs, adjusted for inflation and interest. The Contractors can provide for abandonment every quarter on a units of production basis (based on the ratio of current production to total recoverable reserves). Such provisions can then be regarded as recoverable costs in the quarter they are made. However, every year, the provision should be reviewed and if necessary adjusted with revised costs of abandonment and revised recoverable reserves. Any unused balance of the abandonment costs provisions remaining after completing the abandonment work program is subject to Income Tax.

Almost all expenditure relating to petroleum operations should be regarded as petroleum operations costs for the purpose of cost recovery. However, as stated in the Government Decree No. 84/CP - Article 54 dated 17 December 1996, there are some costs and expenses which cannot be included in recoverable costs

1. Costs and expenses incurred prior to the effectiveness of the Petroleum Contract, except for special cases as agreed upon in the Petroleum Contract or approved by the State Petroleum management authority. 2. Petroleum bonuses of various types and other non-recoverable undertakings agreed upon in the Petroleum Contract. 3. Interest on the amounts invested in Petroleum exploration and production. 4. Fines and penalties, amounts paid as compensatory damages and other damages resulting from the fault of the organisation or the individual. However, whether we can tell the damages were caused by the Contractors or not becomes a problem. If the reasons of damages are others than the Contractors’ fault, costs associated with the accidents would be included in recoverable costs. 5. Money paid for profit taxes in Vietnam and abroad. 6. Losses that have been compensated by insurance. 7. Charitable and social contributions, and expenditures of a gift giving character. 8. Unjustifiable and/or unreasonable expenses discovered by PetroVietnam or other Vietnamese organisations having jurisdiction during audit, final tax settlement and inspection.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.11~~

~~9.3.3 Income tax~~

As stated in Article 33 of Petroleum Law dated 6 July 1993, corporate income tax for petroleum industry is charged at a rate of 50 percent of taxable income. However, the Contractors conducting petroleum operations in deep water areas may be granted a reduction to 40 percent of taxable income. In special cases, exemptions from corporate income tax may be granted.

The total taxable income in Vietnamese PSCs is the balance of total revenue remaining after allocation of Royalty and Cost Recovery. The total revenue mentioned should also include all other revenue related to the petroleum operations. It is important to note that there may be a time when the Contractors have to pay income tax even if they make loss (operating expenditure is greater than Cost Oil allowance). The case of Dai Hung oil field with BHPP is a typical example.

~~9.3.4 Profit sharing~~

Any excess revenue remaining after Royalty, Cost recovery and Income Tax is classed as Profit Oil or Profit Gas and is therefore subject to profit sharing arrangements between the State and the Contractors. The Contractors’ share of Profit Oil is different in different contracts. It also varies depending on the level of production. The Contractors’ share of calculated Profit Oil ranges from 40% to 90%. For the purpose of this study, the following sliding scale has been assumed:-

Table 9.3 - Profit Oil Sharing under typical Vietnamese PSCs Quarterly average production Contractor share of State share of in barrels of oil per day Profit Oil Profit Oil below 15,000 bopd 90% 10% from 15,001 to 30,000 bopd 81% 19% from 30,001 to 75,000 bopd 60% 40% from 75,001 to 150,000 bopd 48% 52% over 150,000 bopd 40% 60%

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.12~~

Profit Gas (defined in the same way as Profit Oil) should be split between the State and the Contractors in the same percentages as for Crude Oil as in Table 9.3 above. The conversion of Natural Gas into barrels of oil equivalent is based on one barrel of Crude Oil being equivalent to 5,500 standard cubic feet of Natural Gas.

Recent PSCs are usually based on profit sharing after income tax. Under some geographic, economic and technical conditions, the split of profit either before income tax or after income tax does not affect the income of different parties in the contract, but only affects who the tax payers are. The Contractors’ share of profit is different in the two cases so that the Contractors would get the same share. If profit is shared before income tax, then the tax payers are each party in the contract.

~~9.3.5 Transfer (profit remittance) tax~~

The profit remittance tax rate is currently 10%. Typically, transfer tax is calculated on that portion of the Contractors’ share of Profit Oil and/or Profit Gas which is transferred outside Viet Nam.

~~9.3.6 Export duty~~

The Contractors are liable to pay an export duty on that part of their share of crude oil which is exported. However, having no indigenous refinery capacity, all of the crude oil currently produced in Viet Nam is exported. The market for oil companies is the international market. As a result, the Contractor’s export duty can be calculated by the following formula:

~~Export duty = (the Contractors’ share of Profit Oil - Transfer tax) * export duty rate~~

Nonetheless, by the year 2003 when the first Vietnamese refinery is supposed to be in operation, the market for oil companies would be both the domestic and international markets. The calculation of the Contractors’ export duty will then need to be modified for the portion of crude oil being exported.

~~According to Dinh Huu Loc, December 1996, export duty rates on oil and gas export are:-~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.13~~

~~Table 9.4 - Export duty rates in Vietnamese PSCs Export duty rate provided Rate currently applicable Oil 2% to 8% 4% Natural gas 0% to 10% 0%~~

~~9.3.7 Bonuses and Fees~~

These are negotiable. Bonuses are payable at the time the contract is signed, on first commercial discovery, production start-up and subsequently as various levels of production are reached. For the purpose of this study, the following bonuses have been assumed:-

Table 9.5 - Possible bonus payments in Vietnamese PSCs Signature bonus US$1.60MM Data acquisition fee USS0.50MM Commercial discovery bonus US$1.00MM Production start bonus US$1.10MM Production rate reaches 25 Mbopd US$2.10MM Production rate reaches 50 Mbopd US$3.10MM Production rate reaches 75 Mbopd US$4.10MM Production rate reaches 100 Mbopd US$5.10MM Production rate reaches 150 Mbopd US$6.10MM

Bonuses are single payments made once the conditions met as set out above are achieved. Production bonuses for gas are calculated in the same way as for oil, at the conversion rate of 5,500 standard cubic feet of gas to one barrel oil equivalent. According to Article 54 of Government Decree No. 84/CP dated 17 December 1996, bonuses are not regarded as recoverable for the purpose of cost recovery.

Contractors must allocate on average US$200,000 prior to the first commercial discovery and US$300,000 thereafter for training purposes each contract year with any unspent balance going to PetroVietnam. These annual training fee is also not recoverable for the purpose of cost recovery.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.14~~

~~9.3.8 State Participation~~

Article 25 of Petroleum Law states that “PetroVietnam shall have the right to participate in capital investment under a Petroleum Contract”. Upon declaration of a commercial discovery, PetroVietnam has the option to acquire from foreign companies a certain percentage of the working interest under the contract. PetroVietnam is generally carried by Companies through the exploration phase. Apart from the carry prior to the first commercial discovery, PetroVietnam would take part as one of the Contractors ie. paying its share of all the costs (including all forms of government take) and receiving its share of revenue.

PetroVietnam has an option to acquire from the Companies up to 15% of the working interest. Since the Companies have incurred all exploration costs up to the first commercial discovery, including those associated with the participating interest of PetroVietnam, they are entitled to recover these costs through reimbursement. For current contracts, PetroVietnam’s share of the past costs can be reimbursed without interest by either

~~• a cash transfer (a lump sum) or • allocating part of PetroVietnam’s entitlement to Cost Recovery, commencing from the start of production.~~

~~The reimbursement is free of any charges, taxes or duties.~~

~~For the economic analyses carried out in the following chapters, it is assumed that there is no state participation by PetroVietnam.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.15~~

~~9.4 Recent development in Vietnamese fiscal regime~~

Recently, petroleum contracts in Vietnam have been developed in both form and content. So far, most contractual arrangements for petroleum exploration and production in Vietnam have been in the form of Production Sharing Contract. This is because PetroVietnam does not have much managerial experience in conducting oil projects. It also lacks money and wants to avoid risk in the exploration period. However, in the long term, the main target of the Vietnam government is to keep a closer involvement in petroleum operations in both technical and financial aspects. On 10 April 1996, PetroVietnam entered into a Business Cooperation Contract (BCC) with Conoco for Block 133 & 134. PetroVietnam then can take part in the management of the project.

