The Economics of Shale Gas Development
in China
Yongjian Zhou
A thesis in fulfilment of the requirements for the degree of
Master of Engineering
School of Petroleum Engineering
August 2016 ORIGINALITY STATEMENT
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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 challenging. I thank him for making time for me despite his busy schedules. He gave me great help with my language frequently during these two years. I also thank him for his patient reading
I would like to thank all the people that I met, or I contacted in Sinopec, 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 Song Zhou and Fei Qing 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 am also extremely grateful to my wife Qianwen Liao. She gives me infinite love and understanding.
I thank my friend Tengyuan Zhang and my colleagues Jing Yu, Min Liu, and Yudong Yuan from the School Petroleum Engineering. They have been there for me whenever I doubted my capability to complete this thesis. Without their motivation and blessings, this thesis would not have been a reality.
Abstract
With the recent rapid growth of China’s economy, the demand for energy has grown correspondingly and the trend is expected to continue. In response to this, China is seeking to adjust its energy structure by diversifying its energy supply. As part of this, shale gas development has become an important energy strategy in China in recent years because there are abundant prospective resources of shale gas. However, the related economic and environmental issues associated with shale gas developments are controversial. This thesis discusses shale gas developments in China and the USA. Then it focuses on the economics of shale gas development in China based on an analysis the costs and benefits of shale gas from the perspectives of (a) the Supply Chain companies (those in the upstream, midstream and downstream sectors) (b) the Whole Economy. Specifically, the aims are as set out below. A. To describe and quantify the benefits and costs of an example Chinese shale gas development for the Whole Economy. The benefits and costs include those external to shale gas Supply Chain companies. B. To assess the benefits and costs of an example Chinese shale gas development for the companies operating the shale gas operation. In other words, the boundary of the analysis is the shale gas Supply Chain on its own. The analysis excludes the economic effects of benefits and costs external to the development. C. By comparing the analyses in 1 and two 2, to quantify the incremental economic effects of external benefits and costs. The results show that the Fuling shale gas development has a mean nominal NPV of positive US$583MM as at 2011 from the perspective of the Supply Chain. That is when the economics exclude External Costs and include Fiscal Costs. However, the mean nominal NPV becomes negative US$595MM from the perspective of the Whole Economy. That is when the economics include External Costs and exclude Fiscal Costs. In other words, the economics of the project for the Supply Chain companies are significantly more attractive than the economics for the Whole Economy. The effects of External Costs are decisive factors in the economics of shale gas. For instance, the greenhouse gas emissions by burning shale gas and the existing central subsidies are significant External Costs.
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The Economics of Shale Gas development in China
Content
Acknowledgements
Abstract
Chapter 1 Introduction ...... 1.1
1.1 Background ...... 1.1
1.2 Aims and Scope ...... 1.2
1.3 Methodology ...... 1.4
1.3.1 Cash Flow Forecasts ...... 1.4
1.3.2 Net Present Value (NPV) ...... 1.5
1.3.3 Probability Analyses ...... 1.7
1.3.4 Monte Carlo Simulation ...... 1.7
1.4 Economic Assumptions ...... 1.8
1.4.1 Methane Price...... 1.8
1.4.2 Cost Assumptions ...... 1.9
1.4.3 Other Economic Assumptions ...... 1.10
1.5 Resource Definitions ...... 1.10
Chapter 2 Literature Review ...... 2.1
2.1 Economic Evaluations in the USA...... 2.1
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2.1.1 Deterministic Evaluations ...... 2.2
2.1.2 Stochastic Evaluation ...... 2.4
2.2 Shale Gas Policies in China ...... 2.8
2.3 Other Analysis ...... 2.9
2.3.1 Socioeconomic Analysis ...... 2.9
2.3.2 SWOT Analysis ...... 2.10
2.3.3 Porter’s Five Forces Model ...... 2.13
2.3.4 Economic Critical Depth (ECD) Analysis ...... 2.14
2.4 Summary ...... 2.14
Chapter 3 China’s Energy and Economy ...... 3.1
3.1 Primary Energy Consumption and the Economy ...... 3.2
3.2 Total Energy Supply and Demand ...... 3.6
3.3 Energy Structure ...... 3.9
3.3.1 Coal ...... 3.13
3.3.2 Crude Oil ...... 3.15
3.3.3 Natural Gas ...... 3.17
3.3.4 Hydropower ...... 3.18
3.3.5 Nuclear Power ...... 3.19
3.3.6 Wind Power ...... 3.20
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3.4 Carbon Dioxide (CO2) Emissions ...... 3.21
3.4.1 Carbon Dioxide Emissions in China...... 3.21
3.4.2 Comparison of Emissions by Different Types Energy ...... 3.23
3.5 Summary and Conclusion ...... 3.24
Chapter 4 Shale gas in China ...... 4.1
4.1 Distribution...... 4.1
4.2 Resources ...... 4.3
4.3 Geology ...... 4.4
4.4 Externalities ...... 4.5
4.4.1 Population ...... 4.7
4.4.2 Roads ...... 4.9
4.4.3 Pipelines...... 4.9
4.5 Development ...... 4.11
4.5.1 Sinopec ...... 4.11
4.5.2 CNPC ...... 4.12
4.5.3 Yanchang Petroleum ...... 4.14
4.5.4 CNOOC ...... 4.14
4.5.5 Other Companies ...... 4.15
4.6 Policies ...... 4.15
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4.6.1 Industrial Policy ...... 4.15
4.6.2 Shale Gas Policy in 2013 ...... 4.17
4.6.3 Fiscal Policies ...... 4.17
Chapter 5 Benefit of Shale Gas Development ...... 5.1
5.1 Shale Gas Resources and Distribution in the USA ...... 5.1
5.1.1 History ...... 5.3
5.2 Shale Gas Success in USA ...... 5.4
5.2.1 Development Model ...... 5.5
5.2.2 Support from Government ...... 5.5
5.2.3 Preferential Policy ...... 5.6
5.2.4 Regulatory and Legal Systems ...... 5.6
5.3 Benefits of Shale Gas Development in USA ...... 5.8
5.3.1 Energy Security ...... 5.8
5.3.2 National Energy Market ...... 5.10
5.3.3 The World Energy Market ...... 5.13
5.3.4 Job Opportunities ...... 5.15
5.3.5 Demonstration Effects ...... 5.15
Chapter 6 The Environmental Risks and Costs of Shale Gas
Development ...... 6.1
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6.1 Water Consumption ...... 6.2
6.1.1 Water Used ...... 6.2
6.1.2 Water Supply ...... 6.3
6.2 Water Contamination ...... 6.4
6.2.1 Shallow Groundwater Contamination ...... 6.7
6.2.2 Shallow Groundwater Contamination by Fluid Migration ..... 6.8
6.2.3 Flowback Fluid Management ...... 6.9
6.3 Greenhouse Gas (GHG) Emissions ...... 6.13
6.3.1 Well Completions ...... 6.14
6.3.2 Equipment Leakage and Venting ...... 6.14
6.3.3 Emissions from Liquid Removal Operations ...... 6.15
6.3.4 Processing ...... 6.15
6.3.5 Emissions in Gas Transport ...... 6.15
6.3.6 CO2 Emissions from Burning Methane ...... 6.16
6.4 Infrastructure Risks ...... 6.16
6.5 Induced Earthquakes ...... 6.16
6.6 Water Costs ...... 6.17
6.7 Flowback Water Handling Costs ...... 6.19
6.8 CO2 Emission Costs ...... 6.21
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6.9 Methane Emission Costs ...... 6.23
6.10 Infrastructure Maintenance ...... 6.24
6.11 Compensation ...... 6.25
6.12 Disaster Costs ...... 6.28
Chapter 7 Fiscal Regime ...... 7.1
7.1 State-Owned Enterprises (SOEs) ...... 7.2
7.2 Upstream Fiscal Structure...... 7.3
7.2.1 Urban Maintenance and Construction Tax ...... 7.7
7.2.2 Educational Surtax ...... 7.8
7.2.3 Resource Tax ...... 7.8
7.2.4 Cost Recovery ...... 7.8
7.2.5 Income Tax ...... 7.9
7.3 Mid-Stream and Down-Stream Tax ...... 7.9
Chapter 8 Case Study ...... 8.1
8.1 Introduction ...... 8.1
8.1.1 History ...... 8.4
8.1.2 Geology ...... 8.6
8.1.3 Resources ...... 8.7
8.1.4 Well Spacing...... 8.8
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8.1.5 Number of wells ...... 8.9
8.1.6 Pipelines...... 8.10
8.1.7 Waterlines ...... 8.11
8.1.8 Roads ...... 8.12
8.2 Economic Assumptions ...... 8.13
8.2.1 Production ...... 8.14
8.2.2 Methane Price...... 8.17
8.2.3 Revenues ...... 8.19
8.2.4 Upstream Costs ...... 8.20
8.2.5 Midstream and Downstream Costs ...... 8.24
8.2.6 External Costs ...... 8.25
8.3 Results ...... 8.32
8.3.1 Nominal Revenues ...... 8.34
8.3.2 Nominal Supply Chain Costs ...... 8.35
8.3.3 Nominal Fiscal Costs ...... 8.37
8.3.4 Nominal External Costs ...... 8.39
8.3.5 Nominal NCFs of the Supply Chain and the Whole Economy
8.41
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8.3.6 PVs of Nominal Revenues ...... 8.42
8.3.7 PVs of Nominal Supply Chain Costs ...... 8.44
8.3.8 PVs of Nominal Fiscal Costs ...... 8.45
8.3.9 PVs of Nominal External Costs ...... 8.46
8.3.10 PVs of Nominal Components Net Cash Flows ...... 8.49
8.3.11 NPVs of Supply Chain and Whole Economy ...... 8.51
8.4 Summary ...... 8.54
8.5 Comparison with Other Studies ...... 8.56
Chapter 9 Conclusion ...... 9.1
Appendix A - Abbreviations ...... A.1
Appendix B - Conversion Factors ...... B.1
Appendix C – Detailed Geological Properties of Major Shale Gas
Distribution Areas ...... C.1
Reference ...... D.1
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List of Figure
Figure 1.1 Shale Gas Development, Transmission, Distribution, and
Consumption ...... 1.3
Figure 1.2 Detailed List of Supply Chain Costs and External Costs ...... 1.5
Figure 1.3 Resources definition ...... 1.11
Figure 3.1 Energy Intensity of GDP from 1990 to 2013 in China ...... 3.2
Figure 3.2 Composition of GDP in 1990 and 2013 by Industrial Sectors ... 3.3
Figure 3.3 Prediction of Energy Consumption in China ...... 3.5
Figure 3.4 Production and Consumption of Energy in China ...... 3.6
Figure 3.5 Energy Imports and Exports from 1990 to 2012 in China ...... 3.8
Figure 3.6 Composition of Domestic Energy Supply from 1990 to 2013 in
China ...... 3.10
Figure 3.7 Composition of Energy Consumption from 1990 to 2013 in
China ...... 3.12
Figure 3.8 Coal Production and Consumption Areas in China ...... 3.15
Figure 3.9 CO2 Emissions in the World and China ...... 3.22
Figure 3.10 Chinese CO2 Emissions per Capita from 1990 to 2011 ...... 3.23
Figure 4.1 Distribution of Shale Gas Resources in China ...... 4.2
Figure 4.2 Water Stress in China ...... 4.6
Figure 4.3 China’s Population Density ...... 4.8
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Figure 5.1 Natural Gas Imports to the USA from 1990 to 2015 ...... 5.9
Figure 5.2 USA’s Crude Oil Imports from 1990 to 2015 ...... 5.10
Figure 5.3 USA’s Natural Gas Production by Source 1990-2040 ...... 5.11
Figure 5.4 Conventional Natural Gas Production in the Gulf of Mexico from
2003 to 2014 ...... 5.12
Figure 5.5 USA’s Natural Gas Wellhead Prices from 1990 to 2012 ...... 5.13
Figure 6.1 Possible Sources of Water Contamination in Shale Gas
Developments ...... 6.5
Figure 6.2 Possible GHG Emission Sources in the Shale Gas Lifecycle .... 6.13
Figure 6.3 Water Handling in a Shale Gas Development ...... 6.19
Figure 6.4 Flowback Handling Costs ...... 6.20
Figure 6.5 The calculation of Compensation ...... 6.25
Figure 7.1 Structure of the Hypothetical Upstream Shale Gas Fiscal Regime in China ...... 7.3
Figure 8.1 General Location of the Fuling Shale ...... 8.2
Figure 8.2 First Stage of Fuling Shale Gas Field ...... 8.3
Figure 8.3 Gas Pipelines Layout for the First Stage Development of the
Fuling Shale ...... 8.10
Figure 8.4 Waterlines layout for the First Stage Development of the Fuling
Shale ...... 8.11
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Figure 8.5 The Roads layout for the First Stage Development of the Fuling
Shale. Economic Assumptions ...... 8.12
Figure 8.6 Single Well Production Profile based on Mean Parameters ... 8.15
Figure 8.7 Annual gas production in the First Stage Development of the
Fuling shale...... 8.16
Figure 8.8 Cumulative Production in the First Stage Development of the
Fuling shale...... 8.17
Figure 8.9 The Locations of the Field Gate Price and the Terminal Price 8.18
Figure 8.10 Nominal Revenues for the Fuling Project ...... 8.35
Figure 8.11 Nominal Supply Chain Costs for the Fuling Project ...... 8.36
Figure 8.12 Breakdown of Taxes for the Fuling Project ...... 8.38
Figure 8.13 Composition of Components of External Costs for the Fuling
Project ...... 8.40
Figure 8.14 Comparison of Mean Nominal NCFs for the Fuling Project . 8.41
Figure 8.15 The Probability Distributions of the Present Values (PVs) of
Methane Sales Revenues and Supply Chain Revenues...... 8.43
Figure 8.16 The Probability Distribution of the PVs of Supply Chain Costs
...... 8.44
Figure 8.17 The probability distribution of the PVs of Supply Chain Fiscal
Costs ...... 8.46
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Figure 8.18 Probability Distribution of the PVs of External Costs ...... 8.47
Figure 8.19 Probability Distribution of the PVs of Costs as Percentage of the PVs of Methane Sales Revenue ...... 8.48
Figure 8.20 Comparison of Probability Distributions of PVs of Revenues and
Costs ...... 8.49
Figure 8.21 Probability Distributions of NPVs from Whole Economy and
Supply Chain Perspectives ...... 8.51
Figure 8.22 Cumulative Probability Distributions of NPVs for the Whole
Economy and the Supply Chain ...... 8.52
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List of Table
Table 1.1 Methane Price and Government Subsidy Assumptions in
US$2014 terms ...... 1.9
Table 2.1 The Results of Weijermars’ Analyses ...... 2.5
Table 2.2 Results from Liu et al.’s Analyses ...... 2.6
Table 3.1 Coal Balances from 1990 to 2012 ...... 3.14
Table 3.2 Crude Oil Balances ...... 3.16
Table 3.3 Total Natural Gas Imports and Exports from 2005 to 2013 ..... 3.18
Table 3.4 Carbon Dioxide Emissions from Various Resources ...... 3.24
Table 4.1 Shale Gas Distribution in China ...... 4.3
Table 4.2 Geological Features and Description ...... 4.4
Table 4.3 Major pipelines in China ...... 4.10
Table 4.4 Milestones for Sinopec’s Shale Gas Development ...... 4.12
Table 4.5 Milestones for CNPC’s Shale Gas Development ...... 4.13
Table 5.1 Shale Gas Distribution in the USA ...... 5.2
Table 6.1 Water Consumption per Shale Gas Well in Texas ...... 6.3
Table 6.2 Comparisons of Water Use ...... 6.3
Table 6.3 Water Use as a % of Total Water Use in Major Shale Gas Fields in the USA in 2011 ...... 6.4
Table 6.4 Volumetric Composition and Purpose of the Typical Constituents
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Table 6.5 Examples of Human-Induced Earthquakes (M-Richter Magnitude
Scale) ...... 6.17
Table 6.6 Price of Water in Regions with Different Water Resources. .... 6.18
Table 6.7 Components of Water Management Costs ...... 6.21
Table 6.8 Components of CO2 Emission Costs...... 6.22
Table 6.9 Methane Emissions during a Shale Gas Development ...... 6.23
Table 6.10 Components of Methane Costs ...... 6.24
Table 6.11 Hypothetical Average Compensation Assumptions for People
Living close to Shale Gas Fields in China ...... 6.27
Table 6.12 Compensation Effect/Income Matrix for China (in real US$2014 term) ...... 6.27
Table 7.1 Simplified Example of the Hypothetical Shale Gas Fiscal Regime
...... 7.6
Table 7.2 Urban Maintenance and Construction Tax Rates ...... 7.7
Table 8.1 Geological Properties of Fuling shale and Other Shale Gas Fields in North America ...... 8.6
Table 8.2 Number of Wells Drilled up to 2015 in the First Stage
Development of the Fuling Shale ...... 8.9
Table 8.3 Detailed Supply Chain and External Costs ...... 8.14
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Table 8.4 Variables of Production Assumptions for a Single Well in Fuling
...... 8.14
Table 8.5 Methane Price Assumptions ...... 8.18
Table 8.6 Revenues for the First Stage Development of the Fuling Shale
Project ...... 8.19
Table 8.7 Real Exploration and Appraisal Costs for the First Stage
Development of the Fuling Shale Project ...... 8.21
Table 8.8 Real Development Costs for the First Stage Development of the
Fuling Shale Project...... 8.22
Table 8.9 Real Annual Operating costs for the First Stage Development of the Fuling Shale Project...... 8.23
Table 8.10 Real Transmission and Distribution Costs for the First Stage
Development of the Fuling Shale Project...... 8.24
Table 8.11 Real Water Use Costs for the First Stage Development of the
Fuling Shale Project ...... 8.25
Table 8.12 Flowback Management Costs for the First Stage Development of the Fuling Shale Project...... 8.26
Table 8.13 Flowback Management Costs Continued for the First Stage
Development of the Fuling Shale Project...... 8.27
Table 8.14 CO2 Emission Costs for the First Stage Development of the
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Fuling Shale Project. (Some emissions and are related to production. Some are emissions from burning methane and are related to sales) ...... 8.28
Table 8.15 Real GHG Emissions Costs for the First Stage Development of the Fuling Shale Project ...... 8.29
Table 8.16 Real Road Maintenance Costs for the First Stage Development of the Fuling Shale Project ...... 8.30
Table 8.17 Real Subsidy and Compensation for the First Stage
Development of the Fuling Shale Project ...... 8.31
Table 8.18 The Supply Chain Revenues and Costs ...... 8.33
Table 8.19 PVs of Costs as Percentages of PVs Methane Sales Revenues 8.48
Table 8.20 Breakdown of the PVs of the Components of Net Cash Flow8.50
Table 8.21 The Mean, P90, P50 NPVs and from Figures 8.22 and 8.23. . 8.52
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.1
Chapter 1 Introduction
1.1 Background
With the recent rapid development of the Chinese economy, the demand for energy has increased correspondingly. This trend is likely to continue.
However, the domestic supply of conventional oil and gas resources has not kept pace with this growth.Furthermore, in the foreseeable future is likely to be unable to keep pace with the demand for these products. It has become a significant national energy security concern.
Over the past 20 years, with the improvement of oil and gas exploration and development technologies, shale gas, and other unconventional energy resources have attracted increased attention. In particular, the development of shale gas in the USA has played a major role in increasing gas supply in that country, thereby reducing external energy dependency and improving the country's energy security.
China, whose estimated shale gas resources are considerable, begins to explore for shale gas in 2009. The government has set a huge target for shale gas production. Its annual national shale gas production target exceeds 1,000 billion cubic feet (Bcf) by the end of 2020[1].
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.2
1.2 Aims and Scope
This thesis focuses on the economics of shale gas development in China based on an analysis of the costs and benefits of shale gas from the perspectives of both the companies involved in the upstream, midstream and downstream sectors (the “Supply Chain”) and the economy/society as a whole (the “Whole Economy”). The latter involves examining the effects of costs that are external to the project itself. These are the externalities.
The externalities include, but are not limited to - a. Water requirements. b.Water contamination issues. c. Greenhouse gas emissions (GHG). d.
Accidents. e. Induced earthquakes.
Specifically, the aims of the thesis are:
A. To describe and quantify the benefits and costs of an example Chinese shale gas development for the Whole Economy. The benefits and costs include those external to shale gas Supply Chain companies.
B. To assess the benefits and costs of an example Chinese shale gas development for the companies operating the shale gas operation. In other words, the boundary of the analysis is the shale gas Supply Chain on its own. The analysis excludes the economic effects of benefits and costs external to the development.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.3
C. By comparing the analyses in points A and B above, to quantify the incremental economic effects of external benefits and costs.
The boundaries of the Supply Chain analyses are illustrated in Figure 1.1
Shale gas producing wells
Residential use Compressor station
Vehicle fuel
Industrial use and export
Upstream Transmission Distribution and development Consumption
Figure 1.1 Shale Gas Development, Transmission, Distribution, and Consumption
The analysis focuses the benefits and costs in a. the upstream stage
(extraction and production) stage, b. the gas transmission and gas distribution stage and c. the consumption stage. The externalities referred to above apply across all stages of a shale gas development.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.4
The analyses incorporate probabilistic assessments of key parameters, thus recognising the inevitable uncertainties inherent in estimating future production, prices, discount rates and costs.
This thesis analyses the economics of the Fuling shale gas project in the
Fuling shale in the Sichuan basin as an example. It does not examine other shale gas projects, nor attempt to analyse the economics of the shale gas industry as a whole in China. Other shale gas projects will have different geological, engineering and economic conditions and therefore, their economic viability will be different. However, the analytical approach adopted for this thesis can be applied to other projects, including those outside China.
1.3 Methodology
The methodologies adopted in this thesis are described below.
