The Economics of Petroleum Exploration and Development in China

By Wanwan Hou

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

January 2009

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

ACKNOWLEDGMENTS

I would like to express my sincere thanks to Mr. Guy Allinson from the School of Petroleum Engineering, University of New South Wales, for his excellent advice and enduring guidance. Without his encouragement and support, my research would have been far more difficult. I thank him for making time for me despite his busy schedules. He gave me great help with my language nearly every day during these two years. I also thank him for his patient reading of my write-ups and for giving me opportunities to conduct occasional research work and tutorials.

I would like to thank all the people that I met or I contacted in Sinopec, CNOOC and CNPC for their willingness to give me advice and help me understanding various aspects of the petroleum industry in China.

I give my deepest thanks to my parents Hongbin Hou and Maolan Fu for their love and support through the years. They encouraged me to come to Australia to undertake this research. They always trust me and understand me even when I doubted myself.

I thank my five best friends in China – Jun, Xiaomu, Ying, Xiaoqing and Jiaye for their great support and love through my ups and downs. They were my second family even if I was thousand miles away from them. I also thank my room mate Lin for his patience and help through my difficult times. ABSTRACT

The international oil and gas industry views China as a key country in its search for petroleum exploration and development investment opportunities. China offers a range of opportunities – from mature, producing areas to frontier exploration areas. When Oil and gas companies make investment decisions to explore for and develop petroleum resources in a particular country, they need to examine many aspects of that country. The decision to invest focuses on assessments of the likely economic rewards and the risks involved.

In this thesis, I attempt to provide a detailed assessment of various factors affecting the economics of petroleum exploration and development in China from an oil and gas investors’ point of view. The thesis is aimed at assisting international oil and gas companies to make investment decisions and assisting their understanding of the petroleum prospects in China.

Based on detailed economic modelling, the thesis aims to demonstrate the profitability of exploration and development of a range of hypothetical but representative oil and gas prospects and discoveries in different areas in onshore and offshore China. The thesis also reviews the key fiscal terms in China and shows the economic impact of individual components of Chinese fiscal terms on field developments in China. The thesis quantifies and analyses the impact of Chinese fiscal terms by measuring the Government Take for a range of hypothetical oil field developments. It includes an analysis of the flexibility of the Chinese fiscal terms by quantifying the effect of Government Take on marginal field developments. In addition, the thesis intends to assess the competitiveness of Chinese fiscal regime in terms of its severity and flexibility as compared to other fiscal regimes in the Asia Pacific Region. Contents Page 1

The economics of petroleum exploration and development in China Contents

Acknowledgements

Abstract Page Chapter 1 Introduction 1.1

Chapter 2 Summary and Conclusions 2.1

Chapter 3 Methodology and Assumptions 3.1 Methodology 3.1 3.2 Assumptions 3.5

Chapter 4 Geography 4.1 Petroleum activities 4.1 4.2 Climate 4.3 4.3 Topography 4.4 4.4 Rivers 4.6 4.5 Vegetation 4.9 4.6 Population 4.10

Chapter 5 Infrastructure 5.1 The economy 5.1 5.2 The labour market 5.3 5.3 Roads 5.4 5.4 Railways 5.5 5.5 Airports 5.6 5.6 Ports 5.8 5.7 Electricity distribution 5.9 5.8 Telecommunications 5.11

Wanwan Hou January 2009 Contents Page 2

Page 5.9 The oil and gas industry 5.12 5.10 Refineries 5.14 5.11 Pipelines 5.17 5.11.1 Crude oil and petroleum product pipelines 5.18 5.11.2 Gas pipelines 5.21

Chapter 6 Energy Market in China 6.1 Crude Oil 6.5 6.1.1 Crude oil reserves 6.5 6.1.2 Crude oil demand/supply 6.6 6.1.3 Crude oil pricing 6.8 6.2 Petroleum products 6.11 6.2.1 Petroleum product supply 6.11 6.2.2 Petroleum product demand 6.12 6.2.3 Petroleum product pricing 6.13 6.3 Natural gas 6.15 6.3.1 Natural gas resources 6.15 6.3.2 Natural gas supply 6.16 6.3.3 Natural gas demand 6.18 6.3.4 Additional natural gas 6.19 6.3.5 Natural gas pricing 6.25 6.4 Coal 6.28 6.4.1 Coal supply 6.28 6.4.2 Coal demand 6.30 6.5 Electricity 6.31 6.5.1 Electricity supply 6.32 6.5.2 Electricity demand 6.34

Chapter 7 Fiscal Regime 7.1 Structure 7.1 7.2 Simplified illustration of workings of Chinese PSC 7.5 7.3 Components of Chinese PSCs 7.7

Wanwan Hou January 2009 Contents Page 3

Page 7.3.1 Royalty 7.8 7.3.2 Value Added Tax 7.10 7.3.3 Cost Recovery 7.10 7.3.4 Profit Sharing 7.13 7.3.5 State Participation 7.15 7.3.6 Signature Bonus and Submission Fee 7.16 7.3.7 Export Duty 7.16 7.3.8 Revenue Windfall Tax 7.17 7.3.9 Income Tax 7.18 7.4 Worked example of a Chinese PSC 7.19

Chapter 8 Fiscal Analyses 8.1 Government Take 8.1 8.2 Fiscal severity and flexibility 8.2 8.3 Assumptions 8.4 8.3.1 Economic assumptions 8.4 8.3.2 Cost assumptions 8.4 8.3.3 Exploration and development timing 8.6 8.3.4 Fiscal terms 8.6 8.4 Analyses of individual components of Chinese fiscal terms 8.9 8.4.1 Single year analysis 8.9 8.4.2 Effect of changing net cash flow 8.12 8.4.3 Project life analyses for marginal field 8.13 8.4.4 Project life analyses for a range of field sizes 8.15 8.5 Impact of fiscal terms on field development – oil price US$80 per bbl 8.20 8.6 Impact of fiscal terms on field development – oil price US$20 per bbl 8.22 8.7 Analysis of Government Take 8.23 8.8 Analysis of minimum economic field size 8.25 8.9 Comparison of fiscal components 8.26 8.10 Effect of fiscal terms on probabilistic field development decisions 8.27

Wanwan Hou January 2009 Contents Page 4

Page 8.11 Effect of Government Take on basin development 8.30 8.12 Summary and conclusions 8.35

Chapter 9 The Comparison of the Fiscal Terms in the Asia Pacific Region 9.1 Comparison of the fiscal terms 9.1 9.2 Assumptions 9.4 9.2.1 Economic assumptions 9.4 9.2.2 Field development assumptions 9.4 9.3 Fiscal severity 9.5 9.4 Regressive/progressive regimes 9.7 9.5 Fiscal efficiency 9.10 9.6 Summary and conclusions 9.14

Chapter 10 Economics of Exploration 10.1 Objectives 10.1 10.2 Cases 10.1 10.3 Approach 10.2 10.4 Assumptions 10.3 10.4.1 Economic assumptions 10.3 10.4.2 Cost assumptions 10.3 10.4.3 Sensitivity assumptions 10.6 10.4.4 Market assumptions 10.7 10.4.5 Exploration and development assumptions 10.7 10.5 Net present value per barrel or per thousand cubic feet graphs 10.11 10.6 Minimum prospect reserves graphs 10.13 10.7 Offshore shallow water China – Bohai Gulf - Oil field exploration and development economics 10.16 10.8 Onshore east China – Bohai Bay Basin - Oil field exploration and development economics 10.21 10.9 Offshore shallow water China – South China Sea - Gas field exploration and development economics 10.26

Wanwan Hou January 2009 Contents Page 5

Page 10.10 Onshore west China – Tarim Basin - Gas field exploration and development economics 10.31 10.11 Summary and conclusions 10.36

Chapter 11 Recommendations 11.1

Appendix A – Conversion factors A.1

Appendix B – Abbreviations B.1

Appendix C – Reserves definitions C.1

Appendix D – Fiscal terms in the Asia Pacific Region D.1

Appendix E – Provisions Concerning the Payment of Royalties for the Exploitation of Offshore Petroleum Resources in China E.1

Appendix F – Measures for the Administration of the Collection of Special Petroleum Proceeds F.1

Appendix G – Enterprise Income Tax Law of the People's Republic of China G.1

References H.1

Wanwan Hou January 2009 Contents Page 6

The economics of petroleum exploration and development in China Contents

List of figures

Figure Page 3.1 Example oil project net cash flow profile 3.2 3.2 Historical oil prices 3.6 4.1Location map of China 4.2 4.2 Major rivers in China 4.8 5.1 China’s GDP growth rate 5.1 5.2 China’s inflation rate 5.3 5.3China railway map 5.6 5.4 Major airports in China 5.8 5.5Major ports in China 5.10 6.1 China's energy flow chart for 2005 6.1 6.2 Changes in government organisations 6.4 6.3 Chinese crude oil reserves 6.6 6.4 Production and consumption of crude oil in china 6.8 6.5 Crude oil benchmark prices 6.10 6.6 Petroleum product production 6.12 6.7 Natural gas reserves in China 6.16 6.8 Gas production in 2005 6.18 6.9 Natural gas supply and demand 6.20 6.10 CBM contract areas by company 6.24 6.11 Coal production 6.29 6.12 China’s electricity output 6.33 7.1 Structure of Chinese PSC 7.4 8.1 Definition of regressive / progressive 8.3 8.2Definition of efficiency 8.4 8.3 Single year fiscal analysis 8.10

Wanwan Hou January 2009 Contents Page 7

Figure Page 8.4 Economic effects of components of Government Take 8.12 – single year analyses 8.5 Economic effects of components of Government Take 8.16 – project life analyses 8.6 Economic effects of Royalty – oil price US$60 /bbl 8.17 8.7 Economic effects of Profit Sharing – oil price US$60 /bbl 8.18 8.8 Economic effects of Export Duty – oil price US$60 /bbl 8.18 8.9 Economic effects of Revenue Windfall Tax – oil price US$60 /bbl 8.19 8.10 Economic effects of Income Tax with depreciation 8.19 – oil price US$60 /bbl 8.11 Economic effects of Income Tax without depreciation 8.20 – oil price US$60 /bbl 8.12 Impact of fiscal terms - oil price US$60 /bbl 8.21 8.13 Impact of fiscal terms - oil price US$20 /bbl 8.23 8.14 Fiscal component as percentage of BTNPV - oil price US$20 /bbl 8.24 8.15 Probability distribution of NPVs before & after Government Take 8.29 8.16 Cumulative probability distribution of NPVs before & 8.29 after Government Take 8.17 Field size distribution 8.31 8.18 Fields that remain undeveloped because of Government Take 8.32 8.19 Oil volumes stranded because of Government Take 8.34 8.20 Field size distribution in China 8.34 9.1 Government Take under Australian PRRT regime 9.6 9.2Government Take 9.7 9.3 Fiscal efficiency of Australian PRRT regime 9.10 9.4Fiscal efficiency 9.11 10.1 An example of net present value per barrel graphs 10.12 10.2 An example of minimum prospect reserves graphs 10.15 10.3 Base case oil field development economic for offshore China 10.18 10.4 Base case oil exploitation economic for offshore China 10.18 10.5 Sensitivity of oil field development economics for areas near 10.19 Zhao Dong Block shallow offshore China

Wanwan Hou January 2009 Contents Page 8

Figure Page 10.6 Sensitivity of oil exploration economics for areas near 10.20 Zhao Dong Block shallow offshore China 10.7 Base case oil field development economic for offshore east China 10.23 10.8 Base case oil exploitation economic for offshore east China 10.23 10.9 Sensitivity of oil field development economics for areas near 10.24 Shengli oil field onshore east China 10.10 Sensitivity of oil exploration economics for areas near 10.25 Shengli oil field onshore east China 10.11 Base case gas field development economic for offshore China 10.28 10.12 Base case gas exploitation economic for offshore China 10.28 10.13 Sensitivity of gas field development economics for areas near 10.29 Yacheng 13-1 gas field shallow offshore China 10.14 Sensitivity of gas exploration economics for areas near 10.30 Yacheng 13-1 gas field shallow offshore China 10.15 Base case gas field development economic for onshore west China 10.33 10.16 Base case gas exploitation economic for onshore west China 10.33 10.17 Sensitivity of gas field development economics for areas near 10.34 Kela 2 gas field onshore west China 10.18 Sensitivity of gas exploration economics for areas near 10.35 Kela 2 gas field onshore west China

Wanwan Hou January 2009 Contents Page 9

The economics of petroleum exploration and development in China Contents

List of tables

Table Page 2.1 Summary of results (Oil price US$80/bbl. Gas price US$6/Mcf) 2.5 5.1 Sector wise growth rates of nominal GDP 5.2 5.2Refineries in China 5.16 5.3 Major oil pipelines in northeast China 5.18 5.4 Major oil pipelines in north China 5.19 5.5 Major oil pipelines in central China 5.19 5.6 Major oil pipelines in east China 5.20 5.7 Major oil pipelines in northwest China 5.21 5.8 Major gas pipelines in China 5.22 6.1 Crude oil balance sheet (Thousand barrels per day) 6.7 6.2 Daqing crude oil spot price FOB (US$/bbl) 6.10 6.3 Consumption of petroleum products in China (Million tonnes) 6.13 6.4 Natural gas production in China (Bcfd) 6.17 6.5 Natural gas consumption in China (MMcfd) 6.19 6.6CBM basins in China 6.24 6.7 Factory prices of the first group of natural gas 6.26 6.8 West-east pipeline gate prices 6.27 6.9 Coal consumption in China (Million tonnes) 6.31 6.10 Top fifteen thermal power plants in China 6.34 6.11 Electricity consumption in China (billion kilowatt hours) 6.35 7.1 Example calculation of the contractors' net cash flow 7.5 in one year under Chinese PSC terms 7.2 Royalty scale for crude oil from offshore China 7.8 7.3 Royalty scale for natural gas from offshore China 7.9 7.4 Royalty scale for crude oil from onshore China 7.9 7.5 Royalty scale for natural gas from onshore China 7.10

Wanwan Hou January 2009 Contents Page 10

Table Page 7.6Cost Recovery Ceiling 7.11 7.7 Profit Sharing for crude oil from onshore China 7.14 7.8 Profit Sharing for crude oil from offshore China 7.14 7.9 Profit Sharing for natural gas 7.15 7.10 Revenue Windfall Tax in China 7.17 8.1 Peak rate and development cost estimation for oil field 8.5 in South China Sea shallow water 8.2 Appraisal, development and production phasing 8.7 8.3 Fiscal assumptions 8.8 8.4 Illustrative calculation of net cash flow over project life 8.14 under Chinese PSC 8.5 Effects of fiscal components on minimum developable field size 8.25 8.6 Mean and Standard Deviation of the variables 8.28 8.7 Oil volumes stranded because of the fiscal terms 8.33 8.8 Oil volumes stranded in China because of the fiscal terms 8.35 9.1 Summary and comparison of oil fiscal terms assumed for 9.2 shallow water 9.2 Peak rate and development cost estimation for oil field 9.5 development in shallow water 9.3 Development and production phasing 9.5 9.4 Ranking of fiscal regimes by severity 9.7 10.1 Cases analysed 10.1 10.2 Peak rate and development cost estimation for base case 10.4 oil fields offshore China (Bohai Gulf) 10.3 Peak rate and development cost estimation for base case 10.5 oil fields onshore east China (Bohai Bay Basin) 10.4 Peak rate and development cost estimation for base case 10.5 gas fields offshore China (South China Sea) 10.5 Peak rate and development cost estimation for base case 10.5 gas fields onshore west China (Tarim Basin) 10.6 Exploration and development schedule in contract years 10.7 10.7 Appraisal, development and production cost phasing for oil fields 10.9

Wanwan Hou January 2009 Contents Page 11

Table Page 10.8 Results of economic analyses for base case oil field 10.16 – offshore shallow water China – Bohai Gulf 10.9 Results of economic analyses for base case oil field 10.21 – onshore east China – Bohai Bay Basin 10.10 Results of economic analyses for base case gas field 10.26 – offshore shallow water China - South China Sea 10.11 Results of economic analyses for base case gas field 10.31 – onshore west China – Tarim Basin 11.1 Comparison of Royalty and Income Tax 11.2

Wanwan Hou January 2009 University of New South Wales

Chapter 1

Introduction

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 1.1

When Oil and gas companies make investment decisions to explore for and develop petroleum resources in a particular country, they need to examine many aspects of that country. The decision to invest is driven by an assessment of the opportunities, the likely rewards and the risks involved. In this thesis, I attempt to provide a detailed assessment of various factors affecting the economics of petroleum exploration and development in China from an oil and gas investors’ point of view. The thesis aims to demonstrate the profitability of exploration and development of hypothetical but representative oil and gas discoveries in different areas in onshore and offshore China and to show the economic impact of Chinese fiscal terms on field developments. In addition, the thesis intends to assess the competitiveness of Chinese fiscal regime as compared to other fiscal regimes in the Asia Pacific Region.

Although many economic evaluations and analyses of oil and gas exploration and development in China have been carried out by Chinese national oil companies as well as international oil companies, the reports are confidential internal company documents. Some economic evaluations are available and sold by service companies (for instance, HIS Energy Services and Wood Mackenzie), but they have limited circulation and are very expensive. Therefore, a comprehensive publicly available study of the economics of petroleum exploration and development in China is essential.

The contents of the thesis are summarised below.

Chapter 3 explains the basic economic methods used in the thesis and oil price assumption. The methodology section includes cash flow analysis, net present value, sensitivity analysis and Monte Carlo Simulation.

Chapter 4 presents a description of the petroleum activities in China, the country’s climate, topography, rivers, vegetation and population.

Chapter 5 describes the economy of China, the key participants in the Chinese oil and gas industry and the oil and gas infrastructure available in China.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 1.2

Chapter 6 gives information on the supply, demand and pricing of crude oil, natural gas, petroleum products, coal and electricity in China.

Chapter 7 contains a description of the Chinese fiscal terms that apply to the Chinese petroleum industry. It also describes the way in which the fiscal terms apply to a hypothetical stand alone field development.

Chapter 8 presents an analysis of the economic impact of individual components of Chinese fiscal terms on field developments in China. It also contains an assessment of the economic efficiency of the fiscal terms – the extent to which they assist or hinder oil and gas field development. In addition, this chapter analyses the effect of Government Take on the profitability and the risks of investing in uncertain field development.

Chapter 9 reviews the fiscal terms for oil in a cross-section of countries in the Asia Pacific Region. It compares the severity and the efficiency of the terms on a consistent basis and show how flexible the terms are in different exploration, development and economic conditions.

Chapter 10 shows the results of economic and sensitivity analysis of field development and exploration in representative areas in China, using the relevant fiscal terms described in Chapter 7.

The thesis does not cover actual field developments, but shows the economics for what are believed to be representative hypothetical developments. The thesis deals only with oil and gas exploration and production economics from a foreign investor’s perspective. It does not cover the economics from the perspective of a state-owned Chinese company. The terms under which the state-owned companies operate oil and gas assets are not publically known. The fiscal terms analysed are only applicable to those foreign companies which invest in China.

The material in Chapter 9 in this thesis has been accepted for publication. The details are –

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 1.3

Conference Details - International Petroleum Technology Conference (IPTC) 3-5 December 2008 Kuala Lumpur, Malaysia Paper Title - The Comparison of the Severity and the Efficiency of Fiscal Terms in the Asia Pacific Region Paper Number - IPTC 12615

A limited number of peer-reviewed papers and publications are available on this topic in the public domain. Those publications that are available have been referenced in this thesis. The main sources of data for the thesis are market intelligence reports, oil and gas companies’ annual reports, newspapers and online news related to petroleum industry, statistical yearbooks, websites of Chinese Government and oil and gas companies and personal communication with people working in Chinese national oil and gas companies.

Wanwan Hou January 2009 University of New South Wales

Chapter 2

Summary and Conclusions

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 2.1

Geography

China is located in the East Asia. It is bordered by North Korea, Mongolia, Russia, Kazakhstan, Kyrgyzstan, Tajikistan, Afghanistan, Pakistan, India, Nepal, Bhutan, Myanmar, Laos and Vietnam.

The climate and terrain of a country can have a considerable influence on petroleum activities in the country and can have a significant effect on the decision to explore for and develop oil and gas assets. For instance, unfavourable climatic conditions, or rough terrain, or remoteness would make petroleum exploration and development more difficult and potentially increase the costs associated with the activities.

With a vast land area, the climate in China is extremely varied. North China has a sub-arctic climate and the southmost China has a subtropical climate. It is moist in the eastern China and arid in the western China. The terrain consists of mountains, hills and plateaux mostly in the west and plains and deltas in the east.

Nearly 80 percent of the petroleum activities are onshore China. Most mature oil and gas fields are located in the eastern China where the geographical risk is very low. In recent years, China has put much effort into exploring for oil and gas resources in the western China in the highlands and desert. These areas often require the application of advanced technologies and have recently been offered to foreign companies. Most offshore petroleum exploration and development in China are in the shallow water areas.

Politics and environmental issues

China has 23 provinces (World Bank, 2002; Food and Agriculture Organization of the United Nations, 1999; United Nations, 2006), 5 autonomous regions, 4 municipalities and 2 Special Political Zones (Hong Kong and Macao). There are few political obstacles to petroleum exploration and development activities in China, although the administration of such activities is highly centralised. The Government strives to

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 2.2 provide a stable and secure business environment for companies operating in the country.

Companies operating in offshore areas in China must take into account environmental protection in accordance with the guidelines the Administration of Environmental Protection in the Exploration and Development of Offshore Petroleum issued by the State Council.

Infrastructure

With the rapidly growing economy in the past three decades in China, the infrastructure in most areas in China has grown rapidly. This includes extensive road and railway networks, a great number of airports and seaports and well-distributed telephone and electricity networks. China has a large number of oil refineries, but the average size is small, being less than a half of the world average. A number of large-scale refineries each with a capacity of over 10 million tonnes per year are under construction and will come online over the next three to five years. The existing and planned pipeline network for crude oil, natural gas and petroleum product assists the development and production of petroleum in China. China also has a large labour force.

Energy market

China’s booming economy drives its demand for energy. Although China produces a large volume of crude oil, its domestic production is much less than the demand. At present, about 45% of its crude oil consumption depends on imported oil. The percentage is expected to increase further in the long term. The production of petroleum products has increased along with the growth in refining capacity, but still can not satisfy the country’s demand. Natural gas production only contributes 3.3% to China’s energy production and its consumption accounts for 2.9% of the total energy consumption. The domestic production and the consumption of natural gas are basically in equilibrium for the present. However, as a clean energy, the demand for natural gas will continue increasing dramatically in the future. The discovery of the

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 2.3 giant Puguang gas field in Sichuan Basin by China National Petrochemical Corporation (Sinopec) and several transnational gas pipelines currently under construction will help meet the country’s demand for natural gas.

Fiscal regime

The Chinese fiscal regime for foreign investors is based on Production Sharing Contracts (PSCs). Ignoring the effect of state participation, for profitable discoveries, the discounted Government Take from field development is between 55% and 59% depending on the field size, oil and gas prices and the terms negotiated.

The main components of a typical Chinese PSC are as follows -

 A Value Added Tax (VAT) rate of 5% of Gross Revenue.

 A Royalty rate of between 0% to 12.5% of Gross Revenue for oil production and between 0% to 3% for gas production.

 A Cost Recovery Ceiling of 60% of Gross Revenue for onshore discoveries and 50% to 62.5% for offshore discoveries.

 A contractors’ share of Profit Petroleum varying from 98% to 40% depending on the level of production. Concessions are given to crude oil production from offshore areas.

 State Participation is typically 51% on a carried basis.

 A Signature Bonus of US$1 million.

 An Export Duty rate of 5% of crude oil exports from offshore fields.

 A Revenue Windfall Tax rate of between 20% and 40% of contractors’ crude oil production depending on oil prices.

 An Income Tax rate of 25% of taxable income.

Fiscal analyses show that royalty has the biggest impact on the development of marginal fields. However, for larger fields, income tax has the greatest effect. Revenue Windfall Tax becomes significant with increases in the oil price. The study also shows that the Chinese fiscal regime is regressive for fields with low profitability (low field size, low oil price or the combination of both). It tends to damage the

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 2.4 development of these fields and can render them uneconomic. Uncertainty analyses show that the probability of the field development being uneconomic increases significantly after Government Take. Depending on the oil price, significant volume of oil might be left stranded because of the effect of the fiscal regime.

Comparison of fiscal regimes in the Asia Pacific Region

Based on the definition of efficiency given in section 8.2, the comparison of fiscal regimes in the Asia Pacific Region shows that the ranking of the fiscal regimes in the Asia Pacific Region from the most severe to the most lenient is – Indonesia, Vietnam, Thailand, Bangladesh, Philippines, Australia PRRT, China offshore and India NELP. The discounted Government Take for profitable projects varies from 54% to 87% depending on the regime. Excluding the effects of State Participation, petroleum activity under the Chinese offshore fiscal regime would give companies higher returns than under most of the other regimes.

The analyses also show that the Indonesian, Vietnam, Philippine and Australian fiscal regimes are regressive. The Chinese, Bangladesh, Thailand and Indian regimes are regressive for marginal fields and become progressive when fields become more economic. The progressive component of the regimes is generally the Profit Sharing mechanism.

In addition, the analyses show that the ranking of the regimes from the most inefficient to the most efficient is – Indonesia, Vietnam, Thailand, Philippines, Bangladesh, Australia PRRT, China offshore and India. Therefore, the Chinese offshore fiscal regime is less inefficient than most of the other regimes in the Asia Pacific Region analysed in this thesis.

The regressive and inefficient components in the Chinese fiscal terms analysed include Royalties, Cost Recovery Ceiling, those aspects of Profit Sharing that are not based on net cash flow and depreciation of costs for Cost Recovery and Income Tax. These components are applied without regard to the before-take net cash flow of the project. They tend to prevent the development of small and marginal fields.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 2.5

Economics of exploration

Table 2.1 summarises the results of the economic analyses of hypothetical, but representative field exploration and development in different areas across China. An oil price of US$80 per barrel and a gas price of US$6 per thousand cubic feet are assumed. The analyses include the effects of State Participation.

Table 2.1 shows a) the minimum economic field size of field development assuming a discovery has already been made, b) the profitability of profitable field development and c) the minimum prospect size of field exploration at a probability of success of 20%. The minimum prospect sizes for other probabilities of success from 10% to 100% are given in Chapter 10.

 Table 2.1 - Summary of results (Oil price US$80/bbl. Gas price US$6/Mcf)     Field development Exploration Minimum Maximum NPV Minimum prospect Cases economic of large field reserves at 20% reserves development POS* Oil MMbbl US$/bbl MMbbl Shallow water China - Bohai gulf 7.3 9.5 31.0 Onshore east China - Bohai Bay Basin 4.1 10.8 13.4   Gas Bcf US$/Mcf Bcf Shallow water China - South China Sea 219 0.42 752 Onshore west China - Tarim Basin 62 0.72 117 * POS = Probability of success

The minimum economic discovered oil reserves and the minimum prospect reserves required onshore east China are lower than those required in shallow water areas on the east coast of China. The minimum economic reserves required to justify gas field development in onshore west China is significantly smaller than that in shallow water areas in the South China Sea. These results primarily reflect the lower costs of exploration and development onshore as compared to offshore.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 2.6

The results indicate that if the Chinese fiscal terms are applicable in these areas, large volumes of discovered oil or gas would remain undeveloped and significant numbers of oil or gas prospects would remain unexplored.

In summary, excluding the effects of State Participation, the Chinese petroleum fiscal terms are relatively lenient and flexible by comparison with those of the China’s neighbours. However, the inefficiencies in the regime in some circumstances could lead to substantial volumes of oil and gas remaining undeveloped because of the fiscal terms. When including the effects of State Participation, the Chinese fiscal terms could significantly hinder the oil and gas exploration in China.

Wanwan Hou January 2009 University of New South Wales

Chapter 3

Methodology and Assumptions

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 3.1

In this chapter, I present the main economic methods and assumptions I use to carry out economic analyses of fiscal terms and of potential exploration and field developments in China.

3.1 Methodology

The economic methods used to carry out the analyses in this study include cash flow analysis, sensitivity analysis and Monte Carlo Simulation.

Cash flow analysis

Cash flow is simply the cash received and the cash expended over a defined period of time. Net cash flow (NCF) is simply the cash received less the cash expended during the period. The equation for net cash flow is given below.

Net cash flow = Cash received in the period less Cash expended in the period

For an oil and gas project, the cash received is usually the gross revenue obtained from the sales of petroleum. The cash spent include exploration costs, development costs, operating costs, abandonment costs and Government Take.

Gross revenue is calculated by multiplying together the petroleum production in each year and the price for the certain product.

Exploration costs are one-off costs incurred before a development take place.

Development costs are also one-off costs incurred at the beginning of a project. These are sometimes referred to as capital costs, although, strictly speaking, capital costs also include exploration costs.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 3.2

Operating costs occur periodically and are necessary to maintain production from the field. They are usually small compared to the initial capital costs.

Abandonment costs are a special category of capital expenditure associated with making good or abandoning an oil or gas field at the end of field life once it has become uneconomic to continue producing.

Government Take is the total amount of cash flow the government received through royalties, profit sharing, income taxes and similar imposts. It excludes State participation. Typically, Government Take is the largest component of net cash flow during the productive life of a field.

Figure 3.1 illustrates the typical net cash flow profile for an oil and gas project.

Figure 3.1 – Example oil project net cash flow profile

Cash flow Gross Revenue

Operating Costs

Government Take

Net Cash Abandonment Costs Flow

1 2 3 4 5 6 7 8 9 10 Years

Capital Costs

Source: Allinson, W. G. (2007). Lecture notes distributed in the unit. PTRL5008 Petroleum Production Economics. University of New South Wales. Kensington on 27 February 2007.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 3.3

Generally speaking, the first large components of cash flow are the initial capital expenditures incurred in the first several years of a project life before production starts. Once production starts, the company will receive gross revenue from the sales of petroleum. Annual operating costs are usually small compared with capital costs. The largest component of cash flow during the productive life of a field is "Government Take", which is the net cash flow that goes to the Government. The remaining costs are abandonment costs. Usually these are incurred at the end of field life when it is no longer economic to continue production. The remaining revenue is the companies’ net cash flow. This money is free for companies to spend on other projects or add to monetary reserves. The companies’ net cash flow is the basis on which companies determine the feasibility of a project and the attractiveness of the investment.

Net Present Value (NPV)

Throughout this study, I use net present value (NPV) as the economic indicator to interpret the results of economic analyses. An NPV is the present value of a net cash flow occurring sometime in the future. It measures how much a project is worth compared with an alternative investment. NPV is calculated by adding together the discounted net cash flow (NCF) in each year of project life. The equation of NPV is shown below.

n NCF NPV  y B y y  i)1(

Where – y = Year “y” n = Total number of years of NCF i = Discount rate (the return on the alternative investment)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 3.4

Sensitivity analysis

Oil and gas projects are subject to uncertainties, such as oil and gas prices, capital costs, production profiles and sometimes fiscal regimes. In this study, I carry out sensitivity analysis to evaluate the effects of changes in each input variable.

Sensitivity analyses involve varying one input variable within a certain range with other variables remain unchanged. The results of a sensitivity analysis illustrate the impact of the uncertainty of each input variable on the profitability of a project.

Monte Carlo Simulation

Monte Carlo simulation is a means of combining the probability distributions of input variables to derive the probability distribution of the output of the analysis. It illustrates the effect of uncertainty better than sensitivity analyses because it shows the effect of uncertainty in several inputs, rather than one at a time and it incorporates the effect of uncertainty and correlation between variables.

The first step for carrying out a Monte Carlo Simulation is to estimate or select an appropriate probability distribution for selected input variables. Probability distributions that are commonly used include normal distributions, lognormal distributions, triangular distributions, uniform distributions, and so on. The second step is to select an output variable for the analysis. For the analyses in this report, the output is the NPV. After defining the selected input variables by probability distributions and selecting an output, we run the Monte Carlo Simulation to determine the probability distribution of the output.

For each run of Monte Carlo simulation, a value from each input distribution is selected at random. With a set of random samples of all input variables, the simulator calculates one result (an NPV). This result is saved. After thousands of runs, we will have stored thousands of NPVs, which can be used to derive a smooth probability distribution of NPV. The probability distribution of the NPV will reflect the probability distributions of the input variables.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 3.5

3.2 Assumptions

The economic assumptions I made in the analyses in this study are set out below.

Oil price assumption

I choose to use a US$80 per barrel as the real oil price in year 2008 terms for many of the base case economic analyses carried out for this thesis. However, in the chapter of fiscal analysis, for the purposes of illustrating certain points, I also used US$60 per barrel as the real oil price in 2008 terms.

During June and July 2008, the spot prices of some crude oil such as Indonesia Minas, Malaysia Tapis and Brent soared to more than US$140 per barrel. It is only recently that nominal oil prices have increased to such high levels. According to a survey in April 2008, most US financial executives from oil and gas companies believe that the price of crude oil will drop below US$100 per barrel by the end of 2008 (SPE news, 2008:18).

In order to determine an appropriate crude oil price for the analyses in this thesis, I use the recent historical price data for Indonesia Minas crude oil. Figure 3.2 shows the moving trend of the Minas crude oil price. I choose Minas crude oil for the analysis, because the quality of the crude oil in the basins I analysed is similar to that of Minas.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 3.6

Figure 3.2 - Historical oil prices

160

140

120

100

80 US$73/bbl

60 Oil price (US$/bbl) price Oil 40

20 Year 0 2005 2006 2007 2008

* Prices quoted are for Indonesia Minas crude oil (from 7 January 2005 to 1 August 2008) Source: World Crude Oil Prices, 2008.

The mean of the historical oil prices over the period from 2005 to the present is US$73 per barrel. The data indicate that 90% of the time the oil price was more than US$53 per barrel and 10% of the time the oil price was more than US$104 per barrel.

Given that the mean of the oil price distribution from above is US$73 per barrel, after considering the more recent movement of crude oil prices, I choose to use US$80 per barrel as a base case oil price to evaluate the economics of oil exploration and development in China. However, oil prices are very uncertain and so in the sensitivity analyses and fiscal analyses carried out in this thesis, I vary the oil price between US$20 per barrel and US$140 per barrel.

Other economic assumptions

I assume the escalation rate for oil and gas prices and all types of costs is a constant 3% per year over the life of the projects I analyse.

I calculate the nominal NPV of a project using a nominal discount rate of 10%. The nominal discount rate is the nominal return obtained on an alternative investment

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 3.7 with similar risk. In practice, the discount rate is normally determined by companies based on a risk-free rate of return plus a premium for risk that relates to a company’s shareholders’ assessment of the risk associated with the company’s investments. Therefore, the discount rate varies from company to company. In the current investment climate oil and gas companies typically use 10% as their nominal discount rate. Therefore, I adopt a 10% nominal discount rate for the analyses in this thesis.

Wanwan Hou January 2009 University of New South Wales

Chapter 4

Geography

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.1

China is located in the East Asia on the western shore of the Pacific Ocean (see Figure 4.1). China has a boundary 22,800 kilometres long. It is bordered by North Korea to the east, Mongolia to the north, Russia to the northeast, Kazakhstan, Kyrgyzstan and Tajikistan to the northwest, Afghanistan, Pakistan, India, Nepal and Bhutan to the west and southwest and Myanmar, Laos and Vietnam to the south (National Bureau of Statistics of China, . 2007:1-2).

China has a land area of about 9.6 million square kilometres, ranking it the third largest country in the world after Russia and Canada. Form north to south, the territory of China stretches from the centre of the Heilong River north of the town of Mohe to the Zengmu Reef at the southernmost tip of the Nansha Islands, covering a distance of 5,500 kilometres. From east to west, China extends from the confluence of the Heilong and Wusuli rivers to the Pamirs - a distance of 5,200 kilometres (China’s Geography, 2008).

China has a coastline of 32,000 kilometres including the island territories, or 18,000 kilometres of coastline without the islands. The Chinese mainland is flanked to the east and south by the Bohai Bay, Yellow Sea, East China Sea and South China Sea. It has a total maritime area of 4.73 million square kilometres. About 5,400 islands are scattered in China's territorial seas, with a total area of 38,700 square kilometres. The largest island is Taiwan with an area of about 36,000 square metres, followed by Hainan with an area of 34,000 square kilometres (National Bureau of Statistics of China, 2007:1-2).

China has 23 provinces (including Taiwan), 5 autonomous regions, 4 municipalities and 2 Special Political Zones (Hong Kong and Macao).

4.1 Petroleum activities

As at 2006, petroleum exploration and production were being carried out in 1,601 licenses, covered a total area of 2,795 thousand square metres, of which 79% are

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.2 onshore and 21% are offshore. Exploration work is in progress in 1,152 blocks in onshore and offshore China (Xue, 2007:5).

Figure 4.1 – Location map of China

%RKDL%D\

Since 1982, the government has openly invited tenders from overseas companies for the exploration for oil and gas in its offshore blocks. Since the early 1990s, some of the onshore blocks have been opened to foreign companies as well. Up to now, more than 150 PSCs have been signed for exploration and development in offshore areas and about 50 PSCs have been signed for onshore areas. As of end-2006, a total of 39 international companies had working interest in 85 officially valid license areas which cover a total of 209,777 square kilometres in onshore and offshore China (Xue, 2007:5).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.3

The major national and foreign companies operating in China are - a) onshore - China National Petroleum Corporation (CNPC), China Petroleum and Chemical Corporation (Sinopec), Yanchang, Asian American Coal, Chevron, China Link, ConocoPhillips, Far East Energy, Genting, Gladstone, Greka, MI Energy, Shell, Sunwing, TerraWest, Total, Verona, b) offshore - China National Offshore Oil Corporation (CNOOC), SPC, Anadarko, BG, BP, CACT, Chevron, ConocoPhillips, Devon, EDC, Husky, JHN, Newfield, Primeline, Roc Oil, Statoil and TARC (Xue, 2007:5).

China continues to attract interests from international oil and gas companies, with Husky’s Liwan 3-1 deepwater gas discovery, Sinopec’s Puguang gas giant and PetroChina’s Nanpu oil giant. In 2006, CNOOC announced the 2006 round of 13 blocks available to foreign companies. In March 2007, CNOOC announced its 2007 bidding round with 22 blocks in offshore China. PetroChina also offered a total of 12 blocks in the Tarim Basin in the northwest onshore China (Xue, 2007:6).

4.2 Climate

The climate in China is extremely diverse. It ranges from subtropical in the far south to sub-arctic in the north and from the monsoon climate of eastern China to the aridity of the northwest.

Most areas in China are in the North Temperate Zone, characterised by distinctive seasons. Monsoon winds, caused by differences in the heat-absorbing capacity of the continent and the ocean, dominate the climate in China. From September to April in the following year, dry and cold winter monsoons blow from Siberia and the Mongolian Plateau resulting in cold and dry winters. Form April to September, warm and humid summer monsoons blow from the seas in the east and south, resulting in overall high temperatures and plentiful rainfall.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.4

Temperature

In terms of temperature, China can be divided from south to north into equatorial, tropical, subtropical, warm-temperate, temperate and cold-temperate zones. In winter, the temperature differences between north and south China are great, but in summer there is considerable less diversity. For instance, the northern parts of Heilongjiang Province which is the northmost province in China experience an average temperature of minus 30 oC in January. The central and southern parts of Guangdong Province experience an average January temperature of above 10 oC. By contrast, in July, except in the Qinghai-Tibet Plateau, the average temperature in most areas in China is above 20 oC.

Precipitation

The precipitation in China varies even more than temperature. Precipitation gradually declines from the southeastern coastal areas to the northwestern inland areas. The annual precipitation varies greatly from place to place. Areas to the south of the Qinling mountains experience abundant rainfall, most of which comes with the summer monsoons. To the north and west China, however, rainfall is very uncertain. In southeast coastal area, the annual average precipitation exceeds 1,600 millimetres, while in some areas in the northwest it drops to below 50 millimetres. There is no precipitation at all in the desert areas (National Bureau of Statistics of China, 2007:1- 3).

4.3 Topography

Topography in China varies greatly in China. Mountains cover 33 percent of China’s landmass, plateaux 26 percent, basins 19 percent, plains 12 percent and hills 10 percent. In other words, the area of mountains, hills and plateaus accounts for 69 percent of the total land area of China (National Bureau of Statistics of China, 2007:1-4).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.5

The terrain of China gradually descends from west to east like a staircase. It can be divided into four “steps”.

The first “step” is the Qinghai-Tibet Plateau enclosed by Himalayas and Kunlun Mountains. It encompasses most of Tibet Autonomous Region and part of Qinghai Province. The Qinghai-Tibet Plateau is the most extensive plateau in the world, averaging more than 4,000 metres above sea level. It is called “the roof of the world”. In the Himalayan Mountains, the world’s highest peak is Mount Everest (known in China as Mount Qomolangma), soaring 8,844 metres above sea level. It crosses over the boundary of China and Nepal (The Geography of China, 2000).

The spine of the Kunlun Mountains separates into several branches. The northern branches, the Altun Shan and the Qilian Shan, border the Qinghai-Tibet Plateau and overlook the Qaidam Basin, a sandy and swampy region containing many salt lakes. A southern branch divides the watersheds of the Huang He and the Yangtze River.

The second “step” includes the gently sloping Inner Mongolia Plateau, the Loess Plateau, the Yunnan-Guizhou Plateau, the Tarim Basin, the Junggar Basin and the Sichuan Basin. The average elevation in these regions is between 1,000 and 2,000 metres. A continental scarp marks the eastern margin of this territory. The scarp extends from the Greater Hinggan Range in northeastern China through the Taihang Shan (a range of mountains overlooking the North Chian Plain) to the eastern edge of the Yunnan-Guizhou Plateau in the south (The Geography of China, 2000).

The Tarim Basin is the largest inland sedimentary basin in China. It covers a diamond- shaped area of 572,700 square kilometres (Wang, et al. 1992:5).

North of the 3,300 kilometre long Great Wall, between the Gansu Province on the west and the Greater Hinggan Range on the east, is the Inner Mongolia Plateau at an average elevation of 1,000 metres above sea level. The Inner Mongolian Prairie is China’s largest natural pastureland and home to the famous Sanhe horses, Sanhe cattle and Mongolian sheep. To the south is the Loess Plateau, covering 600,000

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.6 square kilometres in Shaanxi, parts of Gansu and Shanxi provinces, and some of Ningxia Hui Autonomous Region.

The third “step” begins at the scarp line which is the eastern margin of the second “step” and extends eastward to the coast of the Pacific Ocean. Its elevation drops to between 500 and 1,000 metres above sea level. This territory, from north to south, includes the Northeast Plain, the North China Plain and the Middle-Lower Yangtze Plain. These regions are of dense population and intensive cultivation (The Geography of China, 2000).

To the east of the third “step”, the land extends out into the ocean and forms the fourth step of the staircase. The water depth is less than 200 metres.

4.4 Rivers

China has 50,000 rivers with total length of about 420,000 kilometres. Each of them has a catchment area of more than 100 square kilometres. About 1,500 of these rivers have catchment areas above 1,000 square kilometres. Most of the major rivers have their source on the Qinghai-Tibet Plateau in the west and drop greatly to the east and empty into the Pacific Ocean. As a result, China is rich in hydropower resources (The Geography of China, 2000).

The major rivers in China are Yangtze River (Chang Jiang), Yellow River, Heilong River, Pearl River (Zhujiang), Liaohe, Haihe and Huaihe.

Figure 4.2 shows the major rivers in China.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.7

Yangtze River

Known as “Long River” in Chinese, Yangtze River has a total length of 6,300 kilometres. It is the longest river in China and the third longest river in the world after the Nile in Africa and the Amazon in South America. The Yangtze has a catchment area of 1.8 million square kilometres. It is also known as the “golden waterway” which is an important trade and transportation route in China. The Yangtze has vast hydroelectric potential. It rises in the steep forested gorges in Qinghai-Tibet Plateau and flows though important agricultural regions in Central China which have a warm and humid climate, plentiful rainfall and fertile soil. About 300 million people live along its middle and lower reaches. These people cultivate a vast rice and wheat producing area. The Sichuan Basin, with a mild, humid climate and a long growing season, produces a rich variety of crops. It is also a leading silk producing area and an important industrial region with substantial mineral resources.

Yellow River

The second longest river in China is the Yellow River with a total length of 5,464 kilometres. The Yellow River rises in Tibet and travels through North China before reaching the Bohai Bay. It has a catchment area of 752,000 square kilometres. The Yellow River valley was one of the birthplaces of ancient Chinese civilizations. It has lush pasture lands along its banks, flourishing agriculture and abundant mineral deposits.

Heilong River

The Heilong River is a large river in northeast China with a total lenth of 4,350 kilometres, of which 3,101 kilometres are in China and the additional 1,249 kilometres are in Russia, where it is known as the Amur.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.8

Figure 4.2 – Major rivers in China

Heilong River

Liaohe Hai River

Yellow River Huai River

Lancangjiang Yangtze River

Pearl River

Pearl River

The longest river in the south of China is the Pearl River, which is 2,214 kilometres long. Together with its three tributaries - the Xi, Dong and Bei (West, East and North) rivers, it forms the rich Pearl River Delta near Guangzhou, Zhuhai, Macau and Hong Kong.

Other major rivers

The Hai River (Haihe) in the north, like the other major waterways, flows from west to east. Its upper reaches consist of five rivers that converge near Tianjin and then flow seventy kilometres before emptying into the Bohai Bay. Another major river, the

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.9

Huai River (Huaihe), rises in Henan Province and flows through several lakes before joining the Pearl River near Yangzhou. Other major rivers are the Liaohe in the northeast, Qiantangjiang in the east and Lancangjiang in the southwest.

In addition, China has a famous man-made river - the Grand Canal, running from Beijing in the north to Hangzhou in Zhejiang Province in the south. The construction work first began in the fifth century A.D. With a total length of 1,801 kilometres, the Grand Canal is the longest as well as the oldest man-made waterway in the world. It links five major rivers: the Haihe, Yellow River, Huaihe, Yangtze River and Qiantangjiang.

4.5 Vegetation

China has about 32,000 species of plant, accounting for one eighth of the world’s total (Plants and animals, 2006). The massive diversity of geography in China has resulted in an extraordinary range of plants. China’s plant species include almost all the major plants that grow in frigid, temperate and tropical zones in the northern hemisphere. The south China shares tropical rainforests with Laos, Vietnam and Myanmar, while the Great Hinggan Range in Inner Mongolia has tundra vegetation on top of permafrost.

China contains 175 million hectares of forests which cover 18% of its total land area (National Bureau of Statistics of China, 2007:1-4). China’s forests are mainly in the remote northeastern and southwestern areas. The types of forests vary. The Greater Hinggan, Lesser Hinggan and Changbai mountain ranges in the northeast are China’s largest natural forest areas. Major tree species found here include conifers, such as Korean pine, larch and Olga Bay larch and coniferous broadleaf trees such as white birch, oak, willow, elm and northeast China ash. Subtropical forests dominate central and southern China. Major tree species in the southwest include the dragon spruce, fir and Yunnan pine, as well as teak, red sandalwood, camphor, nanmu and padauk. Xishuangbanna in the south of Yunnan Province is a rare tropical broadleaf forest

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.10 area in China. It contains more than 5,000 plant species and is often called “the kingdom of plants”.

Grasslands in China cover an area of 400 million hectares, stretching more than 3,000 kilometres from the northeast to the southwest. Grasslands make up more than one third of China’s total land area. The vast and productive grasslands are largely concentrated in Inner Mongolia. Ningxia, parts of Qinghai and Tibet. The Inner Mongolian Prairie is China’s largest natural pastureland. There are some important natural pasturelands in north and south of the Tianshan Mountains in Xinjiang Province which are ideal for stockbreeding. The government has recently stepped up efforts to control the conversion of grasslands to pasture but lack sufficient manpower to enforce the policy.

In China, 130 million hectares of land is cultivated. Cultivated land is mainly located in east China on the Northeast Plain, the North China Plain, the Middle-Lower Yangtze Plain, the Pearl River Delta and the Sichuan Basin (National Bureau of Statistics of China, 2007:1-4). The Northeast Plain contains the fertile black soil, which is abundant in wheat, corn, sorghum, soybeans, flax and sugar beet. The brown topsoil in the North Chian Plain is planted with wheat, corn, millet and cotton. The Middle-Lower Yangtze Plain’s flat terrain and many lakes and rivers make the area very suitable for paddy rice and freshwater fish. The Pearl River Delta is also abundant with paddy rice. The purplish soil in the warm and humid Sichuan Basin is green with crops in all seasons. The main crops include paddy rice, rapeseed and sugarcane.

