The economics of petroleum exploration and development in

By Sajith Venugopal

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

July 2005

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

I would like to express my sincerest gratitude 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 wisdom, my research endeavour would have been far more difficult. I thank him for his patient reading of my write- ups and the opportunities he provided me to conduct occasional tutorials and lectures.

I am also extremely grateful to Deepak Mehta and Madhu Nainan from Petrowatch for granting me access to their exclusive database, the interest that they showed in my work played a pivotal role in motivating me to complete this research.

I would like to extend my warmest thanks to my flat-mates Vivek, Frank and Ankur. They were my family in Australia. Each of them has given me great memories that I would cherish throughout my lifetime. They have been the best friends that I could wish for and have helped me greatly through my ups and downs.

I express my deepest thanks to my parents K.P.Venugopal and Valsala Venugopal and my siblings Ajith and Anjali for their unconditional love and support. 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. I also thank my dear Leena for her patience and love through the difficult times. Her presence in my life was a key ingredient in the drive that I had to complete this thesis and I am looking forward to my life with her.

I dedicate this thesis to my parents Abstract

This thesis provides the background to and an analysis of the economics of exploring for and developing oil and gas discoveries in India. It is aimed at helping the oil and gas industry assess the financial attractiveness of investment in that country. The thesis describes the geography, climate, infrastructure, and energy market with an emphasis on how these affect upstream oil and gas industry investment. A detailed description and analysis is given of the petroleum production sharing contract ("PSC") terms embodied in India's New Exploration Licensing Policy ("NELP"), and demonstrates that, depending on negotiations, Government Take under NELP terms is likely to be in the range 50% to 60% for a stand-alone petroleum development. However, PSC terms are regressive for marginal discoveries. In particular, State royalties might hinder the development of small or marginal discoveries and render them uneconomic. As an illustration, depending on the oil price, up to 6 MMbbls of oil in otherwise economically viable small fields in a geological basin might be made uneconomic and left stranded because of the effect of royalties. The thesis also analyses the economics of developing a sample of actual Indian oil and gas fields offshore the east and west coasts of the country in shallow and deep water. Onshore field developments are not analysed because of lack of data. All of the offshore developments analysed are profitable based on past and current economic conditions and knowledge. The majority are also relatively low-risk investments. Finally, the thesis evaluates the profitability of new oil and gas exploration and development offshore the east and west coasts of India. The required minimum size of new exploration prospects are in the range 10 to 17 MMbbls for oil prospects and 138 to 1,100 Bcf for gas prospects assuming a low probability of success. Once a new discovery is made, the required minimum economically developable reserves are 4 to 12 MMbbls for oil discoveries and 63 to 1,400 Bcf for gas discoveries. Contents Page 1

The economics of petroleum exploration and development in India

Contents

Acknowledgements

Page Chapter 1 Introduction 1.1

Chapter 2 Summary and Conclusions 2.1

Chapter 3 Geography 3.1 Petroleum activities 3.2 3.2 Climate 3.4 3.3 Topography 3.5 3.4 Rivers 3.6 3.5 Vegetation 3.8 3.6 Population 3.9

Chapter 4 Infrastructure 4.1 The economy 4.1 4.2 The oil and gas industry 4.3 4.2.1 Sedimentary basins of India 4.5 4.2.2 Key players of petroleum sector 4.6 4.3 Labour market 4.8 4.4 Roads 4.8 4.5 Railways 4.9 4.6 Airports 4.10 4.7 Ports 4.11 4.8 Electricity distribution 4.13 4.9 Telecommunications 4.14 4.10 Refineries 4.14 4.11 Pipelines 4.18

Sajith Venugopal July 2005 Contents Page 2

Page Chapter 5 Energy Market in India 5.1 Crude Oil 5.1.1 Crude oil demand/supply 5.2 5.1.2 Crude oil pricing 5.4 5.2 Petroleum Products 5.2.1 Petroleum product supply 5.6 5.2.2 Petroleum product demand 5.7 5.2.3 Petroleum product quality 5.11 5.3 Natural Gas 5.3.1 Natural gas supply 5.13 5.3.2 Natural gas demand 5.14 5.3.3 Additional natural gas 5.16 5.3.4 Natural gas pricing 5.21 5.4 Liquefied Petroleum Gas (LPG) 5.4.1 LPG supply 5.28 5.4.2 LPG demand 5.30 5.4.3 LPG pricing 5.30 5.5 Coal 5.5.1 Coal supply 5.31 5.5.2 Coal demand 5.34

Chapter 6 Fiscal Regime 6.1 Structure 6.3 6.2 Illustration of workings of Indian PSC 6.4 6.3 Components of Indian NELP PSCs 6.3.1 Royalty 6.7 6.3.2 Cost Recovery 6.7 6.3.3 Profit Sharing 6.11 6.3.4 Income Tax 6.12 6.4 Worked example of an Indian NELP PSC 6.13

Sajith Venugopal July 2005 Contents Page 3

Page Chapter 7 Fiscal Analyses 7.1 Government Take 7.1 7.2 Assumptions 7.2.1 Economic assumptions 7.2 7.2.2 Development assumptions 7.3 7.2.3 Fiscal assumptions 7.3 7.2.4 Summary of assumptions 7.3 7.3 Impact of individual components of Government Take 7.5 7.4 Reserves deemed uneconomic because of Government Take 7.11 7.5 Summary and conclusions 7.17

Chapter 8 Economics of Ravva oil and gas development 8.1 Introduction 8.1 8.2 Assumptions 8.3 8.2.1 Participating interest 8.3 8.2.2 Past oil prices, production and revenues 8.4 8.2.3 Past costs 8.5 8.2.4 Past and future gas prices 8.5 8.2.5 Future oil prices 8.5 8.2.6 Future production 8.5 8.2.7 Exploration and development costs 8.8 8.2.8 Operating costs 8.8 8.2.9 Abandonment costs 8.9 8.2.10 Escalation 8.9 8.2.11 Discounting 8.9 8.2.12 Summary of assumptions 8.9 8.3 PSC terms 8.3.1 Contract period 8.11 8.3.2 Compensation for import waiver 8.11 8.3.3 Production payments 8.11 8.3.4 Cess and Royalty 8.13 8.3.5 Cost petroleum 8.13 8.3.6 Abandonment sinking fund 8.13

Sajith Venugopal July 2005 Contents Page 4

Page 8.3.7 Profit petroleum 8.14 8.3.8 Income tax 8.17 8.4 Results 8.18 8.4.1 Net cash flow 8.19 8.4.2 Components of Government Take 8.20 8.4.3 Sensitivities and uncertainties 8.4.3.1 Spider diagram 8.21 8.4.3.2 PTTR effects – changing front-end development costs 8.24 8.4.3.3 PTTR effects – changing mid-field life costs 8.25 8.4.3.4 Arbitration 8.27 8.4.3.5 Monte Carlo simulation 8.31 8.5 Summary and conclusions 8.33

Chapter 9 Economics of D-1 South oil development 9.1 Introduction 9.1 9.2 Assumptions 9.2.1 Oil prices 9.2 9.2.2 Future production 9.2 9.2.3 Exploration costs 9.3 9.2.4 Development costs 9.3 9.2.5 Operating costs 9.4 9.2.6 Abandonment costs 9.5 9.2.7 Escalation 9.5 9.2.8 Discounting 9.6 9.2.9 Summary of assumptions 9.6 9.3 PSC terms 9.3.1 Cess and Royalty 9.7 9.3.2 Cost petroleum 9.8 9.3.3 Abandonment sinking fund 9.8 9.3.4 Income tax 9.8 9.4 Results 9.9 9.4.1 Net cash flow 9.10 9.4.2 Components of Government Take 9.10 9.4.3 Sensitivity analyses 9.12

Sajith Venugopal July 2005 Contents Page 5

Page 9.4.4 Monte Carlo simulation 9.13 9.5 Summary and conclusions 9.16

Chapter 10 Economics of PY-1 gas development 10.1 Introduction 10.1 10.2 Assumptions 10.2.1 Gas prices 10.2 10.2.2 Condensate prices 10.3 10.2.3 Production 10.3 10.2.4 Exploration and development costs 10.5 10.2.5 Operating costs 10.5 10.2.6 Abandonment costs 10.6 10.2.7 Escalation 10.6 10.2.8 Discounting 10.6 10.2.9 Summary of assumptions 10.6 10.3 PSC terms 10.3.1 Cess and Royalty 10.8 10.3.2 Cost petroleum 10.8 10.3.3 Abandonment sinking fund 10.8 10.3.4 Profit petroleum 10.9 10.3.5 Income tax 10.10 10.4 Results 10.11 10.4.1 Net cash flow 10.12 10.4.2 Components of Government Take 10.13 10.4.3 Sensitivity analyses 10.4.3.1 Spider diagram 10.14 10.4.3.2 Monte Carlo simulation 10.16 10.5 Summary and conclusions 10.19

Chapter 11 Economics of KG-DWN-98/3 gas development 11.1 Introduction 11.1 11.2 Assumptions 11.2.1 Participating interest 11.3 11.2.2 Future gas price 11.3

Sajith Venugopal July 2005 Contents Page 6

Page 11.2.3 Future production 11.3 11.2.4 Exploration costs 11.6 11.2.5 Development costs 11.6 11.2.6 Operating costs 11.7 11.2.7 Abandonment costs 11.7 11.2.8 Escalation 11.7 11.2.9 Discounting 11.8 11.2.10 Summary of assumptions 11.8 11.3 PSC terms 11.3.1 Royalty 11.10 11.3.2 Cost petroleum 11.10 11.3.3 Abandonment sinking fund 11.10 11.3.4 Profit petroleum 11.11 11.3.5 Income tax 11.12 11.4 Results 11.13 11.4.1 Net cash flow 11.14 11.4.2 Components of Government Take 11.15 11.4.3 Sensitivity analyses 11.16 11.4.4 Monte Carlo simulation 11.20 11.5 Summary and conclusions 11.22

Chapter 12 Economics of exploration 12.1 Objectives 12.1 12.2 Cases analysed 12.1 12.3 Approach 12.2 12.4 Assumptions 12.4.1 Economic assumptions 12.3 12.4.2 Market assumptions 12.5 12.4.3 Exploration and development assumptions 12.5 12.5 Net present value per barrel or per thousand cubic feet graphs 12.8 12.6 Minimum prospect reserves graphs 12.10 12.7 Offshore eastern India – Ravva area 12.13 12.8 Offshore western India – D-1 area 12.18 12.9 Offshore eastern India – PY-1 area 12.23

Sajith Venugopal July 2005 Contents Page 7

Page 12.10 Offshore eastern India – KG-DWN-98/3 area 12.28 12.11 Summary and conclusions 12.33

Appendix A - Sedimentary basins of India A.1

Appendix B - Conversions B.1

Appendix C - New Exploration Licensing Policy (“NELP”) Blocks C.1

Appendix D - Oil price assumption D.1

Appendix E - Abandonment sinking fund calculation E.1

Appendix F - Reserves F.1

Appendix G - Economic indicators G.1

Appendix H - Letter from Petrowatch H.1

References R.1

Sajith Venugopal July 2005 Contents Page 8

The economics of petroleum exploration and development in India

Contents

List of figures

Figure Page 3.1 Location map of India 3.1 3.2 Petroleum activity map of India 3.3 4.1 India’s GDP growth rate 4.1 4.2 Key player’s of Indian petroleum sector 4.7 4.3 Ports in India 4.12 4.4 Refineries in India 4.17 4.5 Crude oil and petroleum product pipelines in India 4.20 4.6 Gas pipelines in India 4.22 5.1 India’s energy flowchart for 2003 5.1 5.2 Crude oil pricing 5.5 5.3 Petroleum products from crude oil 5.7 5.4 Self sufficiency in petroleum products 5.11 5.5 Importing natural gas to India 5.17 5.6 Consumer gas prices around India 5.27 5.7 Trends in Indian LPG market 5.29 5.8 Coal and lignite production during last five fiscal years 5.32 6.1 Structure of Indian NELP PSC 6.4 7.1 Impact of components of Government Take 7.5 7.2 Fiscal components as percentage of project’s NPV 7.7 7.3 Economic effects of Indian fiscal regime 7.11 7.4 Field size distribution 7.13 7.5 Fields that remain undeveloped in the basin 7.16 8.1 Location map (Ravva) 8.1 8.2 Ravva facilities 8.2 8.3 Oil production profile (Ravva) 8.6 8.4 Associated gas production profile (Ravva) 8.7 8.5 Non - associated gas production profile (Ravva) 8.8 8.6 Net cash flow against time (Ravva) 8.19

Sajith Venugopal July 2005 Contents Page 9 Figure Page 8.7 Components of Government Take (Ravva) 8.20 8.8 Spider diagram (Ravva) 8.22 8.9 Effect of development cost on profit petroleum (Ravva) 8.25 8.10 Government’s share of profit petroleum (Ravva) 8.26 8.11 Profit petroleum based on “ONGC Carry costs” (Ravva) 8.28 8.12 Profit petroleum based on company net cash flow (Ravva) 8.30 8.13 Ravva NPV frequency distribution 8.32 8.14 Cumulative probability against NPV (Ravva) 8.33 9.1 Location map (D-1) 9.1 9.2 Oil production profile (D-1) 9.3 9.3 Net cash flow against time (D-1) 9.10 9.4 Components of Government Take (D-1) 9.11 9.5 Spider diagram (D-1) 9.12 9.6 D-1 NPV frequency distribution 9.15 9.7 Cumulative probability against NPV (D-1) 9.16 10.1 Location map (PY-1) 10.1 10.2 Gas production profile (PY-1) 10.4 10.3 Condensate production profile (PY-1) 10.5 10.4 Net cash flow against time (PY-1) 10.12 10.5 Components of Government Take (PY-1) 10.13 10.6 Spider diagram (PY-1) 10.15 10.7 PY-1 NPV frequency distribution 10.18 10.8 Cumulative probability against NPV (PY-1) 10.19 11.1 Location map (KG-DWN-98/3) 11.1 11.2 Gas production profile (KG-DWN-98/3) 11.5 11.3 Net cash flow against time (KG-DWN-98/3) 11.14 11.4 Components of Government Take (KG-DWN-98/3) 11.16 11.5 Spider diagram (KG-DWN-98/3) 11.17 11.6 Operating cost sensitivity (KG-DWN-98/3) 11.19 11.7 KG-DWN-98/3 NPV frequency distribution 11.21 11.8 Cumulative probability against NPV (KG-DWN-98/3) 11.22 12.1 An example of net present value per million cubic feet graphs 12.9 12.2 An example of minimum reserves graphs 12.12 12.3 Base case oil field development economics for offshore eastern 12.15 India – (Ravva area)

Sajith Venugopal July 2005 Contents Page 10

Figure Page 12.4 Base case oil exploration economics for offshore eastern India 12.15 – (Ravva area) 12.5 Sensitivity of oil field development economics for regions near 12.16 Ravva field (shallow offshore eastern India) 12.6 Sensitivity of oil exploration economics for regions near Ravva 12.17 field (shallow offshore eastern India) 12.7 Base case oil field development economics for offshore 12.20 western India – (D-1area) 12.8 Base case oil exploration economics for offshore western India 12.20 – (D-1 area) 12.9 Sensitivity of oil field development economics for regions near 12.21 D-1 field (shallow offshore western India) 12.10 Sensitivity of oil exploration economics for regions near D-1 12.22 field (shallow offshore western India) 12.11 Base case gas field development economics for offshore 12.25 eastern India – (PY-1area) 12.12 Base case gas exploration economics for offshore eastern India 12.25 – (PY-1 area) 12.13 Sensitivity of gas field development economics for regions near 12.26 PY-1 field (shallow offshore eastern India) 12.14 Sensitivity of gas exploration economics for regions near PY-1 12.27 field (shallow offshore eastern India) 12.15 Base case gas field development economics for deepwater 12.30 offshore eastern India – (KG-DWN-98/3 area) 12.16 Base case gas exploration economics for deepwater offshore 12.30 eastern India – (KG-DWN-98/3 area) 12.17 Sensitivity of gas field development economics for regions near 12.31 KG-DWN-98/3 field (deepwater offshore eastern India) 12.18 Sensitivity of gas exploration economics for regions near KG- 12.32 DWN-98/3 field (deepwater offshore eastern India)

Sajith Venugopal July 2005 Contents Page 11

The economics of petroleum exploration and development in India

Contents

List of tables

Table Page 2.1 Summary of economics of field developments 2.3 2.2 Summary of results 2.6 3.1 Distribution pattern of petroleum licenses 3.2 4.1 Sector wise real growth rates of GDP 4.2 4.2 Types of basins 4.6 4.3 Refineries in India (Barrels per day) 4.16 4.4 Product pipelines planned by RIL 4.19 5.1 Crude Oil supply in India (Million barrels) 5.3 5.2 Consumption of petroleum products in India (Million barrels) 5.8 5.3 Compounded annual growth rate for petroleum products 5.9 5.4 Projected availability of petroleum products (Million barrels) 5.10 5.5 Natural gas production in India (MMSCFD) 5.13 5.6 Natural gas supply (MMSCFD) 5.14 5.7 Trend in natural gas consumption (MMSCFD) 5.15 5.8 Proposed LNG projects 5.18 5.9 Blocks awarded for CBM exploration 5.20 5.10 Consumer price phased linkage to international prices 5.22 5.11 Sales tax on natural gas 5.24 5.12 Petronet LNG’s gas delivery price in 5.26 5.13 Coal production during last five fiscal years (MOET) 5.33 5.14 Transport of coal 5.33 5.15 Consumer wise offtake of coal (Million oil equivalent tonnes) 5.34 5.16 Coal imports (Million oil equivalent tonnes) 5.35 6.1 Illustration of net cash flow calculations for one year under NELP 6.5 terms 6.2 Royalty rates 6.7 6.3 Illustration of profit split tranches 6.11 6.4 Normal income tax calculation 6.12

Sajith Venugopal July 2005 Contents Page 12

Table Page 6.5 Minimum Alternative Tax (“MAT”) calculation 6.13 7.1 Summary of assumptions as applied in NELP bidding rounds 7.5 7.2 Effects of fiscal components on minimum developable field size 7.8 7.3 Oil volumes not developed / stranded due to Government Take 7.17 8.1 Participating interests (Ravva) 8.3 8.2 Estimates of past average annual prices for Ravva oil 8.4 8.3 Summary of assumptions (Ravva) 8.10 8.4 Compensation paid to Government 8.11 8.5 Production payments to ONGC 8.12 8.6 Past production payments 8.12 8.7 Profit sharing (Ravva) 8.14 8.8 Initial Notional Tax calculation (Ravva) 8.15 8.9 Minimum Alternative Tax calculation (Ravva) 8.16 8.10 Illustration of PTRR calculation (Ravva) 8.17 8.11 Results for base case (Ravva) 8.18 9.1 Development cost for D-1 field (US$MM) 9.4 9.2 Operating costs for D-1 field (US$MM) 9.5 9.3 Summary of assumptions (D-1) 9.7 9.4 Results for base case (D-1) 9.9 10.1 Gas contract price (PY-1) 10.3 10.2 Summary of assumptions (PY-1) 10.7 10.3 Profit split tranches for PY-1 PSC 10.10 10.4 Results for base case (PY-1) 10.11 11.1 Production profile for Phase I production (KG-DWN-98/3) 11.4 11.2 Expenditure made for field development (KG-DWN-98/3) 11.7 11.3 Summary of assumptions (KG-DWN-98/3) 11.9 11.4 Profit split tranches for KG-DWN-98/3 PSC 11.12 11.5 Results for base case (KG-DWN-98/3) 11.13 12.1 Cases analysed 12.1 12.2 Appraisal, production and development cost phasing – Oil fields 12.6 12.3 Base case economic analyses results – Oil offshore eastern India – 12.13 (Ravva area) 12.4 Base case economic analyses results – Oil offshore western India 12.18 – (D-1 area)

Sajith Venugopal July 2005 Contents Page 13

Table Page 12.5 Base case economic analyses results – Gas offshore eastern India 12.23 – (PY-1 area) 12.6 Base case economic analyses results – Gas deepwater offshore 12.28 eastern India – (KG-DWN-98/3 area)

Sajith Venugopal July 2005 University of New South Wales

Chapter 1

Introduction

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 1.1

In this thesis, I attempt to provide a detailed understanding of the factors that influence the economics of exploring for and developing petroleum resources in India from the international oil and gas industry investor’s point of view. The thesis also aims to demonstrate the profitability of exploration and oil and gas discoveries in representative areas in offshore regions of the country and to show the economic effects of the fiscal terms on exploration and field development. I do not incorporate analyses of onshore field developments because of lack of sufficient data.