Furthermore, the government is encouraging PetroVietnam to pursue joint ventures rather than production sharing contracts. The purpose of this is to increase PetroVietnam’s managerial role and technical expertise by gaining experience through its direct involvement in petroleum operations. With the joint-venture form of petroleum arrangement, PetroVietnam actually takes part as the operator and directly manages the day-to-day operation. Unfortunately, it has had to face some difficulties in the negotiation process. This is mainly because of conflicts between the type of joint venture which PetroVietnam wants to sign and the Law on Foreign Investment which cover detailed regulations for joint ventures.

Production sharing contracts would remain the vehicle for foreign participation in newly open (unexplored) blocks. Having limited capital, PetroVietnam intends forming joint ventures with foreign oil companies only in high potential blocks previously explored and located in areas close to the existing oil & gas fields. On the 16th of September 1998, PetroVietnam signed a joint venture for petroleum exploration and production in Block 15-1 with the group of Conoco, Geopetrol, Pedco and SK. Corp. Block 15-1 is located in the northern areas of the Cuu Long Basin, about 40 kilometres southeast of Vung Tau coast. This lies adjacent to the Rang Dong and Ruby oil fields and is very close to the Bach Ho, Rong fields. In 1978, Deminex drilled a wildcat well 15-G 1 which showed evidence of oil and gas. Geological studies previously carried out in this block also

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 9.16~~

indicated the potential for oil. However, it is believed that under the joint venture arrangement, PetroVietnam still bears no exploration risk and carried by foreign companies through the exploration phase. Foreign partners are in the position to invest 100% of exploration costs. However, PetroVietnam will have a 50% stake if the block is commercially justified.

From the legal perspective, the main difference between production sharing contracts and joint ventures is that a joint venture company is a separate legal entity. Instead of a joint operating agreement (JOA), a charter of the joint venture company is formed. The terms of the joint venture itself would be similar to the terms in production sharing contracts. However, joint venture contracts need to cover many other legal aspects. Under the Law on Foreign Investment in Viet Nam, partners of the joint venture must appoint members to a board of management in accordance with their respective interests. There are provisions for majority voting in a number of matters such as the joint venture company’s production and business plan and the removal of the general director. Moving from production sharing contracts, parties to the joint venture company need to incur an additional administrative costs of establishing and operating a separate legal entity {Christopher Moore, 1996).

~~9.5 Worked example of a Vietnamese PSC~~

The following presents a detailed worked example of the workings of a Vietnamese PSC as it would apply to a hypothetical stand alone oil field development. The cash flow calculations have been done for a period of 25 years from 1997 to 2021. However, for the purpose of presentation only calculations to the year 2010 are shown in the following.

~~Author: Huong Luong Lien December 1998 n and development in Viet Nam Page 9.17 cl~~

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~~lor: Huong Luong Lien December 1998 H lomics of petroleum exploration and development in Viet Nam Page 9.24 33 co ^00 2 O oo ^ ° C\ 8^2°'''' O -~~

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~~Author: Huong Luong Lien December 1998 Chapter 10~~

~~Fiscal Analyses The economics of petroleum exploration and development in Viet Nam Page 10.1~~

The description of the current fiscal regime in Viet Nam and the fiscal assumptions made for the economic analyses are presented in the previous chapter, Chapter 9. In this chapter, I present economic analyses of the application of the current fiscal regime to hypothetical, but representative exploration and field development possibilities in Viet Nam. The aims are:-

(a) to analyse the critical aspects of the production sharing contract terms in Viet Nam and also to compare it with other regimes in the region (b) given the reserves distribution of Viet Nam’s southern basins, to try to find out what oil reserves are not being exploited because of the effects of the fiscal regime.

In order to do this, we employ representative exploration conditions and oil field developments offshore south Viet Nam in shallow water of less than 200-metre deep. The economic and development assumptions used are presented in Chapter 11.

~~10.1 Government Take~~

“Government Take” is the total of all quantifiable forms of government involvement in a petroleum project, including royalty, income tax, government’s share of profit oil/gas, transfer tax, export duty, and bonuses and fees. The present value of Government Take is therefore defined in this chapter as follows

~~Present value of Government Take = Present value of total project net cash flow less Present value of Contractors’ net cash flow~~

~~Total project net cash flow is equal to the total project’s gross revenue less the total project’s capital and operating costs.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.2~~

~~Since we have assumed no Stare participation in Chapter 9, Government Take to be expressed as a percentage is defined as follows~~

~~Government Take = Present value of Government Take (as a percentage) divided by Present value of total project net cash flow~~

~~Therefore, Government Take is the portion of the project’s present value which is not available to the Contractors because of Government involvement of one kind or another.~~

~~If there is a direct participation by the State, Government Take (as a percentage) calculation stated above should be modified for the level of direct state participation as follows:-~~

~~Govemment Take (as a percentage) = Present value of Government Take~~

~~Present value of total project net cash flow * (1 - State participation rate)~~

~~Alternatively, the present value of Government Take can be calculated as:-~~

~~Present value of total State cashflow - Present value of State participation cashflow.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.3~~

~~10.2 Impact of individual fiscal components~~

Figure 10.1 shows the economic impact of different fiscal terms on oil developments. The figure is based on the economic analyses of developing individual stand-alone representative oil discoveries offshore shallow water south Viet Nam over a range of field reserves. The top line in Figure 10.1 represents the present value (per barrel of reserves) of gross revenue generated from sales of crude oil over the whole project life.

~~The following fiscal terns have been assumed for Figure 10.1:-~~

• Royalty rates: 8% for production below 50,000 barrels/day 10% for production between 50,001 to 75,000 barrels/day 15% for production between 75,001 to 100,000 barrels/day 20% for production between 100,001 to 150,000 barrels/day 25% for production over 150,000 barrels/day • Cost recovery ceiling 35% • Income tax rate 50% • Company share of profit oil 90% for production less than 15,000 barrels/day 81% for production between 15,001 to 30,000 barrels/day 60% for production between 30,001 to 75,000 barrels/day 48% for production between 75.001 to 150,000 barrels/day 40% for production over 150,000 barrels/day

• Transfer tax rate 10% • Export duty 4% • Bonuses and fees: Signature bonus US$1.60 million Data acquisition fee US$0.50 million Commercial discovery bonus US$1.00 million Production start bonus US$1.10 million Production bonus at 25 Mbopd US$2.10 million Production bonus at 50 Mbopd US$3.10 million Production bonus at 75 Mbopd US$4.10 million Production bonus at 100 Mbopd US$5.10 million Production bonus at 150 Mbopd US$6.10 million Annual training fee US$200,000 to US$300,00 p.a. No State participation

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.4~~

~~Figure 10.1 - Impact of individual fiscal components~~

~~Capital costs~~

~~Operating costs~~

~~Royalty~~

~~Minimum field sipe/j Income tax before Government Take~~

~~I Minimum field size after Government Take Transfer tax /------~~

~~State Profit Oil Export duty / __~~

~~Bonuses and fees Contractor Net Cash Flow~~

~~60 80 100 120 140 Reserves (million barrels)~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.5~~

The two lines below the top line in Figure 10.1 represent the present value of the project’s gross revenue less the present value of capital and operating costs for the whole project. As a result, the third line represents the net present value of the project net cash flow. Subsequent lines show the progress effects of deducting the present value of each component of the Vietnamese fiscal regime. The distance between two lines is a measure of the economic impact of each fiscal component in reducing the final economic return to the contractors. The lowest line in Figure 10.1 shows the net present value of net cash flow to the contractors after deduction of present value of all capital, operating costs and the present value of Government Take.