4.6 Population

China is the first most populous country in the world. In the end of 2007, China’s population was estimated to be 1.32 billion with an annual growth rate of 0.52% (National Bureau of Statistics of China, 2007:4-1).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 4.11

The average population density is 138 people per square kilometre (Population Reference Bureau, 2007). The country’s most densely populated regions are in the east and southeast coastal areas in China. About 56% of the population lives in rural areas and the remaining 44% in urban areas (National Bureau of Statistics of China, 2007:4-1). The three most populated cities are Chongqing with 28 million, Shanghai with 18.2 million and Beijing with 15.8 million (National Bureau of Statistics of China, 2007:4-4).

More than one third of China’s population is under 25 years of age. China has a literacy rate of 95.2 percent for males and 87.1 percent for females (National Bureau of Statistics of China, 2007:4-1).

Wanwan Hou January 2009 University of New South Wales

Chapter 5

Infrastructure

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.1

In this chapter I discuss those aspects of economy and infrastructure in China which are relevant to the petroleum industry. The economy and the level of development of the infrastructure affect the planning, timing and costs of construction as well as operation of a new petroleum project.

5.1 The economy

Figure 5.1 shows the annual average growth rate of the nominal Chinese GDP from 1978 to 2007. The average growth of China’s Gross Domestic Product (GDP) per year in this period was 9.9 percent. Major contributors to this were the market reforms and liberalisation announced by the central government in 1978. In November 2007, China’s nominal GDP has increased to US$3.42 trillion, the third largest in the world after the United States and Japan. As regards GDP measured on a Purchasing Power Parity (PPP) basis, China has the second largest economy after the United States (Economy Watch, 2008)

Figure 5.1 - China's GDP growth rate

16%

14% 13.5%

11.7% 11.4% 12% 10.9% 11.1% 10.4% 10.0% 10.1% 10% 9.1% 8.4% 8.3% 7.8% 8%

6% Percentage (%) Percentage 3.8% 4%

2%

0% 1978 1980 1985 1990 1995 2000 2001 2002 2003 2004 2005 2006 2007 Year

Source: National Bureau of Statistics of China, 2007:3-1; Economy Watch, 2008.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.2

In spite of the high GDP growth, China’s nominal per capita income was only US$2,360 in 2007, which is low when judged against world standards (China Daily, 27 October 2008).

In 2006, agriculture contributed 11.7% of GDP but only 5.6% of the growth of GDP. In 2006, the agriculture sector employed about 43 percent of the labour force in China. Industry and construction accounted for 43.3% and 5.6% of GDP respectively. The service sector accounted for 39.4% (National Bureau of Statistics of China, 2007:3-2). The Chinese agriculture and industry sectors are different in many aspects. Technology, labour productivity and incomes have improved much more rapidly in industry than in agriculture. This has formed a gap between the rural and urban areas in many ways - economic, cultural and social.

Table 5.1 shows the growth of nominal GDP by sector. The industry sector is the major contributor. The agricultural sector has contributed the least.

   Table 5.1 - Sector wise growth rates of nominal GDP    Year 1978 1980 1985 1990 1995 2000 2001 2002 2003 2004 2005 2006 Unit % change over the previous year  Agriculture 4.1 -1.5 1.8 7.3 5.0 2.4 2.8 2.9 2.5 6.3 5.2 5.0 Industry 15.0 13.6 18.6 3.2 13.9 9.4 8.4 9.8 12.7 11.1 11.7 13.0 Construction -0.6 26.7 22.2 1.2 12.4 5.7 6.8 8.8 12.1 8.1 12.6 13.7 Other industry 16.4 12.7 18.2 3.4 14.0 9.8 8.7 10.0 12.8 11.5 11.6 12.9 Services 13.8 6.0 18.2 2.3 9.8 9.7 10.3 10.4 9.5 10.1 10.5 10.8 Source: National Bureau of Statistics of China, 2007:3-3

Figure 5.2 shows China’s inflation rate from 1980 to 2007. During this period, China experienced rapid economic growth with generally low inflation rates. However, in the end of 2007, the inflation rate increased to 6.9%, which is the highest inflation rate since 1996.

Another key indicator of the China’s economic growth is its foreign exchange reserves. The foreign exchange reserves have been steadily accumulating in the last two decades. In 2006, China’s foreign exchange reserves exceeded US$1,000 billion, making China’s foreign exchange reserves the largest in the world (National Bureau of Statistics of China, 2007:20-10).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.3

Figure 5.2 - China's Inflation rate

20% 17.1%

15%

10% 8.3% 7.5% 6.9%

3.9% 5% 3.1% Percentage 2.8% 1.2% 1.8% 1.5% 0.4% 0.7% 0%

-0.8% -1.4% -0.8% -5%

6 7 8 9 0 01 02 04 07* 99 99 99 99 00 0 0 0 0 1980 1990 1995 1 1 1 1 2 2 2 2003 2 2005 2006 2 Year

Source: National Bureau of Statistics of China, 2007:9-1; National Bureau of Statistics of China, 2008.

The foreign investment climate has changed significantly with three decades of reform. In the early 1980s, China restricted foreign investments and required foreign investors to form joint ventures with Chinese companies. Since the early 1990s, the government has allowed foreign investors to manufacture and sell a wide range of products on the domestic market. It also allowed the establishment of wholly foreign-owned companies, which is now the preferred form of Foreign Direct Investment (FDI). On 11 December 2001, China became a member of the World Trad Organisation (WTO). As part of its accession to the WTO, China opened up sectors that had previously been closed to foreign investors. In 2006, China received US$69.5 billion in FDI (National Bureau of Statistics of China, 2007:18-1).

5.2 The labour market

China has a work force of approximately 764 million (estimated in 2006), which is growing at the rate of 0.8% per year. A high literacy rate of 91% and the low wages of Chinese workers have been factors assisting the growth of investment and the economy. 43% of the labour force is employed in agriculture, while 25% is employed

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.4 in industry. The remaining 32% is working for service sector (National Bureau of Statistics of China, 2007:5-5).

As at the end of 2006, it is estimated that 931 thousand people were employed in petroleum exploration and production. About 555 thousand people were employed in processing petroleum and nuclear fuel (National Bureau of Statistics of China, 2007:5- 5).

5.3 Roads

China has a road network of 3.46 million kilometres, although about 45% of this network is classified as village road. About 98 percent of villages and towns in China are already connected by highways. Roads carry 72% of freight traffic and 92% of passenger traffic in China (National Bureau of Statistics of China, 2007:16-2).

China’s National Highways stretch to all four corners of mainland China. Expressways reach the same areas as National Highways, except in the rugged terrain of Tibet. China’s expressways have a total length of 53,600 kilometres, which is the world’s second longest only after the United States (Xin, 2008). The total length of expressway roughly equals that in Canada, Germany and France combined.

The expressway network of China is the result of construction under the “National Trunk Highway System” (NTHS) project initiated in the 1990s. Originally, China planned to build up a 35,000 kilometre NTHS before 2020. The main objective of the NTHS was to construct 12 national arterial highways – five north-south and seven east-west roads, of which 70% of the roads would be expressways. The project was completed in the end of 2007, 13 years ahead of the original plan. At present, Beijing and Shanghai are linked by major highways, mainly expressways, to the capitals of all provinces and autonomous regions of China. The network has connected over 200 cities (Xin, 2008).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.5

On 13 January 2005, the Ministry of Communications announced the National Expressway Network Plan. The aim of the plan is to build up an 85,000-kilometre expressway system over the next three decades (Xin, 2008). The system will connect all capital cities of provinces and autonomous regions and other major cities of at least 500,000 people by the end of 2010 (Xinhua, 2006).

In addition, about 270,000 kilometres of rural highways will be built and upgraded in 2008 (China Daily, 7 January 2008).

5.4 Railways

Rail travel has been the most popular form of intercity transport. China has the world’s third largest rail network. The total length of railways in operation was 63,412 kilometres in 2006 with standard gauge (1,435 mm). There were additional 3,600 kilometres of narrow gauge (750 mm) local industrial lines. About 25,244 kilometres of the railway routes were double-tracked, representing 39.8% of the total. About 37% of the network is electrified (National Bureau of Statistics of China, 2007:16-16).

China’s railways are one of the busiest in the world, moving 24% of global rail traffic with only 6% of the world’ total tracks (Lau, 2008). In 2006, China’s railways carried 3.4 million passengers and 7.9 million tonnes of freight per day. Only India had more passengers and the United States more freight carried per day than China.

China has established railway links between seaports and inland export processing zones. For instance, Chengdu in Sichuan province in southwest China is linked to the Shenzhen Special Economic Zone in Guangdong province in the coastal area of China. A 1,956 kilometre Qingzang railway from Xining in Qinghai province to Lhasa in Tibet is the highest railway in the world. It passes though the Tanggula Mountain which is 5,068 metres above sea level. More than 960 kilometres is at an altitude of more than 4,000 metres. Because of the high altitudes, carriages are supplied with supplemental oxygen (Song, 2006).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.6

A map of China’s railway routes is shown in Figure 5.3.

Figure 5.3 – China railway map

Source: Wikipedia, 2005.

China also has links with some neighbouring countries – North Korean, Kazakhstan, Mongolia, Russia and Vietnam. The “New Silk Road” or the “Eurasian Continental Bridge” project launched in 1992 has developed a 4,131 kilometre railway route starting in Lianyungang, Jiangsu province in east China through central and northwest China to Urumqi, Xinjiang province, to the Alataw Pass and then into Kazakhstan. From that point, the railway links to a 6,800 kilometre route which ends in Rotterdam in Netherlands (Library of Congress, 2006:24).

5.5 Airports

China has a total of 467 airports, of which 142 are civil airports (excluding Hong Kong and Macau). There are more than 30 international airports in China. Of the 30

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.7 international airports, the four major ones are as follows (Civil Aviation Administration of China, 2008).

 Beijing Capital International Airport (PEK), located 27 kilometres northeast of central Beijing, has the greatest flow of passengers each year.

 Shanghai Pudong International Airport (PVG), which is 30 kilometres southeast of central Shanghai in east China.

 Shanghai Hongqiao International Airport (SHA), which is 13 kilometres west of central Shanghai.

 New Guangzhou Baiyun International Airport (CAN) is 28 kilometres from downtown Guangzhou in Guangdong province in south China.

According to the Civil Aviation Administration of China, the passenger throughput capacities of Beijing, Shanghai Pudong and Guangzhou Baiyun Airport rank numbers 14, 44 and 45 in the world respectively. Air traffic within mainland China is often connected through Beijing, Shanghai or Guangzhou (Civil Aviation Administration of China, 2008).

Other major airports are located in Chengdu, Chongqing, Dalian, Hangzhou, Harbin, Hohhot, Kunming, Qingdao, Shenyang, Tianjin, Urumqi, Xiamen and Xi’an. A map of major airports in China is shown in Figure 5.4.

China has international flights to most countries of the world. There are 268 international civil aviation routes and 1,068 domestic routes including 43 routes in Hong Kong and Macau (National Bureau of Statistics of China, 2007:16-36). According to the Civil Aviation Administration of China, the country runs 4,023 flights daily of which 421 are international flights. In 2006, China’s civil aviation sector carried 3.5 million tonnes of freight and 160 million passengers. Domestic air travel in China accounts for nearly 145.5 million passengers per year including Hong Kong and Macau (National Bureau of Statistics of China, 2007:16-2).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.8

Figure 5.4 – Major airports in China

Source: China MapXL, 2007.

5.6 Ports

The mainland of China has a coastline of 18,000 kilometres, which makes the marine transportation very easy. There are more than 150 coastal ports, of which 130 are open to foreign ships (Ministry of Transport of PRC, 2006). The major ports, including river ports accessible by ocean-going ships, are Dandong, Dalian, Qinhuangdao, Tianjin, Weihai, Rizhao, Yantai, Qingdao, Lianyungang, Nanjing, Nantong, Yangzhou, Shanghai, Hankou, Huangpu, Ningbo, Wenzhou, Jiujiang, Fuzhou, Xiamen, Shantou, Guangzhou, Shenzhen, Xingang, Beihai, Zhanjiang, Haikou and Sanya.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.9

In 2006, the cargo traffic handled at all ports was about 3,422 million tonnes. There are sixteen major seaports in China and each of them handled over 50 million tonnes. These major ports together handled about 70% of the total cargo. China’s seven largest seaport terminals are Dalian, Qinhuangdao, Tianjin, Qingdao, Shanghai, Ningbo and Guangzhou. Each has a handling capacity of more than 200 million tonnes a year. Additionally, Hong Kong is a major international port serving as an important trade centre of China (National Bureau of Statistics of China, 2007:16-33).

In 2005, the Shanghai Port Management Department reported that its Shanghai port became the world’s largest cargo port. Shanghai port processed cargo topping 443 million tonnes and exceeded Singapore’s port (National Bureau of Statistics of China, 2007:16-33).

Figure 5.5 shows the location of the major ports in China.

The dominant commodities and cargo types handled at the major ports are coal, petroleum and metal ores. Coal and petroleum account for 32% of all cargo handled in 2006. Other cargo types included steel and iron, mineral building materials, non- metal ores, grain, chemical fertilisers and pesticides, cement, timber and salt (National Bureau of Statistics of China, 2007:16-32).

5.7 Electricity distribution

China’s power transmission and distribution network is grouped into the following 12 regions –

 North region

 Northeast region

 East region

 Central China region

 Northwest region

 South region

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.10

Figure 5.5 – Major ports in China

Yingkou Qinhuangdao Dandong Tianjin Dalian

Weihai Qingdao

Lianyungang

Shanghai

Ningbo

Wenzhou

Fuzhou

Guangzhou Xiamen Shenzhen Beihai Zhuhai Shantou Hong Kong Zhanjiang Haikou Basuo Sanya

 Sichuan-Chongqing region

 Fujian region

 Shandong region

 Hainan region

 Urumqi region

 Lhasa region

The two national companies taking charge of China’s power transmission and distribution are the State Grid Corporation of China (SGCC) and the China South Power Grid Co., Ltd (CSG). The CSG operates the grids in the Guangdong, Yunnan, Guizhou, Guangxi and Hainan regions in southern China, while the SGCC covers the grid in all other regions (China Energy Yearbook, 2004).

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In the Tenth Five-Year Plan period (2001-2005), China’s investment in power industry focused on the construction of power plants, while its investment in constructing the grid system is the focus of the Eleventh Five-Year Plan period (2006-2010). According to the China Electricity Council, in 2007 China has 1.11 million circuit kilometres of transmission lines with 35 kilovolts or more. Among these, 0.22 million circuit kilometres are 220 kilovolt lines, 15,921 circuit kilometres are 330 kilovolt lines, 90,426 circuit kilometres are 500 kilovolt lines and 141 circuit kilometres are 750 kilovolt lines (China Energy Yearbook, 2004).

However, the transmission and distribution network continues to cause shortages and blackouts in various parts of the country. The government is in the process of strengthening the power grid to transfer electricity from western China to densely populated eastern China. China also plans to develop non-polluting forms of electricity generation such as clean coal and hydroelectric power generation.

5.8 Telecommunications

With 1.3 billion citizens, China has the world’s largest fixed line and mobile network in terms of both network capacity and number of subscribers. As at 2006, China has 368 million fixed line subscribers (28 per 100 persons) and 461 million mobile customers (35 per 100 persons). The combined subscriber of fixed lines and mobile lines are expected to increase to 976 million by 2008. Currently, more than 1.25 million cellular subscribers sign up in China every week (National Bureau of Statistics of China, 2007:16-38).

Fixed and mobile operators in China include China Mobile, China Netcom, China TieTong, China Satcom, China Telecom and China Unicom. After its accession to the World Trade Organization (WTO) in 2001, China has gradually opened its telecom services market to foreign companies.

Between mobile and fixed telephone, Xiaolingtong is a limited mobility service. It consists of a wireless local loop that provides access to the fixed line network. It

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.12 competes in big cities with traditional mobile services, since prices are typically far cheaper. There are more than 50 million users (Watts, 2003).

The internet is another important form of communication in China. Internet users have soared from about 60,000 in 1995 to 22.5 million in 2000 and to 137 million in 2006. Internet connections available in the country use dialup and broadband technologies. Over 70% of the broadband lines are via DSL and the rest via cable modems (National Bureau of Statistics of China, 2007:16-39).

According to the National Bureau of Statistics, China had 62,799 permanent post offices in 2006 (National Bureau of Statistics of China, 2007:16-38).

China is forming partnerships with foreign providers to expand its global reach. Three of the six major telecommunications operators are part of an international consortium which signed an agreement with Verizon Business to build the first next generation optical cable system that directly links the United States and China.

5.9 The oil and gas industry

The Chinese petroleum sector (both upstream and downstream) is administered by the National Development and Reform Commission (NDRC).

The NDRC is a macroeconomic management agency under the State Council, which formulates policies for economic and social development and guides the overall economic system restructuring. The NDRC's predecessor was the State Planning Commission (SPC), which was founded in 1952 and was renamed the State Development Planning Commission (SDPC) in 1998.

The National Energy Administration is under the control of NDRC. It administers oil, natural gas, coal, power and other parts of the energy sectors. It is responsible for the study of energy development and utilisation, putting forward energy development strategies and major policies, formulating development plans of the

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.13 energy sector and making recommendations on system reform in the energy sector. Other responsibilities of the National Energy Administration include managing national oil reserves and formulating policy measures for energy conservation and renewable energy development.

The National Energy Administration contains nine departments. They are –

 General Office

 Department of International Cooperation

 Department of Electrical Power

 Department of New Energy and Renewable Energy

 Department of Oil and Natural gas

 Department of Coal

 Office of Policy Studies

 Department of Development Planning

 Department of energy conservation and technological equipments

In addition, the National Oil Reserve Office is also managed by the National Energy Administration.

Under the administration of the NDRC, there are three integrated national oil and gas companies in China and the Chinese petroleum industry is monopolised by these companies. The main features of these companies are set out below.

 China National Petroleum Corporation (CNPC) CNPC is engaged mainly in onshore oil and gas exploration and production. PetroChina Company Limited is wholly owned by CNPC. In addition, CNPC has 13 regional administrative organisations, 29 refining and chemicals enterprises, 14 specialised companies and 4 research institutes (CNPC, 2007).

 China Petroleum & Chemical Corporation (Sinopec) Sinopec is also engaged in onshore oil and gas exploration and production. It has 13 regional administrative organisations, 34 refining and chemicals enterprises, 19

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.14 petroleum product distribution companies, 6 research institutes and 12 other companies and subsidiaries (Sinopec, 2008).

 China National Offshore Oil Corporation (CNOOC) CNOOC is engaged mainly in offshore oil and gas exploration and production. It has one upstream company, one research centre, 7 downstream companies, 3 specialised companies, 5 financial companies and 9 other companies (CNOOC, 2008).

5.10 Refineries

According to the Oilnews website, in 2006 China has 122 refineries including small- scale local refineries. The total annual refining capacity is estimated to be about 369 million tonnes (approximately 2,694 million barrels), which is the second largest in the world after the United States (Sinopec Consultant Company, 2007).

China’s major oil refineries are state-owned. At present, the domestic refining market is mainly supplied by Sinopec and CNPC. These two companies have 88% of the total refining capacity in China, of which Sinopec has 51% and CNPC has 37%. According to the China Petroleum and Petrochemical Industry Economics Research Annual Report, at the end of 2006 Sinopec owned 34 oil refineries of which 7 refineries have an annual capacity of more than 10 million tonnes. CNPC owns 29 refineries of which three have annual capacity of more than 10 million tonnes. Another state owned oil company – CNOOC – is engaged mainly in offshore oil and gas exploration and production and currently does not own any refineries. CNOOC is planning to enter the oil refinery market in the near future (Sinopec Consultant Company, 2007).

Because the industry and transport sectors have grown rapidly in recent years, the demand of petroleum products has increased correspondingly. According to the International Energy Agency (IEA) report, the growth of China’s oil product demand in 2007 was 5.9%.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.15

In order to meet the domestic demand for petroleum products, China is rapidly growing its refining capacity. With several large scale refineries coming online, China will increase its refining capacity by 100 tonnes over the next three to five years. In the mean time, the country plans to close down some small scale refineries with combined capacity of 20 million tonnes per year. By 2010, China is expected to have more than 20 large oil refineries each has an annual refining capacity of 10 million tonnes. The total annual refining capacity is expected to increase to 450 million tonnes (approximately 3,280 million barrels) by 2012 (National Development and Reform Commission, 2005).

Sinopec has plans to build or expand about 20 refineries, each capable of handling 10 million tonnes annually. Among these, about 30 percent are new and the rest are expansion projects. They are mostly in the south and east China.

CNPC is also increasing efforts to obtain a larger share of the domestic refining market. It plans to increase its annual refining capacity to more than 160 million tonnes by 2010, accounting for 40% of China’s total. According to an official of the company, CNPC will build up 18 refineries each with an annual capacity of more than 10 million tonnes by 2020 (Fu, 2008). These include two in Daqing, Heilongjiang prvince, one each in Fushun, Jinzhou, Dalian and Huludao in Liaoning province, two in Lanzhou, Gansu province and three in the Xinjiang autonomous region (China.cn, 2007).

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 Table 5.2 - Refineries in China  Capacity (barrels per Sinopec owned Location day) Beijing Yanshan Company Refinery Beijing 190,000 Qilu Company Refinery Zibo, Shandong 160,000 Shanghai Gaoqiao Company Refinery Shanghai 226,000 Jinling Company Refinery Nanjing, Jiangsu 150,000 Maoming Company Refinery Maoming, Guangdong 270,000 Tianjin Company Refinery Tianjin 120,000 Changling Company Refinery Yueyang, Hunan na Guangzhou Branch Refinery Guangzhou, Guangdong 154,000 Zhenhai Refining and Chemical Company Zhenhai, Zhejiang 360,000 Anqing Company Refinery Anqing, Anhui na Luoyang Company Refinery Luoyang, Henan 100,000 Jingmen Company Refinery Jingmen, Hubei 100,000 Jiujiang Company Refinery Jiujiang, Jiangxi 100,000 Jinan Company Refinery Jinan, Shandong 70,000 Wuhan Petroleum Group co Ltd Wuhan, Hubei 80,000 Cangzhou Refinery Cangzhou, Hebei 70,000 Beihai Company Refinery Beihai, Guangxi na Baling Company Refinery Yueyang, Hunan 122,000 Hubei Fertiliser Company Zhijiang, Hubei na Zhongyuan Petrochemical Refinery Puyang, Henan na Qingdao Petrochemical Refinery Qingdao, Shandong na Sinopec Lubricant Company Beijing na Xi'an Company Refinery Xi'an, Shaanxi na Tahe Company Refinery Kuche, Xinjiang na Sinopec Catalyst Company Beijing na Sinopec Chemical Products Sales Company Beijing na

Table 5.2 gives information on major refineries owned by Sinopec and CNPC along with their processing capacities (Wikipedia, 2008).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.17

 Table 5.2 - Refineries in China - continued  Capacity (barrels CNPC owned Location per day) Daqing Petrochemical Company Daqing, Heilongjiang 120,000 Fushun Petrochemical Corporation Fushun, Liaoning 214,000 Jilin Chemical Group Company Jilin, Jilin province 112,000 Liaoyang Petrochemical Fiber Compay Liaoyang, Liaoning na Lanzhou Petrochemical Corporation Lanzhou, Gansu 120,000 Urumqi Petrochemical Company Urumqi, Xinjiang na Dalian Petrochemical Corporation Dalian, Shandong 220,000 Dushanzi Petrochemical Company Dusanzi, Xinjiang 120,000 Jinzhou Petrochemical Company Jinzhou, Liaoning 110,000 Jinxi Refining and Chemical Company Huludao, Liaoning 110,000 Harbin Petrochemical Company Harbin, Heilongjiang na Qianguo Petrochemical Company Songyuan, Jilin na Dalian West Pacific Petrochemical Corporation Dalian, Shandong 160,000 Daqing Petrochemical Refinery Daqing, Heilongjiang 170,000 Guangxi Petrochemical Company Nanning, Guangxi na Sichuan Petrochemical Company Chengdu, Sichuan na Karamay Petrochemical Company Karamay, Xinjiang na Hohhot, Inner Hohhot Petrochemical Company Mongolia na Huabei Petrochemical Company Renqiu, Hebei na Dagang Petrochemical Company Tianjin na Liaohe Petrochemical Company Panjin, Liaoning na Changqing Petrochemical Company Xianyang, Shaanxi na Ningxia Petrochemical Company Yinchuan, Ningxia na Ningxia Petrochemical Refinery Yinchuan, Ningxia na Qingyang Petrochemical Refinery Qingyang, Gansu na

5.11 Pipelines

According to the National Bureau of Statistics, China had a pipeline network of 48,226 kilometres by the end of 2006, which consist of 24,136 kilometres of oil pipelines and 24,090 kilometres of gas pipelines. Oil pipelines have a total annual capacity of 575.3 million tonnes (approximately 4,200 million barrels), while gas pipelines are capable of transporting 94.2 billion cubic metres (approximately 3,325 billion cubic feet) of natural gas per year (Watkins, 2007).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.18

5.11.1 Crude oil and petroleum product pipelines

The China National Petroleum Corporation (CNPC) operates the largest network of crude oil and petroleum product pipelines in China. As at the end of 2007, CNPC runs 12,463 kilometres of crude oil pipelines, which account for 65% of the country’s total. Its petroleum product network has about 4,622 kilometres, accounting for 42% of the total (CNPC, 2008).

As at the end of 2006, China had 46 major crude oil pipelines and four major petroleum product pipelines in operation (CPGP, 2008). China’s crude oil pipeline networks are distributed over five regions – northeast China, north China, central China, east China and northwest China.

Northeast China pipelines

Northeast China is the largest crude oil producing area in China. A number of major oil fields are in the northeast of China. These include the Daqing, Liaohe and Jilin oil fields. Crude oil production in northeast China accounts for 53.5% of the total production (CPGP, 2008). Major oil pipelines in northeast China are shown in table 5.3.

     Table 5.3 - Major oil pipelines in northeast China      Designed Year of Starting Total length Name End point capacity (million commissioning point (kilometres) barrels per year) Qingtie 1971 Daqing, Tieling, 516 146 Heilongjiang Liaoning Qingtie 2 1974 Daqing, Tieling, 527 na Heilongjiang Liaoning Tiefu 1971 Tieling, Fushun, 77 na Liaoning Liaoning Tieqin 1973 Tieling, Qinhuangdao, 454 na Liaoning Hebei Tieda 1975 Tieling, Dalian, 660 na Liaoning Liaoning Source: CPGP, 2008.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.19

North China pipelines

The major oil fields in north China include Dagang and Huabei and each of them has one or more export oil pipelines. Table 5.4 shows the major oil pipelines in north China.

     Table 5.4 - Major oil pipelines in north China       Designed capacity Year of Total length Name Starting point End point (million commissioning (kilometres) barrels per year) Qinhuangdao, Qinjing 1975 Hebei Beijing 347 43.8 Zhoulizhuang, Dazhou 1968 Dagang, Tianjin Tianjin 211 36.5 Rencang 1976 Renqiu, Hebei Cangzhou, Hebei 109 56.2 Renjing 1976 Renqiu, Hebei Fangshan, Beijing 114 na Source: CPGP, 2008.

Central China pipelines

The major oil fields in central China are located mainly in Hubei and Henan provinces. They include Jianghan oil field, Henan oil field and Zhongyuan oil field. Table 5.5 shows the major oil pipelines associated with these oil fields.

    Table 5.5 - Major oil pipelines in central China      Designed capacity Year of Total length Name Starting point End point (million commissioning (kilometres) barrels per year) Qianjing 1970 Qianjiang, Hubei Jingmen, Hubei 90 12.4 Pulin 1979 Puyang, Henan Linyi, Shandong 242 na Pulin 2 1991 Puyang, Henan Luoyang, Henan 129 na Zhongluo 1985 Puyang, Henan Luoyang, Henan 184 na Zhongluo 2 1992 Puyang, Henan Luoyang, Henan 274 na Source: CPGP, 2008.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.20

East China pipelines

The largest oil field in east China, which is also the third largest oil field in China, is Shengli oil field in Shandong province. Table 5.6 shows the major oil pipelines associated with this and other fields in east China.

     Table 5.6 - Major oil pipelines in east China      Designed capacity Year of Total length Name Starting point End point (million commissioning (kilometres) barrels per year) Luning 1975 Linyi, Shandong Yizheng, 1034 146 Jiangsu Dongxin 1965 Dongying, Xindian, 79.4 40 Shandong Shandong Donglin 1997 Dongying, Linyi, Shandong 152 na Shandong Linji 1973 Linyi, Shandong Jinan, 67 8 Shandong Linji 2 1991 Linyi, Shandong Jinan, 70 11 Shandong Donghuang 1974 Dongying, Huangdao, 245 73 Shandong Shandong Donghuang 2 1986 Dongying, Huangdao, 249 146 Shandong Shandong Source: CPGP, 2008.

Northwest China pipelines

Northwest China contains China’s largest inland basin – Tarim Basin, which has abundant petroleum resources. The major oil pipelines in northwest China is shown in Table 5.7 below.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.21

     Table 5.7 - Major oil pipelines in northwest China       Designed capacity Year of Total length Name Starting point End point (million commissioning (kilometres) barrels per year) Zhongning, Huining 1978 Huianbao, Ningxia Ningxia 309 26 Huage 1991 Huatugou, Qinghai Gelmu, Qinghai 435 14.6 Kulun 1992 Lunnan, Xinjiang Korla, Xinjiang 192 22 Kulun Shihua 1997 Luntai, Xinjiang Korla, Xinjiang 158 na Talun 1995 Tazhong, Xinjiang Lunnan, Xinjiang 605 7.3 - 43.8 Shanshan, Kushan 1997 Korla, Xinjiang Xinjiang 634 73 Dushanzi, Kedu 1991 Karamay, Xinjiang Xinjiang 100 na Kewu 2 1981 Karamay, Xinjiang Urumqi, Xinjiang 293 na Source: CPGP, 2008.

Petroleum product pipelines

The oldest long-distance petroleum product pipeline in China is the Gela pipeline, which was put on stream in 1977. The Gela pipeline starts in Gelmu in Qinghai province and ends in Lhasa in Tibet. It has a total length of 1,080 kilometres with an annual capacity of 250,000 tonnes of petroleum products. More than 900 kilometres of the pipeline were constructed in permafrost areas over 4,000 metres above sea level (CPGP, 2006).

Other major petroleum product pipelines include the Funan pipeline from Fushun to Yingkou in Liaoning province (246 kilometres), the Tianjin-Beijing pipeline (185 kilometres) and the Lanchengyu pipeline from Lanzhou in Gansu province to Chengdu in Sichuan province and to Chongqing (1,200 kilometres) (CPGP, 2006). China is planning to build up a 2,000 kilometre pipeline from Maoming in Guangdong province to Kunming in Yunnan province (Pipeline Report, 2001:4).

5.11.2 Gas pipelines

Gas pipelines are part of China’s efforts to meet its booming gas demand and reduce its reliance on coal. CNPC operates the largest network of natural gas pipelines in

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.22

China. As at the end of 2007, CNPC runs 22,231 kilometres of natural gas pipelines, which account for 89% of the country’s total (CNPC, 2008).

As at the end of 2006, China had about 29 natural gas pipelines in operation. The back bone of the gas pipeline network has been constructed, with two north-south pipelines and four east-west pipelines. The detailed information of major gas pipelines in China is provided in Table 5.8.

     Table 5.8 - Major gas pipelines in China       Designed Year of Total length capacity Name Starting point End point commissioning (kilometres) (Bcm per year) West-East 2004 Lunnan, Xinjiang Shanghai 4000 17 Zhongwu 2005 Zhong County, Wuhan, Hubei 1375 3 Chongqing Shaanjing 1998 Jingbian, Shaanxi Beijing 1104 3.3 Shaanjing 2 2005 Yulin, Shaanxi Beijing 932 12 Sexilan 2001 Sebei, Qinghai Lanzhou, Gansu 953 3 Jining 2005 Yizheng, Jiangsu Anping, Hebei 1498 na Dayu 2005 Daniudi gas field, Yulin, Shaanxi 82 3 Inner Mongolia Shanwu 1997 Shanshan, Urumqi, 302 na Xinjiang Xinjiang Talun 1996 Tazhong, Xinjiang Lunnan, Xinjiang 302 na Zhongcang 1986 Puyang, Henan Cangzhou, 362 0.6 Hebei Zhongkai 1985 Zhongyuan oil Kaifeng, Henan 149 na field, Henan Zhong'an 1986 Zhongyuan oil Anyang, Henan 131 na field, Henan Jingxi 1996 Jingbian, Shaanxi Xi'an, Shaanxi 128 na Shaan'ning 1998 Shaanxi Ningxia 112 na Kulun 1998 Korla, Xinjiang Lunnan, Xinjiang 135 na Source: CPGP, 2008.

The West-East gas pipeline is connected to the Shaanjing parallel pipeline by the 886 kilometre Jining branch.

In 2007, CNPC stared work on a feasibility study on its second West-East gas pipeline project and the construction work started on 22 February 2008. The new pipeline, with a total length of 9,102 kilometres, is expected to run from Horgas in the Xinjiang province to the densely populated cities of Guangzhou and Shanghai. Up to Gansu province, it will be parallel to and interconnected with the first West-East

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.23 pipeline. The capacity of the pipeline will be 30 billion cubic metres per year (Xinhua, 2008).

Sinopec has started building a pipeline linking its Daniudi gas field in Inner Mongolia with Jinan in Shandong Province. The pipeline will have a total length of 1,100 kilometres and a capacity of 3 billion cubic metres of gas per year (Xu, 2007: 21).

Sinopec also planned to build a pipeline from its giant Puguang gas field in Sichuan to Shanghai. The pipeline will run 1,702 kilometres from Puguang gas field in Dazhou, Sichuan provinces to the Qingpu district of Shanghai. An 842 kilometres long branch will connect with the main line at Yichang in Hubei province and pump gas to Puyang in Henan province. Because more gas reserves were proved-up, Sinopec decided to build another line extending south to supply gas to the Pearl River Delta. The construction of the first 1,360 kilometre-long section from Yichang in Hubei province to Shanghai started on 22 May 2007 and is expected to be completed by 2010. The capacity of the pipeline will be 15 billion cubic metres per year (OGJ, 2007).

Transnational pipelines

The Kazakhstan-China oil pipeline is China’s first oil-import pipeline. The pipeline will run 3,000 kilometres from Atyrau in Kazakhstan to Alashankou in Xinjiang Uygur Autonomous Region in China. The operator of the Chinese part of the pipeline is CNPC. The Kenkuyah-Atyrau section of the pipeline is 449 kilometres and will have a capacity of 66 million barrels per year. The Atasu-Alashankou section is 1,000 kilometres with a capacity of 146 million barrels per annum. The third section of the pipeline is currently under construction. It will link Kenkiyak and Kumkol in Kazakhstan (Chen, 2006).

The Central Asia-China gas pipeline is a transnational gas pipeline designed to transport natural gas from Central Asia to Xinjiang in China. If constructed, Turkmenistan, Uzbekistan and Kazakhstan will deliver their natural gas to China. The construction of the 188 kilometre Turkmen section, the 530 kilometre Uzbek section and the Kazakh section has started during 2007 and 2008. After completion, the total

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 5.24 length of the pipeline will be 7,000 kilometres, of which 4,500 kilometres will be in China (Upstream Online, 2008). The pipeline is expected to cost US$7.3 billion.

Wanwan Hou January 2009 University of New South Wales

Chapter 6

Energy Market in China

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.1

This chapter presents the information on the supply, demand and price of crude oil, natural gas, petroleum products, coal and electricity in China. Figure 6.1 shows the country’s energy flow chart for 2005. The numbers in Figure 6.1 is estimated by using the conversion factors in Appendix A.

         Figure 6.1 - China's energy flow chart for 2005   Primary energy availability 1,415 MMtoe  Indigenous production Imports Recovery of Energy  1,236 MMtoe 162 MMtoe 17 MMtoe    Primary energy supply 1,332.27 MMtoe Exports Stock Changes Hydro-power, Crude Natural Nuclear 69  Coal 14 MMtoe oil Gas Power, Wind MMtoe Power 918 280 39  96 MMtoe MMtoe MMtoe MMtoe   Losses in  Primary energy consumption 1,277 MMtoe Transformation 24 Other losses 39 MMtoe MMtoe Hydro-power, Crude Natural Nuclear  Coal oil Gas Power, Wind Power 880 268 37  92 MMtoe  MMtoe MMtoe MMtoe    Transformation into electricity 526 MMtoe Direct energy consumption 752 MMtoe Hydro-power, Hydro-power, Crude Natural Nuclear Crude Natural Nuclear  Coal Coal oil Gas Power, Wind oil Gas Power, Wind Power Power 419 13 1.5 461 255 36  92 MMtoe 0 MMtoe MMtoe MMtoe MMtoe MMtoe MMtoe MMtoe   Electricity  produced 197 MMtoe         Source: China Statistical Yearbook, 2006.

According to the China Statistical Yearbook, China’s energy output is abundant, especially the production of coal. The raw coal output in 2006 is the largest in the world. However, the energy demand grows much faster than the production because the economy is booming in China in the past two decades. According to the National Development and Reform Commission (NDRC), China’s energy situation shifted from

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.2

“whole balance, partial tight” to “whole tight, partial balance” after 2000 (Zhang, 25 December 2003). China’s energy consumption relies mostly on coal. No other country relies on coal to the extent that China does (Wang, 2007). Coal accounts for almost 70% of energy consumption. Crude oil is the second most important energy source in China, but only constitutes less than 25% of the total energy mix. Nearly 45% of the crude oil consumed in China is from imported oil. The natural gas industry has become more and more important in recent years, but still in embryonic form, occupying only a 2.9% market share in China’s energy mix (China Statistical Yearbook, 2006).

Changes in government organisations

The changes in government organisations are summarised in Figure 6.2.

The authorities responsible for the management of energy in China changed significantly in the 1980s and 1990s. Before the Ministry of Energy in 1988, there were four ministries in charge of the energy industry – the Ministry of Oil, the Ministry of Coal, the Ministry of Nuclear Industry and the Ministry of Electricity. The China National Offshore Oil Corporation (CNOOC) was established in 1982, under the control of the Ministry of Oil. The China Petrochemical Corporation (Sinopec Group) was established in 1983, directly under the control of the State Council.

In 1988, the government organisations were reformed. Except for the Ministry of Electricity, the other three ministries became three national companies. The Ministry of Oil became the China National Petroleum Corporation (CNPC) and CNOOC became independent. Since then, both of them came under the control of the State Council. The Ministry of Electricity along with the remaining government functions of the other three ministries formed the Ministry of Energy. However, the Ministry of Energy did not last long. It was disbanded in 1993 during another reform of government institutions. The Ministry of Coal and the Ministry of Electricity were re-established while CNPC and China National Nuclear Corporation (CNNC) remained unchanged.

Four years later, the Ministry of Electricity changed to the China National Electricity Corporation and the Ministry of Coal was disbanded finally.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.3

In 2003, the National Development and Reform Commission (NDRC) was established, taking charge of all the issues regarding the management of energy. The Bureau of Energy was also set up under the NDRC.

As regards petroleum, up to 1998 CNPC had been engaged mainly in onshore oil and gas exploration and production while another state-owned company, Sinopec group engaged in refining and distribution. In 1998, most state owned oil and gas properties were reorganised into two vertically integrated companies – CNPC and Sinopec. CNOOC is the third largest oil company which mainly deals with offshore exploration and production. There was another oil company – China National Star Petroleum Corporation (CNSPC) that was involved in onshore exploration and production. CNSPC was built up in 1997 and became the fourth largest oil company in China. It was acquired by Sinopec in 2000.

At present, there are three state owned oil companies in China – CNPC, Sinopec and CNOOC. All of them have been entitled to sign contracts with foreign companies for jointly exploring and developing the oil and gas resources in China.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.4

Figure 6.2 – Changes in government organisations

Ministry of Nuclear Ministry of Pre 1988 CNOOC Ministry of Oil Ministry of Coal Industry Electricity Sinopec

China National Ministry of 1988 CNOOC CNPC Coal Corporation CNNC Energy Sinopec

Ministry of 1993 CNOOC CNPC Ministry of Coal CNNC Electricity Sinopec

China National 1997-1998 CNOOC CNPC Bureau of Coal CNNC Electricity Sinopec Corporation

2003 Bureau of Energy NDRC Taking charge of all the issues regarding the management of energy

Source: The Transition of Chinese Energy Regulatory bodies, 2008.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.5

6.1 Crude Oil

China was the first country to discover and use oil. The earliest known oil wells were drilled in 347 or earlier. The wells were up to 800 feet (240 metre) deep drilled using bits attached to bamboo poles (Totten, 2004). The first production of oil in China was from the Yanchang oil field in Shanxi Province, discovered in 1907.

Before the People’s Republic of China was formed in 1949, there were several other oil and gas discoveries in China. The largest oil field in that period was the Yumen field in Gansu province. For the ten years before liberation, cumulative production in Yumen oil field was 3.65 million barrels, which accounted for more than 95% of total Chinese production of oil in that period (Kambara, 1974).

In the 1950s China started to develop a modern petroleum industry. However, before the 1980s oil and gas production was controlled by a highly centralised planed economic management system. The supply and demand of petroleum was under the control of the Chinese government. In 1980s, with the “Reform and Opening up” policy, the petroleum market was built up gradually. From the early 1990s, China has a limited petroleum market. However, the Chinese petroleum industry is still partially controlled by the government because of the strategic nature of petroleum.

Today, the crude oil industry in China is mainly monopolised by the three state owned oil and gas companies. Foreign companies are encouraged to explore jointly for and develop crude oil resources in China, especially in the challenging areas where advanced technologies can play a critical role.

6.1.1 Crude oil reserves

According to the 2006 China Petroleum and Petrochemical Industry Economics Research Annual Report, as at the end of 2005 China’s original proven crude oil reserves were estimated to be 50.49 billion barrels. The remaining proven reserves were 17.88 billion barrels, ranking Chinese reserves at number twelve in the world (China Petroleum and Petrochemical Industry Economics Research Annual Report, 2006).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.6

China has a different terminology for reserves than is used in the rest of the world. In China, “reserve” generally means technically recoverable reserve, but internationally the word “reserve” only refers to economically recoverable reserve. According to the BP Statistical Review of World Energy, the remaining proven economically recoverable reserves in China in the end of 2007 were 15.49 billion barrels (BP, 2007).

The remaining proven reserves of eight significant basins in China are shown below in Figure 6.3.

Figure 6.3 - Chinese crude oil reserves

6

5.1 4.9 5

4

3

1.9 1.8 2 1.6

1 0.8 0.3 Remainingin provenreserves B bbl 0.1 0 Songliao Bohai Bay Junggar Ordos Tarim Qaidam Bohai Pearl River Basins Mouth Source: China Petroleum and Petrochemical Industry Economics Research Annual Report, 2006.

The reserves in the eight basins account for 92% of the total remaining proven crude oil reserves in China.

6.1.2 Crude oil demand/supply

Before 1949, the cumulative consumption of oil was said to be about 220 million barrels over half of a century, but only 20 million barrels were produced from indigenous sources. Therefore, 90% of consumption depended on imported oil (Kambara, 1974). In 1949, China’s domestic production of crude oil increased to 879.6 thousand barrels (Zhang & Hu, 1995), but the country still relied on foreign oil. This situation has changed since the discovery of the giant Daqing oil field in 1960s. In 1965,

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.7 the age of self-sufficiency began. China even became an oil exporting country. Most of the exported oil went to Japan. However, this situation only lasted for a very short period because the demand for oil increased rapidly, China’s self-sufficiency ended in 1993 and China began to import again (Li, D. & Du, Y., 2004).

During the past two decades, the production of crude oil has increased gradually, whereas the demand for oil increased more rapidly. Consequently, the gap between demand and indigenous production has increased and China has had to import a huge amount of oil to meet its total demand. In 2003, China became the world’s second largest oil consumer, just behind the US. According to the BP Statistical Review of World Energy, China consumed 7,855 thousand barrels a day of oil in 2007. This number includes inland demand, international aviation, marine bunkers, refinery fuel and loss. Consumption of fuel ethanol and biodiesel is also included. Among the total amount of oil consumption, 3,277 thousands barrels of crude oil were imported a day. In other words, in 2007 more than 40% of the crude oil consumption in China came from imported oil. The crude oil balance sheet from 1990 to 2007 is presented Table 6.1.

  Table 6.1 - Crude oil balance sheet (Thousand barrels per day)    2007  1995 1998 1999 2000 2001 2002 2003 2004 2005 2006# # Domestic production 3,013 3,233 3,213 3,273 3,293 3,354 3,406 3,532 3,642 3,684 3,743 Imports 343 549 735 1,411 1,210 1,394 1,828 2,464 2,552 2,928 3,277 Exports 366 313 144 207 152 154 163 110 162 194 73 Consumption 2,990 3,493 3,805 4,264 4,286 4,527 5,005 5,773 6,034 7530* 7855* Net import dependency  7% 16% 28% 25% 27% 33% 41% 40%  Source: China Energy Statistical Yearbook, 2005. # Data from BP Statistical Review of World Energy June 2007. * Inland demand plus international aviation, marine bunkers, refinery fuel and loss. Consumption of fuel ethanol and biodiesel is also included.

It is predicted that the oil consumption in China will increase by more than 200% in the next twenty years. In 2025, oil consumption will be almost as much as the oil consumption in the US. In contrast, oil production in China will go up slightly in the next two decades. The forecast also indicates that in 2015, 66% of the oil consumed will have to be imported and in 2025, 80% will have to be imported. The period when China was a net oil exporter will never be repeated (Li, D. & Du, Y., 2004).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.8

Figure 6.4 shows the production and consumption of crude oil in China from 1990 to 2006.

Figure 6.4 - Production and consumption of crude oil in China

8,000

7,000

6,000 Consumption 5,000 Net imports

4,000

3,000 Production

2,000 Thousand barrels per day

1,000

0 1990 1995 1998 1999 2000 2001 2002 2003 2004 2005 2006# Year Source: China Energy Statistical Yearbook, 2005. # Data from BP Statistical Review of World Energy June 2007.

6.1.3 Crude oil pricing

Before 1998 the Chinese government strictly controlled crude prices. Although since the 1980s the government has allowed CNPC to adjust crude oil prices, the adjustment is still controlled (Kambara, 1974). In June 1998, the National Plan Commission which was the former National Development and Reform Commission (NDRC) issued the “Crude Oil and Oil Products Price Reform Scheme”. Since then, crude oil prices in China have been linked to crude prices in the international market.

Today, domestic oil prices are determined by adding together the crude oil benchmark prices, the freight and other charges and the quality premium. The benchmark prices are decided by NDRC based on the monthly average FOB prices of crude oils with similar qualities in the international market. An import tariff is added. Finally, the freight and the quality premium are negotiated by the buyer and seller (The present pricing system for crude oil and petroleum product in China, 2001).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.9

Domestic crude oil in China is classified into four categories -

 Light Oil which mainly refers to Xinjiang Turpan-Hami crude oil. The reference crude oil for Light Oil is the Malaysian Tapis crude oil.  Medium Oil I which includes the crude oil produced from Daqing, Jidong, Huabei, Tarim, Zhongyuan, Jiangsu, Jianghan, Dianqiangui, Anhui, Linpan, Changqing and Ansai fields. The reference crude for this category is the Indonesian Minas crude oil.  Medium Oil II which includes the crude oil produced prom Dagang, Shengli, Henan and Inner Mongolia fields. The reference crude oil for this category is the Indonesian Cinta crude.  Heavy Oil which includes the crude oil produced from Gudao and Liaohe field. The reference crude oil for Heavy Oil is the Indonesian Duri crude.

As with crude oil prices in the international market, domestic crude oil prices in China have increased dramatically in recent several years. In addition, the price difference between the Light Oil and Heavy Oil has become larger. In 2003, the average price difference was RMB 353 per tonne (approximately US$5.85/bbl at US$1 = RMB 8.27) which increased to RMB 921 per tonne (approximately US$15.4/bbl at US$1 = RMB 8.19) in 2005 (Sinopec Consultant Company, 2006). Figure 6.5 shows the annual average crude oil benchmark prices in China from 2000 to 2006.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.10

Figure 6.5 - Crude oil benchmark prices

80

70

Medium oil I 60

50 Heavy oil

40 Light oil

30

20 Medium oil II Crude oil (US$/bbl) Crude price

10

0 2000 2001 2002 2003 2004 2005 2006 * Year Source: China Petroleum and Petrochemical Industry Economics Research Annual Report, 2006. * Preliminary data

The available data of the crude oil benchmark prices in China apply only up to the year 2006. For the purpose of carrying out economic analyses in the thesis, more recent oil prices are required. As a guide to the oil price assumptions made in the thesis, since crude oil produced from the basins I analysed are mostly categorised as “Medium Oil I”, I choose prices applicable to Minas crude oil, which is the reference crude oil for “Medium Oil I”.