The contents of the thesis are summarised below.

Chapter 3 describes the petroleum activities in India, the country’s climate, topography, its rivers, land and population.

Chapter 4 gives a description of India’s economy, the sedimentary basins and the key participants in the Indian oil and gas industry. This chapter also gives information on the economic infrastructure and the oil and gas infrastructure available in India.

Chapter 5 describes the energy market in India. In doing so, this chapter includes information on the supply, demand, quality and pricing of crude oil, petroleum products, natural gas, liquefied petroleum gas and coal.

Chapter 6 describes the fiscal terms that apply to the Indian petroleum industry and describes how the fiscal terms apply to a hypothetical stand-alone field development.

Chapter 7 presents an analysis of the impact the various components of the Indian fiscal regime have on field development economics. This chapter also contains an estimate of the oil discoveries that are rendered uneconomic because of the effects of Government Take.

Chapter 8 describes the results of an analysis of the economics of the Ravva oil and gas development in the shallow water off the east coast of India. I analyse the effects of the Post Tax Rate of Return (“PTRR”) regime under which Ravva field operates. I also conduct an investigation of the issued involved in a recent arbitration case involving the Government of India and the operator at Ravva field.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 1.2

Chapter 9 shows the results of economic analyses of the D-1 South field development. D-1 South field lies in the shallow water off the west coast of India.

Chapter 10 shows the results of economic analyses of the PY-1 gas field development. PY-1 field lies in the shallow water off the east coast of India.

Chapter 11 describes the results of economic analyses of the KG-DWN-98/3 gas field development. This field lies in deepwater regions on the east coast of India.

Chapter 12 shows the results of economic and sensitivity analysis of field development and exploration in India. The analysis carried out demonstrates the profitability of representative oil and gas discoveries in the areas described in Chapters 8, 9, 10 and 11.

I would like to thank the following people for their help in preparing this thesis.

Mr. Guy Allinson.

Mr. Deepak Mehta.

Mr. Madhu Nainan.

Sajith Venugopal July 2005 University of New South Wales

Chapter 2

Summary and Conclusions

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 2.1

Geography

Though tropical, the climate in India would not hinder exploration and development of petroleum resources. Although very little exploration has been carried out in onshore areas, there is little geographical risk. The Government has recently offered onshore blocks located at the foothills of the Himalayan mountain range and these might present some challenges, although they should be surmountable.

Politics

Over most of the country, there are few if any political obstacles to exploration and development activity. Previously, terrorist activity affected petroleum operations in the state of . There used to be a constant threat to petroleum installations such as pipelines and refineries. Today, the business environment is more stable as the state government provides security to large number of companies operating in the area. Nevertheless, Oil and Natural Gas Corporation (“ONGC”), one of the national oil companies operating in Assam is often under pressure from various political groups who claim that ONGC has done little to develop the state.

Infrastructure

The infrastructure in most cities around India is well established. Current additional investments on the development of road, rail, telephone and electricity networks should improve the infrastructure further. The government’s planned development of the pipeline network for crude oil, natural gas and petroleum products will assist petroleum exploration and development. India’s large labour force of qualified personnel with oil and gas experience should also assist investors establishing operations in the country.

Energy market

The boom in India’s economy has resulted in an increase in the demand for energy. Even though recent oil and gas discoveries look encouraging, India’s projected energy

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 2.2 demands indicate that the country will remain dependent on crude oil and natural gas imports for the foreseeable future.

Excess refining capacity coupled with an expected increase in refining capacity will facilitate the marketing of crude oil discoveries.

The development of transnational gas pipelines will improve the ability of gas producers to market their product. Natural gas is expected to be in greatest demand in western parts of India as most industries ranging from power, fertiliser to glass manufactures are located there. Reliance’s huge gas discovery on the east coast of India in deepwater offshore might help satisfy existing gas demand in the eastern parts of the country. However, this is to some extent counterbalanced by increasing demand from economic growth in that area.

Fiscal regime

Incentives offered under the New Exploration Licensing Policy (“NELP”) have resulted in increased interest among foreign investors. The Government Take from field development of blocks offered under NELP is likely to between 50% and 60% depending on the terms negotiated.

Analyses of the fiscal regime show that royalty have the most influence on the development of marginal fields. However, for large discoveries the Government’s share of profit petroleum has the greatest impact. A study of the effects of Government Take shows that fiscal terms are regressive at low field size largely because of royalties, but become progressive with larger discoveries. Because of the fact that the NELP terms are regressive for small fields, depending on the price of oil, significant volumes of oil might be rendered uneconomic by the fiscal terms.

Economics of Oil and Gas field developments

The following table and text summarises the results of economic analyses of a sample of existing or planned oil and gas developments in India. The NPVs measured are at the start of PSCs.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 2.3

Table 2.1 – Summary of economics of field developments

Fields analysed Ravva D-1 PY-1 KG-DWN-98/3 NPVs (US$MM) For base case 482.85 91.61 13.64 1,702.86 For P90 level 753.77 218.93 22.57 1,780.03 For P50 level 479.13 72.28 13.90 1,648.37 Mean 528.70 85.07 13.88 1,644.92 For P10 level 367.06 -29.34 5.61 1,491.85

Probability of ------19.00 2.20 ------negative NPV (%)

IRR (%) 37.62 26.49 14.91 24.40

Government Take (%) 73.83 67.41 62.38 75.80

Ravva

The Ravva field development is located offshore the east coast of India in the Krishna Godavari Basin. Ravva produces both oil and gas. The gas production consists of gas associated with oil production plus gas from a separate satellite field in the south west of the contract area. At the time of writing, oil production is approximately 50,000 barrels of oil per day and the total gas production is approximately 90 million cubic feet per day.

The economics of Ravva are strongly influenced by the terms of Ravva PSC. Under some circumstances, investment decisions on the timing and level of expenditure and production can be influenced strongly by the effect of the PSC profit sharing mechanism.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 2.4

D-1

The D-1 South field development, located offshore the western coastline of India in Mumbai Offshore Basin. D-1 South is an oil field with small quantities of associated gas. ONGC plans to produce about 34 MMbbl over 10 years.

The economics of D-1 oil field are strongly influenced by the terms of D-1 PSC. The main sources of income to the Government are from fiscal components such as royalty, cess and income tax.

PY-1

The PY-1 field development is located offshore the southeastern coastline of India in the Cauvery Basin. PY-1 is basically a gas field with small quantities of associated condensate. At the time of writing, Hindustan Oil Exploration Company Limited (“HOEC”) has a 100% participating interest in PY-1 gas field. The development of the PY-1 field began in early 2004 and first gas is expected to be brought to shore by early 2006.

The economics of PY-1 oil field are strongly influenced by the terms of PY-1 PSC. The profit sharing arrangement described in the PSC ensures that the Government’s share of profit petroleum yields the most revenue to the Government over the life of the project.

Sensitivity analysis shows that the value of PY-1 project is most sensitive to the changes made to the development costs and least sensitive to the variations in operating costs.

KG-DWN-98/3

The KG-DWN-98/3 field development is located offshore the eastern coastline of India in the Krishna Godavari Basin in deepwater regions. KG-DWN-98/3 field is a gas discovery with some condensate. Limited (“RIL”) is the operator of the field and plans to begin gas production in year 2008.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 2.5

The economics of KG-DWN-98/3 gas field are strongly influenced by the terms of KG- DWN-98/3 PSC. The profit sharing arrangement described in the PSC ensures that even though profit sharing starts in 2011, this component that yields maximum revenue to the Government over the life of the project.

Economics of exploration

Table 2.1 contains a summary of the results of economic analyses of field development and exploration in representative areas across India. The table shows a) the minimum reserves required to justify the development of a new discovery and b) the value of reserves and the minimum prospect size required to justify exploration drilling.

An oil price of US$ 28 per barrel and a gas price of US$ 3 per giga joule have been assumed.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 2.6

Table 2.2 – Summary of results

Development Exploration Minimum Minimum economic field Net present prospect size Cases reserves value for 20% POS* Oil MMbbls US$/bbl MMbbls Shallow offshore east coast of India (Krishna Godavari Basin) 12 2.78 17.3

Shallow offshore west coast of India (Mumbai Offshore Basin) 4 3.18 10.0 Gas Bcf US$/Mcf Bcf Shallow offshore east coast of India (Cauvery Basin) 63 0.17 138

Deepwater offshore east coast of India (Krishna Godavari Basin) 1,400 0.25 1,100 *POS = Probability of success.

The minimum economic field reserves required for the successful development of an oil field in shallow water areas on the west coast of India is lower than that required for an oil field development on the east coast. This is because of the variations in well costs, productions rates and other development assumptions. In addition, more exploration and development work has been carried out in offshore regions of the west coast of India and the oil and gas infrastructure here is more developed. As a result of this, costs of exploration and development is lower in this region as compared to the east coast of India and the economics were favourable.

The minimum economic field reserves required to justify gas field development in shallow water areas of India is significantly smaller than in the deepwater regions. Even though deepwater areas enjoy better fiscal terms as compared to shallow water

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 2.7 areas, the economics require significantly larger discoveries to overcome the larger costs of exploration and development.

Sajith Venugopal July 2005 University of New South Wales

Chapter 3

Geography

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.1

A location map of India is shown in Figure 3.1. India shares its borders with , Nepal, Burma, Bhutan, China and Bangladesh, and is separated from Sri Lanka by a narrow channel of sea formed by the Palk Strait and the Gulf of Mannar. Andaman and Nicobar Islands in the Bay of Bengal and Lakshadweep in the Arabian Sea are parts of India.

India is the seventh largest country in the world. It measures 3,214 kilometres (“kms”) from north to south and 2,933 kms from east to west at its widest point and has a total area of 3.28 million square kilometres (“sq.kms”). It has a land frontier (length of its border with other countries) of 15,200 kms and a coastline of 7,517 kms (when including the island territories) or 5,600 kms of coastline (without the islands).

Figure 3.1 – Location map of India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.2

3.1 Petroleum activities

Figure 3.2 is a petroleum activity map of India. Petroleum operations are being carried out by national and private companies in 498 concessional areas. Out of these 253 are under Petroleum Exploration Licenses (“PEL”) and 245 under Mining Licenses (“ML”).

Table 3.1 below shows the distribution pattern of the two licenses.

Table 3.1 – Distribution pattern of petroleum licenses

PEL ML Company-wise National oil companies (ONGC, OIL) 63% 77% Private or joint venture companies 37% 23%

Basin-wise Onland 28% 58% Offshore 72% 42%

To date, more than 100 contracts have been signed with private oil and gas companies for the exploration and development of oil and gas. Out of these, 19 pre- NELP (New Exploration Licensing Policy) contracts are in place in which exploration activities are being undertaken by private companies. The Government has signed 90 contracts under four NELP rounds. This does not include contracts that might be awarded under the NELP V licensing round. At present exploration work is in progress in 81 blocks.

The major foreign and Indian companies operating in India are Oil and Natural Gas Corporation (“ONGC”), Limited (“OIL”), Reliance Industries Limited (“RIL”), Cairn Energy India Private Limited (“CAIRN”), Shell India Limited (“SIL”), Videocon Petroleum Limited (“VPL”), Niko Resources Limited (“NIKO”), Hardy Exploration and Production India (“HEPI”), British Gas Exploration and Production India Limited

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.3

(“BGEPIL”), Gas Authority of India Limited (“GAIL”), Geo Global Resources (India) Incorporated (“GEO”)etc.

The Indian government is planning to offer deepwater blocks in future rounds of NELP bidding.

Figure 3.2 – Petroleum activity map of India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.4

3.2 Climate

India has tropical weather with variations occurring from region to region. The northern plains experience vast temperature ranges, with cooler winters and hotter summers. The mountain areas have cold winters and cool summers. As elevations increase sharply in the mountains, climate type can change from subtropical to polar within a few miles.

India has 3 main seasons in a year xRainy – south west monsoon from June to September; north east monsoon between October and November xSummer – from April to July xWinter – from mid-October to February

The rainy season sets in with the south west monsoon in early June. It then progresses northward to cover the whole nation by the end of July. The eastern coastal belts experience north east monsoon during October and November. Along the east coast, during the monsoon period a series of cyclones develop due to severe atmospheric depression in the Bay of Bengal and Indian Ocean.

The summer season in India is at its fiercest from April to July. North India is the most unpleasant during summer, as it remains dry, humid and dusty. Parts of central India escape the very worst of summer season and are considered pleasant. Summers can be extremely hot in western and southern parts of India. The humidity levels during summer are at extreme levels in south India.

Winters in India are pleasant with many sunny days. During winter, the mountain slopes and northern plains experience cold temperatures and reach freezing temperatures at night. Central and western parts of India experience cool evenings. In southern India, there is no winter as the temperatures are very mild. Dry weather generally accompanies the cool winter season, although severe storms sometimes

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.5 traverse the country, yielding slight precipitation on the northern plains and heavy snowfall in the Himalayas (reference 1).

3.3 Topography

India’s topography can be divided into three main regions xthe Himalayas and the associated mountain ranges xthe Gangetic (Indus Ganga Bramhaputra) plain and xthe Peninsular plateau of India.

Himalayas and associated mountain ranges

“The Himalayan range is the highest mountain system in the world” (reference 2). It extends for a distance of 2,400 kms along the northern and eastern borders of India. It contains the world’s highest mountain peak - Mount Everest and ten peaks rising above 7,700 meters. All areas along the Himalayan region, including the foothills are sparsely settled. The main economic activities here are agriculture and animal herding.

Gangetic plain

The Gangetic plain lies south and parallel to the Himalayas. It is a belt of flat, alluvial lowlands. The plain is formed by the Indus, Ganga and the Bramhaputra rivers. The plain extends for 3,200 kms between the mouths of River Ganga and River Indus and is 280 to 400 km wide. This area is one of the most agriculturally productive lands in India. The broad Gangetic plain contains several river systems and stretches from Punjab in the west to the Assam Valley in the east.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.6

Peninsular plateau

Below the Gangetic plains region is peninsular India. “The northern peninsula features a series of mountain ranges and plateaus. The rocky and uneven lands of the northern peninsula are sparsely populated” (reference 2). The major occupation in the western region of the peninsula is animal herding. Coarse grain farming is common in the central part.

“In the southern part of peninsular India lies a series of mountain ranges like the vast Deccan plateau, the steep mountain slopes of the Western Ghats, and the gentler slopes of the Eastern Ghats. Elevations in the plateau region average 600 meters (“m”), although outcroppings as high as 1,200 m occur” (reference 2). The Western Ghats vary in height from 900 to 1,200 m at its northern end and to 2,637 m at its southern end. The Eastern Ghats lie to the east of the Deccan Plateau and are interrupted by the Krishna and Godavari river basins. Elevations of the Eastern Ghats are on an average about 600 m. This region houses a host of industrial enterprises and also supports some agricultural population.

Along the seashores of the Indian Peninsula are very fertile lands. Most populations of farmers and fishermen are located in the west coast, the Gujarat Plain in the north, the Konkan shore in state, and the Malabar Coast in the south. Intense farming occurs in the east coast’s broad alluvial plains, stretching from the Kaveri River delta in the south to the Mahanadi River delta in the north.

3.4 Rivers

The rivers of India can be classified into three groups xthe Himalayan rivers (Indus, Ganga and Brahmaputra) xthe westward flowing rivers of central India xthe eastward flowing rivers of the Deccan plateau and the rest of peninsular India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.7

Himalayan rivers

The Indian subcontinent’s three great northern rivers, the Indus, the Ganga and the Brahmaputra are both snow-fed and rain-fed and thus have continuous flow throughout the year. The Indus, about 2,900 kms, originates from Mount Kailas in the Himalayas, flows through the Ladakh region of Jammu and Kashmir, and then enters Pakistan before falling into the Arabian Sea. The Brahmaputra is about 2,900 kms long and rises in the Himalayas. It flows through Assam state and then through Bangladesh to the Bay of Bengal. The 2,510 kms Ganga rises from Gangotri in the Himalayas and flows through various states in central India before discharging its water into the Bay of Bengal. The Himalayan rivers discharge about 70% of their inflow into the sea.

Westward flowing rivers

India’s major westward flowing river is River Narmada. It is 1,289 kms long, and empties itself into the Arabian Sea. “Its basin consists of about 5 million cultivable hectares. A series of large dams are being constructed on the river as part of a massive development scheme to increase irrigation of the basin” (reference 2). Other rivers flowing west into the Arabian Sea include the three tributaries of Indus River – Chenab, Ravi and Sutlej and rivers like Mahi, Sabarmati, and Tapi.