~~The component of Government Take which has the greatest economic effect on all field sizes is the income tax. This is shown in Figure 10.1 and Figure 10.2.~~

~~Figure 10.2 - Fiscal components as a percentage of Project NPV~~

~~100%~~

~~—x - Transfer tax —+- Export duty —o— Bonuses and fees~~

~~^ 70%~~

~~Income tax~~

~~Royalty~~

~~State’s $hare 0f profit oil~~

~~Field size (million barrels)~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.6~~

Figure 10.1 also shows that there is a difference between the minimum developable field sizes with and without the Government Take. Each of every fiscal component contributes to this difference. However, the income tax causes the minimum field size to increase by the greatest amount (9.3 million barrels - see Table 10.1).

~~Table 10.1 - The effect of each fiscal component on the minimum developable field size~~

The minimum developable Increase in the minimum field size field size caused by Cases (million barrels) each fiscal component (million barrels) Without Government Take 14.4 with Royalty 16.3 1.9 and Income tax 25.6 9.3 and State’s share of profit oil 28.0 2.4 and Transfer tax 30.1 2.1 and Export duty 30.8 0.7 and Bonuses and fees 32.6 1.8

Income tax (as discussed in Chapter 9) is calculated on the balance of total revenue remaining after allocation of royalty and cost recovery. However, the cost recovery term set in the Vietnamese production sharing contracts has a low ceiling of 35% of oil production (for oil discoveries in shallow water). As a result, taxable income can be greater than total revenue less total costs especially at the beginning of the production period. More importantly, as long as oil is being produced from the contract area, the Contractors always have to pay income tax even when they make loss. Income tax is therefore the most significant fiscal component which tends to make small fields uneconomic for contractors to develop. For example, fields of 20 million barrels which are profitable before Government Take become unprofitable after Government Take (see Figure 10.2). The Vietnamese fiscal regime would therefore prevent the development of fields which are economic but have a low level of profitability (that is, marginal fields).

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.7~~

Figure 10.3 presents the relationship between the project profitability as net present value of project net cash flow per barrel of reserves and Government Take as a percentage (see Section 10.1 for the method of calculation). As can be seen from the figure, Vietnamese fiscal regime is regressive. Marginal projects are taxed heavily, while profitable projects are relatively lightly taxed.

~~Figure 10.3 - Economic effects of Vietnamese fiscal regime~~

~~NPV of project net cash flow per barrel of reserves~~

~~Footnote: Net present value (NPV) is calculated using a discount rate of 12.5% per year.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.8~~

~~10.3 Fiscal comparison~~

According to Petroconsultants’ Review of Petroleum Fiscal Regimes (Oil) 1997, the Vietnamese fiscal terms for oil are moderately severe in comparison to other neighbouring countries in the region. This is shown in Table 10.2 in which fiscal regimes are ranked by the level of Government Take for “marginal”, “economic” and “upside” fields. These field categories are defined by Petroconsultants according to the level of profitability on a gross project basis. The table shows the fiscal regimes of Thailand - standard, Philippines, Viet Nam, Indonesia - standard and Malaysia-standard in a ranking order from the lowest to the highest Government Take for each category.

~~Table 10.2 - Fiscal ranking for oil~~

~~Government Take Marginal fields Economic fields Upside fields~~

~~Low level Thailand - standard Philippines Thailand - standard~~

~~Philippines Thailand - standard Philippines~~

~~Viet Nam Viet Nam Viet Nam~~

~~Indonesia - standard Indonesia - standard Malaysia - standard~~

~~High level Malaysia - standard Malaysia - standard Indonesia - standard~~

It is important to note that Government Take varies not only with the fiscal regime, but also with the nature of the development. Table 10.2 however shows the fiscal ranking carried out by Petroconsultants in which the same oil field development assumptions are applied for different fiscal regimes to isolate the effect of fiscal regime on its own. Therefore, the ranking in Table 10.2 are indicative only and ignore differences in development costs between countries.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.9~~

~~10.4 Reserves made uneconomic because of Government Take~~

As stated in section 10.2, the Vietnamese fiscal regime tends to prevent the development of fields which are marginal before Government Take. This section will try to estimate the discovered oil reserves which may not be developed by contractors because of the behaviour of the fiscal regime. For the same reason, prospect oil reserves which may not be drilled by contractors are also estimated.

~~Discovered reserves not being developed~~

Field development economics for oil discoveries in shallow water areas offshore south Viet Nam are presented in section 11.12. From these analyses, the minimum field size which is required for a project to remain profitable after all forms of Government Take is estimated to be 32.6 million barrels. When we assume no Government Take, the minimum economically developable field size is 14.4 million barrels. As a result, fields with recoverable reserves between 14.4 million barrels and 32.6 million barrels would not be developed because of Government Take. The total reserves of fields which have sizes in the [14.4, 32.6] million barrels range are estimated in the following.

Table 10.3 shows a list of oil discoveries offshore south Viet Nam basins and their estimated original reserves. There are 9 discoveries with estimated reserves in the range of 14.4 to 32.6 million barrels. However, Jade 1, Pearl 1 and Rong 14 have already planned by contractors (Petronas, Vietsovpetro) for integrated development with other discoveries of the same blocks. This is because developing a number of fields together would cost much less per field than developing individual fields on the stand-alone basis which is one of the development assumptions made in Chapter 11.

Consequently, there remain 6 discoveries which might not be developed by contractors because of the effect of the fiscal regime. These are Ba Den 1 (29.1 million barrels), Phuong Dong 1 (22.4 million barrels), Dam Doi 1 (30.0 million barrels), Ca Cho 1 (27.0 million barrels), Kim Cuong Tay 1 (26.0 million barrels) and Rong Bay 1 (16.0 million barrels). In total therefore approximately 150 million barrels of oil reserves might not be developed by contractors because of the behaviour of the Vietnamese fiscal regime.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.10~~

~~Table 10.3 - Oil discoveries offshore south Viet Nam basins~~

~~Oil discoveries Estimated original reserves (million barrels)~~

Bach Ho 1 500.00 Ba Den 1 29.12 BaVi 1 9.56 Cam 1 36.65 Diamond 1 13.20 Emerald 1 45.65 Jade 1 32.50 Pearl 1 31.80 Phuong Dong 1 22.40 Rang Dong 1 220.00 Rong 1 85.00 Rong 14 21.64 Ruby 1 150.19 Soi 1 2.45 Tam Dao 1 48.11 Topaz 1 4.49 Vai Thieu 1 2.36 Vung Dong 1/1R 73.30 Dam Doi 1 30.00 Nam Can 1 13.00 Phu Tan 1 9.00 U Minh 1 55.00 Ca Cho 1 27.00 Dai Hung 1 100.00 Dua 1 5.00 Kim Cuong Tay 1 26.00 Rong Bay 1 16.00

~~Total 1,609.42~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.11~~

~~Prospect reserves not being drilled~~

We can also estimate the reserves in exploration prospects which would not be drilled because of Government Take. For this purpose, it is assumed that offshore south Viet Nam basins have a total prospect reserves of 3,000 million barrels of crude oil and that the probability of drilling success is 10%.