1.3.1 Cash Flow Forecasts
I assess the costs and benefits of shale gas developments by constructing net cash flow forecasts under different assumptions. The costs applied in this thesis are summarised in Figure 1.2.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.5
Exploration Costs Appraisal Costs Costs Development Costs
hain hain Operating Costs C Transmission and Distribution Costs Abandonment Costs Supply Supply Fiscal Costs (Taxes) Water use costs
Water contamination costs
CO2 emission penalties from burning methane Methane leakage penalties Road maintenance
External Costs External Central subsidies Compensation Figure 1.2 Detailed List of Supply Chain Costs and External Costs
The costs are divided into two parts. Supply Chain costs that are incurred inside the boundaries of the shale gas development itself. External Costs are the costs associated with the shale gas development but are incurred outside the boundaries of the shale gas development itself. The latter include, but are not restricted to environmental costs connected with shale gas production.
1.3.2 Net Present Value (NPV)
NPV is a measure of the relative monetary advantage gained by investing money in a project by comparison with investing in alternatives opportunities[2].
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The NPV as a single indicator that helps make economic decisions and, more particularly, indicates monetary value. A positive NPV means it worthwhile investing in the project and tells us how much the project is worth. A negative NPV suggests the projects not worth developing[2] and indicates that it would be better to invest in alternative opportunities.
The NPV equation is shown below,
NCF1 NCF2 NCF3 NCFn NPV= + + +………..+ n (1+r)1 (1+r)2 (1+r)3 (1+r)
Where
NPV= Net Present Value
NCF1= Net cash flow in year 1
NCF2= Net cash flow in year 2
NCF3= Net cash flow in year 3
NCFn= Net cash flow in year n
= Discount rate
𝑟𝑟 I do not use other economic indicators that are sometimes used in oil and gas industry economic analyses. For instance, I do not use internal rates of return (IRR), payback periods, or cost-benefit ratios. These have a place in
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.7 some circumstances for some decision makers in the oil and gas industry but have limited use in assessing value.
I also calculate the present value (PV) of revenues and costs.
1.3.3 Probability Analyses
Probability analysis is used to evaluate the uncertainties associated with subsurface structures and future events.
1.3.4 Monte Carlo Simulation
Monte Carlo simulation is a method of combining probability distributions of input parameters (in this thesis, production, prices, and costs) to derive a probability distribution of the output (in this thesis, a project’s revenues, total costs, and NPVs)
There are three main steps involved in carrying out Monte Carlo simulations. First, we need to estimate appropriate probability distributions for the input variables. In this thesis, I use lognormal distributions for all input variables. These are the initial production rate, the production decline rate, all costs, prices and discount rate. In this thesis, the output variables are present values (PVs). The Monte Carlo simulation selects points from the input distributions at random and calculates a PV based on those selections. The simulator repeats this
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.8 process thousands of times to generate and record thousands of corresponding PVs. In all of my analyses, the simulator, generates 5,000
PVs for each analysis. The simulator generates a probability distribution of
PVs based on this data.
1.4 Economic Assumptions
The economic assumptions in this thesis are described below.
1.4.1 Methane Price
I make the methane price assumptions for the Fuling project as set out below. All assumptions are in US$2014 terms.
The field gate price refers to the price at which upstream companies sell methane to the natural gas transmission companies. When upstream companies sell methane, they receive a Government subsidy as an incentive for shale gas development. I use the field gate price plus the government subsidy to determine the economics of the upstream operations.
The terminal methane price is the price that the final consumers pay for the methane produced.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.9
The highest Fuling project field gate price was 2.34 yuan/m3 (US$10.6 per
Mcf) in April 2015, and the Government subsidy was 0.4 yuan/m3 (US$1.8 per Mcf) for the shale gas upstream producer. By the end of November
2015, the field gate price was reduced to 1.64 yuan/m3 (US$7.4 per Mcf) although the subsidy remained 0.4 yuan/m3 (US$1.8 per Mcf). Terminal gas prices are those paid by final consumers. In Chongqing in 2015, the price of methane for residential use was 1.72 yuan/m3 (US$7.8 per Mcf), and the price for industrial use was 2.87 yuan/m3 (US$13 per Mcf) in
2015[3]. The assumptions for the Fuling field gate methane price, the terminal price in Chongqing and the Government subsidies for gas producers, are given in Table 1.1
Units P90 P10 Mean Subsidy US$/Mcf 0.50 2.00 1.16 Field gate methane price US$/Mcf 6.00 12.00 8.80 Terminal methane price US$/Mcf 8.00 16.00 11.74 Table 1.1 Methane Price and Government Subsidy Assumptions in US$2014 terms
1.4.2 Cost Assumptions
The detailed cost assumptions used in my analyses are described in
Chapter 8.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.10
1.4.3 Other Economic Assumptions
Future costs and prices are estimated in US$2014 terms. To convert these to nominal costs and prices, I assume that the escalation rate is constant at 3% per year.
I assume a nominal discount rate of 10%.
1.5 Resource Definitions
Under the definitions of the Petroleum Resource Management System
(“PRMS”), resources are divided into classes according to their levels of uncertainty and commerciality[4].
Under the PRMS, shale gas resources are therefore classified according to their level of uncertainty maturity and the chance of commerciality. In general, there are three classes. They are Reserves, Contingent Resources, and Prospective Resources. 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”[4].
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
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.11 considered to be commercially recoverable due to one or more contingencies”[4]. Prospective Resources are “those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations”[4].
PRODUCTION RESERVES
1P 2P 3P
PROVED PROBABLE POSSIBLE PIIP
COMMERCIAL
PLACE(PIIP) -
IN - CONTINGENT RESOURCES
DISCOVERED 1C 2C 3C COMMERCIAL
-
SUB PROSPECTIVE RESOURCES
Low Estimate Best Estimate High Estimate
Increasing chance of commerciality commerciality of chance Increasing PIIP
TOTAL PETROLEUM INITIALLY
UNDISCOVERED UNRECOVERABLE
Range of Uncertainty
Figure 1.3 Resource definitions[4]
For projects that satisfy the requirements for commerciality, Reserves may be assigned to the project, and the three estimates of the recoverable sales quantities are designated as 1P (Proved), 2P (Proved plus Probable), and 3P (Proved plus Probable plus Possible) Reserves. The equivalent
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 1.12 categories for projects with Contingent Resources are 1C, 2C, and 3C, while the terms low estimate, best estimate, and high estimate are used for Prospective Resources[4].
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.1
Chapter 2 Literature Review
With the emergence of shale gas exploration and development in China, an increasing number of researchers have evaluated the industry and have thereby enhanced the international literature on shale gas extraction and production. This chapter reviews the existing literature of the evaluation shale gas. The literature contains many papers on the technology of shale gas extraction and resource estimates. This literature review focuses on the limited literature dealing with the economics of shale gas rather than the geological and engineering issues.
2.1 Economic Evaluations in the USA
This section discusses the economic evaluations and analyses of shale gas development projects in the USA. The common theoretical approach is a
Discounted Cash Flow (DCF) approach[5]. In some papers, other methods also applied combined with DCF, such as genetic algorithms [6], statistical analysis[7, 8], and system dynamics [9]. In general, the evaluation models are divided into deterministic evaluations and stochastic evaluations[5].
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.2
2.1.1 Deterministic Evaluations
A. Financial Analysis
Financial analysis obtains economic indicators such as NPV, IRR, and CPI by using DCF. These indicators are used to evaluate shale gas development cases and help decision makers.
In some existing literature, the authors provide only simple economic analysis and evaluation [10-12].
However, some articles provide sophisticated financial analysis of shale gas development. For instance, Schweitzer et al. indicate that an obstacle of evaluating shale gas production and economics is a lack of information for well and fracture design completions. Their simulations are based on the various wellbore configurations for gas production in Marcellus shale.
The average costs (for horizontal drilling and fracturing over different distances) and methane sale prices are used in the economic evaluations.
The evaluations are used to choose the most cost- efficient development configuration[13].
Kepes et al. propose an economic rating of shale gas plays including both technical and fiscal factors. They argue that this rating could provide a good way for investors to select valuable shale gas resources in North
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.3
America[14]. However, they did not consider the potential uncertainties in fiscal terms and gas prices as well as other factors in future.
B. Uncertainty and Risk Analysis
Because of the uncertainties and risks of developing shale gas, a deterministic financial analysis may not give a comprehensive evaluation.
Therefore, uncertainty and risk analysis, such as sensitivity analyses and breakeven analysis, are sometimes used. However, such studies ignore the effect of probability.
A sensitivity analysis explores the impacts of input parameters (such as gas production, price, and costs) on a project’s economic indicators such as
NPV, IRR and Discounted Profit to Investment Ratio (DPI).
Wright analyses the economic viability and sensitivity to DPI by changing the gas price, capital costs, and operating costs. He selects three sensitivities, namely 25%, 50% and 75% of the average estimated ultimate recovery per well. The author adopts real (US$2008) costs and prices to evaluate the economics. Only the area with high recoveries is economic.
The sensitivity analysis illustrates that the DPI is more sensitive to changes in capital costs and gas prices[15].
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.4
Gao et al. use sensitivity analyses to calculate the NPV for variations in economic parameters such as gas price, initial production, capital costs and operating costs[16]. They determine how robust the economics of shale gas development in different conditions.
Another author, Duman, obtains the breakeven operating costs for
Marcellus shale by analysing the economic effect of different assumptions.
His results indicate the breakeven price of natural gas to be US$2.94/Mcf in 2011 in a twenty-year production scenario assuming no workovers [17].
Both sensitivity and breakeven analysis have become popular in shale gas research. Researchers have examined the impacts of various parameters, such as royalty and tax rates, on the economics of shale gas[5]. As regards breakeven analyses, the majority of studies still focus on the breakeven gas price since the gas price is a factor over which developers have little control. A limited number of papers concentrate on breakeven costs and breakeven production.
2.1.2 Stochastic Evaluation
Compared with the deterministic evaluations mentioned above, a stochastic (probabilistic) assessment provides a more thorough measurement of the economic viability and risks of shale gas. Probabilistic
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.5 analyses give a more comprehensive basis for companies’ investment decisions.
Weijermars thinks that the uncertainties in gas production and price forecasting should be incorporated in discounted cash flow (DCF) analyses and that this would increase the integrity of economic evaluation[18]. He analyses the Haynesville shale and sets scenarios with estimated ultimate recoveries (EUR) of 10, 8, 6, and 4 Bcf per well with the wellhead gas price in US$4 and US$6 per Mcf. The results as measured by the net present value (NPV) and Internal Rate of Return (IRR) are shown below[18].
Cumulative production NPVs IRR
10 Bcf US$9 MM 20% 8 Bcf US$4 MM 7% 6 Bcf US$-2 MM -4% US$4/Mcf 4 Bcf US$-8 MM -20%
10 Bcf US$23 MM 78% 8 Bcf US$16 MM 40% 6 Bcf US$7 MM 14% US$6/Mcf 4 Bcf US$-2 MM -4% Table 2.1 The Results of Weijermars’ Analyses
His model takes price and production uncertainties into account. However, other inputs, such as operating costs and well capital costs, are also uncertain and should not be ignored.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.6
Liu et al. explore the economic feasibility of the Marcellus shale. They incorporate probability distributions for costs, prices, production as well as royalties. Table 2.2 gives the stochastic results (“P90”, “P50” and “P10” means that there is a 90%, 50% and 10% probability respectively that the values will be exceeded[19].
Indicator Units P90 P50 P10 IRR % 9.0% 15.8% 23.5% NPV (discount rate = 15%) US$ -670,000 86,000 844,000 Table 2.2 Results from Liu et al.’s Analyses
The results give the economic indicators for a single well in the Marcellus shale. However, the research ignores the environmental effects caused by shale gas development which might generate huge expenditure in the future.
Kaiser believes that technological risks, geological uncertainties and gas price volatility affect the economics of shale gas development significantly.
He investigates the economic viability and sustainability of the Haynesville shale using DCF analysis. In this paper, inputs such as gas price, production, and tax rates are represented by various probability distributions. For a methane price of US$5/Mcf, wells are expected to generate returns of between 1% and 11.5% for operating costs (OPEX) of between US$1/Mcf and US$0.5/Mcf and individual well capital costs (CAPEX) of $7.5 million.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.7
For a methane price of US$6/Mcf, the project will generate a return of between 7.6% and 33% for CAPEX of US$10 million to US$7 million and
OPEX of US$0.5/Mcf. If the methane price falls to US$4/Mcf, only a few wells are expected to be profitable[20]. That means the majority of wells in Haynesville are uneconomic under prevailing gas prices. However,
Kaiser only incorporates direct costs. Indirect costs external to the development itself also need to be incorporated.
Stochastic evaluations commonly use Monte Carlo simulation and decision tree approaches. Because of the many uncertain parameters, Gray et al. find that deterministic economic evaluation cannot give results in which we can place confidence. It only provides an indication of commercial potential at a scoping level. Because of this, they propose that evaluations for shale gas development using Monte Carlo simulation should be applied consistently and systematically[21].
In general, several authors argue that shale gas development requires consistent decisions based on probabilistic evaluations, and that decision tree methodology can support this approach [7, 22, 23].
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.8
2.2 Shale Gas Policies in China
The shale gas industry in China is still in its infancy. Therefore, establishing appropriate policies for China’s shale gas industry is seen as a priority.
Yanbin Li et al. point out that current Chinese shale gas industry policies have problems. For instance, they argue that the incentives for exploration and development offered under current policies are not strong enough. In addition, they suggest that China lacks an effective regulatory regime and good investment support mechanisms[24].
Wu Yunna et al. use a system dynamic (SD) model to simulate the trends in the shale gas industry in China under different scenarios. The results illustrate that technology, policy, and costs have an impact on the market competition. They suggest that the Chinese government improve shale gas laws and regulations. At the same time, companies should invest more capital and energy on research and development[25].
In my view, the two articles mentioned above do not give convincing evidence to support their recommendations.
Jiehui Yuan et al. adopt discounted cash flow (DCF) analysis to evaluate shale gas production from the Fuling shale gas project (Fuling). The authors find that production in Fuling is uneconomic under current
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.9 technical and economic conditions. They conduct a policy analysis based on their DCF analyses to evaluate those policies that might improve
Fuling’s profitability. The analysis indicates that policies associated with gas price, financial subsidies, and Income Taxes could be used to strengthen profitability and therefore the incentive to invest[26]. The authors consider that shale gas development in China is vulnerable and that the government should introduce policies to accelerate investment.
In my view, if the economic indicators for the Fuling are negative, the decision to develop needs further thought. Moreover, the estimates of operating costs and exploration costs in their model are higher than the mean of my assumptions, and the authors do not give evidence or references to support their assumptions.
2.3 Other Analysis
2.3.1 Socioeconomic Analysis
Shiwei Yu explores the shale gas in China from socioeconomic perspectives. The author suggests that the lessons from six years of shale gas development reveal the resource potential is potentially large, if uncertain, and its current contribution to the overall supply of energy in
China is small. The current plans for shale gas development aim to
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.10 achieve quick successes and short term benefits. In other words, they lack long-term perspectives. The shale gas industry still follows the “Pollute
First - Pay Later” model which could cause huge environmental risks.
Shiwei Yu finally suggests that strengthening technological research and government incentives might give the shale gas industry a bright future[27]. However, creating favourable conditions for the shale gas industry might not be the right choice when the environmental effects are significantly adverse.
2.3.2 SWOT Analysis
Xinggang et al. point out that the abundant resources, huge potential market, and environmental benefits are strengths (S) and opportunities (O) which make the prospect of developing shale gas in China bright. However, at the same time, there are weaknesses (W) and threats (T) during the early stages of development. Outdated technology, water scarcity, environmental risks, poor infrastructure, insufficient funds, unsound policies and management systems constrain the pace of shale gas development in China [28]. By identifying the advantages and disadvantages of shale gas development, Xing gang et al. construct a
SWOT matrix and formulate strategies for China. They sort SWOT factors, prioritise and combine them to give four types of strategies to accelerate
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.11 the development of shale gas in China – SO strategies, WO strategies, ST strategies and WT strategies [28].
Xinggang et al. give helpful analyses of shale gas development.
Nevertheless, two more significant factors should not be ignored.
First, the economic benefits of shale gas development make a huge contribution to the China’s economy. For instance, Considine et al. find that Marcellus shale gas generated US$2.3 billion in total value added, more than 29,000 jobs, and $240 million in state and local taxes during
2008. Furthermore, the authors predict that the production of Marcellus shale gas will increase to 4 billion cubic feet (BCF) in that year. It will generate US$13.5 billion in value and almost 175,000 jobs. The local taxes income from 2009 to 2020 will be approximate US$12 billion. Although the USA and China have different geological conditions, as well as economic and financial systems, if the development of the Marcellus shale is a guide, there would be considerable economic benefits of shale gas development in China.
Second, Xinggang et al. suggest that social and environmental concerns should be considered. During shale gas operations, there are direct and indirect risks that affect residents’ life and health. For example, huge water consumption and water pollution directly influence residents’ water
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.12 supply and jeopardise their health. In addition, Greenhouse Gas (GHG)
Emissions and noise during drilling, production, and transport can also affect residents’ lives significantly[29].
In my view, SWOT analyses should include the views of a variety of community members. If the number of community members is limited, then the analysis is constrained. The results of the analysis would be unfair to people affected by shale gas development [27]. The paper analyses the issues from the perspectives of government and companies. The views of other community members are ignored.
Another limitation of the SWOT analysis in the paper is that the priorities assigned to different factors are disputable. For example, the authors consider that the weak priorities are - W1 lack of funds, W2 lack of key technologies, W3 prominent water treatment and W4 serious environmental risks[28]. However, in 2013 the Chinese Premier Li Keqiang said "We will resolutely declare war against pollution as we declared war on poverty"[30]. Therefore, according to Li’s statement, environmental risks should be ranked highly, if not in first place. In contrast, for example, the first SO strategy in the paper is to make full use of abundant resources of shale gas to accelerate the exploration and development[28]. In other
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.13 words, this strategy has the highest priority. However, it does not environmental factors rank low.
2.3.3 Porter’s Five Forces Model
In 2014, Wu et al. apply the so-called Porter’s five forces model to analyse the competitive position of shale gas in China. [31]. Porter’s five forces analysis is a framework. The main purpose of the analysis is to explore the level of competition in an industry and a commercial strategy for development. Based on Porter’s model, the authors investigate five main aspects: supplier power, buyer power, barriers to entry, the threat of substitution and the degree of rivalry. Based on these, Wu et al. provide their suggestions for improving the condition of the Chinese shale gas industry. These are (a) Strengthen policy (b) Provide more investment in technology research (c) Learn more from the USA experience (d) Reduce development costs (e).Try to build better market mechanism [31].
Wu’s research takes China’s current situation and market into account.
However, he misses the environmental impacts of shale gas which could be the biggest barrier to shale gas development. In addition, it makes the analysis less than comprehensive.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.14
2.3.4 Economic Critical Depth (ECD) Analysis
Xia et al. (2014) argue that the critical economic depth (ECD) for gas production is a significant factor in the evaluation of the prospective of shale gas. Based on current gas prices, existing technologies and policies, the authors use break-even analysis to calculate the ECD. The breakeven occurs when the net present value (NPV) is zero. The results show that the
ECD strongly influenced by the initial production rate and the production decline rate[32].
However, another key parameter - operating costs - has been ignored because of limited data. In my view, ECD analysis like this is unnecessary if an NPV analysis has already been carried out.
2.4 Summary
In this chapter, the status of current research on shale gas evaluations is presented. My views of the limitations of the research are summarised below.
A. The literature fails to examine the economics of shale gas as a whole system including its externalities (water contamination, GHG emissions, and other environmental factors) adequately.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 2.15
B. The literature does not fully or properly quantify the effect of uncertainty on the economics of shale gas developments.
C. The Chinese literature is presented under a premise that China must develop shale gas. However, there is insufficient analysis, especially quantitative analysis, of the environmental and social effects of shale gas developments in China.
The aims of my thesis are to redress the shortcomings in the current literature as set out above.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.1
Chapter 3 China’s Energy and Economy
In the past 50 years, China's economy has grown rapidly. However, this has been accompanied by a corresponding rapid growth in energy consumption. In addition, there has been an increase in the production and import of fossil fuel such as oil, gas, and coal. These developments have caused an increase in carbon emissions. In response, China is seeking to adjust the structure of its energy use and is developing cleaner (lower
CO2 emitting) energy to support sustainable development.
Natural gas is a relatively clean energy source and is being used increasingly in China and worldwide. According to BP’s World Energy
Outlook, the demand for natural gas in China will come almost double from 2014 to 2035[33]. However, China’s conventional natural gas and
CBM (Coal Bed Methane) resources are relatively small. Therefore, China’s government has started to develop shale gas, the domestic resources of which are relatively abundant.
This chapter explores the trends in energy use and production from economic, environmental and resource perspectives. This sets a context for analysing shale gas development in China.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.2
3.1 Primary Energy Consumption and the Economy
This section analyses energy consumption in China. It uses data on Gross
Domestic Production (GDP) and energy consumption from 1990 to 2013.
GDP is expressed in dollars and energy consumption is expressed in British
Thermal Units (Btu).
Figure 3.1 shows the energy intensity of Chinese GDP in Btu per dollar of
GDP.
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
Energy Consumption (Btu) per US$ of GDP GDP of per US$ (Btu) Consumption Energy 0
Year
Figure 3.1 Energy Intensity of GDP from 1990 to 2013 in China[34]
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.3
In 1990, China’s energy intensity stood at 80,000 Btu per US$. By 2013, its energy intensity decreased dramatically to about 10,000 Btu per
US$ which is close to the world average. By comparison, the energy intensities of the USA and OECD countries are in the range 6,000 to 7,000
Btu per US$ in 2013, which is lower than China[35]. China’s 13th five-year plan expects the energy intensity to fall by 15% from 2015 to 2020.