Eastward flowing rivers

The three major rivers that flow east into the Bay of Bengal are Godavari (1,400 kms long), Krishna (about 1,300 kms long) and river Kaveri (760 kms long). Other significant rivers flowing east into the Bay of Bengal include the tributaries of Ganga. These are Kosi, Gandak, Ghaghara, Gumti and Sarda rivers from the north and Betwa, Chambal, and Son rivers from the south. The Mahanadi river (rising from Chhattisgarh) and river Brahmani (rising from Orissa) are other eastward flowing rivers.

Irrigation of crops is carried out using the waters of all these rivers. However, the amount of water that is stored for purposes such as irrigation and power generation varies enormously from river to river. Water storage depends among other things on the number of dams along the rivers. Only small portions of India’s rivers are

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.8 navigable because of silting and the wide seasonal variation in water flow (due to the monsoon climate). Water transport is thus of little importance in India.

3.5 Vegetation

Forests cover 22 percent of India’s land area. India’s highly varied climate and land produce very dense forests. The majority of forests are either tropical-dry or tropical-moist. “The remainder of forests range in type from tropical evergreen to Himalayan temperate and alpine. Major commercial tree species include teak, rosewood, and sal” (reference 2).

In the higher slopes of Himalayas one can find many varieties of arctic flora. Subtropical plants like orchid are found in the lower levels of the mountain range. Dense forests remain in the few areas where agriculture and commercial forestry have had little effect. Trees like cedar and pine are found in northwestern Himalayan region. Tropical and subtropical types of vegetation bind the eastern slopes of the Himalayas.

The Gangetic plain, with most rivers running through it has more moisture and hence supports many types of plant life. Vegetation is especially luxuriant in the southeastern part of the plains where mangroves and timber trees flourish.

The Assam Valley is an area of evergreen forests, bamboo, and lands with tall grasses. The Malabar Coast is thickly wooded. Evergreens, bamboo, and several varieties of valuable timber trees like teak can be found in this region. Large and extensive jungles are found along the lower elevations of the Western Ghats. The vegetation of the peninsular plateau is less luxuriant. Bamboo, palm, and deciduous trees grow throughout the Deccan Plateau. The Andaman and Nicobar Islands have tropical forests, both evergreen and semi evergreen.

“India has an estimated 45,000 species of plants, 33 percent of which are native. There are 15,000 flowering plant species, 6 percent of the world’s total. About 3,000 to 4,000 of the total number of plant species are believed to be in danger of extinction”. (reference 2)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 3.9

3.6 Population

India is the second most populous country in the world. In July 2004, India’s population was estimated to be 1.06 billion with an annual growth rate of 1.44 percent. The population is estimated to grow to 1.33 billion by 2020.

The average population density is 358 persons per square kilometre (“sq.km”). About 72% of the population lives in rural areas. There are 28 cities in India that are populated by more than a million people. Out of these 28 cities, the 4 most populated are Kolkata with 13.2 million (2001 census), followed by Delhi (12.8 million), Mumbai (11.9 million) and Chennai (6.42 million).

More than half the population of India is under 25 years of age. India has a literacy rate of 70.2 percent for males and 48.35 percent for females. (reference 3)

Sajith Venugopal July 2005 University of New South Wales

Chapter 4

Infrastructure

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.1

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

4.1 The economy

The economy of India has witnessed steady economic growth in the past decade. A prime reason for this is the industrial reforms announced by the central Government in July 1991.

The real gross domestic product (“GDP”) is estimated to have grown by 8.1% in 2003- 2004. Figure 4.1 below shows how the real Indian GDP has grown since 1996-1997.

Figure 4.1 – India’s GDP growth rate

9 8.1 8 7.8

7 6.5 6.1 6 5.8

5 4.8 4.4 4 4

Percentage (%) Percentage 3

2

1

0 1996-97 1997-98 1998-99 1999-2000 2000-01 2001-02 2002-03 2003-04 Time

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.2

Agriculture contributes to about 25% of GDP and almost 60% of the population depends directly on it. Industry and service sectors account for the remaining 25% and 50% of GDP respectively (reference 4).

Table 4.1 shows the sector wise growth rates of GDP. In the early 1990s, poor growth in agriculture was mainly due to an unfavourable monsoon season. With normal monsoons predicted for the current year, the agricultural sector is expected to be a major contributor to improved GDP growth. Other major sectors expected to contribute are manufacturing (under “Industry”) and hotels, transportation and communications (under “Services”) (reference 5).

Table 4.1 – Sector wise real growth rates of GDP

% change over the previous year 1999 2000 2001 2002 2003 2000 2001 2002 2003 2004 (P) (Q) (A) Agriculture and allied 0.3 -0.1 6.5 -5.2 9.1 Industry 4.8 6.5 3.4 6.4 6.5 Mining and quarrying 3.3 2.4 2.2 8.8 4.0 Manufacturing 4.0 7.4 3.6 6.2 7.1 Electricity, gas and water supply 5.2 4.3 3.6 3.8 5.4 Construction 8.0 6.7 3.1 7.3 6.0 Services 10.1 5.5 6.8 7.1 8.4 Trade, hotels, transport and communications 8.5 6.8 8.7 7.0 10.9 Financial services 10.6 3.5 4.5 8.8 6.4 Community, social and personal services 12.2 5.2 5.6 5.8 5.9 Total GDP 6.1 4.4 5.8 4.0 8.1

Footnotes A: Advance estimates; Q: Quick estimates; P: Provisional estimates Source: Central Statistical Organization, Economic Survey 2003-2004.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.3

Another key indicator of the country’s economic growth is its foreign exchange reserves. India’s foreign exchange reserves have been steadily accumulating in recent years. India saw its foreign exchange reserves exceed US$ 100 billion on 19 December 2004.

India has one of the most liberal policies for Foreign Direct Investment (“FDI”). FDI of up to 100% is permitted in most sectors.

4.2 The oil and gas industry

The Ministry of Petroleum and Natural Gas (“MoPNG”) is entrusted with the responsibility of exploration and production oil and natural gas (including import of Liquefied Natural Gas) as well as their refining distribution and marketing. Other responsibilities of the Ministry include overseeing the import, export and conservation of crude oil and petroleum products.

The activities of the Ministry are carried out through 10 public sector units, 11 subsidiaries and 6 other organizations. Listed below are the key organizations that in the Indian petroleum sector.

Public Sector Units xOil and Natural Gas Corporation Limited (“ONGC”) xOil India Limited (“OIL”) x Limited (“IOCL”) x Corporation Limited (“HPCL”) x Corporation Limited (“BPCL”) xMangalore Refinery and Petrochemicals Limited (“MRPL”) xIBP Company Limited (“IBP”) xGas Authority of India Limited (“GAIL”) x Limited (“EIL”) x and Co. Limited

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.4

Subsidiaries and other companies xONGC Videsh Limited (“OVL”) Wholly owned by ONGC xIndian Oil Blending Limited Wholly owned by IOCL xEIL Asia Pacific Sdn. BHD Wholly owned by EIL xCertification Engineers International Limited Wholly owned by EIL x and Company Limited Subsidiary of IBP xKochi Refineries Limited (“KRL”) Subsidiary of BPCL x Limited (“NRL”) Subsidiary of BPCL x and Petrochemicals Limited Subsidiary of IOCL xChennai Petroleum Corporation Limited (“CPCL”) Subsidiary of IOCL xIBP Co. Limited Subsidiary of IOCL xIndian Oil Mauritius Limited Subsidiary of IOCL

Other key organizations xDirectorate General of Hydrocarbons (“DGH”). The responsibilities of DGH include ensuring practice of proper reservoir management practices, reviewing and monitoring exploratory programmes and development plans for national oil companies and private oil companies, and monitoring production and optimum utilization of gas fields. xOil Industry Safety Directorate (“OISD”). OISD develops standards and codes for safety and fire fighting. xOil Industry Development Board (“OIDB”). OIDB provides financial assistance for the development of the oil industry. xPetroleum India International (“PII”). PII was set up to provide technical, managerial and human resource development (“HRD”) services in the upstream as well as downstream sector. xCentre for High Technology (“CHT”). xPetroleum Conservation Research Association (“PCRA”).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.5

4.2.1 Sedimentary Basins of India

There are 26 sedimentary basins in India, covering a total area of approximately 1.78 million square kilometres (“million sq. km.”). The offshore area (up to 400 metre water depth) accounts for 0.39 million sq.km, while the onshore area takes up the balance 1.39 million sq.km. Some segments of the deep-water areas, which have an estimated basin area of 1.35 million sq.km, are believed to hold significant resources. The total sedimentary basin area thus is 3.13 million sq.km, (including deep-water areas).

The sedimentary basins in India have been classified into four categories, based on the state of geological knowledge of the basin, presence and/or indication of hydrocarbons and the current state of development.

Table 4.2 below illustrates the categories in which the 26 basins are classified.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.6

Table 4.2 – Types of basins

Basin Category Nature

I Proven basins with commercial production. There are 7 basins in this category.

II Basins with known occurrences of hydrocarbons, but from which no commercial production has yet been obtained. There are 2 basins in this category.

III Basins in which significant shows of hydrocarbons have not yet been found, but which on general geological considerations are considered prospective. There are 7 basins under this category.

IV Basins, which on analogy with similar hydrocarbon producing basins in the world, are deemed to be prospective. There are 10 basins under this category. Footnotes: Table 4.2 is an extract from ICRA report on sedimentary basins in India Source: Ministry of Petroleum and Natural Gas

Appendix A contains the classification of all 26 sedimentary basins of India.

4.2.2 Key players of petroleum sector

The Indian petroleum sector can be divided into the following 3 sub-sectors xOil and gas Exploration and Production (“E & P”); xOil Refining; and xMarketing (Gas and Refined products)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.7

Figure 4.2 lists the companies involved in each of theses sub-sectors.

Figure 4.2 – Key players of Indian petroleum sector

Indian Petroleum Sector

Oil and Gas Exploration Refining Distribution & Marketing

CPCL, KRL, IOC, HPCL, BPCL BPRL, MRPL, IBP (Subsidiary NRL Integrated Refining of IOCL) Pure Refiners and Marketing Refining Product Marketing

ONGC & OIL (national oil companies) GAIL, Gujarat Private and joint venture companies Gas, Mahanagar include Reliance, Cairn Energy, Shell, Gas Ltd, Hardy Oil, British Gas, Niko, to name a Indraprastha few. Gas Ltd.

Gas Distributors E & P Companies

Source: Thirty-ninth Lok Sabha committee report (reference 6)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.8

4.3 The labour market

India has a work force of approximately 482 million (estimated in 2004), which is growing at a rate of 2.07% per year. A literacy rate of 65.38% and low wages of Indian workers have been factors assisting in the growth of investment and the economy. India is capitalising on its large number of well educated people and has a large pool of skilled workers and qualified management personnel.

60% of the labour force is employed in the agriculture sector, with industry (17%) and services sectors (23%) accounting for the remaining (reference 7).

According to MoPNG, the number of people employed in petroleum industry was at 133,610 in 2002. Of this, 50% of the workers were employed in Exploration and Production and Marketing sectors.

4.4 Roads

India has a vast road network of 3.32 million kilometres (“kms”). The National Highways with 58,112 kms and State Highways with 136,888 kms constitute 5.87% of the total road network. District and village roads account for the remaining 3.13 million kilometers (reference 8).

Roads carry 70% of freight traffic and 85% of passenger traffic. The National Highways even though only 2% of total road network, account for 40% of total traffic. Of the total 195,000 kms of National and State Highways, only 1% have four lanes, 34% have two lanes and the remaining 65% operates with one lane.

The Government recently began the following three initiatives to develop road network in India (reference 9). xNational Highways Development Project (NHDP). Under this project, 13,146 kms of National Highways are proposed to have four or six lanes. There are two components to NHDP project. First, the 5,846 kms Golden Quadrilateral covering National Highways connecting Delhi, Mumbai, Chennai and Kolkata. Second, the

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.9

7,300 kms North-South and East-West corridors (“NSEW”) connecting Srinagar in the north to Kanyakumari in the south, and Silchar in the east to Porbandar in west India. xPradhan Mantri Bharat Jodo Pariyojana (“PMBJP”). This project involves four- laning and linking of all state capitals that are away from NHDP to NHDP. This project is bound to be more beneficial to the north-eastern states. xPradhan Mantri Gram Sadak Yojana (“PMGSY”). This project addresses development of road network in rural areas of the country. Asian Development Bank (“ADB”) and World Bank would be providing substantial funding for implementation of this project.

Work is in progress in all of these projects and they are scheduled to be completed by the end of 2007.

4.5 Railways

Indian railway (“IR”) is the largest rail network in Asia and the world’s second largest under one management. IR employs nearly 1.6 million people. The network of IR is spread over 63,122 route kilometres (“RKm”) comprising 45,622 RKm of broad gauge (1,676 mm), 14,364 RKm of meter gauge (1000 mm) and 3,136 RKm of narrow gauge (762/610 mm). Only 26% of this network is electrified (reference 10).

IR runs around 11,000 trains daily of which 7,000 are passenger trains. IR moves around 13 million people and over 1 million tonne of freight daily. The freight loading performance of railways stood at 557.4 million tonnes in 2003-2004. Of the total freight loaded, coal and petroleum products accounted for 50.9%.

The rail network is divided into 16 operating zones, based on geographical regions. The Golden Quadrilateral connecting the 4 metro cities (Mumbai, Chennai, Kolkata and Delhi) and its diagonals are the main arteries of IR’s rail network. Although, the Golden Quadrilateral constitute to only 16% of IR’s rail network, it carries over 65% of freight and over 55% of passenger traffic (reference 11).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.10

A plan has been prepared for various projects to augment sectional capacity on Golden Quadrilateral. The Government has launched a scheme to remove all the capacity bottlenecks in the critical sections of the rail network by investing US$ 3.4 billion over the next five years. The scheme involves the following projects xImproving sectional capacity on Golden Quadrilateral to run more long-distance mail/express and freight trains at a higher speed of 100 kilometres per hour. xImproving rail connectivity to ports and development of multi-modal corridors to hinterland. xConstruction of four mega bridges - 2 over the river Ganga, 1 each over the rivers Brahmaputra and Kosi.

There are also ongoing projects to improve suburban metro rail systems in Mumbai, Chennai and Kolkata. In Delhi, construction work is going ahead for a new metro rail system.

4.6 Airports

India has a total of 126 airports, which include 11 international airports, 89 domestic airports and 26 civil enclaves at Defence airfields.

Of the 11 international airports, the 5 major ones are located at xMumbai in the west xDelhi in central India xKolkata in the east xChennai in south east and xThiruvanathapuram in south west.

The other 6 airports that fall under international airport status have customs and immigration facilities for limited international operations by national carriers and for foreign tourist and cargo charter flights.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.11

India has entered into Air Service Agreements (“ASA”) with 100 countries to date. Airlines from 52 different countries are presently operating to/from India. India’s airports handle approximately 44 million passengers per year, of which the 5 major international airports account for 67% of passenger traffic (reference 12).

According to Ministry of Civil Aviation (“MOCA”), domestic air travel between the major cities in north, central and south of India account for nearly 15 million passengers per year. Many of the domestic airports have been upgraded of late.

MOCA had recently announced that it would develop 22 new non-metro airports. These non-metro cities are important tourist destinations of the country.

4.7 Ports

India has a vast coastline of 5,560 kilometres, which makes marine transportation very easy. There are 12 major ports and about 185 minor and intermediate ports. Of the 185 minor and intermediate ports, cargo handling operations are undertaken in about 61 ports while the remaining are restricted to fishing and passenger traffic.

The cargo traffic handled at all the ports was around 344.5 million tonnes in 2003- 2004. Major ports handled about 76% of this cargo. The dominant commodities and cargo types handled at the major ports are petroleum products and coal. They make up for almost 50% of all cargo handled. Other cargo types handled included iron ore, vegetable oil, food grains, fertilizer and containerized cargo.

Major ports were formed under Major Port Act, 1963 whereas minor ports are under the control of State Maritime Boards. Low productivity at a number of major ports has been a major cause of concern for the port authorities. In order to change this, the Government has opened up the port sector for private operators. This has led to competition between the ports.

Figure 4.3 shows the locations of all the major ports and some key minor ports.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.12

Figure 4.3 – Ports in India

It is expected that by 2006-2007, demand for cargo handling capacity at ports to increase to 530 million tonnes. This would require huge investments in the port sector. Since central and most of state governments are not in a position to invest in the port sector, private participation will be needed.

In terms of technical parameters, the rate of progress in India’s port sector is impressive. However, considerable effort is still needed to get up to world standards. The Government hopes to continually benchmark Indian ports against the best ports worldwide such as Colombo, Hong Kong or Singapore (reference 13).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.13

4.8 Electricity distribution

India’s transmission and distribution network is distributed into the following 5 regions xNorthern region xWestern region xSouthern region xEastern region xNorth-eastern region

The transmission and distribution network uses 400 kilovolt (“KV”) lines as the main and bulk transmission system in each region. States around the country use 132 KV and 110 KV networks as the main transmission systems (reference 14). Other transmission networks use include x66 KV, 33KV and 22 KV systems operating as sub-transmission system xA 11 KV network as primary distribution system and xA 400 V (3-phase) and a 220 V network for local distribution of electricity

As at December 2004, the Central Electricity Authority stated that the country had 0.173 million-circuit kilometres (“Ckm”) of transmission lines. However, the transmission and distribution network continues to experience shortages and blackouts in various parts of the country. In order to redress this, the Government is in the process of strengthening the National Power Grid to facilitate transfer of electricity from surplus regions to consumers elsewhere in the country. Presently, the total inter regional transmission capacity is 8,100 mega watt (“MW”) and this is expected to increase to 10,600 MW by the end of 2007.

By 2011-2012, India also plans to electrify all of its villages. Future plans include development of renewable and non-polluting forms of electricity generation by laying emphasis on hydroelectric (hydel), solar and wind power generation (reference 15).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.14

4.9 Telecommunications

Telephone lines go to almost every part of the country. The total subscriber base for fixed lines and mobiles stood at 43.9 million and 43 million respectively (estimated in September 2004). Fax and telegraph facilities are also available. Telegraph services are offered at 31,770 centers across the country.

The Internet is another important form of communication within India. At present, there are a total of 188 Internet Service Provider’s (“ISPs”) providing services to an internet subscriber base of 5.3 million. There are a total of 10,709 cyber cafes at the moment. Internet connections available in the country use dialup and broadband technologies.