Exploration economics for oil prospects in shallow water areas offshore south Viet Nam are presented in section 11.12. From these analyses, the minimum prospect size required to justify an exploration programme (that is, a seismic survey and 2 exploration wells) is estimated to be 102.2 million barrels. When we assume no Government Take, the minimum prospect size is 38.4 million barrels. This implies that prospects with recoverable reserves between 38.4 million barrels and 102.2 million barrels would not be drilled because of Government Take. The total reserves of the prospects which have sizes in the [38.4, 102.2] million barrels range are estimated in the following.

It is not known how many undrilled exploration prospects there are in the basins offshore south Viet Nam. Their individual sizes are also not known. In order to estimate these unknowns, I assume that the existing discoveries listed in Table 10.3 are a representative sample of potential discoveries in south Viet Nam basins. I assume that the sizes of all existing and future discoveries in south Viet Nam basins follow a log normal distribution with the same mean and standard deviation as the sizes of existing discoveries listed in Table 10.3. Figure 10.4 shows the probability distribution of crude oil reserves in all existing and future discoveries in south Viet Nam basins.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.12~~

~~Figure 10.4 - Probability distribution for oil reserves in offshore south Viet Nam basins~~

~~P r 0 b a b~~

~~t y~~

~~Oil reserves in individual fields/prospects (million barrels)~~

Data generated from the simulation has been used to calculate the portion of total reserves in fields greater than a certain field size. For example, to find out what percentage of the total reserves of all discoveries listed in Table 10.3 belong to discoveries with estimated original reserves greater than 80 million barrels, we should add together the reserves in Bach Ho 1 (500 million barrels), Rang Dong 1 (220 million barrels), Rong 1 (85 million barrels), Ruby 1 (150.19 million barrels) and Dai Hung (100 million barrels). In total therefore, 1,055.19 million barrels (or 1,055.19 divided by 1,609.42 equals 65.56%) of total reserves are in fields greater than 80 million barrels.

Figure 10.5 shows the portion of total existing and potential crude oil reserves which are contributed by discoveries of different sizes. This relationship has been created from the lognormal reserves distribution in Figure 10.4.

~~Author: Huong Luong Lien December 1998 H 1) momics of petroleum exploration and development in Viet Nam Page 10.13 uoi;nqu;uoD (%)~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.14~~

~~From the relationship shown in Figure 10.5, we can estimate the portions of total reserves in fields greater than the minimum prospect size without and with Government Take. These are:-~~

~~• 82.58% of total reserves are in fields greater than 38.4 million barrels • 55.12% of total reserves are in fields greater than 102.2 million barrels~~

As a result, 27.46% of total reserves is in fields greater than 38.4 million barrels but less than 102.2 million barrels. This portion of total reserves should not be drilled because of the effect of Government Take. However, discoveries with reserves sizes in the range of 38.4 to 102.2 million barrels should be excluded from the calculation as they were already drilled. These are Emerald 1 (45.7 million barrels), Rong 1 (85.0 million barrels), Tam Dao 1 (48.1 million barrels), Vung Dong 1 (73.3 million barrels), U Minh 1 (55.0 million barrels) and Dai Hung 1 (100.0 million barrels) which total up to 407.1 million barrels (see Table 10.3).

The total ultimate reserves of oil prospects offshore south Viet Nam basins has been assumed to be 3,000 million barrels. Therefore, (3,000*27.46% - 407.1) = 416.7 million barrels would not be drilled by contractors because of the effects of the Vietnamese fiscal regime. The results when probability of drilling success is 20% are also shown in Table 10.4.

Table 10.4 - Prospect reserves not drilled due to Government Take Probability Minimum Minimum Portion of Portion of Portion Reserves of prospect prospect total total of total not be drilling reserves reserves reserves reserves reserves drilled success without GT with GT in in in fields due to (a) (b) fields>(a) fields>(b) [(a), (b)] GT MMbbls MMbbls % %% MMbbls 823.8 less 10% 38.4 102.2 82.58% 55.12% 27.46% 407.1= 416.7 534.6 less 20% 26.4 57.9 89.60% 71.78% 17.82% 335.8T= 198.8 Footnote: MMbbls = million barrels, GT = Government Take T . . . . existing discoveries with reserves sizes in the range of 26.4 to 57.9 million barrels (see Table 10.3)

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 10.15~~

All of the results presented in this section 10.4 are estimates only. The quality of these estimates depends on whether the available data of estimated reserves is a representative sample of the actual reserves estimates for offshore south Viet Nam basins as well as other assumptions such as exploration and development costs, fiscal terms, economic and development assumptions made in Chapter 8, 9 and 11. A major assumption is that the estimated minimum field size cut offs (38.4 and 102.2 million barrels) are based on stand alone developments. Lower cut offs would be more appropriate if costs could be shared with other field developments and if fiscal relief was obtained by developing fields in the same PSC.

Given the caveats set out above, the quantification of the effects of the Vietnamese fiscal regime in reducing economically attractive prospects in the country are indicative only. However, they illustrate how significant the fiscal regime is in determining the economic hydrocarbon resource base of Viet Nam.

~~Author: Huong Luong Lien December 1998 Chapter 11~~

~~Economics The economics of petroleum exploration and development in Viet Nam Page 11.1~~

~~This chapter presents the results of economic analyses of exploring for and developing crude oil and gas discoveries in Viet Nam.~~

~~11.1 Objectives~~

~~The economic analyses discussed in this study are based on hypothetical, but representative developments and are not specific to any particular fields or prospects.~~

~~The aims of the economic analyses in this chapter are:-~~

• To examine the critical features of the Viet Nam fiscal regime. • Assuming a discovery has been made, to demonstrate the profitability of field development over a range of reserves and to determine the minimum reserves which would make the development of a discovery economically justified. • To determine the minimum potential reserves in an undrilled prospect which are required before drilling is economically justified given the risks and costs of exploration and the profitability of any ensuing development.

~~11.2 Cases analysed~~

~~The cases analysed are shown in Table 11.1.~~

~~Table 11.1 - Cases analysed Case Area Main product PSC assumption number~~

1 Onshore North Viet Nam Oil Onshore oil 2 Gas Onshore gas 3 Offshore shallow water - North Viet Nam Oil Shallow water oil 4 Gas Shallow water gas 5 Offshore shallow water - South Viet Nam Oil Shallow water oil 6 Gas Shallow water gas 7 Offshore deep water - South Viet Nam Oil Deep water oil

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.2~~

In each case, projections of future after-net cash flows from hypothetical, but representative field developments have been made. The net cash flow projections employ the fiscal assumptions set out in Chapter 9 and the cost estimates set out in Chapter 8. The results are expressed in terms of the net present value (“NPV”) of net cash flow per barrel or per thousand cubic feet of reserves. The methodology and economic and field development assumptions employed are set out in the following sections.

~~11.3 Approach~~

~~For each of the exploration and field development cases considered, the following steps have been carried out:-~~

• I assume a set of representative exploration and field development parameters such as seismic costs, exploration well costs, reservoir depth etc. These assumptions are set out in Chapter 8. • I estimate the costs of exploration and field development based on the assumptions set out in Chapter 8. Existing and planned developments in the same or comparable areas have been used as a guide in making the estimates. • I make economic and development cost scheduling assumptions. • I carry out cash flow analyses based on the cost estimates, the appropriate fiscal terms and the economic and development assumptions. • I carry out sensitivity analyses of project development in the different areas and under different conditions with the assumption that a discovery has been made. • I use expected value analyses to determine minimum prospect reserves as a function of the probability of drilling success.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.3~~

~~11.4 Net Present Value per barrel or per million cubic feet graphs~~

The results of field development economics in this study are presented mostly as graphs showing the net present values per barrel of nominal (that is, undeflated) net after tax cash flow to the PSC Contractors. I assume no State Participation. An example set of four graphs are presented in Figure 11.1 which shows the sensitivity of the economics to changes in peak well production rate, oil price, capital costs and fiscal terms. Each graph shows the results of base case economics together with sensitivities. In general, the sensitivities have been carried out assuming that only one parameter is varied with other parameters retaining their base case values.