100% 90% Tertiary 80% industry, 32% Tertiary
industry, 46% 70% 60% 50% Secondary industry, 41% 40% Secondary 30% industry, 44% Percertage of of GDP total Percertage 20% Primary 10% industry, 27% Primary 0% industry, 10% 1990 2013 Year
Figure 3.2 Composition of GDP in 1990 and 2013 by Industrial Sectors [34]
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.4
To explore the basis for this trend, Figure 3.2 compares the composition of
GDP in 1990 and 2013 by industrial sectors.
There are three main industrial sectors - the primary sector, the secondary sector, and the tertiary sector.
The primary sector makes direct use of natural resources. It includes agriculture, fishing, and mining. The primary sector is large and has high energy intensity.
The secondary sector is less energy intensive because it is based on manufacturing and construction.
The tertiary sector is the service sector. It has the lowest energy intensity[36].
In 1990, primary industry’s GDP represented 27% of total GDP. By 2013, it contributed only 10% of GDP. The contribution to GDP of the secondary sector shows only a slight decline from 1990 to 2013. However, the contribution of the tertiary sector increases significantly in the period. In
1990, its GDP represented the smallest part of total GDP at 27%. In contrast, in 2013, the contribution of the tertiary sector’s GDP reaches 46% and becomes the largest sector. These structural changes dominate the overall decline in energy intensity.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.5
Although energy intensity of GDP goes down, as Figure 3.3 shows, total energy demand still increases.
200 180 160
140
120 100 80 Quadrillion Btu Quadrillion
Energy Consuption In Consuption Energy 60 40 20 0 2005 2010 2015 2020 2025 2030 2035 Year
Figure 3.3 Prediction of Energy Consumption in China[37]
The decline in energy intensity relieves the pressure to supply energy to the economy to some degree. However, it is not likely to be sufficient to stop energy consumption growth in future. Figure 3.3 shows that energy consumption is expected to increase to 172 quadrillion Btu in 2035. In
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.6 other words, China continues to require more energy to support economic development.
3.2 Total Energy Supply and Demand
The balance between supply and demand of energy is the key to maintaining economic growth.
Figure 3.4 shows the domestic production and consumption of energy in
China from 1990 to 2013.
100
90 80
70 Consumption 60 50 Production 40
(in (in Btu) quadriilion 30 20
Energy Prodction And And Prodction Energy Consumption 10 0 1990 1993 1996 1999 2002 2005 2008 2011 Year
Figure 3.4 Production and Consumption of Energy in China [34]
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.7
Chinese energy production and consumption almost keep in balance from
1990 to 2000. However, in 2001, the balance begins to break, coinciding with China entering the World Trade Organization (WTO). The WTO provided more opportunity for international trade for member countries.
From this point, more and more countries became China’s trading partners. As a result, China imports an increasing amount of energy from other countries to support economic growth.
In 1990, the export of energy from China was 1.4 quadrillion Btu and it remaines stable at around two quadrillions Btu from 1990 to 2012.
However, Figure 3.5 shows that energy imports experience a dramatic rise from 0.3 quadrillion Btu in 1990 to 16 quadrillion Btu in 2012.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.8
18 16
14
12 10 8 Imports Exports 6 (in (in Btu) quadrillion 4 Energy imports and exports exports and imports Energy 2 0 1990 1995 2000 2005 2010 2012 Year
Figure 3.5 Energy Imports and Exports from 1990 to 2012 in China[34]
From 1990 to 1995, China exported more energy than it imported.
However, from 2000, the energy trade balance reversed and energy imports started to exceed exports. Furthermore, the excess continued to increase. By 2012, the trade deficit (the excess of imports over exports) peaked at 13 quadrillions Btu.
The big trade deficit reflects the fact that China's economy has a strong dependence on energy supply from other countries. This affects economic,
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.9 political and military relationships with those countries. It also weakens national energy security.
In sum, in response to the imbalance between production and consumption, the Chinese government is attempting to widen its access to new energy sources.
3.3 Energy Structure
Different countries have different energy structures that reflect their resource endowment, environmental requirements and so on. China relies on energy from coal, crude oil, natural gas and other sources including nuclear and renewable energy (hydro, nuclear, solar, bioenergy and wind power). Solar energy and bioenergy still represent less than 0.2% of total power generation. Because of this, I do not include them in the analyses in this thesis.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.10
100% Other 90%
Crude Oil 80% 70% 60% Natural Gas 50% Coal 40% 30%
(percentage of total energy) of energy) total (percentage 20% Composition of Energy Supply Energy Composition of 10% 0%
Year
Figure 3.6 Composition of Domestic Energy Supply from 1990 to 2013 in China[34].
From Figure 3.6, in the past 30 years, coal has been the primary source of
China's energy supply. From 1990 to 2012, coal accounted for more than
73% of total energy, and it peaked at 78% in 2005. Crude oil is the second most important energy source. It took up 19% of total energy in 1990, and it declined to 9% in 2013. In contrast, natural gas and other energy sources show the opposite trend. The share of natural gas production was only 2% in 1990. Then it increased to 5% in 2013. The production of hydro,
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.11 nuclear and wind energy rose from 5% in 1990 to 11% of total energy in
2013.
The structure of energy consumption is a little different from the structure of production. Figure 3.7 shows that from 1990 to 2013, coal consumption has decreased from 76% to 66% of total consumption. However, natural gas and others are used increasingly. Crude oil is still a second most important component of demand. It accounts for 18% of total energy consumption in 2013. Non-fossil energy occupied around 10% of primary energy consumption in 2013. By the end of 2015, the share of non-fossil energy reached 12%, which a little higher than the target under the 12th five-year plan. China’s government has set a new target that it will increase to 15% by 2020 and 20% by 2025.
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.12
100% Other 90%
Crude Oil 80% 70% 60% 50% Coal Natural Gas 40% 30%
(percentage of of energy) total (percentage 20%
Composition Composition consumption energy of 10% 0%
Year
Figure 3.7 Composition of Energy Consumption from 1990 to 2013 in China[34]
The characteristics of China's energy structure are summarised as set out below.
A. Coal still dominates the economy. However, according to the thirteenth five-year plan, the composition of coal in total energy will decrease to below 60% by the end of 2020.
B. The production and consumption of natural gas, hydropower, nuclear power and wind power have increased. By the end of 2013, output and
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.13 consumption of this energy represent 16% of total energy production and consumption.
C. The production of crude oil has decreased sharply. However, the consumption of crude oil has remained stable.
3.3.1 Coal
China is the biggest coal consumer and producer in the world. However, its coal proven reserves rank third in the world behind the USA and Russia.
By the end of 2014, China's proven coal reserves were 115 billion tonnes
[38], which accounted for 13% of total world coal proven reserves.
However, production and consumption occupied 47% and 51% respectively of total global coal production and consumption. A reserve/production ratio (R/P) is the remaining life of fossil fuels, expressed in years assuming the same rate of production each year.
China’s coal reserve/production ratio is 30 years, which is much lower than the world average (110 years). Over-exploration conflicts with
China’s sustainable development goals.
The supply of coal chiefly comes from domestic production. Table 1 shows that from 1990 to 2012, imports increased from 2 to 288 million tonnes
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.14
(0.4 to 5.7 quadrillion Btu). Imports represent approximately 8% of total coal supply.
Unit 1990 1995 2000 2005 2010 2011 2012 Total supply Million Tonnes 1,022 1,335 1,368 2,269 3,298 3,606 3,800 Production Million Tonnes 1,080 1,361 1,384 2,350 3,235 3,516 3,645 Imports Million Tonnes 2 2 2 26 163 182 288 Exports Million Tonnes 17 29 55 72 19 15 9 Stock change in the year Million Tonnes -42 1 37 -35 -81 -78 -124 Total Consumption Million Tonnes 1,055 1,377 1,411 2,319 3,122 3,430 3,526 Table 3.1 Coal Balances from 1990 to 2012[34]
Figure 3.8 maps the main coal production and consumption areas in China.
China's coal resources are unevenly distributed across the regions. Most of the coal resources are in the north and west of China. In contrast, the south and east of China have limited coal resources. Furthermore, coal production and consumption are unbalanced. Coal consumption is concentrated in the east and south central of China. This is especially true in Jiangsu, Zhejiang and Guangdong provinces where coal consumption far exceeds coal production[39].
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.15
Figure 3.8 Coal Production and Consumption Areas in China
Because coal resources are unevenly distributed, transporting coal requires significant rail and road infrastructure. This requires investment and manpower. Transporting coal consumes energy and contributes to pollution.
3.3.2 Crude Oil
China's crude oil reserves are low compared to those in the rest of the world. In 2014, proven crude oil reserves in China were 18.5 billion bbl,
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.16 which represented only 1.1% of the total world proved crude oil reserves.
However, the production of crude oil was 4.2 million bbl per day, which represented 5% of global crude oil production. China’s reserves/production (R/P) ratio is 12 years[38].
Despite the domestic exploration effort, China’s domestic oil production still cannot keep pace with oil consumption. As Table 3.2 shows, a significant part of crude oil supply comes from imports. In 2012, China imported 61% of its crude oil consumption. It is predicted that this will increase to 80% in 2030.
Unit 1990 1995 2000 2005 2010 2011 2012 Total supply MMbbl 838 1,178 1,659 2,385 3,238 3,347 3,508 Production MMbbl 1,014 1,100 1,195 1,329 1,488 1,487 1,521 Imports MMbbl 55 269 715 1,258 2,158 2,316 2,425 Exports MMbbl 228 180 159 212 299 302 285 Stock change in the year MMbbl -3 -11 -91 9 -109 -154 -153 Total consumption MMbbl 842 1,178 1,649 2,385 3,170 3,326 3,493 Dependence on imports % 8% 34% 44% 59% 61% 61% Table 3.2 Crude Oil Balances [34]
At present, China chiefly imports crude oil from Saudi Arabia, Oman,
Sudan, Angola, and Iran. These countries are located in the Middle East and Africa. Thus, the imported oil must be transported by sea. The
Malacca Strait and other important seaways are critical for China's energy
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.17 security. In other words, China's energy security is critically affected by the political and economic position of petroleum exporting countries and by the availability of transport routes from those exporting countries.
3.3.3 Natural Gas
Natural gas energy sources consist of conventional and unconventional natural gas. Conventional gas is chiefly found in source sandstone rocks which can be extracted by long-established methods. Unconventional gas is generated in other source rocks which require different production technologies. Unconventional gas mainly includes coal seam gas (CSG), tight gas and shale gas.
Natural gas extraction in China started later than crude oil extraction. The natural gas industry began to develop rapidly from 1990 and especially in recent years. Between 2004 and 2014, the proven reserves of natural gas increased from 53 to 122 trillion cubic feet [38]. Two-thirds of these reserves were unconventional gas reserves. Furthermore, shale gas reserves were almost 75% of unconventional gas reserves[33]. Compared with conventional natural gas resources that have been developed for many years, the potential of shale gas is perhaps more critical to China’s future natural gas production.
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Chinese natural gas production has grown rapidly. It rose from 1,511 billion cubic feet in 2004 to 4,750 billion cubic feet in 2014. Its R/P is 25.7
(years)[38]. However, the consumption of natural gas was 6,551 billion cubic feet in 2014. In other words, there was a gap of 1,800 Bcf between domestic consumption and domestic supply.
To meet the gap, China imported LNG and pipeline gas from Australia,
Russia, and the Middle East. As shown in Table 3.3, by the end of 2013,
China imported 32% of its gas requirements.
Unit 2005 2006 2007 2008 2009 2010 2011 2012 2013 Imports Bcf 0 35 141 162 268 583 1109 1441 1942 Exports Bcf 106 102 92 113 113 141 113 102 71 Net imports Bcf -106 -67 49 49 155 441 996 1338 1872 External dependency % 12% 2% 5% 12% 22% 26% 32% Table 3.3 Total Natural Gas Imports and Exports from 2005 to 2013[34]
3.3.4 Hydropower
Hydropower is currently a small, but growing source of renewable energy to the economy.
In 2013, the national installed capacity of hydropower was 278 million kilowatts. It accounted for 23% of the total installed power generation
Yongjian Zhou August 2016 The Economics of Shale Gas Development in China Page 3.19 capacity in the country. The production of hydropower mainly comes from in the west of China, especially in Sichuan and Yunnan Provinces[40].
During the twelfth five-year plan, the China's installed capacity of hydropower is expected to increase by 20 million kilowatts. By the end of
2020, the national installed capacity of hydropower is expected to exceed
350 million kilowatts. In addition, the consumption of hydropower is expected to increase to 25% of total electricity consumption by 2020 according to 13th five-year plan[41]. The development of hydropower has helped diversify energy supply and contributed to economic development significantly. In addition, it has helped China become one of the leading hydropower technology exporters.
3.3.5 Nuclear Power
China started to develop nuclear energy in the 1980s. The Taishan nuclear station was the first nuclear plant in China. It began construction in 1985 and, in 1991, started to generate electricity. China was the 7th country to have nuclear power after the USA, Britain, France, the former Soviet
Union, Canada and Sweden.
However, by 2012, there were only 16 operating nuclear power stations in
China. In 2011, they contributed only 2% of total electricity generation
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[40]. Although nuclear power in China is a late-comer, development of the nuclear industry has accelerated in the past five years. There are now 26 nuclear stations under construction, which represent 39% of new-build nuclear plants in the world. The National Development and Reform
Committee plan that in 2020, the generating capacity will be 40 million kilowatts[41].
3.3.6 Wind Power
Wind energy first appeared in the 1950s when the wooden windmill was used to lift water. In the 1970s, the Chinese Government considered wind power to be critical, and wind power is now growing rapidly. By the late of the 1980s, China started to import some medium-sized generator sets from Denmark, Belgium, Sweden, the United States and Germany. It used these sets to build eight wind power stations in Xinjiang, Inner Mongolia,
Shandong, Zhejiang, Fujian, and Guangdong. In 1992, the installed capacity reached 8 megawatts. Since the year 2000, China has significantly increased its investment in wind power. In 2013, wind power stations had a capacity of 1 million kilowatt hours. Wind energy is available in all 32
Chinese provinces. Inner Mongolia produces 24% of Chinese wind energy supply and is the single highest wind energy producing province in
China[40].
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The 13th five-year plan estimated that in the installed capacity of wind power will reach 300 million kilowatts in 2020[41].
3.4 Carbon Dioxide (CO2) Emissions
The massive exploitation of resources in China has caused an unprecedented environmental problem. CO2 emissions have a significant effect on the environment and this directly relates to fossil-fuel-based energy production and consumption[42]. Since the 21st century, carbon emissions have caused concern worldwide. Furthermore, the Chinese people have started to worry about their living environment. In recent years, many areas of China have suffered from the effects of air pollution, which significantly influences people's lives and their health.
3.4.1 Carbon Dioxide Emissions in China
In 1990, China's CO2 emissions stood at 2,461 million tonnes. However, in
2011, they almost quadrupled, reaching 9,020 million tonnes. China's share of world carbon dioxide emissions rose 15%, from 11% in 1990 to 26% in 2011. They are expected to continue to increase in the foreseeable future. (Figure 3.9)
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40,000
35,000 World
30,000
) 2 25,000
20,000
15,000 China (in tonnes of CO of tonnes (in 10,000
5,000 CO2 emissions in the world and China and the world in emissions CO2
0 1990 2000 2006 2007 2008 2009 2010 2011 Year
Figure 3.9 CO2 Emissions in the World and China[35]
In 1990, carbon emissions per capita in China were much lower than the global average. However, as shown in Figure 3.10, in 2006, it started to surpass the global average, and the gap is getting bigger.
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8
7 China
6 ) 2 5
4 World 3 (in tonnes of CO of tonnes (in 2
Carbon Emissions per Emissions Carbon capita 1
0 1990 2000 2006 2007 2008 2009 2010 2011 Year
Figure 3.10 Chinese CO2 Emissions per Capita from 1990 to 2011[35]
3.4.2 Comparison of Emissions by Different Types Energy
There are various methods of generating electricity. Each has advantages and disadvantages associated with costs, environmental impact and so on.
To make a fair comparison, we need to consider the lifecycle of electricity generation including construction, operation and decommissioning.
Table 3.4 presents the World Nuclear Association’s estimates of the range of carbon emission in different types of energy.
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Resources Mean Low High
Tonnes CO2 e/GWh Coal 888 756 1,310 Oil 733 547 935 Natural Gas 499 362 891 Nuclear 29 2 130 Hydroelectric 26 2 237 Wind 26 6 124 Table 3.4 Carbon Dioxide Emissions from Various Resources [43]
As can be seen from the table, hydro, nuclear, and wind power have small
CO2 emissions compared to coal, oil, and natural gas. Natural gas CO2 emissions are almost half those of coal.
Table 3.4 shows that developing renewable energy, nuclear and natural gas can reduce significantly CO2 emissions from energy consumption.
3.5 Summary and Conclusion
For a long time, energy supply has been a significant issue affecting the economic development of China. Four energy obstacles handicap the economic development in China.
A. Domestic energy supply cannot meet domestic demand.
B. Continued exploitation of coal and crude oil resources is not sustainable.
C. The need for significant energy imports affects national energy security.
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D. Environmental pollution associated with energy consumption associated is on the rise.
Taking into account the issues set out above, developing shale gas could offer China significant opportunities. There are two main reasons. First, there are abundant shale gas resources in China. The Energy Information
Administration estimates that China has 1,115 trillion cubic feet technically recoverable (probable) shale gas. Therefore, shale gas development has the potential to increase domestic energy supply substantially. At the same time, this will help energy security issues associated with China’s reliance on imports. Second, shale gas has relatively low carbon emissions compared to coal. The carbon emissions by shale are only half those of coal, which assists environmental problems.
Although renewable energy has fewer carbon emissions, the production of renewables is a long way from meeting China’s energy requirement in next 20 years.
At the same time, there are significant external environmental costs associated with shale gas production. These include water requirement, water contamination, GHG gas emissions, compensation for residents and road maintenance. This thesis discusses and attempts to quantify these
External Costs.
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Chapter 4 Shale gas in China
China’s government has decided to develop shale gas vigorously to meet national energy supply. However, the prospects for shale gas are still unclear. This chapter analyses the overall development of shale gas in
China.
4.1 Distribution
According to the Energy Information Administration (EIA), China has the largest shale gas resources worldwide. The EIA has made a central estimate that China’s technically recoverable shale gas resource is 1,116 trillion cubic feet (Tcf).
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Figure 4.1 Distribution of Shale Gas Resources in China [44]
The majority of shale gas resources are located in five regions.
A. South China (including Sichuan, Jianghan, Subei basins, Yangtze platform)
B. Northwest China. (Tarim, Qaidam, Turpan and Junggar Basins)
C. Northeast China. (Songliao basin and Bohai Gulf)
D. North China. (Ordos Basin)
E. Qinghai-Tibet. (Qiangtang Basin)[28]
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4.2 Resources
China’s shale gas resources are abundant. Table 4.1 shows the shale gas resources in major Chinese basins[44]. More detailed information is given in Appendix C.
Gas In Technically Percentage Basin Formation Place recoverable of total (Tcf) (Tcf) Qiongzhusi 500 125 11.2% Sichuan Longmaxi 1,146 287 25.7% Permian 715 215 19.3% Yangtze L. Cambrian 181 45 4.0% Platform L. Silurian 415 104 9.3% Niutitang/Shuijintuo 46 11 1.0% Jianghan Longmaxi 28 7 0.6% Qixia/Maokou 40 10 0.9% Mufushan 29 7 0.6% Greater Wufeng/Gaobiajian 144 36 3.2% Subei U. Permian 8 2 0.2% L. Cambrian 176 44 3.9% L. Ordovician 377 94 8.4% Tarim M.-U. Ordovician 265 61 5.5% Ketuer 161 16 1.4% Pingdiquan/Lucaogou 172 17 1.5% Junggar Triassic 187 19 1.7% Songliao Qingshankou 155 16 1.4% Total 4,745 1,116 100% Table 4.1 Shale Gas Distribution in China[25]
The source of this information does not employ the PRMS categories described in section 1.5 of this thesis. However, I infer that the majority of
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the resources are effectively a combination of Prospective and Contingent
Resources at “Best Estimate” and “2C” levels of confidence under PRMS definitions.
4.3 Geology
As regards shale gas developments, several geological parameters are important. These are described in Table 4.1.
Geological parameter Description Total Organic Carbon (TOC) TOC represents the content of the organic material in the source rocks. Thermal maturity is the degree of heating in the process of kerogen transforming to Thermal Maturity (R0) hydrocarbon. It is usually measured by vitrine reflectance (R0).
Thickness The thickness of shale can reflect the volume of organic matter stored in shale. Depth The depth of shale reservoir affects the difficulty of drilling and production.
Reservoir pressure The pressure in a reservoir affects the rate of production. Table 4.2 Geological Features and Description[45]
The Sichuan basin’s and the Yangtze platform’s geological properties are similar to shale gas plays in Eastern USA. Their TOCs are between 3.2%-
4.0%. The thicknesses of their shale reservoirs and their thermal maturities are high. The Tarim Basin is largest shale resource in China in
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areal extent (central estimate = 234,000 square miles = 606,057 square kilometers). However, its TOC is only 1% to 2%. The Juggar basin has the most favourable geological characteristics. The average thickness of source rocks is extremely high (central estimate = 1,000 feet = 300 meters).
Its TOC is 4% on average and the peak TOC can reach 20%. The reservoir is over-pressured. Appendix C gives the detailed geological properties of shale gas areas in China.
4.4 Externalities
In addition to the geology, there are other factors that could affect shale gas developments in China. These include water resources, the effect on the population, roads, and pipeline infrastructure.