The country has one of the largest postal networks in the world. At present, India has 0.16 million permanent post offices as compared to 0.076 million in China (reference 16). India has a large and ambitious space communications programme with 8 operating INSAT satellite networks.

The growth in telecommunication sector recently received a boost with the Government’s decision to raise permissible limit of Foreign Direct Investment (“FDI”) to 74%. India hopes to increase its teledensity (telephone lines per 100 people) from 7% (at present) to about 17% by 2005-2006.

4.10 Refineries

India currently has an annual refining capacity of 923.36 million barrels. At present, the oil-refining sector has 10 oil refining companies with 18 refineries operating in the country.

Indian Oil Corporation Limited (“IOCL”) owns 10 of the 18 refineries run. While, Limited (“RPL”) is the sole private sector refinery operating in the country, Mangalore Refinery and Petrochemicals Limited (“MRPL”) is a joint sector entity. The remaining 16 refineries are public sector companies.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.15

Of the 16 public sector refineries, 10 are owned by IOCL and its subsidiaries. IOCL owns 7 refineries, while its subsidiaries Chennai Petroleum Corporation Limited (“CPCL”) and Bongaigaon Refinery and Petrochemicals have 2 and 1 refinery respectively. Hindustan Petroleum Corporation Limited (“HPCL”) has 2 refineries, while Bharat Petroleum Corporation Limited (“BPCL”) and its two subsidiaries Kochi Refineries Limited (“KRL”) and Numaligarh Refineries Limited (“NRL”) have a refinery each. Oil and Natural Gas Corporation (“ONGC”) is a recent entrant in refining business.

Historically, the Indian market was characterised by shortages in petroleum products. At present there is an oversupply of petroleum products in India. Due to the oversupply, it is not possible to correctly access the future plans of refinery capacity additions.

However, despite the oversupply, there are regional variations. North India is a product deficient region, whereas south and western India has surplus capacity at the moment. To meet petroleum product demand in future, a number of expansion and green field projects has been planned to be completed by 2007.

The expansion projects planned include, capacity expansions at IOCL’s Panipat and Koyali refineries. The new refineries to be constructed are HPCL’s Bhatinda refinery in north India, BPCL’s Bina refiney in central India, IOCL’s Paradip refinery in east India and Nagarjuna (“NOR”) at Cuddalore in south India.

Under present circumstances, the annual refining capacity is expected to increase to 1,012 million barrels with a number of ongoing expansion projects expected to be completed by 2007. However, if there is a growth in demand of petroleum products, in addition to the expansion projects under implementation, three or four new refineries might be commissioned taking the annual refining capacity to 1,136 million barrels by 2007.

Table 4.3 gives information on all existing refineries along with their processing capacities. Table 4.3 also includes details on the new refinery projects expected to go online by 2007 (references 17 and 18).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.16

Table 4.3 – Refineries in India (Barrels per day)

Present Manufacturers Location Capacity Reliance Petroleum Limited (“RPL”) 662,710 Indian Oil Corporation Limited (“IOCL”) Koyali 275,200 Indian Oil Corporation Limited (“IOCL”) Mathura 160,660 Indian Oil Corporation Limited (“IOCL”) Panipat 120,500 Indian Oil Corporation Limited (“IOCL”) Barauni 120,500 Indian Oil Corporation Limited (“IOCL”) Haldia 92,380 Indian Oil Corporation Limited (“IOCL”) Guwahati 20,100 Indian Oil Corporation Limited (“IOCL”) Digboi 13,050 Hindustan Petroleum Corporation Limited (“HPCL”) Mumbai 110,455 Hindustan Petroleum Corporation Limited (“HPCL”) Vishakapatnam 150,620 Bharat Petroleum Corporation Limited (“BPCL”) Mumbai 120,500 Kochi Refineries Limited (“KRL”) Kochi 150,620 Chennai Petroleum Corporation Limited (“CPCL”) Chennai 130,530 Chennai Petroleum Corporation Limited (“CPCL”) Narimanam 20,100 Bongaigaon Refinery and Petrochemicals Limited Bongaigaon 47,190 (“BRPL”) Mangalore Refinery and Petrochemicals Limited Mangalore 194,595 (“MRPL”) Numaligarh Refineries Limited (“NRL”) Numaligarh 60,245 Oil and Natural Gas Corporation (“ONGC”) Tatipaka 1,565

New refineries planned for completion by 2007 Hindustan Petroleum Corporation Limited (“HPCL”) Bhatinda 180,740 Indian Oil Corporation Limited (“IOCL”) Paradip 180,740 Nagarjuna Oil Refinery (“NOR”) Cuddalore 120,500 Bharat Petroleum Corporation Limited (“BPCL”) Bina 120,500

Figure 4.4 gives shows the location of existing refineries and those proposed to be completed by 2007.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.17

Figure 4.4 – Refineries in India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.18

4.11 Pipelines

Pipelines are the most cost-effective way of transporting crude oil, natural gas and petroleum products like petrol and diesel. India at present has a pipeline network of over 15,000 kilometres (“kms”). The country’s pipeline network comprises of the following - gas pipelines of 5,798 kms, oil pipelines of 5,613 kms and petroleum product pipelines of 5,567 kms (estimated in 2003). With the government recently delicensing the pipeline sector, in the next six years another 17,000 kms of pipelines is expected to be developed in the country.

Crude oil and petroleum product pipelines

Indian Oil Corporation Limited (“IOCL”) operates the largest network of crude and product pipelines in the country (reference 19). IOCL operates 2,813 kms of crude oil pipelines with an annual installed capacity of 209 million barrels. Their product pipeline network runs over 4,591 kms with an annual capacity of 208 million barrels.

Oil India Limited (“OIL”) transports all crude oil produced in north-eastern India to refineries using a 1,157 kms pipeline.

Reliance Industries Limited (“RIL”) has plans to lay six new product pipelines (5,895 kms) over the next two years. Details of the route and distance of proposed pipelines are given in Table 4.4 below.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.19

Table 4.4 – Product pipelines planned by RIL

Route Length (km) Jamnagar - Patiala 1,580 Jamnagar – Kanpur 2,540 Goa – Hyderabad 660 Chennai – Bangalore 540 Haldia – Ranchi 375 Kakinada – Vijayawada 200

“Of the pipelines listed above, two will evacuate products from Reliance’s 33 million tonne per annum Jamnagar refinery. These two are the 2,540 kms pipeline to Kanpur via Ahmedabad and Bhopal and the 1,580 kms pipeline to Patiala via Delhi. These will cater to the demand in north and west India - the two biggest markets. Reliance's other four product pipelines will cater to south India, where demand is set to grow by 3% per annum. These pipelines will be fed from Goa. Reliance plans to feed Goa by moving products from Jamnagar in barges” (reference 20).

Figure 4.5 shows all crude oil and petroleum product pipelines in India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.20

Figure 4.5 – Crude oil and petroleum product pipelines in India

Gas pipelines

Gas Authority of India Limited (“GAIL”) is the largest natural gas transmission company in the country. Of the 5,798 kms gas pipeline network in the country, GAIL operates over 4,600 kms, including the Hazira – Vijaypur – Jagdishpur (“HVJ”)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.21 pipeline (2,800 kms) located in northwestern India. GAIL transports approximately 90% of the total gas transmitted by pipelines in India.

India at present is supply-deficient in gas. According to Hydrocarbon Vision 2025 report, the demand for natural gas is projected to increase from 5,332 million cubic feet per day (“MMSCFD”) in 2002 to about 8,157 MMSCFD in 2007 and 13,806 MMSCFD in 2025. India is investing heavily in gas pipeline development to support increased use of gas. A number of new gas pipelines are expected to be commissioned by 2007 (approximately 10,000 kms).

Two fundamental developments include the following xGAIL plans to develop a National Gas Grid of 7,890 kms to provide gas to all parts of the country. The National Gas Grid is expected to cost over US$ 4.3 billion. xFollowing Reliance’s huge gas discovery in the Krishna-Godavari basin, Reliance is laying a 2,000 km gas pipeline from the Kakinada coast to Goa. This pipeline is expected to address gas demand in states like Andhra Pradesh, Madhya Pradesh and Karnataka. This pipeline will also have a spur to Mumbai to cater to the industrial belt in the region. Reliance has also planned another gas pipeline from Bhubaneshwar in Orissa, (where it is exploring gas in the NEC-OSN field) to its refinery at Jamnagar in Gujarat.

Figure 4.6 below shows all gas pipelines in India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 4.22

Figure 4.6 – Gas pipelines in India

Transnational pipelines

In addition to pipeline projects, Government of India is attempting to import gas from countries such as Iran, and Bangladesh. The chapter on “Energy Market in India” gives more detailed information on these projects.

Sajith Venugopal July 2005 University of New South Wales

Chapter 5

Energy Market in India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.1

The discussion in this chapter focuses on the supply, demand and price of crude oil, petroleum products, natural gas, liquefied petroleum gas and . The country’s energy flow chart for 2003 is presented in Figure 5.1. In Figure 5.1, it is assumed that there are no stock change or transmission and distribution losses. The numbers shown in Figure 5.1 are estimated by using the approximate energy conversion factors in Appendix B.

Figure 5.1 – India’s energy flowchart for 2003

Energy availability 357.97 MMtoe Indigenous production Imports 250.96 MMtoe 107.01 MMtoe

Total primary energy supply 346.96 MMtoe Exports 11.01 MMtoe

Petroleum Coal

Crude oil and Coal products 0.71 MMtoe petroleum products 205.43 10.3 114.26 MMtoe MMtoe MMtoe 5.1 MMtoe Natural gas 27.1 MMtoe Hydro power

Final energy consumption Transformation into 354.27 MMtoe electricity 3.7 MMtoe

Crude oil and Coal petroleum products 185.3 104.1 MMtoe MMtoe Electricity Natural gas 42.7 MMtoe 22.17 MMtoe

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.2

5.1 Crude Oil

Crude oil accounts for nearly 33% of India’s total energy consumption. Crude oil was first discovered by Assam Railway and Trading Company in 1867 at Digboi, Assam in the north east of India. Until 1950, crude oil production was confined to the north- eastern region. Crude oil production increased beginning in the 1960s with the discovery of the Assam and Ankleshwar oil fields (located at north-eastern and western India respectively). In mid 1980s, Bombay High (North), Heera, Gandhar and Bombay High (South) oil fields were discovered. Discovery of these fields resulted in a quantum jump in crude oil production.

Crude oil is currently produced from both onshore and offshore fields. The major onshore fields are located in Tamil Nadu, Gujarat, Assam, and Andhra Pradesh. Offshore production is mainly from Bombay High region. Private/Joint Venture Companies’ (“JVCs”) produce crude oil from offshore fields like Panna-Mukta and Ravva located on the west and eastern coasts of India.

In 1956, the government set up two national oil companies Oil and Natural Gas Corporation (“ONGC”) and Oil India Limited (“OIL”). Since that time the number of companies operating in the country has grown substantially.

5.1.1 Crude oil demand/supply

Indigenous production of crude oil in India currently accounts for approximately 29% of its demand. India is therefore heavily depended on crude oil imports. Since gaining independence in 1947, there has been a sharp increase in oil demand in the country. Most of this demand can be attributed to the growth in demand for refined oil products.

Table 5.1 below indicates crude oil supplied to the Indian economy. India is the world’s sixth largest oil consumer. The import dependency increased from 71.07% in 2002-03 to 71.25% in 2003-04, when the country imported 665 million barrels of crude oil in 2003-04 (reference 21).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.3

Table 5.1 – Crude Oil supply in India (Million barrels)

1995 1997 1998 1999 2000 2001 2002 1996 1998 1999 2000 2001 2002 2003 Domestic production Onshore 86.79 84.22 83.56 82.17 85.91 86.64 83.56 Offshore 166.17 145.57 134.07 122.63 121.90 117.79 128.71 Private/JVCs* 4.76 18.40 22.28 29.47 29.91 30.35 29.98 Crude imports 200.11 252.89 291.73 423.67 543.15 576.87 600.33 Total oil supplied 457.83 501.08 531.64 657.94 780.86 811.65 842.58

Domestic 56.29% 49.53% 45.13% 35.61% 30.44% 28.93% 28.75% production

Crude imports 43.71% 50.47% 54.87% 64.39% 69.56% 71.07% 71.25% * Joint venture companies

Because of expected sustained economic growth, India’s oil demand is projected to increase in the next two decades. According to the Planning Commissions’ 10th five- year estimates, the demand for crude oil in India is expected to increase to 134.50 million tonnes by 2006-07 and further to 172.47 million tonnes by 2011-12. The transportation sector is expected to be the main driver during this period.

The government plans to employ the following measures during the 10th five-year plan to achieve oil security for the country xAccelerating exploration efforts in deep water offshore and frontier areas. xMaintaining current production levels by undertaking a number of improved oil recovery (“IOR”) projects and enhanced oil recovery (“EOR”) projects. ONGC is currently involved with a number of IOR/EOR projects on the east and western regions of India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.4 xAcquiring oil and gas properties abroad. Presently Indian companies have acquired oil and gas assets in Russia, Vietnam, Iran, Iraq, Sudan, Libya and Yemen etc. xDevelopment of strategic oil storage facilities to protect domestic energy security in the event of a war. This move would also safeguard the economy from oil price shocks due to volatility in international oil prices. Initially, the government plans to construct storage facilities for 2.5 million tonnes of crude oil at Vishakapatnam and Mangalore. Other sites being considered for developing storage facilities include , Kolkata and Tripura.

5.1.2 Crude oil pricing

Before April 2002, the Government of India determined crude oil prices through an Administered Pricing Mechanism (“APM”). For a decade between 1982 and 1992, the price paid to National Oil Companies (“NOCs”) for crude oil was left unchanged at the equivalent of US$ 7.40 per barrel (assuming an exchange rate of 1 US$ = 18.83 Rupees - the average US$-Rupee exchange rate between 1982 and 1992).

In 1992, a Cabinet Committee (appointed by the petroleum ministry to review crude oil pricing) observed that the price paid to the NOCs resulted in low revenue to the producers. This made it impossible for the producing NOCs to generate resources for developing more oil fields or to undertake additional exploration. This in turn resulted in a plateau in crude oil production. To improve crude production, the Cabinet Committee directed the government to pay the NOCs a sum that would give a 15% post tax return on capital employed in addition to the general payment for production costs incurred. Thus the price of crude was increased to US$ 7.57 per barrel by 1993 and further to US$ 7.68 per barrel by April 1996.

In April 1998 domestic crude oil prices was linked to international prices with floor and ceiling price set at US$ 7.68 per barrel and US$ 15.04 per barrel respectively. The basic price paid to NOCs was US$ 7.68 per barrel.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.5

Further, in December 1998, the government launched New Exploration Licensing Policy (“NELP”) to attract foreign companies to undertake exploration and production activities in India.

Figure 5.2 – Crude oil pricing

8.6

8.2 US $ per barrel

Era under Administered Pricing Mechanism 7.8

7.68 7.68 7.57 Market driven pricing from April 2002 7.4 7.4

Year 7 1982-1992 1993 1996 1997-2002

In April 2002 the APM was dismantled. Today, with the decontrolling of the petroleum sector the producing companies are free to set their own price for crude oil.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.6

5.2 Petroleum products

India at present has 18 refineries with an annual installed capacity of 923.36 million barrels (reference 17). Recently India has witnessed an increase in its refinery throughput. The refinery throughput has increased from 630.38 million barrels in 1999-2000 to 825.36 million barrels in 2002-2003. Due to low/stagnant crude production in India, the majority of the crude used to produce refined products is imported.

5.2.1 Petroleum product supply

In India there are 10 oil refining companies. While the government allows 100% foreign equity in private refining ventures, foreign investment in public sector refineries is restricted to 26%. The equity participation of foreign companies in petroleum product marketing has been capped at 74%. The Indian lubricants market was deregulated in 1997. Since then several multinational companies like Shell, ExxonMobil, Caltex, etc., have entered the Indian lubricants market.

Indian Oil Corporation (“IOC”) is major supplier of petroleum products in India. IOC accounts for approximately 50% of India’s total petroleum products. Bharat Petroleum Corporation Limited (“BPCL”) and Hindustan Petroleum Corporation Limited (“HPCL”) with market shares of 19% and 17% respectively are the other major suppliers of petroleum products.

Production of petroleum products in India has increased following the increase in refining capacity and at present there is an oversupply. Figure 5.3 shows the annual production of selected petroleum products.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.7

Figure 5.3 – Petroleum products from crude oil

400.00

350.00

300.00

250.00

200.00

321.75 150.00 297.95 300.27 Million Barrels High Speed Diesel Kerosene Naphtha

100.00

50.00 93.93 74.92 77.95 77.32 82.11 77.01

0.00 2001-02 2002-03 2003-04* Year

The modes of transport used to supply petroleum products include product pipelines, the rail network, ships and trucks. During 2003-04, 40.7% of the petroleum products were moved by pipeline and 46.3% by rail. Coastal and road movements accounted for 8.8% and 4.2% respectively.

5.2.2 Petroleum product demand

The major petroleum products consumed in India include naphtha, motor spirit (petrol), kerosene/superior kerosene oil (“SKO”), high speed diesel (“HSD”), fuel oils.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.8

The transport sector is the leading consumer of petroleum products. HSD and MS accounts for nearly 45% of total petroleum product consumption. Naptha is used as feedstock/fuel in fertilizer units, in powerplants and in the petrochemical sector. Kerosene is used for cooking and lighting purposes. Fuel oils include oils used for agricultural purposes and fuels used as secondary fuels in thermal power plants, fertilizer units etc.

The domestic consumption of petroleum products in India since 1998 is given in Table 5.2. Figures shown in this table include the petroleum products imported by private companies.

Table 5.2 – Consumption of petroleum products in India (Million barrels)

1998 1999 2000 2001 2002 2003 1999 2000 2001 2002 2003 2004* Naptha/NGL 75.65 91.80 99.45 99.45 101.15 99.45 Motor sprirt (MS/Petrol) 46.48 49.86 55.77 59.15 64.22 66.76 Kerosene (SKO) 94.43 92.11 87.46 80.50 80.50 78.95 High speed diesel oil (HSD) 277.51 293.18 282.73 272.29 273.04 278.26 Fuel oils 83.25 83.25 84.58 86.58 84.58 85.25 Total domestic consumption 703.63 754.37 777.60 780.32 809.07 839.29 * Provisional Source: Economic Survey 2003-2004 (reference 22)

As stated earlier, at present there is an oversupply of petroleum products in India. The reasons contributing to the oversupply are slackening demand for petroleum products and the increase of refining capacity within the country. From being a net importer in early 2000, India today is a net exporter of petroleum products.