The vertical axes give the net present value per barrel or per million cubic feet of total project reserves. The net present value calculated is the net present value of net cash flow to the contractors after all forms of State Take (except State Participation). The net cash flows have been calculated assuming that a discovery has already been made and the cash flows begin from the time of the discovery and last until the end of the economic life of the field. In other words, the analyses are “full cycle economics” for a stand-alone development.

~~The horizontal axes show the range of reserves for which net present values per barrel or per million cubic feet are calculated.~~

The graphs also give minimum economic reserves for an existing discovery under different assumptions. The minimum economic reserves can be read off the graphs at the points where the net present value per barrel first becomes zero as reserves are reduced.

In some cases, the net present value per barrel or per million cubic feet graphs may show occasional inflections. These are the result of assuming that additional platforms are required as field sizes reach progressively higher levels. This causes disproportionately large step increases in capital costs as reserves increase.

~~Author: Huong Luong Lien December 1998 H ■ — h o o o c E o a. « O 3 E s~~

~~igure 11.1 - An example of net present value per barrel graphs JO } o~~

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~~ithor: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.5~~

~~11.5 Minimum prospect reserves graphs~~

The economic analyses of field development discussed in section 11.4 above ignore the costs and risks associated with the exploration effort required to make the discovery on which the development is based. The results of analyses which incorporate exploration cost and risk are presented in this study as graphs showing minimum prospect reserves versus probability of success.

The net present values derived from the cash flow analyses have been used to calculate the expected value of the decision to delineate and drill a prospect assuming a range of reserves and probabilities of success. The expected value has been calculated as follows:

~~Expected value = Net present value of development of discovery * Probability of success less Net present value of exploration costs * Probability of failure~~

~~A positive expected value implies that the decision to drill the exploration well is economically justified. In order to get the results needed, the following steps have been carried out:-~~

• the reserves are varied. • the net present values of the cash flows resulting from the development of those reserves are derived. • the resulting expected values for given probabilities of success are calculated. • the minimum prospect reserves for a given probability of success are determined by defining the points where the expected values first become zero.

An example set of four minimum prospect reserves graphs are given in Figure 11.2. Each curve shows the minimum anticipated reserves size for a prospect depending on the probability of success. For any given probability of success, any field size lower than that given by the curve would have a negative expected value, and therefore theoretically should not be drilled.

~~Author: Huong Luong Lien December 1998 H 'o I 1 to o c o o E D, E S~~

~~gure 11.2 - An example of minimum prospect reserves graphs $9AJ9S3J o J3AJ3S3J~~

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.7~~

~~11.6 Economic assumptions~~

~~The base case economic assumptions used in the economic analyses are as follows:-~~

• We assume that the oil price is US$18.00 per barrel in 1997 escalating at 3 percent per year. • We assume that the gas price is US$2.50 per thousand cubic feet escalating at 3 percent per year. • We assume that all prices, capital and operating costs escalate at 3 percent per year. • We have calculated net present values using nominal (that is, undeflated) after tax cash flow of a potential field development and a discount rate of 12.5%.

~~In the diagrams shown in this chapter, the base case economics are depicted as bold solid curves. Sensitivity analyses have been carried out by varying the following key economic inputs:-~~

~~• Peak well production rate • Oil/gas price • Capital costs • Fiscal terms (Royalty and the Contractor’s share of profit oil/gas)~~

In doing sensitivity analyses, peak well production rate and capital costs are varied to the lower and upper cases of 50% and 150% of the value assumed for the base case. The oil price sensitivities are US$13 and US$23 per barrel. Similarly, the gas price is varied between US$2.0 and US$3.0 per million cubic feet. As regards fiscal sensitivities, royalty rates are set to zero percent and the Contractor’s profit shares are set to 100% so that we can see the impact of these two fiscal terms on the economics of oil and gas exploration and field development. Although income tax is a critical fiscal component, it is unlikely to vary between individual PSCs (except in special cases). A corporate income tax rate of 50% is stated in Article 33 of Petroleum Law.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.8~~

~~11.7 Market assumptions~~

As regards the economics of developing gas discoveries, it is assumed that a market exists for gas. In practice, this might not always be the case particularly for remote offshore gas discoveries located distance from the existing and proposed infrastructure. The infrastructure and market for gas are discussed in Chapter 4 and 5 respectively.

~~11.8 Development assumptions~~

~~The timing for exploration, appraisal, production and development operations for hypothetical oil and gas fields are shown in Table 11.2.~~

~~Table 11.2 - Exploration and field development timing assumptions Oil Gas Shallow Deep Shallow Unit: contract year Onshore water water Onshore water~~

~~Exploration Timing of seismic 1 1 1 1 1 Timing of discovery 2 2 2 2 2~~

~~Appraisal Period of appraisal 2 to 4 2 to 3 2 to 3 2 to 4 2 to 3~~

~~Field development Development decision 2 2 2 2 2 Period of development 3 to 6 3 to 7 3 to 7 3 to 6 3 to 8~~

Production Production start 3 5 5 5 7 First year of peak production 3 to 5* 5 to 7* 5 to 7* 5 7 Duration of peak production 3 years 1 to 2 1 to 2 10 years 10 years years* years*

~~Footnote: * Depends on field size. See Table 11.3~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.9~~

In all onshore oil and gas development cases, it has been assumed that field development takes place from a central processing centre. Oil production is temporarily stored in tanks. Gas is piped to local power stations.

In all offshore shallow water oil and gas development cases, it has been assumed that field development takes place with one or more fixed production platforms depending on the size of the field and the level of peak production. Oil is stored offshore in the floating, storage and offloading (FSO) tankers and gas is assumed to be sold at the end of a spur pipeline.

In all offshore deep water oil development cases, it has been assumed that multiple tanker based FPSOs (floating production, storage and offloading) and associated subsea systems will be used to develop the field.

~~The exploration programme committed by contractors under production sharing contracts is assumed to include the following:-~~

~~• Acquisition, processing and interpretation of 1,000 kilometres of seismic data • Drilling two exploration wells for offshore blocks or three exploration wells for onshore blocks.~~

~~These exploration programmes are assumed to be carried out in the first two years of the contract with 50% of the total exploration costs incurred in year 1 and the other 50% in year 2.~~

Table 11.3 shows the appraisal, production and development cost phasing assumptions for our hypothetical oil and gas field in different situations. The timing of field development start-up shown in Table 11.2 is potentially variable in all cases, but particularly in the case of offshore gas discoveries. In practice, lead time will depend on the size and nature of the development and its location. However, with gas discoveries, the issues of gas market and transportation might result in a longer lead time. The lack of gas infrastructure in Viet Nam will largely increase the lead time from discovery to field development start-up unless for the future gas discoveries located near the existing Bach Ho gas pipeline or the proposed Nam Con Son pipeline, both in Viet Nam southern basins.

~~Author: Huong Luong Lien December 1998 x I~~

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~~11.9 Onshore north Viet Nam - oil exploration and field development economics~~

Figure 11.3 shows the base case results of economic analyses of developing individual stand-alone representative oil discoveries onshore north Viet Nam over a range of field reserves. Based on these economics, Figure 11.4 shows the minimum reserves size required in an exploration prospect to justify drilling (that is, to give a positive expected value) given the probability of drilling success.