In most of the base case economic analyses, an oil price of US$80 per barrel is chosen for the real oil price in year 2008 terms. A discussion of the oil prices assumed is presented in section 3.2.

Table 6.2 provides the annual average spot price (FOB) of Daqing crude oil from 1997 to 2007.

 Table 6.2 - Daqing crude oil spot price FOB (US$/bbl)   Year 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Price 19.49 12.47 17.16 28.15 24.00 25.27 29.57 36.61 52.65 63.33 70.00 Source: World Crude Oil Prices, 2008.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.11

6.2 Petroleum products

At present, China has 122 refineries , with a total installed capacity of 2,694 million barrels per year. This ranks Chinese refinery capacity at number two in the world after the USA. Although the total number is impressive, the average size of the refineries is small at only 19 million barrels per year, which is less than a half of the world average. Because of high crude oil prices and low domestic petroleum product prices, oil refining companies do not show enthusiasm for enhancing capacity. The growth of the oil refining capacity in China has been relatively low in recent years. The annual average growth rate has been between 2% and 3% (Sinopec, 2007).

6.2.1 Petroleum product supply

In early the 1980s, Sinopec was the only national petroleum company licensed to supply petroleum products to the domestic market. In late the 1980s, to meet the increasing demand for petroleum products, the government deregulated the market. Since then, CNPC, CNOOC, local governments at all levels and even some private economic utilities have established their own petroleum products selling and distribution system. Nevertheless, Sinopec still held the dominant position. After the reorganisation of the petroleum companies in 1998, CNPC changed from an upstream company to a vertically integrated company. Its downstream section has been growing fast. Today, the domestic petroleum product market is mainly supplied by Sinopec and CNPC. The two companies have 89% of the total refining capacity in China, of which Sinopec has 52% and CNPC owns 37%. Sinopec accounts for approximately 37% of the country’s total production of petroleum products each year (Sinopec, 2007).

On 11 December 2006, China opened its petroleum product wholesale market to foreign companies. This followed the opening of the retail market in 2005, which fulfilled a WTO entry obligation. Several international companies such as Shell, BP and ExxonMobil have already entered the Chinese market, but their market shares are still very low.

The production of petroleum products in China has increased along with the growth in both crude oil production and refining capacity. However, domestic production can not satisfy the country’s demand. Although the controlled low domestic prices make

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.12 importing products loss-making, China still has to increase the import of petroleum products to maintain supplies. In addition, the Ministry of Commerce limits the export of petroleum products to help China meet its domestic demand. The export quota has been decreased from 12 million tonnes in 2005 to 9 million tonnes in 2006 (Sinopec, 2007). Figure 6.6 shows the annual production of fuel oil, gasoline, kerosene and diesel oil in China.

Figure 6.6 - Petroleum product production 98.4 100

90 85.3

80 74.9 77.1 70.8 70

60 52.7 47.9 50 41.3 41.5 43.2 40

Million Tonnes 30 20.5 18.6 18.5 20.0 20.3 20 8.7 7.9 8.3 8.6 9.6 10

0 2000 2001 2002 2003 2004 Year

Fuel Oil Gasoline Kerosene Diesel Oil Source: China Energy Statistical Yearbook, 2005.

6.2.2 Petroleum product demand

The Chinese refining sector accounts for about 95% of total Chinese crude oil consumption. The major petroleum products consumed in China include gasoline, kerosene, diesel oil and fuel oil. The transport sector including storage and postal services is the largest consumer of petroleum products and accounts for about 50% of total consumption. The industrial sector is the second largest consumer. Therefore, the development of industry and transport is the most significant factor that drives the petroleum product demand in China. As China is in a fast developing period and the industrial sector grows the fastest, the demand of petroleum products has increased significantly in recent years.

Table 6.3 provides the consumption of the four major petroleum products.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.13

As can be seen in Table 6.3, diesel oil dominates the demand for petroleum products in China. The consumption of diesel has grown at the fastest rate. In 2004, it accounted for nearly half of the total domestic consumption. Diesel Oil is used as an energy source for ships and industries such as mining and manufacturing. Therefore, the major consumers of diesel oil are the transportation and industrial sectors. The consumption from the two sectors accounts for 41% and 22% of the total diesel consumption respectively (Sinopec, 2007). The demand for gasoline and fuel oil has also increased significantly. The key factor contributing to the increase in gasoline consumption is the sharp increase in the sale of commercial vehicles. The industrial and power generation sectors are the main consumers of fuel oil.

 Table 6.3 - Consumption of petroleum products in China (Million tonnes)    1995 1998 1999 2000 2001 2002 2003 2004

Fuel Oil 36.94 38.29 39.34 38.73 38.50 38.74 42.21 47.84 Gasoline 29.10 33.29 33.81 35.05 35.98 37.50 40.72 46.96 Kerosene 5.12 6.71 8.24 8.70 8.90 9.19 9.22 10.61 Diesel Oil 43.21 52.83 62.32 67.74 71.08 76.67 84.10 98.95 Total consumption 114.37 131.11 143.71 150.22 154.46 162.10 176.24 204.35 Source: China Energy Statistical Yearbook, 2005.

The major petroleum product consuming areas in China are the fast developing regions in the east, especially Beijing, Shanghai, Tianjin, and the province of Guangdong, Jiangsu and Zhejiang (China Energy Statistical Yearbook, 2005).

The forecasts indicate that the demand for petroleum products in China will increase to about 280 million tonnes in 2010 and 420 million tonnes in 2020 (Yang & Hong, 2007).

6.2.3 Petroleum product pricing

China has linked its domestic prices of petroleum products to the international prices since May 2000. This followed the liberalisation of crude oil prices in 1998. However, the new pricing system seems inefficient and distortions in the domestic petroleum product market continue.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.14

The current pricing system links domestic prices to the prices of corresponding petroleum products in Singapore (weighted 60 percent), Rotterdam (30 percent) and New York (10 percent). NDRC formulates the benchmark prices based on the weighted average prices in these three international markets plus freight charges and inland customs dues. Sinopec and CNPC can adjust the prices within 8% of the benchmark prices and decide their final retail prices. When the monthly fluctuation of weighted average prices in the three markets exceeds 8%, NDRC would correspondingly adjust the benchmark prices in the following month, based on which Sinopec and CNPC would decide new retail prices. In practice, however, domestic prices of petroleum products have seldom been adjusted. There has always been a significant time lag in time between a movement in international prices and the adjustment of domestic prices. The main reason for this is that the Chinese government has tried to protect the domestic economy from rising oil prices (The problem with the Chinese oil pricing mechanism, 2007).

Such pricing system cannot reflect the real relation between supply and demand and has brought many problems to the Chinese petroleum product market. Downstream companies have suffered large losses because of the gap between domestic prices and international prices. The revenue from selling petroleum products in the domestic market could not cover costs. In order to compensate oil companies for their losses, the government has given large subsidies to the downstream sectors of the state owned companies. The delay in the price adjustment has led to repeated supply shortages, because wholesalers had an incentive to store petroleum products in anticipation of the increase in domestic prices (Cornelius & Story, 2007).

In a meeting held in October 2006, NDRC and the delegates of the three state owned companies introduced a planned cost-plus pricing system. The new system will connect the domestic prices of petroleum products to the crude oil prices for Brent, Dubai and Minas. The product prices will be set to compensate refiners for the costs of crude oil and its transport plus a refining margin. The implementation of the new system is yet to be approved.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.15

6.3 Natural gas

The Chinese natural gas industry is in its infancy. It started after other energy industries and only contributes about 3% to the Chinese energy mix (Ma & Ma, 2000). Natural gas exploration and development started in the 1950s after the People’s Republic of China was established. The first discovery was the Weiyuan gas field in Sichuan Basin in the southwest of China which contains abundant natural gas resources.

The natural gas industry in China grew very slowly in the 20th century. Consumer gas prices were high, policies were undeveloped, the natural gas utilisation was inefficient and there was a lack of infrastructure. However, natural gas is becoming more and more important. Experts contend that the 21st century is the natural gas century because natural gas is more abundant than oil and is more environmental friendly than crude oil or coal.

6.3.1 Natural gas resources

According to the preliminary results of the third oil and gas resources evaluation, natural gas resources in China are 1,925 trillion cubic feet (Tcf) in total, of which 494 Tcf are technically recoverable. Most of the recoverable natural gas resources are located onshore China and only 18.4% are offshore. Natural gas has been discovered in 69 Chinese basins. Of these, 12 basins are significant. These are Songliao, Bohai Bay, Sichuan, Ordos, Qaidam, Tarim, Junggar, Turpan-Hami, East China Sea, Pearl River Mouth, Qiongdongnan and Qinggehai. These basins contain 80% of the total recoverable natural gas resources in China. As at the end of 2005, the original proven reserves of natural gas in China were estimated to be 123 Tcf. Only 19% had been produced. The remaining reserves were 99 Tcf (China Petroleum and Petrochemical Industry Economic Annual Report, 2006). Figure 6.7 shows the remaining proven reserves of the 12 major gas bearing basins in China.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.16

Figure 6.7 - Natural gas reserves in China

100 90.2 90 80 70 60 53.7 47.0 50 40 30 20 14.6 11.0 10.1 8.6 5.8 10 4.6 4.5 2.8 3.6 Remaining proven reserves in Tcf reserves proven Remaining 0

n i a ay ar ao m a ea u dos rim B li a ami gg d a S ich Or Ta ai ngnan S h o Qai in o Jun Song er Mouth B Qinggeh pan-H v r t Ch i Tu s R Qiongd Ea earl Basins P Source: China Petroleum and Petrochemical Industry Economic Annual Report, 2006

The five largest natural gas fields in China are Puguang, Kela-2, Sulige, Longgang and Daqing-Xushen gas fields, all of which have proven reserves of more than 100 billion cubic metres (about 3,530 Bcf). Most of these fields are located in western China. The Puguang and Sulige gas fields are both in the Sichuan basin. Kela-2 and Longgang are situated in Tarim and Ordos basins respectively. The Daqing-Xushen gas field was discovered in 2005 in the deep volcanic rocks, thousands of metres below the giant Daqing oil field. It is considered the biggest gas field in eastern China.

The China Petroleum and Petrochemical Industry Economic Annual Report predicts that further exploration in China will increase the proven reserves of natural gas to 200 Tcf by 2020.

6.3.2 Natural gas supply

The production of natural gas in China increased from 1.25 billion cubic feet per day (Bcfd) in 1985 to 6.44 Bcfd in 2007. Its share in the overall energy production also has risen from 2.0% to 3.3% during this period. Table 6.4 gives the details.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.17

  Table 6.4 - Natural gas production in China (Bcfd)    1985 1990 1995 2000 2001 2002 2003 2004 2005 2006* 2007#  Production 1.25 1.48 1.74 2.63 2.93 3.16 3.39 4.01 4.74 5.66 6.44

As percentage of Total Energy Production 2.0% 2.0% 1.9% 2.8% 2.9% 3.0% 2.8% 2.9% 3.3%  na  na Source: China Energy Statistical Yearbook, 2005. * BP Statistical Review of World Energy June 2007. # Xu, 14 January 2008.

More than 95% of the production comes from the 12 major gas bearing basins listed in the previous section. Of the natural gas produced from those basins, onshore production accounts for nearly 90%. The Sichuan basin has the highest production with 14.296 Bcm in 2005 (about 1.383 Bcfd). It is the only basin that has a daily gas production of more than one billion cubic feet per day in China and accounts for 29% of the total Chinese gas production. The second and third biggest gas producing basins are the Ordos basin and the Tarim basin. These produced 767 million cubic feet per day (MMcfd) and 599 MMcfd respectively in 2005 (China Petroleum and Petrochemical Industry Economic Annual Report, 2006). Gas production in each of the major basins is presented below in Figure 6.8. Production in the basins broadly corresponds to the reserves.

Among the three national oil and gas companies, CNPC produces the most natural gas with almost 75% of natural gas production in 2005. The other two companies – Sinopec and CNOOC produce the remaining natural gas (China Petroleum and Petrochemical Industry Economic Annual Report, 2006).

Almost all of the gas produced was supplied to the domestic market. From 1999, a small portion of the gas production was exported. However, exports decreased slightly in recent years.

Natural gas supply will continue to rise in the coming decades. Production is expected to rise to 7.74 Bcfd in 2010 and to 11.61 Bcfd in 2020 (China Petroleum and Petrochemical Industry Economic Annual Report, 2006).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.18

Figure 6.8 - Gas production in 2005

1,383 1,400

1,200

1,000 767 800 599 600 429 400 304 280 277 Gas production in MMcfd 205 165 200 148

0

i i n y n m os a iao hua rd B da c O Tarim ai -Ham i ongl S oh Junggar S Qai an B Qinggeha ongdongna Turp Qi Basins Source: China Petroleum and Petrochemical Industry Economics Research Annual Report, 2006.

6.3.3 Natural gas demand

As with gas production, the demand for natural gas in China only accounts for 3% of the total energy demand (China Statistical Yearbook, 2007). During the past ten years, the consumption of natural gas has risen tremendously, but because of infrastructure limitations, the growth has been constrained. However, the situation is changing. As a clean energy source, natural gas demand will continue increasing in the coming future. It is expected that the demand will be 107 Bcm in 2010 and 210 Bcm in 2020. By then, gas consumption is expected to contribute 8% of the overall energy consumption in China (China Petroleum and Petrochemical Industry Economic Annual Report, 2006).

In China, natural gas is mainly used as industrial and residential fuel. However, it is also used for power generation, transport, in the chemical industry, and so on. Its use as an industrial fuel accounts for 74% of the country’s total gas demand (China Energy Statistical Yearbook, 2005). The detailed consumption of natural gas by various sectors is given in Table 6.5.

The pattern of natural gas consumption has changed significantly during the decade. Residential consumption of gas increased the most rapidly because gas has become more affordable. Since natural gas has advantages over crude oil both in price and its

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.19 effects on the environment, the number of industrial gas consumers also increased steadily.

       Table 6.5 - Natural gas consumption in China (MMcfd)          1995 2000 2001 2002 2003 2004 2005 Total consumption 1,715.8 2,369.7 2,652.8 2,822.5 3,279.3 3,836.8 4,633.8 Farming, Forestry, Animal Husbandry, Fishery and Water 0.2 Conservancy Industry - 1,493.1 1,953.6 2,106.5 2,200.5 2,590.1 2,839.8 3,421.6 Mining and Quarrying 501.6 706.2 768.7 773.5 786.3 745.4 850.9 Manufacturing 974.9 1,168.4 1,248.5 1,341.1 1,692.5 1,922.2 2,313.4 Electric power, Gas and water production 16.6 79.0 89.4 85.9 111.4 172.2 257.2 and supply Construction 2.7 7.9 7.0 6.6 6.8 13.4 14.4 Transport, Storage and Post 15.2 56.2 57.6 61.6 66.0 107.9 158.9 Wholesale, Retail trade and 5.3 33.3 48.4 59.0 66.2 88.8 104.4 hotel, Restaurants Others 11.5 6.2 6.8 136.8 166.4 Residential consumption 187.7 312.6 426.6 494.8 550.2 650.1 768.2 Source: China Energy Statistical Yearbook, 2005.

As stated in the previous sections, most of China’s gas resources are located in the western and central regions, which are less developed. However, the areas which have the highest and the fastest growing demand of energy are in the south and east. At present, there are four significant gas-consuming regions in China. They are Sichuan-Chongqing region, coastal area in southeast China, North China region including Beijing, Tianjin, Shandong and Henan province, and the Yangtze River Delta Region. All these regions except Sichuan – Chongqing are in the east. Therefore, gas transmission and distribution networks are crucial to the development of the Chinese natural gas market. Detailed information about natural gas pipelines are presented in Chapter 5 – Infrastructures.

6.3.4 Additional natural gas

Although the supply and demand of natural gas are basically in equilibrium for the present, demand is expected to rise more rapidly than production. Figure 6.9 displays the supply and demand situation of natural gas in the recent past and into the future.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.20

Figure 6.9 - Natural gas supply and demand

22

20 18 Actual data Forecast 16

14 Consumption 12

Bcfd 10

8

6 Production 4

2

0 1995 1998 1999 2000 2001 2002 2003 2004 2005 2006* 2010 2015 2020 Year Source: China Energy Statistical Yearbook, 2005. * BP Statistical Review of World Energy June 2007. Forecasts: China Petroleum and Petrochemical Industry Economics Research Annual Report, 2006.

There are two ways to bridge China’s gas growing demand-supply gap, one is to import gas by pipeline from Russia and Central Asia. The other is to import liquefied natural gas (LNG). According to the prediction in the figure, in 2020 43% of natural gas is expected to be imported.

Importing natural gas using pipelines

In March 2006, the proposal to transport natural gas from Russia to China moved to a new stage. A memorandum of understanding has finally been signed by the two countries. It is agreed that the world’s biggest gas exporting country will supply 60-80 Bcm of natural gas to China every year starting from 2011. In April 2006, Russia made an agreement with China’s two national petroleum companies – CNPC and Sinopec, to construct a 300 km gas pipeline starting from the West Siberia in Russia to the Xinjiang province in China. It will join the West-east gas pipeline in Xinjiang and feed gas to the coastal areas in the east China. The construction work is expected to be completed in 5 years. The pipeline will have a capacity to deliver 30-40 Bcm of natural gas annually. Moscow has also agreed in principle to construct another pipeline from Sakhalin and

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.21 maybe the Kovykta field in East Siberia to China’s Xinjiang province (Upstreamonline, 19 Nov 2007).

CNPC agreed in April 2006 to import 30 billion cubic metres of gas per year from Turkmenistan for 30 years from 2009 via the Central Asia Gas Pipeline. The pipeline will start from Turkmenistan, go through Uzbekistan and Kazakhstan, then enter China and join the West-east pipeline. After construction has finished, the three countries could all supply natural gas to China (Upstreamonline, 22 Jan 2008).

Importing LNG

An alternative way to secure China’s gas supply is importing LNG. At the end of 2005, China had 18 LNG projects in progress, most of which were controlled by CNOOC. Upsurging demand for LNG in Asia, the US and Europe has boosted LNG prices, which to some extent has hampered the development of the Chinese LNG projects. China so far has secured three long-term LNG supply contracts for three terminals in Shanghai, the province of Guangdong and Fujian.

Guangdong LNG is the first LNG project in China. It was approved by the government in December 1999 and put on stream in 2006. CNOOC and BP set up a joint venture to operate the project (Upstream, 2007:13). The Guangdong LNG terminal will receive 3.7 million tonnes of LNG per annum from the Northwest Shelf Australia for 25 years. Fujian LNG is the second largest LNG project in China. It came on stream in 2007. It will be supplied by the Indonesian Tangguh project with 2.6 million tonnes of LNG per annum for 25 years. The Shanghai LNG project will come on stream in June 2008 and will be supplied by Petronas from Malaysian sources (China Petroleum and Petrochemical Industry Economic Annual Report, 2006).

During the APEC Summit in September 2007 in Sydney, PetroChina signed two LNG purchase agreements. One is with Shell for the supply of LNG from the Gorgon project in Western Australia. The Gorgon project would sell 1 million tonnes of LNG per year to PetroChina under a 20-year contract. The other is to supply 2 to 3 million tonnes of LNG every year for 15 to 20 years from Woodside’s proposed Browse project off Western Australia. The supply is expected to begin between 2013 and 2015 (PetroChina LNG Purchase Agreements in Australia, 17 September 2007).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 6.22

China and Iran signed a memorandum of understanding in 2004 for Sinopec to buy 10 million tonnes per year of LNG from Iran for 25 years, but the two sides have failed to agree on the contract terms. The construction work of an LNG terminal in the coastal city of Qingdao, Shandong Province, has been suspended because of the lack of agreement (Upstreamonline, 12 November 2007).

China still needs more sources of LNG to achieve its target of 30 million tonnes per year by 2010. The country is considering setting up a state-owned company to negotiate contracts for foreign supplies of LNG on behalf of major terminal developers. However, objections to this plan might be raised by the current three LNG developers – PetroChina, Sinopec and CNOOC (Xu, 2007:23).

Gas production from Coal Bed Methane (CBM)

Coal Bed Methane (CBM) is natural gas extracted from coal seams. In order to supplement supplies of natural gas, China is making great effort to encourage CBM projects. China has potential CBM resources of 37 Tcm, ranking the country third in the world after Russia and Canada (First of 10 CBM pipelines to be constructed, 05 November 2007). China is in early stages of CBM development and most CBM projects in China are in the exploration or initial development phases. The production rate in 2007 was estimated to be 290 MMcfd. Qinshui basin in north China’s Shanxi Province, which is estimated to have 3.96 Tcm CBM in place, is the only basin that is currently producing CBM (Xu, 2007). According to the CBM development plan drafted by the National Development and Reform Commission (NDRC), China will increase its annual CBM output to 10 Bcm by 2010 (about 967 MMcfd). Table 6.6 and Figure 6.10 shows the CBM basins in China and the current CBM contract areas awarded.

All CBM blocks are identified and awarded by the Ministry of Land and Resources, P.R.C. The projects that involve cooperation with foreign companies have to be approved by the Ministry of Commerce.

Companies involved in CBM exploration and development in China include –

 China Petroleum and Chemical Corporation (Sinopec)  China United Coalbed Methane Corp. (CUCBM)

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 Chevron Corporation  Greka Energy  BP plc  Far East Energy Corp  TOTAL SA  China National Petroleum Corporation (CNPC)  Asian American Coal  ConocoPhillips  Verona Development  Reflection Oil & Gas  Ivana Ventures Inc  TerraWest Energy Corp  Fortune Oil plc  Shell plc  Arrow Energy  Pacific Asia China Energy Inc

At present, CUCBM – 50:50 held by CNPC and China National Coal Group - is the only state owned company that is authorised to engage foreign companies to explore and develop the CBM resources in China. The government is considering authorising other national companies such as Sinopec and CNPC to have rights to cooperate with foreign companies to break the monopoly. Recently, the government is starting redistributing the CBM resources and assets between CNPC and CUCBM. CUCBM will hand over 50% of its operating CBM blocks to CNPC. After the restructure, CUCBM will be 100% held by China National Coal Group.

China established its first CBM research centre in September 2007. The institute will take charge of formulating regulations for the country’s CBM industry.

Two pipelines for CBM transmission will be built in the next five years. One of them will start from Duanshi County in Shanxi Province to Bo’ai County in Henan Province, where it will be connected to the West-east pipeline. The 120km pipeline will pass through the Qinshui basin in Shanxi and transport its CBM to the market in eastern China. The designed capacity is 1 Bcm per year. This will be China’s first cross-province CBM pipeline. The other pipeline will connect Songzao County in

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Chongqing Municipality to the nearby Chongqing City (China - CBM Pipeline Project – Await Approval, 31 October 2007).

According to the 11th Five-Year Plan issued by NDRC, China plans to build 10 CBM pipelines by the end of 2010 with a total length of 1,441 km and total capacity of 6.53 Bcm.

 Table 6.6 - CBM basins in China   CBM basins Location Jungger Basin Xinjiang Province, northwest China Erlian Basin Inner Mongolia, north China Ningwu Basin Shanxi Province, north China Ordos Basin North China Qinshui Basin Shanxi Province, north China Bohai Gulf Basin Northeast China Hefei Basin Anhui Province, east China Boyang Basin Jiangxi Province,southeast China Chenzhou Basin Hunan Province, south China Nanpanjiang Basin Yunnan Province, southwest China Source: Chakhmakhchev, 2007.

Figure 6.10 - CBM contract areas by company

sq.km Sinopec Corp CUCBM Chevron Corp Other partner(s) Greka Energy BP plc Far East Energy TOTAL SA CNPC Asian American Coal

Top 15 companies ConocoPhillips Verona Development Reflection Oil & Gas Ivana Ventures Inc TerraWest Energy Corp

0 5,000 10,000 15,000 20,000

Source: Chakhmakhchev, 2007.

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6.3.5 Natural gas pricing

Up to 2005 China had a dual domestic natural gas pricing mechanism. Gas was classified into two categories – planned gas and self-marketing gas. Planned gas refers to the amount of gas that is produced under the government regulation and sold to specified industries and end users. Self-marketing gas is the gas used and sold by the producers themselves. For the planned gas, prices were strictly controlled by the government. Different prices were fixed by the government based on gas used by four groups of end users including fertiliser manufactures, residents, business and other users. For self-marketing gas, the government sets only a benchmark price. Suppliers and consumers are able to negotiate their own prices based on the benchmark price.

There are significant price differences between planned gas and self-marketing gas. Planned gas has been much cheaper than self-marketing gas, which lead to unfair competition between downstream enterprises. In addition, domestic gas prices in China were relatively low compared with the gas prices in the international market. While crude oil prices surged, both the price of planned gas and self-marketing gas remained low. Based on thermal equivalent, the average gas price in China was only 30% of the average crude oil price. For a well-developed country with a market economy, the proportion is generally between 0.84 and 1.21 (National Development and Reform Commission's press conference on the reform of the pricing mechanisms for natural gas, 16 January 2006). The low domestic gas price was one of the reasons for boosting gas demand and an inefficient use of gas. While downstream companies were consuming gas lavishly, the gas producers were facing difficulties.

In order to deal with the above issues, Chinese government implemented a reform of the natural gas pricing system. The new regulations came into effect on 26th December in 2005. Under the new policy, the dual pricing system was abolished. The government no longer specified any fixed gas prices. Instead, the government provided benchmark factory prices which companies can use to negotiate. The major reforms included -

 The uses of gas were reclassified. The new classification consisted of fertiliser production, industrial consumption and city fuel gas.

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 Benchmark factory prices were classified into two groups. The first group included all of the gas produced from oil and gas fields in Sichuan, Chongqing, Changqing, Qinghai, Xinjiang and the initially planned gas produced from Dagang, Liaohe and Zhongyuan oil fields. The second group contained all other gases.

 The government was to adjust the benchmark prices every year based on the prices of other energy sources such as crude oil, LPG and coal. The adjustment between any two subsequent years was to be less than 8%.

 The benchmark price in the second group was set at US$3.7 per thousand cubic feet (approximately at US$1 = RMB 7.5) in the end of 2005. The government planned to raise the benchmark price for the first group to the same level as that of the second group in 3 to 5 years and establish a uniform benchmark price for all gas (National Development and Reform Commission's press conference on the reform of the pricing mechanisms for natural gas, 16 January 2006).

 After the new policy was put into effect, government increased the benchmark price for the first group. The last price adjustment was on 8 November 2007. The current prices set for the first group are given in Table 6.7. The price data in Table 6.7 have been obtained from discussion with staff in Chinese oil companies.

    Table 6.7 - Factory prices of the first group of natural gas    Industrial fuel Supplied by City fuel End users Fertiliser Supplied directly by fuel gas gas producers companies Price in US$/thousand 2.61 4.82 4.99 3.47 cubic feet* * Approximately at US$1 = RMB 7.5

Gas prices for major pipelines

The price for pipeline gas - usually called the “gate price” consists of the gas factory price and the transmission tariff. The “gate” refers to the point between cross-province pipelines and city distribution networks.

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The average gate price for the West-East pipeline gas is US$4.87 per thousand cubic feet. Table 6.8 gives the detailed gate prices for different places.

 Table 6.8- West-east pipeline gate prices  Zhejiang Jiangsu Anhui Henan  Shanghai Province Province Province Province Price in US$/Mcf* 5.17 5.10 4.95 4.68 4.38 Source: China Petroleum and Petrochemical Industry Economics Research Annual Report, 2006 * Approximately at US$1 = RMB 7.5

As at 2006, the average gate gas price of the two Shaanxi-Beijing pipelines is US$5.65 per thousand cubic feet and the average Zhongwu Pipeline gas price is US$4.57 per thousand cubic feet.

The gas price at a delivery point consists of the producer price, the transmission tariff and the distribution fee. Because of the increase in both the producer price and the transmission tariff, the local government has raised end-user prices significantly in recent years. For instance, in November 2007 the price of the residential fuel gas in Beijing has risen by US$0.57 per thousand cubic feet. The price of industrial gas went up by US$1.51 per thousand cubic feet, which is 35% more than the original price. The price of gas for vehicles has increased by US$5.29 per thousand cubic feet, 65% of the original price (Finance Bureau of Zhoukou, 2007).

As at 2007, the average price of the residential fuel gas in major cities in China is more than US$8.7 per thousand cubic feet (approximately at US$1 = RMB 7.5).

Currently, the natural gas sector is monopolised by two national companies – CNPC and Sinopec. Natural gas production, transmission and distribution are fully operated by these two companies. A transmission network is being constructed and will require at least 5 years for completion. In the long-run, natural gas prices are expected to be deregulated and driven by free market competition. However, free market gas prices would be too high at present, especially in the undeveloped western China areas. Therefore, the natural gas prices will still be partly controlled by the government in the near future.

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6.4 Coal

No other country relies on coal to the extent that China does (Wang, 2007). Almost all of coal consumed in China is indigenously produced. China has substantial coal resources. According to the latest statistical data based on the new standard - “Classification of Solid Mineral Resources/Reserves”, the proved extractable coal reserves in China are 188.6 billion tonnes, which is about 20% of the world’s total reserves and ranks the country the second in the world. With the annual production rate of 1.9 billion tonnes, the reserves are sufficient to maintain supply for nearly a century. In addition, China has 145.5 billion tonnes of basic coal reserves and 687 billion tonnes of coal resources, which together make 1,021 billion tonnes. The reserves are not well distributed. Most of the reserves are in north and northwest China. The province of Shanxi, Shaanxi and Inner Mongolia contain 64% of the total. Shanxi province is the biggest coal containing region with reserves almost one-third of the total reserves in the country (China coal resources, 2008).

6.4.1 Coal supply

In the 1950s, coal accounted for 97% of the total output of primary energy. With the development of petroleum industry after 1960s, the share of coal production decreased to 70% in 1980, but then steadily increased to 76% in 2005 (China Energy Yearbook, November 2005).

Under the planned economy and the priority strategy of heavy industries, coal output increased from 66 million tonnes in 1952 to 636 million tonnes in 1979, with an annual growth rate of 8.8 % (Almanac of China’s economy, 1981). However, this output still could not satisfy the country’s appetite for energy. Under such circumstances, the central government relaxed entry to the industry and local government, collective and private-owned coal mines were allowed to enter. Coal mines were classified into three types – Central Government Owned Mines (CGMs), Local Government Owned Mines (LGMs) and Village, Town and Private Owned Mines (VTPMs). By the end of 1980s, coal was oversupplied in China. In 2006 coal production amounted to 2.38 billion tonnes (China Statistical Yearbook, 2007).

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Despite the huge output, the average annual production rate of LGMs and VTPMs was poor. Most of small mines were illegal, low quality and dangerous. Thousands of Chinese miners were killed in accidents every year. In 1998, a policy of closing small coal mines and decreasing coal output was implemented. More than 30,000 illegal small mines had been closed by the end of 1999 (Almanac of China’s economy, 2000). In 2004, China had approximately 28,000 coal mines consisting of 600 CGMs, 2000 LGMs and 26,000 VTPMs (China Energy Yearbook, November 2005). The Government aims to reduce the number of small mines to nearly 10,000 in 2009 (Huang, 2006). Figure 6.11 presents the production of the three types of coal mines in China.

Figure 6.11 - Coal production

2,400

2,000

1,600

1,200

800 Million Tonnes

400

0 1980 1985 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Year

CGMs LGMs VTPMs Source: China Energy Yearbook, November 2005; China Energy Statistical Yearbook, 2005.

Corresponding to the distribution of coal reserves, the coal production mainly comes from north and northwest China. Shanxi Province in northern China is the largest coal producing province. Its coal output in 2006 was about 600 million tonnes, nearly one-fourth of the total output (Wang, 2007). As most of coal mines are far away from the developed regions in the east, where most of the coal is consumed, coal transport plays an important role. The main modes of transport of coal in China are railways, road and water. Railways account for 58.2% of the total coal movement (China Energy Yearbook, November 2005).

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Coking coal output was 912 million tonnes in 2005 and accounted for about 40% of all coal produced in China. The ash content is generally above 20% and the sulphur content is relatively high. The quality of non-coking coal in China is high, especially bituminous coal (long flame coal, non-caking coal and weakly caking coal) with a low ash and sulphur content.

Coal production in China is scattered and the scale of individual coal producer is very small. The Shenhua Group Corporation limited (Shenhua Group) is the biggest coal producing company in China, but its production only accounts for 6% of the total production of the country. The other nine major coal companies include –

 Datong Coal Mine Group Company  Shanxi Coking Coal Group Co. limited  Yankuang Group  China National Coal Group Corporation  Huainan Mining Industry Group limited  Pingdengshan Coal Co. Ltd  Kailuan Group  Yangquan Coal Industry (Group) Co., Ltd  Huaibei Coalfield Group Limited

In 2003, coal produced by the above ten corporations accounted for 24.2% of the total coal production in China (China Energy Yearbook, November 2005).

6.4.2 Coal demand

In 2005 coal consumption accounted for 69% of total primary energy, down from a peak of 72% in 1980. Consumption increased from 610 million tonnes in 1980 to 2,147 million tonnes in 2005. The average annual growth rate between 2001 and 2005 was about 11% (China Statistical Yearbook, 2006).

More than 47% of coal produced in China is used to generate electricity and this portion is still rising as the number of coal-fired power plants increases. Nearly 80% of China’s electricity is generated by coal. In addition, other industries like steel, building materials and chemicals are also major coal consumers (China Energy

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Yearbook, November 2005). Table 6.9 gives the detailed consumption of key consumers of coal in China. The residential consumption of coal has decreased because of the increasing use of gas, LPG and electricity by urban residents.

   Table 6.9 - Coal consumption in China (Million tonnes)      1985 1990 1995 1998 1999 2000 2001 2002 2003 Power generation 177 291 477 527 539 592 646 733 876 Steel 70 107 155 159 160 161 171 176 185 Building materials 86 100 155 153 155 160 160 160 175 Chemical industry 52 59 82 77 79 77 77 80 82 Share in total 47% 53% 67% 78% 78% 80% 84% 84% 81% Resident 156 167 135 89 84 80 75 70 319 Others 275 331 296 175 183 160 132 151 Total 816 1055 1299 1180 1200 1230 1260 1370 1637 Source: China Energy Yearbook, November 2005.

China exports its surplus coal. Exports increased from 3.12 million tonnes in 1978 to 94 million tonnes in 2003, with an annual growth rate of 15%. China became the second largest coal exporting country in the world. However, exports decreased to only 63 million tonnes in 2006 and China dropped down the ranks to number five. The entities that have been authorised to export coal are China National Coal Group Corporation, Shanxi Coal import & Export Group Corporation, Shenhua Group and China Minmetals Corporation. Because of the shortage of domestic coking coal supply, the steel sector is importing a small amount of coking coal from neighbouring Mongolia (Callick, 2007).

Although energy consumption in China is gradually moving from solids to liquids, because indigenous coal resources are abundant, coal is likely to remain the leading energy source at least in the medium term.

6.5 Electricity

China’s electricity output and total generation capacity both rank the country the second in the world, just behind the USA. More than 40% of energy consumed in China is used to generate electricity. China mainly relies on thermal power, 98% of which is generated using coal (China Energy Yearbook, November 2005). As a result of closing small coal mines, coal supplied to electricity industry has decreased. Therefore, in winter when coal and electricity demand highly increases, many China’s provinces suffer from electricity shortages.

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6.5.1 Electricity supply

The electricity supply-demand relationship in China is unsteady. Before 1985, China’s electricity industry was wholly controlled by the central government. Generation, transmission, distribution and retailing were integrated into one entity under the administration of Ministry of Water and Power Industry (Wang, 2007). Low fixed electricity prices led to serious shortages. In 1986, the supply-demand gap was more than 20% of total generation. The government liberalised the generation sector in 1985 to attract investment. As a result, from 1985 the electric power installed capacity increased by 10 gigawatt per year for 11 years. Until the end of 1990s, electricity was oversupplied in China. To restrain the overheated generation sector, the government then restricted the operation of thermal power projects for three years. However, the domestic economy grew faster than the government expected. In 2002, China faced electricity shortages again. The situation became worse in 2005 with 26 out of 34 provinces in China experiencing power shortages (Liu, 2006). In 2007, the supply and demand of electricity were basically balanced after several large scale power plants were put into production.

During the last decade, China’s electricity industry has experienced a dramatic output and capacity growth. Electricity output increased from 301 billion kilowatt hours in 1980 to 2,500 billion kilowatt hours in 2005. The average increase between 2001 and 2005 was 13% (China Statistical Yearbook, 2006). Figure 6.12 shows China’s electricity output from 1980 to 2005.

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Figure 6.12 - China's electricity output

2,500

2,000

1,500

1,000 Billion kilowatt hours 500

0 1980 1985 1990 1995 2000 2001 2002 2003 2004 2005* Year

Hydropower Thermal Power Nuclear Power Source: China Energy statistical Yearbook, 2005. * China Statistical Yearbook, 2006.

It has taken 38 years for China to expand its electricity generation capacity from 2 gigawatt in 1949 to more than 100 gigawatt in 1987. It took only another 20 years to increase capacity to more than 700 gigawatt in 2007 (An, 2008). Thermal power is the dominant electricity source in China and has the fastest growth rate. Thermal power accounts for 78% of the total capacity, while hydropower accounts for 21% and nuclear power for 1% (China Statistical Yearbook, 2006). In 2005, China had 104 thermal power plants with an individual installed capacity for each plant of more than one gigawatt. The top fifteen thermal power plants are given in Table 6.10 below.

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  Table 6.10 - Top fifteen thermal power plants in China    Name Location Capacity (gigawatt)

Tuoketuo Hohhot, Inner Mongolia 3.60 Houshi Zhangzhou, Fujian 3.60 Dezhou Dezhou, Shandong 2.60 Shalingzi Xuanhua, Hebei 2.40 Zouxian Zoucheng, Shandong 2.40 Jiahua Jiaxing, Zhejiang 2.40 Lanbi Zhenjiang, Jiangsu 2.16 Yangcheng Yangcheng county, Shanxi 2.10 Shentou Dier Shuo county, Shanxi 2.00 Shajiao C Dongguan, Guangdong 1.98 Huarun Chanshu Chanzhou, Jiangsu 1.95 Beilun Ningbo, Zhejiang 1.80 Waigaoqiao Shanghai 1.80 Mawan Shenzhen, Guangdong 1.80 Xingtai Xingtai, Hebei 1.62 Source: Qiu, 2007.

6.5.2 Electricity demand

China’s electricity consumption is shown in Table 6.11. China is the second largest consumer of electricity in the world, but the electricity consumption per capita in 2003 was only 1,477 kilowatt hours, which is 50% of the world average (China Energy Yearbook, November 2005). During the last twenty years, the demand of electricity in China has increased at an average rate of approximately 12% per year (China Statistical Yearbook, 2006). The development of heavy industries such as steel, chemical and construction is the key factor that drives the increase of China’s electricity consumption. In addition, there has been a rapid increase in residential consumption.

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  Table 6.11 - Electricity consumption in China (billion kilowatt hours)    1985 1990 1995 2000 2001 2002 2003 2004 2005* Farming, forestry, animal 31.7 42.7 58.2 67.3 76.2 77.6 77.3 80.9 87.6 husbandry, fishery conservancy Industry 328.3 487.3 766.0 965.4 1053.5 1192.7 1390.0 1625.4 1848.2 Construction 7.1 6.5 16.0 15.5 14.5 16.4 19.0 22.2 23.4 Transport, storage and 6.3 10.6 18.2 28.1 30.9 33.8 39.7 45.0 43.0 post Wholesale, retail trade 3.8 7.6 20.0 39.4 44.5 50.0 62.3 73.5 75.2 and hotel, restaurants Others 12.2 20.2 23.4 64.3 68.8 75.9 91.1 103.7 134.1 Residential 22.3 48.1 100.6 167.2 183.9 200.1 223.8 246.5 282.5 consumption Total 411.8 623.0 1002.3 1347.2 1472.4 1646.5 1903.2 2197.1 2494.0 Source: China Energy statistical Yearbook, 2005. * China Statistical Yearbook, 2006.

Wanwan Hou January 2009 University of New South Wales

Chapter 7

Fiscal Regime

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Throughout this study the term “fiscal regime” is taken to mean all economically quantifiable forms of Government involvement in oil and gas field developments. It includes State Participation, Royalty, Profit Sharing arrangement and all kinds of taxes. I define the contractors to be the companies operating in upstream petroleum sector and signing Production Sharing Contracts (PSCs) for exploring and developing of oil and gas fields.

Since the 1980s, the PSC has become the most commonly form of contract used to govern the joint study between Chinese and foreign companies in petroleum exploration. It is signed between the Chinese state-owned oil and gas companies and foreign oil companies, referred to as Contractors. China National Petroleum Corporation (CNPC) and China Petroleum and Chemical Corporation (Sinopec) are permitted to cooperate with international oil companies and are responsible for awarding concessions and monitoring the activities of those companies operating onshore China. The China National Offshore Oil Corporation (CNOOC) is responsible for offshore China. Since 1982, the Chinese government has openly invited tenders from overseas companies for the exploration for oil and gas in its offshore blocks. Since the early 1990s, some of the onshore blocks have been opened to foreign companies as well. The Government has organised four open bidding rounds for offshore exploration areas and three bidding rounds for onshore areas. More than 150 PSCs have been signed for exploration and development in offshore areas and about 50 PSCs have been signed for onshore areas.

This study uses and contains a description and analysis of PSC terms which are believed to be typical of current agreements. A detailed description of the structure and components of these typical PSC provisions follows.

7.1 Structure

According to the model PSC for the fourth round of bidding for offshore joint exploration dated October 1992, the term of the contract shall not exceed thirty consecutive contract years from the date of signature, unless otherwise stipulated.

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The exploration period generally lasts seven years and consists of three phases – 3, 2 and 2 years. The development period starts from the approval of the Overall Development Program and end on the date of completion of development set in Overall Development Program. The production period for any discovery within the contract area shall not exceed fifteen years from the start of commercial production.

The ring fence is the whole of the production sharing contract area and not just the area surrounding the field development.

Figure 7.1 illustrates the basic structure of a typical Chinese PSC as a flow chart. The flow chart shows how the contractors’ after tax net cash flow is derived under the PSC terms. There are three main sections - a) the project’s cash flow, b) the Government’s cash flow, c) the contractors’ cash flow.

The beginning of the flow chart in the top left hand side of Figure 7.1 is Gross Revenue obtained from sales of petroleum. Royalty and Value Added Tax are levied as a percentage of Gross Revenue. In a typical Chinese PSC, the Value Added Tax rate is fixed while the Royalty rate is based on an incremental sliding scale depending on production rates (see later).

After Royalty and VAT, contractors are allowed to recover their costs subject to a Cost Recovery Ceiling (see later).

The remaining revenue after reducing Royalty and Cost Recovery is Profit Petroleum which is shared between the Government and contractors on a sliding scale depending on petroleum production.

After Profit Petroleum allocation, the contractors have to pay Bonus, Export Duty and Revenue Windfall Tax. Various Bonuses are paid by contractors out of their total revenue, (that is, the sum of Cost Recovery and contractors’ share of Profit Petroleum). In this analysis, I assume that all contractors’ share of oil production is exported. Therefore, contractors have to pay an Export Duty out of their total

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 7.3 revenue. When the price of crude oil sold is higher than US$40 per barrel, Revenue Windfall Tax is applied.

Finally, the contractors are liable to pay Income Tax. Taxable income is calculated by adding together the Cost Recovery and the contractors’ share of Profit Petroleum and subtracting operating costs as well as the depreciation of capital costs. On the right hand side of Figure 7.1, the contractors’ total revenue is equal to Cost Recovery plus the contractors’ share of Profit Petroleum. The contractors’ outgoings consist of Income Tax, Signature Bonus and the contractors’ share of capital and operating costs. The contractors’ Net Cash Flow shown at the bottom of the right hand side is the remaining revenue after deducting outgoings from total revenue.

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Figure 7.1 – Structure of Chinese PSC

Project Cash Flow Government Cash Flow Contractors Cash Flow

Gross Revenue

Royalty and Value Royalty and VAT to Added Tax (VAT) Government

Cost Recovery Cost Recovery to Contractors Profit Petroleum to Government

Profit Petroleum Profit Petroleum to Contractors

Export Duty to Export Duty Government

Bonuses to Bonuses Government

Revenue Windfall Revenue Windfall Tax to Government Tax

Income Tax to Government Income Tax

Contractors share of all costs spend

Net Cash Flow to Contractors

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7.2 Simplified illustration of workings of Chinese PSC

Table 7.1 gives an example of the calculation of contractors’ net cash flow in one year under Chinese offshore PSC terms for shallow water. I make the following assumptions for this calculation.

 The VAT rate is 5%.

 The Royalty rates are as shown in the table.

 The Cost Recovery Ceiling is 54.5%.

 The contractors’ shares of Profit Petroleum are as shown in the table.

 The Income Tax rate is 25%.

 The Export Duty rate is 5%.

 The oil price is US$80/bbl.

 The only costs incurred during the year are operating costs.

 Capital costs have already been depreciated for tax.

 Table 7.1 - Example calculation of the contractors' net cash flow in one year under Chinese PSC terms  Gross Revenue Comments Oil Production (Kbopd) 50.0 Example data Oil Price (US$/bbl) 80.0 Example data Oil Revenue (US$MM) 1,460.0 Production * price * 365 days Royalty and VAT  Gross Revenue (US$MM) 1,460.0 From above Value Added Tax (US$MM) 5% 73.0 Gross Revenue * VAT rate (5%) Production  A Below 20 Kbopd 0% 0.0 Production in Tranche A * Royalty rate Tranche A B Between 20 and 30 Kbopd 4% 0.4 Production in Tranche B * Royalty rate Tranche B C Between 30 and 40 Kbopd 6% 0.6 Production in Tranche C * Royalty rate Tranche C D Between 40 and 60 Kbopd 8% 0.8 Production in Tranche D * Royalty rate Tranche D E Between 60 and 80 Kbopd 10% 0.0 Production in Tranche E * Royalty rate Tranche E F Over 80 Kbopd 12.5 0.0 Production in Tranche F * Royalty rate Tranche F % Total (Kbopd) 1.8 Sum of Tranche A to F Calculated Oil Royalty Rate (%) 3.6% Total(Kbopd) divided by oil production rate(Kbopd) Oil Royalty (US$MM) 52.6 Gross Revenue * calculated oil Royalty rate Royalty and VAT (US$MM) 125.6 Oil Royalty + VAT

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 Table 7.1 - Example calculation of the contractors' net cash flow in one year under Chinese PSC terms - continued  Cost Recovery (US$MM)  Available Cost Recovery (54.5%)  795.7 Gross Revenue * Cost Recovery Ceiling Opex this year 60.0 Example data Unrecovered opex from previous year 0.0 Example data Total opex to recover 60.0 Sum of two costs above Opex recovery 60.0 The minimum of available Cost Recovery and total  opex to recover “Investment recovery oil” 735.7 Available Cost Recovery after recovering opex Exploration costs this year 0.0 Example data Unrecovered expl costs from previous 0.0 Example data year Total exploration costs to recover 0.0 Sum of two costs above Exploration Cost Recovery 0.0 The minimum of available Cost Recovery and total  exploration cost to recover Remaining recovery oil 735.7 Available Cost Recovery after recovering exploration costs Development costs this year 0.0 Example data Unrecovered dev costs from previous 0.0 Example data year Total dev costs to recover with interest 0.0 Sum of two costs above Development Cost Recovery 0.0 The minimum of available Cost Recovery and total  development costs to recover Total Cost Recovery to contractors 60.0 Opex + exploration + development Cost Recovery   Profit Petroleum (US$MM)  Gross Revenue 1,460.0 From the oil revenue calculation above Royalty and VAT 125.6 From the Royalty and VAT calculation above Cost Recovery to contractors 60.0 From the Cost Recovery calculation above Total Profit Petroleum  1,274.4 Gross Revenue - Royalty - Cost Recovery A Production below 20 Kbopd 100% 20.0 Prodn in TrancheA * Contractors% in TrancheA B Production between 20 & 40 Kbopd 95% 19.0 Prodn in TrancheB * Contractors% in TrancheB C Production between 40 & 60 Kbopd 90% 9.0 Prodn in TrancheC * Contractors% in TrancheC D Production between 60 & 100 Kbopd 85% 0.0 Prodn in TrancheD * Contractors% in TrancheD E Production between 100 & 150 Kbopd 80% 0.0 Prodn in TrancheE * Contractors% in TrancheE F Production between 150 & 200 Kbopd 70% 0.0 Prodn in TrancheF * Contractors% in TrancheF G Production over 200 Kbopd 60% 0.0 Prodn in TrancheG * Contractors% in TrancheG Total (Kbopd)  48.0 Sum of Tranche A to G Contractors' rate of Profit Petroleum (%) 96.0% Total(Kbopd) divided by prodn rate(Kbopd) Contractors' Profit Petroleum 1,223.5 Profit Petroleum * rate of Profit Petroleum   Export Duty  Cost Recovery to contractors 60.0 From the Cost Recovery calculation above Contractors' Profit Petroleum 1,223.5 From the Profit Petroleum calculation above Contractors' total revenue  1,283.5 Sum of two revenues above Export Duty 5% 64.2 Contractors' total revenue * Export Duty rate

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 Table 7.1 - Example calculation of the contractors' net cash flow in one year under Chinese PSC terms - continued  Revenue Windfall Tax  Contractors' total revenue 1,283.5 From the Contractors' total revenue calculated above Oil price 80.0 From above Contractors' oil production 16.0 Contractors' total revenue/oil price A US$40/bbl < Oil price <= US$45/bbl 20% 1.0 (Oil price - US$40) * the rate - Quick Calculation Deduction(0.0) B US$45/bbl < Oil price <= US$50/bbl 25% 1.0 (Oil price - US$45) * the rate - Quick Calculation Deduction(0.25) C US$50/bbl < Oil price <= US$55/bbl 30% 0.8 (Oil price - US$50) * the rate - Quick Calculation Deduction(0.75) D US$55/bbl < Oil price <= US$60/bbl 35% 0.3 (Oil price - US$55) * the rate - Quick Calculation Deduction(1.5) E Oil price > US$60/bbl 40% 5.5 (Oil price - US$60) * the rate - Quick Calculation Deduction(2.5) Revenue Windfall Tax for one barrel of oil 8.5 Sum of Tranches A to E Revenue Windfall Tax 136.4 Revenue Windfall Tax for one barrel of oil * Contractors' oil prodn   Income Tax (US$MM)  Contractors' total revenue 1,283.5 From the contractors' total revenue calculated above Exploration Cost 0.0 From above Depreciated Development costs 0.0 Example data Operating Costs 60.0 From above Export Duty 64.2 From the Export Duty calculation above Revenue Windfall Tax 136.4 From the Revenue Windfall Tax calculation above Taxable Income 1,022.9 Contractors' revenue-sum of 3 costs above Taxable income with loss carry forward 1,022.9 Taxable income - loss from previous year Total taxable income 1,022.9 From taxable income with loss carry forward Income Tax rate (%) 25% Rate under tax law Income Tax 255.7 Total taxable income * Income Tax rate   Contractors' Net Cash Flow  Contractors' Cost Recovery 60.0 From Cost Recovery calculation above Contractors' Profit Petroleum 1,223.5 From Profit Petroleum calculation above Contractors' Total Revenue 1,283.5 Sum of two revenues above Exploration Cost 0.0 From above Development Costs 0.0 From above Operating Costs 60.0 From above Export Duty 64.2 From the Export Duty calculation above Revenue Windfall Tax 136.4 From the Revenue Windfall Tax calculation above Income Tax 255.7 From the Income Tax calculation above Contractors' Net Cash Flow 767.2 Contractors' total revenue - sum of above 6 loss

Calculation of Government Take (Gov Take") Project Gross Revenue 1,460.0 From oil revenue calculation above Project total costs 60.0 Exploration + development + operating costs Project Net Cash Flow before Gov Take 1,400.0 Project Gross Revenue - project total costs Contractors' Net Cash Flow after Gov Take 767.2 From Contractors' NCF calculation above Difference = Government Take 632.8 Equal to 45% of project net cash flow

7.3 Components of Chinese PSCs

The main components of the Chinese PSCs are described in detail below.