Water requirements for hydraulic fracturing could be an obstacle to shale gas development. I use the ratio of withdrawals to supply to indicate the degree of water stress across China. These ratios are shown in Figure 4.2
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Figure 4.2 Water Stress in China[46]
The majority of areas which are rich in shale gas face water supply issues.
For instance, the Tarim and Junggar basins are located in areas with extreme water scarcity. Given this, developers will need to pay extra costs in acquiring and transporting water before drilling. Water resources are relatively abundant in South China including Sichuan, Jianghan and Subei.
However, companies in these areas still need to consider seasonal variations in water availability. The Fuling project, as the first shale
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development in the area, has good water resources. It is located at the junction of the Yangtze and Wu Rivers and in the centre of the Three
Gorges reservoir. The risks of water shortage issue in this area very low.
All water for the Fuling shale gas development is purchased from the
Baitao water works which are sourced from the Wu River.
4.4.1 Population
China has the largest population of any country in the world. Shale gas extraction might affect a large number of people. Given the population density, choosing the best construction sites is also important to shale gas developers.
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Figure 4.3 China’s Population Density[47]
As can be seen from Figure 4.3, the population density is high in the
Sichuan, Jianghan and Subei Basins (260-520 people per square mile =
100-200 people per square kilometre. That means to develop these shale plays could affect a large number of people and developers might need to consider this in acquiring land and in the way they develop and operate any shale gas project. In contrast, the Tarim and Jungger basin are relatively uninhabited areas. Thus, acquiring land is less of a constraint in
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shale gas companies’ construction plans. However, as regards selling shale gas, those fields close to consumers can dramatically decrease transport time and costs. Therefore, population density is a key factor in shale gas development.
4.4.2 Roads
The provision of roads is also a critical factor in the exploration and development of shale gas. If there are no existing roads near a shale gas prospect, then this will delay development. In general, the traffic network in South and Southeast China is well developed. However, the road network is poor in Northwest China, especially in relatively uninhabited areas. Therefore, shale gas development in the Tarim and Jungger basins might be constrained by a sparse road network.
4.4.3 Pipelines
Gas pipelines are essential for shale gas development. However, the gas pipeline network in China is not as extensive as it is in the USA. Many pipelines cross the Sichuan basin and this might assist future developments. In addition, the Tarim, Jungger, Songliao basins have existing pipelines. However, the shale gas sites may be far from the main pipelines.
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Total Capicity Name Start End length (Bcf per (miles) year) West-East 1 Tarim Shanghai 2,604 706 West-East 2 Khorgos Guangzhou 5,396 1,059 West-East 3 Xinjiang Guangdong 4,575 1,059 Lunzhi Luntai, Guangdong 326 424 Seninglan Qaidam Lanzhou 591 106 Zhonggui Ningxia Guiyang 1,014 530 Chuanyu network Sichuan Chongqing 992 530 China-Burma Kyaukpyu Kunming 682 424 Zhongwu Zhong Wuhan 846 106 Chuandong Puguang Shanghai 1,366 424 Huaiwu Huaiyang Wuhan 295 53 Jining Yizheng Anping 929 353 Fushen Fuxin Shenyang 213 NA Hashen Harbin Shenyang 344 NA Dashen Dalian Shenyang 262 297 Kegu Inner Mongolia Beijing 223 141 Qinshen Qinhuangdao Shenyang 252 282 Yongtangqin Langfang Qinghuangdao 193 318 Table 4.3 Major pipelines in China[48]
Most of the major pipelines cross the big basins with conventional gas fields that are not far from potential shale gas fields. However, several pipelines are for natural gas imports including the China-Burma pipeline.
In 2014, the total annual capacity of major pipelines exceeded 7,000 Bcf.
However, total natural production was 4,700 Bcf in the same year[49].
This suggests that the remaining transmission capacity could be used for shale gas. In addition, the national government has decided to speed up pipeline construction in the next few years.
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4.5 Development
In 2009, China carried out its first shale gas exploration project. This marked the official start of shale gas development. China also set up a shale gas research center as well as shale gas-related policies and development plans. Now there are four state-owned companies with rights to shale gas development. They are China National Petroleum
Corporation (CNPC) and Chemical Corporation (Sinopec), the China
National Petroleum Corporation (CNPC), the China National Offshore Oil
Corporation (CNOOC) and Shanxi Yanchang Petroleum (Yanchang
Petroleum).
4.5.1 Sinopec
Before commercial shale gas development began, Sinopec spent more than 2 billion yuan (US$ 320 million) drilling 15 wildcat wells to find shale gas. The results were unsatisfactory. However, Sinopec persisted and continued to explore, with the result that it become the first company achieve a commercial breakthrough. Table 4.3 below shows the milestones of Sinopec’s shale gas development.
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Time Event Sinopec started evaluations in the Nanchuan, Fuling, and 2009 Wanzhou areas of the Chongqing municipality. Sinopec drilled Jiaoye 1HF well and achieved a production 2012 rate of 7.1 MMcfd. The National Energy Administration set up "Fuling shale gas 2012.Dec national level demonstration area " Sinopec authorised its Jianghan branch to develop shale gas 2013.Sep in Fuling. Fuling shale formal begins the commercial development 2014.Feb stage. 2014.Dec 144 wells had been completed. Multi-well pad drilling was introduced to speed up 2015.Feb development. 2015.Mar Exporting gas pipelines for the Fuling shale were finished. Table 4.4 Milestones for Sinopec’s Shale Gas Development[50]
In 2015, the daily sales of shale gas from the Fuling to the Chongqing municipality were 212 MMcfd. The remainder of gas sales from the Fuling project will be to East China through the Chuandong pipeline. The shale gas production target is 353 bcf in 2020. The costs of well drilling and completions decreased from US$15 million per well in 2014 to US$12 million per well in 2015.
4.5.2 CNPC
The Southwest and Zhejiang branches of CNPC are responsible for shale gas development in the company. The Southwest oil and gas branch of
CNPC is developing the Changning shale gas block and the Zhejiang branch
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operates the Zhaotong shale gas block. Table 4.4 shows the milestones for
CNPC’s shale gas development.
Time Event CNPC combined with Royal Dutch Shell to assess the resources 2009 of the Fushuang-Yongchuan block.
2010 CNPC drilled the first shale gas well in China in Weiyuan. CNPC signed profit sharing contract with Shell to develop the 2012 Fushuang-Yonggan block. CNPC acquired a 20% equity in ConocoPhillips' Browse & 2013.Feb Poseidon shale gas project and a 29% equity in the Canning shale gas project. CNPC acquired a 28.57% share in Ente Nazionale Idrocarbur. 2013.Mar AS the part of this, it obtained a 20% equity in a Mozambique shale project. 2013.Dec Changning shale gas companies were set up. First shale gas export pipeline completed. The total length of 2014.May the pipepline is 57.8 miles and the capacity is 250 MMcfd. The Southwest oil and gas branch daily gas supply reached 2014.Sep 21.2 MMcfd and cumulative sales were 6.6 bcf. 2015.Mar First shale gas well in Rongchan block was completed. Table 4.5 Milestones for CNPC’s Shale Gas Development [50]
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Although the speed at which CNPC developed shale gas is lower than that of Sinopec, CNPC believes that its prospects are better than for Sinopec’s properties. CNPC predicts that its production of shale gas will reach 706 bcf in 2020.
4.5.3 Yanchang Petroleum
Yanchang Petroleum is also involved in shale gas development. It has been involved from 2008. However, Yanchang Petroleum’s shale gas blocks are located mainly in the Erdos basin where many of the geological properties are not ideal.
One exception to this is that the buried depth of the potential resources is only 0.62 miles (approximately 1 kilometre), which decreases the difficulty of drilling. However, because existing pipelines for transporting gas are lacking, Yanchang Petroleum uses produced gas directly to generate electricity.
4.5.4 CNOOC
CNOOC has a cautious attitude to shale gas development. From 2014 to
2015, partly reflecting the effects of a decreasing oil price, CNOOC shale gas development is at a standstill.
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4.5.5 Other Companies
In 2012, the Ministry of Land and Resources (MLR) sold shale gas exploration rights in 20 shale gas block to the public. The total area of blocks is 7,722 square miles (200,000 square kilometres) distributed across eight provinces. However, the majority of bidding companies only completed 2-D seismic exploration. As a result, shale gas exploration rights are no longer open to private enterprises and now only four state-owned companies have rights to produce oil and gas.
4.6 Policies
The policy is an essential part of shale gas development. In the six-year history of shale gas exploration and development, the Chinese government has developed the shale gas policies described below.
4.6.1 Industrial Policy
A. Shale gas as a mineral resource.
In 2011, the Ministry of Land and Resources (MLR) defined shale gas as a mineral. However, from an administrative perspective, it treated shale gas as a separate, independent mineral resource[24].
B. Encouragement of participation in shale gas exploration and extraction.
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On November 2012, the MLR issued a “Notice of strengthening shale gas exploration and supervision”. This gave government support to investors that wished to explore for shale gas. In addition, the government offered help to owners of exploration rights to apply for more exploration areas following an exploration breakthrough. The Government agreed to offer production rights for parts of shale gas blocks following successful exploration. It required local land and resources departments to guarantee land-use for shale gas exploration and development.
C. Shale gas development in China from 2011 to 2015.
On March 2012, the government announced its five-year shale gas development plan. It proposed four targets to be achieved in 5 years[24].
The first target was to finish a basic assessment of national shale gas resources and an analysis of their distribution.
The second target was for production to reach 6.5 billion cubic meters
(230 Bcf) in 2015.
The third target was to research methods of evaluating shale gas resources in China as well as to study those technologies which best suit the complex geological conditions in China.
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The final target was to establish best practice industry standards covering exploration, production, and environmental protection.
4.6.2 Shale Gas Policy in 2013
On October 2013, the National Energy Administration (NEA) issued China’s first policy for shale gas industry. It emphasised that the government would increase the level of financial support for shale gas development. In addition, the NEA encouraged any entrants to the shale gas market, thereby setting up an open market. In addition, it emphasised the need for environmental protection in shale gas developments. As regards technology, the government encouraged the adaption of technologies that matched the best international practice[26].
4.6.3 Fiscal Policies
A. Subsidies
On 1 November 2012, the National Energy Administration and Ministry of
Finance announced a shale gas development and utilisation subsidy in which the Central Finance department agreed to subsidise shale gas development companies. From 2012 to 2015, the subsidy was 0.4 yuan/m3
(US$1.81/Mcf). In addition, the local finance department was permitted to give additional subsidies based on the local development situation.
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On 17 April 2015, the National Energy Administration and the Ministry of
Finance declared a 2016-2020 shale gas subsidy policy. From 2016 to 2018, the Central Finance subsidy is 0.3 yuan/m3 (US$1.36/Mcf). From 2018 to
2020, the Central Finance subsidy will decrease to 0.2 yuan/m3 (US$0.91/
Mcf). The subsidies can increase depending on the development of the shale gas industry, technological advance and costs.
B. Tax policy
At present, the shale gas fiscal system remains undeveloped. However, the government has taken action to improve the situation. China’s government has collaborated with the USA government to set up a plan to cooperate in shale gas fiscal policy.
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Chapter 5 Benefits of Shale Gas Development
This chapter discusses shale gas development in the USA as an indicative pointer to the potential benefits of shale gas development in China assuming further investment. It describes the background and the positive effects of shale gas development.
5.1 Shale Gas Resources and Distribution in the USA
The USA’s shale gas resources are abundant. Table 5.1 shows that the total quantity of onshore technically recoverable resources is 750 trillion cubic feet (central estimate of resources). The shale gas resources are mainly located in the Northeast, Gulf Coast, Mid-continent, Southwest,
Rocky Mountain and West Coast of the USA[51]. The source of this information does not employ the PRMS categories described in section 1.5 of this thesis. However, I infer that the majority of the resources are a combination of Prospective and Contingent Resources at “Best Estimate” and “2C” levels of confidence plus “2P” reserves under PRMS definitions.
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Submodule region Shale Shale play Shale gas play resources (trillion cubic feet)# Northeast Marcellus 410 Antrim 20 Devonian Low Thermal 14 Maturity New Albany 11 Greater Siltstone 8 Big Sandy 7 Cincinnati Arch 1 Subtotal 472 Percent of total 63% Gulf Coast Haynesville 75 Eagle Ford 21 Floyd-Neal & Conasauga 4 Subtotal 100 Percent of total 13% Mid-Continent Fayetteville 32 Woodford 22 Cana Woodford 6 Subtotal 60 Percent of total 8% Southwest Barnett 43 Barnett-Woodford 32 Avalon & Bone Springs 2 Subtotal 76 Percent of total 10% Rocky Mountain Mancos 21 Lewis 12 Williston-Shallow Niobrara 7 Hilliard-Baxter-Mancos 4 Bakken 4 Subtotal 43 Percent of total 6% Total onshore the Lower- 750 48 States Table 5.1 Shale Gas Distribution in the USA (# Central estimates of resources. The totals assume that the arithmetic addition of resources in individual areas is a reasonable approximation to the correct statistical addition)
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5.1.1 History
From 1627 to 1669, French exploration workers gave a description of the
“black shale” in the Appalachian basin[52]. This “black shale” refers to the
Devonian shale in Western New York.
The recognised start of the shale gas industry in the USA was 1821 when the Mitchell Company drilled the first shale gas well in the Durdirk shale in
Chautauqua County. The gas was produced from 26 feet thick shale section at a depth of 69 feet [53, 54]. Later, some rural areas in New York began to use shale gas for home lighting. Up to the 1880s, the eastern parts of the USA already had significant shale gas production. However, after the 1880s, the shale gas industry in the USA was relatively inactive.
In the late 1970s, because the oil price was high and unconventional oil and gas production was more technically feasible, shale gas exploration and development regained some momentum[55]. Shale gas exploration primarily focused on the Barnett Shale in the Fort Worth basin. The
Mitchell Company drilled several wildcat wells in the shallow horizons in this area. However, peak production from each well was small, and the output declined sharply. As a result, Mitchell transferred its drilling focus to the deeper shale. In 1981, Mitchell completed the first appraisal well and used nitrogen foam fracturing to make Barnett shale become the first
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modern shale gas field in the USA. In 1986, Mitchell finished collecting information on the Barnett[56]. It obtained data on porosity, total organic carbon (TOC), permeability and the fracture direction of the subsurface rocks. This laid a good foundation for future shale gas development. In
2000, Devon Energy company merged with Mitchell and became the biggest lease holder in the Barnett[55, 57].
Through two decades of progress, many technologies including hydraulic fracturing, horizontal well staged fracturing and synchronous fracturing has been developed[56]. These not only make better use of the shale resources but also reduce its development costs.
In the 21st century, shale gas technologies have been widely used. Now,
Michigan, Indiana, Appalachian, and other states have developed their shale gas resources. Shale gas companies have sprung up rapidly. In only two years from 2005 to 2007, the number of shale gas companies grew from 23 to 64[58].
5.2 Shale Gas Success in USA
The growth of shale gas in the USA is based primarily on its abundant shale gas resources. However, in addition, the field development model,
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financial support, the legal system and regulatory mechanisms have all played key roles.
5.2.1 Development Model
In the early 20th century, the shale gas developers were mainly small- scale energy companies. These companies continued to explore for shale gas, and some moved into the feasibility study stages. The larger companies were less prominent[59].
Since the beginning of the 21st century, shale gas production technologies matured and shale gas profits became much more visible. Large enterprises’ financial positions are more stable than the small developers.
They joined shale gas developments through joint ventures and through acquiring small shale gas companies[53, 60].
5.2.2 Support from Government
The USA government started to assist shale gas industries financially 30 years ago, and it has continued up to today. In the early 1970s, the USA
Department of Energy invested 100 million dollars into shale gas technology research[61, 62] and the federal government set up a special fund for unconventional resources research.
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In 2004, the USA passed the American Power Act. The USA government agreed to provide US$45 million per year to unconventional natural gas studies until 2014. With government financial support, shale gas technologies made significant breakthroughs.
5.2.3 Preferential Policy
The USA government has implemented many preferential tax policies to upstream development including tax breaks and favourable cost deductions. For example, in 1980, the federal government passed the
Crude Oil Windfall Profits Tax Act. This Act gave tax breaks to unconventional gas and oil drilling from 1979 to 1993 and production and sales before 2003. In addition to this, the shale gas industry also enjoys the preferential tax treatment of conventional oil and gas [61-63]. In some areas, the local governments do not levy any production tax from shale gas developers[64].
These preferential policies assist shale gas developers and help promote of shale gas developments.
5.2.4 Regulatory and Legal Systems
The USA shale gas industry is subject to state laws and federal regulation.
The American rules and regulations for traditional oil and gas
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development also apply to shale gas development. The Environmental
Protection Administration establishes most of the federal laws. The
Bureau of Land Management and Development and the Forest Service
Department are responsible for administering private land-use rights.
When there is a conflict between legislation and regulations, federal statutes take priority.
The federal government manages access to interstate pipelines and environmental standards governing the development of shale gas projects[65]. The States are responsible for managing the mining process.
Mining rights and land rights belong to different bodies. For private land, the developer must sign leasing contracts with the mining right holders.
For drilling and pipeline construction, the developer signs agreements with the landowner and applies for the licenses from the state governments[60].
For public land, the federal government does the planning. The private companies can obtain the mining rights through a public tender. However, the companies pay the corresponding mineral-use fee.
Concerning the shale gas related environmental issues, the USA government enacts all relevant regulations and permits[66].
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5.3 Benefits of Shale Gas Development in USA
Shale gas development in the USA has brought massive changes to both the national and the international energy market. This section analyses the effects of shale gas on these markets.
5.3.1 Energy Security
Shale gas development has enabled some traditional energy importing states, such as Pennsylvania and New York to achieve energy self- sufficiency. In fact, these States have become net energy exporters[67].
The imports of natural gas from Canada and of LNG (Liquefied Natural Gas) from the Trinidad have sharply decreased. Figure 5.1 shows that total natural gas imports fell from a peak of 4,608 Bcf in 2007 to just over 2,718
Bcf in 2015.
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5,000 4,500
4,000 3,500 3,000 2,500 2,000 1,500
Natural Gas in Imports Natural Bcf 1,000 500 0 1990 1995 2000 2005 2010 2015 Year
Figure 5.1 Natural Gas Imports to the USA from 1990 to 2015[67]
At the same time, the dependence on oil imports from has reduced.
Figure 5.2 shows that from 2005 to 2015, the imports of crude oil decreased from 3,696 Bcf to 2,683 Bcf. In 2011, the USA government announced that the import of crude oil is expected to decline by one-third in next ten years[68, 69].
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4,000
3,500
3,000
2,500
2,000
1,500
1,000 Crude Crude Oil in Imports bbl Million 500
0 1990 1995 2000 2005 2010 2015 Year
Figure 5.2 USA’s Crude Oil Imports from 1990 to 2015[67]
5.3.2 National Energy Market
The shale gas's upsurge has had an enormous impact on the conventional natural gas industry which is shown in Figure 5.3.
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2015 35 Histrory Projections
30
25 50%
20 36% Shale gas
15 Tight gas 10 Alaska Lower 48 onshore conventional Gas Production (trillion cubic feet) cubic (trillion Gas Production 5 Lower 48 offshore Coalbed methane 0 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 Year
Figure 5.3 USA’s Natural Gas Production by Source 1990-2040[37]
The share of shale gas production in total gas production reached 36% in
2015, and it is expected to increase to around 50% in 2040. By comparison, conventional natural gas’ share is expected to become smaller.
For instance, Figure 5.4 shows that conventional natural gas production in the Gulf of Mexico dropped from 4,194 Bcf in 2003 to 986 Bcf 2014. In that period, the number of natural gas drilling rigs fell from 170 to nearly
100[65].
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4,500
4,000
3,500
3,000
2,500
2,000
Production Production bcf in 1,500
1,000
500
0 2003 2005 2007 2009 2011 2013 Year
Figure 5.4 Conventional Natural Gas Production in the Gulf of Mexico from 2003 to 2014 [35]
The majority of USA shale gas production areas are now close to the ultimate consumers. This saves transport costs and transport times. This has helped the natural gas price to remain relatively low.
Because of the financial crisis in 2008, the demands of the international market decreased. Massive shale gas production has led to oversupply. As a result, the natural gas price fell. The wellhead price dropped from $7.97 per thousand cubic feet (per Mcf) in 2008 to US$2.66 per Mcf [68].
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9.0
8.0
7.0
6.0
5.0
4.0
3.0
2.0 (in $ per thousand cubic feet) cubic (in $ per thousand
USA natural gas wellhead price wellhead gas natural USA 1.0
0.0
Year
Figure 5.5 USA’s Natural Gas Wellhead Prices from 1990 to 2012 [70]
5.3.3 The World Energy Market
The development of shale gas in the USA has also changed the pattern of the world energy market.
A. The USA and Russia
The USA’s natural gas resource advantages have considerably improved the country’s position in the international energy market. In contrast, as the principal supplier of gas to Europe, Russia's natural gas production has
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reduced sharply. Shale gas development has helped strengthen the USA’s political and economic influence, whereas Russia's international influence has been weakened. In 2010, the state Duma (the Energy Committee of
Russia) held a roundtable called "Shale gas resources development prospects". The USA and Europe have started large-scale development of unconventional resources. Mr. Medvedev, who was prime minister of
Russian from 2008 to 2012, has called for a quick transformation to change Russia’s oil and gas export position.
B. International LNG Exports
Shale gas development in the USA has led to an oversupply of the gas to national market. In addition, the LNG demands of North America have decreased. Therefore, some international LNG projects are seeking new buyers. For example, Qatar’s 7.7 million tonne LNG project and Trinidad’s
LNG project are now looking to the Asia-Pacific region for new export markets[71]. They are looking especially to China, which is the biggest energy consumer in the Asia-Pacific region.
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C. Natural Gas Use.
The Energy Information Agency (the EIA) predicts that, because of its low carbon emissions, large-scale production, and falling price, natural gas could become the second-ranking primary energy resource by 2035[68].