Table 5.3 below indicates the compounded annual growth rate (“CAGR”) for selected petroleum products. Data in Table 5.3 are provisional figures reported for the year 2003-04 and the CAGR has been calculated considering consumption of petroleum production in years 2002-03 and 2003-04.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.9

Table 5.3 – Compounded annual growth rate for petroleum products

Products Quantity (MMbbl) Growth rate (%) Liquefied petroleum gas (LPG) 108.00 11.5 % Motor spirit (MS/Petrol) 66.92 4.6 % Naphtha 100.66 -1.0 % Superior Kerosene Oil (SKO) 79.00 -1.9 % High Speed Diesel (HSD) 278.26 1.8 % Furnace oil 86.58 2.1 % Bitumen 20.61 13.4 % Total petroleum products 839.29 3.7 %

The drop in demand for kerosene can be attributed to LPG replacing kerosene as cooking fuel in most households around the country.

Stringent anti-adulteration steps initiated by the government in 2003, has resulted in the upward trend of diesel demand in the country.

Another factor that has helped in increase in demand of petroleum produts like diesel (HSD) and petrol (MS) is the sharp increase in commercial vehical sales. The increase in petrol and diesel consumption follows the boom in the auto sector. Another significant growth area has been in the consumption of bitumen indicating an increase in the construction of roads. The demand for naphtha is on the decline as both the fertilizer and power sectors are introducing measures that would encourage the use of natural gas as the primary fuel in these sectors.

The 10th five-year plan estimates that the demand for petroleum products will grow at 3.7% per annum. Table 5.4 gives details on availability of petroleum products during the 10th five-year period (2002-03 to 2006-07). Table 5.4 has been compiled based on information contained in reference (23).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.10

Table 5.4 shows projected availablity of selected petroleum products like LPG, naphtha, MS, SKO, HSD, furnace oil, bitumen etc.

Table 5.4 – Projected availability of petroleum products (Million barrels)

2003 2004 2005 2006 2007 (P) (P) (P) (P) (P) Liquefied petroleum gas (LPG) 87.58 92.68 102.31 101.50 100.22 Motor spirit (MS/Petrol) 89.39 93.74 97.84 99.63 98.78 Naphtha 100.98 114.33 116.88 114.92 113.31 Light distillates (Total) 266.43 287.95 302.32 301.55 298.44

Superior Kerosene Oil (SKO) 108.13 113.47 116.56 116.95 115.64 High Speed Diesel (HSD) 352.56 387.32 422.43 425.14 429.62 Middle distillates (Total) 496.88 541.05 588.90 592.35 587.25

Furnace oil 50.48 52.21 47.49 40.23 39.69 Bitumen 19.70 19.33 18.91 18.79 18.60 Heavy distillates (Total) 151.86 157.06 154.50 151.24 149.54

Petroleum products (Total) 915.16 986.06 1,045.72 1,045.14 1,035.22

As shown in Table 5.4, the demand for middle distillates is expected to be more than the demand for either light or heavy distillates. It is expected that in the terminal year of the 10th five-year plan (2007), the demand for light, middle and heavy distillates would reach 298.44, 587.25 and 149.54 million barrels respectively. Even though demand is expected to increase, the oversupply situation in the market is likely to continue with India’s installed refining capacity of 923.36 million barrels likely to increase by around 146.6 million barrels per annum over the next 4-5 years.

India’s self sufficiency in petroleum products has declined over the years and at present hovers around the 31% mark. Figure 5.4 below is based on information contained in reference (24).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.11

Figure 5.4 – Self sufficiency in petroleum products

100%

80% Self SuffiencySelf (%) 60%

40% 56% 50% 45% 44%

20% 43% 41% 39% 38% 34.8% 31.8% 31.2% 30.8% 30.5% 29.3%

0% 1990-91 1991-92 1992-93 1993-94 1994-95 1995-96 1996-97 1997-98 1998-99 1999-00 2000-01 2001-02 2002-03 2003-04* Year

5.2.3 Petroleum product quality

In India, the Bureau of Indian Standards (“BIS”) formulates the Indian standards for petroleum and coal related products. All refining and marketing companies follow the quality specifications set by BIS.

The three main types of motor gasoline (motor spirit/petrol) sold in India are MS 87, MS 94 and MT 80. While MS 87 and MS 94 are used for passenger cars, three wheelers and two wheelers, MT 80 is manufactured for defence applications. The motor gasoline used in India have the following octane specifications - RON-88 and RON-93 (reference 25). From February 2000, only unleaded petrol is sold in India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.12

Jet A-1 is the jet fuel used throughout the country. The maximum permissible aromatic content in jet fuel differs according to aircrafts used. In aircrafts used for commercial aviation, the maximum permissible aromatic content is 25% (by volume) (reference 26). In aircrafts used for defence purposes, the allowable aromatic content level is 22% (for normal defence aircrafts) and 20% (for defence aircrafts with Russian engines).

Diesel oil sold for transportation has a minimum cetane number of 48 (reference 27). The maximum permissible sulphur content in diesel supplied to the entire country is 0.25% (by weight). Diesel supplied to the four metropolitan cities has a maximum permissible sulphur content level of 0.05% (by weight). A lower sulphur content limit has been set for diesel allotted to the four metros due to environmental reasons.

Fuel oils of four different grades are supplied in India, LV, MV 1, MV 2 and HV (reference 28). The maximum permissible sulphur content in these grades varies between 3.5% and 4.5% (by weight). The maximum viscosity of the different grades of fuel oils ranges from 80 to 370 centistokes (at 500C).

Bitumen of the following quality grades are marketed in India – 80/100, 60/100 and 30/40.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.13

5.3 Natural Gas

Indian natural gas industry started in the 1960s with production from discoveries in Assam and Gujarat. The production of natural gas received a substantial boost with the discovery of associated gas at Bombay High field in 1974. Between 1977 and 1984 significant gas discoveries were made off the western coast of India and the gas sector has grown significantly with discoveries made in many states around India. The most recent commercial discovery is Reliance-Niko consortiums’ discovery in Krishna Godavari basin.

5.3.1 Natural gas supply

Natural gas production in India has increased from about 774 million cubic feet per day (“MMSCFD”) in 1985-86 to about 3,037 MMSCFD in 2002-2003 (provisional). Table 5.5 below gives details. ONGC accounts for nearly 80% of gas production. Other contributors to gas production include Oil India and private or joint venture companies like Reliance, Cairn Energy etc.

Data included in Table 5.5 is based on information contained in reference (29).

Table 5.5 - Natural gas production in India (MMSCFD)

1990 1995 1996 1997 1998 1999 2000 2001 2002 1991 1996 1997 1998 1999 2000 2001 2002 2003 Onshore Oil India 147 139 142 162 166 167 180 157 169 ONGC 232 416 434 479 515 530 537 543 568

Offshore ONGC 1,362 1,604 1,625 1,751 1,694 1,719 1,786 1,783 1,777 Private/JVCs* Nil 32 49 163 278 335 348 392 523 Total 1,741 2,190 2,250 2,554 2,653 2,752 2,852 2,875 3,037 * Joint venture companies

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.14

Natural gas production in India is approximately 3,037 MMSCFD but only about 2,508 MMSCFD is supplied. The net difference resulting from usage of natural gas for the following purposes prior to supply – xFlaring during production

xInternal consumption for LPG extraction/C2-C3 shrinkage

Table 5.6 gives details on natural gas supply in India. Data included in Table 6.6 is based on information contained in references (30).

Table 5.6 - Natural gas supply (MMSCFD)

1996 1997 1998 1999 2000 2001 2002 2003 1997 1998 1999 2000 2001 2002 2003 2004* Production 2,254 2,554 2,653 2,745 2,852 2,875 3,037 3,096 Flared 187 180 170 151 156 165 136 109 Internal use 303 334 342 352 367 379 393 395 Supply 1,764 2,040 2,141 2,242 2,329 2,341 2,508 2,592 * Provisional

Natural gas from Reliance’s gas discovery is expected to boost current supply figures by nearly 60%. Incremental gas supply is also expected from Panna-Mukta-Tapti oil & gas field and the Vasai East gas discovery.

5.3.2 Natural gas demand

Initially the demand for natural gas was low in India. However, the commissioning of the HBJ pipeline and the growth of the power and fertilizer industries led to an increase in demand. Gas demand in India is mainly from the power and fertilizer industry. These sectors account for nearly 75% of the nations’ gas consumption.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.15

To meet the future energy demands of the country, the Indian government initiated Hydrocarbon Vision 2025 in February 2000. According to Hydrocarbon Vision 2025 report, the demand for natural gas is projected to increase from 5,331 million cubic feet per day (“MMSCFD”) in 2002 to about 8,156 MMSCFD in 2007 and 13,806 MMSCFD in 2025. The projected increase reflects the strong industrial growth that is expected during this period.

India expects to meet its increasing energy requirements by constructing new gas based power plants. Some advantages of gas-based power plants are as follows xGas based plants take shorter time to build xGas power plants can be operated closer to plant capacity

xEnvironmentally more clean fuel with less CO2 emissions

India’s economy is driven by the performance of its agriculture sector and curbing fertilizer production costs is instrumental to its growth. Costs involved with fertilizer production can be reduced by using natural gas as the feedstock.

Table 5.7 below gives information on the natural gas consumption by various end- users.

Table 5.7 – Trend in natural gas consumption (MMSCFD)

1996 1997 1998 1999 2000 2001 2002 1997 1998 1999 2000 2001 2002 2003 Fertilizer 738 847 858 828 853 780 794 Power 670 769 829 899 860 884 854 Sponge/Iron 111 143 122 109 129 123 110 Other Industries 251 278 319 402 488 550 668

Total 1,769 2,036 2,129 2,238 2,330 2,337 2,426

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.16

With the growth of domestic gas production expected to be slow, the Indian government has plans to import additional gas to meet demands.

5.3.3 Additional natural gas

In order to bridge its energy demand-supply gap, the Government of India plans to import natural gas through pipelines or in the form of liquefied natural gas (“LNG”) in LNG tankers. While natural gas from Middle East is expected to meet northern India’s gas requirements, gas from the Reliance find coupled with LNG imports from East Asia/Australia should satisfy the gas market in southern and eastern India.

Importing natural gas using pipelines

Projects being considered for supply of natural gas to India using a pipeline include - xA pipeline connecting Iran’s South Pars field with HVJ pipeline in India via Pakistan. The length of this pipeline would be 2,670 kilometers. Another option being considered is a sub-sea pipeline. xExtending the Asia Development Bank (“ADB”) sponsored Turkmenistan- Afghanistan-Pakistan (“TAP”) project to India. If the Indian government agrees to this proposal, a pipeline connecting Daulatabad in Turkmenistan with HVJ pipeline in India at a distance of 1,700 kilometers could soon become a reality. xThe Indian Government recently proposed constructing a pipeline from Burma to India via Bangladesh for evacuating gas discovered in A-1 Block in Burma by ONGC and GAIL (Indian companies forming the consortium at A-1 Block).

Because of the volatile relationship that India shares with Pakistan, pipelines from Iran and Turkmenistan might not materialize in the near future. The Bangladesh government cited huge demands for natural gas within Bangladesh as a reason for rejecting Indian government’s earlier proposal (to import piped gas from Bangladesh to eastern shores of India). However, the future of the Indo-Burmese pipeline via Bangladesh looks promising. Due to geo-political issues, none of the pipeline initiatives have actually progressed. In this context, the alternative of importing LNG becomes important.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.17

Importing LNG

India is expected to become a major importer of LNG in the coming few years. The length of India’s coastline provides a good opportunity for the prospective LNG suppliers (includes suppliers from Middle East, East Asia and Australia) to access the natural gas market in India. Figure 5.5 shows a map of possible routes to import natural gas to India.

Figure 5.5 – Importing natural gas to India

The Government of India set up Petronet LNG to develop infrastructure required for importing and regasification of LNG. Petronet LNG is a consortium consisting of GAIL, ONGC, BPCL, IOC, Gujarat Government, Gaz de France, Ras Gas and financial institutions. LNG terminals are also being established in locations like Dahej, Kochi,

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.18

Dabhol, Ennore and Jamnagar. Apart from Petronet LNG, some of the other companies involved in the proposed LNG projects are listed in Table 5.8 (reference 31).

Table 5.8 – Proposed LNG projects

Capacity Port location Ownership (Million tons/year) Dahej, Gujarat Petronet LNG 5.0 Jamnagar, Gujarat Reliance 5.0 Gopalpur, Orissa Al-Manhal 5.0 Dabhol, Maharashtra Dabhol Power Company 5.0 Ennore, Tamil Nadu TIDCO + Partner 5.0 Hazira, Gujarat Shell 2.7 Kochi, Kerala Petronet LNG 2.5 Vizag, Andhra Pradesh TOTAL + HPCL 2.5 Mangalore, Karnataka Finolex 2.5

In January 2004, the first LNG cargo arrived at Dahej from . Reports indicate that Shell’s Hazira project is likely to be commissioned by the end of 2004. However, Reliance’s gas discovery competes strongly and has raised doubts about the commercial viability of some of the projects listed above.

Two key issues that are fundamental to the success of the LNG import plans are xThe Indian governments’ formulation of LNG policy. xCreation of a competitive gas market.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.19

Gas production from Coal Bed Methane (“CBM”)

Coal Bed Methane (“CBM”) is a gas extracted from coal beds. The government plans to explore and develop unconventional gas resources like CBM to bridge the energy gap in the country. The current policy in India is that the blocks are identified by the and then awarded by Ministry of Petroleum and Natural Gas.

Under the first round of CBM licensing, 8 blocks were awarded for exploration and development work. 5 of these blocks were awarded under first offer of bidding. 2 blocks were awarded on nomination basis to ONGC-CIL (“ Limited”) consortium. Rights to explore and develop the final block offered under CBM-Iwas granted to Corporation Limited (“GEECL”) on recommendation from the Foreign Investment Promotion Board (“FIPB”), India.

Under the second round of CBM licensing, another 8 blocks were awarded under first offer of bidding. The total area covered by the 16 blocks awarded under the two rounds of CBM licensing is 7,810 square kilometers (“sq.kms”).

The companies that participated individually or as a consortium in the two CBM exploration rounds included xOil and Natural Gas Corporation (“ONGC”) xIndian Oil Corporation (“IOC”) xReliance Industries Limited (“RIL”) xEssar Oil Limited (“EOL”) xCoal India Limited (“CIL”) xGreat Eastern Energy Corporation Limited (“GEECL”) xGujarat State Petroleum Corporation Limited (“GSPCL”)

Table 5.9 below includes a list of all 16 blocks awarded under the two rounds of CBM policy (reference 32).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.20

Table 5.9 – Blocks awarded for CBM exploration

Awarded under CBM – I

Block State Company/Consortium Bokaro Jharkhand ONGC - IOC North Karanpura Jharkhand ONGC – IOC Sohagpur East Madhya Pradesh RIL Sohagpur West Madhya Pradesh RIL Raniganj East West Bengal EOL Raniganj North West Bengal ONGC – CIL Jharia Jharkhand ONGC – CIL Raniganj South West Bengal GEECL

Awarded under CBM – II

Block State Company/Consortium SK-CBM-2003/II Jharkhand ONGC NK (West)-CBM-2003/II Jharkhand ONGC SH (North)-CBM-2003/II Chhatisgarh & Madhya RIL Pradesh ST-CBM-2003/II Madhya Pradesh ONGC WD-CBM-2003/II Maharashtra ONGC BS (1)-CBM-2003/II Rajasthan RIL BS (2)-CBM-2003/II Rajasthan RIL BS (3)-CBM-2003/II Gujarat ONGC – GSPCL

It is expected that by 2005-06, India would be producing 0.28-0.34 MMSCFD of gas from its CBM fields. India will be the fourth country after United States, Australia and China to produce natural gas using CBM technology. The Government of India also announced that preparatory activities for offering more CBM blocks under CBM III are in progress.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.21

5.3.4 Natural gas pricing

Gas pricing under the Administered Pricing Mechanism (“APM”)

Till 1986, the price of natural gas depended on the cost of alternative fuels like coal or naphtha. In 1986, with the commencement of the HVJ pipeline, Government of India decided to fix uniform prices for natural gas on a year-to-year basis. Due to law and order problems in the north-eastern states, the government decided to subsidize gas prices for these states. A gas pool account was set up to absorb the burden created as a result of the subsidies granted to north-eastern states. Thus the consumer price was set to cover producer price, state royalty, transmission tariff and a charge to the gas pool account. The producer price, state royalty and transmission tariffs were all kept constant.

In October 1997, the government introduced changes to the pricing mechanism. From a fixed price regime, the consumer price was now linked to international price of a basket of fuel oils. The energy equivalent of this fuel oil basket was to be 283.21 Kilocalorie per scf. The fuel oil basket consisted of the following xItaly, medium sulphur (1% sulphur), free on board (“FOB”) basis xNorth Western Europe (“NWE”), Amsterdam-Rotterdam-Antwerp (“ARA”)(1% sulphur), cost insurance freight (“CIF”) basis xSingapore, High Sulphur Fuel Oil (“HSFO”) 180 centistoke (“CST”) (3.5% sulphur), FOB basis xArab Gulf, HSFO, 180 CST (3.5% sulphur), FOB basis

Components that determine the gas price at a delivery point include the consumer price (price linked to basket of fuel oils), transmission tariff, state royalties and other taxes. A brief description of these components is as follows

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.22

Consumer price

The consumer price was linked to international prices in a phased manner. Table 5.10 below gives details on the phasing of linking consumer prices to international prices.

Table 5.10 – Consumer price phased linkage to international prices

% of basket of fuels % of basket of fuels Rest of India North-East India October 1997 – March 1998 55 30 April 1998 – March 1999 65 40 April 1999 – March 2000 75 45

Floor price of gas from March 2000 US$ 1.46 per GJ US$ 0.81 per GJ Ceiling price of gas from March 2000 US$ 1.92 per GJ US$ 1.15 per GJ

The price of gas charged by private/joint venture fields is higher than the price of domestic gas supplied by National Oil Companies. Gas supplies from private/joint venture fields obtained a price higher than the ceiling price of US$ 1.92 per GJ (approximately @ 1US$ = 46.34 Rupees) set for domestic gas supplies.

Transmission tariff

GAIL is responsible for the distribution of more than 90% of the natural gas produced in India. The gas transmission charge depends on whether the gas is transmitted through the HVJ pipeline or the regional pipelines.