~~Table 11.4 sets out the key base case results presented in Figure 11.3 and 11.4.~~

~~Table 11.4 - Results of economic analyses for base case ■ oil onshore north Viet Nam~~

~~Maximum net present value (US$ per barrel) 2.22 Minimum field reserves (million barrels) 5~~

~~Minimum prospect reserves (million barrels) at a 10% probability of drilling success 76~~

~~Minimum prospect reserves (million barrels) at a 20% probability of drilling success 41~~

Figure 11.5 and Figure 11.6 show the sensitivity analyses carried out for peak well production rate, oil price, capital costs and fiscal terms. These demonstrate that the economics of field development are robust to adverse changes in peak well production rate and oil price.

Figure 11.5 shows that when well productivity decreases to 1.5 thousand barrels per day, the maximum net present value goes down to US$1.64 per barrel. When the oil price is US$13 per barrel, the maximum net present value decreases to US$1.46 per barrel. The economics are less sensitive to capital costs within a [-50,+50] percent range.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.13~~

The fiscal terms sensitivity diagram shows that the two components of the Vietnamese production sharing contract, royalty and the contractor’s share of profit oil, have similar effects on the field development economics of oil discoveries onshore north Viet Nam. If the contractor’s share were set to 100%, the maximum net present value would be as high as US$2.52 per barrel. By comparison, the elimination of royalty charges has as big an effect as the elimination of profit sharing.

Figure 11.6 shows that changes in the peak well productivity and the oil price has greater effects on the exploration economics than changes in the capital costs and the fiscal terms. When the oil price is US$13 per barrel, the minimum prospect reserves at 10% probability of success increases to more than 100 million barrels.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.14~~

~~Figure 11.3 - Base case oil field development economics for onshore north Viet Nam~~

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~~Figure 11.4 - Base case oil exploration economics for onshore north Viet Nam~~

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~~Author: Huong Luong Lien December 1998 p -C 'o jj 1~~

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~~Author: Huong Luong Lien December 1998 igure 11.6 - Sensitivity of oil exploration economics for onshore north Viet Nam~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.17~~

~~11.10 Onshore north Viet Nam - gas exploration and field development economics~~

Figure 11.7 shows the base case results of economic analyses of developing individual stand-alone representative gas discoveries onshore north Viet Nam over a range of field reserves. Based on these economics, Figure 11.8 shows the minimum reserves size required in an exploration prospect to justify drilling (that is, to give a positive expected value) given the probability of drilling success.

~~Table 11.5 sets out the key base case results presented in Figure 11.7 and 11.8.~~

~~Table 11.5 - Results of economic analyses for base case - gas onshore north Viet Nam~~

~~Maximum net present value (US$ per thousand cubic feet) 0.33 Minimum field reserves (billion cubic feet) 30~~

~~Minimum prospect reserves (billion cubic feet) at a 10% probability of drilling success 736~~

~~Minimum prospect reserves (billion cubic feet) at a 20% probability of drilling success 342~~

Figure 11.9 and Figure 11.10 show the sensitivity analyses carried out on peak well production rate, gas price, capital costs and fiscal terms. These demonstrate that the economics of field development are robust to adverse changes in peak well production rate and gas price.

Figure 11.9 shows that when well productivity decreases to 5 million cubic feet per day, the maximum net present value goes down to US$0.27 per thousand cubic feet. When the gas price is US$2.0 per thousand cubic feet, the maximum net present value decreases to US$0.23 per thousand cubic feet. The economics are sensitive to capital costs within a [-50,+50] percent range.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.18~~

The fiscal terms sensitivity diagram shows that the component of the Vietnamese production sharing contract which has the greater effect on the economics is the contractor’s share of profit gas. If the contractor’s share were set to 100%, the maximum net present value would be as high as US$0.38 per thousand cubic feet. In contrast, the elimination of royalty charges has a negligible effect as the royalty rates for gas set by the government are relatively low (between 0% and 10% of the gas production).

Figure 11.10 shows that the economics of exploration are sensitive to adverse changes in peak well production rate, gas price and capital costs. However, they are less sensitive to changes in the fiscal terms. When the gas price is US$2.0 per thousand cubic feet, the minimum prospect reserves at 10% probability of success increases to more than 1,000 billion cubic feet.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.19~~

~~Figure 11.7 - Base case gas field development economics for onshore north Viet Nam~~

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~~Author: Huong Luong Lien December 1998 '■g ” b o 0 E o tx~~

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~~Author: Huong Luong Lien December 1998 gure 11.10 - Sensitivity of gas exploration economics for onshore north Viet Nam~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.22~~

~~11.11 Offshore shallow water north Viet Nam - oil exploration and field development economics~~

Figure 11.11 shows the base case results of economic analyses of developing individual stand-alone representative oil discoveries offshore shallow water north Viet Nam over a range of field reserves. Based on these economics, Figure 11.12 shows the minimum reserves size required in an exploration prospect to justify drilling (that is, to give a positive expected value) given the probability of success.

~~Table 11.6 sets out the key base case results presented in Figure 11.11 and 11.12.~~

~~Table 11.6 - Results of economic analyses for base case - oil shallow water north Viet Nam Maximum net present value (US$ per barrel) 1.83 Minimum field reserves (million barrels) 29~~

~~Minimum prospect reserves (million barrels) at a 10% probability of drilling success 75~~

~~Minimum prospect reserves (million barrels) at a 20% probability of drilling success 48~~

Figure 11.13 and Figure 11.14 show the sensitivity analyses carried out for peak well production rate, oil price, capital costs and fiscal terms. These demonstrate that the economics of field development are robust to adverse changes in peak well production rate and oil price.

Figure 11.13 shows that when well productivity decreases to 1.5 thousand barrels per day, the maximum net present value goes down to US$1.30 per barrel. When the oil price is US$13 per barrel, the maximum net present value decreases to US$0.97 per barrel. The economics are sensitive to capital costs within a [-50,+50] percent range.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.23~~

The fiscal terms sensitivity diagram shows that the component of the Vietnamese production sharing contract which has the greater effect on the economics is the contractor’s share of profit oil. If the contractor’s share were set to 100%, the maximum net present value would be as high as US$2.56 per barrel. By comparison, the elimination of royalty charges has a smaller effect for large field sizes. This is because when royalty charges are eliminated, the resulting positive effect is partly offset by the negative effect of income tax on the contractors’ net cash flow (see Chapter 9).

Figure 11.14 shows that the economics of exploration are sensitive to adverse changes in peak well production rate, oil price and capital costs. However, they are less sensitive to changes in the fiscal terms. When the oil price is US$13 per barrel, the minimum prospect reserves at 10% probability of success increases to nearly 150 million barrels.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.24~~

~~Figure 11.11 - Base case oil field development economics for shallow water north Viet Nam~~

~~Reserves (MMbbl)~~

~~Figure 11.12-Base case oil exploration economics for shallow water north Viet Nam~~

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~~Author: Huong Luong Lien December 1998 H "o 1~~

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.27~~

~~11.12 Offshore shallow water north Viet Nam - gas exploration and field development economics~~

Figure 11.15 shows the base case results of economic analyses of developing individual stand-alone representative gas discoveries offshore shallow water north Viet Nam over a range of field reserves. Based on these economics, Figure 11.16 shows the minimum reserves size required in an exploration prospect to justify drilling (that is, to give a positive expected value) given the probability of success.

~~Table 11.7 sets out the key base case results presented in Figure 11.15 and 11.16.~~

~~Table 11.7 - Results of economic analyses for base case - gas shallow water north Viet Nam~~

~~Maximum net present value (US$ per thousand cubic feet) 0.16 Minimum field reserves (billion cubic feet) 172~~

~~Minimum prospect reserves (billion cubic feet) at a 10% probability of drilling success 879~~

~~Minimum prospect reserves (billion cubic feet) at a 20% probability of drilling success 450~~

Figure 11.17 and Figure 11.18 show the sensitivity analyses carried out for peak well production rate, gas price, capital costs and fiscal terms. These demonstrate that the economics of field development are robust to adverse changes in peak well production rate and gas price.