5.3.4 Job Opportunities
Shale gas development not only carries direct job opportunities but also creates employment in other related industries. In Ohio, hotel, real estate, and catering all benefited from the surge in shale gas production.
According to America's Natural Gas Alliance, the shale gas industry will support 1.6 million jobs in 2035[72].
5.3.5 Demonstration Effects
The development of shale gas development in the USA has triggered interest in shale gas development globally. At present, more than 41 countries actively explore for and develop shale gas resources.
European countries have shown a high degree of enthusiasm for shale gas development, hoping to reduce their long-term dependence on Russian energy supplies. At present, many oil companies have begun exploring for shale gas resources in Europe, including X-Mobil, Chevron and
ConocoPhillips and Shell.
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China and India, as the big energy consumers, have vigorously promoted shale gas development to help solve energy supply issues. Through communication with the USA, now they all have begun to establish shale gas industries.
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Chapter 6 The Environmental Risks and Costs of
Shale Gas Development
Shale gas production in the USA and elsewhere has grown rapidly and provided economic benefits. However, the potential risks and environmental effects of past and future shale gas developments cannot be ignored. Burning natural gas leads to lower greenhouse gas (GHG) emissions than other fossil fuels. Nevertheless, shale gas development has significant environmental disadvantages.
Horizontal drilling and hydraulic fracturing technologies have been fundamental to the development of shale gas production. Shale reservoirs naturally have very low permeability and the oil and gas cannot flow easily.
Hydraulic fracturing involves injecting hydraulic fracturing fluid (consisting of water, chemicals, and proppants) at high-pressure into the wellbore to create cracks which provide pathways for gas and oil to flow more easily.
However, with the advent of hydraulic fracturing technology, the associated environmental risks have caused controversy.
The areas of environmental concern are listed below.
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A. Water consumption,
B. Water contamination
C. Greenhouse Gas (GHG) emissions,
D. Infrastructure risks,
E. Induced seismic activity.
This chapter discusses shale gas’ environmental hazards and estimates of the environmental costs of shale gas development (External Costs).
6.1 Water Consumption
There are two issues concerned with water consumption in shale gas developments. They are the total water used and the water supply.
6.1.1 Water Used
A large amount of water is used in shale gas developments in horizontal well drilling and the hydraulic fracturing processes. The amount of water consumption is determined by the depth of the well, the horizontal drilling length and the fracturing period[73]. Table 6.1 shows water consumption per horizontal well for different shale gas plays in Texas.
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Shale Play Units Range Average Value Barnett Million US gallons 0.75 - 5.5 2.8 Haynesville Million US gallons 0.7 - 7.4 5.7 Eagle Ford Million US gallons 1.2 - 8.9 4.3 Table 6.1 Water Consumption per Shale Gas Well in Texas[74]
Table 6.2 gives comparisons to make the amounts more meaningful. I take single horizontal well in the Eagle Ford as a reference. The annual water consumption of this shale gas well is almost four times that of a conventional gas well. In addition, it is equivalent to the average water consumption of 535 Chinese people or 78 Americans.
Units Value Average water use per vertical well Million US gallons 1.2 Average water uses per person per day in China US gallons 22 Average water uses per person per day in the USA US gallons 151 Table 6.2 Comparisons of Water Use[75]
6.1.2 Water Supply
The environmental risks of water supply to shale gas developments are significant if the water used is a large part of the total water resource and/or the total water consumption in the area. A shale gas development in an area with poor water supply could have a considerable effect on the local environment.
Table 6.3 gives the water consumption in different sectors in the location
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of major shale gas fields of the USA in 2011. In general, the water used in shale takes less than 1% of total water use. Therefore, the water use risks in these shale gas fields are relatively small.
Public Industrial Power Shale Shale play Supply and generation Irrigation Livestock gas Mining Barnett 82.7% 4.5% 3.7% 6.3% 2.3% 0.4% Fayetteville 2.3% 1.1% 33.3% 62.9% 0.3% 0.1% Haynesville 45.9% 27.2% 13.5% 8.5% 4.0% 0.8% Marcellus 12.0% 16.1% 71.7% 0% <0.1% <0.1% Table 6.3 Water Use as a % of Total Water Use in Major Shale Gas Fields in the USA in 2011[76]
However, the population density, rainfall pattern, the distance to the source of water, seasonal and other factors all affect the risks associated with shale gas water consumption. Therefore, we need to research and analyse information on individual shale gas development areas to have a comprehensive understanding of the economic and environmental effects by shale gas water consumption.
6.2 Water Contamination
Water contamination is a controversial issue, because potentially it can have dangerous consequences. The environmental assessments from the year 2000 to the year 2011 of most of the shale gas wells in the USA are positive[77]. However, some observers point out that shale gas
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development may cause water pollution in various processes. Figure 6.1 illustrates the possible causes of water pollution in a typical shale gas development.
Wastewater storage Water treatment
C B A
Drinking water aquifers
D
E Intermediate-depth formation G
Shale formations
Saline water formations F
Figure 6.1 Possible Sources of Water Contamination in Shale Gas Developments[78]
The possible sources are summarised below.
A. Leakage and spills from wastewater storage and open pits could contaminate surface and shallow ground water.
B. Waste water treatment water could discharge to the local stream.
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C. Leakage from storage ponds used for injection into deep wells.
D. During shale gas well casing, the stray gas from the shale formation could contaminate a shallow aquifer.
E. Stray gas generated in an intermediate-depth formation through leaks in the annulus of a well could pollute shallow water.
F. Migration of gas from saline water formations to a shallow water aquifer could affect the shallow aquifer.
G. Leakage from the injection well could contaminate a shallow aquifer.
In this thesis, I focus on water contamination caused by stray gas and fluid migration.
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6.2.1 Shallow Groundwater Contamination
There are two main causes of shallow groundwater contamination by stray gas. First, casing failure can lead to fluid leakage. Second, well cementation failure can create flow pathways between the casing pipe and reservoir layers[79, 80]. Some researchers have found that the concentration of methane can be high near an active shale gas well.
Osborn et al. investigated 68 fresh water wells near the Marcellus shale.
The research finds that the average concentration of methane in water was 19.2 milligramme/litre (5 mg/gal) in shale gas-extraction areas (that is, within 1 km = 0.62 miles of each well). This was 17 times higher than that in non-extraction areas (no gas wells within 0.62 miles)[81]. The geochemical analysis showed that the methane gas in the water had the same origin as the production gas. However, no fracturing fluid and high- salinity water were detected in the water samples. That suggests that the test could not prove categorically that the increased concentration of methane was directly caused by shale gas extraction.
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Jackson et al. expanded the sample size to 144 drinking water wells. They found that methane concentrations in gas-extraction areas were 6 times higher than in non-extraction areas. The ethane concentration was 23 times greater than in non-extraction areas. Propane was only detected in
10 wells in gas-extraction areas[79]. Warner et al. adopted the same method to research 177 drinking-water wells. However, the results showed there was no pollution caused by natural gas[81].
In conclusion, there is no direct evidence to prove that stray gas will cause shallow water contamination. We would need to compare baseline water data before and after gas extraction for more conclusive evidence[82].
Then we would need to investigate how gas extraction affects the shallow water resources.
6.2.2 Shallow Groundwater Contamination by Fluid Migration
There are two possibilities for contamination by fluid movement. These include (a) the connectivity between a shale reservoir and groundwater aquifers and (b) the driving force of upward migration.
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As regards connectivity, many observers consider that hydraulic fracturing cannot create pathways to the groundwater table. Conventional hydraulic fracturing operates in a shale bed which is typically more than 1 km (0.62 miles) deep, whereas the groundwater aquifer depth is typically less than
300 m (0.19 miles) deep. Therefore, the distance between shale gas reservoirs and groundwater aquifers is typically more than 700 m (0.43 miles). The development of fractured fissures is restricted by sealing rocks and fracturing fluid filtration[83]. Microseismic imaging shows that there is typically more than 1 km (0.62 miles) between shale gas reservoir fractures and the water aquifer [78, 84, 85].
As regards the driving force, the pressure of shale reservoir decreases after the fracturing fluid flows back and capillary forces restrict the fluid flow. As a result, fracturing fluid tends to be bound and stored in the shale gas reservoirs[86]
6.2.3 Flowback Fluid Management
The hydraulic fracturing process involves pumping fracturing fluid into the wellbore to increase pressure at target depth and this creates fissures in shale gas reservoir rocks. Fracturing fluids contain water, proppants and chemicals that could pollute groundwater[87]. Even a small portion of
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these chemicals could create hazards to ground water. Table 6.4 shows the typical composition of fracturing fluids.
Composition Constituent Example Purpose (% by vol) A “Proppant” for sand Water and 99.5 Sand suspension grains to hold micro sand fractures open Dissolves minerals and Hydrochloric or Acid 0.123 initiates crack in the muriatic acid rock Minimises friction Friction Polyacrylamide or 0.088 between the fluid and reducer mineral oil the pipe Increases the viscosity Surfactant 0.085 Isopropanol of the fracture fluid Creates a brine carrier Salt 0.06 Potassium chloride fluid Scale Prevents scale 0.043 Ethylene glycol inhibitor deposits in pipes Sodium or Maintains pH-adjusting 0.011 potassium effectiveness of agent carbonate chemical additives Prevents precipitation Iron control 0.004 Citric acid of metal oxides Corrosion n,n-dimethyl form Prevents pipe 0.002 inhibitor amide corrosion Minimises growth of bacteria that produce Biocide 0.001 Glutaraldehyde corrosive and toxic by- products Table 6.4 Volumetric Composition and Purpose of the Typical Constituents of Hydraulic Fracturing Fluid[87]
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After fracturing, some fracturing fluid would return to the surface. This is called flowback. The ratio of the flowback volume to the total injected fracturing fluid volume is the flowback rate.
There are large differences in flowback rates between individual shale gas fields. In the Barnett shale, the flowback rate is 30% to 50% of the injected fluid. However, the flowback rate is only 5% to 15% in the Haynesville shale[83]). Flowback water contains a high concentration of total dissolved solids (TDS) and sulphites. It also could contain metal as well as toxic non-metallic and radioactive elements. If a small volume of flowback water leaked to the surface water, the impact on water quality could be severe[46]. High salinity, diversity of pollutants and mixed composition all increase the difficulty of flowback water management.
Possible sources of contamination during flowback water management include those shown below.
A. Leakage during the water management process. These include, but are not limited to water storage tank failure and leakage during wastewater transport.
B. Negligent disposal without any treatment.
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C. Regular wastewater treatment plant might not entirely remove halogen, heavy metal and radioactive elements. This is referred to as substandard disposal.
In the Marcellus shale, water treatment eliminates 90% of Barium (Ba) and of Radium (Ra). However, the concentrations of Chlorine (Cl) and Bromine
(Br) downstream are significantly higher than in the upstream. Radioactive
Ra in the downstream is approximately 200 times larger than in the upstream, which would exceed the security standard[88].
In summary, shortcomings in flowback water management could lead to severe water pollution. However, the risk of these issues can be mitigated by optimising the water treatment technology and regulation systems.
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6.3 Greenhouse Gas (GHG) Emissions
GHG emissions in developing shale gas reservoirs arise from CO2 emissions from burning methane and methane emissions from equipment and vehicles. The latter produces CO2 when fuel is burned.
Figure 6.2 summarises the possible sources of GHG emissions in a typical shale gas development.
Development and Production Stage Well Liquid Well Equipment Processing Completion Removal 1 2 3 4
Transmission and Distribution Stage Gas Transport in Pipelines
5
Consumption Stage Burning Gas 6
Figure 6.2 Possible GHG Emission Sources in the Shale Gas Lifecycle
The potential sources of GHG emissions are summarised below.
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6.3.1 Well Completions
Howarth et al. (2011) considered that hydraulic fracturing could cause methane emissions when methane mixes with the flowback water. In addition, during the drill-out stage, more methane is emitted. They estimate that 1.9% of the methane from shale gas production might leak into the air during well completion[89]. However, some think Horwath’s research overestimates the leakage. The USA Environmental Protection
Agency estimated that the methane vented during well completion and workovers is from 0.006% to 2.75% of gas production (the mean is
0.46%)[90].
The GHG emissions from well completions and workovers remain uncertain. No-one gives firm evidence that quantifies the GHG emissions from these processes.
6.3.2 Equipment Leakage and Venting
During the gas recovery stage, equipment such as meters, dehydrators, and compressors all have the potential for methane and CO2 emissions. In addition, gas flaring for the power of equipment also produces CO2. The
EPA considers the methane emission ranges from 0.35% to 1.20% of total gas production. CO2 emissions range from 0.39g to 0.55g per mega joule
(MJ) of natural gas production[90].
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6.3.3 Emissions from Liquid Removal Operations
Removing liquids that are associated with methane production which builds up and prevent flow in wet gas wells could result in some of the methane escaping into the atmosphere. In conventional natural gas production, 0.27%-2.98% methane escapes[90]. In general, the majority of shale gas wells does not need liquid unloading. In some uncommon cases when shale gas needs liquid unloading, the methane emission is 0.02 to
0.26% of total production[89, 91].
6.3.4 Processing
Some natural gas contains heavy hydrocarbons and impurities such as sulphur gas. Before the natural gas is transported, it is treated to ensure that it meets quality standards. During treatment, CO2 vents at a rate of
0.83g - 1.08g per MJ of treated gas and methane is vented at a rate of 0.06% to 0.23% of treated gas[90].
6.3.5 Emissions in Gas Transport
Treated natural gas is transported by pipelines at high-pressure. Then it is distributed to consumers in low-pressure pipelines. During transmission and distribution, 0.29% to 1.05% of the produced gas leaks to the air[90].
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6.3.6 CO2 Emissions from Burning Methane
The methane produced from shale gas development will be burned by the final consumers. As a result, a large amount CO2 would be emitted to the atmosphere. This has an environmental impact and could attract a carbon emissions penalty.
6.4 Infrastructure Risks
In a study conducted by Graham (2014), in 2010-2012 the traffic accident rate in intensively drilled areas in North Pennsylvania was 15%-23% higher than in the less intensively drilled areas. Moreover, in 2010-2012 the truck crash rate in heavily explored areas was 61%-65% greater than in shale gas extraction controlled areas. The increasing traffic accident rate is mainly caused by road overload leading to road damage. In addition to traffic accidents, other accidents related to shale gas construction and operations are also significant.
6.5 Induced Earthquakes
Human-induced earthquakes have caused extensive concern. There is three shale gas development activities that could induce earthquakes.
A. The hydraulic fracturing technology used to extract gas.
B. The large amounts of fluid injected into disposal wells.
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C. The injection of wastewater into the subsurface.
Table 6.5 gives examples of the human-induced earthquakes that are large enough to be felt and might cause damage.
Earthquake Year Location Causes (magnitude) 2011 Youngstown, Ohio M4.0 Fluid injection 2010–2011 Arkansas M4.7 Fluid injection Dallas Airport M3.3 Fluid injection 2008–2009 Geysers Geothermal Field M4.6 Injection 1976–1984 Gazli, Uzbekistan, M7.2 Gas recovery 1962–1966 Rocky Mountain Arsenal M5.3 Fluid injection 1945–1995 Rangely, CO M4.9 Injection Table 6.5 Examples of Human-Induced Earthquakes[92] (M-Richter Magnitude Scale)
According to the United States Geological Survey (USGS), the potential for earthquakes has been increased by human activities in some regions of
USA. In particular, California, Oklahoma, Kansas, Texas, Colorado, New
Mexico, and Arkansas have a high risk of damaging earthquakes. USGS concludes that the primary reason for earthquakes in these areas is wastewater disposal[93].
6.6 Water Costs
I apply the water use costs equation below to estimate water use costs.
Water use costs(Wc) = water use(bbl.) per well * total number of wells *
the value of water per bbl (Equation 6-1)
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In some areas of water scarcity, the value of water cannot be represented by the local price of water. In the Eagle Ford, farmers have become worried about the future of their water supply. For instance, in 2012, the farmers refused to sell water to the shale gas companies at a price of
US$0.75 per gallon, which is 50% higher than US$0.50 per gallon that applied in 2011. However, there are no price guidelines as regards water use for fracturing. In water shortage areas, shale gas developers need to transport water by pipelines or trucks from other water abundant areas.
As a result, the price of water would increase. However, if the water used by shale gas represents a small part of the total water resource, the price of water is likely to be equal to the local water price. Table 6.6 illustrates the water costs that might apply. In the Fuling project, which l analyse in another chapter, shale gas water consumption is less than 5% of the total water resources in the area. Therefore, I assume that the price of water is equal to the local industrial water price US$0.07 per bbl.
Total water uses for shale as percentage of total water resource in the region Description
0%-5% 100% local water price 5%-10% 200% local water price 10%-20% 300% local water price more than 20% 500% local water price Table 6.6 Price of Water in Regions with Different Water Resources.
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6.7 Flowback Water Handling Costs
The assumed flowback water handling process in Fuling is illustrated in
Figure 6.3
Source Fracturing Flowback Reuse Well A water fluid water treatment
Source Fracturing Well B Flowback Reuse water fluid water treatment
Source Fracturing Flowback Reuse Well C water fluid water treatment
Source Fracturing Flowback Recycle
Well D water fluid water Treatment
Figure 6.3 Water Handling in a Shale Gas Development
There are two ways in which flowback water can be handled.
A. The flowback water is treated and re-used. The treated water is blended with additional source water and the system is designed to meet the chemical standard of fracturing water.
B. The recycling process removes all suspended and dissolved materials from the flowback which ensures that the water has high quality. Treated water is directly discharged to a surface aquifer or used in other industries.
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First, developers purchase water from water works. Then, the pure water is mixed with chemicals before being injected underground. When the fracturing process is finished, part of the fracturing fluid flows back to the surface. Flowback water from fracturing is passed through preliminary treatment facilities near the rig. This is re-used by other wells belonging to the rig pad. After all wells on the rig pad have been completed, all the flowback water is sent to a water treatment plant for recycling.
I assume that flowback water handling costs are estimated using the equation in Figure 6.4.
Flowback Handling Costs (Equation 6-2)
Waste water treatment facility costs
plus Treatment costs
plus Transport costs
equals Flowback handling costs
Figure 6.4 Flowback Handling Costs
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The wastewater treatment facility includes a water treatment plant. I assume that the water treatment plant for a 200-well shale gas field costs
US$15 million and that the total the equipment cost is US$5 million in
2014
The total treatment costs are obtained by multiplying the volumes of treated water by the costs for different handling methods including re-use, recycling and disposal.
The transport cost equals the unit transport costs multiplied by corresponding water amounts and distances to the destinations.
I assume the components of water management costs in Table 6.7 in real
US$2014 terms)
Components Units P90 P10 Mean Source Water use per well kbbl 18 130 63.5 [74] Reuse water treatment cost US$/bbl 1.00 2.00 1.4 [94] Recycle water treatment cost US$/bbl 3.50 6.25 4.7 [94] Transport cost US$/bbl/mile 0.02 0.04 0.03 [94] Table 6.7 Components of Water Management Costs
6.8 CO2 Emission Costs
In order to evaluate the cost of CO2 emissions, I assume a carbon tax/penalty, which is a form of pollution tax. The CO2 emission costs are calculated as shown below.
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CO2 emission costs = Carbon tax rate(Carbon penalty) * CO2 emission
weight (Equation 6-3)
Where,
The CO2 emission weight (in tonnes) refers to the total CO2 emissions from gas production and from burning natural gas by final consumers.
Currently, a carbon tax is not levied in China. However, it is likely to be introduced in the future.
The carbon penalties are different in different countries. In 2010, India applied a nationwide carbon penalty at a rate US$1.07/tonne. By the end of 2014, this increased to US$1.6/tonne[95]. Sweden introduced a CO2 tax of US$100/tonne in 1991. The tax rate increased to US$114/tonne in 2007 term[96]. For the analyses in this thesis, I estimate the P10 and P90 CO2 penalties to be US$1.6 and US$114 per tonne.
The CO2 emission assumptions used in my analyses are shown below in
Table 6.8.
Components Units P90 P10 Mean Source
CO2 emissions from burning gas kg/Mcf NA NA 54.12 [97]
CO2 emissions during production kg/Mcf 1.05 1.77 1.42 [98] Table 6.8 Components of CO2 Emission Costs
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6.9 Methane Emission Costs
Compared to CO2, methane has a shorter lifetime in the atmosphere.
However, the same volume of methane can heat the atmosphere 25 times more than CO2 in a 100 year period[99]. Furthermore, methane as an odorous and soluble gas might affect peoples’ lives by its smell and through water pollution.
In this thesis, methane costs are total methane emissions multiplied by a methane emission penalty.
The total methane emissions assumptions for a shale gas field are based on Andrew Burnham et al.'s research[97]. As shown in Table 6.9 below, total methane leakage is in the range 0.71% to 5.23% of total production by volume.
Units P90 P10 Mean (by volume) Well completion and workover % of production 0.01 2.75 0.46 Well equipment % of production 0.35 1.20 0.73 Processing % of production 0.06 0.23 0.15 Transport and distribution % of production 0.29 1.05 0.67 Total % of production 0.71 5.23 2.01 Table 6.9 Methane Emissions during a Shale Gas Development [97]
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The components of methane costs used in my analyses are summarised in
Table 6.10 in real US$2014 terms)
Components Units P90 P10 Mean Source Methane emission penalty US$/Mcf 20 100 53.2 Estimated Methane emission rate % 0.71 5.23 2.5% [97] Table 6.10 Components of Methane Costs
6.10 Infrastructure Maintenance
Roads are the infrastructure most directly affected by shale gas activities.
Therefore, in this thesis, I include road maintenance costs as part of the
External Costs of shale gas development.
Road maintenance costs = length of road * maintenance fee per
unit road length (Equation 6-4)
Where,
The length of road refers to the length of roads which construction vehicles use frequently.