For gas transmission along HVJ pipeline, the uniform transportation charge is US$ 0.78 per GJ (approximately @ 1US$ = 46.34 Rupees). This price is linked to a gas with a calorific content of 240.73 Kilocalorie per scf. For gas having a lower or higher calorific content, the transmission charge will increase or decrease proportionately. The transmission tariff to GAIL would increase by 1% for every 10% increase in

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.23 consumer price index (“CPI”). This increase in transmission tariff is accounted for from the gas pool account and not from end-users/consumers.

For gas transmitted along regional pipelines, the transmission charge is based on individual contract signed between GAIL and the end-user. The average gas transmission charge is US$ 0.14 per GJ (approximately @ 1US$ = 46.34 Rupees). The gas transmission charge along the regional pipelines is much lower when compared to that along the HVJ pipeline because xThe investment made in regional pipelines was comparatively less. xSome regional pipelines have been constructed by the consumers and are only operated by GAIL.

State royalty and other taxes

Taxes paid by consumers include state royalty and sales tax. The royalty paid is 10% of producer price. The sales tax applied on natural gas is different in each state in India. The sales tax applied on natural gas in some of the key states in India is given in Table 5.11 (reference 33).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.24

Table 5.11 – Sales tax on natural gas

State Tax Rate (%) State Tax Rate (%) Andhra Pradesh 16 Maharashtra 13 Assam 13.2 Manipur 13 Bihar - Meghalaya - Delhi 20 20 Goa 8 Orissa 12 Gujarat 12 Punjab - Haryana 10 Rajasthan 11.5 Himachal Pradesh 8 Sikkim - Jammu & Kashmir 20 Tamil Nadu 8 Karnataka 12 Tripura 12 Kerala 24 Uttar Pradesh 20 Madhya Pradesh 8 Uttaranchal 20 Chhatisgarh 8 West Bengal -

The ministry of petroleum plans to dismantle the old pricing mechanism and achieve 100% fuel oil parity in prices. In July 2003, key recommendations were made by a group of ministers (empowered to review the natural gas prices). The group of ministers recommended the following xAn increase in the consumer gas price from the current price of US$ 1.92 per GJ to US$ 2.16 per GJ (approximately @ 1US$ = 46.34 Rupees) xAn increase in the transmission charge along HVJ pipeline to US$ 0.78 per GJ. xAllowing ONGC and OIL to sell gas from joint-venture fields at market driven prices (excepting the 35.31 MMSCFD of gas produced from the Cairn Energy operated Ravva field to avert severe impact on power consumers in Andhra Pradesh).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.25 xLimiting contributions to the gas pool account to Rupees 1 billion per year, or according to the actual compensation provided for subsidized gas prices in north- eastern states (whichever being lower). This can be compared to the current amount of Rupees 2.5 billion per year.

The recommendations on price revision for natural gas produced by national oil companies like ONGC and OIL may come into effect soon. For the new fields and additional gas from existing fields, it has been recommended that the gas pricing be market determined.

Post APM - Market driven pricing

This section deals with the prices at which gas could be sold under a market driven pricing mechanism. Gas supplies from Ravva’s satellite gas field are the first to sell at market driven prices. GAIL was successful in achieving a price of US$ 3.81 per GJ (delivered) for gas from Ravva satellite fields.

Imported LNG is expected to cost more than domestic gas. The high price for imported LNG is because of additional costs related to regasification, transportation, marketing, shipping and sales tax. Table 5.12 below gives details on costs incurred by Petronet LNG before arriving at a delivery price of US$ 4.25 per GJ for consumers in Gujarat.

The FOB price of gas from Ras Gas is linked to Japanese Cocktail Crude (“JCC”) for the first five years. Ras Gas plans to sell gas to Petronet at a FOB price of US$ 2.67 per GJ for the first five years after which the price would be linked to a basket of crude oil with a floor price of US$ 2.13 per GJ (equivalent to US$ 16 per barrel) and a ceiling price of US$ 3.20 per GJ (equivalent to US$ 24 per barrel).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.26

Table 5.12 – Petronet LNG’s gas delivery price in Gujarat

US$ per GJ Ras Gas to Petronet FOB at Abu Dhabi 2.67 Shipping cost 0.27 Customs duty @ 5% 0.15 Regasification cost 0.46 Ethane, propane extraction cost (paid to ONGC) (-) 0.16 Final price to off taker 3.39

Sales tax (12% in Gujarat) 0.41 Marketing margin for GAIL, IOC, BPCL 0.11 Transportation charge along HVJ pipeline 0.34 Final delivered cost to consumer in Gujarat 4.25

Offshore Mumbai, ONGC has offered natural gas to Tata Power Company from its marginal fields at a price between US$ 3.69 and 3.96 per GJ. Shell is expected to market LNG around Hazira at prices close to US$ 3.69 per GJ. Incremental gas from Tapti gas field offshore Mumbai is reported to be sold at a price between US$ 4.22 and 4.75 per GJ.

Gas from Reliance’s discovery on the east coast is expected to be marketed at a lower price than imported LNG. Reliance’s gas discovery at Krishna-Godavari might undermine stability of LNG projects planned on east coast. Reliance is expected to land gas at a price of US$ 2.64 per GJ at Kakinada. Reliance has offered to deliver gas at US$ 3.69 per GJ for power companies in Karnataka.

Recently Reliance reported that it would deliver gas at a very competitive rate of US$ 3.13 per GJ to National Thermal Power Corporation’s Kawas and Gandhar power plants in Gujarat. The lowest price at which natural gas had been sold in Gujarat till then was at US$ 3.48 per GJ. Figure 5.6 below illustrates the expected landfall prices for gas supplies made by various parties around India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.27

Figure 5.6 – Consumer gas prices around India

Natural gas consumers in the supply constrained market of western India would clearly benefit from competitive pricing. Pricing of gas could also depend on the sector to which the gas is supplied. Glass manufactures in Gujarat are reported to be willing to pay a price as high as US$ 5.28/GJ for gas supplies. The power and fertilizer companies have repeatedly said that they would purchase gas only if it is below US$ 3.69/GJ.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.28

Imported LNG could compete aggressively with domestic gas supplies with the help of certain fiscal concessions from the government. These concessions include reduced sales tax and abolishment of the 5% customs duty presently levied on all LNG imports.

Pricing is expected to be most competitive in western India. If more discoveries are made on the east coast, gas could be cheapest in that area.

5.4 Liquefied Petroleum Gas (LPG)

Liquefied Petroleum Gas (“LPG”) is a fuel that has many applications ranging from domestic cooking, automobile engines and as petrochemical feedstock. LPG accounts for nearly 8.5% of the total petroleum product consumption of India. LPG is quickly replacing kerosene as the most preferred domestic cooking fuel.

5.4.1 LPG supply

Public Sector Units/Oil Marketing Companies (“PSU/OMCs”) like Indian Oil Corporation (“IOC”), Hindustan Petroleum Corporation Limited (“HPCL”), Bharat Petroleum Corporation Limited (“BPCL”) and Indo Burma Petroleum (“IBP”) currently account for 95% of supply of LPG. These OMCs supply LPG in bottled cylinders (5, 14.2, 19, 35 or 47.5 kilogram each) to households or as bulk packages (using tank- trucks) for commercial and industrial consumers.

Figure 5.7 indicates the growth witnessed in Indian LPG market in recent years.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.29

Figure 5.7 – Trends in Indian LPG market

10

Consumption 8 Production

6

9.307 8.351 4 7.728 7.651

Million Tonnes 7.016 6.992 7.288 6.422 6.148

4.484 2

0 1999-00 2000-01 2001-02 2002-03 2003-04* Time

The total quantity of LPG imported during 2003-04 was 1.7 million tonnes. LPG was imported mainly from Saudi Arabia, Kuwait, Malaysia and United Arab Emirates.

The LPG bottling capacity in India was a provisional figure of 7,402 million tonnes in 2003-04. There are a large number of bottling plants are present in Maharashtra, Uttar Pradesh, Tamil Nadu and Andhra Pradesh. Traditionally LPG was transported in bulk by rail (using tank wagons) or by road (using tank trucks) in India. Recently, the Gas Authority of India Limited (“GAIL”) commissioned its 1,239 kilometre LPG pipeline to transport LPG from Kandla and Jamnagar in western India to the north and northwestern states of India. A similar pipeline is also being considered for transporting LPG in southern India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.30

5.4.2 LPG demand

The Indian demand for LPG in 2003-04 was 9.50 million tonnes. The demand for LPG has been on the rise in recent years. Over 90% of LPG consumed in India is used for domestic cooking fuel. The remaining 10% is used for industrial heating and commercial establishments like restaurants and hotels.

Until recently, the OMCs marketed LPG only in urban areas. Having saturated urban markets they are now expanding to the rural areas where only private companies operated historically. Today, LPG is available in most rural villages where kerosene used to be the only fuel used for domestic cooking.

The demand is further expected to rise as HPCL is exploring new ways for using LPG in household and industrial sectors. HPCL plans to introduce household appliances like air-conditioners, generators, geysers that could use LPG as a fuel. “In the industrial sector, HPCL has developed a machine powered by LPG for drying tea leaves” (reference 34).

The demand for LPG as an auto fuel has been stagnant in the past few months. The high level of taxes that are imposed on auto LPG by state governments is believed to be the reason. With help from state and central governments, the OMCs expect that the demand for LPG as an auto fuel would increase in the future.

In the fiscal year 2005-06, the demand is expected to grow at 9% annually to touch 10.36 million tonnes. By 2006-07, India’s LPG demand is expected to touch 12 million tonnes. Domestic LPG production is currently around 7.7 million tonnes and is expected to increase to 8.8 million tonnes by 2007. The deficit of over 3 million tonnes is expected to be met through LPG imports.

5.4.3 LPG pricing

Pricing of LPG is controlled by the government at the moment and LPG is sold at subsidized rates to consumers. Even though the Administered Pricing Mechanism was dismantled, the government has extended subsidies to LPG and kerosene till date.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.31

The government expects to phase out all subsidies by 2006. Complete deregulation of LPG pricing should result in an increase in the number of marketers of LPG.

In the past, the growth of private companies in the Indian LPG market had been hampered because they were not able to compete with the subsidized prices. Presently the retail selling price of domestic LPG is US$ 6.77 per GJ in Mumbai. The bulk (ex-storage) prices of LPG at the various refineries ranges between US$ 8.97 per GJ to US$ 10.25 per GJ.

5.5 Coal

India is the world’s third largest producer of coal. Coal is the most abundant fossil fuel in India and accounts for approximately 55% of India’s energy needs. The bulk of country's high rank coal resources (approximately 95%) are located in the Damodar Valley coalfields.

5.5.1 Coal supply

Coal production in India has constantly increased over the last three decades. In India, while coal production increased from 299.97 million tonnes in 1999-2000 to 355.72 million tonnes in 2003-2004 (provisional), the production of lignite increased from 22.12 million tonnes in 1999-2000 to 27.96 million tonnes in 2003-2004 (provisional).

Non-coking coal accounts for nearly 90% of all coal produced in the country. The ash content in coal produced ranges between 15 and 45%.

Coal India Limited (“CIL”) and Neyveli Lignite Corporation Limited (“NLCL”) are the main producers of coal and lignite. Both CIL and NLCL are public sector undertakings under the control of Ministry of Coal. While CIL and its subsidiaries are the major producers of coal in India, NLCL is involved with exploration of lignite deposits in Tamil Nadu and generation of power from lignite based power projects. Figure 5.8 presents India’s coal and lignite production during the last five years (reference 35).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.32

Figure 5.8 – Coal and lignite production during last five fiscal years

400

350

300 Coal 250

200 355.72 336.87 309.63 322.64 150 292.27 299.97 Million Tonnes Million

100 Lignite 50

22.12 22.95 24.81 26.02 27.96 0 1998-99 1999-00 2000-01 2001-02 2002-03 2003-04* Time

Singareni Collieries Company Limited (“SCCL”) is the main source for coal supply in the southern region. Small quantities of coal are also produced by captive collieries like Tata Iron and Steel Company (“TISCO”), Indian Iron and Steel Company Limited (“IISCO”) and Damodar Valley Corporation (“DVC”). As stated earlier CIL and its subsidiaries are the major producers of coal in the country. The subsidiaries of CIL include x Limited (“ECL”) x Limited (“BCCL”) x Limited (“CCL”) xNorthern Coalfields Limited (“NCL”) x Limited (“WCL”) x Limited (“SECL”) x Limited (“MCL”) and xNorth Eastern Coalfields (“NEC”)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.33

Table 5.13 gives details on company-wise coal production during the last five fiscal years (reference 36).

Table 5.13 – Coal production during last five fiscal years (MMToe)+

1998 1999 2000 2001 2002 2003 Company 1999 2000 2001 2002 2003 2004* ECL 16.70 15.44 17.23 17.55 16.71 17.21 BCCL 16.70 17.15 15.96 15.52 14.85 13.95 CCL 19.78 19.92 19.52 20.78 22.73 22.95 NCL 22.45 23.62 25.45 26.10 27.72 28.91 WCL 19.52 20.81 21.64 22.75 23.25 24.30 SECL 35.38 36.11 37.09 39.42 40.94 43.65 MCL 26.75 26.78 27.54 29.39 32.11 36.91 NEC 0.39 0.35 0.41 0.39 0.39 0.45 Total CIL 157.66 160.19 164.83 171.91 178.69 188.34 SCCL 16.80 18.17 18.61 18.94 20.43 20.81 Captive Collieries 5.20 6.04 6.90 7.94 7.95 9.52 Grand Total 179.66 184.40 190.34 198.33 207.08 218.67 + MMToe = Million Tonnes of oil equivalent, * Provisional

The important modes of transport of coal are railways, road, merry-go-round systems (“MGR systems”), conveyor belt ropeways and the rail-cum-sea route. Table 5.14 presents the share of these modes of transport in the total movement of coal.

Table 5.14 – Transport of coal

Railways 53.0% Road 14.0% Merry-go-round systems 22.1% Other (conveyor belt ropeways, rail-cum-sea routes etc) 10.9%

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.34

5.5.2 Coal demand

Coal is the most important source of energy for electricity generation. About 70% of the coal produced in India is consumed by the power sector as most thermal power stations depend upon coal as their feedstock. In addition, other industries like steel, cement, fertilizer, chemicals, paper and thousands of medium and small-scale industries are also dependent on coal for their process and energy requirements. Another sector dependent on the use of coal is the transportation sector. Even though direct consumption of coal by the railways has reduced over the last few years (because steam locomotives have been phased out), the energy requirement for electric traction locomotives is still met by coal converted into electric power.

Table 5.15 below gives details on the offtake of some key consumers of coal from 1997-1998 to 2002-2003. The figures in brackets given in Table 5.15 are washery middlings and are not included in totals.

Table 5.15 – Consumer-wise offtake of coal (Million Tonnes of oil equivalent)

1997 1998 1999 2000 2001 2002 Consumer 1998 1999 2000 2001 2002 2003* Power houses 130.89 125.82 136.86 144.21 149.23 116.40 (Middlings) (2.23) (1.86) (1.30) (1.53) (1.11) (0.51) Steel plants and Cokeries 14.51 15.36 13.16 12.28 12.47 11.86 Locomotives 0.03 0.02 0.01 0.01 -- -- Cement plants 6.23 5.29 5.84 6.35 7.28 5.85 Fertilizer plants 2.85 2.53 2.07 1.95 1.97 0.73 Brick kilns, Textiles, 30.40 26.54 27.61 27.83 28.22 15.29 Chemicals, Paper etc. (1.29) Total Offtake 182.55 177.40 187.11 194.01 200.28 150.83 (3.52) (1.86) (1.30) (1.53) (1.11) (0.51) * Provisional

In the past two decades coal consumption grew at an annual rate of 5.7% while coal production grew at 5.1%. The deficit had been met by coal imports. Coking coal is

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 5.35 being imported by steel sector. Coal based power plants, cement plants, captive power plants, sponge iron plants industrial consumers and coal traders are importing non-coking coal. Coke is being imported mainly by pig-iron manufacturers and iron and steel sector consumers.

Table 5.16 gives details of import of coal and products during the last five fiscal years.

Table 5.16 – Coal imports (Million Tonnes of oil equivalent)

1999 2000 2001 2002 2003 2000 2001 2002 2003 2004* Coking Coal 6.76 6.80 6.83 7.96 7.38 Non-coking Coal 5.35 6.07 5.80 6.34 5.84 Coke 1.48 1.49 1.40 1.38 1.23 Total Import 13.59 14.35 14.03 15.68 14.45 * Provisional

The Planning Commission estimates the domestic coal production in 2006-07 to be about 248.97 million tonnes of oil equivalent (“MMToe”). This is against an estimated coal demand of 283.08 MMToe. The resulting deficit of 34.11 MMToe is expected to be met through import of coking coal for the steel sector and non-coking coal for the cement sector.

Sajith Venugopal July 2005 University of New South Wales

Chapter 6

Fiscal regime

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.1

Throughout this study the term “fiscal regime” is taken to mean all economically quantifiable forms of Government involvement in oil and/or gas field development. The fiscal regime includes royalty, production sharing arrangements and taxes of all kinds such as income tax, sales tax, export duty etc. In this chapter, I refer to the companies operating in upstream petroleum sector as Contractors because they are signatories to Production Sharing Contracts (“PSCs”) for the exploration and development of oil and gas.

The Government of India has been inviting private investment in the exploration for oil and gas since early 1980s. Up to 1991, the Government initiated 3 bidding rounds limited to offshore areas. In 1991 the Government began offering blocks on a regular basis. Between 1991 and 1995, the Government held 6 bidding rounds which included both offshore and onshore blocks. In 1996-97, after a review of the investment policy for the exploration of oil and gas - the fiscal and contract terms, the Government formulated the New Exploration Licensing Policy (“NELP”).

New Exploration Licensing Policy (“NELP”)

The introduction of NELP has renewed investor interest in India. A total of 19 PSCs were signed before NELP and under the first four rounds of NELP a total of 90 contracts were signed. Appendix C includes a list of all blocks offered under the first four rounds of NELP bidding rounds.