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7.3.1 Royalty

On 1 January 1989, an incremental sliding scale Royalty was introduced for offshore PSCs.

According to the model contract for the fourth bidding round for offshore co- operation dated October 1992, Royalty is paid in accordance with “Provisions Concerning the Payment of Royalties for the Exploitation of Offshore Petroleum Resource” (see Appendix E).

In these regulations, the Royalty on crude oil for offshore projects is based on the crude oil production in the contract area. The sliding scale Royalty rate for fourth round contracts is shown below.

 Table 7.2 - Royalty scale for crude oil from offshore China  Production (bopd) Royalty Rate

Below 20,000 0% 20,000 - 30,000 4% 30,000 - 40,000 6% 40,000 - 60,000 8% 60,000 - 80,000 10% Over 80,000 12.5%

The Royalty on natural gas for offshore projects is calculated based on natural gas production in the contract area. The sliding scale Royalty rate for the fourth round contracts is given below.

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 Table 7.3 - Royalty scale for natural gas from offshore China  Production (MMcfd)* Royalty Rate

Below 193.4 0% 193.4 – 338.5 1% 338.5 – 483.6 2% Over 483.6 3% * Converted from cubic metre assuming 1 cubic metre = 35.3 cubic feet (cf)

The sliding scale Royalty rate for crude oil and natural gas from onshore China is shown in Table 7.4. On 28th July 1995, the Ministry of Finance provided a concession on the Royalty rates for onshore production especially for production in Qinghai Province, Tibet Autonomous Region, Xinjiang Uygur Autonomous Region. The concession also applied to shallow water areas across China. However, no definition of shallow water was supplied. These areas are “designated areas”.

 Table 7.4 - Royalty scale for crude oil from onshore China  Production (bopd) Royalty Rate  Designated Areas* Other Areas Below 10,000 0% 0% 10,000 - 20,000 0% 2% 20,000 - 30,000 4% 4% 30,000 - 40,000 6% 6% 40,000 - 60,000 8% 8% 60,000 - 80,000 10% 10% Over 80,000 12.5% 12.5% * Qinghai Province, Tibet Autonomous Region, Xinjiang Uygur Autonomous Region and shallow water areas

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 Table 7.5 - Royalty scale for natural gas from onshore China  Production (MMcfd)# Royalty Rate Designated Areas* Other Areas  Below 193.4 Below 96.7 0% 193.4 – 338.5 96.7 – 241.8 1% 338.5 – 483.6 241.8 – 483.6 2% Over 483.6 Over 483.6 3% * Qinghai Province, Tibet Autonomous Region, Xinjiang Uygur Autonomous Region and shallow water areas # Converted from cubic metre assuming 1 cubic metre = 35.3 cubic feet (cf)

7.3.2 Value Added Tax

There is also a Value Added Tax (VAT), which is based on Gross Revenue. The levy applies since 1st January 1994 and replaces the Consolidated Industrial and Commercial Tax (CICT). The rate of VAT is 5%.

7.3.3 Cost Recovery

Under typical PSCs, contractors are allowed to recover their costs of exploration, development and operation incurred within the production sharing contract area from the revenue after Royalty (See the comment on ring fencing in section 7.1 above).

Under Chinese PSCs, there is a limit on Cost Recovery, referred to here as Cost Recovery Ceiling or “Cost Recovery Oil”. This is the maximum amount of project revenue the contractors can use to recover costs. The Cost Recovery Ceiling for the fourth round of bidding for offshore productions has a sliding scale. Onshore PSCs have a fixed ceiling. The details are given below.

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  Table 7.6 - Cost Recovery Ceiling    Production (bopd) Cost Recovery Ceiling  Fourth Round - Offshore Onshore Below 20,000 62.5% 60% 20,000 - 30,000 58.5% 60% 30,000 - 40,000 56.5% 60% 40,000 - 60,000 54.5% 60% 60,000 - 80,000 52.5% 60% Over 80,000 50.0% 60%

At first sight this arrangement may appear unusual because normally it is expected that the terms for offshore areas give incentives compared to onshore areas. However, most onshore exploration carried out by foreign contractors in China is in remote areas and any commercial discovery will require large investment in infrastructure to bring it to market. According to the model contract, the Cost Recovery Ceiling for natural gas developments is 70%.

In Chinese PSCs, costs are recovered in the following order -

1. Operating costs 2. Exploration costs 3. Development costs with interest

Contractors can also recover interest on unrecovered development costs at a rate of 9%. Interest on other costs is not recoverable.

Unrecovered costs in any one year can be carried forward and recovered in future years, but are still subject to the Cost Recovery Ceiling. Any costs incurred in the contract area that have not been fully recovered by the end of the production period remain unrecovered and cannot be transferred to other PSCs in China.

A description of the way in which costs are recovered is set out below.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 7.12 a) Operating costs

Operating costs are costs incurred in the production of petroleum. They mainly consist of maintenance costs and field labour costs etc. These also include periodic general and administration costs. b) Exploration costs

Any Cost Recovery oil remaining after recovering operating costs is called “Investment Recovery Oil”. The first claim on Investment Recovery Oil is exploration costs in the contract area. Exploration costs are costs incurred in the search for petroleum. They include -

 Geological, geophysical, geochemical, topographical and seismic data acquisition, processing and interpretation

 Exploration and appraisal wells (including facilities, materials, labour and services)

 General and administration expenditures allocated to exploration costs c) Development costs

Any Investment Recovery Oil remaining after recovering exploration costs is used to recover development costs incurred in the contract area. Development costs are costs incurred in the construction of petroleum reservoirs and all associated offtake, processing and transport systems. They include -

 Drilling wells to produce petroleum. These include dry development, production and injection wells;

 Completed production and injection wells

 Costs related to material, labour and services used in drilling and completing wells

 Purchasing, leasing, installing or constructing facilities such as platforms, storage tankers, flow lines, pipelines, wellhead equipment, subsurface equipment export

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terminals etc

 Costs related to studies of field facilities

 General and administration expenditures allocated to development costs

Costs not recoverable

Non-recoverable costs include -

 Costs incurred before the PSC is signed

 Any types of petroleum Bonuses including Signature Bonuses

 Interest on petroleum exploration and production costs

 Fines and penalties

 Donations and contributions

 Losses that have been compensated by insurance

Abandonment costs are not specifically mentioned in the model PSC. I therefore assume that no provisions for abandonment costs are allowed and abandonment costs are not recoverable.

7.3.4 Profit Sharing

Revenues remaining after deducting Royalty, VAT and Cost Recovery are identified as “Remainder Oil” - also widely known as “Profit Oil”. Profit Oil is divided into “Share Oil” for the Government and “Allocable remainder oil” for the Contractors. In Chinese PSCs, these are calculated using a negotiable percentage based on the average daily production rate. An indicative sliding scale Profit Sharing arrangement is shown in the following tables.

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 Table 7.7 - Profit Sharing for crude oil from onshore China  Annual crude oil production (bopd) Allocable Government's remainder oil share oil

Below 6,000 98% 2% 6,000 - 12,000 94% 6% 12,000 - 24,000 92% 8% 24,000 - 36,000 85% 15% 36,000 - 48,000 75% 25% 48,000 - 70,000 60% 40% 70,000 - 100,000 50% 50% Over 100,000 40% 60%

 Table 7.8 - Profit Sharing for crude oil from offshore China  Annual crude oil production (bopd) Allocable Government's share remainder oil oil

Below 20,000 100% 0% 20,000 - 40,000 95% 5% 40,000 - 60,000 90% 10% 60,000 - 100,000 85% 15% 100,000 - 150,000 80% 20% 150,000 - 200,000 70% 30% Over 200,000 60% 40%

For low levels of production, although the Cost Recovery Ceiling is only 50% to 62.5%, in fact the contractors receive 100% of Profit Oil anyway. This means effectively that there is no ceiling for low production.

Profit Gas is defined in the same way as Profit Oil. The Profit Sharing arrangement for natural gas is different from crude oil. The Profit Shares for gas are negotiated by the parties so that the contractor is able to obtain a reasonable economic benefit from the project. Indicative Profit Shares for gas are shown in Table 7.9 -

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  Table 7.9 - Profit Sharing for natural gas    Annual gas production (MMcfd)* Allocable remainder gas Government's share gas

Below 29.0 98% 2% 29.0 - 58.0 96% 4% 58.0 - 116.1 94% 6% 116.1 - 174.1 90% 10% 174.1 - 232.1 75% 25% 232.1 - 338.5 60% 40% 338.5 - 483.6 50% 50% Over 483.6 40% 60% * Converted from cubic metre assuming 1 cubic metre = 35.3 cubic feet (cf)

The “Allocable remainder oil/gas” is the amount of Profit Oil/gas to be divided amongst the participants in the contract. “Share Oil/Gas” goes directly to the Government.

7.3.5 State Participation

According to the model PSC for the fourth round of bidding for offshore cooperation in China, the “Allocable remainder oil” of each oil field in each calendar year is shared by the participators in proportion to their respective participating interests in the development. CNOOC, CNPC and Sinopec have the option to take a 51% share in the development of a field and accordingly receive 51% of the “Allocable remainder oil”. CNOOC, CNPC and Sinopec will reimburse the other participants for their share of any development and operating costs incurred on their behalf. However, they do not reimburse participants in respect of exploration costs. In other words, contractors have to bear all the exploration risk involved. However, contractors can recover through Cost Recovery those exploration costs spent on behalf of CNOOC, CNPC and Sinopec.

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7.3.6 Signature Bonus and Submission Fee

PSCs in all four offshore licensing rounds and three onshore rounds include a Signature Bonus of $1 million. Bonuses are not recoverable for the purposes of Cost Recovery.

The Bonus schedule is described below.

 US$0.25 million payable within 30 days of the Effective Date of the PSC

 US$0.25 million payable within 30 days of the expiry of the First Exploration Period

 US$0.5 million payable within 30 days of the approval of Overall Development Plan

There is another fee called the “Submission fee”. When a bid is submitted, contractors have to pay a non-refundable fee between US$10,000 to US$40,000 depending on the size of the PSC.

Signature Bonuses and Submission fee are deductable for tax purposes.

7.3.7 Export Duty

An additional tax is imposed on contractors’ crude oil exports from offshore fields in China. This tax is referred to as Export Duty. Export Duty became effective from 1 August 2007 and the rate was set to be 5% of contractors’ revenue. However, Contractors are granted a five-year holiday from paying Export Duty if they are working on contracts that are already signed with Chinese partners.

The Government has stipulated that crude oil produced from onshore fields in China is to be sold to the domestic market.

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7.3.8 Revenue Windfall Tax

On 25 March 2006, the State Council decided to levy a “Petroleum Special Profit Charge” which is also known as the “Revenue Windfall Tax” on oil producers (both domestic and foreign) selling crude oil produced in China. The Revenue Windfall Tax was put into effect on 26 March 2006 and only applies to the crude oil sold after this date. According to the Ministry of Finance, the Revenue Windfall Tax is applicable regardless of whether the crude oil is sold within or outside China.

The Revenue Windfall Tax is to be levied when the weighted average price of crude oil sold in any month exceeds US$40 per barrel. The rate starts at 20% and rises by 5% for each additional US$5 per barrel increase in crude oil price until it reaches a ceiling of 40% at US$60 per barrel. The Revenue Windfall Tax payable per barrel is calculated as follows –

(Monthly weighted average price per barrel of crude oil sold - US$40) multiplied by the Revenue Windfall Tax rate less the “Quick Calculation Deduction”.

The tax rates and the Quick Calculation Deductions for different ranges of crude oil price are given in Table 7.10.

 Table 7.10 - Revenue Windfall Tax in China  Crude oil price (US$/bbl) Rate Quick Calculation Deduction (US$)

40 - 45 (including 45) 20% 0.00 45 - 50 (including 50) 25% 0.25 50 - 55 (including 55) 30% 0.75 55 - 60 (including 60) 35% 1.50 above 60 40% 2.50

The monthly average price of crude oil is calculated by dividing the total revenue from crude oil sold in one month by the total number of barrels of crude oil sold in that month.

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The Government is considering raising the threshold of Revenue Windfall Tax from US$40 per barrel to US$80 per barrel as the levy has caused oil companies to suffer significantly financial losses in recent years.

The Revenue Windfall Tax is regarded as “non-tax revenue”. It is collected and administered by the Ministry of Finance rather than the State taxation authorities. Nevertheless, the tax paid is treated as a business expense and is deductible for Income Tax purposes.

7.3.9 Income Tax

As from 1991, corporation tax (Income Tax) has been charged at 30% for foreign companies. In addition, there is a maximum 3% local tax on the contractors’ share of revenue less its share of costs. A new Corporation Income Tax Law has been promulgated in March 2007 and put into effect in 1 January 2008. In this new law, the Income Tax rate was reduced to 25% for both domestic and foreign companies. There is no local tax in the new tax law.

The contractors’ revenue contains two elements -

 Cost Recovery to the contractor

 The contractors’ share of Allocable Remainder Oil

The deductions for Income Tax are –

 Bonuses

 Export Duty

 Revenue Windfall Tax

 The contractors’ share of the operating costs, exploration costs and the depreciation of development costs

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Operating and exploration costs are written off immediately once production begins. Development costs are written off over a period of not less than 6 years on a straight line basis once production commences.

Abandonment costs are not specifically mentioned. Therefore, I assume that provisions for abandonment costs would not be allowed and abandonment costs only become deductible once incurred.

Losses can be carried forward. There is a ring fence around the contract area for tax purposes. However, in 1988, the General Taxation Bureau of the Ministry of Finance announced modifications to relax the ring fence to allow failed exploration expenses anywhere in China to be offset against taxable income. In other words, if a foreign contractor terminates a contract, expenses from that operation can be carried over to reduce the taxable income in any new contract signed within 10 years from the termination date of the first contract.

7.4 Worked example of a Chinese PSC

The following table presents a detailed example of the workings of a Chinese PSC as it would apply to a hypothetical stand alone offshore oil field development. For the purposes of presentation only, calculations are shown only for the first 10 years.

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Table 1a Production & Revenue Units Spare Total 1 2 3 4 5 6 7 8 9 10 Oil production per day Kbopd  20.60 30.90 41.20 41.20 32.53 25.69 20.28 Oil production per year MMbbl/yr  77.53 7.52 11.28 15.04 15.04 11.87 9.38 7.40 Years of production Years  1 2 3 4 5 6 7 Price escalation per year % 3%  1.00 1.03 1.06 1.09 1.13 1.16 1.19 1.23 1.27 1.30 Oil price US$/bbl 80.00  80.00 82.40 84.87 87.42 90.04 92.74 95.52 98.39 101.34 104.38 Gross Revenue US$MM  7,395.27 657.29 1,015.51 1,394.63 1,436.47 1,168.32 950.22 772.84 Table 1b Production & Revenue Explanations            Oil production per day Average production in thousand barrels per day  Oil production per year Production in million barrels per year  Years of production Number of years from production start  Price escalation Oil price escalation using the escalation rate shown in "Spare" column  Oil price Oil price in money of the day terms (US$ per barrel)  Gross Revenue Gross Revenue = Oil production * Oil price       

Table 2a Expenditures Units Spare Total 1 2 3 4 5 6 7 8 9 10 Exploration costs US$MM  -51.00 -25.50 -25.50 Development costs US$MM  -512.11 -25.61 -102.42 -153.63 -153.63 -76.82 Fixed operating costs US$MM -40.97 -286.78 -40.97 -40.97 -40.97 -40.97 -40.97 -40.97 -40.97 Variable operating costs per bbl US$/bbl -1.00  -1.00 -1.00 -1.00 -1.00 -1.00 -1.00 -1.00 Oil production per year MMbbl/yr  7.52 11.28 15.04 15.04 11.87 9.38 7.40 Variable operating costs per year US$MM  -7.52 -11.28 -15.04 -15.04 -11.87 -9.38 -7.40 Total operating costs US$MM  -364.31 -48.49 -52.25 -56.01 -56.01 -52.84 -50.35 -48.37 Past costs if any US$MM -122.00 -122.00   Table 2b Expenditures Explanations            Exploration costs Exploration costs in real terms  Development costs Development costs in real terms  Fixed operating costs Annual fixed operating costs in real terms  Variable operating costs per bbl Variable operating costs in US per bbl in real terms  Oil production per year Annual oil production in million barrels per year  Variable operating costs per year Variable operating costs in real terms = Variable costs in US$ per bbl in real terms * Annual oil production in million barrels  Total operating costs Sum of fixed and variable operating costs in real terms  Past costs if any Past costs spent 

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Table 3a Escalated expenditures Units Spare Total 1 2 3 4 5 6 7 8 9 10 Costs escalation factor per year % 3%  1.00 1.03 1.06 1.09 1.13 1.16 1.19 1.23 1.27 1.30 Exploration cost escalated US$MM  -51.77 -25.50 -26.27 Development cost escalated US$MM  -548.43 -25.61 -105.50 -162.99 -167.88 -86.46 Fixed operating cost escalated US$MM  -343.03 -44.77 -46.11 -47.49 -48.92 -50.39 -51.90 -53.46 Variable operating cost escalated US$/bbl  -92.44 -8.22 -12.69 -17.43 -17.96 -14.60 -11.88 -9.66 Total operating cost escalated US$MM  -435.47 -52.98 -58.80 -64.93 -66.88 -64.99 -63.78 -63.12 Past costs (exploration) US$MM -122.00 -122.00  Table 3b Escalated expenditures Explanations            Costs escalation factor Cost escalated using escalation rate shown in "Spare" column  Exploration cost escalated Exploration costs multiplied by cost escalation factor  Development cost escalated Development costs multiplied by cost escalation factor  Fixed operating cost escalated Fixed operating costs multiplied by cost escalation factor  Variable operating cost escalated Variable operating costs multiplied by cost escalation factor  Total operating cost escalated Fixed operating costs escalated plus variable operating cost escalated  Past costs (exploration) Past cost are already spent so no escalation occurs 

Table 4a Before-tax net cash flow Units Spare Total 1 2 3 4 5 6 7 8 9 10 Gross Revenue US$MM  7,395.27 657.29 1,015.51 1,394.63 1,436.47 1,168.32 950.22 772.84 Exploration cost escalated US$MM  -51.77 -25.50 -26.27 Development cost escalated US$MM  -548.43 -25.61 -105.50 -162.99 -167.88 -86.46 Operating cost escalated US$MM  -435.47 -52.98 -58.80 -64.93 -66.88 -64.99 -63.78 -63.12 Past costs US$MM -122.00 -122.00  Before-tax net cash flow US$MM  6,359.60 -51.11 -131.76 -162.99 436.42 870.25 1,329.70 1,369.60 1,103.33 886.44 709.72 Table 4a Before-tax net cash flow Explanations            Gross Revenue Gross Revenue from oil production  Exploration cost escalated Total project exploration costs  Development cost escalated Total project development costs  Operating cost escalated Total project operating costs  Past costs Past costs  Before-tax net cash flow Net cash flow for project = Gross Revenue - sum of exploration, development and operating costs. 

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Table 5a Royalty & VAT calculations Units Spare Total 1 2 3 4 5 6 7 8 9 10 Gross Revenue US$MM  7,395.27 657.29 1,015.51 1,394.63 1,436.47 1,168.32 950.22 772.84 VAT US$MM 5% 369.76 32.86 50.78 69.73 71.82 58.42 47.51 38.64 A production <= 20 Kbopd Kbopd 0%  B 20 Kbopd < Prodn <= 30 Kbopd Kbopd 4%  0.02 0.40 0.40 0.40 0.40 0.23 0.01 C 30 Kbopd < Prodn <= 40 Kbopd Kbopd 6%  0.05 0.60 0.60 0.15 D 40 Kbopd < Prodn <= 60 Kbopd Kbopd 8%  0.10 0.10 E 60 Kbopd < Prodn <= 80 Kbopd Kbopd 10%  F production > 80 Kbopd Kbopd 12.5%  Total kbopd  0.02 0.45 1.10 1.10 0.55 0.23 0.01 Calculated Oil Royalty Rate %  0.00% 0.00% 0.00% 0.12% 1.47% 2.66% 2.66% 1.70% 0.89% 0.06% Oil Royalty US$MM  119.67 0.77 14.92 37.10 38.21 19.82 8.42 0.43 VAT and Royalty US$MM  489.43 33.63 65.70 106.83 110.04 78.24 55.93 39.08 Table 5b Royalty & VAT calculations Explanations           Gross Revenue Gross Revenue from oil production VAT Value added tax = Gross Revenue * VAT rate (5%) A production <= 20 Kbopd Production less than or equal to 20,000 barrels per day * Royalty rate A in "Spare" column B 20 Kbopd < Prodn <= 30 Kbopd Production between 20,000 and 30,000 barrels per day * Royalty rate B in "Spare" column C 30 Kbopd < Prodn <= 40 Kbopd Production between 30,000 and 40,000 barrels per day * Royalty rate C in "Spare" column D 40 Kbopd < Prodn <= 60 Kbopd Production between 40,000 and 60,000 barrels per day * Royalty rate D in "Spare" column E 60 Kbopd < Prodn <= 80 Kbopd Production between 60,000 and 80,000 barrels per day * Royalty rate E in "Spare" column F production > 80 Kbopd Production over 80,000 barrels per day * Royalty rate F in "Spare" column Total Sum of Tranches A to F Calculated Royalty rate Royalty rate = Sum of Tranche A to F / Oil production rate Oil Royalty Royalty = Gross Revenue * Royalty rate VAT and Royalty VAT plus Royalty 

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Table 6a Contractors’ Cost Recovery Units Spare Total 1 2 3 4 5 6 7 8 9 10 Gross Revenue US$MM 7,395.27 657.29 1,015.51 1,394.63 1,436.47 1,168.32 950.22 772.84 Cost Recovery Ceiling assumed US$MM 62.5%  62.5% 62.5% 62.5% 62.5% 62.5% 62.5% 62.5% 62.5% 62.5% 62.5% Available Cost Recovery oil US$MM 4,622.05 410.80 634.69 871.64 897.79 730.20 593.89 483.02 Opex to be recovered this year US$MM 435.47 52.98 58.80 64.93 66.88 64.99 63.78 63.12 Unrecovered opex from previous year US$MM Total opex to be recovered US$MM 435.47 52.98 58.80 64.93 66.88 64.99 63.78 63.12 Opex recovery US$MM 435.47 52.98 58.80 64.93 66.88 64.99 63.78 63.12 Unrecovered opex this year US$MM  Investment recovery oil US$MM 4,186.57 357.82 575.89 806.72 830.92 665.21 530.11 419.91 Exp cost to be recovered this year US$MM 122.00 51.77 25.50 26.27 Unrecovered exp cost from previous year US$MM  25.50 51.77 51.77 Total exp cost to be recovered US$MM 180.80 25.50 51.77 51.77 51.77 Exp Cost Recovery US$MM 51.77 51.77 Unrecovered exp cost this year US$MM 122.00  25.50 51.77 51.77 Remaining recovery oil US$MM 4,134.81 306.06 575.89 806.72 830.92 665.21 530.11 419.91 Dev cost to be recovered this year US$MM 548.43 25.61 105.50 162.99 167.88 86.46 Unrecovered dev cost from previous year US$MM  25.61 133.41 308.40 197.98 Total dev cost to be recovered with interest US$MM 9% 1,273.71 25.61 133.41 308.40 504.04 302.26 Dev Cost Recovery US$MM 608.32 306.06 302.26 Unrecovered dev cost this year US$MM  25.61 133.41 308.40 197.98 Total Cost Recovery US$MM  1,095.56 410.80 361.07 64.93 66.88 64.99 63.78 63.12

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Table 6b Contractors’ Cost Recovery Explanations            Gross Revenue Gross Revenue from oil production  Cost Recovery Ceiling Cost Recovery Ceiling using the rate shown in "Spare" column  Available Cost Recovery oil Gross Revenue * Cost Recovery Ceiling  Opex to be recovered this year Contractors’ share of operating costs (assumed to be 100%)  Unrecovered opex from previous year Operating costs not recovered in the previous year  Total opex to be recovered Sum of all operating costs to be recovered in this year  Opex recovery Opex Cost Recovery = minimum of "available Cost Recovery oil" and "total opex to be recovered"  Unrecovered opex this year Unrecovered opex this year = Total opex to be recovered - Opex recovery  Investment recovery oil Investment recovery oil = Available Cost Recovery oil - Opex recovery  Exp cost to be recovered this year Total exploration costs (including Past costs as shown in "Spare" column)  Unrecovered exp cost from previous year Exploration costs not recovered in the previous year  Total exp cost to be recovered Sum of all exploration costs to be recovered in this year  Exp Cost Recovery Exploration Cost Recovery = minimum of "Investment recovery oil" and "total exp cost to be recovered"  Unrecovered exp cost this year Unrecovered exp cost this year = Total exp cost to be recovered – Exp Cost Recovery  Remaining recovery oil Remaining recovery oil = Investment recovery oil – Exp Cost Recovery  Dev cost to be recovered this year Contractors’ share of development costs (assumed to be 100%)  Unrecovered dev cost from previous year Development costs not recovered in the previous year  Total dev cost to be recovered with interest Sum of all development costs to be recovered in this year including interest on unrecovered costs  Dev Cost Recovery Development Cost Recovery = minimum of "Remaining recovery oil" and "total dev cost to be recovered"  Unrecovered dev cost this year Unrecovered dev cost this year = Total dev cost to be recovered – Dev Cost Recovery  Total Cost Recovery Company total Cost Recovery = Opex recovery + Exp Cost Recovery + Dev Cost Recovery 

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Table 7a Contractors’ Profit Oil Units Spare Total 1 2 3 4 5 6 7 8 9 10 Gross Revenue US$MM  7,395.27 657.29 1,015.51 1,394.63 1,436.47 1,168.32 950.22 772.84 VAT and Royalty US$MM  489.43 33.63 65.70 106.83 110.04 78.24 55.93 39.08 Total Cost Recovery US$MM  1,095.56 410.80 361.07 64.93 66.88 64.99 63.78 63.12 Profit Oil US$MM  5,810.29 212.85 588.75 1,222.87 1,259.56 1,025.09 830.52 670.65 Oil production Kbopd  20.60 30.90 41.20 41.20 32.53 25.69 20.28 Tranche A production <= 20 Kbopd  100%  20.00 20.00 20.00 20.00 20.00 20.00 20.00 Tranche B 20 Kbopd < Prodn <= 40 Kbopd  95%  0.57 10.35 19.00 19.00 11.91 5.40 0.27 Tranche C 40 Kbopd < Prodn <= 60 Kbopd  90%  1.08 1.08 Tranche D 60 Kbopd < Prodn <= 100 Kbopd  85%  Tranche E 100 Kbopd < Prodn <= 150 Kbopd  80%  Tranche F 150 Kbopd < Prodn <= 200 Kbopd  70%  Tranche G production > 200 Kbopd  60%  Total  20.57 30.35 40.08 40.08 31.91 25.40 20.27 Calculated contractors’ profit share %  0.0% 0.0% 0.0% 99.9% 98.2% 97.3% 97.3% 98.1% 98.9% 99.9% Contractors’ Profit Oil US$MM 100% 5,702.70 212.54 578.36 1,189.63 1,225.32 1,005.34 821.32 670.18 Table 7b Contractors’ Profit Oil Explanations            Gross Revenue Gross Revenue from oil production  VAT and Royalty Total VAT and Royalty  Total Cost Recovery Total Cost Recovery = Contractors’ Cost Recovery  Profit Petroleum Profit Petroleum = Gross Revenue - VAT and Royalty - Total Cost Recovery  Oil production Oil production per day  Tranche A production <= 20 Kbopd Production less than or equal to 20,000 barrels per day * Contractors’ share A in "Spare" column  Tranche B 20 Kbopd < Prodn <= 40 Kbopd Production between 20,000 and 40,000 barrels per day * Contractors’ share B in "Spare" column  Tranche C 40 Kbopd < Prodn <= 60 Kbopd Production between 40,000 and 60,000 barrels per day * Contractors’ share C in "Spare" column  Tranche D 60 Kbopd < Prodn <= 100 Kbopd Production between 60,000 and 100,000 barrels per day * Contractors’ share D in "Spare" column  Tranche E 100 Kbopd < Prodn <= 150 Kbopd Production between 100,000 and 150,000 barrels per day * Contractors’ share E in "Spare" column  Tranche F 150 Kbopd < Prodn <= 200 Kbopd Production between 150,000 and 200,000 barrels per day * Contractors’ share F in "Spare" column Tranche G production > 200 Kbopd Production over 200,000 barrels per day * Contractors’ share G in "Spare" column  Total Sum of Tranches A to G  Calculated contractors’ profit share Contractors’ share = Sum of Tranches A to G / Total oil production  Contractors’ Profit Oil Contractors’ Profit Oil = Profit Petroleum * Calculated contractors’ profit share 

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Table 8a Bonuses Units Spare Total 1 2 3 4 5 6 7 8 9 10 Bonus 1 - effective date of the PSC US$MM  0.25 0.25      Bonus 2 - expiry of 1st exp period US$MM  0.25 0.25  Bonus 3 - approval of dev plan US$MM  0.50  0.50      Total bonuses US$MM 1.00 0.25 0.25 0.50 Table 8b Bonuses Explanations            Bonus 1 - effective date of the PSC Bonus paid at the effective date of the PSC      Bonus 2 - expiry of 1st exp period Bonus paid at the expiry of the First Exploration Period  Bonus 3 - approval of dev plan Bonus paid for the approval of Overall Development Plan  Total Bonuses Sum of the three Bonuses 

Table 9a Contractors’ Export Duty Units Spare Total 1 2 3 4 5 6 7 8 9 10 Contractors’ Cost Recovery US$MM  1,095.56 410.80 361.07 64.93 66.88 64.99 63.78 63.12 Contractors’ Profit Oil US$MM  5,702.70 212.54 578.36 1,189.63 1,225.32 1,005.34 821.32 670.18 Contractors’ total revenue US$MM  6,798.25 623.35 939.43 1,254.56 1,292.20 1,070.33 885.10 733.29 Contractors' Export Duty US$MM 5% 339.91 31.17 46.97 62.73 64.61 53.52 44.25 36.66 Table 9b Contractors’ Export Duty Explanations            Contractors’ Cost Recovery Contractors’ Cost Recovery calculated above  Contractors’ Profit Oil Contractors’ share of Profit Petroleum calculated above  Contractors’ total revenue Equals Contractors’ Cost Recovery + Contractors’ Profit Oil  Contractors’ Export Duty Contractors’ Export Duty = Contractors’ total revenue * Export Duty rate 

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Table 10a Contractors’ Revenue Windfall Tax Units Spare Total 1 2 3 4 5 6 7 8 9 10 Contractors’ Cost Recovery US$MM  1,095.56 410.80 361.07 64.93 66.88 64.99 63.78 63.12 Contractors’ Profit Oil US$MM  5,702.70 212.54 578.36 1,189.63 1,225.32 1,005.34 821.32 670.18 Contractors’ total revenue US$MM  6,798.25 623.35 939.43 1,254.56 1,292.20 1,070.33 885.10 733.29 Oil price US$/bbl  80.00 82.40 84.87 87.42 90.04 92.74 95.52 98.39 101.34 104.38 Contractors' oil production MMbbl 71.26 7.13 10.43 13.53 13.53 10.88 8.73 7.03 A US$40/bbl < Oil price <= US$45/bbl US$/bbl 20%  1.00 1.00 1.00 1.00 1.00 1.00 1.00 B US$45/bbl < Oil price <= US$50/bbl US$/bbl 25%  1.00 1.00 1.00 1.00 1.00 1.00 1.00 C US$50/bbl < Oil price <= US$55/bbl US$/bbl 30%  0.75 0.75 0.75 0.75 0.75 0.75 0.75 D US$55/bbl < Oil price <= US$60/bbl US$/bbl 35%  0.25 0.25 0.25 0.25 0.25 0.25 0.25 F Oil price > US$60/bbl US$/bbl 40%  8.47 9.52 10.60 11.71 12.86 14.04 15.25 Revenue Windfall Tax per barrel US$/bbl  11.47 12.52 13.60 14.71 15.86 17.04 18.25

Revenue Windfall Tax US$MM  1,044.78 81.77 130.59 183.93 198.98 172.49 148.79 128.23 Table 10b Contractors’ Revenue Windfall Tax Explanations            Contractors’ Cost Recovery Contractors’ Cost Recovery calculated above      Contractors’ Profit Oil Contractors’ share of Profit Petroleum calculated above  Contractors’ total revenue Equals Contractors’ Cost Recovery + Contractors’ Profit Oil  Oil price Oil price in money of the day terms (US$ per barrel)  Contractors' oil production Contractors’ oil production = Contractors’ total revenue / Oil price  For oil price between US$40 and US$45 per barrel,(oil price - US$40) * Revenue Windfall Tax rate A in "Spare" column - “Quick Calculation A US$40/bbl < Oil price <= US$45/bbl Deduction”(0) For oil price between US$45 and US$50 per barrel,(oil price - US$45) * Revenue Windfall Tax rate B in "Spare" column - “Quick Calculation B US$45/bbl < Oil price <= US$50/bbl Deduction”(0.25) For oil price between US$50 and US$55 per barrel,(oil price - US$50) * Revenue Windfall Tax rate C in "Spare" column - “Quick Calculation C US$50/bbl < Oil price <= US$55/bbl Deduction”(0.75) For oil price between US$55 and US$60 per barrel,(oil price - US$55) * Revenue Windfall Tax rate D in "Spare" column - “Quick Calculation D US$55/bbl < Oil price <= US$60/bbl Deduction”(1.5) For oil price over US$60 per barrel,(oil price - US$60) * Revenue Windfall Tax rate F in "Spare" column - “Quick Calculation F Oil price > US$60/bbl Deduction”(2.5)  Revenue Windfall Tax per barrel Sum of Tranches A to F  Revenue Windfall Tax Revenue Windfall Tax = Revenue Windfall Tax per barrel * Contractors’ oil production 

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Table 11a Contractors’ Income Tax Units Spare Total 1 2 3 4 5 6 7 8 9 10 Contractors’ Cost Recovery US$MM  1,095.56 410.80 361.07 64.93 66.88 64.99 63.78 63.12 Contractors’ Profit Oil US$MM  5,702.70 212.54 578.36 1,189.63 1,225.32 1,005.34 821.32 670.18 Contractors’ total revenue US$MM  6,798.25 623.35 939.43 1,254.56 1,292.20 1,070.33 885.10 733.29 Exploration costs escalated US$MM -122.00 -51.77 -25.50 -26.27 Depreciated development costs # US$MM  -548.43 -91.41 -91.41 -91.41 -91.41 -91.41 -91.41 Operating costs escalated US$MM  -435.47 -52.98 -58.80 -64.93 -66.88 -64.99 -63.78 -63.12 Bonuses US$MM  -1.00 -0.25 -0.25 -0.50 Contractors’ Export Duty US$MM  -339.91 -31.17 -46.97 -62.73 -64.61 -53.52 -44.25 -36.66 Revenue Windfall Tax US$MM  -1,044.78 -81.77 -130.59 -183.93 -198.98 -172.49 -148.79 -128.23 Contractors’ net revenue US$MM  4,376.89 -25.75 -26.52 -0.50 366.02 611.66 851.57 870.32 687.93 536.87 505.28 With loss carry forward US$MM -122.00  -147.75 -174.27 -174.77 191.26 611.66 851.57 870.32 687.93 536.87 505.28 Contractors’ taxable income US$MM  4,254.89 191.26 611.66 851.57 870.32 687.93 536.87 505.28 Contractors’ Income Tax US$MM 25% 1,063.72 47.81 152.92 212.89 217.58 171.98 134.22 126.32 Table 11b Contractors’ Income Tax Explanations  Contractors’ Cost Recovery Contractors’ Cost Recovery calculated above  Contractors’ Profit Oil Contractors’ share of Profit Petroleum calculated above  Contractors’ total revenue Equals Contractors’ Cost Recovery + Contractors’ Profit Oil  Exploration costs escalated Total project exploration costs including past costs  Depreciated development costs Contractors’ share of escalated development costs (100%) are depreciated over 6 years on a straight line basis.  Operating costs escalated Contractors’ share of operating costs (100%)  Bonuses Bonuses calculated above  Contractors’ Export Duty Contractors’ Export Duty calculated above  Revenue Windfall Tax Revenue Windfall Tax calculated above  Contractors’ net revenue Equals contractors’ total revenue - Sum of all costs above  With loss carry forward Undeducted costs carried forward  Contractors’ taxable income Positive values of contractors’ net revenue after loss carry forward  Contractors’ Income Tax Equals Taxable income * Tax rate (33% from the "Spare" column)       Footnotes- # I assume that the depreciation method adopted is 6-year straight line method.

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Table 12a After-tax net cash flow Units Spare Total 1 2 3 4 5 6 7 8 9 10 Contractors’ Cost Recovery US$MM  1,095.56 410.80 361.07 64.93 66.88 64.99 63.78 63.12 Contractors’ Profit Oil US$MM  5,702.70 212.54 578.36 1,189.63 1,225.32 1,005.34 821.32 670.18 Contractors’ total revenue US$MM  6,798.25 623.35 939.43 1,254.56 1,292.20 1,070.33 885.10 733.29 Exploration costs escalated US$MM -122.00 -51.77 -25.50 -26.27 Development costs escalated US$MM  -548.43 -25.61 -105.50 -162.99 -167.88 -86.46 Operating costs escalated US$MM  -435.47 -52.98 -58.80 -64.93 -66.88 -64.99 -63.78 -63.12 Bonuses US$MM  -1.00 -0.25 -0.25 -0.50 Contractors’ Export Duty US$MM  -339.91 -31.17 -46.97 -62.73 -64.61 -53.52 -44.25 -36.66 Revenue Windfall Tax US$MM  -1,044.78 -81.77 -130.59 -183.93 -198.98 -172.49 -148.79 -128.23 Contractors’ Income Tax US$MM  -1,063.72 -47.81 -152.92 -212.89 -217.58 -171.98 -134.22 -126.32 After-tax net cash flow US$MM  3,313.17 -51.36 -132.01 -163.49 241.73 463.69 730.08 744.15 607.35 494.05 378.96 Table 12b After-tax net cash flow Explanations  Contractors’ Cost Recovery Contractors’ Cost Recovery calculated above  Contractors’ Profit Oil Contractors’ share of Profit Petroleum calculated above  Contractors’ total revenue Equals contractors’ Cost Recovery + Contractors’ Profit Oil  Exploration costs escalated Total project exploration costs  Development costs escalated Contractors’ share of development costs (100%)  Operating costs escalated Contractors’ share of operating costs (100%)  Bonuses Bonuses calculated  Contractors’ Export Duty Contractors’ Export Duty calculated  Revenue Windfall Tax Revenue Windfall Tax calculated  Contractors’ Income Tax Contractors’ Income Tax calculated  After-tax net cash flow Equals contractors’ total revenue - Sum of all costs - Bonuses - Export Duty - Revenue Windfall Tax - Income Tax 

Wanwan Hou January 2009 University of New South Wales

Chapter 8

Fiscal Analyses

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A description of the current fiscal regime in China is presented in Chapter 7. This chapter contains economic analyses of a hypothetical, but representative exploration and field development possibility in China. I assume the fiscal terms given in Chapter 7 apply to the hypothetical development.

The hypothetical analysis is representative of exploration and development conditions in the South China Sea in shallow water of less than 500 metres.

The aim of this chapter is to analyse in depth the economic effects of the Chinese fiscal terms on exploration and development.

8.1 Government Take

“Government Take” is the total amount of cash flow the government received by its involvement and participation in a project. Government Take includes royalties, the Government’s share of Profit Petroleum, Export Duty, Revenue Windfall Taxes, Income Taxes and Bonuses.

Government Take is defined in following -

Discounted Government Take = Present value of total project net cash flow less Present value of the contractors’ net cash flow

Undiscounted Government Take = Total project net cash flow less Contractors’ net cash flow

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

Undiscounted Government Take = Undiscounted Government Take as a percentage divided by Total project net cash flow

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The total project net cash flow before Government Take is derived by deducting the project total costs from the Gross Revenue. The Gross Revenue is the total revenue received from the sale of petroleum produced in the project. The total costs consist of exploration, development, operating and the abandonment costs incurred at the end of the project life.

8.2 Fiscal severity and flexibility

My analyses of the Chinese fiscal terms include estimates of their severity and their flexibility. As regards the latter, I examine to what extent the terms are regressive or progressive and to what extent they are efficient. The terms severity, regressive/progressive and efficiency are discussed below.

Severity

The fiscal severity of a regime is determined by measuring Government Take for highly profitable developments with before-take NPV of more than approximately 4,000 to 5,000 million dollars.

Regressive/progressive

The meanings of regressive and progressive are summarised below and are illustrated in Figure 8.1.

Regressive = Government Take as percentage of project before-take NPV is higher for small and marginal projects than it is for more profitable projects. Progressive = Government Take as percentage of project before-take NPV increases with the increase in the profitability of projects.

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Figure 8.1 – Definition of regressive / progressive

100%

Progressive

Regressive Government Take in % 0% 0 Project before-take NPV in US$MM

Efficiency

The efficient and inefficient have the following meanings and are illustrated in Figure 8.2.

Efficient = Government Take is zero when the project before-take NCF or NPV is zero or negative. Inefficient = Government Take is positive when the project before-take NCF or NPV is zero or negative.

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Figure 8.2 – Definition of efficiency

Zero Inefficient Government Take US$MM Efficient

0 Contractors’ after-take NCF or Contractors’ NPV in Project before-take NCF or NPV in US$MM

8.3 Assumptions

The assumptions I use for the analyses in this chapter are set out below.

8.3.1 Economic assumptions

 I assume that the base case oil price is US$80 per barrel in 2008 escalated at 3% per year starting in 2009.  I assume that all exploration, appraisal, development and operating costs are escalated at 3% starting in 2009.  I calculate the NPV per barrel of nominal after-take net cash flow using a nominal discount rate of 10%.

8.3.2 Cost assumptions

I estimate the costs of exploration, appraisal, development and production based on the data from existing oil and gas fields in the shallow water region of South China Sea.

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Costs change from case to case as the geological and topographic conditions are different. The estimates I make are intended to be representative costs.

The detailed costs assumptions are listed below -

 I assume that an offshore 2D seismic survey would cost US$1,000 per kilometre.

 The cost of an exploration well is assumed to be US$20 MM per well for shallow water (less than 500 metres) in South China Sea.

 Appraisal wells are drilled after a discovery has been made and the costs for drilling in different conditions and areas vary. I assume that the cost of drilling an appraisal well is 85% of the cost for drilling an exploration well in the same area. Therefore, an offshore appraisal well drilling would cost US$17 MM per well in shallow water.

 I assume that development costs for various peak production rate equals the peak rate multiplied by a capex factor. Peak production depends on field size and location. I assume that the peak annual production varies from 15% to 30% of initial reserves. My assumptions for peak rates, capex factors and development costs are made in the following table.

             Table 8.1 - Peak rate and development cost estimation for oil field in South China Sea shallow water              Reserves MMbbl 10 20 30 40 50 75 100 125 150 200 225 250 Peak rate % 30% 28% 25% 23% 20% 18% 15% 15% 15% 15% 15% 15% Peak Kbopd 8.2 15.120.5 24.7 27.4 36.0 41.1 51.4 61.6 82.2 92.5 102.7 production Capex factor US$MM 20 19 18 17 16 15 14 13 12 11 10 9 /Kbopd Development US$MM 164 286 370 419 438 539 575 668 740 904 925 925 cost

 Annual fixed real operating costs in each year of production are assumed to be 8% of the total real development cost and the variable operating costs are estimated to be US$1 per barrel.

 I assume that the abandonment cost incurred at the end of the economic life of a field is 20% of the total development cost.

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8.3.3 Exploration and development timing

I assume the exploration period is the first two contract years. During the exploration period, a seismic survey of 2,000 kilometres is conducted and three exploration wells are drilled.

I assume that 50% of the total exploration costs are spent in the first contract year and another 50% are spent in the second year of the contract.

Appraisal, development and production phasings are shown in Table 8.2.

8.3.4 Fiscal terms

All fiscal assumptions are given in Table 8.3. These assumptions are based on the Chinese PSC terms described in Chapter 7.

In the analyses of this chapter, I assume no state participation. I assume that contractors hold 100% of the working interests of the projects.

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            Table 8.2 - Appraisal, development and production phasing               Year 1 2 3 4 5 6 7 8 9 10 Appraisal well phasing  fields less than 60 million barrels Number of wells 1 fields less than 120 million barrels Number of wells 1 1 fields more than 120 million barrels Number of wells 1 2 Production phasing  fields less than 20 million barrels % of peak* 100% Decline fields less than 60 million barrels % of peak* 75% 100% Decline fields more than 60 million barrels % of peak* 50% 75% 100% 100% Decline Development costs phasing % of total 5% 20% 30% 30% 15% * Peak production depends on field size and location. Peak production is assumed to vary from 15% to 30% of initial reserves.