The maintenance fee per unit length is 3% of the construction costs per unit length of the road.
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6.11 Compensation
Water management aims to reduce water pollution. A CO2 emission tax or penalty imposes a cost on CO2 emissions at all stages of the production and consumption.
However, shale gas developments would also affect people's lives and health by (a) land occupation, (b) air pollution, (c) transport, (d) accidents and (e) the potential risks of induced earthquakes. To take into account these additional External Costs, I assume an overall compensation cost.
The calculation of the compensation cost is shown in Figure 6.5.
Compensation(Equation 6-5)
The affected area
Multiplied by Population density
Multiplied by Compensation for per person
equals Total compensation
Figure 6.5 The calculation of Compensation
I assume that the affected area is within 0.62 km (1 mile) of the area in which shale gas wells are located. I also assume that the population density is the average population density in the area.
Yongjian Zhou August 2016 The economics of shale gas development in China Page 6.26
Two conditions affect shale gas compensation. First, all land belongs to the government (the Chinese people). Second, the population density in
China is very high. Many authors assume compensation related to local conditions. Several factors are important.
The use of local facilities is a matter of debate. For example in the UK, the affected communities received compensation of 100,000 British pounds plus 1% of the total revenue from the well in 2014 [100, 101]. However, this policy does not consider the population factor and the levels of local income. The British people living close to the shale gas wells believed that they should have received more compensation.
In my analyses, I assume a range of compensation levels that take into account the level of local incomes and medical costs.
Table 6.11 gives the assumed average compensation for person per year and Table 6.12 shows the compensation that might apply in the area of the Fulling shale gas development discussed in another chapter.
Yongjian Zhou August 2016 The economics of shale gas development in China Page 6.27
Impact level Description Calculation During a shale gas 10% of average development, there is little residents' annual Small effect effect on resident’s life. income per year
Water and air quality are 20% of average affected by shale gas residents' annual development slightly. income per year Normal effect However, the water quality still reaches the nation standard. Water and air quality are 30% of average influenced. The health of residents' annual residents decrease. Therefore, income + 100% of the Large effect the sickness rate increases. average medical expenditure of local people per year Table 6.11 Hypothetical Average Compensation Assumptions for People Living close to Shale Gas Fields in China
Income level Low(Income Median(Income High(Income US$1000 and US$2000 and US$3000 and Effect level medical costs medical costs medical costs US$100) US$200) US$300) small US$100 US$200 US$300 Normal US$200 US$400 US$600 Big US$400 US$800 US$1200 Table 6.12 Compensation Effect/Income Matrix for China (in real US$2014 term)
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6.12 Disaster Costs
In this thesis, compensation does not take into account the worst/disaster cases including deaths by induced earthquakes. If these events happen, the results are cannot be quantified easily in monetary terms. It is possible that the risks and costs of such events could significantly outweigh the benefits of shale gas development completely.
Yongjian Zhou August 2016 The economics of shale gas development in China Page 7.1
Chapter 7 Fiscal Regime
In China, the existing shale gas developers are state-owned. These enterprises not only pursue their own economic interests but also bear a lot of social responsibilities. These social responsibilities include assisting the national economy, helping to solve employment issues and fulfilling national strategies. As the result, tax policy is designed specifically for these companies’ activities.
China has not established a fiscal policy for non-state companies that might develop shale gas in the future. For the analyses in this thesis, I assume a hypothetical shale gas fiscal regime that combines the conventional gas fiscal regime in China and the tax regime as it applies to
Sinopec’s operations.
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7.1 State-Owned Enterprises (SOEs)
SOEs refer to the companies with more than 50% government ownership.
In China, SOEs are companies that are totally controlled by the central government.
From 1979 to 2000, China’s government vigorously supported SOEs. The majority of government tax revenue is funded by SOEs. As a result, a large number of SOEs were established in this period. In addition, some government departments were converted into to SOEs. For example, in
1988, the Ministry of Oil was converted into two SOEs, these being the
China National Petroleum Corporation (CNPC) and the China National
Offshore Oil Corporation (CNOOC). Both of them have since come under the control of the State Council [102].
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7.2 Upstream Fiscal Structure
Figure 7.1 gives the hypothetical structure of the upstream shale gas fiscal regime in China
Cash flow to Government take Company take project
Upstream revenue
Resource and other Resource and other taxes taxes to government
Costs recovery to Costs recovery company
Profit gas to Profit gas company
Income Tax to Income Tax government
Total costs
NCF to company
Figure 7.1 Structure of the Hypothetical Upstream Shale Gas Fiscal Regime in China
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The beginning of the flow chart is at the top left - Upsteam Revenue. Then,
Resources Tax, Educational surtax, Urban Maintenance and Construction
Tax are deducted. After that, companies recover their costs during development. The remaining revenue after tax payment and cost recovery is profit gas. In China, all of the profit gas profit goes to the developers.
Finally, the developers pay Income Tax to the government. The net cash flow (NCF) of the company is equal to cost recovery plus profit gas minus
Income Tax and operating costs.
The calculations below show an example of calculation of company’s NCF in a single year under the shale gas fiscal regime. The assumptions for the calculations are below.
A. Gas production is 200 MMcf/d and the methane price is US$ 10 per Mcf
B. The resource tax rate is 5%.
C. VAT is US$ 50 million. This is only used to calculate other taxes. It is not directly levied by the government.
D. The Urban maintenance and construction tax rate is 5% of VAT.
E. The Education supplementary tax is 1% of VAT.
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F. For Figure 7.1, I assume that there are no capital cost and abandonment cost in the year. The operating cost is US$ 50 million.
G. The Income Tax rate is 25%.
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Upstream Revenue Units Value Explanation Gas production MMcf/d 200 Example data Gas price US$/Mcf 10 Example data Upstream revenue US$MM 730 Production*price*365 days Resource tax and others Upstream Revenue US$MM 730 From above Resource tax US$MM 5% 37 Revenue*tax rate VAT US$MM 50 Example data Urban maintenance tax US$MM 5% 2.5 VAT*tax rate Educational tax US$MM 1% 0.5 VAT*tax rate
Total resource tax and others US$MM 40 Sum resource tax Urban Maintenance Tax and Education Tax Cost recovery Upstream revenue US$MM 730 From above
Available costs to recover US$MM 691 Upstream revenue-Total resource tax and others Opex this year US$MM 50 Example data Capex this year US$MM 0 Example data Unrecovered costs from last year US$MM 0 Example data Total costs to recover US$MM 50 Sum three items above The minimum of Total costs to Total cost recovery US$MM 50 recover and Available costs recovery Profit gas Upstream Revenue US$MM 730 From above Total resource tax and others US$MM 40 From above Total Cost recovery US$MM 50 From above Total profit gas US$MM 641 Upstream Revenue-Total resource tax and others-Total cost recovery Income Tax Total profit gas US$MM 541 From above Income Tax US$MM 25% 135 Total profit gas*tax rate Company's net cash flow Upstream US$MM 730 From above Total resource tax and others US$MM 139 From above Opex this year US$MM 50 Example data Capex this year US$MM 0 Example data Income Tax US$MM 135 From above Upstream Revenues-sum of above 4 Company's net cash flow US$MM 406 loss
Government take US$MM 175 Sum the resource tax and other taxes and Income Tax Table 7.1 Simplified Example of the Hypothetical Shale Gas Fiscal Regime
Yongjian Zhou August 2016 The economics of shale gas development in China Page 7.7
7.2.1 Urban Maintenance and Construction Tax
According to the "Urban Maintenance and Construction Tax Temporary
Regulations of the People's Republic of China", the “Urban Maintenance and Construction Tax” has three rates depending on the situation. The details are shown in Table 7.2.
Regions Rates Urban 7% of VAT County, town 5% of VAT Except for Urban, County, and Town 3% of VAT Table 7.2 Urban Maintenance and Construction Tax Rates [103]
In Table 7.2, the Value Added Tax (VAT) is a tax on the value added to a commodity or service. The State Council of China stipulates the VAT rate in onshore petroleum, gas and offshore oil are 17%, 13% and 5% respectively[104].
VAT is also a deductible tax. In a shale gas development, the deductible rate for exploration costs is 100%, and the deductible proportion of operating costs is 50%.
Therefore, the VAT equation in shale gas field is,
The value of VAT = (Revenue - 100% * Capex + 50% * Opex) * 13%
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In the Chinese shale gas industry, VAT is only used to calculate Urban maintenance and construction tax and Educational tax. It does not occur in cash flow.
7.2.2 Educational Surtax
The educational surtax is an additional tax which contributes to developing the local education industry. For oil and gas companies, the educational surtax is 3% of VAT.
7.2.3 Resource Tax
China’s government impose the resource tax to promote companies rationally develop resources and increase the economic income.
In 2015, the Ministry of Finance and National Tax Bureau issued a "Notice
Regarding the Adjustment of the Oil and Gas Resource Tax Rate ". It declared that the Resource Tax for a shale gas field would be 5.39% of sales revenue[105].
7.2.4 Cost Recovery
Companies are allowed to cover capital costs and operating costs occurred in a year. In addition, uncovered costs can be carried forward. There is no cost recovery ceiling.
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7.2.5 Income Tax
In China, the Income Tax rate is 25%. However, in 2011 the Ministry of
Finance and the State Taxation Administration jointly issued a statement entitled "Concerning the Fiscal Policies of Western Development Strategy".
The strategy states that the Income Tax rate will be 15% in West China including Chongqing, Sichuan,Guizhou, Yunnan, Tibet, Shanxi,Gansu,
Ningxia,Qinghai and Xinjiang,etc. The Fuling development analysed in this thesis is in the western area and so I have assumed a tax rate of 15%.
7.3 Mid-Stream and Down-Stream Tax
Insufficient data is available in the public domain to model mid-stream and down-stream taxation accurately. Therefore, as a first approximation,
I have calculated annual mid-stream and down-stream tax as set out below.
Mid-stream and Downstream Tax = (Methane Sale Revenue - Costs) * Tax rate
Where,
Methane Sale Revenue = Final sale (terminal) price * Total selling methane
Costs = Operating Costs + Costs of purchasing methane from the upstream operations
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Tax rate = 25%
Yongjian Zhou August 2016 The economics of shale gas development in China Page 8.1
Chapter 8 Case Study
8.1 Introduction
The economic analyses in this thesis are based on data concerning the
Fuling shale in the Fuling District of the Chongqing Municipality in central
China. Figure 8.1 shows the location of Fuling shale and Figure 8.2 displays the extent of the complete development as planned. The Fuling shale gas field is in the Sichuan Basin. China Petroleum & Chemical Corporation
(Sinopec) operates the field and envisages developing it in stages.
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Figure 8.1 General Location of the Fuling Shale
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Figure 8.2 First Stage of Fuling Shale Gas Field[3]
The Fuling shale first stage construction area is in the Fuling District of the
Chongqing Municipality. The west and north boundaries reach to the
Yangtze River. The southern boundary reaches to the Wu River, and the eastern boundary is the administrative boundary of the mining right. The average temperatures range from 15 to 17 . Transport in this area is reasonably developed. Railways, shipping℃ and℃ road transport, are all available [106]. The second stage of construction has not started. If the first stage of the Fuling shale project is successful, Sinopec will apply to
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develop more areas near the first phase. The exploration area is 7,308 km2
(2,822 mile2) which contains Nanchuan, Wulong, Fengdu, Changshou,
Dianjiang, Fuling, Zhong, Wan and liangping county. If the exploration results are satisfactory, the Fuling shale gas project will have more than
6,000 wells. However, in this chapter, I analyse only the first stage of the development, which has 208 wells planned.
8.1.1 History
The exploration and development of the Fuling shale started in 2009. Its exploration and development history can be divided into three stages.
(A) First Phase - Exploration (2009-2012)
Sinopec’s exploration for shale gas was an important strategy for the company. In 2009, the Southern exploration branch of Sinopec established a research department and began to explore the Sichuan Basin.
In 2011, the Southern exploration branch of Sinopec selected Jiao Shiba as the most likely economic development area. In 2012, the Jiaoye 1 vertical well was drilled. After drilling Jiaoye 1, Sinopec selected a depth of 2,400m as the target layer for a horizontal well and began to drill the Jiaoye 1HF well[3, 107].
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In October 2012, the Jiaoye HF1 well was completed. The production rate on test reached 200,000 m3 per day (7 MMcfd). In 2013, daily production stabilised at 60,000 m3 per day (2 MMcfd) and the casing pressure was about 20Mpa. The cumulative production in 2013 was 3,800,000 m3 (134
MMcf).
(B) Second phase - Pilot Project (2013-2014)
Based on the performance of the Jiaoye HF1 well, Sinopec developed a pilot project based on ten rig platforms and 26 horizontal wells.
The pilot project had three primary targets. These are listed below.
A. To determine the length of horizontal wells, that would maximise resources.
B. To test the effects on production of different fracturing designs.
C. To determine a reasonable well production rate[108].
In 2014, the daily production was between 50,000 and 300,000 m3 /d
(1.8MMcfd and 10.6 MMcfd) per well. The casing pressure was between
15 and 33 Mpa.
(C) Third phase – First Stage Development (2014 onwards)
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In 2014, Sinopec finalised the “Fuling shale gas field Jiaoshiba area first stage production scheme” and started construction. By the end of 2015,
Sinopec predicted that cumulative gas production for this stage would reach 50×810 m3 (177 Bcf)[107].
8.1.2 Geology
The Fuling shale is marine-deposited, black shale of the Upper Ordovician- lower Silurian age. The shales in this area are widespread and thick[109].
The total organic carbon content of the shale is 2.1% to 6.3%, and its thermal maturity is high[110]. Table 8.1 sets out the main geological properties of the Fuling shale and compares them with those of key shale plays in North America.
District Fuling Haynesville Marcellus Barnett Thickness(ft) 125-262 197-295 49-197 98-590 TOC 2.1%-6.3% 0.5%-4.0% 3.0%-12% 4.50% R0 2.2%-3.0% 1.2%-3.0% 1.2%-3.5% 1.0%-2.1% Porosity 2.5%-7.1% 4.0%-14 4.0%-12% 4.0%-6.0% Gas Content (m3*/t) 4.7-7.2 2.8-9.3 1.7-4.2 5.5-9.9 EUR (108m3) 1.1 1.6 1.0 1.2 Table 8.1 Geological Properties of Fuling shale and Other Shale Gas Fields in North America[111]. “EUR” means Expected Ultimate Recovery.
The source of this information does not explicitly employ the PRMS categories described in section 1.5 of this thesis to derive EUR estimates.
However, I infer that the majority of the resources are a combination of
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Prospective and Contingent Resources at “Best Estimate” and “2C” levels of confidence under PRMS definitions.
8.1.3 Resources
The Fuling district has abundance mineral resources and biological resources. In this study, shale gas resources and water resources are two primary resources types which affect shale gas development.
A. Shale Gas Resources
Fuling shale (First stage)'s resources data is shown below,
Total gas bearing area-263 km2 (49.92 mi2)
Total gas in place is 1,947×108 m3 (6,875.7 bcf)
Technically recoverable Prospective and Contingent Resources (Best
Estimates and 2C) are 500×108 m3 (1,765.7 bcf)
Proven Reserves (2P) are 278×108 m3 (981.74 bcf)[3]
B. Water Resources
Fuling,as the first business development shale gas field has local water recourses. Fuling is located at the intersection between the Yangtze and
Wu River and the centre of the Three Gorges reservoir. That means Fuling is one of the most abundant areas in China for water supply. Water
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shortages in this area are almost non-existent. All water for shale gas development in Fuling is purchased from the Baitao water works which is sourced from the Wu River.
8.1.4 Well Spacing
The factors below determine the well spacing in the First Stage
Development of the Fuling shale[108].
A. The wells should access as much of the resource as possible
B The horizontal section of the horizontal wells is perpendicular to the direction of principal stress.
C. The distance between the horizontal sections of two wells is either
800m (2,625 ft) or 1,000m (3,281 ft).
D. Wells are drilled from drilling pads in clusters.
E. Four wells belong to one drilling pad. Figure 8.3 shows the well spacing pattern for a 1,000m well spacing[3].
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Figure 8.3 Well Spacing Pattern [3]
8.1.5 Number of wells
Sinopec deployed 51 drilling pads and drilled 169 horizontal wells in this area between 2013 and 2015[3].(see Table 8.2)
Item Units Value Area for production wells km2(mi2) 208(80) Drillin pads Number 51 Wells completed in 2013 Number 20 Wells completed in 2014 Number 68 Wells completed in 2015 Number 81 Table 8.2 Number of Wells Drilled up to 2015 in the First Stage Development of the Fuling Shale[3]
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8.1.6 Pipelines
The total length of the pipelines in the First Stage Development of the
Fuling shale is 50 km (31 miles). This includes 30 km of main pipelines and
20 km (12.4 miles) branch pipelines. The pipeline layout is shown in Figure
8.4[3]. The total cost of pipelines was 18,000,000 yuan (US$2.86 million in
2011 terms). The natural gas is transported from the dehydration station to the Chuangdong natural gas pipeline for subsequent sale to East China.
(See Figure 8.3)
Figure 8.3 Gas Pipelines Layout for the First Stage Development of the Fuling Shale[3]
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8.1.7 Waterlines
The layout of the water pipelines (waterlines) is roughly as same as the gas pipelines. They follow similar pathways. The layout of the main waterlines are shown in Figure 8.5[3]. The total costs of waterlines are
11,000,000 yuan (US$1.75 million in 2011 terms) (see Figure 8.4)
Figure 8.4 Waterlines layout for the First Stage Development of the Fuling Shale[3]
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8.1.8 Roads
First Stage Development of the Fuling shale is located in Jiaoshi and Baitao
Counties. It is surrounded by three roads. They are the X182 county road in the east, the S105 provincial road in the north and 319 national roads in the southwest. According to the development plan, a main in-field road is needed running through the gas field. The length of the main road is 42 km (26 miles)[3], In addition, the length of the roads for each drilling rig is
1km (0.62 miles). Figure 8.6 illustrates the location of the main road.
Figure 8.5 The Roads layout for the First Stage Development of the Fuling Shale. Economic Assumptions [3]
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8.2 Economic Assumptions
I use the first stage of Fuling shale gas project as the subject of my economic analyses. The analyses include the upstream, midstream and downstream components of the project. The costs analysed are “Supply
Chain Costs” and “External Costs”. “Supply Chain Costs” are the costs that
“Supply Chain Companies” incur directly on project development and operation. “External Costs” refer to costs that are not usually incurred by
Supply Chain Companies. These are the indirect environmental and other costs associated with shale gas development. Table 8.3 itemises Supply
Chain Companies’ costs and External Costs.
Based on projected revenues and costs, I obtain the net cash flows (NCFs) and the net present value (NPV) of shale gas development. I use lognormal distributions for all the inputs. I generate probability distributions of NPV based on Monte Carlo simulation using 5,000 iterations.
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Exploration Costs Appraisal Costs Costs Development Costs
hain Operating Costs C Transmission and Distribution Costs Abandonment Costs Supply Supply Fiscal Costs(Taxes) Water use costs Water contamination costs
CO2 emission penalties from burning methane Methane leakage penalties Road maintenance
External Costs External Central subsidies Compensation Table 8.3 Detailed Supply Chain and External Costs
8.2.1 Production
I base the initial field production for the First Stage Development on the actual production in the Fuling shale in 2014. The decline rate and the decline exponent for a single well are based on data from Sinopec (see
Table 8.3)
Units P90 P10 Mean Source Initial production MMcfd 1.5 3.5 2.1 [3] Decline rate % 36% 59% 47% [112] Decline exponent No 0.34 0.93 0.54 [112] Table 8.4 Variables of Production Assumptions for a Single Well in Fuling
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Based on the mean estimates in Table 8.4, the production profile for a single well over 20 years is shown in Figure 8.6. The mean production for a single well in the first year is 2.1MMcfd and it decreases to 0.2MMcfd after 20 years.
4.0
3.5
3.0
2.5
2.0 P10 1.5 Mean P90 1.0
Single Well Production (MMcf/d) Production Well Single 0.5
0.0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Year
Figure 8.6 Single Well Production Profile based on Mean Parameters
Based on the production assumptions above and the plan of well drilling in the First Stage Development of the the Fuling shale, Figure 8.7 and 8.8 gives the details of the production from the First Stage Development in
Fuling. The mean value of my estimate of the total field output is 15 Bcf in
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2013. After more wells have been completed, the total field production is expected to increase to 104 Bcf (285 MMcfd) in 2015. After that, the total field production declines. By the end of the year 2032, the total annual production decreases to 6 Bcf (16 MMcfd) and the cumulative production from the start of production is 539 Bcf.
120 P10
100 Mean P90
80
60
40
Field Field in annual production Bcf 20
0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Year
Figure 8.7 Annual gas production in the First Stage Development of the Fuling shale.
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700
600
500
400 P10 300 Mean P90 200
Cumulative production production Bcf in Cumulative 100
0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Year
Figure 8.8 Cumulative Production in the First Stage Development of the Fuling shale.
8.2.2 Methane Price
The methane prices assumed in the analyses are set out in Table 8.5. The field gate price is the price at which upstream companies sell methane to gas transmission companies. The terminal price is the price at which gas transmission and distribution companies sell methane to final consumers
(See Figure 8.9).
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Units P90 P10 Mean Subsidy US$/Mcf 0.5 2 1.16 Field gate methane price US$/Mcf 6 12 8.80 Terminal methane price US$/Mcf 8 16 11.74 Table 8.5 Methane Price Assumptions
Field gate price Terminal price
Residential use
Vehicle fuel
Industrial use and export
Upstream Transmission and development Distribution Final consumption
Figure 8.9 The Locations of the Field Gate Price and the Terminal Price
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8.2.3 Revenues
Estimates are shown for the initial years only. All prices and costs are in real 2014 terms.