Some of the fiscal and contractual terms offered under NELP are as follows xThere is no mandatory state participation through National Oil Companies (“NOCs”) or any carried interest of the Government. xAll blocks offered are to be awarded through open international competitive bidding. xForeign participation is permitted up to 100%. xNo signature, discovery or production bonuses need to be paid to the Government by the Contractor.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.2 xThere is no commitment for any minimum expenditure. xNOCs are to get the same fiscal and contractual terms as private companies. They are also required to compete for obtaining petroleum exploration licenses (“PELs”) on a competitive basis instead of the earlier system of granting them PELs on nomination basis. xThe Government has waived all customs duty on imports related to petroleum operations. xThere is freedom for Contractors to sell crude oil and natural gas in domestic market at market related prices. This incentive gives the option to price crude and gas sales on a competitive basis rather than selling it under fixed pricing policy of the Government. xThe royalty payment for crude oil is set at 12.5% for onshore areas and 10% for offshore areas. xThe royalty on deepwater areas (beyond 400 metres water depth) is 5% for the first 7 years after the start of commercial production. After 7 years, the royalty rate increases to 10%. The lower royalty rate during initial years of field life is intended to encourage deepwater exploration in India. xThe limit for recovering costs (“the cost recovery ceiling”) is biddable up to 100%. xProfit sharing is based on pre-tax Investment Multiples (“IM”) and is biddable. xThe contractor has the option to amortise exploration and drilling expenditures over a period of 10 years from first commercial production. Exercising this option would help the Contractor to recover costs faster. xContributions to a site restoration fund (also known as an abandonment sinking fund) are fully deductible in the same year when calculating income tax.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.3 xThere is a 7 year tax holiday for income tax from commencement of production. Hence, during the first 7 years of commercial production, the Contractor has to only pay the Minimum Alternative Tax (“MAT”). MAT is levied at 7.5% of taxable income in all years. xThe Contractors enjoy fiscal stability during the entire period of their contracts. xA separate Petroleum Tax Guide (“PTG”) has been put in place to facilitate investors. xA Model Production Sharing Contract (“MPSC”) is used to aid in negotiation. The MPSC is reviewed for every NELP round.

This study uses and contains a description and analysis of PSC terms that are believed to be typical of current arrangements for exploration concessions. Legal and administrative aspects are not considered. A detailed description of the structure and components that form the typical PSC provisions are given below

6.1 Structure

Figure 6.1 shows the basic structure of the NELP PSC as a flow chart. The flow chart shown is a simplified version designed to highlight the main commercial workings of the PSC. Figure 6.1 has three main areas. Theses show the derivation of net cash flow for - xThe Project as a whole (the left hand side of Figure 6.1) xThe Government (the centre of Figure 6.1) xThe Contractors (the right hand side of Figure 6.1)

The beginning of the flow chart is the top left hand side of Figure 6.1. The remainder of the diagram shows how the different elements of Government Take are applied in the derivation of net cash flow. The net cash flow to the Contractors is shown at the bottom right hand side.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.4

Figure 6.1 – Structure of Indian NELP PSC

Project Cash Flow Government Cash Flow Contractor Cash Flow

Gross Revenue Gross Revenue

Royalty to Government Royalty

Cost Recovery Cost Recovery to Contractor

Profit Petroleum to Government

Profit Petroleum Profit Petroleum to Contractor

Income Tax to Income Tax Government

Contractor share of all costs spend

Net cash flow to Contractor

6.2 Illustration of workings of Indian PSC

Table 6.1 contains a numerical example of the Contractors’ net cash flow in one year under Indian NELP PSC terms. It is a simplified illustration of the workings of Indian PSCs. I assume the following for the calculation - Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.5 xThe cost recovery ceiling is 80%. xThe only costs during the year are operating costs (US$ 20MM) and abandonment provision (US$ 3.2MM). xThe development is in shallow water offshore and therefore the royalty rate is 10%. xThe Government’s share of profit petroleum is 50%. xMinimum Alternative Tax (“MAT”) does not apply and capital costs have already been depreciated for tax purposes. xThe seven year tax holiday is finished.

Table 6.1 – Illustration of net cash flow calculation for one year under NELP terms

Comments Gross Revenue Oil production (Kbopd) 9.1 Example data Oil price (US$/bbl) 30.0 Example data Oil revenue (US$MM) 100.0 Production * Price * 365 days

Royalty Gross revenue (US$MM) 100.0 From above Well head value (US$MM) 80. 0 Assumption (80%) Royalty rate (%) 10.0 NELP terms Total royalty (US$MM) 8.0 Well head value * Royalty rate (10%)

Cost Recovery (US$MM) Operating costs 20.0 Example data Abandonment provision 3.2 Example data Unrecovered costs from previous year 0.0 Example data Royalty paid 8.0 From royalty calculation above Total costs to recover 31.2 Sum of the three costs above

Maximum cost recovery (80%) 80.0 Gross revenue * Cost recovery ceiling Cost Recovery to Contractors 31.2 The minimum of Total costs to recover & Maximum cost recovery

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.6

Profit Petroleum (US$MM) Gross revenue 100.0 From above Cost Recovery 31.2 From above Total profit petroleum 68.8 Gross revenue – Cost Recovery Profit petroleum to Contractor (50%) 34.4 Total profit petroleum * 50%

Income tax (US$MM) (A) Cost Recovery to Contractor 31.2 From cost recovery calculation above Profit Petroleum to Contractor 34.4 From profit petroleum calculation above Total revenue to Contractor 65.6 Sum of the two revenues above (B) Royalty paid 8.0 From royalty calculation above Operating costs 20.0 From above Abandonment provision 3.2 From above Depreciation 0.0 Assumption Total expenditure made 31.2 Sum of all three above

Taxable income 34.4 (A) – (B) Tax rate applied to Contractor (%) 41.0 NELP terms Total taxable liability 14.1 Taxable income * Tax rate (41%)

Net Cash Flow to Contractor (C) Cost Recovery to Contractor 31.2 From cost recovery calculation above Profit Petroleum to Contractor 34.4 From profit petroleum calculation above Total revenue to Contractor 65.6 Sum of the two revenues above (D) Royalty paid 10.0 From royalty calculation above Operating costs 20.0 From above Abandonment provision 3.2 From above Income tax liability 14.1 From above Total expenditure made 47.3 Sum of all four above

Final Net Cash Flow to Contractor 18.3 (C) – (D)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.7

Calculation of Government Take Project Gross Revenue 100.0 From Gross Revenue calculation above Project Total Costs 23.2 Operating + Abandonment costs Project Net Cash Flow 76.8 Project Gross Revenue – Project Total costs Contractor’s Net Cash Flow 18.3 From above Difference = Government Take 58.5 Equal to 76.17% of project net cash flow

6.3 Components of Indian NELP PSCs

The main components of the Indian PSCs are described in more detail below

6.3.1 Royalty

As stated in Petroleum Tax Guide 1999, royalty is payable as a percentage of revenue generated from sales of crude oil or natural gas. Royalty rates depend on the circumstances of the PSC. Table 6.2 below lists the royalty rates applied to crude oil and natural gas sales in India.

Table 6.2 – Royalty rates

Onshore 12.5%

Shallow offshore (less than 400 meters) 10.0%

Deep offshore (over 400 meters) 5.0% for first 7 years of production, 10.0% thereafter

6.3.2 Cost Recovery

Under typical NELP PSCs, the Contractors can recover various costs incurred within the area of the PSC. Contactors recover costs from revenue available for cost

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.8 recovery. This is computed by multiplying “Gross Revenue” (generated from petroleum sales) by the “Cost Recovery Ceiling” (see below).

The limit set for cost recovery, often referred to as “Cost Recovery Ceiling” is negotiable as a percentage of gross revenue. If the “Cost Recovery Ceiling” is 100%, then the revenue available for cost recovery is all of “Gross Revenue.

The order in which costs are recovered is as follows

Royalty Production/Operating costs Exploration costs Development costs Any costs which have not been recovered in the previous year Abandonment provisions

If the total recoverable costs are greater than the revenue available for cost recovery, then the excess costs are carried forward for recovery in the following year or in later years.

A brief description of the various costs incurred by the Contractor is given below a) Production/Operating costs

Production costs are expenditures incurred in production of petroleum. Production costs typically consist of field labour costs, maintenance costs etc. These also include the general and administrative expenditure allocated to production costs. b) Exploration costs

Exploration costs are expenditure incurred in the search for petroleum, which may include xGeological, geophysical, geochemical, topographical and seismic surveys and data acquisition, processing and interpretation

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.9 xLabour, materials, supplies and services used in drilling exploration and appraisal wells xGeneral and administrative expenditures allocated to exploration costs c) Development costs

Development costs are expenditure incurred in the development of petroleum reservoirs and all associated off take, processing and transportation systems. These may include xDrilling wells for purposes of producing petroleum, including dry, producing and injection wells xCompleting producing and injection wells xCosts related to material, services and labour used in drilling and completing wells xPurchase, installation or construction of production, transport and storage facilities for production of petroleum, such as pipelines, flow lines, production and treatment units, wellhead equipment, subsurface equipment, enhanced recovery systems, offshore and onshore platforms, export terminals and piers, harbours and related facilities and access roads for production activities. xCosts related to engineering and design studies for field facilities xGeneral and administrative expenditures allocated to development costs d) Abandonment provision

Abandonment provisions, also known as “Site Restoration Payments”, are costs and expenses that may include the following xCosts related to proper abandonment of wells, other facilities, removal of equipment, structures and debris

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.10

xExpenses linked to establishment of drainage, replacement of top soil, re- vegetation, in-filling of excavations or any other appropriate actions in the circumstances

The Contractor is required to establish a Site Restoration Fund in accordance with the scheme notified by the Government. Any payment that is made to the Site Restoration Fund is fully cost recoverable.

Costs not recoverable

Some costs and expenses that cannot be included in recoverable costs include xCosts and expenses incurred prior to the effectiveness of the PSC, in respect to preparation, signature or ratification xCosts of marketing or transportation of petroleum beyond the “Delivery Point” xFines, interest and penalties imposed by Courts of law of the Republic of India xDonations and contributions xAttorney's fees and other costs and charges in connection with arbitration proceedings and sole expert determination pursuant to the PSC xExpenditures on creation of any partnership or joint venture arrangement xCosts and expenditures incurred as a result of misconduct or negligence of the Contractor xAmounts paid with respect to non-fulfilment of contractual obligations

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.11

6.3.3 Profit Sharing

Profit petroleum is shared between the Government and the Contractor in varying proportions depending on an Investment Multiple (“IM”) ratio calculation using the Contractors’ cash flow in the previous year.

The IM for the previous year is determined by dividing the accumulated Contractors’ “Net Cash Income” by the Contractors’ accumulated “Investment”.

“Net Cash Income” equals the Contractors’ revenue (Cost recovery plus Share of Profit Petroleum) less the Contractors’ Production costs and Royalty payments.

“Investment” equals the Contractors’ Exploration costs plus Development costs.

The split of profit petroleum between the Contractor and the Government is determined by the IM ratio. The IM ratio in any one year gives the profit petroleum split between the concerned parties for the next year.

Table 6.3 below, gives an illustration of profit split tranches used for petroleum sharing.

Table 6.3 – Illustration of profit sharing

Contractor’s share of Government’s share of Investment Multiple profit petroleum next profit petroleum next this year year year below 1.5 100% 0% 1.5 to 2.0 90% 10% 2.0 to 2.5 80% 20% 2.5 to 3.0 70% 30% 3.0 to 3.5 60% 40% over 3.5 50% 50%

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.12

6.3.4 Income Tax

Income tax calculations are based on the revenues and expenditures of each individual company in the PSC. The ring fence for income tax is the PSC with the exception that failed exploration costs outside the PSC can be deducted against tax. Income tax is calculated as follows a) “Normal” Income Tax

The first step in calculating liability for income tax is to calculate the “Normal” income tax. Under NELP terms, there is a 7 year tax holiday for “Normal” income tax from production start.

“Normal” income tax is calculated as shown in Table 6.4.

Table 6.4 – Normal income tax calculation

Contractor’s revenue (A) Contractor’s expenditures (B)

Cost recovery Royalties Profit petroleum Operating costs Exploration costs Depreciation of development costs at different rates depending on the equipment Abandonment provision Tax losses from previous years

A less B multiplied by the tax rate equals “Normal” income tax liability

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.13 b) Minimum Alternative Tax (“MAT”)

The next step is to calculate the Minimum Alternative Tax (“MAT”). MAT is calculated as 7.5% of Contractor’s profit for the period under consideration. There is no 7 year tax holiday for MAT.

Table 6.5 below gives details of the Minimum Alternative Tax (“MAT”) calculation.

Table 6.5 – Minimum Alternative Tax (“MAT”) calculation

Contractor’s revenue (A) Contractor’s expenditures (B)

Cost recovery Royalties Profit petroleum Operating costs Depleted exploration and development costs (units of production basis) Abandonment provision Tax losses from previous years

A less B multiplied by 7.5% equals MAT

6.4 Worked example of an Indian NELP PSC

The following presents a detailed worked example of the workings of an Indian NELP PSC, as it would apply to a hypothetical stand alone oil field development. The cash flow calculations have been carried out for a period of 25 years. However, for the purpose of presentation only, calculations for the first 10 years are shown in the following.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.14

Table 1a Production & Revenue Units Factors Totals 1 2 3 4 5 6 7 8 9 10 Oil production per day Mbopd 7.50 7.50 11.25 15.00 12.75 10.84 9.21 Oil production per year MMbbl/yr 27.03 2.74 2.74 4.11 5.48 4.65 3.96 3.36 Years of production Years 1 2 3 4 5 6 7 Price escalation % per year 3 % 1.00 1.03 1.06 1.09 1.13 1.16 1.19 1.23 1.27 1.30 Oil price US$/bbl 30.00 30.00 30.90 31.83 32.78 33.77 34.78 35.82 36.90 38.00 39.14 Gross revenue US$ MM 974.75 89.74 92.43 142.81 196.12 171.71 150.33 131.61 Table 1a Production & Revenue Explanations Oil production per day Average production in thousand barrels per day Oil production per year Production profile in million barrels per year Years of production Number of years from production start Price escalation Oil price escalation using escalation rate shown in “Factors” column Oil price Oil price projection in money of the day terms (US$ per barrel) Gross revenue Gross revenue = oil production * oil price

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.15

Table 2a Expenditures Units Factors Totals 1 2 3 45678910 Costs escalation factor % per year 3 % 1.00 1.03 1.06 1.09 1.13 1.16 1.19 1.23 1.27 1.30 Operating costs US$ MM -105.00 -15.00 -15.00 -15.00 -15.00 -15.00 -15.00 -15.00 Exploration costs US$ MM -10.00 -10.00 Development costs US$ MM -150.00 -50.00 -100.00 Past costs if any (US$ 50MM) US$ MM 50.00 -50.00 Abandonment provision US$ MM -70.00 -10.00 -10.00 -10.00 -10.00 -10.00 -10.00 -10.00 Table 2b Escalated expenditures Escalated values used in net cash flow analysis Operating costs escalated US$ MM -125.59 -16.39 -16.88 -17.39 -17.91 -18.45 -19.00 -19.57 Exploration costs escalated US$ MM -10.00 -10.00 Development costs escalated US$ MM -153.00 -50.00 -103.00 Past costs if any (US$ 50MM) US$ MM -50.00 Abandonment provision escalated US$ MM -83.73 -10.93 -11.26 -11.59 -11.94 -12.30 -12.67 -13.05 Table 2c Escalated expenditures Explanations Cost escalation factor Cost escalation using escalation rate shown in “Factors” column Operating costs escalated Operating costs multiplied by cost escalation factor Exploration costs escalated Exploration costs multiplied by cost escalation factor Development costs escalated Development costs multiplied by cost escalation factor Past costs if any (US$ 50MM) Past costs are already spend so no escalation occurs Abandonment provision escalated Abandonment provision multiplied by cost escalation factor

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.16

Table 3a Before tax NCF Units Factors Totals 1 2 3 45678910 Gross revenue US$ MM 974.75 89.74 92.43 142.81 196.12 171.71 150.33 131.61 Operating costs escalated US$ MM -125.59 -16.39 -16.88 -17.39 -17.91 -18.45 -19.00 -19.57 Exploration costs escalated US$ MM -10.00 -10.00 Development costs escalated US$ MM -153.00 -50.00 -103.00 Past costs if any (US$ 50MM) US$ MM 50.00 -50.00 Abandonment provision escalated US$ MM -83.73 -10.93 -11.26 -11.59 -11.94 -12.30 -12.67 -13.05 Before tax net cash flow US$ MM 602.43 -60.00 -103.00 0.00 62.42 64.29 113.83 166.27 140.96 118.66 98.99 Table 3b Before tax NCF Explanations Gross revenue Gross revenue from oil production Operating costs escalated Total project operating costs Exploration costs escalated Total project exploration costs Development costs escalated Total project development costs Past costs if any (US$ 50MM) Past costs Abandonment provision escalated Total project abandonment provision Before tax net cash flow Net cash flow for project = Gross revenue – Sum of operating, exploration, development and abandonment provisions

Table 4a Royalty calculations Units Factors Totals 1 2 3 45678910 Gross revenue US$ MM 974.75 89.74 92.43 142.81 196.12 171.71 150.33 131.61 Well head value US$ MM 779.80 71.79 73.95 114.25 156.90 137.36 120.26 105.29 Royalty rate US$ MM 10 % 10 % 10 % 10 % 10 % 10 % 10 % 10 % 10 % 10 % 10 % Royalty paid US$ MM 77.98 7.18 7.39 11.42 15.69 13.74 12.03 10.53 Table 4b Royalty calculations Explanations Gross revenue Gross revenue from oil production Well head value Well head value is computed as 80% of “Gross revenue” (assumption) Royalty rate Shallow water development, hence royalty rate is 10% as shown in “Factors” column Royalty paid Royalty paid = Well head value * Royalty rate