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   Table 8.3 - Fiscal assumptions     Value Added Tax (VAT) 5% of Gross Revenue Royalty rate (% of Gross Revenue) 0% when the production rate is less than 20kbopd  4% when the production rate is between 20kbopd and 30kbopd  6% when the production rate is between 30kbopd and 40kbopd  8% when the production rate is between 40kbopd and 60kbopd  10% when the production rate is between 60kbopd and 80kbopd  12.5% when the production rate is more than 80kbopd Cost Recovery Ceiling 62.5% when the production rate is less than 20kbopd  58.5% when the production rate is between 20kbopd and 30kbopd  56.5% when the production rate is between 30kbopd and 40kbopd  54.5% when the production rate is between 40kbopd and 60kbopd  52.5% when the production rate is between 60kbopd and 80kbopd  50.0% when the production rate is more than 80kbopd Contractors' share of Profit Oil 100% when the production rate is less than 20kbopd  95% when the production rate is between 20kbopd and 40kbopd  90% when the production rate is between 40kbopd and 60kbopd  85% when the production rate is between 60kbopd and 100kbopd  80% when the production rate is between 100kbopd and 150kbopd  70% when the production rate is between 150kbopd and 200kbopd  60% when the production rate is more than 200kbopd Bonuses (US$MM) 0.25 Bonus paid for the effect of the PSC  0.25 Bonus paid for the expiry of the First Exploration Period  0.50 Bonus paid for the approval of Overall Development Plan Export Duty rate 5% of contractors' total revenue Revenue Windfall Tax rate 20% when the oil price is between US$40/bbl and US$45/bbl  25% when the oil price is between US$45/bbl and US$50/bbl  30% when the oil price is between US$50/bbl and US$55/bbl  35% when the oil price is between US$55/bbl and US$60/bbl  40% when the oil price is more than US$60/bbl Income Tax 25% of taxable income (development costs are depreciated over 6 years on a straight line basis)

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8.4 Analyses of individual components of Chinese fiscal terms

This section shows the economic impact of individual components of Chinese fiscal terms.

8.4.1 Single year analysis

Figure 8.3 shows a numerical example of a calculation of the contractors’ after-take net cash flow under example Chinese offshore PSC terms in a single year of a net cash flow analysis. It is a simplified illustration of the workings of the PSC. There are three main parts in this chart, which show a) the project cash flow, b) the Government cash flow and c) the contractors’ cash flow. The assumptions for the calculation are as follows –

 The only costs during the year are operating costs.  The Cost Recovery Ceiling is 58.5%.  Contractors’ share of Profit Petroleum is 95%.  Export Duty rate is 5%.  Bonus this year is US$0.  Income Tax rate is 25%.

Gross Revenue and Royalty

The beginning of the flow chart in the top left hand side of Figure 8.3 is Gross Revenue obtained from sales of petroleum. The Gross Revenue in this case is assumed to be $600. Value Added Tax and Royalty together are 6% of Gross Revenue.

Cost Recovery

Contractors can recover their costs from revenue available after Royalty. In this case, the contractors’ total cost is $550. However, there is a Cost Recovery Ceiling of 58.5%. The revenue available for Cost Recovery is only $351 and is not sufficient to recover the cost. Therefore the effective Cost Recovery is only $351.

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Figure 8.3 – Single year fiscal analysis

Project Cash Flow Government Cash Flow Contractors Cash Flow

Gross Revenue $600

Royalty (1%) and Royalty and VAT to Value Added Tax Government $36 (5%) $36

Contractors’ share Cost Recovery Ceiling 58.5% Cost Recovery to of Opex $550 contractors $351 Profit Petroleum to Government (5%) $11

Profit Petroleum Profit Petroleum $213 to contractors (95%)$202

Export Duty to Government $28 Export Duty (5%) $28

Bonuses to Government $0 Bonuses $0

Revenue Windfall Tax to Government Revenue Windfall $59 Tax (20%-40%) $59

Income Tax to Government $0 Income Tax (25%) $0

Contractors share of all costs spend $550

Net Cash Flow to contractors $-83

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Profit Sharing

The remaining revenue after reducing Royalty and Cost Recovery is Profit Petroleum ($213), which is shared between the Government and the contractors. The government receives 5% of the Profit Petroleum while the contractor gets the remaining 95%.

Bonuses, Export Duty and Revenue Windfall Tax

After Profit Petroleum, the contractors have to pay Bonuses, Export Duty and Revenue Windfall Tax. The Bonus is $0 in this example. I assume that all contractors’ oil production is exported. Therefore, the Export Duty payable is 5% of contractors’ total revenue, which is the sum of Cost Recovery and contractors’ share of Profit Petroleum. Since the oil price assumed is US$80 per barrel, the Revenue Windfall Tax is $59 based on the incremental sliding scale for Revenue Windfall Tax rates and the corresponding Quick Calculation Deductions.

Income Tax

Finally, the contractors are liable to pay Income Tax. Taxable income is calculated by adding together the Cost Recovery ($351) and the contractors’ share of Profit Petroleum ($202) and then subtracting the sum of the contractors’ total cost ($550), Export Duty ($28) and Revenue Windfall Tax paid ($59). Therefore, the taxable income is $0 and there is no tax liability.

Contractors’ net cash flow

On the right hand side of Figure 8.3, the contractors’ total revenue is equal to Cost Recovery ($351) plus the contractors’ share of Profit Petroleum ($202). The contractors’ total outgoings consist of Export Duty ($28), Bonus ($0), Revenue Windfall Tax ($59) and Income Tax ($0) and contractors’ total costs ($550). The contractors’ Net Cash Flow shown at the bottom of the right hand side is the remaining revenue after deducting their total outgoings from their total revenue. The net cash flow equals -$83.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.12

In this project, the net cash flow before Government Take is $50, but after Government Take, the net cash flow becomes negative (-$83). Thus the project is uneconomic.

8.4.2 Effect of changing net cash flow

Figure 8.4 illustrates the economic effects of each component of Government Take for this simple case over a range of values for before-take net cash flow. I assume a constant Gross Revenue ($600) and increasing costs ($100 to $600).

Figure 8.4 - Economic effects of components of Government Take - single year analyses

500

Government's share 400 of Profit Oil

300 Revenue Windfall Tax Before-take NCF Income Tax

200

100 Export Duty Components of NCF in$ Royalty 0 0 50 100 150 200 250 300 350 400 450 500 Case shown in Figure 8.3 -100 Project before-take NCF in $

In Figure 8.4, the solid line on the top shows the before-take net cash flow (NCF). The remaining five lines show the NCF after the cumulative effects of Royalty, Profit Sharing, Export Duty, Revenue Windfall Tax and Income Tax. The distance between two lines is the NCF of each fiscal component and therefore is a measure of the effect of each fiscal component.

As can be seen from the graph, regardless of the profitability of the project, Royalty and VAT together are always $36 because they are calculated based on Gross Revenue of $600. For the project with a before-take NCF of less than $36, the NCF would become negative after Royalty and VAT.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.13

If there is no Cost Recovery Ceiling for Cost Recovery, the Government’s share of Profit Petroleum would only be positive when the after-Royalty NCF is positive. However, the Cost Recovery Ceiling assumed for this example is 58.5%. Profit Petroleum is the remaining revenue after deducting Royalty and Cost Recovery. The total Cost Recovery in this case is much less than the total cost because of this Cost Recovery Ceiling. Therefore, even if the project is uneconomic after Royalty, the Profit Petroleum after deducting Royalty and Cost Recovery from the Gross Revenue is still positive.

In contrast, Income Tax only starts when the contractors’ taxable income is positive.

In this simplified example, Royalty, Profit Sharing, Export Duty and Revenue Windfall Tax are more damaging than Income Tax to marginal projects (projects with low net cash flow before Government Take). This is because they make marginal projects uneconomic, whereas Income Tax does not. For more profitable projects, Income Tax becomes more severe than other components.

8.4.3 Project life analyses for marginal field

The analysis above illustrates the effects of the Chinese fiscal terms for a single year. The following analysis illustrates the effects over the full life of a project.

Table 8.4 shows the calculation of contractor’s net cash flow for a hypothetical field with reserves of 4 million barrels. This field is in representative exploration and development conditions offshore China in the South China Sea in shallow water. The calculation follows the same procedure as stated in the single year case. However, instead of having only one production year, in this analysis fiscal terms are applied to the whole project life. The assumptions of fiscal terms are given in Table 8.3. In the following analyses, Royalty refers to both VAT and Royalty and, in order to illustrate the effect of fiscal terms, I use a real oil price of US$60 per barrel. The other assumptions are the same as those presented in section 8.3.

Excluding the effects of the fiscal terms, the project starts in 2008 and would finish in 2019 because from 2019 the Gross Revenue is not enough to cover all the costs.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.14

   Table 8.4 - Illustrative calculation of net cash flow over project life under Chinese PSC      Units Total 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Gross Revenue $MM 300.8 94.5 66.6 47.0 33.1 23.3 16.4 11.6 8.2 Exploration costs $MM 62.9 31.0 31.9  Development costs $MM 113.4 17.5 4.5 18.4 28.5 29.3 15.1  Operating costs $MM 72.6 9.2 8.9 8.8 8.9 8.9 9.1 9.3 9.5 Abandonment costs $MM 23.4 23.4 Before take NCF $MM 29.9 -31.0 -49.4 -4.5 -18.4 56.9 28.4 23.0 24.2 14.4 7.4 2.3 -23.4 Total Royalty $MM 14.6  4.7 3.3 2.3 1.7 1.2 0.8 0.6  NCF after Royalty $MM 15.2 -31.0 -49.4 -4.5 -18.4 52.1 25.0 20.7 22.6 13.2 6.5 1.7 -23.4 Contractors' Cost Recovery $MM 182.9  59.1 41.6 29.4 20.7 14.6 10.3 7.2  Profit Oil $MM 95.1 30.7 21.7 15.3 10.8 7.6 5.3 3.8  Contractors' Profit Oil $MM 95.1 30.7 21.7 15.3 10.8 7.6 5.3 3.8  NCF after Profit Sharing $MM 15.2 -31.0 -49.4 -4.5 -18.4 52.1 25.0 20.7 22.6 13.2 6.5 1.7 -23.4 Bonuses $MM 1.0 0.3 0.3 0.5  NCF after Bonuses $MM 14.2 -31.3 -49.7 -5.0 -18.4 52.1 25.0 20.7 22.6 13.2 6.5 1.7 -23.4 Contractors' total revenue $MM 278.0 89.8 63.3 44.6 31.4 22.2 15.6 11.0  Export Duty $MM 13.9 4.5 3.2 2.2 1.6 1.1 0.8 0.6  NCF after Export Duty $MM 0.3 -31.3 -49.7 -5.0 -18.4 47.7 21.9 18.4 21.0 12.1 5.8 1.2 -23.4 Oil price $/bbl  60.0 61.8 63.7 65.6 67.5 69.6 71.6 73.8 76.0 78.3 80.6  Revenue Windfall Tax $MM 19.1 4.7 3.9 3.2 2.6 2.0 1.6 1.2  NCF after Revenue Windfall Tax $MM -18.1 -31.3 -49.7 -5.0 -18.4 43.0 17.9 15.2 18.5 10.1 4.2 -22.7  Taxable Income $MM 38.4  27.0 11.4   Income Tax $MM 9.6 6.7 2.9  After Tax NCF $MM -27.7 -31.3 -49.7 -5.0 -18.4 43.0 11.2 12.4 18.5 10.1 4.2 -22.7 

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.15

As shown in the table, the total before take NCF including abandonment costs is $29.9 MM. After Royalty, the total NCF becomes $15.2 MM. The Profit Oil to the Government is $0. Contractors receive 100% of the Profit Oil because the production rate in each year is below 20 Kbopd. After Export Duty, the total NCF falls further to $0.3 MM. After deducting Revenue Windfall Tax, the year in which it is uneconomic to continue production has been brought forward to 2018 and the total NCF becomes negative (-$18.1 MM).

Taxable income, as explained in the single year case, is calculated by adding together the Cost Recovery and the contractors’ share of Profit Oil and subtracting the contractors’ total deductions. The calculated taxable income is $38.4 MM. Therefore the contractors pay tax of $9.6 MM. The after-tax NCF is $27.7 MM.

The Income Tax payment is positive because the taxable income is positive in some years even though the total NCF after Revenue Windfall Tax is negative. This is mainly because of the depreciation of capital costs for Income Tax.

The application of Income Tax makes the total NCF to Government Take higher than in the single year case illustrated in Figure 8.3. This example indicates that all components of Government Take except Profit Sharing are damaging to marginal projects under a typical Chinese PSC system.

8.4.4 Project life analyses for a range of field sizes

I have generated the NCF per barrel of reserves for stand-alone field developments over a range of field sizes. The assumptions for the production profile, capital and operating costs of different field sizes are presented in section 8.3. In order to show the effect of fiscal terms more clearly, I assume the real oil price to be US$60/bbl for this analysis.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.16

Figure 8.5 - Economic effects of components of Government Take - project life analyses 60

50

40 Before-take NCF Government's share of Profit Oil 30 Export Duty Income Tax

20 Revenue Windfall Tax Royalty 10

0 0 102030405060

Components of NCF per bbl ($/bbl) -10 Case shown in Table 8.4 -20 Project before-take NCF per bbl of reserves ($/bbl)

Figure 8.5 shows the economic effects of each component of Government Take for the total project over a range of before-take NCFs per barrel of reserves. In Figure 8.5, the solid line on the top shows the before-take NCF per barrel of reserves and the following lines show the NCF after Royalty, after Profit Sharing, after Export Duty, after Revenue Windfall Tax and after Income Tax per barrel of reserves. The intercept of each curve and the horizontal axis indicates the minimum economic project NCF per barrel after each component of fiscal terms. As shown in the figure, the minimum economic project NCF per barrel increases after each fiscal component is applied. After Income Tax, the project would only be economic if the before tax NCF is higher than US$16 per barrel. Therefore, projects with profitability of lower than US$16 per barrel before-take would not be economic.

When the project profitability becomes high, the Royalty increases slightly because the Royalty rate goes up with the increase in production rate. The Government’s share of Profit Oil is zero for low profitability projects, because in this analysis low profitability is associated with low production rate. The Export Duty and Revenue Windfall Tax are almost constant for different levels of project profitability. In Figure 8.4 (for the single year analysis), Income Tax starts from the point at which the NCF after Revenue Windfall Tax is zero and does not hurt marginal projects. However, in

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.17 the total project analysis, it has a more damaging effect on the economics of the development of marginal fields and makes them uneconomic.

Figures 8.6 to 8.11 illustrate the impact of each component of Government Take individually. When analysing one particular component, it is assumed that the other components do not apply. For instance, Figure 8.6 shows the effect of only Royalty on the project net cash flow. For this diagram, the Government’s share of Profit Oil, the Bonuses, the Export Duty rate, the Revenue Windfall Tax rate and the Income Tax rate are assumed to be zero.

Figure 8.6 - Economic effects of Royalty - oil price US$60 /bbl

60

50

40 Before-take NCF

30

($/bbl) 20

Royalty 10

Before & after Royalty NCF per bbl 0 0 102030405060 -10 Project before-take NCF per bbl of reserves ($/bbl)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.18

Figure 8.7 - Economic effects of Profit Sharing - oil price US$60 /bbl

60

50 Before-take NCF Government's 40 share of Profit Oil

30

20 bbl ($/bbl) bbl

10

0 Before & after Profit Sharing NCF per 0 102030405060 -10 Project before-take NCF per bbl of reserves ($/bbl)

Figure 8.8 - Economic effects of Export Duty - oil price US$60 /bbl

60

50

40 Before-take NCF

30

($/bbl) 20 Export Duty

10

0

Before & after Export & after Duty Before NCF per bbl 0 102030405060 -10 Project before-take NCF per bbl of reserves ($/bbl)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.19

Figure 8.9 - Economic effects of Revenue Windfall Tax - oil price US$60 /bbl

60

50

40 Before-take NCF

30

20 Revenue Windfall Tax NCF per bbl ($/bbl) NCF per bbl 10

0 Before & after Revenue Windfall Tax 0 102030405060 -10 Project before-take NCF per bbl of reserves ($/bbl)

Figure 8.10 - Economic effects of Income Tax with depreciation - oil price US$60 /bbl 60

50

40 Before-take NCF

30

20 bbl ($/bbl)

Income Tax 10

Before & after IncomeNCF Tax per 0 0 102030405060 -10 Project before-take NCF per bbl of reserves ($/bbl)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.20

Figure 8.11 - Economic effects of Income Tax without depreciation - oil price US$60 /bbl 60

50

40 Before-take NCF

30

($/bbl) 20 Income Tax

10

0

Before & after Tncome Tax TncomeNCF per Tax & after bbl Before 0 102030405060

-10 Project before-take NCF per bbl of reserves ($/bbl)

From the illustration in the above graphs, it is clear that each component of Government Take under typical Chinese PSC system except Profit Sharing is inefficient. Figures 8.10 and 8.11 show the economic effect of Income Tax with and without the depreciation of capital costs respectively. In both cases, Income Tax is damaging to small projects, but in the case without depreciation, Income Tax is less severe. However, for the case without depreciation, Income Tax is still inefficient because there is no tax relief on abandonment costs.

8.5 Impact of fiscal terms on field development – oil price US$80 per bbl

In the sections above, I analyse the effect of individual components of the Chinese fiscal terms on the net cash flow of an oil project. This analysis was aimed at examining the severity and flexibility of the regime. In this section, I analyse the effect of the fiscal terms on oil field development decisions and focus on the NPV of net cash flow for a range of conditions. I generate the net present values (NPVs) per barrel of field development based on the economic analyses carried out in section 8.4.4.

Figure 8.12 shows the economic impact of the fiscal terms on field development over a range of reserves. For this analysis, I assume that the oil price is US$80/bbl.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.21

Figure 8.12 - Impact of fiscal terms - oil price US$80/bbl

60 Gross Revenue

50 Exploration, development, operating and abandonment costs Royalty NPV of BTNCF 40 Minimum size before Government Take

30 Export Duty Profit Sharing Revenue Windfall T

20 Income Tax

NPV of ATNCF

10 Minimum size after Contractors' NPV per bbl in $/bbl bbl NPV per Contractors' Government Take

0 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 Reserves in MMbbl

The top line in Figure 8.12 shows the NPV per barrel of reserves of the Gross Revenue generated from the sales of hydrocarbon produced from the field over the economic life of the project. The peak in the curve is an artefact of the production profile assumed and is not significant in this analysis.

The second curve below the Gross Revenue line is the NPV per barrel of reserves of the contractors’ before tax net cash flow. It is derived by subtracting the present value of exploration, development, operating and abandonment costs from the NPV of Gross Revenue.

The four dotted lines show the NPV of the project net cash flow after deducting successively a) the present value of Royalty, b) the present value of the Government’s share of Profit Petroleum, c) the present value of Export Duty and d) the present value of Revenue Windfall Tax. The distance between the top line and the second line indicates the NPV of Royalty. Similarly, the distance between any two dashed lines indicates the NPV of the Government’s share of Profit Petroleum, Export Duty or Revenue Windfall Tax.

The lowest line illustrates the NPV per barrel of the contractors’ after-take net cash flow.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.22

The distance between any two lines illustrates the economic impact of each component of Chinese fiscal terms on the contractors’ net present value.

Discounted Government Take – oil price US$80 per bbl

Figure 8.12 shows that for large fields at the right hand side of the figure, the project before-take NPV is US$40 per barrel. After all types of Government Take, the contractors’ NPV is US$17 per barrel. In other words, for profitable fields, discounted Government Take is 57% of the project before-take NPV.

Minimum field size – oil price US$80 per bbl

The figure also shows that when the oil price is US$80/bbl, the minimum field size making the development economic before any type of Government Take is about 3 million barrels (MMbbl). In other words, it is economic to develop a field with a discovery of more than approximately 3 million barrels if there is no Government Take. However after Government Take, the minimum economic field size increases to about 7 MMbbl. The fields with a discovery between 3 MMbbl and 7 MMbbl are rendered uneconomic because of Government Take, in which case neither the contractors nor the Government gain any benefit.

8.6 Impact of fiscal terms on field development – oil price US$20 per bbl

The analysis above is based on an assumption that the oil price is US$80/bbl. In contrast, Figure 8.13 shows the NPVs per barrel of oil development over a range of reserves at an oil price of US$20/bbl. This figure gives similar information to that in Figure 8.12, but is based on a much lower oil price. All the other assumptions remain the same.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.23

Figure 8.13 - Impact of fiscal terms - oil price US$20/bbl

6

5

NPV of BTNCF Royalty 4

Export Duty 3 Minimum size before Government Take Profit Sharing Income Tax

2

NPV of ATNCF 1

Contractors' NPV per bbl in $/bbl Minimum size after Government Take 0 0 50 100 150 200 250 Reserves in MMbbl

Discounted Government Take – oil price US$20 per bbl

Figure 8.13 shows that for a field with 250 MMbbl reserves, the project before-take NPV is more than US$6 per barrel. After Government Take, the contractors’ NPV is US$2.7 per barrel. Therefore, when oil price is US$20/bbl, discounted Government Take is about 55% of the project before-take NPV for profitable fields.

Minimum field size – oil price US$20 per bbl

As can be seen from Figure 8.13, minimum economic reserves before Government Take are 54 million barrels. However, after Government Take the minimum economic field size increases to 89 million barrels. The difference between the minimum economic field size before and after-take is significantly higher than that in the case with US$80/bbl oil price.

8.7 Analysis of Government Take

The previous section demonstrates that Chinese fiscal terms are more damaging to marginal field development at low oil prices than at high oil prices. This section illustrates the significance of each fiscal component based on the analysis presented in

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.24 section 8.6, in which the oil price assumed is US$20/bbl. I choose the case with the low oil price because it illustrates the effect of Government Take more clearly.

The Figure 8.14 plots each component of the Government Take as a percentage of the project’s before-tax NPV over a range of reserves.

Figure 8.14 - Fiscal component as percentage of BTNPV - oil price US$20/bbl

400% Fields uneconomic Government Take makes before Government field development 350% Fields economic after Take uneconomic Government Take 300%

250%

Government's Export Duty 200% Profit Oil

150% Income Tax 100% Percentage (%) BTNPV of Royalty 50%

0% 0 10 30 50 55 60 65 70 75 100 125 150 200 225 250 Reserves in MMbbl

As shown in Figure 8.13 in section 8.6, the minimum economic field sizes before and after Government Take are 54 MMbbl and 89 MMbbl respectively when oil price is US$20/bbl. As can be seen from Figure 8.14, Government Take is more than 100% of the before-take NPV for the field size between 54 and 89 million barrels. As discussed above, these fields will remain undeveloped, in which case Government Take will be zero.

The figure also shows that the smaller the field size, the more Government Take is as a percentage of the before-tax NPV. That is to say, the Government Take hurts marginal fields more heavily than larger fields. This demonstrates that Chinese fiscal regime is regressive. In Figure 8.14, for fields larger than 20 million barrels, the Government Take remains stable in terms of the percentage of the before-tax NPV (around 55% to 65%). These fields will remain economic after Government Take. However, with the

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.25 decrease in field size, each component especially Royalty increases dramatically and all together takes more than 100% of the project NPV.

Figure 8.14 shows that the Royalty as a percentage of before-take NPV is the largest of the fiscal components for smaller fields. This demonstrates that for marginal fields, Royalty has the most significant impact and can seriously damage the economics of field development.

8.8 Analysis of minimum economic field size

The effect of different components of Government Take on minimum economic field size can also be shown in Table 8.5 assuming the oil price is 20, 80 or 140 dollars per barrel.

       Table 8.5 - Effects of fiscal components on minimum developable field size        Oil price = US$20/bbl Oil price = US$80/bbl Oil price = US$140/bbl Increase in Increase in Increase in minimum field minimum field minimum Minimum Minimum Minimum Cases size caused by size caused by field size field size field size field size the fiscal the fiscal caused by the (MMbbl) (MMbbl) (MMbbl) regime regime fiscal regime (MMbbl) (MMbbl) (MMbbl) Before Government 54.13 2.80 1.26 Take After Royalty 66.57 12.43 2.99 0.19 1.38 0.12 After Government's 67.07 0.51 2.99 0.00 1.38 0.00 share of Profit Oil After Bonuses 67.23 0.16 3.02 0.03 1.40 0.02 After Export Duty 76.82 9.59 3.37 0.35 1.51 0.12 After Revenue 76.82 0.00 4.91 1.54 2.51 1.00 Windfall Tax After Income Tax 88.97 12.15 6.52 1.60 2.92 0.40

Table 8.5 shows that the component of Government Take which leads to the biggest increase in minimum economic field size varies for different oil prices. When oil price is low (US$20/bbl), the most severe component is Royalty, followed by Income Tax and Export Duty. Profit Sharing and Bonuses have little effect on the economics of the field development. Since the oil price is lower than the threshold of Revenue Windfall Tax (US40 per barrel), no Revenue Windfall Tax applies. When the oil price is US$80/bbl, the most severe components are Revenue Windfall Tax and Income Tax. Other

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.26 components do not affect the field economics very much. When oil price is very high (US$140/bbl), the component that has the biggest impact on field development is Revenue Windfall Tax, followed by Income Tax. The Government’s share of Profit Oil is 0 when oil price is US$80 or US$140 per barrel.

8.9 Comparison of fiscal components

The analyses carried out in previous sections demonstrate that Chinese fiscal regime is inefficient and regressive. Marginal fields are hurt heavily by Government Take, while profitable fields are relatively lightly taxed. The regressive components of Chinese fiscal terms include Royalty, Export Duty and depreciation of costs for Income Tax.

I summarise and compare the economic effect of each fiscal component in the following.

Royalty

Among the components in Chinese fiscal terms, Royalty has the greatest impact when the oil price is very low. Therefore, among the components of the Chinese PSC terms, Royalty is the most inefficient and regressive, because it tends to be more severe when the development is marginal. Marginal developments are those with low oil price, small field size, high costs or the combination of these factors. In addition, Royalty is levied at the very beginning of production, while other levies are imposed on the contractors’ revenue after Royalty, Cost Recovery and Profit Sharing.

Income Tax

Income Tax also has very significant effect on field development economics, especially for more profitable fields. Income Tax is calculated on the contractors’ net revenue which is the revenue remaining after deducting all their costs from their total revenue. The contractors’ total revenue consists of Cost Recovery and the contractors’ share of Profit Petroleum. In the Chinese PSC, there is no depreciation in the calculation of Cost Recovery. Capital costs can be recovered immediately when they are spent as long as there is any revenue available. Unrecovered capital costs can be carried forward and be recovered in the future years. This means the contractors are able to

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.27 get their money back earlier and have higher total revenue at the beginning of the field life. In contrast, when calculating Income Tax, the capital costs can not be deducted immediately from the contractors’ total revenue, but have to be depreciated over several years. Higher total revenue and lower deductions result in a high tax liability at the beginning of the field life, thus giving a high present value of tax paid.

Export Duty and Revenue Windfall Tax

Export Duty and Revenue Windfall Tax have moderate effects. The Revenue Windfall Tax rate is high (20% to 40%). However, it is only payable when the oil price is higher than US$40 per barrel and only applies to the portion of oil production sold at a price of higher than the threshold. It also allows certain deductions. Therefore, the effect of the Revenue Windfall Tax only becomes important with high oil prices. For Export Duty, there are no deductions, but the Export Duty rate is relatively low (5%).

Bonuses and Profit Sharing

Both Bonuses and Profit Sharing have little impact on field development. In these analyses, Bonuses are assumed to be only US$1MM and the Profit Sharing arrangement in Chinese offshore PSCs is very favourable to contractors.

8.10 Effect of fiscal terms on probabilistic field development decisions

The oil and gas industry increasingly employs probabilistic techniques, including Monte Carlo simulation, to make field development investment decisions. This includes generating a probability distribution of NPV rather than a best estimate, or a limited range of NPVs. In this section, I examine the effect of the Chinese fiscal terms on the probability distribution of NPV used for a field development decision. I generate probability distributions of the NPV of the field development before and after Government Take. For illustration, I assume that the uncertain variables are Peak Production Rate, Oil Price, Capital Costs, Operating Costs, Discount Rate and Production Decline Rate. All these variables follow a normal distribution. The mean and the standard deviation of them are shown below in Table 8.6.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.28

Table 8.6 - Mean and Standard Deviation of the variables

Production Capital Operating Discount  Peak Rate Oil Price Decline Costs Costs Rate Rate Unit Kbopd US$/bbl US$MM US$MM % % Mean 30 60 700 50 10% 80% SD 20 20 200 10 1% 10%

All variables have a lower limit of zero. The Production Decline Rate has an upper limit of 100%. The Peak Production Rate, Capital Costs and Operating Costs are positively correlated to each other with a correlation coefficient of 0.7. The Peak Production Rate is also negatively correlated with Production Decline Rate. The correlation coefficient is assumed to be -0.7. Since the productivity of a discovery is highly uncertain, I assume a high standard deviation for Peak Production Rate. This ensures that the analysis appropriately covers a broad range of possible reserves. The Oil Price and the Discount Rate are not correlated with any other variables. They are independent.

I run the Monte Carlo simulation for 1,000 times and generate the probability distribution of the NPV. The generated probability distribution of the NPV for the field development before and after Government Take is presented in Figure 8.15. In the figure, the horizontal axis shows the NPV and the vertical axis gives the probabilities. The dark columns represent the before-take NPVs and the lightly shaded columns represent the after take NPVs. As shown in Figure 8.15, the probability distribution of NPV moves to the left after Government Take. The mean of the NPV decreases from US$1,853 MM to US$820 MM. The standard deviation also decreases from US$1,621 MM to US$820 MM. In other words, the Government Take significantly decreases the probability of high levels of profitability and raises the probability of low levels of profitability.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.29

Figure 8.15 - Probability distribution of NPVs before & after Government Take

6%

5% After Government Take Mean = US$820 MM

4% Before Government Take Mean = US$1,853 MM 3% Probability in % 2%

1%

0% -2,000 -800 400 1,600 2,800 4,000 5,200 6,400 7,600 NPV in US$MM

Figure 8.16 shows the cumulative probability distribution of the NPV before and after Government Take. There is a 20% chance that the after-take NPV is US$0 or less. For the case in which the fiscal regime does not apply, there is only a 12% chance that the NPV of developing this field is US$0 or negative. Therefore, Government Take increases the probability of losing money by investing in this project.

Figure 8.16 - Cumulative probability distribution of NPVs before & after Government Take

100%

90% After Government Take 80% Before Government Take 70%

60%

50%

Negative 40% NPV 20% 30%

Cumulative probability in % 20% Negative NPV 10% 12%

0% -2,000 -1,000 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 NPV in US$MM

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.30

8.11 Effect of Government Take on basin development

As illustrated in previous sections, the Chinese fiscal regime is inefficient. It tends to hinder the development of marginal fields. In a given basin, there may be a significant number of such fields and collectively they could contain a significant volume of oil. If these fields are undeveloped then significant resources would be left stranded.

Resources stranded because of fiscal terms

From the analysis in section 8.5, ignoring Government Take, the minimum field size required to make the field development remain profitable is about 3 million barrels when the oil price is US$80/bbl. The effect of Government Take increases the minimum economically developable field size to about 7 million barrels. In other words, any fields between 3 million barrels and 7 million barrels will not be developed because of Government Take. This might not be a significant difference. However, as illustrated in section 8.6, when the oil price is lower at US$20/bbl, the minimum discovered reserves before and after Government Take would be 54 million barrels and 89 million barrels respectively.

According to the statistical data, a large portion of the oil fields in China have between 50 million barrels and 90 million barrels. Therefore, significant number of fields in China would remain undeveloped at an oil price of US$20 per barrel if the Chinese fiscal terms were applicable. In the following, I analyse the fiscal regime on the field development of hypothetical basins and illustrate how the fiscal terms could leave significant resources undeveloped. I also analyse the effect of the fiscal terms on the development of oil fields across China.

Hypothetical basin analysis

In order to illustrate the effect of Government Take on the development of a basin with different field sizes, I assume three basins containing 50, 100 and 500 fields. For each basin, I assume a lognormal field size distribution with a 90% chance that individual field reserves are 5 million barrels or more and a 10% chance that the reserves are 200 million barrels or more. This assumption is based on the field size distribution of oil fields across China (see Figure 8.20 below).

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.31

Figure 8.17 shows the field size distribution for three hypothetical basins with 50, 100 and 500 fields. For each graph, the horizontal axis shows the individual field sizes. The range of reserves is between 0 and 1,000 million barrels. The vertical axes show the frequency that different field sizes occur.

Figure 8.17 - Field size distribution

18 Size of the basin - 16 50 fields 14

12

10

8

6 Numberfields of

4

2

0 0 100 200 300 400 500 600 700 800 900 1,000 Reserves (MMbbl)

Figure 8.17 - Field size distribution - continued

35 Size of the basin - 30 100 fields

25

20

15

Number of fields 10

5

0 0 100 200 300 400 500 600 700 800 900 1,000 Reserves (MMbbl)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.32

Figure 8.17 - Field size distribution - continued

120 Size of the basin - 500 fields 100

80

60

40 Number of fields

20

0 0 100 200 300 400 500 600 700 800 900 1,000 Reserves (MMbbl)

I analyse the economics of different field sizes and, for each basin, note the number of fields rendered uneconomic and the total volume of oil left stranded because of the fiscal terms. The results are given in Table 8.7 and Figures 8.18 and 8.19.

Figure 8.18 - Fields that remain undeveloped because of Government Take

70 59 60 Oil price = US$20/bbl

50 46

40 Oil price = US$80/bbl 30

20 16 12 8 10 7 Number of fields remain undeveloped 0 50 100 500 Number of fields

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.33

   Table 8.7 - Oil volumes stranded because of the fiscal terms    Oil price = Assumptions Made Oil price = US$80/bbl US$20/bbl Individual field sizes left stranded 54.1 – 89.0 MMbbl 2.8 - 6.5 MMbbl Basin with 50 fields   Total volume of oil (MMbbl) 3,328 3,328 Number of fields undeveloped 8 7 Oil stranded (MMbbl) 550 30 % of total discoveries in the basin 16% 14% % of total volume of oil in the basin 17% <1%  Basin with 100 fields   Total volume of oil (MMbbl) 7,438 7,438 Number of fields undeveloped 12 16 Oil stranded (MMbbl) 853 66 % of total discoveries in the basin 12% 16% % of total volume of oil in the basin 11% <1%  Basin with 500 fields   Total volume of oil (MMbbl) 37,398 37,398 Number of fields undeveloped 59 46 Oil stranded (MMbbl) 4,112 214 % of total discoveries in the basin 12% 9% % of total volume of oil in the basin 11% <1%

The analysis shows that the oil volume stranded by fiscal terms is relatively low with an oil price of US$80 per barrel. However, if the oil price is US$20 per barrel, the total volume of oil left in the reservoir could be significant.

China analysis

The field size distribution of oil fields across China is shown in Figure 8.20. At the end of 2003, 556 oil fields had been discovered in China both onshore and offshore (industry data). Among these fields, only 31 fields (6%) had more than 200 million barrels. 293 fields contain recoverable reserves of less than 20 million barrels, which is 53% of the total.

These fields have already been developed. The purpose of this section is to make a hypothetical estimate of the number of fields and the total volume of oil that would be rendered uneconomic if the Chinese fiscal terms were applied to all of the fields in China.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.34

Figure 8.19 - Oil volumes stranded because of Government Take

4,500 4,112 4,000 Oil price = US$20/bbl 3,500

3,000

2,500

2,000 Oil price = US$80/bbl 1,500

1,000 853 550 500 214 Volume of oil left stranded(MMbbl) Volume of 30 66 0 50 100 500 Number of fields

Figure 8.20 - Field size distribution in China

220

200 Total number of fields - 556 180

160

140

120

100

80 Number of fields 60

40

20

0 0 100 200 300 400 500 600 700 800 900 1,000 Reserves (MMbbl)

The results are shown in Table 8.8. They show that the oil volume stranded by fiscal terms in China could be significant at an oil price of US$20 per barrel. Although the percentage of oil stranded in China when the oil price is US$80 per barrel is less than 1%, the volume is 395 MMbbl, which is a large amount.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 8.35

   Table 8.8 - Oil volumes stranded in China because of the fiscal terms    Oil price = Oil price =  US$20/bbl US$80/bbl Individual field sizes left stranded 54.1 - 89.0 MMbbl 2.8 - 6.5 MMbbl 556 fields  Total volume of oil (MMbbl) 46,218 46,218 Number of fields undeveloped 49 88 Oil stranded (MMbbl) 3,433 395 % of total discoveries in China 9% 16% % of total volume of oil China 7% <1%

8.12 Summary and conclusions

In this chapter, I analyse the economic effects of critical aspects of Chinese fiscal terms on field development in China and the profitability of the development. The component of Government Take which has the biggest impact on the economics of development of marginal fields is Royalty. Income Tax is more damaging to the development of profitable fields. Revenue Windfall Tax becomes severe with the increase in oil price.

The analyses indicate that Chinese fiscal regime is regressive. It tends to harm small and less profitable fields more heavily, and renders uneconomic some of those fields which otherwise would be developed.

A Monte Carlo simulation shows that the mean profitability of the field development diminishes because of the Chinese fiscal regime and that the probability of the field development being uneconomic rises after Government Take.

The number of fields and the volume of oil left stranded because of Government Take depend on both the size of the basins and the oil price. The volume of oil left stranded increases significantly when the oil price falls and the size of the basin increases.

Wanwan Hou January 2009 University of New South Wales

Chapter 9

The Comparison of the Fiscal Terms in the Asia Pacific Region

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.1

This chapter reviews the key fiscal terms for oil in a cross section of countries in the Asia Pacific Region - Australia, Indonesia, Vietnam, Bangladesh, Philippines, Thailand, and India. The terms reviewed are believed to be typical of current agreements for oil exploration and development. As a simplification, the effects of State Participation are not included in the analyses. Based on detailed economic modelling of the effect of the fiscal terms on hypothetical oil field developments, I present a comparison of the severity of the Chinese fiscal terms and the fiscal terms reviewed in this chapter on a consistent basis. In addition, I analyse and compare the efficiency of the terms and thereby show how flexible the terms are at responding to different exploration, development and economic conditions.

Given that the Government-controlled gas prices in some countries would affect the economics of the exploration and development, fiscal terms for gas discoveries are not easily compared and so are not considered in this chapter.

9.1 Comparison of the fiscal terms

A summary of the oil fiscal terms for shallow water in the eight countries is given in Table 9.1.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.2

       Table 9.1 - Summary and comparison of oil fiscal terms assumed for shallow water (see also the continuation of the table)          Production Sharing Contract (PSC) regimes Royalty/tax regimes Australia  Bangladesh Philippines Vietnam India NELP Indonesia China offshore Thailand PRRT First Tranche Value Added Tax (VAT) – Petroleum (FTP) 5% 0-20 Kbopd 5% - 20% of Gross Royalty - 0-2Kbopd 5.00% 20-50 Kbopd 8% Revenue, shared 0-20 Kbopd 0% 2-5 Kbopd 6.25% 50-75 Kbopd 10% 10% of Royalty none none between 20-30 Kbopd 4% none 5-10 Kbopd 10.0% 75-100 Kbopd 15% well head value Government and 30-40 Kbopd 6% 10-20 Kbopd 12.5% 100-150 Kbopd 20% Contractors 40-60 Kbopd 8% over 20 Kbopd over 150 Kbopd 25% based on profit 60-80 Kbopd 10% 15.0% shares over 80 Kbopd 12.5% Cost negotiable - typically Recovery maximum 50% 70% maximum 50% 100% 50% - 62.5% none none 100% Ceiling based on investment 0-20 Kbopd 100% Special multiples 0-25 Kbopd 45% 20-40 Kbopd 95% Remuneratory 0-75 Kbopd 50% below 1.5 100% 25-50 Kbopd 35% 40-60 Kbopd 90% Benefit (SRB) Contractors' maximum 75-100 Kbopd 45% 1.5-2.0 90% 26.79% before 50-75 Kbopd 25% 60-100 Kbopd 85% none payment 0%-75% Profit Shares 40% 100-150 Kbopd 40%-45% 2.0-2.5 80% tax 75-100 Kbopd 15% 100-150 Kbopd 80% depends on annual over 150 Kbopd 30%-40% 2.5-3.0 70% over 100 Kbopd 12.5% 150-200 Kbopd 70% revenue per metre 3.0-3.5 60% over 200 Kbopd 60% depth of well over 3.5 50% Income Tax none none 50% 41.82% 44% 25% 30% 50% 3%, 5% and 7% based on Withholding none none level of capital none none none none none Tax contribution of investors

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.3

   Table 9.1 - Summary and comparison of oil fiscal terms assumed for shallow water - continued      Production Sharing Contract (PSC) regimes Royalty/tax regimes  Bangladesh Philippines Vietnam India NELP Indonesia China offshore Australia PRRT Thailand discovery bonus negotiable, discovery bonus production bonues negotiable, production 12.5 Kbopd - $1MM signature bonus - signature Bonuses 25 Kbopd - $2MM negotiable none bonus none none 50 Kbopd - $1MM bonus - $1MM 37.5 Kbopd - $3MM negotiable 75 Kbopd - $2MM 50 Kbopd - $4MM 100 Kbopd - $3MM 62.5 Kbopd - $5MM 100 Kbopd - $10MM 4% on crude 5% on crude oil Export Duty none none none none none none oil export export straight negotiable, negotiable, different items are 25% no depreciation for line/declining Depreciation for 25% straight line 10% depends on typically depreciated at declining Cost Recovery, 1/6 balance over life capital costs (intangible costs) straight line the type of straight line different rates balance straight line for tax of assets/life of (tangible costs) costs project contract area contract area (except for (except for amortised exploration contract contract Ring fence contract area contract area contract area exploration whole country deduction for tax area area deduction for tax purpose - whole purpose - whole country) country) Revenue Windfall Minimum Domestic Tax on crude oil Resource Rent Tax Alternate Tax Market produced in China Other charges none none none (RRT) 40% on none (MAT), 7.84% on Obligation and sold at prices income contractors’ profit (DMO) more than US$40/bbl

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.4

9.2 Assumptions

I carry out the analyses for a range of hypothetical stand-alone fields which are located offshore in the water depth of less than 200 metres. I have estimated the production profile, capital and operating costs of different field sizes and derived net present values (NPVs) before and after Government Take. In the analyses, I assume that contractors hold 100% of the working interests of the projects.

9.2.1 Economic assumptions

 I assume that the oil price varies from US$20 per barrel to US$140 per barrel in 2008 escalated at 3% per year starting in 2009.  I assume that all exploration, appraisal, development and operating costs are escalated at 3% starting in 2009.  I calculate the NPV of nominal after-take net cash flow using a nominal discount rate of 10%.

9.2.2 Field development assumptions

I estimate the costs of exploration, appraisal, development and production based on data from hypothetical, but representative oil field developments. Costs change from case to case depending on field size.

The detailed cost assumptions are -

 I assume that the exploration costs are US$20 million.

 I assume that development costs for various peak production rates are equal to the peak rate multiplied by a capex factor, defined as the development cost per thousand barrels per day (Kbopd). I assume that peak field production varies from 15% to 30% of initial reserves depending on field size. These assumptions give the peak field rate, capex factor and development costs shown in the following table.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.5

    Table 9.2 - Peak rate and development cost estimation for oil field development in shallow water     Reserves MMbbl* 10 20 30 40 50 75 100 125 150 200 225 250 Peak rate % 30% 28% 25% 23% 20% 18% 15% 15% 15% 15% 15% 15% Peak production Kbopd* 8.2 15.120.5 24.7 27.4 36.0 41.1 51.4 61.6 82.2 92.5 102.7 US$MM Capex factor /Kbopd 20 19 18 17 16 15 14 13 12 11 10 9 Development costs US$MM 164 286370 419 438 539 575 668 740 904 925 925 * MMbbl stands for million barrels. Kbopd stands for thousand barrels per day.

I assume that the exploration period is the first two contract years. I assume that US$1 million are spent in the first contract year and US$19 million are spent in the second year of the contract.

Development and production phasings are shown in Table 9.3.

            Table 9.3 - Development and production phasing               Year 12 345 6 7 8910 Production phasing % of peak 50% 100% Decline Development costs phasing % of total 10% 20% 50% 20% 

 Annual fixed real operating costs in each year of production are assumed to be 8% of the total real development costs.

 I assume that the abandonment cost incurred in the end of the economic life of a field is 20% of the total development costs.

9.3 Fiscal severity

As defined in Chapter 8, the fiscal severity of a regime is determined by measuring Government Take for highly profitable developments. In this chapter, I calculate the Government Take as a percentage of before-take NPVs on a discounted basis.

For each fiscal regime, I carry out cash flow analyses and generate before and after-take NPVs for a range of field developments with reserves varying from 10 MMbbl to 250 MMbbl and an oil price varying from US$20 per bbl to US$140 per bbl.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.6

I plot the Government Take as a percentage on a scatter diagram for each country and fit the results with a best-fit smooth curve. An example of the process is shown in Figure 9.1. The figure shows the Government Take as percentage of project before-take NPV under Australian Petroleum Resource Rent Tax (PRRT) regime.

Figure 9.1– Government Take under Australian PRRT regime

100% Government Take 90%

80%

70%

60% 59 Government Take in % %

50%

40% 0 2,000 4,000 6,000 8,000 10,000 12,000 Project before take NPV in US$MM

For the example in Figure 9.1, the Government Take becomes almost constant when the project NPV is higher than approximately US$6,000 million. Government Take (in this case, 59%) represents a measure of the severity of the fiscal regime.

I repeat the same procedure as that used to prepare Figure 9.1 for the other regimes and present the best-fit curves in Figure 9.2. This figure illustrates and compares the severity of the fiscal terms in the eight countries.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.7

Figure 9.2 – Government Take

100%

90% Indonesia

Vietnam 80% Thailand

70% Philippines Australia Bangladesh

60% China Government Take inGovernment Take %

India 50%

40% 0 2,000 4,000 6,000 8,000 10,000 12,000 Project before take NPV in US$MM

Based on the results shown in Figure 9.2, the ranking of the regimes from the most severe to the most lenient is shown in Table 9.4 below.

  Table 9.4 - Ranking of fiscal regimes by severity   Regimes Government Take (%)  Most severe Indonesia 87%  Vietnam 81% Thailand 80% Bangladesh 63% Philippines 61% Australia PRRT 59% China offshore 57% Most lenient India NELP 54%

9.4 Regressive/progressive regimes

I also analyse the fiscal regimes in terms of whether they are progressive or regressive.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.8

In the example shown in Figure 9.1, for project NPVs lower than US$6,000 million, the Government Take as a percentage of project before-take NPV becomes higher for projects with low levels of profitability. This shows that the regime is regressive.

Based on the results shown in Figure 9.2, I classify the regimes into two groups – a) regressive regimes and b) regressive then progressive regimes. The figure shows that all regimes are regressive when the profitability is very low. At higher levels of profitability, however, a mixed picture emerges. This is discussed below.

Regressive regimes

As shown in Figure 9.2, for Indonesian, Vietnamese, Philippine and Australian regimes, Government Take is high for projects with low levels of profitability (marginal projects) and falls as the projects become more economic. The variation in Government Take from marginal to profitable projects is from 13% to 26% depending on the country. For instance, in Indonesia the Government Take varies from 100% to 87%, a variation of 13%. These regimes are regressive because they tend to take more from small or marginal projects than from more profitable projects. This is mainly because of regressive components such as Royalty, Cost Recovery Ceiling and depreciation of capital costs for Cost Recovery and Income Tax. They are regressive because they are not functions of net cash flow of the project (which is the basis for making investment decisions).

Royalty is generally the first levy on project Gross Revenue. Generally, it does not take into account any of the costs spent on the project. Therefore, for projects with low profitability, Royalty is likely to take 100% of the net cash flow and render the project uneconomic.

A Cost Recovery Ceiling is the maximum amount of project Gross Revenue that contractors can use to recover costs. A low Cost Recovery Ceiling (for instance, 70% in Philippines and a maximum of 50% in Vietnam) might not be enough to recover all costs spent or might delay Cost Recovery, especially for marginal projects with low Gross Revenue and high costs. Cost Recovery Ceilings therefore decrease or delay the contractors’ Cost Recovery and at the same time increase the Government’s share of Profit Petroleum.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.9

The depreciation of capital costs for Cost Recovery makes the contractors’ Cost Recovery low and therefore increases the Government’s share of Profit Petroleum at the beginning of the life of a project. The depreciation of costs for Income Tax increases the amount of taxable income in the beginning of the project life and therefore increases the tax payable.

Regressive - progressive regimes

Figure 9.2 shows that for Chinese, Bangladesh, Thailand and Indian regimes, as the profitability of the project grows, Government Take decreases at first, but then starts to increase when the project becomes more profitable. The increase reflects the fact that at least one component of Government Take is progressive to some extent (generally the Profit Sharing component).