Figure 11.17 shows that when well productivity decreases to 5 million cubic feet per day, the maximum net present value goes down to US$0.09 per thousand cubic feet. When the gas price is US$2.0 per thousand cubic feet, the maximum net present value decreases to US$0.08 per thousand cubic feet. The economics are very sensitive to capital costs within a [-50,+50] percent range.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.28~~

The fiscal terms sensitivity diagram shows that the component of the Vietnamese production sharing contract which has the greater effect on the economics is the contractor’s share of profit oil. If the contractor’s share were set to 100%, the maximum net present value would be as high as US$0.23 per thousand cubic feet. In contrast, the elimination of royalty charges has a negligible effect for small reserves and a more pronounced effect for large field sizes. This is because the royalty rate for daily production below 5 million cubic metres (that is, 176.57 million cubic feet) is zero (see Chapter 9).

Figure 11.18 shows that the economics of exploration are sensitive to adverse changes in peak well production rate, gas price and capital costs. However, they are less sensitive to changes in the fiscal terms. When the gas price is US$2.0 per thousand cubic feet, the minimum prospect reserves at 10% probability of success increases to nearly 2,000 billion cubic feet.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.29~~

~~Figure 11.15 - Base case gas field development economics for shallow water north Viet Nam~~

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.32~~

~~11.13 Offshore shallow water south Viet Nam - oil exploration and field development economics~~

Figure 11.19 shows the base case results of economic analyses of developing individual stand-alone representative oil discoveries offshore shallow water south Viet Nam over a range of field reserves. Based on these economics, Figure 11.20 shows the minimum reserves size required in an exploration prospect to justify drilling (that is, to give a positive expected value) given the probability of success.

~~Table 11.8 sets out the key base case results presented in Figure 11.19 and 11.20.~~

~~Table 11.8 - Results of economic analyses for base case - oil shallow water south Viet Nam~~

~~Maximum net present value (US$ per barrel) 1.84 Minimum field reserves (million barrels) 33~~

~~Minimum prospect reserves (million barrels) at a 10% probability of drilling success 103~~

~~Minimum prospect reserves (million barrels) at a 20% probability of drilling success 58~~

Figure 11.21 and Figure 11.22 show the sensitivity analyses carried out for peak well production rate, oil price, capital costs and fiscal terms. These demonstrate that the economics of field development are robust to adverse changes in peak well production rate and oil price.

Figure 11.21 shows that when well productivity decreases to 2 thousand barrels per day, the maximum net present value goes down to US$1.32 per barrel. When the oil price is US$13 per barrel, the maximum net present value decreases to US$0.96 per barrel. The economics are sensitive to capital costs within a [-50,+50] percent range.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.33~~

The fiscal terms sensitivity diagram shows that the component of the Vietnamese production sharing contract which has the greater effect on the economics is the contractor’s share of profit oil. If the contractor’s share were set to 100%, the maximum net present value would be as high as US$2.55 per barrel. By comparison, the elimination of royalty charges has a smaller effect for large field sizes. This is because when royalty charges are eliminated, the resulting positive effect is partly offset by the negative effect of income tax on the contractors’ net cash flow (see Chapter 9).

Figure 11.22 shows that the economics of exploration are sensitive to adverse changes in peak well production rate, oil price and capital costs. However, they are less sensitive to changes in the fiscal terms. When the oil price is US$13 per barrel, the minimum prospect reserves at 10% probability of success increases to approximately 200 million barrels.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.34~~

~~Figure 11.19 - Base case oil field development economics for shallow water south Viet Nam~~

~~8 1.25~~

~~Reserves (MMbbl)~~

~~Figure 11.20-Base case oil exploration economics for shallow water south Viet Nam~~

~~Probability of drilling success~~

~~Author: Huong Luong Lien December 1998 - 8~~

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~~Author: Huong Luong Lien Dec< n The economics of petroleum exploration and development in Viet Nam Page 11.37~~

~~11.14 Offshore shallow water south Viet Nam - gas exploration and field development economics~~

Figure 11.23 shows the base case results of economic analyses of developing individual stand-alone representative gas discoveries offshore shallow water south Viet Nam over a range of field reserves. Based on these economics, Figure 11.24 shows the minimum reserves size required in an exploration prospect to justify drilling (that is, to give a positive expected value) given the probability of success.

~~Table 11.9 sets out the key base case results presented in Figure 11.23 and 11.24.~~

~~Table 11.9 - Results of economic analyses for base case - gas shallow water south Viet Nam~~

~~Maximum net present value (US$ per thousand cubic feet) 0.21 Minimum field reserves (billion cubic feet) 162~~

~~Minimum prospect reserves (billion cubic feet) at a 10% probability of drilling success 997~~

~~Minimum prospect reserves (billion cubic feet) at a 20% probability of drilling success 475~~

Figure 11.25 and Figure 11.26 show the sensitivity analyses carried out for peak well production rate, gas price, capital costs and fiscal terms. These demonstrate that the economics of field development are robust to adverse changes in peak well production rate and gas price.

When well productivity decreases to 15 million cubic feet per day, the maximum net present value goes down to US$0.18 per thousand cubic feet. When the gas price is US$2.0 per thousand cubic feet, the maximum net present value decreases to US$0.12 per thousand cubic feet. As seen from Figure 11.25, the economics of field development are not very sensitive to an increase in peak well production rate. However, they are highly sensitive to capital costs within a [-50%,+50%] range.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.38~~

The fiscal terms sensitivity diagram shows that the component of the Vietnamese production sharing contract which has the greater effect on the economics is the contractor’s share of profit oil. If the contractor’s share were set to 100%, the maximum net present value would be as high as US$0.27 per thousand cubic feet. In contrast, the elimination of royalty charges has a negligible effect for low field sizes and a more pronounced effect for large reserves. This is because the royalty rate for daily production below 5 million cubic metres (that is, 176.57 million cubic feet) is zero (see Chapter 9).

Figure 11.26 shows that the economics of exploration are sensitive to adverse changes in gas price and capital costs. However, they are less sensitive to changes in the fiscal terms. When the gas price is US$2.0 per thousand cubic feet, the minimum prospect reserves at 10% probability of success increases to approximately 1,700 billion cubic feet.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.39~~

~~Figure 11.23 - Base case gas field development economics for shallow water south Viet Nam~~

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.42~~

~~11.15 Offshore deep water (350 metres) south Viet Nam - oil exploration and field development economics~~

Figure 11.27 shows the base case results of economic analyses of developing individual stand-alone representative oil discoveries offshore deep water south Viet Nam over a range of field reserves. Based on these economics, Figure 11.28 shows the minimum reserves size required in an exploration prospect to justify drilling (that is, to give a positive expected value) given the probability of drilling success.

~~Table 11.10 sets out the key base case results presented in Figure 11.27 and 11.28.~~

~~Table 11.10 - Results of economic analyses for base case - oil deep water south Viet Nam~~

~~Maximum net present value (US$ per barrel) 1.84 Minimum field reserves (million barrels) 22~~

~~Minimum prospect reserves (million barrels) at a 10% probability of drilling success 158~~

~~Minimum prospect reserves (million barrels) at a 20% probability of drilling success 71~~

Figure 11.29 and Figure 11.30 show the sensitivity analyses carried out for peak well production rate, oil price, capital costs and fiscal terms. These demonstrate that the economics of field development are robust to adverse changes in peak well production rate and oil price.