Revenue (US$ 2014) Unit P90 P10 Mean 2011 2012 2013 2014 2015 2016 Methane production Bcf 15.39 62.42 103.80 70.57 Losses % 5% 5% 5% 5% Remaining production Bcf 14.62 59.30 98.61 67.04 Subsidy US$/Mcf 0.5 2 1.16 1.16 1.16 1.16 1.16 Gate station price US$/Mcf 6 12 8.80 8.80 8.80 8.80 8.80 Terminal price US$/Mcf 8 16 11.74 11.74 11.74 11.74 11.74 Methane Sales Revenue US$MM 171.64 696.17 1157.68 787.07 Supply Chain Revenue US$MM 188.57 764.81 1271.82 864.67 Revenue (US$ 2014) Explanation Methane production Estimated methane production in the year Losses Some methane production is used or lost during production. Remaining production The volume of gas production which is sold Subsidy The central subsidy for upstream companies Gate station price The price at which midstream companies buy methane from upstream companies Terminal price The price at which consumers buy methane Methane Sales Revenue Remaining methane production * the real terminal price Supply Chain Revenue Remaining methane production * (Subsidy + the real terminal price) Table 8.6 Revenues for the First Stage Development of the Fuling Shale Project
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8.2.4 Upstream Costs
The Tables 8.7 to 8.9 present the detailed upstream costs assumptions used in my economic analyses of the First Stage
Development of the Fuling shale. The calculations are shown for the initial years only. All prices and costs are in real 2014 terms. The real abandonment costs are assumed to be 15% of the cumulative real development costs. The mean of real abandonment costs is US$382MM in US$2014 terms and the mean of the nominal abandonment costs is US$883MM in
2040.
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Exploration & Appraisal Costs (US$ 2014) Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 Seismic survey area mile2 134 134 Costs per square mile US$MM 0.05 0.20 0.12 0.12 Seismic exploration costs US$MM 16.08 Number of appraisal wells No 8 8 Cost per appraisal well US$MM 8 22 14.34 14.34 Total appraisal costs US$MM 114.72 Exploration & Appraisal Costs (US$ 2014) Explanations Seismic survey area Actual 3D seismic survey area in Fuling by Sinopec Costs per square mile Assumed 3D seismic survey costs per square mile Total exploration costs Seismic survey area * costs per square mile Number of appraisal wells Number Cost per appraisal well Assumed costs of each appraisal well Total appraisal costs Number of appraisal wells * Cost per appraisal well Table 8.7 Real Exploration and Appraisal Costs for the First Stage Development of the Fuling Shale Project
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Real (US$2014) Development Costs Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 Number of development wells No 20 68 81 Costs per development well US$MM 8 22 14.34 14.34 14.34 14.34 Total costs of development wells US$MM 286.80 975.12 1,161.54 Unit facilities costs per well US$MM 0.5 1 0.73 0.73 0.73 0.73 Total facilities costs this year US$MM 14.60 49.64 59.13 Cumulative facilities costs US$MM 14.60 64.24 123.37 123.37 Total development costs US$MM 301.40 1,024.76 1,220.67 Real (US$2014) Development Costs Explanations Number of development wells The number of development wells each year Costs per development well Assumed costs of drilling, fracturing and completing a single well Total costs of wells Number of wells * cost per well Unit facilities costs Assumed surface facilities costs including in-field roads, vehicles, dehydration etc. Total facilities costs this year Facilities costs * number of development wells Cumulative facilities costs Total facilities costs from project begin + Total facilities costs this year Total development costs Total costs of wells + Total supporting facilities costs Table 8.8 Real Development Costs for the First Stage Development of the Fuling Shale Project.
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Annual Operating Costs (US$2014) Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 Maintenance costs % 3% 3% 3% 3% 3% Cumulative facilities costs US$MM 14.60 64.24 123.4 123.4 Total maintenance costs US$MM 0.438 1.927 3.701 3.701 Materials and salaries US$MM/well 0.1 0.2 0.15 0.15 0.15 0.15 0.15 Cumulative number of wells No 20 88 169 169 Total materials and salaries US$MM 3.00 13.20 25.35 25.35 Management fees US$MM/Bcf 0.1 0.4 0.23 0.23 0.23 0.23 0.23 Total management fees US$MM 3.54 14.36 23.87 16.23 Total annual operating costs US$MM 6.98 29.48 52.93 45.28 Annual Operating Costs (US$2014) Explanations Maintenance costs Maintenance costs as a percentage of cumulative capital costs of facilities Cumulative facilities costs The capital costs of existing facilities(from Table 8.8) Total maintenance costs Maintenance costs * cumulative facilities costs Materials and salaries Average material and salaries per well per year Cumulative number of wells The number of wells available each year Total materials and salaries Materials and salaries * cumulative wells Management fees Management fees based per unit of methane production Total management fees Mean of methane production estimates (Table 8.6) * total management fee Total Annual Operating Costs Sum of total maintenance costs, materials and salaries and management fees Table 8.9 Real Annual Operating costs for the First Stage Development of the Fuling Shale Project.
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8.2.5 Midstream and Downstream Costs
The Tables 8.10 presents the detailed Midstream and downstream costs assumptions used in my economic analyses of the
First Stage Development of the Fuling shale. The calculations are shown for the initial years only. All prices and costs are in real 2014 terms. This is only a first approximation and that you lack the data to model it properly.
Transmission and Distribution Costs (US$2014) Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 Total methane sales Bcf 14.62 59.3 98.61 67.04 Transmission and Distribution costs per Mcf US$/Mcf 1 3 1.90 1.90 1.90 1.90 1.90 Total distribution costs US$MM 27.78 112.7 187.4 127.4 Transmission and Distribution Costs (US$2014) Explanations Total methane sales Volume of methane sold to consumers Transmission and Distribution Cost per Mcf Assumed distribution costs based on Chonqing natural gas company Total distribution costs Total sales volume * distribution costs per Mcf Table 8.10 Real Transmission and Distribution Costs for the First Stage Development of the Fuling Shale Project.
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8.2.6 External Costs
The following table presents detailed assumptions and a worked example of External Costs in Fuling. For presentation purposes, the estimates are shown for the initial years only.
Water Use Costs (US$2014) Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 Water use per well kbbl 18 130 65.14 65.14 65.14 65.14 Number of development wells No 20 68 81 Total water use Kbbl 1,302.80 4,429.52 5,276.34 Price of water US$/Kbbl 0.07 0.07 0.07 0.07 Total water use costs US$MM 0.09 0.31 0.37 Water Use Costs (US$2014) Explanation Water use per well Water use per shale well Number of development wells Number of wells drilled this year(from Table 8.8) Total water use Water use per well * the number of wells Price of water Price of water in US$ per bbl (refer to 6.6) Total water use costs Total water use * price of water (Equation 6-1) Table 8.11 Real Water Use Costs for the First Stage Development of the Fuling Shale Project
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Flowback Recycle Costs (US$2014) Units P90 P10 Value 2011 2012 2013 2014 2015 2016 Total water treatment facilities costs US$MM 20 Flowback rate % 5% 45% 22% 22% 22% 22% Re-use water treatment costs US$/bbl 1.00 2.00 1.47 1.47 1.47 1.47 Re-use Treatment volume kbbl 214.96 730.87 870.60 Total re-use treatment costs US$MM 0.32 1.07 1.28 Recycle water treatment costs US$/bbl 3.50 6.25 4.80 4.80 4.80 4.80 Recycle treatment volume Kbbl 71.65 243.62 290.20 Total recycle treatment costs US$MM 0.34 1.17 1.39 Flowback Recycle costs (US$2014) Explanation Total water treatment facilities costs Estimated cost of treatment facilities Flowback rate Estimated flowback rate Re-use water treatment costs Estimated re-use water treatment cost per bbl.(refer to 6.7) Reuse Treatment volume Flowback rate * total water use (from Table 8.7)*3/4 (Based on Figure 6.3) Total re-use treatment costs Treatment volume * Re-use water treatment cost per bbl. Recycled water treatment costs Estimated recycle water treatment cost per bbl.(refer to 6.7) Recycle treatment volume Water usage per well (Table 8.11) * Flowback rate * 1/4(Based on Figure 6.3) Total recycle treatment costs Recycle treatment volume *Recycle water treatment cost per bbl. Table 8.12 Flowback Management Costs for the First Stage Development of the Fuling Shale Project.
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Flowback Transport Costs (US$2014) Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 Transport costs per bbl per mile US$ 0.02 0.04 0.03 0.03 0.03 0.03 Transport distance mile 5 5 5 5 Transport volume Kbbl 286.62 974.49 1,160.79 Total transport costs US$MM 0.04 0.15 0.17 Total water management costs US$MM 20.70 2.39 2.85 Flowback Transport Costs (US$2014) Explanation Transport costs per bbl per mile Estimated transport cost per bbl per mile (refer to 6.7) Transport distance Estimated transport distance Transport volume Recycle treatment volume + Re-use treatment volume (From Table 8.12) Transport costs Transport costs per unit * Transport distance * Transport volume Transport costs + Recycle treatment cost (From Table 8.12) + Re-use treatment Total water management costs costs(From Table 8.12) + water treatment facilities costs (From Table 8.12) (Equation 6-2) Table 8.13 Flowback Management Costs Continued for the First Stage Development of the Fuling Shale Project.
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CO2 Emissions Costs (US$2014) Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 Carbon penalty US$/t 1.6 114 53.96 53.96 53.96 53.96 53.96
CO emissions during production t/MMcf 1.05 2.00 1.39 1.39 1.39 1.39 1.39 2 CO emissions by burning methane t/MMcf 54.12 54.12 54.12 54.12 54.12 2 Total methane production Bcf 15.39 62.42 103.80 70.57
Total methane sales Bcf 14.62 59.30 98.61 67.04
Total CO emissions MM t 812.65 3,296.03 5,481.06 3,726.38 2 CO emission costs US$MM 43.85 177.85 295.76 201.08 2 CO2 Emissions Costs(US$2014) Explanation Carbon penalty Estimated carbon penalty $ per tonne (refer to 6.8)
CO2 emissions during production Estimated CO2 emission per Mcf during production
CO2 emissions by burning methane Estimated CO2 emission per Mcf of methane Total methane production Estimated methane production in the year (from Table 8.6) Total methane sales The volume of gas production which is sold (from Table 8.6)
Methane production (from Table 8.7)*CO2 emissions rate +Total methane sales Total CO2 emissions (from Table 8.7)*CO2 emissions by burning methane
CO2 emission costs Total CO2 emissions*Carbon penalty (Equation 6-3)
Table 8.14 CO2 Emission Costs for the First Stage Development of the Fuling Shale Project. (Some emissions and are related to production. Some are emissions from burning methane and are related to sales)
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Methane Emissions Costs Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 (US$2014)
Methane emission penalty US$/Mcf 2.00 10.00 5.45 5.45 5.45 5.45 5.45 Methane emission rate % 0.71% 5.00% 2.61% 2.61% 2.61% 2.61% 2.61% Methane emission volume Mcf 401.68 1,629.16 2,709.18 1,841.88
Methane emission costs US$MM 2.19 8.88 14.77 10.04 Total GHG emission costs US$MM 46.04 186.73 310.52 211.11 Methane Emissions Costs Explanation (US$2014) Methane emission penalty Estimated methane emission penalty rate $ Mcf (refer to 6.9) Methane emission rate Estimated methane emission as percentage of gas production Methane emission volume Methane emission rate*Total gas production(from Table 8.5) Methane emission costs Methane emission volume*methane penalty (Equation 6-3)
Total GHG emission costs Total Methane emission costs+Total CO2 emission costs(From Table 8.14) Table 8.15 Real GHG Emissions Costs for the First Stage Development of the Fuling Shale Project
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Road Maintenance Costs (US$2014) Units P90 P10 Value 2011 2012 2013 2014 2015 2016 2 Maintenance length mile 50 150 94.93 94.93 94.93 94.93 94.93 US$ Costs of road construction per mile 1.3 1.3 1.3 1.3 1.3 MM Maintenance costs % 3% 3% 3% 3% 3%
US$ Total maintenance costs 3.70 3.70 3.70 3.70 MM Road Maintenance Costs (US$2014) Explanation Maintenance length Estimated length of road to maintain Costs of road construction per mile Estimated costs of road construction per mile Maintenance costs Estimated maintenance costs as percentage of construction costs(refer to 6.10) Maintenance length*Costs of road construction per mi*Maintenance costs Total maintenance costs (Equation 6-4) Table 8.16 Real Road Maintenance Costs for the First Stage Development of the Fuling Shale Project
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Subsidies and Compensation Units P90 P10 Mean 2011 2012 2013 2014 2015 2016 (US$2014) Subsidy per Mcf US$/Mcf 0.5 2 1.16 1.16 1.16 1.16 1.16 Total Subsidies US$MM 16.96 68.79 114.39 77.77 Affected areas mile2 40 40 40 40 40
Population density people/mile2 367 367 367 367 367
Compensation for per person US$ 100 1,200 554.23 554.23 554.23 554.23 554.23 Total compensation US$MM 8.14 8.14 8.14 8.14 Subsidies and Compensation Explanation (US$2014) Subsidy per Mcf Subsidy per Mcf of methane sold Total Subsidies Subsidy per Mcf * Total methane sales (From Table 8.6) Affected areas Estimated areas affected by shale gas development Population density Population density in the Fuling project area Compensation for per person Estimated compensation per person (refers to 6.11) Total compensation Affected areas * population density * compensation per person(Equation 6-5) Table 8.17 Real Subsidy and Compensation for the First Stage Development of the Fuling Shale Project
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8.3 Results
This thesis focuses on the economics of shale gas development in China based on an analysis of the costs and benefits of shale gas from the perspectives of (a) the economy/society as a whole and (b) the Supply
Chain Companies.
Specifically, the aims are to compare the economics of a shale gas project from the points of view of -
A. The economy as a whole. This “Whole-Economy Analysis” includes all
Supply Chain Costs except the Fiscal Costs, which are within the project boundary – as well as the “External Costs”, which are the costs incurred outside the project boundary.
B. The company or companies that are operating the project. This
“Company Analysis” includes all the Supply Chain Costs but excludes
External Costs. As part of this analysis, I also analyse the effects of taxation and Subsidy Revenue on the Supply Chain Companies.
As part of this comparison, I evaluate the incremental economic effects of
External Costs.
Most of the assumptions for my economic analyses are probability distributions that reflect the uncertainties in those assumptions. The
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results are probability distributions of the net present values (NPVs) of the project derived from Monte Carlo simulations. I derive the NPVs from projections of annual nominal net cash flows (NCFs) from the start of the project (I assume that this is 2011) to the end of the project’s economic life.
The revenues and costs of the Supply Chain (the Upstream, Midstream, and Downstream) are described in Table 8.18.
Supply Chain Revenues and Costs (Field Gate Price + Subsidy) * Total Methane Revenue sales
Costs Exploration costs Appraisal costs Development costs Operating costs Upstream Abandonment costs Fiscal Costs Resource and other taxes Income Taxes Revenue Terminal price*Total Methane sales Methane purchase costs (equal to the Costs Upstream Methane Sales Revenue at the Field Gate) Transmission and Distribution cost
Downstream Midstream and and Midstream Fiscal Costs Income Taxes
Table 8.18 The Supply Chain Revenues and Costs
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I assume that the Supply Chain Companies operating the project do not pay for any of the External Costs because the latter is beyond the economic boundary of the shale gas project itself. This would typically be the case for many international projects. However, there might be exceptions in particular cases. For instance, in some cases, the company might pay some or all external road maintenance costs. However, my analysis discussed below shows that external road costs are a relatively small portion of total External Costs.
8.3.1 Nominal Revenues
The mean of nominal Methane Sales Revenues and Supply Chain
Revenues (equal to Methane Sales Revenues plus Subsidy Revenues) in the first 20 years of the Fuling project are shown in Figure 8.10
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1,400
1,200 Supply Chain Revenue
1,000
800 Methane Sales Revenue
600
400
200 Mean of Nominal Revenues (US$ MM) (US$ Revenues of Nominal Mean 0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year
Figure 8.10 Nominal Revenues for the Fuling Project The project starts in 2011. There is a two-year exploration stage. Then, in
2013, production starts and the revenues reach a peak in 2016. After that, the revenue decreases because of production declines.
8.3.2 Nominal Supply Chain Costs
The means of the projected nominal Supply Chain Costs are presented in
Figure 8.11.
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1,600
1,400 Transmission and Distribution Costs 1,200 Operating Costs 1,000
800 Development Costs 600 Appraisal Costs 400 Exploration Costs 200
0 Nominal Annual Supply Chain Costs (US$MM) Costs Chain Supply Annual Nominal 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year
Figure 8.11 Nominal Supply Chain Costs for the Fuling Project (The abandonment costs occur after the economic life of the upstream development. In this case, it occurs in 2040)
Expenditure begin in 2011 with the exploration costs associated with the discovery well. The Fuling appraisal stage occurs in 2012. In 2013 the development itself and production begin. Because many wells are drilled, fractured and completed from 2013 to 2015, the development costs are extremely high in this period. The field’s development costs peak in 2015.
The cumulative field development costs are more than 80% of total
Upstream Costs. After 2015, the Upstream Costs consist of only operating
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costs and gas distribution costs. Abandonment costs occur after the economic life of the upstream development. This varies depending on the net cash flow profile of a given case.
Total undiscounted nominal Supply Chain Costs are significant. In total, these costs are 72% of the total undiscounted nominal Methane Sales
Revenues. At the peak, the Supply Chain Costs are 123% of the nominal peak Methane Sales Revenues.
8.3.3 Nominal Fiscal Costs
Table 8.12 sets out the means of the nominal Fiscal Costs in the Supply
Chain and their breakdown
Fiscal Costs begin with first gas production in the year 2013. They increase in line with production and then dip down in 2015 reflecting the effects of losses carried forward. Then, they grew to $US96MM in 2015. This is because the Fiscal Costs related to resources, urban-maintenance, education and transmission and distribution taxes increase as more gas is produced. After 2015, Fiscal Costs decline because gas production drops.
However, by 2017 the company has deducted all the carry forward development costs against the Income Tax and so Income Taxes increase.
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In the following years, Fiscal Costs go down because production declines and there are no further carry forward losses.
Total undiscounted nominal Fiscal Costs are not large. In total, these costs are 12% of the total undiscounted nominal Methane Sales Revenues. At the peak, the Fiscal Costs are 8% of the undiscounted nominal peak
Methane Sales Revenues.
100
90 Transmission and Distribution Income Tax 80 Upstream Resources 70 tax and other taxes 60 Upstream Income Tax 50 40 30 20
Nominal Fiscal Costs NCF (in US$ MM) MM) US$ (in NCF Costs Fiscal Nominal 10 0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year
Figure 8.12 Breakdown of Taxes for the Fuling Project
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8.3.4 Nominal External Costs
The projected means of the nominal incremental External Costs are illustrated in Figure 8.13. The External Costs first appear in 2013 when the development begins. The total nominal incremental External Costs increase to a peak in 2015 as development activity intensifies and then decrease each year up to the end of field life as production declines.
Project subsidies and Green House Gas (GHG) emission penalties arising from methane leaks and burning methane are all strongly positively correlated with gas production. These costs are a significant portion of the total External Costs. Therefore, the total nominal External Costs are significantly affected by the level of gas production.
Preliminary facilities construction and well-drilling costs are concentrated in the period 2013 to 2015. Therefore, the External Costs of water, road maintenance, and water management are also the highest in these three years. For instance, in 2013, considerable capital is invested in a water treatment plant. After 2015, the significant components of External Costs are compensation costs and GHG emission costs. In contrast, because there are abundant water resources in the area of the Fuling shale, water use costs are small. They are too low to present clearly in Figure 8.13.
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Total undiscounted nominal External Costs are significant. In total, these costs are 42% of the total undiscounted nominal Methane Sales Revenues.
At the peak, the External Costs are 38% of the nominal peak Methane
Sales Revenues.
500
Road manitenace 450 400 Methane burning penalities 350 Compensation 300 Subsidy 250 200 Water management 150 Methane leakage penalities 100 50 Nominal Annual External Costs (US$MM) Costs External Annual Nominal 0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year
Figure 8.13 Composition of Components of External Costs for the Fuling Project
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8.3.5 Nominal NCFs of the Supply Chain and the Whole Economy
Figure 8.14 compares the means of the nominal net cash flows (NCFs) from the perspectives of (a) the Whole Economy and (b) the companies in the Supply Chain. The Supply Chain Analysis includes the effects of Supply
Chain Costs and Fiscal Costs. The Whole Economy Analysis contains the effects of Supply Chain Costs and External Costs but excludes Fiscal Costs.
800 Supply Chain NCF 600
Whole Economy NCF 400
200
0
-200 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
-400 Mean of Nominal NCF(US$ MM) NCF(US$ of Nominal Mean -600
-800 Year
Figure 8.14 Comparison of Mean Nominal NCFs for the Fuling Project
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As can be seen from Figure 8.14, External Costs reduce the NCF significantly. Although not shown explicitly in Figure 8.14, as mentioned above, Fiscal Costs have a relatively minor effect on the NCF of the Supply
Chain companies. Abandonment costs are not shown in Figure 8.14. They occur at the end of the economic life of the upstream development. This varies depending on the net cash flow profile.
8.3.6 PVs of Nominal Revenues
The probability distributions of the present values (PVs) of Methane Sales
Revenues and Supply Chain Revenues as at 2014 are shown in Figure 8.15
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Supply
Chain
Methane Sales Revenue Probability % Probability
0 1,000 2,000 3,000 4,000 5,000 6,000 PVs of Revenues (US$MM)
Figure 8.15 The Probability Distributions of the Present Values (PVs) of Methane Sales Revenues and Supply Chain Revenues.