In Chinese and Bangladesh regimes, Profit Sharing is on an incremental sliding scale based on production rates. Contractors receive higher shares if the production rate is low. However, production rate is not the only factor that affects the net cash flow. Profit Sharing based on production rates neglects the effect of petroleum prices and costs. When the oil price is low or costs are high, a field with high production rates could also be marginal. Therefore, the Government Takes under Bangladesh regimes only increase slightly when the project NPV becomes very high. The progression of Chinese fiscal regime also reflects the effect of Revenue Windfall Tax, which becomes important with increasing oil prices.

In Thailand fiscal regime, Special Remuneratory Benefit (SRB) is payable on Profit Petroleum, which can be considered as a type of tax. The SRB rate is based on the adjusted annual revenue per metre depth of well which effectively takes into account the oil prices. As a result, the Thailand fiscal regime becomes progressive from a very low project NPV.

In the Indian regime, Profit Petroleum is shared on a sliding scale based on the contractors’ Investment Multiple which is the ratio of contractors’ accumulated net cash income to the contractors’ accumulated investment. Therefore, for more profitable projects, the progressive components of the regime, which is Profit Sharing,

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.10 dominate and the Government Take increases significantly after the project NPV is higher than US$300 million.

9.5 Fiscal efficiency

I analyse the efficiency of the fiscal regimes by showing the relationship between the contractors’ after-take NPV and the project before-take NPV. I plot the results on a scatter diagram and fit them with a best-fit curve. An example for Australian PRRT regime is given in Figure 9.3. As can be seen in the figure, Australian PRRT regime is inefficient because the after-take curve does not pass through the zero point. The intersection point of the curve and the horizontal axis illustrates the minimum profitability of the project before Government Take, at which the field is economic to develop. In other words, if a project before-take NPV is lower than this value, the project would become uneconomic after Government Take. Therefore, the lower the minimum profitability the more efficient/flexible the regime is. In Figure 9.3, the minimum profitability of the project for Australian PRRT regime is US$80 million.

Figure 9.3 – Fiscal efficiency of Australian PRRT regime

2,000

1,800 Fiscal efficiency

1,600

1,400 Zero Government Take 1,200 Government Take 1,000

800

600

400 8 After Government Take

Contractor's after take NPV in US$MM in NPV take after Contractor's 200

0 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 Project before take NPV in US$MM

I repeat the same process as that used to prepare Figure 9.3 for the other regimes and show the resulting best-fit curves in Figure 9.4.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.11

Figure 9.4 – Fiscal efficiency

700

Fiscal efficiency 600

500

400

India China Bangladesh Philippines 300

200 Australia

100 Thailand Vietnam Contractors' after take NPV in US$MM after take Contractors' Indonesia

0 0 200 400 600 800 1,000 1,200 Project before take NPV in US$MM

Figure 9.4 shows that the ranking of the fiscal regimes from the most inefficient to the most efficient is – Indonesia, Vietnam, Thailand, Philippines, Bangladesh, Australia PRRT, China offshore and India.

Indonesian production sharing contracts (PSCs)

Among the eight fiscal regimes, the Indonesian PSCs are the most inefficient. The contractors’ after-take NPV would only be positive if the project NPV is higher than US$450 million. Therefore, US$450 million is the minimum profitability of the project before Government Take. In other words, if the NPV is less than US$450 million, the development is economic on a before-take basis. However, contractors would probably decide not to develop the field because the NPV after Government Take is negative.

The distortions referred to above reflect the inefficiency of certain components of the Indonesian fiscal regime. They are FTP and depreciation of costs for Cost Recovery and Income Tax. FTP is a portion of Gross Revenue, which is shared between the Government and the contractors based on Profit Shares. It is effectively a type of Royalty because it is a percentage of Gross Revenue not net cash flow. Therefore, for

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.12 the projects with very low net cash flow, FTP is likely to damage the project and render it uneconomic. Although Income Tax is paid on contractors’ profit, the rate is relatively high (44%) and is applied after depreciating capital costs.

Vietnamese PSCs

Vietnamese regime is slightly less harsh than Indonesian regime. Under Vietnamese PSCs, the minimum economic project NPV (US$420 million) is almost the same as that in Indonesia. In other words, Vietnamese regime is also very inefficient for the development of marginal fields.

The inefficiency referred to above is the result of certain features of Vietnamese regimes. They are Royalties, Cost Recovery Ceiling, Export Duty and the depreciation of capital costs for Income Tax. The Income Tax rate in Vietnam is also very high (50%).

Thailand fiscal regime

Thailand regime is much more efficient than Indonesian and Vietnamese regimes. It is more lenient to marginal fields and becomes more severe for profitable fields. The minimum economic project NPV is US$140 million. The efficiency of Thailand regime mainly reflects the effect of SRB.

Philippine service contracts (SCs)

The Philippines fiscal terms are as efficient as the Thailand regime. The minimum profitability of the project before Government Take is also US$140 million. Under Philippine fiscal terms, there is no Royalty, Income Tax or any other type of taxes applied to contractors. However, the regime is still inefficient because of the Cost Recovery Ceiling and depreciation of costs for Cost Recovery.

Bangladesh PSCs

The Bangladesh fiscal regime is very similar to the Philippines but with a Profit Sharing based on production levels. The incremental sliding scale of profit shares makes the

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.13

Bangladesh PSCs more efficient than the Philippines PSCs. The minimum Project before-take NPV under Bangladesh PSCs is US$120 million.

Australian Petroleum Resource Rent Tax (PRRT) regime

Australian PRRT regime is one of the most efficient regimes in the Asia Pacific Region. It is deliberately designed to be lenient for small and marginal fields. As shown in Figure 9.6, the minimum project before-take NPV under Australian PRRT regime is lower than that under most of the regimes analysed, which is only US$80 million. When the project becomes more economic, the Government Take in Australia becomes more than that in Bangladesh.

There are only two components in Australian PRRT regime – Resource Rent Tax (RRT) and Income Tax. RRT is progressive and efficient. It is levied on net income after all costs are deducted with compound interests. However, the efficiency of RRT is counteracted by the effect the depreciation of costs for Income Tax, which make the Australian regime inefficient as a whole.

Chinese PSCs

Figure 9.4 shows that Chinese offshore PSCs are more lenient and efficient than most of the other regimes. The minimum economic before-take NPV is US75 million. Although Chinese PSCs contain a certain number of inefficient components, their impact is mild. The inefficient terms include VAT, Royalty, Cost Recovery Ceiling, Export Duty and depreciation of costs for Income Tax. However, Royalty is levied based on production levels and the rates are relatively low (0% to 12.5%). There is no depreciation of costs for Cost Recovery and development costs are recovered with a 9% compound interest. The Profit Sharing is based on production levels as well and the Government’s shares are relatively low (0% to 40%). For low levels of production, although the Cost Recovery Ceiling is only 50% to 62.5%, in fact the contractors receive 100% of Profit Petroleum anyway. This means effectively that there is no ceiling for low production. The Income Tax rate (25%) is also low compared with that in other countries.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.14

Indian NELP PSCs

The most efficient regime among the regimes analysed is Indian NELP regime. The efficiency is mainly driven by the fact that Profit Sharing depends on Investment Multiples. The inefficient features in Indian NELP PSCs are Royalty and the depreciation or depletion of costs for Income Tax. However, the Royalty is levied on well head value, which is less than Gross Revenue and the rate is relatively low (10%). The Cost Recovery Ceiling is negotiable, but is assumed to be 100% in these analyses. In addition, there is no depreciation for Cost Recovery in Indian NELP PSCs.

9.6 Summary and conclusions

Fiscal severity

The ranking of the petroleum fiscal regimes in the Asia Pacific Region from the most severe to the most lenient is – Indonesia, Vietnam, Thailand, Bangladesh, Philippines, Australia PRRT, China offshore and India NELP. The Government Take for profitable projects varies from 54% to 87% depending on the regimes.

The Government Take under China offshore fiscal terms is 57% of before-take NPV. In comparison to other countries, the petroleum activities carried out under China offshore fiscal terms would give companies higher returns than most regimes in the Asia Pacific Region.

Fiscal flexibility

All fiscal regimes analysed are inefficient and regressive for marginal fields. Among these regimes, China offshore regime is more efficient than most of the other regimes analysed. It is relatively more lenient to small and marginal fields as compared to other regimes.

The regressive and inefficient elements in the regimes include –

 Royalties  Cost Recovery Ceiling

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 9.15

 Profit Sharing that not based on net cash flow  Depreciation of costs for Cost Recovery and Income Tax

These are components of the fiscal terms which are applied without regard to the before-take net cash flow of the project. They place imposts on the final return received by the contractor which are disproportionate to the level of before-take net cash flow. The fiscal components that make a regime regressive also tend to make the regime inefficient. The application of these terms damages the development of small and marginal fields. Some of these fields may not be developed if the after-take NPV becomes negative because of the effect of fiscal terms. If this is the case, neither the Government nor the contractors would obtain any benefit.

Considering the energy shortage all over the world, developing small and marginal fields will become increasingly significant in the coming future. The Asia Pacific Region is one of the most prominent regions of the world for oil and gas exploration and development. It contains a range of opportunities – from mature, producing areas to frontier exploration areas. Among these prospects and discoveries, a large proportion of them are likely to be marginal. The fiscal terms in the Asia Pacific Region have a considerable influence on the economics of exploration and production and therefore would distort the companies’ investment decisions. Many marginal exploration areas or discoveries might not be explored or developed purely because of the effect of fiscal terms. To avoid the distortion resulting from the fiscal terms, it is important for the Governments to consider increasing the flexibility of their fiscal regimes to encourage investment.

Wanwan Hou January 2009 University of New South Wales

Chapter 10

Economics of Exploration

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.1

In this chapter, I present the results of economic analyses of crude oil and gas exploration and field development in China.

10.1 Objectives

The economic analyses in this section are based on hypothetical but representative field developments in China. The objectives of the analyses are as follows -

 To examine the effect of the Chinese fiscal regime

 To show the minimum economic reserves and the profitability of field developments over a range of reserves assuming that discoveries have already been made

 To determine the minimum prospect reserves for undrilled structures

10.2 Cases

The base cases analysed are shown as below in Table 10.1.

   Table 10.1 - Cases analysed     Area Product PSC assumption

Bohai Gulf Oil Shallow water oil Bohai Bay Basin (Jiyang sub-basin) Oil Onshore oil - east China South China Sea (Qiongdongnan Basin) Gas Shallow water gas Tarim Basin Gas Onshore gas - west China

I show the profitability of field developments by calculating the net present value (NPV) of project after-take net cash flow per barrel or per thousand cubic feet of reserves. The after-take cash flows incorporate the detailed effects of the Chinese fiscal regime presented in Chapter 8.

I also include the effect of State Participation in the analyses in this chapter. After a discovery is made in an exploration area, CNPC, Sinopec or CNOOC has the option to

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.2 take a 51% working interest of the field. The companies will pay their share of any development and operating costs incurred. However, they do not compensate the exploration costs paid by contractors. In other words, contractors are liable to pay 100% of exploration costs. Although contractors can recover these costs through Cost Recovery, State Participation effectively increases the exploration risk that contractors undertake and increases the minimum prospect reserves used to make exploration investment decisions. The description of State Participation is also presented in Chapter 7.

In addition, I set out the economic, market, exploration and development assumptions made for the analyses.

10.3 Approach

For each case analysed, I have taken the following steps -

 I assume production profiles and the costs of exploration, development and operation using data on existing oil and gas fields in the same region as a guide. I have escalated these to levels that I consider appropriate to current conditions.

 I make base case cash flow analyses for each case based on my economic, exploration, development and fiscal assumptions.

 I carry out sensitivity analyses (a) for field development economics assuming that a discovery has been made, and (b) for exploration economics assuming that a discovery has not been made. Based on these analyses, I determine (a) minimum developable field size and (b) the minimum prospect reserves over a range of given probabilities of exploration drilling success.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.3

10.4 Assumptions

The economic, exploration and development assumptions made in the base case analyses are set out below.

10.4.1 Economic assumptions

 I assume for the base cases that the oil price is US$80 per barrel in 2008 escalated at 3% per year starting in 2009. For the sensitivity analyses, the range of oil prices assumed is US$20 to US$140 per barrel.

 I assume for the base cases that the gas price is US$6.00 per thousand cubic feet escalated at 3% per year starting in 2009.

 I assume that all exploration, appraisal, development and operation costs are escalated at 3% starting in 2009.

 I calculate the NPV per barrel or per thousand cubic feet of nominal after-take net cash flow using a discount rate of 10%.

10.4.2 Cost assumptions

I estimate the costs of exploration, appraisal, development and production taking the data from existing oil and gas fields in the same area or similar conditions as the guide. Costs change from case to case as the geological and topographic conditions vary. The estimates I make are intended to be representative costs.

The detailed costs assumptions are listed below -

 I assume that an offshore 2D seismic survey would cost US$1,000 per kilometre and that an onshore 2D seismic survey would cost US$5,000 per kilometre on average.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.4

 The cost of an exploration well is assumed to be US$20 MM per well for shallow water (less than 500 metres) offshore China. For onshore exploration wells, I assume a cost of US$6 MM per well to dill to a depth of 3,000 metres and US$10 MM per well to drill to a depth of 4,000 to 6,000 metres.

 Appraisal wells are drilled after a discovery has been made and the costs for drilling in different conditions and areas vary. I assume that the cost of drilling an appraisal well is approximately 85% of the cost for drilling an exploration well in the same area. For instance, an offshore appraisal well drilling would cost US$17 MM per well in shallow water. Onshore appraisal wells are assumed to cost US$5 MM per well for a depth of 3,000 metres and US$8 MM for a depth of 4,000 to 6,000 metres.

 I assume the total field development costs are related to the development costs in an existing field in the same region. I assume that the development costs of a hypothetical field with a peak field rate of X thousand barrels per day (Kbopd) would be -

Costs for X Kbopd = Known costs * (X / Known peak rate) ^0.7

Peak production rate depends on the size and location of the field. For oil fields, I assume that the peak annual production rate varies from 15% to 30% of initial reserves. For gas fields, I assume that the peak rate is a constant 5% of initial reserves. My assumptions for peak rates and development costs are made in the following tables.

    Table 10.2 - Peak rate and development cost estimation for base case oil fields offshore China (Bohai Gulf)     Reserves MMbbl 10 20 30 40 50 75 100 125 150 200 225 250 Peak rate % 30% 28% 25% 23% 20% 18% 15% 15% 15% 15% 15% 15% Peak Kbopd production 8 15 21 25 28 36 41 51 67 82 93 103 Development US$MM cost 166 254 315 358 386 466 512 599 680 832 903 973

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.5

 Table 10.3 - Peak rate and development cost estimation for base case oil fields onshore east China (Bohai Bay Basin)    Reserves MMbbl 10 20 30 40 50 75 100 125 150 200 225 250 Peak rate % 30% 28% 25% 23% 20% 18% 15% 15% 15% 15% 15% 15% Peak production Kbopd 8 15 21 25 28 36 41 51 67 82 93 103 Development US$M 1,1 cost M 195 298 371 421 453 548 602 704 800 978 1,062 43

 Table 10.4 - Peak rate and development cost estimation for base case gas fields offshore China (South China Sea)    Reserves Bcf 100 200 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 Peak rate % 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% Peak production MMcfd 14 27 68 103 137 171 205 240 274 308 342 377 Development cost US$MM 140 228 433 575 703 821 933 1,040 1,142 1,240 1,335 1,427

          Table 10.5 - Peak rate and development cost estimation for base case gas fields onshore west China (Tarim Basin)    Reserves Bcf 100 200 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 Peak rate % 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% Peak production MMcfd 14 27 68 103 137 171 205 240 274 308 342 377 Development cost US$MM 59 96 183 242 296 347 394 439 482 523 563 602

The reference field for oil fields offshore China is Zhao Dong Block in the Bohai Gulf. According to the ROC Oil’s quarterly reports, Zhao Dong has 50 MMbbl reserves, a peak production rate of 24.45 Kbopd and total proposed development costs of US$385.4 million. For onshore oil fields east China, I use the data from 12 fields in the Shengli oil field complex in the Bohai Bay basin (onshore areas) in South China Sea as the guide. The fields have an average peak production rate of 13.66 Kbopd and average total development costs of US$278.41 million (converted from RMB at US$1 = RMB7.5). For offshore gas fields, I use the data from Yacheng 13-1 gas field in the Qiongdongnan Basin in South China Sea. Yacheng 13-1 is the first gas field discovered in offshore China and also the biggest offshore gas field operated by foreign companies. It has initial gas reserves of 2,649 billion cubic feet. The peak production rate and total capital costs are 389 MMcfd and US$1,460MM. For the analysis of gas fields in onshore China, the reference field is Kela 2 gas field in the Tarim Basin in the northwest China. Kela 2 is one of the largest single gas fields in China. It was put on stream in December 2004. Kela 2 has 8,048 Bcf gas reserves. The

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.6 peak production rate is estimated to be 1,044 MMcfd. The total budget for development is US$1.229 million.

The field development data referred to above have been obtained from discussion with Chinese oil companies during a visit to China from January to February 2007.

 Annual fixed operating costs in each year of production are assumed to be 8% of the total development cost. I assume that variable operating costs are US$1 per barrel.

 I assume that the abandonment cost incurred in the end of the economic life of a field is 20% of the total development costs.

10.4.3 Sensitivity assumptions

I carry out the sensitivity analyses by varying the following four key parameters - 

 Oil/gas price

 Peak well production rate

 Development cost

 Fiscal terms which include Royalty and Revenue Windfall Tax (for oil) / Income Tax (for gas)

I vary the oil price between US$20 and US$140 per barrel. I vary the gas price between US$3.00 and US$20.00 per thousand cubic feet.

I vary the peak well production rate and development cost between 50% and 150% of the value assumed in the base case.

As regards the fiscal terms, I show the effect of zero Royalty and zero Revenue Windfall Tax on the economics of oil field development. For gas fields, I vary only the Royalty and Income Tax because the Revenue Windfall Tax does not apply to the sale of natural gas. I do not change the Bonuses, Profit Sharing and Export Duty as they

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.7 have less influence on the net present value than the other components (see Chapter 8).

10.4.4 Market assumptions

I assume that there is an existing market for oil and gas produced in these base cases. Supply and demand of oil and gas in China are discussed in Chapter 6.

10.4.5 Exploration and development assumptions

The schedule for the exploration and development of oil and gas fields is set out below in Table 10.6.

 Table 10.6- Exploration and development schedule in contract years    Oil shallow Gas Gas shallow Oil onshore water onshore water Exploration    Timing of seismic 1 1 1 1 Timing of discovery 2 2 2 2 Appraisal  Period of appraisal 2 to 4 2 to 3 2 to 4 2 to 3 Field development   Development decision 2 2 2 2 Period of development 3 to 6 3 to 7 3 to 6 3 to 8 Production   Production start 3 5 5 7 First year of peak production 3 to 5* 5 to 7* 5 7 Duration of peak 1 to 2 production 3 years years* 10 years 10 years * Depends on field size. See Table 10.7.

During the exploration period, I assume that a 2D seismic survey of 2,000 kilometres would be conducted. Three exploration wells are drilled. Half of the total exploration costs are estimated to be spent in the first contract year and the other half are spent in the second year of the contract.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.8

Appraisal, development and production costs phasing for the base cases are shown in Table 10.7. My assumptions for oil field and gas field are also given.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.9

   Table 10.7 - Appraisal, development and production cost phasing for oil fields    Onshore year 12345678910 Appraisal well phasing   Less than 1 million barrels Number of wells 0  1 to 5 million barrels Number of wells 1  5 to 10 million barrels Number of wells 1 1  10 to 40 million barrels Number of wells 1 1 1  40 to 80 million barrels Number of wells 1 1 2  More than 80 million barrels Number of wells 1 2 2  Production phasing   Less than 40 million barrels % of peak* 100% 100% 100% Decline  40 to 80 million barrels % of peak* 75% 100% 100% 100% Decline  More than 80 million barrels % of peak* 50% 75% 100% 100% 100% Decline  Development costs phasing % of total  50% 25% 15% 10%  * Peak production depends on field size and location. Peak production is assumed to vary from 15% to 30% of initial reserves. Offshore  1 2345678910 Appraisal well phasing    Less than 60 million barrels Number of wells  1  60 to 120 million barrels Number of wells  1 1  More than 120 million barrels Number of wells  1 2  Production phasing   Less than 20 million barrels % of peak*  100% Decline  20 to 60 million barrels % of peak*  75% 100% Decline  More than 60 million barrels % of peak*  50% 75% 100% 100% Decline  Development costs phasing % of total  5% 20% 30% 30% 15%  * Peak production depends on field size and location. Peak production is assumed to vary from 15% to 30% of initial reserves.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.10

 Table 10.7 - Appraisal, development and production cost phasing for gas fields    Onshore year 1 2 345678910 Appraisal well phasing   Less than 10 billion cubic feet Number of wells 0  10 to 100 billion cubic feet Number of wells 1  100 to 300 billion cubic feet Number of wells 1 1  300 to 800 billion cubic feet Number of wells 1 1 1  More than 800 billion cubic feet Number of wells 1 1 2  Production phasing   All fields % of peak* 100% 100% 100% 100% 100% 100% Development costs phasing % of total  10% 50% 35% 5%  * Peak production depends on field size and location. Peak production is assumed to be 5% of initial reserves. Offshore  1 2345678910 Appraisal well phasing    Less than 300 billion cubic feet Number of wells  1  300 to 800 billion cubic feet Number of wells  1 1  More than 800 billion cubic feet Number of wells  1 2  Production phasing   All fields % of peak*  100% 100% 100% 100% Development costs phasing % of total  2.5% 5% 10% 40% 37.5% 5%  * Peak production depends on field size and location. Peak production is assumed to be 5% of initial reserves.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.11

10.5 Net present value per barrel or per thousand cubic feet graphs

The profitability of the hypothetical field development is measured by the NPV per barrel or per thousand cubic feet of the nominal after-take net cash flow of the contractors over a range of reserves. The contractors’ after-take NPV per barrel reflects their 49% working interest of the field. An example set of graphs is given in Figure 10.1.

In each graph, the horizontal axes show the range of reserves for which NPVs per barrel or per thousand cubic feet have been calculated. The vertical axes present the NPVs per barrel or per thousand cubic feet. The base case NPV per barrel or per thousand cubic feet is shown with solid lines and the sensitivity analyses are shown with dotted lines.

Figure 10.1 also shows the minimum economic reserves for any particular case. The minimum economic reserves are the points where the NPVs per barrel or per thousand cubic feet become zero as the reserves decrease.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.12

Figure 10.1 - An example of net present value per barrel graphs

Oil price sensitivity Development cost sensitivity

25 25

Oil price at US$140 per bbl

20 20

Development cost at 50% 15 15 Oil price at US$80 per bbl Development cost at 100%

10 10

Oil price at US$20 per bbl 5 5 NPV at 10% per bbl (US$/bbl)

NPV at 10% per bbl (US$/bbl) NPV Development cost at 150%

0 0 0 50 100 150 200 250 0 50 100 150 200 250 Reserves(MMbbl) Reserves(MMbbl)

Peak production rate sensitivity Fiscal terms sensitivity

25 25

20 20

15 Peak production at 150% 15 No Revenue Windfall Tax Peak production at 100% No Royalty

10 10

Chinese PSC 5 5 NPV at 10% per bbl (US$/bbl) NPV at 10% per bbl (US$/bbl) Peak production at 50%

0 0 0 50 100 150 200 250 0 50 100 150 200 250 Reserves(MMbbl) Reserves(MMbbl) Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.13

10.6 Minimum prospect reserves graphs

The analyses of NPV per barrel or per thousand cubic feet shown above are carried out based on the assumption that a discovery has already been made. They ignore the exploration risks.

In order to incorporate exploration risk, I calculate the expected value of the drilling decision as defined in the formula below. This is calculated for a range of given probabilities of success.

Expected value equals Net present value of development of discovery * Probability of success less Net present value of exploration costs * Probability of failure

When the expected value is positive, then the decision to drill the exploration well is economically justified.

I also calculate minimum prospect reserves incorporating exploration risks and the costs of failure.

The following steps are carried out for this analysis. 

 I vary the discovery size.

 I calculate the NPVs per barrel or per thousand cubic feet of field development over the given range of discovery sizes.

 I calculate the expected values for a range of probabilities of success.

 The minimum prospect reserves are the reserves for which the expected value becomes zero.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.14

Four sample graphs of minimum prospect reserves for different probabilities of success are set out in Figure 10.2. Sensitivity analyses are also shown. Any reserves lower than the curve shown would lead to a negative expected value and therefore a decision would be made not to drill.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.15

Figure 10.2 - An example of minimum prospect reserves graphs

Oil price sensitivity Development cost sensitivity

100 40

90 35 80 Oil price at US$20 per bbl 30 Development cost at 150% 70 25 60

50 20

40 Development cost at 100% 15 Oil price at US$140 per bbl

reserves(MMbbl) 30 reserves(MMbbl) Minimum prospect Oil price at US$80 per bbl Minimum prospect 10 20 5 10 Development cost at 50% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success(%) Probability of drilling success(%) Peak production rate sensitivity Fiscal terms sensitivity

40 40

35 35

30 30

Peak production at 50% 25 25

20 20 Chinese PSC

15 Peak production at 100% 15 reserves(MMbbl) reserves(MMbbl) Minimum prospect Minimum prospect 10 10 No Royalty Peak production at 150% 5 5 No Revenue Windfall Tax

0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success(%) Probability of drilling success(%)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.16

10.7 Offshore shallow water China – Bohai Gulf - Oil field exploration and development economics

Figure 10.3 shows the results of the economic analyses of hypothetical base case oil field development in the areas close to the Zhao Dong block in Bohai Gulf offshore China. It shows the NPV per barrel over a range of reserves. The results are for representative field developments in the Bohai Gulf and they do not represent the analyses of actual oil fields.

Figure 10.4 shows the minimum prospect reserves required for exploration drilling decisions for different given probabilities of success which are calculated based on the economics shown in Figure 10.3.

The key results of the economic analyses carried out for the base case development are listed below in Table 10.8.

 Table 10.8 - Results of economic analyses for base case oil field – offshore shallow water China – Bohai Gulf   Maximum net present value (US$ per barrel) 9.5 Minimum field reserves (Million barrels) 7.3 Minimum prospect reserves (million barrels) at 20% probability of success 31.0 Minimum prospect reserves (million barrels) at 50% probability of success 13.4

The results of sensitivity analyses are presented in Figure 10.5 and Figure 10.6. They show the effects of varying oil price, peak well production rate, development cost and fiscal terms as presented in previous sections.

It is clear from Figure 10.5 that the economics of field development and exploration are most sensitive to changes in oil price. The economics are also sensitive to changes in development costs, the decrease in peak well production rate and zero Revenue Windfall Tax. In contrast, the increase in peak production rate and zero Royalty have the minimal effects on field development economics.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.17

The oil price sensitivity graph in Figure 10.5 shows that if the oil price drops to US$20 per barrel, the maximum net present value per barrel would decrease to US$1.2/bbl as compared to US$9.5/bbl for the base case economics.

The peak production rate sensitivity graph shows that the economics are more sensitive to the decrease in the peak production rate than to the increase in the peak production rate within a +/- 50% range.

The fiscal terms sensitivity graph demonstrates that minimum field reserves for fields that operate under a regime with no Royalty or no Revenue Windfall Tax is higher than the base case. This is because that Royalty and Revenue Windfall Tax are regressive components in the fiscal terms.

Figure 10.6 shows that the decrease in oil price has a significant impact on exploration decisions. Changes in development costs and the decrease in the peak production rate also have a large effect on the exploration economics. However, exploration economics are insensitive to the increase in peak production rate and changes to fiscal terms.

The oil price sensitivity graph in Figure 10.6 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 35 to more than 100 MMbbls.

The development cost sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 51 to 73 MMbbls.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.18

Figure 10.3 - Base case oil field development economic for offshore China

20

18 Bohai Gulf

16

14

12

10

8

6

4 NPV at 10% per bbl (US$/bbl) at 10% per bbl NPV

2 Reserves (MMbbl) 0 0 50 100 150 200 250

Figure 10.4 - Base case oil exploration economics for offshore China

100 90 Bohai Gulf 80

70

60

50

40

30

20

10 Minimum prospect reserves (MMbbl) 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Probability of drilling success (%)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.19

Figure 10.5 – Sensitivity of oil field development economics for areas near Zhao Dong Block shallow offshore China

Oil price sensitivity Development cost sensitivity

20 20

18 Bohai Gulf 18 Bohai Gulf

16 16 Development cost at 50% of base case assumption 14 14 Oil price at US$140 per bbl Oil price at US$80 per bbl Development cost at 100% of base case assumption 12 12

10 10

8 8

6 6 Development cost at 150% of base case assumption 4 4 Oil price at US$20 per bbl NPV at 10% per bbl (US$/bbl) NPV at 10% (US$/bbl) per bbl 2 2

0 0 0 50 100 150 200 250 0 50 100 150 200 250 Reserves (MMbbl) Reserves (MMbbl)

Peak production rate sensitivity Fiscal terms sensitivity

20 20

18 Bohai Gulf 18 Bohai Gulf

16 16 No Revenue Windfall Tax 14 14 No Royalty Peak production at 150% of base case assumption Peak production at 100% of base case assumption 12 12

10 10

8 8 Chinese PSC 6 6

4 4 Peak production at 50% of base case assumption NPV at 10%(US$/bbl) per bblNPV NPV at 10% per bbl (US$/bbl) 2 2

0 0 0 50 100 150 200 250 0 50 100 150 200 250 Reserves (MMbbl) Reserves (MMbbl) Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.20

Figure 10.6 – Sensitivity of oil exploration economics for areas near Zhao Dong Block shallow offshore China

Oil price sensitivity Development cost sensitivity

100 100

90 Bohai Gulf 90 Bohai Gulf

80 80

70 Oil price at US$20 per bbl 70

60 60 Development cost at 150% of base case assumption 50 50 (MMbbl) (MMbbl) 40 Oil price at US$140 per bbl 40 Development cost at 100% of base case assumption

30 30 Oil price at US$80 per bbl 20 20 Minimum prospect reserves Minimum prospect reserves 10 10 Development cost at 50% of base case assumption 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

Peak production rate sensitivity Fiscal terms sensitivity

100 100

90 Bohai Gulf 90 Bohai Gulf

80 80

70 70

60 60 Peak production at 50% of base case assumption 50 50 (MMbbl) 40 (MMbbl) 40 Peak production at 100% of base case assumption Chinese PSC 30 30

20 20 Minimum prospect reserves Minimum prospect reserves No Royalty 10 Peak production at 150% of base case assumption 10 No Revenue Windfall Tax 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

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10.8 Onshore east China – Bohai Bay Basin - Oil field exploration and development economics

Figure 10.7 shows the results of the economic analyses for the base case oil field development in the areas close to the Shengli oil field complex in the Bohai Bay Basin onshore east China. It gives the NPV per barrel over a range of reserves. The results are for representative field developments in the Bohai Bay Basin and they do not represent the analyses of actual oil fields. In Figure 10.7, when field reserves are larger than 50 MMbbl, the NPV per barrel decreases. This is mainly because of the high development costs assumed for onshore oil fields. The increase in revenue per barrel of reserves from larger fields is offset by the high costs spent.

Figure 10.8 shows the minimum prospect reserves required for exploration drilling decisions for different given probabilities of success which are calculated based on the economics shown in Figure 10.7.

The key results of the economic analyses carried out for the base case development are listed below in Table 10.9.

 Table 10.9 - Results of economic analyses for base case oil field – onshore east China – Bohai Bay Basin   Maximum net present value (US$ per barrel) 10.8 Minimum field reserves (Million barrels) 4.1 Minimum prospect reserves (million barrels) at 20% probability of success  13.4 Minimum prospect reserves (million barrels) at 50% probability of success  6.7

The results of sensitivity analyses are presented in Figure 10.9 and Figure 10.10. Both of them show the effects of varying oil price, peak well production rate, development cost and fiscal terms as presented in previous sections.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.22

As can be seem from Figure 10.9, the economics of field development are the most sensitive to changes made to oil price. The economics are also sensitive to changes in development costs, peak well production rate and zero Revenue Windfall Tax. In contrast, zero Royalty has a minimal effect on field development economics.

The oil price sensitivity graph in Figure 10.9 shows that if the oil price drops to US$20 per barrel, the maximum net present value per barrel would decrease to US$0.9/bbl as compared to US$10.8/bbl for the base case economics.

The peak production rate sensitivity graph shows that for fields larger than 120 MMbbl, the NPVs per barrel for the case with high peak rate are lower than the NPVs per barrel for the base case. For fields larger than 180 MMbbl, the NPVs per bbl are lower than the 50% peak rate case. This demonstrates that for large fields, lower peak production rates give higher NPVs and therefore are preferable. This is because for each reserves case, the gain in up front revenue from increasing peak rate is more than offset by the reduction in revenue towards the end of field life.

The fiscal terms sensitivity graph demonstrates that minimum field reserves for fields that operate under a regime with no Royalty or no Revenue Windfall Tax is higher than the base case. This is because that Royalty and Revenue Windfall Tax are regressive components in the fiscal terms.

Figure 10.10 shows that the decrease in oil price has a significant impact on exploration decisions. Changes in development costs and the decrease in the peak production rate also have a large effect on the exploration economics. However, exploration economics are not very sensitive to the increase in oil price, peak production rate and changes to fiscal terms.

The oil price sensitivity graph in Figure 10.10 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 14 to more than 100 MMbbls.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.23

The development cost sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 18 to 31 MMbbls.

Figure 10.7 - Base case oil field development economic for onshore east China

20

18 Bohai Bay Basin

16

14

12

10

8

6

4 NPV at 10% per bbl (US$/bbl)

2 Reserves (MMbbl) 0 0 50 100 150 200 250

Figure 10.8 - Base case oil exploration economics for onshore east China

50 45 Bohai Bay Basin 40

35

30

25

20

15

10

5 Minimum prospect reserves (MMbbl) reserves Minimum prospect 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%)

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Figure 10.9 – Sensitivity of oil field development economics for areas near Shengli oil field onshore east China

Oil price sensitivity Development cost sensitivity

20 20

18 Bohai Bay Basin 18 Bohai Bay Basin

16 Oil price at US$140 per bbl 16 Development cost at 50% of base case assumption

14 14 Oil price at US$80 per bbl Development cost at 100% of base case assumption 12 12

10 10

8 8

6 6 Development cost at 150% of base case assumption 4 Oil price at US$20 per bbl 4 NPV at 10% per bbl (US$/bbl) 2 (US$/bbl) bbl at 10% per NPV 2

0 0 0 50 100 150 200 250 0 50 100 150 200 250 Reserves (MMbbl) Reserves (MMbbl) Peak production rate sensitivity Fiscal terms sensitivity

20 20

18 Bohai Bay Basin 18 Bohai Bay Basin

16 16 No Revenue Windfall Tax No Royalty Peak production at 150% of base case assumption 14 14 Peak production at 100% of base case assumption 12 12

10 10

8 8 Chinese PSC 6 6

4 Peak production at 50% of base case assumption 4 NPV at 10% per bbl (US$/bbl) 2 NPV at 10% per bbl (US$/bbl) 2

0 0 0 50 100 150 200 250 0 50 100 150 200 250 Reserves (MMbbl) Reserves (MMbbl) Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.25

Figure 10.10 – Sensitivity of oil exploration economics for areas near Shengli oil field onshore east China

Oil price sensitivity Development cost sensitivity

100 50

90 Bohai Bay Basin 45 Bohai Bay Basin

80 40

70 Oil price at US$20 per bbl 35

60 30 Development cost at 150% of base case assumption 50 25

(MMbbl) 40 (MMbbl) 20 Development cost at 100% of base case assumption 30 Oil price at US$140 per bbl 15

20 Oil price at US$80 per bbl 10 Minimum prospect reserves Minimum prospect reserves Minimum prospect 10 5 Development cost at 50% of base case assumption 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

Peak production rate sensitivity Fiscal terms sensitivity

50 50

45 Bohai Bay Basin 45 Bohai Bay Basin

40 40

35 35

30 Peak production at 50% of base case assumption 30 25 25

(MMbbl) 20 Peak production at 100% of base case assumption (MMbbl) 20 Chinese PSC 15 15

10 10 Minimum prospect reserves Minimum prospect reserves Minimum prospect 5 Peak production at 150% of base case assumption 5 No Royalty No Revenue Windfall Tax 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

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10.9 Offshore shallow water China – South China Sea - Gas field exploration and development economics

Figure 10.11 shows the results of the economic analyses for the base case gas field development in the areas close to the Yacheng 13-1 gas field in the Qiongdongnan Basin in South China Sea. It gives the NPV per thousand cubic feet (Mcf) over a range of reserves. The results are for representative field developments in the South China Sea and they do not represent the analyses of actual gas fields.

Figure 10.12 shows the minimum prospect reserves required for exploration drilling decisions for different given probabilities of success which are calculated based on the economics shown in Figure 10.11.

The key results of the economic analyses carried out for the base case development are listed below in Table 10.10.

 Table 10.10 - Results of economic analyses for base case gas field – offshore shallow water China - South China Sea   Maximum net present value (US$ per Mcf) 0.42 Minimum field reserves (Billion cubic feet) 219 Minimum prospect reserves (Billion cubic feet) at 20% probability of success 752 Minimum prospect reserves (Billion cubic feet) at 50% probability of success  361

The results of sensitivity analyses are given in Figure 10.13 and Figure 10.14. The figures show the effects of varying gas price, peak well production rate, development cost and fiscal terms as presented in previous sections.

The results in Figure 10.13 show that the economics of field development are the most sensitive to changes made to the gas price. The economics are also very sensitive to changes in development costs within a +/- 50% range, the decrease in

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.27 peak well production rate and zero Income Tax. In contrast, the 150% peak rate and zero Royalty have less effect on field development economics.

The gas price sensitivity graph in Figure 10.13 shows that when the gas price increases to US$20 per thousand cubic feet, the maximum net present value per thousand cubic feet increase to US$2.27 per thousand cubic feet as compared to US$0.42 per thousand cubic feet shown in Table 10.10.

The peak production rate sensitivity graph shows that the economics are more sensitive to the decrease in the peak production rate.

The fiscal terms sensitivity graph demonstrates that minimum field reserves are at maximum for fields that operate under a regime with no Royalty. However, across the full range of reserves considered, zero Royalty has less effect on field economics than zero Income Tax. When the Income Tax is zero, the maximum net present value per thousand cubic feet is US$0.59 per thousand cubic feet.

Figure 10.14 shows that the decrease in gas price has a significant impact on exploration decisions. The decrease in the peak production rate by 50% of the base case also has great effects on the exploration economics. Exploration economics are less sensitive to changes made to the development cost and the increase in the peak rate. The changes to fiscal terms have minimal effect on the exploration economics.

The gas price sensitivity graph in Figure 10.14 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 278 to more than 3,500 Bcf.

The peak well production rate sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 1016 to 3,078 Bcf.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.28

Figure 10.11 - Base case gas field development economic for offshore China

1.0

0.9 South China Sea

0.8

0.7

0.6

0.5

(US$/Mcf) 0.4

0.3

0.2

NPV at 10%NPV per thousand cubic feet 0.1 Reserves (Bcf) 0.0 0 500 1,000 1,500 2,000 2,500

Figure 10.12 - Base case gas exploration economics for offshore China

3,500 South China Sea 3,000

2,500

2,000

1,500

1,000

500 Minimumprospect (Bcf) reserves

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%)

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.29

Figure 10.13 – Sensitivity of gas field development economics for areas near Yacheng 13-1 gas field shallow offshore China

Gas price sensitivity Development cost sensitivity

2.5 1.0

South China Sea 0.9 South China Sea

2.0 0.8 Gas price at US$20/Mcf Development cost at 100% of base case assumption 0.7 Development cost at 50% of base case assumption 1.5 0.6

0.5

1.0 0.4

Gas price at US$6/Mcf feet (US$/Mcf) feet (US$/Mcf) 0.3

0.5 0.2 Development cost at 150% of base case assumption Gas price at US$3/Mcf NPV at 10% per thousand cubic

NPV at 10% thousand cubic per 0.1

0.0 0.0 0 500 1,000 1,500 2,000 2,500 0 500 1,000 1,500 2,000 2,500 Reserves (Bcf) Reserves (Bcf) Peak production rate sensitivity Fiscal terms sensitivity

1.0 1.0

0.9 South China Sea 0.9 South China Sea

0.8 0.8 No Income Tax Peak production at 150% of base case assumption 0.7 0.7 Peak production at 100% of base case assumption No Royalty 0.6 0.6

0.5 0.5

0.4 0.4 feet (US$/Mcf) feet feet (US$/Mcf) 0.3 0.3 Chinese PSC 0.2 0.2 NPV NPV at 10% thousand cubic per

NPV at 10% per thousand cubic 10% at NPV 0.1 0.1 Peak production at 50% of base case assumption 0.0 0.0 0 500 1,000 1,500 2,000 2,500 0 500 1,000 1,500 2,000 2,500 Reserves (Bcf) Reserves (Bcf) Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.30

Figure 10.14 – Sensitivity of gas exploration economics for areas near Yacheng 13-1 gas field shallow offshore China

Gas price sensitivity Development cost sensitivity

3,500 3,500 South China Sea South China Sea 3,000 3,000

2,500 2,500

2,000 2,000 Development cost at 150% of base case assumption

1,500 Gas price at US$3/Mcf 1,500 Development cost at 100% of base case assumption

1,000 Gas price at US$6/Mcf 1,000

Gas price at US$20/Mcf 500 500

Minimum prospect reserves (Bcf) Minimum prospect reserves (Bcf) Development cost at 50% of base case assumption 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

Peak production rate sensitivity Fiscal terms sensitivity

3,500 3,500 South China Sea South China Sea 3,000 3,000

2,500 2,500

Peak production at 50% of base case assumption 2,000 2,000

1,500 1,500

Chinese PSC 1,000 1,000 Peak production at 100% of base case assumption

500 500 No Income Tax

Minimum prospect reserves (Bcf) Peak production at 150% of base case assumption Minimum prospect reserves (Bcf) No Royalty 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

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10.10 Onshore west China – Tarim Basin - Gas field exploration and development economics

Figure 10.15 shows the results of the economic analyses for the base case gas field development in the areas close to the Kela 2 gas field in the Tarim Basin northwest China. It gives the NPV per thousand cubic feet (Mcf) over a range of reserves. The results are for representative field developments in the Tarim Basin and they do not represent the analyses of actual gas fields.

Figure 10.16 shows the minimum prospect reserves required for exploration drilling decisions for different given probabilities of success which are calculated based on the economics shown in Figure 10.15.

The key results of the economic analyses carried out for the base case development are listed below in Table 10.11.

 Table 10.11 - Results of economic analyses for base case gas field – onshore west China – Tarim Basin   Maximum net present value (US$ per Mcf) 0.72 Minimum field reserves (Billion cubic feet) 62 Minimum prospect reserves (Billion cubic feet) at 20% probability of success 282 Minimum prospect reserves (Billion cubic feet) at 50% probability of success 117

The results of sensitivity analyses are given in Figure 10.17 and Figure 10.18. The figures show the effect of variations in gas price, peak well production rate, development cost and fiscal terms.

The results in Figure 10.17 show that the economics of field development are the most sensitive to changes made to the gas price. The economics are also very sensitive to the decrease in peak well production rate and the elimination of

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.32

Income Tax. In contrast, the economics are insensitive to changes made to development cost, the increase in peak rate and the elimination of Royalty.

The gas price sensitivity graph in Figure 10.17 shows that when the gas price rises to US$20 per thousand cubic feet, the maximum net present value per thousand cubic feet increases to US$2.86 per thousand cubic feet as compared to US$0.72 per thousand cubic feet shown in Table 10.11 above.

The peak production rate sensitivity graph shows that the economics are more sensitive to the decrease in the peak production rate. For the case with 50% peak rate, the maximum net present value per thousand cubic feet drops to US$0.44 per thousand cubic feet.

The fiscal terms sensitivity graph demonstrates that the elimination of Royalty has less effect on field economics than the elimination of Income Tax. When the Income Tax is zero, the maximum net present value per thousand cubic feet is US$0.97 per thousand cubic feet.

Figure 10.18 shows that the decrease in gas price has a significant impact on exploration decisions. The decrease in the peak production rate by 50% of the base case also has a large effect on exploration economics. In contrast, exploration economics are less sensitive to changes made to the development cost and the increase in the peak rate. The changes made to fiscal terms have minimal effect on the exploration economics.

The gas price sensitivity graph in Figure 10.18 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 140 to almost 1,400 Bcf.

The peak well production rate sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 430 to 1,020 Bcf.

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Figure 10.15 - Base case gas field development economic for onshore west China

1.6 Tarim Basin 1.4

1.2

1.0

0.8 (US$/Mcf) 0.6

0.4

NPV at 10% per thousand cubic feet 0.2 Reserves (Bcf)

0.0 0 500 1,000 1,500 2,000 2,500

Figure 10.16 - Base case gas exploration economics for onshore west China

1,400 Tarim Basin 1,200

1,000

800

600

400

200 Minimumprospect (Bcf) reserves

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%)

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Figure 10.17 – Sensitivity of gas field development economics for areas near Kela 2 gas field onshore west China

Gas price sensitivity Development cost sensitivity

3.0 1.6 Tarim Basin Tarim Basin 1.4 2.5 Gas price at US$20/Mcf 1.2 Development cost at 50% of base case assumption 2.0 1.0 Development cost at 100% of base case assumption

1.5 0.8

Gas price at US$6/Mcf 0.6 1.0 feet (US$/Mcf) feet (US$/Mcf) 0.4 Development cost at 150% of base case assumption Gas price at US$3/Mcf 0.5 0.2 NPV NPV at 10% per thousand cubic NPV at 10% thousand cubic per 0.0 0.0 0 500 1,000 1,500 2,000 2,500 0 500 1,000 1,500 2,000 2,500 Reserves (Bcf) Reserves (Bcf)

Peak production rate sensitivity Fiscal terms sensitivity

1.6 1.6 Tarim Basin Tarim Basin 1.4 1.4

1.2 Peak production at 150% of base case assumption 1.2 No Income Tax No Royalty 1.0 Peak production at 100% of base case assumption 1.0

0.8 0.8

0.6 0.6 feet (US$/Mcf) feet feet (US$/Mcf) Chinese PSC 0.4 0.4

0.2 Peak production at 50% of base case assumption NPV atNPV 10% per thousand cubic 0.2 NPV at 10% per thousand cubic 10% at NPV

0.0 0.0 0 500 1,000 1,500 2,000 2,500 0 500 1,000 1,500 2,000 2,500 Reserves (Bcf) Reserves (Bcf) Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page10.35

Figure 10.18 – Sensitivity of gas exploration economics for areas near Kela 2 gas field onshore west China

Gas price sensitivity Development cost sensitivity

1,400 1,400 Tarim Basin Tarim Basin 1,200 1,200

1,000 1,000

800 800 Gas price at US$3/Mcf Development cost at 150% of base case assumption

600 600

Development cost at 100% of base case assumption 400 400 Gas price at US$6/Mcf Gas price at US$20/Mcf 200 200

Minimum prospect reserves (Bcf) Minimum prospect reserves (Bcf) Development cost at 50% of base case assumption 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

Peak production rate sensitivity Fiscal terms sensitivity

1,400 1,400 Tarim Basin Tarim Basin 1,200 1,200

1,000 1,000

800 Peak production at 50% of base case assumption 800

600 600

Peak production at 100% of base case assumption Chinese PSC 400 400

200 200 No Income Tax

Minimum prospect reserves (Bcf) Peak production at 150% of base case assumption Minimum prospect reserves (Bcf) No Royalty 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Probability of drilling success (%) Probability of drilling success (%)

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10.11 Summary and conclusions

In this chapter, I discuss the economics of field development and exploration in representative areas across China. The areas analysed include Bohai Gulf (offshore China), Bohai Bay Basin (onshore east China), South China Sea (offshore China) and Tarim Basin (onshore west China). An actual oil/gas field is selected for each area as a guide for economic and development assumptions. The base case economic analyses are carried out using an oil price of US$80 per barrel and a gas price of US$6 per thousand cubic feet (approximately equivalent to US$6 per giga joule).

Based on the results of the economic analyses, I conclude that the minimum filed reserve needed to justify the field development of an oil field is lower for fields located onshore east areas than offshore China. This is mainly because of the different well cost, development cost and other development assumptions.

As regard to the gas field developments in China, the minimum economic field reserves required to justify the gas field development in onshore west areas of China is significantly smaller than in offshore areas. This is because the well cost and the development costs for onshore areas are much lower than in offshore areas.

My conclusions of the sensitivity analyses conducted are given below.