Figure 11.29 shows that when well productivity decreases to 2.0 thousand barrels per day, the maximum net present value goes down to US$1.03 per barrel. When the oil price is US$13 per barrel, the maximum net present value decreases to US$0.70 per barrel. The economics are sensitive to capital costs within a [-50,+50] percent range.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.43~~

The fiscal terms sensitivity diagram shows that the component of the Vietnamese production sharing contract which has the greater effect on the economics is the contractor’s share of profit oil. If the contractor’s share were set to 100%, the maximum net present value would be as high as US$2.37 per barrel. By comparison, the elimination of royalty charges has a smaller effect for large field sizes. This is because when royalty charges are eliminated, the resulting positive effect is partly offset by the negative effect of income tax on the contractors’ net cash flow (see Chapter 9).

Figure 11.30 shows that the economics of exploration are sensitive to adverse changes in peak well production rate, oil price and capital costs. However, they are less sensitive to changes in the fiscal terms. When the peak well productivity decreases to 2.0 thousand barrels per day, the minimum prospect reserves at 10% probability of success increases to more than 240 million barrels.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page 11.44~~

~~Figure 11.27 - Base case oil field development economics for deep water south Viet Nam~~

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~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page A. 1~~

~~Appendix A - Reserves definitions~~

This appendix summarises the reserves definitions revised by the Society of Petroleum Engineers (SPE)/ World Petroleum Congresses (WPC) Task Force on Petroleum Reserves Definitions which were published in the May 1997 issue of the Journal of Petroleum Technology (JPT), pages 527-528. It also includes the definitions of technical/commercial reserves and potential resources.

“Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward.” (JPT, May 1997). Reserves may be attributed to either natural reservoir forces and energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.

All reserves estimates carry some degree of uncertainty, depending chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principle classifications, either proved or unproved. Unproved reserves are more uncertain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively greater degrees of uncertainty in their recoverability.

Proved reserves “Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations.” (JPT, May 1997).

~~If a single best estimate of reserves is made, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered.~~

~~If a range of reserve estimates and their associated probabilities are generated, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page A.2~~

~~Unproved reserves~~

“Unproved reserves are based on geologic and/or engineering data similar to that used in the estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved.” (JPT, May 1997). The uncertainties associated with reserves estimation can be expressed by allocating appropriate quantities of reserves to the probable and possible classifications.

~~Probable reserves “Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable.” (JPT, May 1997).~~

When a range of reserve estimates and their associated probabilities are generated, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

Possible reserves “Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves.” (JPT, May 1997).

When a range of reserve estimates and their associated probabilities are generated, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page A.3~~

~~Reserve status categories Reserves status categories define the development and producing status of wells and reservoirs. Proved reserves can be categorised as developed or undeveloped.~~

Developed reserves “Developed reserves are expected to be recovered from existing wells including reserves behind pipe. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor.” (JPT, May 1997). Developed reserves may be sub-categorised as producing or non producing reserves.

Producing reserves “Reserves subcategorised as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation” (JPT, May 1997)

~~Non-producing reserves “Reserves subcategorised as non-producing include shut-in and behind-pipe reserves.” (JPT, May 1997). Shut-in reserves are expected to be recovered from:~~

• completion intervals which are open at the time of the estimate but have not started producing, • wells which were shut-in for market conditions or pipeline connections, or • wells not capable of production for mechanical reasons.

~~Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.~~

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page A.4~~

~~Undeveloped reserves Undeveloped reserves are expected to be recovered:~~

• from new wells on undrilled acreage, • from deepening existing wells to a different reservoir, • where a relatively large expenditure is required to recomplete an existing well, or install production or transportation facilities for primary or improved recovery projects.

~~Technical/Commercial reserves According to An Oil and Gas Handbook (1992) of Bank of Scotland, technical and commercial reserves are defined as follows:-~~

~~Technical reserves Technical reserves are theoretically producible at a gross operating margin by for example normal primary or secondary recovery methods.~~

~~Commercial reserves Commercial reserves are restricted to volumes of oil or gas recoverable at an acceptable profitability.~~

Potential resources Potential resources are volumes of oil and/or gas that it is anticipated can be produced from a basin. The estimates are based on data obtained from regional geological and/or geophysical surveys, exploration drilling, and improved recovery methods to be employed in the future.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page B. 1~~

~~Appendix B - Conversion factors~~

~~Length 1 metre = 3.281 feet = 39.37 inches 1 kilometre = 0.621 statute miles~~

~~Volume 1 barrel = 0.159 cubic metres 1 cubic metre = 35.3147 cubic feet~~

Volume/weight equivalents (at 60° F/ 15° C) Crude oil: 1 metric tonne= 7.33 barrels LPG liquids 1 metric tonne = 10.9 barrels Gasoline (pool) 1 metric tonne = 8.5 barrels Middle Distillates 1 metric tonne = 7.5 barrels Fuel Oils 1 metric tonne= 6.8 barrels Asphalt 1 metric tonne= 6.1 barrels

~~Gas, oil and equivalent fuel values~~

1 barrel of oil equivalent = 5,500 to 6,000 cubic feet of natural gas 1 tonne of petroleum products = 1.06 metric tonne of oil equivalent 1 trillion cubic feet of gas (TCF) = 23.31 million metric tonnes of oil equivalent 1 metric tonne of coal = 0.7 metric tonne of oil equivalent 1 Terawatt hours (TWH) or 1 billion kilowatt hours = 0.086 million metric tonnes of oil equivalent

Source: The Oil and Gas Handbook, Bank of Scotland, 3rd Edition, 1992. World Energy Outlook 1998 Edition, the International Energy Agency, 1998. Energy Indicators of Developing Member Countries of ADB, Asian Development Bank, 1992.

~~Author: Huong Luong Lien December 1998 The economics of petroleum exploration and development in Viet Nam Page C. 1~~

~~Appendix C - ABBREVIATIONS~~

~~Abbreviation Explanation~~

~~API American Petroleum Institute bbl barrel~~

~~Bcf billion cubic feet gas (that is, 109 cubic feet)~~

~~Bopd barrels of oil per day cf cubic feet of gas~~

~~FPSO floating production, storage and offloading~~

~~FSO floating, storage and offloading~~

~~GDP gross domestic product~~

~~LPG liquefied petroleum gas~~

~~Mbopd thousand barrels of oil per day~~

~~Mcf thousand cubic feet of gas~~

~~MM million~~

~~MMbbl million barrels~~

~~MMcfd million cubic feet of gas per day~~

~~MMtoe million tonnes of oil equivalent~~

~~NFW new field wildcat~~

~~NPV net present value~~

~~PSC production sharing contract~~

~~SALM single anchor leg mooring~~

~~SPM single point mooring~~

~~Tcf trillion cubic feet of gas (that is, 1012 cubic feet)~~

~~Author: Huong Luong Lien December 1998 References Page R. 1~~

~~The economics of petroleum exploration and development in Vietnam~~

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~~Author: Huong Luong Lien December 1998 References Page R.2~~

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~~Vietnam oil & gas report, volume 3, issue 9, May 1997 and volume 3, issue 10, June 1997.~~

Vo Thi Lien, Downstream development plan on the basis of oil & gas products demand and resources available in Viet Nam, International conference on Dung Quat, Da Nang, Viet Nam, 31/3 - 2/4, 1997, pp. 29-35.

~~World Conservation Monitoring Centre on the web, The Socialist Republic of Viet Nam, http://www. wcmc. org. ukJinfoserv/countryp/vietnam/index, html, 1994.~~

~~Author: Huong Luong Lien December 1998~~