The mean of the PVs of Supply Chain Revenue is US$3,580MM. In addition,
90% of the revenues (P90) are more than US$2,519MM and 10% of the revenues (P10) exceed US$4,788MM.
The difference between these revenues reflects the size of the revenue from the Subsidy.
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8.3.7 PVs of Nominal Supply Chain Costs
The probability distribution of the PVs of Supply Chain Costs is shown in
Figure 8.16.
P50 = US$2,455MM Men = US$2,555MM P90 = US$1,767MM
Probability % Probability P10 = US$3,480MM
0 1,000 2,000 3,000 4,000 5,000 6,000 PVs of Supply Chain Costs (US$MM)
Figure 8.16 The Probability Distribution of the PVs of Supply Chain Costs
The mean value of PVs of Supply Chain Costs is US$2,555MM. P90 value is
US$1,767MM and P10 value US$3,480MM.
The mean of PV of nominal Supply Chain Costs is significant. It is 84% of the PV of Methane Sales Revenues.
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8.3.8 PVs of Nominal Fiscal Costs
The probability distribution of the PVs of Supply Chain Fiscal Costs is shown in Figure 8.17.
The mean of the PVs of the Fiscal Cost is US$443MM. P10 value is
US$224MM, and P90 is US$696MM.
The mean of PV of nominal Fiscal Costs is not significant compared to the other costs. It is 13% of the mean PV of nominal Methane Sales Revenues.
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P50 = US$411MM
Mean = US$443MM
P10 = US$696MM Probability % Probability
P90 = US$224MM
0 200 400 600 800 1,000 1,200 1,400 PVs of Supply Chain Fiscal Costs(US$MM)
Figure 8.17 The probability distribution of the PVs of Supply Chain Fiscal Costs
8.3.9 PVs of Nominal External Costs
The probability distribution of the PVs of External Costs is shown in Figure
8.18, and its cumulative probability equivalent is in Figure 8.19
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P90 = US$363MM
P50 = US$731MM
Probability % Probability Mean = US$1,299MM
P10 = US$2,267MM
0 1,000 2,000 3,000 4,000 5,000 PVs of External Costs (US$MM)
Figure 8.18 Probability Distribution of the PVs of External Costs
The mean of the PVs of external costs is US$1,299MM. In addition, 90% of the PVs are more than US$363MM (the “P90”) and 10% of the PVs exceed
US$2,267MM (the “P10”).
The PV of nominal External Costs is significant. The mean is 43% of the PV of the mean of the Methane Sales Revenues and is 50% of the PV of
Supply Chain Costs.
Figure 8.19 gives the probability distribution of the PVs of economic components compared to the probability distribution of the PVs of the
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Supply Chain Revenue. Table 8.19 gives the mean, P90, P50, and P10 values for the economic components as a percentage of Methane Sales
Revenue.
External costs
Supply Chain Costs
Probability% Fiscal Costs
0% 20% 40% 60% 80% 100% 120% 140% Economic Components as Percentage of Gross Revenue
Figure 8.19 Probability Distribution of the PVs of Costs as Percentage of the PVs of Methane Sales Revenue
PVs of Costs as % of PV of Mean P90 P50 P10 Methane Sales Revenues External Costs 43% 11% 23% 75% Supply Chain Costs 84% 50% 78% 125% Fiscal Costs 13% 8% 13% 18% Table 8.19 PVs of Costs as Percentages of PVs Methane Sales Revenues
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The Figure 8.19 and Table 8.19 above indicate that the Supply Chain costs significantly affect the Fuling project. External costs are also a large burden on the project.
8.3.10 PVs of Nominal Components Net Cash Flows
Figure 8.20 shows in absolute terms (US$MM terms) how the PVs of economic components compare (including Methane Sales Revenues,
Supply Chain Revenue and Costs, Fiscal and External Costs). Table 8.20 gives the statistics for these components.
Supply Chain Fisacal Costs
Supply Chain External Costs Revenue
Supply Chain Costs Probability % Probability Methane Sales Revenue
-1,000 0 1,000 2,000 3,000 4,000 5,000 6,000 PV in US$MM
Figure 8.20 Comparison of Probability Distributions of PVs of Revenues and Costs
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PVs (In US$MM) Mean P90 P50 P10 PVs of Supply Chain Revenue (SCR) 3,580 2,519 3,472 4,788 PVs of Methane Sales Revenue (MSR) 3,258 2,222 3,147 4,462 PVs of Supply Chain Costs(SCC) 2,555 1,767 2,455 3,480 PVs of Supply Chain Taxes(SCT) 443 224 411 696 PVs of External Costs(EC) 1,299 363 731 2,267 NPVs (In US$MM) Mean P90 P50 P10 NPV of Supply Chain (=SCR-SCC-SCT) + 583 - 600 + 597 + 1,761 NPV of Whole Economy (=MSR-SCC- - 595 - 2,270 - 242 + 1,310 EC) Difference in NPVs + 1,178 + 1,670 + 839 + 451 Table 8.20 Breakdown of the PVs of the Components of Net Cash Flow (The means of the NPVs can be can be derived arithmetically from the means of the PVs of the individual components. This is not true for the other statistics shown. Apart from the means, the P90, P50 and P10 NPVs shown above do not correspond to the arithmetical derivations)
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8.3.11 NPVs of Supply Chain and Whole Economy
Figure 8.22 shows the probability distributions of the NPVs of the Fuling shale gas development from the perspectives of (a) the Whole Economy
(including External Costs, but excluding Fiscal Costs) and (b) the Supply
Chain Companies’ perspective (excluding External Costs but including
Fiscal Costs and Subsidy Revenue).
Mean of Supply Chain NPVs = US$583 MM
Mean of Whole Economy NPVs = US$ - 595MM Probablitiy % Probablitiy
Supply Chain NPVs Difference Whole Economy NPVs between means = US$1,178MM
-3,000 -2,000 -1,000 0 1,000 2,000 3,000 4,000 5,000 6,000 NPV in US$MM
Figure 8.21 Probability Distributions of NPVs from Whole Economy and Supply Chain Perspectives
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The corresponding cumulative distributions are in Figure 8.23.
100% Difference between 90% means = 80% US$1,178MM
70% Mean of Whole Economy NPVs = US$ - 595MM 60% NPVs of Whole Economy 50% Mean of Supply Chain 40% NPVs = US$583MM Confidencei n % % n Confidencei 30% 20% NPVs of Supply Chain 10% 0% -5,000-4,000-3,000-2,000-1,000 0 1,000 2,000 3,000 4,000 5,000 NPVs in US $MM
Figure 8.22 Cumulative Probability Distributions of NPVs for the Whole Economy and the Supply Chain
Table 8.20 gives a comparison of the mean, P90, P50 and P10 NPVs
Unit Mean P90 P50 P10 NPVs of Supply Chain US$MM + 583 - 600 + 597 + 1,761 NPVs of Whole Economy US$MM - 595 - 2,270 - 242 + 1,310 Difference US$MM + 1,178 + 1,670 + 839 + 451 Table 8.21 The Mean, P90, P50 NPVs and from Figures 8.22 and 8.23.
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From the Supply Chain perspective, the mean NPV is positive US$583MM.
However, the NPV at a 90% confidence level is negative. That implies the first stage of Fuling shale might be economically viable depending on the decision maker’s level of risk aversion.
However, from the perspective of the Whole Economy, which includes the
External costs, the mean NPV is negative US$595MM. This implies that the project is not economically attractive. The difference between the means of these two NPVs (US$1,178MM) demonstrates the significant impact that the External Costs have on the economics of the project.
The differences between the Supply Chain NPVs and the Whole Economy
NPVs become more significant at P90 levels of confidence and less significant at P10 levels of confidence. This is because –
(a) at the P90 level of confidence, the lower NPVs tend to reflect lower
Revenues and External Costs tend to be high compared to these revenues and
(b) at the P10 level of confidence, the higher NPVs tend to reflect higher
Revenues and External Costs tend to be low compared to these revenues.
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8.4 Summary
In this chapter, I analyse the Fuling shale gas project as a case study.
The Fuling shale gas development has a mean nominal NPV of positive
US$583MM as at the year 2014 from the perspective of the Supply Chain companies. That is when the economics exclude External Costs and include Fiscal Costs. However, the NPV at a 90% confidence level is negative. That implies the first stage of Fuling shale might be economically viable depending on the decision maker’s attitude to risk.
However, the mean nominal NPV becomes negative US$595MM from the perspective of the economy as a whole. That is when the economics include External Costs and exclude Fiscal Costs. In other words, the economics for the Whole Economy Supply Chain contradict the economics for the Supply Chain companies and imply that the project is unviable.
If the External Costs are a included, they represent a significant burden on the economics of the development. The largest single component of the
External Costs are the costs of GHG emissions resulting from methane CO2 emissions by burning methane.
After the costs of GHG emissions, subsidies are the next most significant
External Cost.
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There is a considerable inherent potential variation in the NPVs. This reflects the large uncertainties in the parameters we are required to estimate for decision-making in developing shale gas projects.
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8.5 Comparison with Other Studies
I have compared my analyses of the Fuling shale gas project with reports in the published literature on the economics of shale gas developments in the USA. The literature suggests that American shale gas projects tend to have higher development and operating costs than in the Fuling project. In addition, natural gas prices assumed for the analyses of shale gas in the
USA are much lower than assumed for the Fuling development. However, the Fiscal Costs paid the state-owned companies in China for shale gas industry are relatively low. On balance, the economics from a Supply
Chain company perspective are more attractive for the Fuling development than the economics of developments in the USA.
None of the analyses of shale gas developments in the USA include the effect of External Costs, and few are based on probabilistic assumptions that reflect the large uncertainties involved.
The Jiehui Yuan et al. [6] evaluate the Fuling shale gas project using discounted cash flow analysis from an upstream company perspective. In contrast to my analyses, they conclude that the economics of the Fuling project from an upstream company perspective are poor. However, their estimates of operating costs and exploration costs are much higher than
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the means of these costs used in my analyses. Furthermore, they do not consider External Costs and do not carry out probabilistic analyses.
Most of the published research analyses the economics of shale gas development purely from company perspectives and ignore some or all of the inherent disadvantages of such developments. My analyses show that evaluating the economics of shale gas from the perspective of the Whole
Economy (that is, including External Costs, but excluding Fiscal Costs), makes shale gas development significantly less attractive.
My analyses also show that shale gas economics have considerable uncertainty, which has a large effect on development decision-making.
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Chapter 9 Conclusion
To meet increasing national energy consumption, China’s government has begun to develop its shale gas resources. Although the evolution of shale gas in the USA has had significant success, the prospects for similar success for shale gas in China are still unclear. This thesis discusses shale gas development both in China and the USA. It analyses the economics of shale gas development in China from the perspectives of the shale gas
Supply Chain and the Whole Economy for an example project. This example is the first stage of the Fuling shale gas project.
Specifically, the aims of the thesis are as set out below.
A. To describe and quantify the benefits and costs of an example Chinese shale gas development for the Whole Economy. The benefits and costs include those external to shale gas Supply Chain companies but exclude the companies’ fiscal costs.
B. To assess the benefits and costs of an example Chinese shale gas development for the companies operating the shale gas development. In other words, the boundary of the analysis is the shale gas Supply Chain on its own. The analysis excludes the economic effects of benefits and costs external to the development.
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3. By comparing the analyses in 1 and two 2, to quantify the incremental economic effects of External Costs of shale gas development.
The analyses in this thesis show that the Fuling shale gas development has a mean nominal NPV of positive US$583MM as at the year 2014 from the perspective of the Supply Chain companies. That is when the economics exclude External Costs and include Fiscal Costs. However, the NPV at a 90% confidence level is negative. That implies the first stage of Fuling shale might be economically viable depending on the decision maker’s attitude to risk. Some decision makers might consider the NPVs to be marginal.
However, the mean nominal NPV becomes negative US$595MM from the perspective of the economy as a whole. That is when the economics include External Costs and exclude Fiscal Costs. In other words, the economics for the Whole Economy contradict the economics for the
Supply Chain companies and imply that the project is uneconomic from a wider perspective.
The key reasons for the difference are the External Costs. The mean of PV of External Costs is 43% of the Methane Sales Revenue. They, therefore, represent a significant burden on the economics of development. At higher levels of confidence, the effect of External Costs is much greater. At lower levels of confidence, the effect is much smaller. The largest single
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component of the External Costs are the costs of GHG emissions resulting from methane CO2 emissions by burning methane.
After the costs of GHG emissions, subsidies are the next most significant
External Cost. That means if we ignore the Government subsidy and consider the CO2 emissions, the NPV could be significantly overstated.
Inherently, there is a considerable potential variation in the NPVs. This reflects the large uncertainties in the parameters we are required to estimate for decision-making in developing shale gas projects.
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Appendix A - Abbreviations bbl = barrel Bcf = Billion cubic feet Btu=British Thermal Units Capex =Capital costs cf=Cubic feet CNOOC= China National Offshore Oil Corporation CNPC= China National Petroleum Corporation
CO2=Carbon Dioxide DCF=Discounted Cash Flow DPI= Discounted Profit to Investment Ratio EIA = Energy Information Administration ft=feet GDP = gross domestic product GHG=Green gas emission GWh=gigawatt-hours IRR= Internal rates of return Kbbl=Thousand barrels kg=kilo gram km=kilo metre km2= cubic kilo metre LNG= Liquefied Natural Gas m=metre M=Richter magnitude scale M3= Cubic metre
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Mcf=Thousand cubic feet mile2=cubic mile MM = million MMcfd=Million cubic feet per day NCF = Net cash flow No=Number NPV = Net Present value Opex=Operating costs R/P ratio= reserves/production (R/P) ratio R/P ratio= reserves/production (R/P) ratio
R0=Thermal Maturity Sinopec= China Petroleum and Chemical Corporation t=tonnes Tcf = Trillion cubic feet TOC=Total Organic Carbon US$MM = million US dollars USA=United States of America WTO=World Trade Organization
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Appendix B - Conversion Factors
Length 1 Kilometre=0.62 miles 1 metre=3.28 feet Area 1 cubic metre=10.76 cubic feet 1 square kilometre=1 square metre=0.39 square mile Volume 1 cubic metre=35.31 cubic feet=264.16 US gallons=6.29 barrels 1 cubic kilometre=1,000 cubic metre 1 Tcf=1,000 Bcf=1000,000 MMcf=1000,000,000 Mcf=1012 cubic feet 1 kbbl=1000 bbl Weight Tonnes=1000 kilograms=1000,000 grams Energy 1 cubic feet natural gas=1,025 British Thermal Units
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Appendix C – Detailed Geological Properties of Major Shale Gas Distribution Areas
The source of this information does not employ the PRMS categories described in section 1.5 of this thesis to derive the
Expected Ultimate Recovery (“EUR”) estimates. However, I infer that the majority of the resources are a combination of
Prospective and Contingent Resources at “Best Estimate” and “2C” levels of confidence under PRMS definitions.
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Yangtze Platform (611,000 Sichuan (74,500 mi2) Basin/Gross Area mi2) Shale Formation Qiongzhusi Longmaxi Permian L. Cambrian L. Silurian Geologic Age L. Cambrian L. Silurian Permian L. Cambrian L. Silurian Basic Data Depositional Environment Marine Marine Marine Marine Marine
Prospective Area (mi2) 6,500 10,070 20,900 3,250 5,035 Organically Rich 500 1,000 314 500 1,000 Thickness (ft) Net 275 400 251 275 400 10,000 - 9,000 - 10,000 - 16,400 9,000 - 15,500 3,280 - 16,400 Depth (ft) Interval 16,400 15,500 Physical Extent Average 13,200 11,500 9,700 13,200 11,500 Reservoir Pressure Mod.Overpress. Mod.Overpress. Mod.Overpress. Normal Normal Average TOC (wt. %) 3.00% 3.20% 4.00% 3.00% 3.20% Thermal Maturity (% Ro) 3.20% 2.90% 2.50% 3.20% 2.90% Reservoir Properties Clay Content Low Low Low Low Low
Gas Phase Dry Gas Dry Gas Dry Gas Dry Gas Dry Gas GIP Concentration (Bcf/mi2) 109.8 162.6 114.1 99.4 147.1 GIP (Tcf) 499.6 1,146.10 715.2 181 414.7 Resource Technically Recoverable (Tcf) 124.9 286.5 214.5 45.2 103.7 Table C.1 Geological Properties of Major Shale Gas Distribution Areas[113]
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Basin/Gross Area Jianghan (14,440 mi2) Shale Formation Niutitang/Shuijintuo Longmaxi Qixia/Maokou Geologic Age L. Cambrian L. Silurian Permian
Basic Data Depositional Environment Marine Marine Marine
Prospective Area (mi2) 1,280 670 1,230 650 1,100 2,080 Organically Rich 533 394 394 700 700 700 Thickness (ft) Net 267 197 197 175 175 175 8,200 - 10,000 - 9,840 - 16,400 3,300 - 7,000 7,000 - 10,000 10,000 - 13,120 Depth (ft) Interval 12,000 14,760 Physical Extent Average 13,120 10,000 12,380 5,500 8,500 11,500 Reservoir Pressure Normal Normal Normal Normal Normal Normal Average TOC (wt. %) 6.60% 2.00% 2.00% 2.00% 2.00% 2.00% Thermal Maturity (% Ro) 2.25% 1.15% 2.00% 0.85% 1.15% 1.80% Reservoir Properties Clay Content Low Low Low Low Low Low
Gas Phase Dry Gas Wet Gas Dry Gas Assoc. Gas Wet Gas Dry Gas GIP Concentration (Bcf/mi2) 148.9 51 67.1 14.1 48.3 66.6 GIP (Tcf) 45.7 8.2 19.8 1.8 10.6 27.7 Resource Technically Recoverable (Tcf) 11.4 1.6 4.9 0.2 2.7 6.9 Table C.2 Geological Properties of Major Shale Gas Distribution Areas (continued)[113]
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Basin/Gross Area Greater Subei (55,000 mi2) Shale Formation Mufushan Wufeng/Gaobiajian U. Permian Geologic Age L. Cambrian U. Ordovician-L. Silurian U. Permian
Basic Data Depositional Environment Marine Marine Marine
Prospective Area (mi2) 2,040 5,370 9,620 1,350 290 Organically Rich 400 820 820 500 500 Thickness (ft) Net 300 246 246 150 150 Interval 13,000 - 16,400 11,500 - 13,500 13,500 - 16,400 3,300 - 8,200 8,000 - 1,000 Depth (ft)
Physical Extent Average 14,700 12,500 14,500 5,800 9,000 Reservoir Pressure Normal Normal Normal Normal Normal Average TOC (wt. %) 2.10% 1.10% 1.10% 2.00% 2.00% Thermal Maturity (% Ro) 1.20% 1.15% 1.45% 1.15% 1.35% Reservoir Properties Clay Content Low Low Low Low Low
Gas Phase Dry Gas Wet Gas Dry Gas Wet Gas Dry Gas GIP Concentration (Bcf/mi2) 118.6 66 87.8 35.8 55.4 GIP (Tcf) 29 42.5 101.4 5.8 1.9 Resource Technically Recoverable (TCF) 7.3 10.6 25.4 1.5 0.5 TABLE C.3 Geological Properties of Major Shale Gas Distribution Areas(continued)[113]
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Basin/Gross Area Tarim (234,200 mi2) Shale Formation L. Cambrian L. Ordovician M.-U. Ordovician Ketuer Geologic Age L. Cambrian L. Ordovician M.-U. Ordovician L. Triassic
Basic Data Depositional Environment Marine Marine Marine Lacustrine
Prospective Area (mi2) 6,520 19,420 10,450 10,930 15,920 Organically Rich 380 300 300 390 400 Thickness (ft) Net 240 170 160 240 200 9,840 - 11,000 - 16,400 10,000 - 16,400 8,610 - 12,670 9,500 - 16,400 Depth (ft) Interval 16,400 Physical Extent Average 14,620 13,690 10,790 12,180 13,000 Reservoir Pressure Normal Normal Normal Normal Normal Average TOC (wt. %) 2.00% 2.40% 2.10% 2.50% 3.00% Thermal Maturity (% Ro) 2.00% 1.80% 0.90% 2.00% 0.90% Reservoir Properties Clay Content Low Low Low Low Low
Gas Phase Dry Gas Dry Gas Assoc. Gas Dry Gas Assoc. Gas GIP Concentration (Bcf/mi2) 77.1 59.8 12.6 85 40.5 GIP (Tcf) 175.9 377.5 32.8 232.3 161.2 Resource Technically Recoverable (Tcf) 44 94.4 3.3 58.1 16.1 Table C.4 Geological Properties of Major Shale Gas Distribution Areas(continued)[113]
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Songliao (108,000 Junggar (62,100 mi2) Basin/Gross Area mi2) Shale Formation Pingdiquan/Lucaogou Triassic Qingshankou Geologic Age Permian Triassic Cretaceous Basic Data Depositional Environment Lacustrine Lacustrine Lacustrine
Prospective Area (mi2) 7,400 8,600 6,900 Organically Rich 820 820 1,000 Thickness (ft) Net 410 410 500 Interval 6,600 - 16,400 5,000 - 16,400 3,300 - 8,200 Depth (ft)
Physical Extent Average 11,500 10,000 5,500 Reservoir Pressure Highly Overpress. Highly Overpress. Mod. Overpress. Average TOC (wt. %) 5.00% 4.00% 4.00% Thermal Maturity (% Ro) 0.85% 0.85% 0.90% Reservoir Properties Clay Content Medium Medium Medium
Gas Phase Assoc. Gas Assoc. Gas Assoc. Gas GIP Concentration (Bcf/mi2) 64.7 60.5 45 GIP (Tcf) 172.4 187.5 155.4 Resource Technically Recoverable (Tcf) 17.2 18.7 15.5 Table C.5 Geological Properties Of Major Shale Gas Distribution Areas(continued)[113]
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