Oil/gas price sensitivity

Changes made to oil/gas prices have significant effect on field development economics of all cases analysed. The impact on exploration economics is very large when oil/gas prices drop. This is because the prices determine the gross revenue of the field development. This demonstrates that the volatility of oil and gas prices has the most significant effect on field development.

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Development cost sensitivity

When changes are made to the development cost, the economics of exploration and development of gas fields in South China Sea are significantly affected. The field exploration and development economics in onshore areas and oil filed exploration and development economics in Bohai Bulf in offshore areas are less affected.

Peak production rate sensitivity

The decrease in peak production rate has much more impact on the economics of field exploration and development than the increase in peak rate within a +/- 50% range. The economics of exploring and developing gas fields in South China Sea are the most sensitive to changes made to peak production rate.

Fiscal terms sensitivity

Changes made to the fiscal terms have similar effect on the economics of field exploration and development in all of the cases analysed. Across the range of field sizes considered, the elimination of Royalty has a smaller effect on the economics of field exploration and development than the elimination of Revenue Windfall Tax or Income Tax. However, for low reserves, Royalty has a greater effect than the other fiscal components (see Chapter 8).

Wanwan Hou January 2009 University of New South Wales

Chapter 11

Recommendations

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 11.1

One of the findings of this thesis is that the Chinese fiscal regime for foreign contractors has inefficiencies that could hinder petroleum exploration and development in China. As a consequence, a significant number of small and marginal prospects and discoveries might not be developed unless the fiscal terms are revised. Such a situation is clearly unfavourable to both the Government and the contractors because neither would benefit if discoveries are not developed because of the way in which the fiscal terms operate. In order to avoid the distortions resulting from the fiscal terms and encourage investments, I would recommend that the Government improve the flexibility and the efficiency of the fiscal terms.

As illustrated in Chapter 8, the inefficient components in Chinese fiscal terms include Royalties, Cost Recovery Ceiling, Profit Sharing, Export Duty, Revenue Windfall Tax and the depreciation of capital costs for Income Tax purposes. These are the terms that are applied regardless of the project before-take net cash flow. In contrast, an efficient regime would be expected to place levies in proportion to the project before-take net cash flow. An efficient regime would guarantee that those Projects which are economic before take would also be economic after Government Take.

Comparison of Royalty and Rate of Return Tax

One example of an inefficient component of the Chinese PSC is Royalties. They are based on the gross revenue and therefore ignore the costs. In contrast, an example of an efficient fiscal mechanism is one based on compounded net cash flow. The latter is often referred to as a rate of return (ROR) regime in which tax or profit sharing does not come into effect until the net cash flow has generated a threshold rate of return. Table 11.1 compares the impacts of royalty and the ROR mechanisms on the contractors’ net present value.

The gross revenue, costs and net cash flow of the project are shown on the top of Table 11.1. The remainder of the table contains simplified calculations of the net cash flow for cases with Royalty and ROR Tax applied. As shown in the table, the project NPV at a 15% discount rate is $21.9 million. Therefore, the project is profitable before Government Take.

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 Table 11.1 - Comparison of Royalty and Income Tax     Units Total 1 2 3 4 5 6 Project NCF  Gross Revenue $MM 435.0  65.0 160.0 120.0 90.0 Capex $MM 200.0 50.0 150.0  Opex $MM 100.0  25.0 25.0 25.0 25.0 Project NCF $MM 135.0 -50.0 -150.0 40.0 135.0 95.0 65.0 Project NPV (15%) $MM 21.9        Royalty  Calculation Gross Revenue $MM 435.0  65.0 160.0 120.0 90.0 Royalty (10%) $MM 43.5  6.5 16.0 12.0 9.0 Capex $MM 200.0 50.0 150.0 Opex $MM 100.0  25.0 25.0 25.0 25.0 Contractors' NCF $MM 91.5 -50.0 -150.0 33.5 119.0 83.0 56.0 Contractors' NPV $MM -1.4  (15%)  ROR Tax  Calculation Gross Revenue  435.0  65.0 160.0 120.0 90.0 Capex 200.0 50.0 150.0  Opex 100.0  25.0 25.0 25.0 25.0 Project NCF $MM 135.0 -50.0 -150.0 40.0 135.0 95.0 65.0 Cum NCF +15% $MM -511 -50.0 -208.0 -198.6 -93.4 -12.4 50.7 Taxable income $MM 50.7  50.7 Income Tax (86%) $MM 43.5  43.5 Contractors' NCF $MM 91.5 -50.0 -150.0 40.0 135.0 95.0 21.5 Contractors' NPV $MM 3.1  (15%)  Source: Allinson, W. G. (2007). Lecture notes distributed in the unit. PTRL5008 Petroleum Production Economics. University of New South Wales. Kensington on 27 February 2007.

As regards the Royalty calculation, I assume that the royalty is 10% of Gross Revenue. The total royalty received by the Government is $43.5 million. After Royalty, the contractors’ NPV is reduced to minus $1.4 million, which implies that the project would not be developed. In such circumstances, neither the company nor the Government would obtain any benefit from the discovery.

As regards the ROR Tax, the project net cash flow is accumulated and compounded at a rate of 15%, which is the discount rate used to calculate the NPV. For instance, the net cash flow in the first year is minus $50 million. This is multiplied by (1+15%) and

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 11.3 then plus the net cash flow in the second year to give minus $208 million. The ROR tax is applicable once the cumulative net cash flow becomes positive. In this case, contractors receive a 15% rate of return before paying any tax. The tax rate assumed is 86% to ensure that the Government Take is $43.5 million which is the same as the royalty that would have been paid in the first case if the project went ahead. Under the ROR regime, the after-tax net cash flow is still positive. It is $3.1 million, which implies that the project would be developed and both company and the Government would benefit from the discovery.

The situation in Table 11.1 is purely a simplified illustration set up to compare a royalty and an ROR tax mechanism. The inefficient royalty regime tends to prevent the project from being developed while the efficient ROR tax regime does not. Theoretically, the Government would receive same amount of net cash flow from the project under both regimes. However, if the Royalty regime applies, the project would not be developed and thus neither the Government nor the contractors would receive any benefit. The ROR regime overcomes this problem. However, a key feature of the ROR regime is that the Government Take must wait until later in the project life after the contractors have received at least a 15% return on the project.

Recommendations

There are several fiscal regimes in the world that contain components which are based on ROR or similar mechanisms. One is Australian Petroleum Resource Rent Tax Regime. Others are based on “revenue-over-cost” (“R-over-C”), as applies in Malaysia, or “investment multiples” as applies in India.

As mentioned above, one feature of efficient regimes based on ROR, R/C or investment multiples is that Governments would not obtain any revenue until the contractors receive a certain level of return on their investment. Depending on the discount rate used, this would affect the NPV of the Government Take. However, if the Government’s discount rate is low, then the NPV of delayed Government Take might still yield an attractive benefit for the Governments and allow marginal projects to proceed. Since there are grounds for the Governments’ discount rate to

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page 11.4 be lower than the oil companies’ discount rate, a more efficient fiscal regime would potentially be beneficial for both Governments and oil companies.

Based on the discussion in the previous section, I would recommend that the Chinese Government as well as other Governments in the world mitigate or even eliminate the inefficient components in their fiscal regimes and develop more efficient regimes with tax or profit sharing mechanisms based on measures of profitability such as the ROR. This would significantly encourage the development of marginal projects.

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Appendix A – Conversion factors

Length 1 metre = 3.281 feet = 39.37 inches 1 kilometre = 0.621 miles (international)

Volume 1 barrel = 0.159 cubic metres 1 cubic metre = 35.31 cubic feet

Volume/weight equivalents Crude oil 1 metric tonne = 7.31 barrels LPG liquids 1 metric tonne = 11.06 barrels Light Naphtha 1 metric tonne = 9.33 barrels Heavy Naphtha 1 metric tonne = 8.48 barrels Aviation Gasoline 1 metric tonne = 8.97 barrels Motor Gasoline 1 metric tonne = 8.67 barrels Kerosene 1 metric tonne = 7.78 barrels Light Diesel 1 metric tonne = 7.62 barrels Fuel Oil (low sulphur) 1 metric tonne = 6.80 barrels Fuel Oil (high sulphur) 1 metric tonne = 6.53 barrels Bitumen 1 metric tonne = 6.23 barrels

Gas, oil and equivalent fuel values 1 barrel of oil equivalent = 5,500 to 6,000 cubic feet of natural gas 1 tonnes of petroleum products = 1.062 metric tonne of oil equivalent 1 tonne coal = 0.531 metric tonne of oil equivalent 1 trillion cubic feet of gas (TCF) = 23.31 million metric tonne of oil equivalent 1 billion kilowatt hours = 0.086 million metric tonne of oil equivalent

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Source - International Energy Agency Statistics Oilnews, China National Petroleum Corporation U.S. Department of Energy, Energy Information Administration (2001)

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Appendix B – Abbreviations bbl = barrel Bcf = billion cubic feet Bcfd = billion cubic feet per day Bcm = billion cubic metre bopd = barrels of oil per day Capex = capital costs cf = cubic feet FTP = first tranche petroleum GDP = gross domestic product Kbopd = thousand barrels of oil per day MAT = minimum alternate tax Mcf = thousand cubic feet MM = million MMbbl = million barrels MMcfd = million cubic feet per day MMtoe = million tonnes of oil equivalent NELP = Indian New Exploration Licensing Policy NCF = net cash flow NPV = net present value opex = operating costs PRRT = petroleum resource rent tax PSC = production sharing contract SC = service contract SRB = special remuneratory benefit Tcf = trillion cubic feet Tcm = trillion cubic metre US$MM = million US dollars VAT = value added tax

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Appendix C – Reserves definitions

This appendix presents the reserves definitions adopted by the Society of Petroleum Engineers (SPE), American Association of Petroleum Geologists (AAPG), World Petroleum Council (WPC) and Society of Petroleum Evaluation Engineers (SPEE) on Petroleum Resources Management System which were approved in 2007. The Petroleum Resources Management System consolidates, builds on, and replaces guidance previously contained in the 1997 Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions publications and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources”. This appendix also includes the definitions of Contingent Resources and Prospective Resources. Data include in this appendix is made available by SPE on their official web page.

1 Petroleum Reserves Definitions

These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that this document will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings.

1.1 Reserves Definitions

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page C.2 and may be sub-classified based on project maturity and/or characterized by development and production status.

To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame.

A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.

To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

1.1.1 Project Maturity Sub-Classes

On Production

The development project is currently producing and selling petroleum to market. The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%.

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Approved for Development

All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way.

At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget.

Justified for Development

Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

1.2 Reserves Status Definitions

Once projects satisfy commercial risk criteria, the associated quantities are classified as Reserves. These quantities may be allocated to the following subdivisions based on the funding and operational status of wells and associated facilities within the reservoir development plan.

Developed Reserves

Developed Reserves are expected quantities to be recovered from existing wells and facilities.

 Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

 Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

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Undeveloped Reserves

Undeveloped Reserves are quantities expected to be recovered through future investments:

(1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

Development and production status are of significant importance for project management. While Reserves Status has traditionally only been applied to Proved Reserves, the same concept of Developed and Undeveloped Status based on the funding and operational status of wells and producing facilities within the development project are applicable throughout the full range of Reserves uncertainty categories (Proved, Probable and Possible).

Quantities may be subdivided by Reserves Status independent of sub-classification by Project Maturity. If applied in combination, Developed and/or Undeveloped Reserves quantities may be identified separately within each Reserves sub-class (On Production, Approved for Development, and Justified for Development).

1.3 Reserves Category definitions

The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that:

 There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

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 There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

 There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately (see Category Definitions and Guidelines, section 2.2.2).

Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (risk-based) approach, the deterministic scenario (cumulative) approach, or probabilistic methods. (see “2001 Supplemental Guidelines,” Chapter 2.5). In many cases, a combination of approaches is used.

For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible.

Proved Reserves

Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

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Probable Reserves

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves

Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.

Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves.

Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the “best estimate” is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk (see “2001 Supplemental Guidelines,” Chapter 2.5).

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2 Other definitions

2.1 Contingent Resources

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

2.2 Prospective Resources

Potential resources are those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration.

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Appendix D – Fiscal terms in the Asia Pacific Region

This section presents a description of the structures and the key components of the oil fiscal terms in Australia, Indonesia, Vietnam, Bangladesh, Philippines, Thailand and India.

1 Australian Petroleum Resource Rent Tax (PRRT) regime

Australian PRRT regime applies to all offshore petroleum projects outside the Territorial Sea Limit, except for the Northwest Shelf project and two exploration permits offshore Western Australia. The basic structure of Australia PRRT regime is shown below in Figure D.1.

Figure D.1 – Structure of Australian PRRT regime

Gross revenue

less

Resource Rent Tax

less

Income Tax

less

Capex and Opex

equals

NCF to companies

RRT

The Resource Rent Tax is levied before Income Tax at a rate of 40% on income. It is payable after all cumulative costs with uplift have been recovered. In other words, RRT comes into effect only when projects have earned a minimum rate of return. Expenditures in different categories are compounded at different rates when

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.2 deducting from the gross revenue obtained from petroleum sales. The categories include a) “Development” costs, b) “Recent” exploration costs and c) “Old” exploration costs.

“Development” costs include capital costs incurred on the development of a project and annual operating costs of the project. These costs are compounded at a rate of 5% plus the interest rate for long term bond. The long term bond rates in the years from 1980 to 2004 are shown in Table D.1. Before 1 July 1990, the compound rate was 15% plus the long term bond rate.

“Recent” exploration costs refer to exploration costs incurred not more than five years before the grant of the production licence. These costs are compounded at a threshold rate of 15% plus the long term bond rate.

“Old” exploration costs are exploration costs incurred more than five years before the grant of the production licence. They are accumulated forward at GDP factor rates. The GDP factor rates from 1980 to 2004 are shown in Table D.1.

Expenditures must be deducted in a specific order depending on the date that costs have been incurred. The order of the deductions and corresponding compound rates are shown in Table D.2. In 1990, broader ring fence provisions were introduced. The ring fence for exploration costs changed from the project area to the whole of offshore Australia. The ring fence for development costs remained the project area.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.3

 Table D.1 - GDP factors and long term bond rates (LTBR)  Recent Financial years GDP Long term bond Development exploration ended 30 June factor % rate % uplift* % uplift % 1980 10.4 10.66 25.66 25.66 1981 10.8 12.58 27.58 27.58 1982 10.3 15.48 30.48 30.48 1983 11.0 14.43 29.43 29.43 1984 7.1 12.72 27.72 27.72 1985 6.5 13.41 28.41 28.41 1986 6.8 13.65 28.65 28.65 1987 8.3 13.57 28.57 28.57 1988 8.4 12.55 27.55 27.55 1989 9.3 12.86 27.86 27.86 1990 5.8 13.31 28.31 28.31 1991 3.0 12.11 27.11 17.11 1992 1.4 9.87 24.87 14.87 1993 1.0 8.35 23.35 13.35 1994 1.5 7.39 22.39 12.39 1995 2.1 9.85 24.85 14.85 1996 2.9 8.67 23.67 13.67 1997 1.5 7.63 22.63 12.63 1998 1.8 5.98 20.98 10.98 1999 0.4 5.45 20.45 10.45 2000 1.7 6.51 21.51 11.51 2001 4.5 5.82 20.82 10.82 2002 2.6 5.88 20.88 10.88 2003 2.8 5.34 20.34 10.34 2004 3.5 5.68 20.68 10.68 2005 2.7 5.42 20.42 10.42 2006 2.8 5.40 20.40 10.40 2007 3.2 5.82 20.82 10.82 * Development uplift rate is the LTBR plus 15% to 1990, LTBR plus 5% after 1990.

  Table D.2 - Order of deduction    Order Expenditure Compound rate 1 "Development" costs before 1 July 1990 LTBR+15% 2 "Recent" exploration costs before 1 July 1990 LTBR+15% 3 "Development" costs after 1 July 1990 LTBR+5% 4 "Old" exploration costs before 1 July 1990 GDP factor 5 "Recent" exploration costs after 1 July 1990 LTBR+15% 6 "Old" exploration costs after 1 July 1990 GDP factor 7 Abandonment cost As incurred

RRT is deductible for income tax purposes.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.4

Income tax

Income tax is payable after Petroleum Resource Rent Tax. Income tax rate is 30% at present. This rate was put into effect on 1 July 2001. Prior to 2001, the income tax rate had been changed frequently. In 1988, the rate was 49%, which was reduced to 39% and further to 33% in 1993. In the beginning of the financial year 1995/1996, it was increased to 36%. However, under the New Business Tax System Act 1999, the rate dropped to 34% in the financial year 2000/2001 and then to 30% in 1 July 2001.

In the calculation of taxable income, exploration, appraisal, operating and abandonment expenditures are deductible immediately. RRT is deducted in the same way.

Capital expenditures on plant and equipment (other than plant used exclusively for exploration purposes) are depreciated over the economic life of individual assets. The standard asset life is determined by the taxation commissioner for the oil and gas industry. The depreciation method can be either straight line or declining balance. If the declining balance method is used, the rate is set at 150% of the straight line method. However, the life of the project may be claimed if it is less than the life of assets and the assets are not renewable. Non-plant development costs (site preparation, provision of facilities etc) are depreciated on a straight line basis over the lesser of the field life and 10 years. Depreciation begins when an asset is first installed ready for use.

For the purpose of the analyses in this thesis, I assume that all capital costs are depreciated on a straight line basis over the economic life of a field starting from production begins.

The ring fence for income tax is around the whole of Australia. Deductible expenses can be offset against income from any source.

After tax net cash flow

The companies’ after tax net cash flow is the remaining revenue after deduct RRT, income tax and all capital and operating costs from the gross revenue.

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2 Bangladesh production sharing contracts (PSCs)

Most fiscal terms of a Bangladesh PSC are negotiable. This section describes and interprets the most recent model PSC announced in 1997. The terms described are believed to be typical. In practice, individual PSCs might be different from the one used here.

Figure D.2 shows the basic structure of a Bangladesh PSC. It is a simplified flow chart showing the derivation of the contractors’ net cash flow in one production year.

The chart contains three parts of cash flows – project cash flow, state cash flow and contractors’ cash flow. The beginning of the chart is the Gross Revenue on the top left hand side of the figure. The net cash flow (NCF) to the contractors is shown at the bottom right hand side. Detailed descriptions of each component of the fiscal terms are given following the figure.

Royalty

There is no Royalty in Bangladesh PSCs.

Cost Recovery

In Bangladesh, contractors are allowed to recover their share of costs using the gross revenue from sales of petroleum. The costs can be recovered are restricted within a ring fence around the contract area. There is a negotiable cost recovery ceiling with a maximum 50% for oil and 55% for gas and natural gas liquids.

Costs are recoverable in the following order –

 Operating costs as incurred;  Exploration costs and tangible capital costs are recovered in the year in which the costs are incurred or the year in which commercial production starts, whichever is later;

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.6

Figure D.2 – Structure of Bangladesh PSC

Project Cash Flow State Cash Flow Contractors Cash Flow

Gross revenue

Cost Recovery to Cost Recovery Contractors

Profit Petroleum to State Profit Petroleum Profit Petroleum to Contractors

Bonuses to State Bonuses

Contractor share of Capex and Opex

NCF to Contractors

 Intangible capital costs are depreciated at a negotiable rate (indicatively 25%) on a straight line basis starting in the year of production begins;  Any costs not recovered in any one year are carried forward and recovered in the following years.

In some earlier contracts, tangible costs were depreciable and intangible costs expensed. In this analysis, I assume that 60% of development costs are depreciated and the other 40% are expensed. Costs not recovered after the end of the economic life of a field are considered as losses to contractors.

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Profit Sharing

The remaining revenue after cost recovery is Profit Petroleum which is shared between contractors and Petrobangla on an incremental sliding scale based on levels of production rate. The sliding scale is negotiable. Table D.3 shows the shares of profit oil used in the analyses in this chapter.

 Table D.3 - Profit sharing in Bangladesh PSCs   Increment of production State’s share of Profit Contractors’ share of Profit (Kbopd) Petroleum Petroleum 0 - 25 55% 45% 25 - 50 65% 35% 50 - 75 75% 25% 75 - 100 85% 15% over 100 87.5% 12.5%

Bonuses

There is no signature bonus in Bangladesh PSCs. A discovery bonus is payable once a discovery is made. In this thesis, I assume that the discovery bonus is 1 million US dollars (US$1MM).

Production bonuses are payable as different levels of production are reached. The production levels for oil in thousand barrels per day (Kbopd) together with example bonuses are –

12.5 Kbopd $1 MM 25 Kbopd $2 MM 37.5 Kbopd $3 MM 50 Kbopd $4 MM 62.5 Kbopd $5 MM 100 Kbopd $10 MM

Bonuses are not cost recoverable.

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Income Tax

Income tax is paid on the contractors’ behalf by Petrobangla out of its share of production. Therefore, the effective tax for the contractors is zero.

After tax net cash flow

Contractors’ total revenue consists of the Cost Recovery and the contractors’ share of Profit Petroleum. The contractors’ total outgoing includes the bonuses and the contractors’ share of capital and operating costs. The contractors’ after tax net cash flow is calculated by deducting the contractors’ total outgoing from their total revenue.

3 Philippines service contracts (SCs)

This section describes the typical terms of the Philippines service contracts as set out in the Presidential Decree No 87 of 1972 as amended by the Presidential Decree No 1857 of 1983. In practice, the terms are negotiable for individual SCs and might be different to those set out here.

The basic structure of a Philippines SC is shown in Figure D.3. It is a simplified flow chart showing the way in which contractors’ net cash flow is derived in one production year under a Philippines SC.

The chart contains three parts of cash flows – project cash flow, state cash flow and contractors’ cash flow. The beginning of the chart is the Gross Revenue on the top left hand side. The NCF to the contractors is shown at the bottom right hand side. Detailed descriptions of each component of the fiscal terms are given following the figure.

Royalty

There is no Royalty in Philippines SCs.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.9

Figure D.3 – Structure of Philippines SC

Project Cash Flow State Cash Flow Contractors Cash Flow

Gross revenue

Filipino Participation FPIA to Incentive Allowance Contractors (FPIA)

Cost Recovery Cost Recovery to Contractors

Profit Petroleum to State Profit Petroleum Profit Petroleum to Contractors

Bonuses to State Bonuses

Contractor share of Capex and Opex

NCF to Contractors

Filipino Participation Incentive Allowance (FPIA)

If a Filipino company holds a participating interest of at least 15% in the contract, the contractors are allowed to receive a share of the gross revenue on the scales shown in Table D.4.

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 Table D.4 - Filipino Participation Incentive Allowance  Filipino Company Standard FPIA (of gross Deep water contracts* FPIA Participation revenue) (of gross revenue) 30.0% or more 7.5% 7.5% 27.5% - 30.0% 6.5% 7.7% 25.0% - 27.5% 5.5% 7.5% 22.5% - 25.0% 4.5% 7.5% 20.0% - 22.5% 3.5% 7.5% 17.5% - 20.0% 2.5% 7.5% 15.0% - 17.5% 1.5% 7.5% Below 15.0% 0.0% 0.0% * Deepwater field development (>200 metres depth) in contracts that are not deepwater contracts (>85% of the contract area is more than 200 metres depth) also qualify under DOE Circular No. 94-01-01.

Cost Recovery

In the Philippines, the contractors are allowed to recover various costs incurred within the contract area using the gross revenue available from sales of petroleum. There is a cost recovery ceiling of 70% of the gross revenue.

Costs are recoverable in the following order –

 Operating costs as incurred;  Exploration costs as incurred;  Tangible capital costs are depreciated over 10 years (5 years for deep water) on a straight line basis starting in the year of production begins;  Intangible capital costs as incurred;  Any costs not recovered in any particular year are carried forward and recovered in the following years.

Contractors can also recover a provision for abandonment costs towards the end of field life once 70% of the estimated reserves in a field have been produced. Costs not recovered after the end of the economic life of a field are considered as losses to the contractors.

In 1983, there has been a Cross Cost Recovery Allowance that allows costs incurred in one deepwater contract to be recovered from the gross revenue of another deepwater

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.11 contract. The restrictions on costs incurred prior to the date of production are shown below in Table D.5.

 Table D.5 - Cross Cost Recovery Allowance  Years prior to the date of production Portion of costs recoverable up to 10 100% 11 80% 12 60% 13 40% 14 20% 15 or more 0%

Profit Sharing

The remaining revenue after cost recovery is Profit Petroleum which is shared between contractors and State on a fixed percentage. The profit sharing scale is negotiable with contractors’ share not exceed 40% and State’s not less than 60% of the Profit Petroleum.

Bonuses

The amounts of bonuses payable in Philippines SCs are negotiable. There is a discovery bonus payable once a discovery is made (for example US$1MM). Production bonuses are payable as different levels of production are reached. The production levels for oil in thousand barrels per day (Kbopd) are –

50 Kbopd for example $1 MM 75 Kbopd for example $2 MM 100 Kbopd for example $3 MM

Bonuses are not cost recoverable.

There are typically no bonus payments for gas production.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.12

Income Tax

Income tax is paid on the contractors’ behalf by the Office of Energy Affairs from the State’s share of production. Therefore, the effective tax for the contractors is zero.

After tax net cash flow

The contractors’ total revenue consists of the Cost Recovery, contractors’ share of Profit Petroleum and the FPIA, if any. The contractors’ total outgoing includes the bonuses and the contractors’ share of capital and operating costs. Therefore, the contractors’ after tax net cash flow is calculated by deducting the contractors’ total outgoing from their total revenue.

4 Vietnamese PSCs

The basic structure of a Vietnamese PSC is illustrated in Figure D.4. It is a simplified flow chart illustrating the general way in which the contractors’ net cash flow is derived in one production year.

The chart contains three parts of cash flows – project cash flow, state cash flow and contractor’s cash flow. The beginning of the chart is the Gross Revenue on the top left hand side. The remaining of the chart shows the way in which different elements of State Take are applied in the derivation of after tax NCF. The NCF to the contractors is shown at the bottom right hand side. Detailed descriptions of each component of the fiscal terms are given following the figure. In practice, the terms are negotiable for individual PSCs and might be different to those set out here.

Royalty

Under Vietnamese PSCs, Royalty is levied as a percentage of Gross Revenue. As set out in the Petroleum Decree effective from 1 July 2000, Royalty is calculated on an incremental sliding scale based on the rate of production. The minimum and maximum royalty rates are 4% and 25% for crude oil and 0% and 10% for gas. Before 1 July 2000, the lowest royalty rate for crude oil was 6% and in special cases, the highest rate for

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.13

Figure D.4 – Structure of Vietnamese PSC

Project Cash Flow State Cash Flow Contractors Cash Flow

Gross revenue

Royalty Royalty to State

Cost Recovery Cost Recovery to Contractors

Profit Petroleum to State Profit Petroleum Profit Petroleum to Contractors

Export Duty to State Export Duty

Bonuses to State Bonuses

Income Tax to State Income Tax

Transfer Tax to Transfer Tax State

Contractor share of Capex and Opex

NCF to Contractors

crude oil could exceed 25%. The sliding scale of royalties effective from 1 July 2000 is shown in Table D.6. The previous rates are shown in brackets.

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 Table D.6 - Royalty rates in Vietnamese PSCs effective 1 July 2000  Average daily production Royalty rate (%) Encouraged Oil Gas projects Other projects Kbopd MMm3D MMcfd* 0 - 20 4 (6) 5 (8) 20 - 50 6 (6) 8 (8) 50 - 75 - 8 10 75 - 100 10 15 100 - 150 15 20 over 150 20 25 0 - 5 0 - 175 0 (0) 0 - 5 - 10 175 - 350 3 (3) 5 over 10 over 350 6 (6) 10 *Assuming that 1 cubic metre = 35 cubic feet

Under the amendments to the Petroleum Law in 2000, “encouraged projects” were defined as: “petroleum operations in deep-water areas (>200 metres depth), remote offshore areas and other areas with especially difficult geological and geographic conditions as specified in lists of blocks determined and issued by the Prime Minister.”

Under the Petroleum Law, if agreed by the contractors and PetroVietnam, PetroVietnam can meet the contractors’ royalty and tax liability from its share of Profit Petroleum. This practice was adopted for many of the contracts signed in the early to mid-1990s. However, in the more recent contracts, contractors are expected to pay royalty directly.

Cost Recovery

After royalty, the contractors are allowed to recover costs from the Gross Revenue, subject to a negotiated cost recovery ceiling. In the June 2000 amendments to the Petroleum Law, the maximum cost recovery ceiling is 50% for oil and 60% for non-associated gas. It could be increased to 70% for “encouraged projects”. In the 1990s, the ceilings were in the range of 30% to 45%. For some contracts signed at that time, the ceilings were linked to production rates.

Costs can be recovered under Vietnamese PSCs include all exploration, appraisal, development and production costs incurred within the contract area. All costs are

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.15 expensed and recovered immediately. In the case of transport costs, the costs incurred up to the point of delivery of the product are also recoverable. Abandonment costs the government has approved are recoverable. However, no sinking fund formula for recovering abandonment costs is specified in the PSC.

Interest, bonuses, data purchase and training fund costs are not recoverable.

Profit Sharing

The revenue remaining after royalty and cost recovery is Profit Petroleum which is shared between the contractors and the State at negotiable rates on an incremental sliding scale depending on the production rate. Table D.7 gives the indicative profit shares for crude oil.

 Table D.7 - Profit sharing in Vietnamese PSCs  Increment of Production (Kbopd) Contractors' share of Profit Petroleum 0 - 75 50% 75 - 100 45% 100 - 150 40% - 45% over 150 30% - 40%

For profit gas, the contractors’ share is indicatively a fixed 50%, although in the 2004 model contract the incremental rates and the contractors’ share were negotiable.

Export Duty

There is an export duty at the rate of 4% of the market price of the cost recovery oil and profit oil exported outside Vietnam. The rate is 0% for exported natural gas. Export duty is not cost recoverable in the 2004 model contract.

Income Tax

The income tax rate set out in the 1993 Petroleum Law is 50%. However, income tax might be exempt or reduced for special cases. According to the 2003 Law on Corporate Income Tax which entered into effect on 1 January 2004, the income tax rate ranges

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.16 from 28% to 50% depending on each specific project and business establishment. The model contract issued in the 2004 deep water licensing round specifies an income tax rate of 32%. At the discretion of the government, the contractors can be exempt from paying income tax for a maximum of two years. Under Petroleum Law, if agreed, PetroVietnam may pay income tax on behalf of the contractors out of the State’s share of production.

The following table gives a summary of the income tax rates.

 Table D.8 - Income tax rates in Vietnam  Type of contracts Normal rate Discretionary rates Normal projects 50% Year 1,2 - exemption  Year 3,4 - 24%  Year 5 onwards 50% Encouraged projects 32% Year 1,2 - exemption  Year 3,4 - 16%  Year 5 onwards 32%

Income tax is levied on contractors’ income, which consists of Cost Recovery and the contractors’ share of Profit Petroleum. The deductions allowed include operating costs, export duty, interest, taxes and fees related to production and business activities and depreciation of fixed assets. No depreciation method is specified. It is negotiable and set out in individual contracts. However, the Ministry of Finance issues guidelines for annual depreciation rates which are typically on a straight line basis. The depreciation rates for plant and machinery are between 10% and 20%. In this analysis, I assume that 60% of the development costs are depreciated at a rate of 20% on a straight line basis.

Withholding Tax

Withholding tax is 3%, 5% or 7% of the profit transferred, depending on the level of capital contribution of such foreign investor. PetroVietnam may pay these taxes from the State’s share of production if agreed by the parties.

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After tax net cash flow

The contractors’ total revenue consists of Cost Recovery and contractors’ share of Profit Petroleum. The contractors’ total outgoing includes export duty, bonuses, income tax, withholding tax and the contractors’ share of capital and operating costs. Therefore, the contractors’ after tax net cash flow is calculated by deducting the contractors’ total outgoing from their total revenue.

5 Thailand fiscal regime

The basic structure of the Thailand fiscal regime is shown in Figure D.5. The figure illustrates the general way in which the contractors’ after tax net cash flow is derived in one production year.

The chart contains the contractors’ cash flow and the State cash flow. The Gross Revenue shown in the box on the top left hand side is the beginning of the chart. The remaining of the chart shows the way in which different elements of State Take are applied in the derivation of net cash flow. The net cash flow to the contractors is shown at the bottom left hand side. Detailed descriptions of each component of the fiscal terms are given following the figure.

Royalty

Royalty is payable monthly out of Gross Revenue on a sliding scale depending on production rates. There is a ring fence around the exploration block for royalty. The incremental sliding scale is shown in the table below.

  Table D.9 - Royalty rates in Thailand fiscal regime    Royalty rate (%) Royalty rate (%) Oil production Gas production onshore & shallow deep water areas (Kbopd) (MMcfd) water areas (<200m) (>200m) 0 - 2 0 - 20 5.00 3.500 2 - 5 20 - 50 6.25 4.375 5 - 10 50 - 100 10.00 7.000 10 - 20 100 - 200 12.50 8.750 over 20 over 200 15.00 10.500

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Figure D.5 – Structure of Thailand fiscal regime

Contractors Cash Flow State Cash Flow

+Gross revenue

-Royalty +Royalty to State

-Costs

-Special +Special Remuneratory Remuneratory Benefit Benefit to State

-Income Tax +Income Tax to State

=NCF to Contractors

Under the Petroleum Act (4) of 4 August 1999, there might be a reduction in the royalty of up to 30% for concession blocks or production areas where geological conditions are unfavourable or for new concessions where high costs are indicated. Such reduction may only apply for up to four years for existing petroleum operations and three years for new concessions.

Special Remuneratory Benefit (SRB)

SRB is payable on Profit Petroleum once all prior losses are offset. The SRB payment equals the profit petroleum multiplied by the SRB rate. The steps of the derivation of Profit Petroleum and SRB rate are illustrated as follows.

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 Profit Petroleum The profit petroleum is calculated by deducting the following from the gross revenue: capital costs, operating costs, royalty payments, any losses carried forward and a special reduction, if any. The special reduction is defined as the “amount of money the government prescribes from time to time when awarding concessions”. In Petroleum Regulation No.15 issued on 8 December 1989, it was stated that this reduction would not exceed 35% of capital costs on any exploration blocks. The special reduction rates for different geological region are shown in Table D.10.

  Table D.10 - Special reduction rates for SRB   Special reduction rate in Special reduction rate in Region 1989 1997 Onshore 0% 10% Offshore  Gulf of Thailand 0% 25% Andaman Sea: Shallow * 25% Andaman Sea: Deep * 35% * Fixed at State’s discretion up to maximum of 35%

 SRB rate The SRB rate payable depends on the “annual revenue per one metre depth of well” (in Baht per metres). It also takes into account the geology and geological risk which is reflected by a geological stability factor (GSF). The annual revenue used in the calculation is adjusted by an inflation factor and a currency exchange factor. The annual revenue per one metre depth of well is calculated using the equation below.

Rev Annual revenue per one metre depth of well = e  GSFM Where –

Reve (Baht) = adjusted annual revenue that reflects the dollar value of any year’s annual revenue at the time the concession was granted.

Reve is calculated as follows –

Reve = Revm  (Ie/Im)  0.5  ((Ce/Cm) + (Pe/Pm)) Where –

Revm = current year’s revenue in Baht

Ie = the exchange rate in the year the concession was awarded

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Im = the exchange rate in the accounting (i.e. current) period

Ce = the consumer price index in the year the concession was awarded

Cm = the consumer price index in the accounting (i.e. current) period

Pe = the producer price index* in the year the concession was awarded

Pm = the producer price index* in the accounting (i.e. current) period

*The original formula in the 1991 PA 19 Sec 2 used the wholesale price index. It was replaced by the producer price index in January 2000.

M (metres) = cumulative metres of wells drilled on the concession area. This includes dry holes, water and gas injection wells, but excludes abandoned production wells which have produced over 100,000 barrels of oil. GSF (metres) = geological stability factor GSF is a constant fixed for each geological region. A summary of GSF is given in Table D.11.

 Table D.11 - Geological stability factor (GSF) by region    GSF (metres) GSF (metres) GSF (metres) Region 2000 & 2005 1995 -1998 1989 Onshore  Northern Plains 300,000 300,000 150,000 Central Plains 300,000 300,000 150,000 Southern Plans 300,000 300,000 150,000 Northeast 450,000 450,000 170,000 Offshore  Gulf of Thailand 600,000 150,000 150,000 Andaman Sea: Shallow 600,000 600,000 150,000 Andaman Sea: Deep 1,200,000 1,200,000 180,000

Once the annual revenue per metre is derived, the SRB rate is determined as follows.

The SRB rate is calculated every year and is rounded up to the nearest percent.

Having derived the profit petroleum and the SRB rate, the SRB payment can be calculated.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.21

 Table D.12 - SRB rates in Thailand fiscal regime  Annual revenue per one metre depth of well (Baht/metre) SRB rate below 4,800 0% 4,800 - 14,400 0% plus 1% per 240 Baht/metre 14,400 - 33,600 40% plus 1% per 960 Baht/metre 33,600 - 91,200 60% plus 1% per 3,840 Baht/metre above 91,200 75%

Income Tax

The current income tax rate is 50%. The ring fence for income tax is around the concession area. The deductions against tax allowed are as follows –

 Royalty is deductible;  Special Remuneratory Benefit is deductible;  Operating costs are deductible;  Interest charge is deductible but interest earned is subject to tax at 50-60%;  Tangible exploration and development costs are depreciated over 5 years;  Intangible exploration and development costs are depreciated over 10 years;  Concession acquisition costs are depreciated over 10 years;  All costs associated with deep water blocks are depreciated over 5 years;  Home office expenditure “reasonably allocable to the petroleum business of the company” is deductible. No specific limit is set, either in terms of amounts or of percentage of total costs.

Any generally accepted depreciation method can be used, such as straight line depreciation. Once a method is selected, it can not be changed.

Although abandonment costs are not specifically mentioned, abandonment sinking funds are not allowed as deductions for tax purposes. Therefore, provisions for abandonment costs would not be allowed. Abandonment costs only become deductible once incurred.

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After tax net cash flow

The revenue remaining after deducting royalty, costs, SRB and income tax is the net cash flow to the contractors.

6 Indian NELP PSCs

India’s New Exploration Licensing Policy (NELP) was announced in 1997. This section describes and interprets the NELP terms as announced in the 2005 bidding round. In practice, terms are negotiable for individual PSCs and might be different to those set out here.

The basic structure of the India NELP PSC is illustrated in Figure D.6. It is a simplified flow chart that illustrates the way in which the contractors’ net cash flow is derived in one production year.

The chart contains three parts of cash flows – project cash flow, State cash flow and contractors’ cash flow. The Gross Revenue shown in the box on the top left hand side is the beginning of the chart. It is the gross income of the project from the sales of petroleum produced from a field. The remaining of the chart shows the way in which different elements of State Take are applied in the derivation of net cash flow. The net cash flow to the contractors is shown at the bottom right hand side. Detailed descriptions of each component of the fiscal terms are given following the figure.

Royalty

Royalty is payable on a percentage of the well head value of the oil and gas production. The royalty rate varies depending on the circumstances. A summary of royalty rates is given in Table D.13.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.23

Figure D.6 – Structure of Indian NELP PSC

Project Cash Flow State Cash Flow Contractors Cash Flow

Gross revenue

Royalty Royalty to State

Cost Recovery Cost Recovery to Contractors

Profit Petroleum to State Profit Petroleum Profit Petroleum to Contractors

Income Tax to State Income Tax

Contractor share of Capex and Opex

NCF to Contractors

  Table D.13 - Royalty rates in Indian NELP PSCs     Onshore Offshore  Shallow water (<400 metres) Deep water (>400 metres)* Oil 12.5% 10.0% 5.0% Gas 10.0% 10.0% 5.0% * The reduced rate of 5% for deep offshore developments in over 400 metres of water is only available for the first seven years of commercial production. After seven years, the rate would be the same as that for offshore shallow water areas (10%).

In the model PSC, well head value is not defined in detail. In practice, well head value is derived by deducting the costs of transport and treatment from the gross revenue.

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.24

However, the model PSC does not specify what costs are deductible. In this illustrative analysis, I assume that well head value is 80% of the gross revenue.

Cost Recovery

Contractors can recover all their costs from a biddable percentage of the gross revenue. This percentage is referred to the cost recovery ceiling. There is a ring fence around the contract area for cost recovery purposes. All costs are expensed and recovered immediately.

Based on the practice in existing Indian PSCs, the use of cost recovery ceiling is very unusual. In effect, 100% of the gross revenue is available for cost recovery in most existing PSCs.

Costs are recovered in the following order –  Royalty payments  Operating costs  Exploration costs  Development costs  Any costs which have not been recovered in previous years

Profit Sharing

The remaining revenue after deducting the cost recovery from the gross revenue is Profit Petroleum. Profit petroleum is shared between the State and the contractors on a sliding scale based on the contractors’ “Investment Multiple” (IM) actually achieved in the previous year.

The IM is defined as the ratio of the contractors’ accumulated net cash income from petroleum operations in any particular year to the contractors’ accumulated investment in the contract area in the same year. The two factors are determined using following equations.

Net cash income = contractors’ cost recovery + contractors’ share of Profit Petroleum – contractors’ operating costs – royalty payments

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.25

Investment = contractors’ exploration costs + development costs

The IM in any one year determines the profit shares in the following year. The incremental sliding scale is defined in the 2006 model contract but the profit shares are negotiable. As an illustration, the profit shares assumed for the analyses in this chapter are shown in the table below.

 Table D.14 - Profit sharing in India NELP PSCs  Investment multiple at the end of Contractors' share of Profit Petroleum in previous year current year below 1.5 100% 1.5 - 2.0 90% 2.0 - 2.5 80% 2.5 - 3.0 70% 3.0 - 3.5 60% over 3.5 50%

Prior to NELP, profit sharing was calculated on a sliding scale depending on the after tax cumulative net cash flow as a multiple of the exploration and development costs.

Income Tax

Currently, the income tax rate is 40% for foreign companies. In addition, foreign companies are subject to a 2.5% surcharge on income tax. Some of the materials regarding the fourth NELP licensing round (2003) indicate that the surcharge would be abolished. However, it is not clear that whether this has actually happened. To be conservative, I assume that the surcharge does apply in this analysis. Since the 2004/2005 financial year, the income tax rate has been enhanced by an educational charge at a rate of 2% on tax payment (inclusive of surcharge). Therefore, the final effective income tax rate for foreign companies is 40%*(1+2.5%)*(1+2%) = 41.82%.

Under the NELP terms, there is an income tax holiday of seven years from the start of production.

Income tax is payable on the contractors’ taxable income. An illustration of the calculation of taxable income is given below.

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Contractors’ cost recovery plus Contractors’ share of profit petroleum less Royalty payments less Exploration and production costs less Depreciation of development costs on a declining balance basis less Abandonment sinking fund equals Taxable income

In practice, different items of capital costs are depreciated at different rates. For a simplified illustration in this analysis, I assume a depreciation rate of 25% for income tax purposes. I also assume that 50% of development costs are depreciated and the remaining 50% are expensed and deducted immediately.

Minimum Alternate Tax (MAT)

With effect from April 1997, the MAT has applied. The MAT is payable at 7.5% on the contractors’ profit. However, there is also a 2.5% surcharge and 2% educational charges apply to the MAT payment. The effective rate of MAT is therefore 7.5%*(1+2.5%)(1+2%) = 7.84%.

An example of the calculation of the contractors’ profit is shown below –

Contractors’ cost recovery plus Contractors’ share of profit petroleum less Royalty payments less Exploration and production costs

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.27 less Depletion (mainly development costs on a unit of production basis) less Abandonment sinking fund equals Profit

In practice, each company may has different accounting practices and calculate the profit differently. For instance, some of the capital costs are depreciated. In this study, I assume that 50% of development costs are depleted and 50% are depreciated at 27.82%.

The depreciation rates set out in the Income Tax Act 1961 for income tax and in Company Law for MAT are shown in Table D.15.

  Table D.15 - Annual depreciation rates    Type of asset Income Tax Act (for income tax) Company Law (for MAT) Land 4% 4% Buildings 10% 5% Plant & machinery 15% 27.82% Furniture & fittings 10% 18.10% Vehicles 15% 25.89% Computers 60% 40%

The seven-year tax holiday does not apply to the MAT.

Under the NELP terms, MAT applies in cases where the income tax payment on contractors’ income is less than 7.5% of their profits. In other words, the tax payable by the contractors is either the normal income tax or the MAT whichever is higher. For the tax years ending on of after 31 March 2001, MAT payments can not be carried forward for set off against income tax payments in following years. However, for tax years ending on or before March 2000 and beginning on or after 1 April 2006, MAT payments may be carried forward for five years and deducted against tax payments. In 2006/2007, the rate of MAT was increased to 10% on contractors’ profit. In addition, the period within which MAT could be carried forward and deducted against tax was extended from five years to seven years.

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The ring fence for income tax purposes is around the country in relation to conventional oil and gas operations. Contractors can deduct all their unsuccessful exploration costs outside the contract area against tax.

After tax net cash flow

Based on the foregoing, the contractors’ total revenue consists of the cost recovery and contractors’ share of Profit Petroleum. The contractors’ total outgoing includes the royalties, income tax and the contractors’ share of capital and operating costs. Therefore, the contractors’ after tax net cash flow is calculated by deducting the contractors’ total outgoing from their total revenue.

7 Indonesian PSCs

The basic structure of a conventional Indonesian PSC is illustrated in Figure D.7. The figure illustrates the way in which the contractors’ after tax net cash flow is derived in one production year.

The chart contains three parts of cash flows – project cash flow, state cash flow and contractor’s cash flow. The Gross Revenue shown in the box on the top left hand side is the beginning of the chart. It is the gross income of the project from the sales of petroleum produced from a field. The remaining of the chart shows the way in which different elements of State Take are applied in the derivation of net cash flow. The net cash flow to the contractors is shown at the bottom right hand side. Detailed descriptions of each component of the fiscal terms are given following the figure. In practice, terms are negotiable for individual PSCs which might be different to those set out in here.

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Figure D.7 – Structure of Indonesian PSC

Project Cash Flow State Cash Flow Contractors Cash Flow

Gross revenue

First Tranche FTP to State FTP to Contractors Petroleum (FTP)

Domestic Obligation to State

Cost Recovery and Cost Recovery and Investment Credits Investment Credits to Contractors Profit Petroleum to State Profit Petroleum Profit Petroleum to Contractors

Bonuses to State Bonuses

Income Tax to Income Tax State

Contractor share of Capex and Opex

NCF to Contractors

FTP

The first claim on Gross Revenue from the sales of petroleum is FTP which is shared between the State and the contractors. FTP is currently 20% of the gross revenue in

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.30 conventional areas and 15% in frontier areas. Shares of FPT are in principle negotiable, but are typically the same as the shares for Profit Petroleum (see below).

Cost Recovery

After FTP, the contractors are allowed to recover their costs from the remaining revenue. There is no cost recovery ceiling in Indonesian PSCs. The contractors can recover costs from 100% of the remaining revenue after the share of FTP.

The costs that can be recovered immediately as incurred include exploration costs, operating costs, intangible capital costs and interest on loans raised for capital expenditures. Tangible capital costs are depreciated on a declining balance basis. I assume that the depreciation for oil is 25% over 4 years, with a balance allowed for unrecovered costs in the fifth year.

Under the 1995 model contract, contractors must make provisions for abandonment costs. Such sinking funds are also cost recoverable.

Investment Credit

Under Indonesian PSCs, an Investment Credit is recovered from Gross Revenue before the recovery of costs. Various investment credits apply to the capital costs depending on the water depth and the age of the reservoir. Under conventional terms, for an oil development the percentage is maximum 15.78% for tertiary rocks and 102.14% for pre-tertiary rocks. For frontier areas in water depth greater than 1,000 metres, the investment credit is 80% of the capital costs. Since the introduction of the 1993 incentives, the investment credit no longer applies for frontier areas.

For simplified illustration, I assume that no investment credit applies in this analysis.

Profit Sharing

The revenue remaining after FTP and Cost Recovery is Profit Petroleum which is shared between the State and the contractors. The shares vary depending on the location and the type of the development. Since the introduction of the 1993 incentives, the

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page D.31 contractors’ share of profit oil is 15% for conventional areas and 35% for frontier areas. The contractors’ share of profit gas is 35% for conventional areas and 40% for frontier areas.

The profit shares given above are on an after-tax basis. However, the shares are expressed in contracts on a before-tax basis. The equivalent before-tax share is derived by dividing the given after-tax share by (1 – tax rate). Therefore, providing the current income tax rate of 44%, the before-tax shares are as follows.

 Table D.16 - Profit sharing on a before-tax basis in Indonesian PSCs   Conventional areas Frontier areas Oil 26.79% 62.50% Gas 62.50% 71.43%

Income Tax

Income tax is payable on the contractors’ revenue. This revenue includes Cost Recovery, the contractors’ share of FTP and Profit Petroleum which is not sold under the domestic obligation (see below). Income received in the form of interest, dividends or royalty is also taxable. The current income tax rate is 44%. There is a ring fence around the contract area for income tax purposes.

Note that the income tax rate is a composite of a 30% basic income tax and a 20% withholding tax on the balance. The calculation of the combined rate is shown below.

Basic income tax rate = 30% Income remaining after company tax = 70% Withholding tax rate = 20% Therefore, effective withholding tax = 70% * 20% = 14% Therefore, effective total income tax = 30% + 14% = 44%

The income tax applying to the contracts signed between 1984 and 1994 was 48%. This is composed of a 35% basic income tax and a 20% withholding tax. For the PSCs signed before 1984, the rate was 56% (45% basic income tax and 20% withholding tax).

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The deductions allowed and depreciation rules for income tax purposes are the same as those for Cost Recovery. Bonuses are also tax deductible.

Domestic Market Obligation (DMO)

Under Indonesian PSCs, in each year after the fifth year of production, contractors must sell a portion of their FTP and Profit Oil to the domestic Indonesian market at a discounted price. The DMO oil price is 15% of the price obtained in international markets for conventional contracts and 25% for frontier contracts. Under the 2002 conventional model contract, DMO applies to natural gas as well, but the DMO gas price is at market rates.

The DMO is calculated based on the lower of a) the total domestic consumption of crude oil in Indonesia divided by the total domestic production of crude oil in Indonesia, b) 25%. The maximum DMO equals the lower of a) or b) multiplied by the contractors’ before-tax share of FTP and Profit Oil. If the contractors’ FTP and Profit Oil are less than the maximum DMO calculated, the shortfall cannot be carried forward to the next year. In any year, if recoverable operating costs exceed the remaining revenue after deducting FTP and Investment Credit, contractors would be relieved from the DMO.

Bonuses

I assume that there is a signature bonus of US$1MM payable in this analysis.

After tax net cash flow

Based on the foregoing, the contractors’ total revenue consists of the cost recovery, investment credit, the contractors’ share of FTP and profit petroleum. The contractors’ total outgoing includes the bonuses, income tax and the contractors’ share of capital and operating costs. Therefore, the contractors’ after tax net cash flow is calculated by deducting the contractors’ total outgoing from their total revenue.

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Appendix E – Provisions Concerning the Payment of Royalties for the Exploitation of Offshore Petroleum Resources in China

PROVISIONS CONCERNING THE PAYMENT OF ROYALTIES FOR THE EXPLOITATION OF OFFSHORE PETROLEUM RESOURCES

(Approved by the State Council on December 5, 1988, promulgated by Decree No. 1 of the Minister of Finance on 1 January, 1989)

Important Notice

This English document is coming from the LAWS AND REGULATIONS OF THE PEOPLE'S REPUBLIC OF CHINA GOVERNING FOREIGN-RELATED MATTERS (July 1991) which is compiled by the Bureau of Legislative Affairs of the State Council of the People's Republic of China, and is published by the China Legal System Publishing House. In case of discrepancy, the original version in Chinese shall prevail.

Whole Document

Article 1

These Provisions are formulated in accordance with the Regulations of the People's Republic of China on the Exploitation of Offshore Petroleum Resources in cooperation with Foreign Enterprises, in order to promote the development of national economy, to expand international economic and technological cooperation, and to encourage the exploitation of China's offshore petroleum resources.

Article 2

All Chinese and foreign enterprises, which are engaged in the exploitation of offshore petroleum resources pursuant to the law in the inland sea, territorial sea and continental shelf of the People's Republic of China and in any other sea areas under

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page E.2 the jurisdiction of the People's Republic of China, shall pay royalties in accordance with these Provisions.

Article 3

Royalties shall be computed and imposed on the basis of the gross output of crude oil or natural gas produced every calendar year from each oil or natural gas field. The rates of the royalties are as follows:

1. Crude oil

 the portion of annual gross output of crude oil not exceeding 1 million tons, shall not be subject to the payment of royalties;

 for the portion of annual gross output of crude oil from 1 million to1.5 million tons, the rate shall be 4%;

 for the portion of annual gross output of crude oil from 1.5 million to2 million tons, the rate shall be 6%;

 for the portion of annual gross output of crude oil from 2 million to 3 million tons, the rate shall be 8%;

 for the portion of annual gross output of crude oil from 3 million to 4 million tons, the rate shall be 10%;

 for the portion of annual gross output of crude oil exceeding 4 million tons, the rate shall be 12.5%.

2. Natural gas

 the portion of annual gross output of natural gas not exceeding 2 billion cubic meters, shall not be subject to the payment of royalties;

 for the portion of annual gross output of natural gas from billion to 3.5 billion cubic meters, the rate shall be 1%;

 for the portion of annual gross output of natural gas from 3.5 billion to 5 billion cubic meters, the rate shall be 2%;

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page E.3

 for the portion of annual gross output of natural gas exceeding 5 billion cubic meters, the rate shall be 3%.

Article 4

The royalties for crude oil and natural gas shall be paid in kind.

Article 5

The royalties for crude oil and natural gas shall be levied and administered by the tax authorities.

With respect to the royalties of Chinese-foreign Cooperative oil or gas fields, the operators shall act as agents for withholding the royalties, and shall hand over the royalties withheld to China National Offshore Petroleum Corporation, which, in turn, shall act as an agent for making the payment of the royalties.

Article 6

The royalties shall be computed annually and paid in advance in instalments either based on times or on terms; and the final settlement shall be made after the end of the tax year. The time limits for advance payment and final settlement shall be set by the tax authorities.

Article 7

The oil or gas fields operators shall, within 10 days after the end of each quarter, submit to the tax authorities a report on the output of oil or gas field sand any other related materials required by the tax authorities.

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Article 8

The withholding agents and paying agents with regard to the royalties must, in accordance with the time limits set by the tax authorities, pay the royalties. In case of failure to pay the royalties within the time limits, the tax authorities shall impose a surcharge for over due payment equal to 1% of the overdue royalties for every day in arrears, starting from the first day the payment becomes overdue.

Article 9

In the case that the oil or gas fields operators, in violation of the provisions in Article 7, fail to submit on time to the tax authorities the reports on output of oil or gas field sand other related materials required by the tax authorities, the tax authorities may impose a fine in light of the circumstances up to but not exceeding RMB5,000 in dealing with those who conceal the actual output, the tax authorities, in addition to pursuing the royalties payment, may impose a fine, in light of the circumstances, up to but not exceeding five times of the amount of royalties that shall be made up.

Article 10

The following terms, used in these Provisions, are defined below:

(1) Crude oil: refers to solid and liquid hydrocarbon in the natural state as well as any liquid hydrocarbon extracted from natural gas, except for methane (CH 4) (2) Natural gas: refers to non-associated natural gas and associated natural gas in the natural state.

Non-associated natural gas: refers to all gaseous hydrocarbon extracted from gas deposits, including wet gas, dry gas, and residual gas remaining after the extraction of liquid hydrocarbon from wet gas.

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Associated natural gas: refers to all gaseous hydrocarbon extracted from Oil deposits simultaneously with crude oil, including residual gas remaining after the extraction of liquid hydrocarbon.

(3) Annual gross output of crude oil: refers to the total amount of crude oil produced by each oil or gas field in the same contracted area, in one calendar year, less the quantity of oil used for petroleum operations and that of wasted.

(4) Annual gross output of natural gas: refers to the total amount of natural gas produced by each oil or gas field in the same contracted area, in one calendar year, less the quantity of natural gas used for petroleum operations and that of wasted.

Article 11

These Provisions shall become effective as of January 1, 1989.

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Appendix F – Measures for the Administration of the Collection of Special Petroleum Proceeds

MEASURES FOR THE ADMINISTRATION OF THE COLLECTION OF SPECIAL PETROLEUM PROCEEDS

Article 1

These Measures are formulated in order to promote the reform of the petroleum pricing mechanism, promote the continuous, healthy and balanced development of national economy and regulate the administration of the collection of special petroleum proceeds.

Article 2

The "special petroleum proceeds" mentioned in these Measures shall refer to the proceeds on a certain proportion of the excessive returns obtained from their sales of domestic crude oil when the price thereof exceeds a certain level, which is collected by the State from the petroleum exploitation enterprises.

Article 3

All the enterprises that independently exploit and sell the crude oil within the territorial lands and waters of the People's Republic of China and other enterprises that exploit and sell crude oil in the form of equity or contractual joint venture in the above-mentioned fields (hereinafter referred to as the equity or contractual joint ventures) shall pay special petroleum proceeds according to these Measures.

Article 4

The special petroleum proceeds are non-tax incomes of the state revenue and shall be incorporated into the management of state budgetary revenues.

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Article 5

The Ministry of Finance shall be responsible for the administration of the collection of special petroleum proceeds. The petroleum exploitation enterprises directly under the Central Government shall declare and pay special petroleum proceeds to the Ministry of Finance, and the local petroleum exploitation enterprises shall declare and pay special petroleum proceeds to the financial supervision commissioners' offices dispatched by the Ministry of Finance, and the special petroleum proceeds for the joint and contractual joint venture shall be withheld by the Chinese party.

Article 6

The special petroleum proceeds shall be collected at excessive progressive ad valorem rates for five grades, and be calculated on a monthly basis and paid on a quarterly basis.

Article 7

The ratio for the collection of special petroleum proceeds shall be determined on the basis of the monthly weighted average price of the crude oil sold by the petroleum exploitation enterprises. For the purpose of facilitating the reference to the oil price on international market, the price of crude oil shall be calculated at the ratio of US Dollars per barrel, and the starting point shall be USD 40 per barrel.

The specific ratio of collection and the quick calculation deduction are prescribed in the following form (see the attached form for the formula of calculation):

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Price of Crude Oil (US Quick Calculation Deduction Dollars Per Barrel) Ratio of Collection (US Dollars Per Barrel)   40-45 (included) 20% 0 45-50 (included) 25% 0.25 50-55 (included) 30% 0.75 55-60 (included) 35% 1.5 More than 60 40% 2.5

Article 8

When the special petroleum proceeds are calculated, the ratio between tonnage and barrels of crude oil shall be calculated in light of the ratio between tonnage and barrels of the oil type actually implemented or adopted by a petroleum exploitation enterprise; and the exchange rate between US Dollars and Renminbi shall be averagely calculated on the monthly basis at the middle price published every day in the current month by the People's Bank of China.

Article 9

Where a petroleum exploitation enterprise group has several affiliated petroleum exploitation enterprises, the special petroleum proceeds shall be collected and paid by the petroleum exploitation enterprise group.

Article 10

The petroleum exploitation enterprises that pay special petroleum proceeds shall faithfully fill in the forms for the declaration of special petroleum proceeds (see attached form), and after the collection, all the enterprise groups shall declare and pay the special petroleum proceeds to the organs of public finance within ten working days upon the expiration of each quarter.

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Article 11

The organ of public finance shall carefully examine the forms for the declaration of special petroleum proceeds reported by petroleum exploitation enterprise groups and confirm the amount of special petroleum proceeds that the petroleum exploitation enterprises should pay in written form. A petroleum exploitation enterprise shall turn over them into the central treasury within five working days upon receipt of the written confirmation notification.

Article 12

The "common payment forms" uniformly printed under the supervision of the Ministry of Finance shall be generally used for the payment of special petroleum proceeds. All the items in the payment forms shall be completely and correctly filled in. The "Ministry of Finance" shall be filled in the column of the "organ of public finance", the "level of the Central Government" shall be filled in the column of the "budgetary grade", and the "special petroleum proceeds" of clause 7113 in the category 71 of "other incomes" shall be filled in the column of "budgetary category".

Article 13

In case a petroleum exploitation enterprise fails to pay special petroleum proceeds within the prescribed time limit and in full amount, the organ of public finance shall order it to pay them within the time limit, and impose a late fee at the rate of 0.05% for each day as of the date of delay.

Article 14

No organ of public finance may illegally reduce or exempt the special petroleum proceeds that the petroleum exploitation enterprises should pay.

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Article 15

The special petroleum proceeds shall be incorporated into the costs and expenses of the enterprises, and the enterprise income tax thereof can be deducted before the tax payment.

Article 16

In case a petroleum exploitation enterprise fails to pay special petroleum proceeds according to these Measures, the organ of public finance shall punish it according to the Regulation on the Penalties and Sanctions against Illegal Fiscal Acts.

Article 17

These Measures shall come into force as of March 26, 2006.

Article 18

The power to interpret these Measures shall remain with the Ministry of Finance. Attached Form: Form for the Declaration of Special Petroleum Proceeds (omitted)

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Appendix G – Enterprise Income Tax Law of the People's Republic of China

ENTERPRISE INCOME TAX LAW OF THE PEOPLE'S REPUBLIC OF CHINA

(Adopted at the 5th Session of the 10th National People's Congress of the People's Republic of China on March 16, 2007)

Contents Chapter I General Rules Chapter II Taxable Income Amount Chapter III Payable Tax Amount Chapter IV Preferential Tax Treatments Chapter V Withholding by Sources Chapter VI Special Adjustments to Tax Payments Chapter VII Administration of Tax Levy Chapter VIII Supplementary Rules

Chapter I General Rules

Article 1

The enterprises and other organizations which have incomes (hereinafter referred to as the enterprises) within the territory of the People's Republic of China shall be payers of the enterprise income tax and shall pay their enterprise income taxes according to the present Law.

The sole individual proprietorship enterprises and partnership enterprises are not governed by the present law.

Article 2

Enterprises are classified into resident and non-resident enterprises.

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The term "resident enterprise" as mentioned in the present Law means an enterprise which is set up under Chinese law within the territory of China, or set up under the law of a foreign country (region) but whose actual management organ is within the territory of China.

The term "non-resident enterprise" as mentioned in the present Law means an enterprise which is set up under the law of a foreign country (region) and whose actual management organ is not within the territory of China but who has organs or establishments within the territory of China, or who does not have any organ or establishment within the territory of China but who has incomes sourced in China.

Article 3

For its incomes sourced from both inside and outside the territory of China, a resident enterprise shall pay the enterprise income tax.

In case a non-resident enterprise sets up an organ or establishment within the territory of China, it shall pay enterprise income tax on its incomes sourced inside the territory of China and incomes sourced outside the territory of China but actually connected with the said organ or establishment.

In case a non-resident enterprise has no organ or establishment within the territory of China, or its incomes have no actual connection to its organ or establishment inside the territory of China, it shall pay enterprise income tax on the incomes sourced inside the territory of China.

Article 4

The enterprise income tax shall be levied at the rate of 25%. In case a non-resident enterprise obtains incomes as mentioned in Paragraph 3, Article 3 of the present Law, the tax rate shall be 20%.

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Chapter II Taxable Income Amount

Article 5

The balance after the tax-free and tax-exempt incomes, each deduction item as well as the permitted remedies for losses of the previous year(s) being deducted from an enterprise's total income amount of each tax year shall be the taxable income amount.

Article 6

An enterprise's total income amount refers to the monetary and non-monetary incomes from various sources and includes: (1) income from selling goods; (2) income from providing labor services; (3) income from transferring property; (4) equity investment gains, such as dividend, bonus; (5) interest incomes; (6) rental income; (7) royalty income; (8) income from accepting donations; and (9) other incomes.

Article 7

The tax-free income refers to the following incomes which are included in the total income amount: (1) The treasury appropriations; (2) The administrative fees and the governmental funds which are levied in accordance with the law and fall under the treasury administration; and (3) Other tax-free incomes as prescribed by the State Council.

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Article 8

When calculating the taxable income amount, the reasonable expenditures which actually happened and have actual connection with the business operations of an enterprise, including the costs, expenditures, taxes, losses, etc. may be deducted.

Article 9

As regards an enterprise's expenditures for public welfare donations, the portion within 12% of the total annual profits is permitted to be deducted.

Article 10

When calculating the taxable income amount, none of the following expenditures may be deducted: (1) Such equity investment gains as dividend, bonus paid to the investors; (2) Payment for enterprise income tax; (3) Late fee for taxes; (4) Pecuniary punishment, fines, and losses of confiscated properties; (5) Expenditures for donations other than those prescribed in Article 9; (6) Sponsorship expenditures; (7) Unverified reserve expenditures; (8) Other expenditures in no relation to the obtainment of revenues;

Article 11

An enterprise's depreciations of fixed assets, which are calculated pursuant to the related provisions, are permitted to be deducted in the calculation of the taxable income amount.

As regards any of the following fixed assets, no depreciation may be calculated for deduction:

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(1) The fixed assets which have not yet been put into use, among which houses and buildings are not included; (2) The fixed assets which are rented in through commercial lease; (3) The fixed assets which are rented out through finance leasing; (4) The fixed assets for which depreciation has been fully allocated but which are still in use; (5) The fixed assets in no relation to the business operations; (6) The land which is separately evaluated and entered into account as an item of fixed asset; and (7) Other fixed assets for which no depreciation may be calculated for deduction.

Article 12

An enterprise is allowed to deduct the amortized expenditures of intangible assets calculated under the related provisions when calculating the taxable amount of incomes.

For the following intangible assets, no amortized expense may be calculated: (1) The intangible assets, which are developed by the enterprise itself and the expenditures have been deducted when calculating the taxable income amount; (2) The self-created business reputation; (3) The intangible assets in no relation to the business operations; and (4) Other intangible assets for which no amortized expense may be calculated for deduction.

Article 13

The following expenditures incurred by an enterprise shall be deemed as long-term deferred expenditures when calculating the taxable income amount. Those amortized pursuant to the related provisions are permitted to be deducted: (1) The expenditures for rebuilding a fixed asset, for which depreciation has been fully allocated; (2) The expenditures for rebuilding a rented fixed asset;

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(3) The expenditures for heavily repairing a fixed asset; and (4) Other expenditures which shall be deemed as long-term deferred expenditures.

Article 14

When calculating the taxable income amount, an enterprise may not deduct the costs of the investment assets during the period of external investment.

Article 15

In case an enterprise uses or sells its inventories, it is permitted to deduct the costs of the inventories calculated pursuant to the related provisions when calculating the taxable income amount.

Article 16

In case an enterprise transfers an asset, it is permitted to deduct the net value of the asset when calculating the taxable income amount.

Article 17 An enterprise may not offset the losses of its overseas business organs against the profits of its domestic business organs in the consolidated calculation of its enterprise income taxes.

Article 18

The losses suffered by an enterprise during a tax year may be carried forward and made up by the incomes during subsequent years, however, the carry-forward period may not exceed 5 years.

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Article 19

In case a non-resident enterprise obtains incomes as prescribed in Paragraph 3, Article 3 of the present Law, the following approaches shall be adopted in calculation of its the taxable income amount: (1) As regards dividends, bonuses and other equity investment gains, interests, rentals and royalties, the taxable income amount shall be the total income amount; (2) As regards incomes from assigning property, the taxable income amount shall be the balance of the total income amount less the net value of the property; and (3) As regards other incomes, the taxable income amount shall be calculated according to the approaches as mentioned in the preceding two items by analogy.

Article 20

The specific scope and standards of revenues and deductions, as well as the concrete tax treatment methods of assets as prescribed in this Chapter shall be constituted by the treasury and tax administrative departments under the State Council.

Article 21

If the enterprise's financial or accounting treatment method does not comply with any tax law or administrative regulation when calculating the taxable income amount, the tax law or administrative regulation shall prevail.

Chapter III Payable Tax Amount

Article 22

The payable tax amount shall be the balance of the taxable amount multiplied by the applicable tax rate minus the tax amounts deducted and exempted as prescribed in the present Law.

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Article 23

In case an enterprise has already paid overseas the enterprise tax for the following incomes, it may deduct it from the payable tax amount of the current period. The limit of tax credit shall be the payable tax amount on such incomes calculated under the present Law. The part exceeding the limit of tax credit may, during the five subsequent years, be offset from the balance of the limit of tax credit of each year minus the tax amount which ought to be offset in the current year: (1) A resident enterprise's taxable incomes sourced from outside the territory of China; and (2) Taxable incomes obtained outside the territory of China by a non-resident enterprise having organs or establishments inside the territory of China, but having actual connection with such organs or establishments.

Article 24

As regards the dividends, bonuses and other equity investment gains earned outside the territory of China by a resident enterprise from a foreign enterprise which it controls directly or indirectly, the portion of income tax on this income paid outside the territory of China by the foreign enterprise the territory of China may be treated as the allowable tax credit of the resident enterprise's overseas income tax amount and be deducted within the limit of tax credit as provided for in Article 23 of the present Law.

Chapter IV Preferential Tax Treatments

Article 25

The important industries and projects whose development is supported and encouraged by the state shall enjoy the preferential treatments in enterprise income tax.

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Article 26

An enterprise's following incomes of shall be tax-free ones: (1) The interest incomes from treasury bonds; (2) Dividends, bonuses and other equity investment gains generated between qualified resident enterprises; (3) Dividends, bonuses and other equity investment gains which are obtained from a resident enterprise by a non-resident enterprise with organs or establishments inside the territory of China and have actual connection with such organs or establishments; and (4) Incomes of qualified not-for-profit organizations.

Article 27

As regards the following incomes, the enterprise income tax may be exempted or reduced: (1) The incomes generated from the engagement in agriculture, forestry, husbandry and fishery; (2) The incomes generated from investment in and business operations of the important public infrastructure projects supported by the state; (3) The income generated from the projects of environmental protection, energy and water saving and satisfying the related requirements; (4) The incomes generated from transferring technologies and satisfying the related requirements; and (5) The income as provided for in Paragraph 3, Article 3 of the present Law.

Article 28

As regards a small meagre-profit enterprise satisfying the prescribed conditions, the enterprise income tax shall be levied at a reduced tax rate of 20%.

As regards important high-tech enterprises necessary to be supported by the state, the enterprise income tax shall be levied at the reduced tax rate of 15%.

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Article 29

The autonomous organ of an autonomous region of ethnic minorities may determine to reduce or exempt the enterprise income tax by enterprises within the said autonomous region. In case the decision on deduction or exemption is made by an autonomous prefecture or county, it shall be reported to the people's government of the province, autonomous region, or municipality directly under the Central Government for approval.

Article 30

An enterprise may additionally calculate and deduct the following expenditures in the calculation of the taxable income amount: (1) The expenditures for researching and developing new technologies, new products and new techniques; and (2) The wages paid to the disabled employees or other employees encouraged to hire by the State.

Article 31

In case a startup investment enterprise engages in important startup investments necessary to be supported and encouraged by the state, it may deduct a certain proportion of the investment amount from the taxable income amount.

Article 32

In case an enterprise surely needs to accelerate the depreciation of any fixed asset by virtue of technological progress or for any other reason, it may curtail the term of depreciation or adopt a method for accelerated depreciation.

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Article 33

As regards the incomes earned by an enterprise from producing products complying with the industrial policies of the state by comprehensively utilizing resources, the income may be downsized in the calculation of the amount of taxable incomes.

Article 34

As regards the amount of an enterprise's investment in purchasing special equipment for protecting environment, saving energy and water, work safety, etc., the tax amount may be deducted at a certain rate.

Article 35

The specific measures for the preferential tax treatments as referred to in the present Law shall be constituted by the State Council.

Article 36

The State Council may constitute special preferential policies on the enterprise income tax in case the national economic and social development so requires, or the business operations of enterprises have been seriously affected by emergencies and other factors, and submit them to the Standing Committee of the National People's Congress for archival filling.

Chapter V Withholding by Sources

Article 37

The payable income taxes on the incomes obtained by a non-resident enterprise as prescribed in Paragraph 3, Article 3 of the present Law shall be withheld by sources, with the payer acting as the obligatory withholder, who shall withhold the tax amount from each payment or payment due.

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Article 38

As regards the payable income taxes on the incomes obtained by a non-resident enterprise within the territory of China from undertaking engineering projects or providing labor services, the payer of the project price or remuneration may be designated as the obligatory withholder by the tax organ.

Article 39

In case the obligatory withholder has failed to withhold the income tax which ought to be withheld according to Articles 37 and 38 of the present Law or is unable to perform the withholding obligation, the taxpayer shall pay them at the place where the income has occurred. In case the taxpayer fails to do so, the tax organ may recover the payable tax of the enterprise from its other income items within the territory of China which ought to be paid by the payer.

Article 40

An obligatory withholder shall, within 7 days after the date of withholding, turn over to the state treasury the tax payments which it withholds every time and submits a form of report on the withheld enterprise income taxes to the local tax organ.

Chapter VI Special Adjustments to Tax Payments

Article 41

As regards a transaction between an enterprise and its affiliated parties, in case the taxable revenue or income of the enterprise or its affiliated parties reduces by virtue of the failure to conform to the arms length principle, the tax organ may, through a reasonable method, make an adjustment.

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As regards the costs of an enterprise and its affiliated parties for jointly developing or accepting intangible assets, or jointly providing or accepting labor services, they shall, when calculating the taxable income amount, apportion them according to the arms length principle.

Article 42

An enterprise may propose the pricing principles and calculation methods for the transactions between it and its affiliated parties to the tax organ, the tax organ and the enterprise shall, upon negotiations and confirmation, achieve an advance pricing arrangement.

Article 43

When an enterprise submits its annual enterprise income tax returns to the tax organ, an annual report on the affiliated transactions between it and its affiliated parties shall be attached.

When the tax organ investigates into the affiliated transactions, the enterprise and its affiliated parties, as well as other enterprises in relation to the affiliated transactions under investigation, shall, according to the related provisions, provide the related materials.

Article 44

In case any enterprise refuses to submit the materials on transactions which happened between it and its affiliated parties, or provides any false or incomplete material, on the basis of which the true information about the affiliated transactions cannot be reflected, the tax organ may determine upon check its taxable income amount.

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Article 45

As regards an enterprise which is set up in a country (region) where the actual tax burden is apparently lower than the tax rate as prescribed in Paragraph 1 of Article 4 of the present Law by a resident enterprise or controlled by an resident enterprise or by a Chinese resident, in case it fails to distribute the profits or decreases the distribution not by virtue of reasonable business operations, the portion of the aforesaid profits attributable to this resident enterprise shall be included in its incomes of the current period.

Article 46

As regards an enterprise's interest expenditures for any credit investments and equity investments accepted from its affiliated parties, in excess of the prescribed criterion, the enterprise may not deduct them when calculating the taxable income amount.

Article 47

In case an enterprise makes any other arrangement not for any reasonable commercial purpose, which causes the decrease of its taxable revenue or income, the tax organ may, through a reasonable method, make an adjustment.

Article 48

In case the tax organ makes an adjustment to a tax payment pursuant to the provisions in this Chapter so that it is necessary to recover the tax payment in arrears, it shall do so and charge an additional interest according to the provisions of the State Council.

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Chapter VII Administration of Tax Levy

Article 49

The administration for levying enterprise income taxes shall be subject to the Law of the People's Republic of China on Administering Tax Levy in addition to the present Law.

Article 50

The tax payment place of a resident enterprise shall be its registration place unless it is otherwise provided for in any tax law or administrative regulation. But in case its registration place is outside the territory of China, the tax payment place shall be the place at the locality of its actual management organ.

As regards a resident enterprise which has set up operational organs without legal person status inside the territory of China, it shall, on a consolidated basis, calculate and pay its enterprise income taxes.

Article 51

In case a non-resident enterprise earns any income as prescribed in Paragraph 2, Article 3 of the present Law, the tax payment place shall be the place at the locality of the organ or establishment. In case a non-resident enterprise has set up two or more organs or establishments within the territory of China, it may choose to have its main organ or establishment make a consolidated payment of the enterprise income tax upon the examination and approval of the tax organ.

As regards a non-resident enterprise which earns any income as prescribed in Paragraph 3, Article 3 of the present Law, the place at the locality of the obligatory withholder shall be the tax payment place.

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Article 52

Enterprises may not pay their enterprise income taxes on a consolidated basis unless it is otherwise prescribed by the State Council.

Article 53

Enterprise income taxes shall be calculated on the basis of a tax year, which is from January 1 to December 31 of the Gregorian calendar year. In case an enterprise's business operations are started or terminated in the middle of a tax year, which leads to its actual business operation period in this tax year being shorter than 12 months, its actual business operation period shall constitute a tax year.

When an enterprise is under liquidation according to law, the liquidation period shall be a tax year.

Article 54

Enterprise income taxes shall, on the monthly or quarterly basis, be paid in advance. An enterprise shall submit an enterprise income tax return for advance payment to the tax organ and pay the tax in advance within 15 days after the end of a month or quarter. An enterprise shall submit an annual enterprise income tax return for the settlement of tax payments to the tax organ and settle the payable or refundable amount of taxes within 5 months after the end of each year. When an enterprise submits an enterprise income tax return, the financial statements and other related materials shall be attached in accordance with the related provisions.

Article 55

In case an enterprise terminates its business operation in the middle of a year, it shall apply to the tax organ for calculating and paying the enterprise income taxes of the current period within 60 days after the actual date for terminating its business operations. Before the deregistration formalities are handled, an enterprise shall

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page G.17 make a declaration to the tax organ and pay the enterprise income taxes on the basis of the income of the liquidation.

Article 56

Enterprise income taxes to be paid pursuant to the present law shall be calculated on the basis of RMB. In case any income is calculated on the basis of a currency other than RMB, the taxes shall, after such income converted into RMB, be calculated and paid.

Chapter VIII Supplementary Rules

Article 57

In case an enterprise has already been set up before the promulgation of the present Law and enjoys low tax rates in accordance with the provisions of the tax laws and administrative regulations in force at that time, it may, in accordance with the provisions of the State Council, continue to enjoy the preferential treatments within five years as of the promulgation of the present Law and gradually transfer to the tax rate as prescribed in the present Law. In case an enterprise enjoys the preferential treatment of tax exemption for a fixed term, it may, after the promulgation of this Law, continue to enjoy such treatment in accordance with the provisions of the State Council until the fixed term expires. However, if an enterprise has failed to enjoy the preferential treatment by virtue of failure to make profits, the term of preferential treatment may be counted as of the year when the present Law is promulgated.

As regards high-tech enterprises which are newly established with the key support of the State within the particular areas set up by law for developing foreign economic cooperation and technological exchanges or the areas enjoying the abovementioned special policies as provided for by the State Council, they may enjoy transitional preferential tax treatments. The specific measures thereof shall be constituted by the State Council. As regards other enterprises falling within the encouraged category

Wanwan Hou January 2009 The economics of petroleum exploration and development in China Page G.18 as already determined by the State Council, they may, according to the provisions of the State Council, enjoy the preferential treatment of tax reduction or exemption.

Article 58

In case any provision in a tax treaty concluded between the government of the People's Republic of China and a foreign government is different from the provisions in the present Law, the provision in the said treaty shall prevail.

Article 59

The State Council shall constitute a regulation for implementing the present Law.

Article 60

The present law shall go into effect as of January 1, 2008. The Income Tax Law of the People's Republic of China Concerning Foreign-funded Enterprises and Foreign Enterprises as adopted on April 9, 1991 at the 4th Session of the Standing Committee of the 7th National People's Congress and the Interim Regulation of the People's Republic of China Concerning Enterprise Income Tax as promulgated on December 13, 1993 by the State Council shall be concurrently abolished.

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References

Chapter 2 Summary and Conclusions

1. World Bank. (2002). Country Reform Summaries: China. Available from: http://www1.worldbank.org/publicsector/civilservice/rsChina.pdf (Accessed at 5 January 2009), p 3. 2. Food and Agriculture Organization of the United Nations. (1999). China. Available from: http://www.fao.org/nr/water/aquastat/countries/china/index.stm (Accessed at 5 January 2009). 3. United Nations. (2006). People's Republic of China: Public Administration Country Profile. Available from: http://unpan1.un.org/intradoc/groups/public/documents/UN/UNPAN023305.pdf (Accessed at 5 January 2009), p 2.

Chapter 3 Methodology

1. Oil execs tip price to drop, investment to increase. (May 2008). SPE News, page 18. 2. World Crude Oil Prices. (6 August 2008). Energy Information Administration. Available from: http://tonto.eia.doe.gov/dnav/pet/pet_pri_wco_k_w.htm (Accessed 25 August 2008).

Chapter 4 Geography

1. National Bureau of Statistics of China. (2007). China Statistical Yearbook 2007. Available from http://www.stats.gov.cn/tjsj/ndsj/2007/indexeh.htm (Accessed 25 August 2008). 2. China’s Geography. (2008). E Study Chinese. Available from: http://www.estudychinese.com/web/aboutchina/geography/news01.htm (Accessed 14 December 2008). 3. Xue, F. (Editor). (2007). Annual Synopsis 2006: GEPS Reports. Sydney: IHS.

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4. The Geography of China. (2000). Asian Info. Available from: http://www.asianinfo.org/asianinfo/china/geography.htm (Accessed 14 December 2008). 5. Wang, Q. M., Nishidai, T. & Coward, M. P. (1992). The Tarim Basin, NW China: Formation and aspects of petroleum geology. Journal of petroleum geology, 15(1):5. 6. Plants and animals. (2006). Chinese Government’s Official Web Portal. Available from: http://english.gov.cn/2006-02/08/content_182521.htm (Accessed 14 December 2008). 7. Population Reference Bureau. (2007). China Statistics. Available from: http://www.prb.org/Countries/China.aspx (Accessed 14 December 2008).

Chapter 5 Infrastructure

1. China Economy. (2008). Economy Watch. Available from: http://www.economywatch.com/world_economy/china/ (Accessed 25 August 2008). 2. National Bureau of Statistics of China. (2007). China Statistical Yearbook 2007. Available from http://www.stats.gov.cn/tjsj/ndsj/2007/indexeh.htm (Accessed 25 August 2008). 3. NBS: China accounts for 6% of world’s GDP in 2007. (27 October 2008). China Daily. Available from: http://www.chinadaily.com.cn/china/2008- 10/27/content_7145044.htm (Accessed 14 December 2008). 4. National Bureau of Statistics of China. (2008). Consumer Price Index (CPI) Kept Growth in November. Available from: http://www.stats.gov.cn/english/newsandcomingevents/t20071211_402451256.h tm (Accessed 25 August 2008). 5. Xin, D. (07 January 2008). National highway target set for year. Available from: http://www.china.org.cn/china/national/2008-01/07/content_1238273.htm (Accessed 25 August 2008). 6. Xinhua. (23 November 2006). China to have 85,000 km of expressway in 30 years. Available from: http://www.chinadaily.com.cn/bizchina/2006- 11/23/content_741287.htm (Accessed 14 December 2008).

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7. China to add and upgrade 270,000 km of rural highway. (07 January 2008). China Daily. Available from: http://www.chinadaily.com.cn/china/2008- 01/07/content_6373720.htm (Accessed 25 August 2008). 8. Lau, N. (1 February 2008). Railways best serve our transport needs. Available from: http://chinadaily.com.cn/opinion/2008-02/01/content_6435761.htm (Accessed 14 December 2008). 9. Song, R. (29 September 2006). Qinghai-Tibet Railway Brings Train Travels to "Roof of the World". Available from: http://www.chinese- embassy.org.uk/eng/zt/zgxz/t274455.htm (Accessed 25 August 2008). 10. Library of Congress of the United States of America. (August 2006). Country Profile: China, page 24. Available from http://lcweb2.loc.gov/frd/cs/profiles/China.pdf (Accessed 14 December 2008). 11. Civil Aviation Administration of China. (25 January 2008). Plan for Layout of Chinese Civil Airports. Available from: http://www.caac.gov.cn/A1/200801/t20080125_11050.html (Accessed 14 December 2008). 12. List of railways in China. (2005). Wikipedia. Available from: http://en.wikipedia.org/wiki/List_of_railways_in_China (Accessed 25 August 2008). 13. China MapXL. (2007). China Airports. Available from: www.chinamapxl.com/images/china-airport-map.gif (Accessed 25 August 2008). 14. Ministry of Transport of People’s Republic of China. (2006). China National Coastal Ports Arrangement Planning. Available from: http://www.moc.gov.cn/zhuzhan/zaixianfangtan/yanhaigangkou_BJGHJD/index. html (Assessed 14 December 2008). 15. Editorial Committee of the China Energy Yearbook. (November 2005). China Energy Yearbook 2004. Beijing: China Petrochemical Press. 16. Watts, C. (2003). China’s telecom market: an overview. China Business. 17. CNPC. (2007). Organization. Available from: http://www.cnpc.com.cn/eng/company/presentation/organization (Accessed 25 August 2008).

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18. Sinopec. (2007). Subsidiaries. Available from: http://www.sinopec.com.cn/about_sinopec/subsidiaries (Accessed 25 August 2008). 19. CNOOC. (2007). Group Organisation. Available from: http://www.cnooc.com.cn/zhyww/gsjj/zzjg/default.shtml (Accessed 25 August 2008). 20. Sinopec Consultant Company. (September 2007). China Petroleum and Petrochemical Industry Economics Research Annual Report. 21. National Development and Reform Commission. (December 2005). Medium and long-term development plan for refinery industry. 22. Fu, G. (8 May 2008). CNPC will increase refining capacity to 40% of the country’s total by 2010. Available from: http://energy.people.com.cn/GB/71895/7214364.html (Accessed 25 August 2008). 23. China.cn. (6 September 2007). China plans huge build-up in oil refineries. Available from: http://en.china.cn/content/d81652,c417bf,1423_4014.html (Accessed 25 August 2008). 24. List of oil refineries. (2008) Wikipedia. Available from: http://en.wikipedia.org/wiki/List_of_oil_refineries#China (Accessed 14 December 2008). 25. Watkins, E. (8 October 2007). NBS: China’s pipeline network increases length, capacity. Oil & Gas Journal, 105(38). 26. CNPC. (2008). Natural gas and pipelines. Available From: http://www.cnpc.com.cn/CNPC/ywycp/trqygd/default.htm (Accessed 25 August 2008). 27. CPGP. (2006). Summary of major onshore oil and gas pipeline in China. Available from: http://news.upc.edu.cn/syzg/sykp/sycy/20061117/030813.shtml (Accessed 14 December 2008). 28. Longest product oil pipeline project. (June 2001). International Pipeline News. Pipeline Report, page 4. 29. CPGP. (2008). The construction history of Chinese long distance pipelines. Available from: http://www.oilpipeline.com.cn (Accessed 25 August 2008).

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30. Xinhua. (22 February 2008). China starts work on $20B pipeline for Turkmen gas. Available from: http://www.downstreamtoday.com/News/Articles/200802/China_Starts_Work_o n_B_Pipeline_for_T_8868.aspx?AspxAutoDetectCookieSupport=1 (Accessed 25 August 2008). 31. Xu, Y. (20 July 2007). Sinopec pipes up for Daniudi gas. Upstream, page 21. 32. Sinopec selects pipeline compression technology. (10 March 2008). Oil & Gas Journal, 106:10. 33. Chen, F. (12 July 2006). Kazakhstan-China oil pipeline opens to operation. Available from: http://news3.xinhuanet.com/english/2006- 07/12/content_4819484.htm (Accessed 25 August 2008). 34. Turkmen break ground on China pipe. (30 August 2007). Upstream Online. Available from: http://www.upstreamonline.com/live/article139613.ece (Accessed 25 August 2008). 35. China National Petroleum subsidiaries to pay billions for Central Asia gas pipeline. (30 December 2007). The China Post. Available from: http://www.chinapost.com.tw/china/business/2007/12/30/137003/China- National.htm (Accessed 25 August 2008).

Chapter 6 Energy Market in China

1. National Bureau of Statistics of China. (2007). China Statistical Yearbook 2007. Available from http://www.stats.gov.cn/tjsj/ndsj/2007/indexeh.htm (Accessed 25 August 2008). 2. Zhang, G. (25 December 2003). Economic Half an Hour. (Television broadcast). Beijing: CCTV. 3. Wang, B. (2007). An imbalanced development of coal and electricity industries in China. Energy Policy, 35:4959:4968. 4. The Transition of Chinese Energy Regulatory bodies. (18 January 2008). Available from: http://pk75329.bokee.com/viewdiary.23458660.html. (Accessed 14 December 2008). 5. Totten, G. E. (2004). A timeline of highlights from the histories of ASTM Committee DO2 and the petroleum industry. Available from:

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http://www.astm.org/COMMIT/D02/to1899_index.html (Accessed 25 August 2008). 6. Kambara, T. (1974). The Petroleum Industry in China. The China Quarterly. 60:699:719. 7. Sinopec Consultant Company. (2006). China Petroleum and Petrochemical Industry Economics Research Annual Report. 8. BP. (June 2007). BP Statistical Review of World Energy June 2007. Available from: www.bp.com/statisticalreview (Accessed on 25 August 2008). 9. Li, D. & Du, Y. (2004). The history and future of China oil and gas. Paper SPE 89776. Conference proceedings of the SPE Annual Technical Conference and Exhibition held in Houston. Conducted by SPE. Richardson: SPE. 10. Zhang, S. & Hu, J. (1995). Present situation and development tendency of China’s petroleum market. Paper SPE 29901. Conference proceedings of the International Meeting on Petroleum Engineering held in Beijing. Conducted by SPE. Richardson: SPE. 11. National Bureau of Statistics & National Development and Reform Commission. (2005). China Energy Statistical Yearbook. Beijing: China Statistics Press. 12. The present pricing system for crude oil and petroleum product in China. (7 June 2001). Oilnews. Available from: http://www.oilnews.com.cn/gb/guonei/2001- 06/07/content_5133.htm (Accessed 14 December 2008). 13. World Crude Oil Prices. (6 August 2008). Energy Information Administration. Available from: http://tonto.eia.doe.gov/dnav/pet/pet_pri_wco_k_w.htm (Accessed 25 August 2008). 14. Sinopec. (2007). The analysis and forecast of the petroleum product market in China in 2007. Available from: http://www.tjec.gov.cn/ContentView.aspx?ContentID=4742 (Accessed on 25 August 2008). 15. Yang, Y & Hong, T. (2007). The analysis and forecast of the development of petroleum products in China, 2007. Available from: http://www.chinabgao.com/freereports/17506.html (Accessed 25 August 2008). 16. The problem with the Chinese oil pricing mechanism. (24 May 2007). China.org.cn, Available from:

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http://www.china.com.cn/economic/zhuanti/2007nyfz/2007- 05/24/content_8302553.htm (Accessed 14 December 2008). 17. Cornelius, P. & Story, J. (2007). China and global energy markets. Orbis, 4:5:20. 18. Ma, S. & Ma, X. (2000). The Price Mechanism of Natural Gas and Its Relative Environment Condition. Paper SPE 64780. Conference proceedings of the SPE International Oil and Gas Conference and Exhibition held in Beijing. Conducted by SPE. Richardson: SPE. 19. Xu, Y. (14 January 2008). China output on the rise. Upstreamonline. Available from: http://www.upstreamonline.com/live/article147052.ece (Accessed 25 August 2008). 20. CNPC and Gazprom agree on gas price. (19 Nov 2007). Upstreamonline. Available from: http://www.upstreamonline.com/live/article144457.ece (Accessed 25 August 2008). 21. China ‘agrees price for Turkmen gas’. (22 Jan 2008). Upstreamonline. Available from: http://www.upstreamonline.com/live/article147449.ece (Accessed 25 August 2008). 22. Joint venture to bring gas to southern China. (1 June 2007). Upstream, page 13. 23. PetroChina LNG Purchase Agreements in Australia. (17 September 2007). Available from: http://pgeps.ihsenergy.com/. (Accessed 25 August 2008). 24. Sinopec puts Qingdao LNG on back burner. (12 November 2007). Upstreamonline. Available from: http://www.upstreamonline.com/live/article144028.ece (Accessed 14 December 2008). 25. Xu, Y. (4 May 2007). China looks for leverage on LNG. Upstream, page 23. 26. First of 10 CBM pipelines to be constructed. (05 November 2007). IHS energy. Available from: http://iol.ihsenergy.com/. (Accessed 14 December 2008). 27. Xu, Y. (1 June 2007). PetroChina eyes coalbed methane. Upstream. 28. China – CBM Pipeline Project – Await Approval. (31 October 2007). IHS energy. Available from: http://pgeps.ihsenergy.com/. (Accessed 14 December 2008). 29. Chakhmakhchev, A. (2007). Worldwide Coalbed Methane Overview. Paper SPE106850. Conference proceedings of the 2007 SPE Hydrocarbon Economics and Evaluation Symposium held in Dallas. Conducted by SPE. Richardson: SPE. 30. The National Development and Reform Commission's press conference on the reform of the pricing mechanisms for natural gas. (16 January 2006).

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China.com.cn, Available from: http://www.china.com.cn/chinese/PI- c/1095134.htm (Accessed 14 December 2008). 31. Finance Bureau of Zhoukou. (23 November 2007). National Development and Reform Commission increases the natural gas prices. Available from: http://www.zkcz.gov.cn/news/news_view.asp?newsid=3737 (Accessed 14 December 2008). 32. China coal resources. (2008). Available from: http://www.ChinaCoal.org.cn (Accessed 25 August 2008). 33. Editorial Committee of the China Energy Yearbook. (November 2005). China Energy Yearbook 2004. Beijing: China Petrochemical Press. 34. Almanac of China’s economy. (1980). Beijing: China Economy Almanac Publishing House. 35. Almanac of China’s economy. (2000). Beijing: China Economy Almanac Publishing House. 36. Huang, Y. (2006). Safety production and sustainable development of coal industry will influence national economy and energy safety. Paper presented at the 9th Peak Forum of China Energy Strategy: Shanghai. Available from: http://chnes.chitec.cn/hitech/showDoc_ff8080810ba1dca4010bbcc28ae14ca.htm l (Accessed 25 August 2008). 37. National Bureau of Statistics of China. (2006). China Statistical Yearbook 2006. Available from http://www.stats.gov.cn/tjsj/ndsj/2006/indexeh.htm. (Accessed 25 August 2008). 38. Callick, R. (2007). All the Coal in China. The American. Available at http://american.com/archive/2007/may-june-magazine-contents/all-the-coal- in-china/ (Accessed 14 December 2009). 39. Liu, W. (2006). The electricity supply in China: wandered between shortage and redundancy. Available from: http://news.xinhuanet.com/fortune/2006- 08/28/content_5016506.htm (Accessed 25 August 2008). 40. An, N. (2008). China’s electricity power generation capacity has increased to a new height. Available from: http://www.worldenergy.com.cn/StatisticsData/2008/0424/content_36193.htm (Accessed 25 August 2008).

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41. Qiu, S. (2007). The ranking of the installed capacity of thermal power plants in China, 2005. Available from: http://ranking.worldenergy.com.cn/2007/0711/content_17978.htm (Accessed 25 August 2008).

Chapter 7 Fiscal Regime

1. China National Offshore Oil Corporation. (1992). Offshore Model Production Sharing Contract for the fourth round of bidding. 2. Measures for the Administration of the Collection of Special Petroleum Proceeds 2006 (PRC). 3. Provisions Concerning the Payment of Royalties for the Exploitation of Offshore Petroleum Resources 1988 (PRC). 4. Enterprise Income Tax Law of the People's Republic of China 2007 (PRC).

Chapter 9 The Comparison of the Fiscal Terms in the Asia Pacific Region

1. Petroleum Resource Rent Tax Assessment Act 1987 (Cth). 2. Machmud, K.L. (2000). The Indonesian Production Sharing Contract: An Investor’s Perspective. London: Kluwer Law International. 3. Rahman, M. (2006). Production Sharing Contract. Banglapedia. Available from: http://www.banglapedia.org/HT/P_0290.HTM (Accessed 25 August 2008). 4. Vietnam Model Petroleum Production Sharing Contract. Available from: http://www.petrovietnam.com.vn (Accessed 25 August 2008). 5. Philippines Model Petroleum Service Contract 2006. Available from: http://www.doe.gov.ph (Accessed 25 August 2008). 6. Poonsombudlert, R. et al. (2008). Thai Petroleum Concessions. Available from: http://www.ctlo.com/tpc.htm (Accessed 25 August 2008). 7. Ministry of Petroleum and Natural Gas of India. (2007). Model Production Sharing Contract. Available from: http://petroleum.nic.in/nelp3.pdf (Accessed 25 August 2008).

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Chapter 10 Economics of Exploration

1. ROC Oil Company. (2006). Report to Shareholders: Activities for the Quarter Ended 30 September 2006. 2. ROC Oil Company. (2006). Report to Shareholders: Activities for the Quarter Ended 31 December 2006. 3. ROC Oil Company. (2007). Report to Shareholders: Activities for the Quarter Ended 31 March 2007. 4. ROC Oil Company. (2007). Report to Shareholders: Activities for the Quarter Ended 30 June 2007. 5. ROC Oil Company. (2007). Report to Shareholders: Activities for the Quarter Ended 30 September 2007. 6. ROC Oil Company. (2007). Report to Shareholders: Activities for the Quarter Ended 31 December 2007.

Wanwan Hou January 2009