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.17

Table 5a Contractor’s cost recovery Units Factors Totals 1 2 3 45678910 Gross revenue US$ MM 974.75 89.74 92.43 142.81 196.12 171.71 150.33 131.61 Available revenue US$ MM 779.80 71.79 73.95 114.25 156.90 137.36 120.26 105.29 Royalty paid US$ MM 77.98 7.18 7.39 11.42 15.69 13.74 12.03 10.53 Operating costs escalated US$ MM 125.59 16.39 16.88 17.39 17.91 18.45 19.00 19.57 Exploration costs escalated US$ MM 10.00 10.00 Development costs escalated US$ MM 153.00 50.00 103.00 Abandonment provisions escalated US$ MM 83.73 10.93 11.26 11.59 11.94 12.30 12.67 13.05 Costs to be recovered this year US$ MM 450.30 60.00 103.00 0.00 34.50 35.53 40.41 45.54 44.48 43.70 43.15 Unrecovered costs from last year US$ MM 50.00 110.00 213.00 213.00 175.71 137.29 63.45 Total costs to be recovered US$ MM 1412.75 110.00 213.00 213.00 247.50 211.24 177.70 108.99 44.48 43.70 43.15 Cost recovery US$ MM 500.30 71.79 73.95 114.25 108.99 44.48 43.70 43.15 Unrecovered costs this year US$ MM 110.00 213.00 213.00 175.71 137.29 63.45 Table 5b Contractor’s cost recovery Explanations Gross revenue Gross revenue from oil production Available revenue Available revenue = Gross revenue * Cost recovery ceiling (assumed to be 80%) Royalty paid Royalty paid = Gross revenue * Royalty rate (10%) Operating costs escalated Total project operating costs Exploration costs escalated Total project exploration costs Development costs escalated Total project development costs Abandonment provisions escalated Total project abandonment provision Costs to be recovered this year Equals “Uncovered costs from last year” + Royalty + Sum of all costs (including Past costs as shown in grey cell) Unrecovered costs from last year Equals costs that was not recovered in previous year Total costs to be recovered Sum of all costs to be recovered in this year Cost recovery Final cost recovery = Minimum of “Total costs to be recovered” and “Available revenue” Unrecovered costs this year Uncovered costs this year = Gross revenue – Royalty - Sum of all costs spend (including Past costs if any)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.18

Table 5a Contractor’s profit oil Units Factors Totals 1 2 3 45678910 Gross revenue US$ MM 974.75 89.74 92.43 142.81 196.12 171.71 150.33 131.61 Contractor’s Cost recovery US$ MM 500.30 71.79 73.95 114.25 108.99 44.48 43.70 43.15 Total profit petroleum US$ MM 474.45 17.95 18.49 28.56 87.13 127.22 106.63 88.46 Contractor’s share of profit petroleum US$ MM 353.40 17.95 18.49 28.56 76.71 101.78# 63.98* 44.23## Royalty paid US$ MM -77.98 -7.18 -7.39 -11.42 -15.69 -13.74 -12.03 -10.53 Operating costs escalated US$ MM -125.59 -16.39 -16.88 -17.39 -17.91 -18.45 -19.00 -19.57 Net Cash Income US$ MM 650.13 66.17 68.16 113.99 153.81 114.08 76.65 57.28 Cumulative Net Cash Income US$ MM 66.17 134.33 248.32 402.13 516.21 592.85 650.13 Past costs if any US$ MM 50.00 Exploration costs escalated US$ MM 10.00 10.00 Development costs escalated US$ MM 153.00 50.00 103.00 Total “Investment” US$ MM 163.00 60.00 103.00 Cumulative “Investment” US$ MM 60.00 163.00 163.00 163.00 163.00 163.00 163.00 163.00 163.00 163.00 Investment Multiple (“IM”) Ratio 0.41 0.82 1.52 2.47 3.17 3.64 3.99 IM <= 1.5 % 100 % 100 % 100 % 100 % 100 % 100 % 90 % 1.5 < IM <= 2.0 % 90 % 80% 2.0 < IM <= 2.5 % 80 % 2.5 < IM <= 3.0 % 70 % 3.0 < IM <= 3.5 % 60 % 60 % IM > 3.5 % 50 % 50 % 50 % Contractor’s share of profit petroleum % 100 % 100 % 100 % 100 % 100 % 90 % 80 % 60 % 50 % 50 % next year Footnotes # Total profit petroleum (=127.22) * Contractor’s share of profit petroleum next year (=80%) equals Contractor’s share of profit petroleum this year (=101.78) ^ Total profit petroleum (=106.63) * Contractor’s share of profit petroleum next year (=60%) equals Contractor’s share of profit petroleum this year (=63.98) ## Total profit petroleum (=88.46) * Contractor’s share of profit petroleum next year (=50%) equals Contractor’s share of profit petroleum this year (=44.23)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.19

Table 5b Contractor’s profit oil Explanations Gross revenue Gross revenue from oil production Contractor’s cost recovery Total cost recovered according to PSC terms Total profit petroleum Total profit petroleum = Gross revenue – Cost recovery done Contractor’s share of profit petroleum Contractor’s share of profit petroleum = Total profit petroleum * Contractor’s share of profit petroleum in % Royalty paid Royalty paid = 10% of Gross revenue Operating costs escalated Total operating costs escalated Net Cash Income Cost recovery + Contractor’s share of profit petroleum - Royalty paid - Operating costs Cumulative Net Cash Income Net Cash Income is accumulated over the years Past costs if any Past costs Exploration costs escalated Total exploration costs escalated Development costs escalated Total development costs escalated Total “Investment” Equals Past costs + Exploration costs + Development costs Cumulative “Investment” Total “Investment” is accumulated over the years Investment Multiple (“IM”) Ratio of “Cumulative Net Cash Income” and “Cumulative Investment” IM <= 1.5 Percentage in “Factor” column when Investment Multiple is less than or equal to 1.5 1.5 < IM <= 2.0 Percentage in “Factor” column when Investment Multiple is between 1.5 and 2.0 2.0 < IM <= 2.5 Percentage in “Factor” column when Investment Multiple is between 2.0 and 2.5 2.5 < IM <= 3.0 Percentage in “Factor” column when Investment Multiple is between 2.5 and 3.0 3.0 < IM <= 3.5 Percentage in “Factor” column when Investment Multiple is between 3.0 and 3.5 IM > 3.5 Percentage in “Factor” column when Investment Multiple is greater than 3.5 Contractor’s share of profit petroleum Maximum of all percentages in six rows above next year

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.20

Table 6a Contractor’s income tax Units Factors Totals 1 2 3 45678910 Normal Income tax Contractor’s cost recovery US$ MM 500.30 71.79 73.95 114.25 108.99 44.48 43.70 43.15 Contractor’s share of profit petroleum US$ MM 353.40 17.95 18.49 28.56 76.71 101.78 63.98 44.23 Contractor’s total revenue US$ MM 853.71 89.74 92.43 142.81 187.41 146.26 107.68 87.38 Royalty paid US$ MM -77.98 -7.18 -7.39 -11.42 -15.69 -13.74 -12.03 -10.53 Operating costs escalated US$ MM -125.59 -16.39 -16.88 -17.39 -17.91 -18.45 -19.00 -19.57 Exploration cost escalated US$ MM -10.00 -10.00 Depreciation of development cost US$ MM 25 % -153.00 -25.75 -19.31 -14.48 -10.86 -8.15 -6.11 -68.33# Past costs if any US$ MM -50.00 Abandonment provision escalated US$ MM -83.73 -10.93 -11.26 -11.59 -11.94 -12.30 -12.67 -13.05 Net revenue US$ MM 403.40 -10.00 29.49 37.59 87.92 131.01 93.63 57.87 -24.10 Taxable income US$ MM 90.88^ 56.07 Tax rate US$ MM 41 % 41% 41% 41% 41% 41% 41% 41% 41% 41% 41% Normal Income Tax liability US$ MM 62.11 38.39 23.73 Minimum Alternative Tax (“MAT”) Contractor’s cost recovery US$ MM 500.30 71.79 73.95 114.25 108.99 44.48 43.70 43.15 Contractor’s share of profit petroleum US$ MM 353.40 17.95 18.49 28.56 76.71 101.78 63.98 44.23 Contractor’s total revenue US$ MM 853.71 89.74 92.43 142.81 187.41 146.26 107.68 87.38 Royalty paid US$ MM -77.98 -7.18 -7.39 -11.42 -15.69 -13.74 -12.03 -10.53 Operating costs escalated US$ MM -125.59 -16.39 -16.88 -17.39 -17.91 -18.45 -19.00 -19.57 Depleted (Exploration + Past) costs US$ MM -60.00 -6.08 -6.08 -9.12 -12.15 -10.33 -8.78 -7.46 Depleted Development costs US$ MM -153.00 -15.50 -15.50 -23.24 -30.99 -26.34 -22.39 -19.03 Abandonment provision escalated US$ MM -83.73 -10.93 -11.26 -11.59 -11.94 -12.30 -12.67 -13.05 Taxable income US$ MM 353.40 33.67 35.33 70.04 98.72 65.10 32.81 17.73 Tax rate US$ MM 7.5 % 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% Minimum Alternative Tax liability US$ MM 26.51 2.53 2.65 5.25 7.40 4.88 2.46 1.33 Contractor’s income tax liability US$ MM 81.28 2.53 2.65 5.25 7.40 38.39 23.73 1.33 Footnotes – # I assume that the depreciation method adopted is declining balance method with balloon payment occurring in the 7th year of production. The depreciation rate assumed is 25%.

^ I assume the tax holiday granted under NELP terms to be 4 years as against the 7 year tax holiday normally granted by Indian Government.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.21

Table 6b Contractor’s income tax Explanations Normal Income tax Contractor’s cost recovery Total cost recovered according to PSC terms Contractor’s share of profit petroleum Contractor’s share of profit petroleum calculated above Contractor’s total revenue Equals Contractor’s cost recovery + share of profit petroleum Royalty paid Equals 10% of Gross revenue Operating costs escalated Total project operating costs Exploration cost escalated Total project exploration costs Depreciation of development cost Development costs are depreciated using declining balance method. Depreciation rate used = 25% Past costs if any Past costs Abandonment provision escalated Total project abandonment provision Net revenue Equals Contractor’s total revenue – Royalty – Sum of all costs made Taxable income Positive values of Net revenue Tax rate Income tax rate as laid out by Indian law (41% for foreign companies) Normal Income Tax liability Equals Taxable income * Tax rate

Minimum Alternative Tax (“MAT”) Contractor’s cost recovery Total cost recovered according to PSC terms Contractor’s share of profit petroleum Contractor’s share of profit petroleum calculated above Contractor’s total revenue Equals Contractor’s cost recovery + share of profit petroleum Royalty paid Equals 10% of Gross revenue Operating costs escalated Total project operating costs Depleted (Exploration + Past) costs Depleted costs are computed on a units of production basis Depleted Development costs Depleted costs are computed on a units of production basis Abandonment provision escalated Total project abandonment provision Taxable income Equals Contractor’s total revenue – Royalty – Sum of all costs made Tax rate Equals 7.5% Minimum Alternative Tax liability Equals Taxable income * Tax rate

Contractor’s income tax liability In any year equals maximum between nominal Tax liability and Minimum Alternative Tax liability

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 6.22

Table 7a After tax net cash flow Units Factors Totals 1 2 3 45678910 Contractor’s cost recovery US$ MM 500.30 71.79 73.95 114.25 108.99 44.48 43.70 43.15 Contractor’s share of profit petroleum US$ MM 353.40 17.95 18.49 28.56 76.71 101.78 63.98 44.23 Contractor’s total revenue US$ MM 853.71 89.74 92.43 142.81 187.41 146.26 107.68 87.38 Royalty paid US$ MM -77.98 -7.18 -7.39 -11.42 -15.69 -13.74 -12.03 -10.53 Operating costs escalated US$ MM -125.59 -16.39 -16.88 -17.39 -17.91 -18.45 -19.00 -19.57 Exploration cost escalated US$ MM -10.00 -10.00 Development cost escalated US$ MM -153.00 -50.00 -103.00 Abandonment provision escalated US$ MM -83.73 -10.93 -11.26 -11.59 -11.94 -12.30 -12.67 -13.05 Income tax liability US$ MM -81.28 -2.53 -2.65 -5.25 -7.40 -38.39 -23.73 -1.33 After tax net cash flow US$ MM 322.13 -60.00 -103.00 52.72 54.25 97.15 134.46 63.39 40.25 42.90 Table 7b After tax net cash flow Explanations Contractor’s cost recovery Total cost recovered according to PSC terms Contractor’s share of profit petroleum Contractor’s share of profit petroleum calculated above Contractor’s total revenue Equals Contractor’s cost recovery + share of profit petroleum Royalty paid Equals 10% of Gross revenue Operating costs escalated Total project operating costs Exploration cost escalated Total project exploration costs Development cost escalated Total project development costs Abandonment provision escalated Total project abandonment provision Income tax liability Total income tax liability calculated above After tax net cash flow Equals Contractor’s total revenue – Royalty – Sum of all costs made – Income tax liability

Sajith Venugopal July 2005 University of New South Wales

Chapter 7

Fiscal analyses

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.1

A description of the current fiscal regime under NELP terms in India is given in Chapter 6. This chapter contains economic analyses of a hypothetical, but representative exploration and field development possibility in India. For the purpose of conducting this study, I assume the fiscal terms described in Chapter 6 to apply to the hypothetical field considered.

The hypothetical field analysed is representative of exploration and development conditions offshore India in the Krishna Godavari Basin, in shallow water depths of less than 200 meter (“m”).

The aim of this chapter is to analyse the economic effects on field development of critical aspects of fiscal terms in India.

7.1. Government Take

“Government Take” is the total of all quantifiable forms of government involvement in a petroleum project, including royalty, production sharing arrangements (if any), income tax, and Government’s share of profit petroleum. Government Take is defined as follows -

Total project net cash flow Government Take = less Contractor’s net cash flow

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

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.2

The total project net cash flow equals the project’s total gross revenue less the project’s total costs. The project’s total costs include exploration, development, operating and abandonment costs.

Following oil and gas industry convention, Government Take is measured on an undiscounted basis.

7.2. Assumptions

7.2.1 Economic assumptions

Exploration cost

For the purpose of defining the typical cost of drilling an exploration well in the shallow water regions of Krishna Godavari Basin, I have taken the cost of an exploration well drilled in Ravva PSC (in the same basin). The cost of a Ravva PSC exploration well in 1994 was approximately US$ 2.50MM. Assuming this cost escalates at an escalation rate of 3% per year, the cost of an exploration well at the time of writing in the same region would be around US$ 4.28MM. Along with the cost of drilling, I include additional costs related to seismic and geological studies, and thus take the total exploration costs per well to be approximately US$ 5MM.

Development cost

I have based the development costs of a hypothetical discovery in the Krishna Godavari Basin on information on development spending of the Ravva field, which initially had a peak rate of 35,000 barrels of oil per day (“bopd”).

I assume that the cost of developing a field with a peak rate of X thousand bopd (“kbopd’) would be

Costs for X kbopd = Costs for 35 kbopd * (X/35)^0.7

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.3

7.2.2 Development assumptions

I assume that all development spending would be made in the first 3 years of project life.

10% of total development costs would be spent in the second year of project life, 50% in the third year and 40% in the fourth year.

Details of production phasing are given in Table 7.1.

7.2.3 Fiscal assumptions

All assumptions related to fiscal terms under which this hypothetical field would operate are given in Table 7.1. These are terms assumed for the NELP bidding rounds.

7.2.4 Summary of assumptions

In Table 7.1, I give a detailed summary of all economic and development assumptions used in this study.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.4

Table 7.1 – Summary of assumptions as applied in NELP bidding rounds Economic assumptions

Exploration cost – I assume each exploration or appraisal well to cost US$ 5MM. Development cost – I scale all costs up or down using a 0.7 Power Rule. Oil Price – US$ 28 per barrel (refer to Appendix D) Development assumptions Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Exploration/Appraisal well phasing fields less than 10 million barrels Number of wells 1 fields less than 50 million barrels Number of wells 2 1 fields less than 100 million barrels Number of wells 2 2 fields greater than 100 million barrels Number of wells 2 2 2

Production phasing fields less than 10 million barrels % of peak* 100% Decline fields less than 50 million barrels % of peak* 75% 100% Decline fields less than 100 million barrels % of peak* 50% 75% 100% 100% 100% 100% Decline fields greater than 100 million barrels % of peak* 25% 50% 75% 100% 100% 100% 100% 100% 100% Decline

Development cost phasing % of total 10% 50% 40% Fiscal assumptions

Royalty rate 10% Royalty rate is 10% of well head value of crude oil. Well head value is assumed to be 80% of gross revenue generated from crude oil sales. Cost recovery ceiling 80% Government’s share of profit oil 10% when Investment Multiple reaches 2.0 20% when Investment Multiple reaches 2.5 30% when Investment Multiple reaches 3.0 40% when Investment Multiple reaches 3.5 50% when Investment Multiple is over 3.5

Income tax rate 41% Tax rate for Foreign companies

* Peak production is assumed to be 5% of initial reserves per year

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.5

7.3. Impact of individual components of Government Take

Figure 7.1 shows the relative economic impact of the fiscal assumptions listed in Table 7.1. The figure is based on the economic analyses of developing individual, representative stand alone oil discoveries in the shallow waters of Krishna Godavari Basin. The economic analysis carried out is for a range of field reserves using a real oil price of US$ 28 per barrel (refer to Appendix D).

Figure 7.1 – Impact of components of Government Take

20

18 Analysis conducted at 16 US$ 28 per barrel Gross Revenue 14

12

10 Minimum size before Exploration,development, Government Take operating and abadonment costs 8 NPV of BTNCF

6 Royalty (Profit petroleum)

NPV @ 10% per barrel of reserves (US$) 4 Income Tax

2 Minimum size after all forms NPV of ATNCF of Government Take Reserves (MMbbl) 0 0 2 4 6 8 1012141618202224262830

The top line in Figure 7.1 represents the present value per barrel of reserves of the Gross Revenue generated from crude oil sales over the economic life of the project. The peak in the curve relates to the production profile assumed and has no significance in the context of this exercise.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.6

The second line below the top line represents the present value of Gross Revenue less the present value of the project’s exploration, development, operating and abandonment costs. Hence, this line represents the net present value (“NPV”) of the Contractor’s before tax net cash flow.

Subsequent lines show the impact of deducting the present values of royalty, Government’s share of profit petroleum and finally the income tax. The distance between any two lines demonstrates the economic impact that each fiscal component has on reducing the final economic return to the Contractor.

The lowest line in Figure 7.1 represents the net present value of the after tax net cash flow to the Contractor.

Figure 7.2 plots the various fiscal components of Government Take as a percentage of the project’s before tax NPV over a range of field sizes.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.7

Figure 7.2 – Fiscal components as percentage of project’s NPV

Fields uneconomic before Government 220% Government Take Take makes 200% field development Analysis conducted 180% uneconomic at US$ 28 per barrel 160%

140% Fields economic after Government Take Royalty 120% 100% Government's share of Profit 80% Petroleum 60% Percentage of BTNPV (%) 40% Income Tax 20% 0.6 2.8 4.6 5.9 6.3 16.3 23.8 58.4 133.9 242.4 Field size (MMbbl)

Figure 7.2 shows that ignoring the effects of Government Take; discoveries are economic when field sizes are greater than approximately 4 million barrels (“MMbbls”). This is based on the before tax net cash flow of the Contractor. After Government Take, the minimum economic field size is approximately 6 MMbbls. For the field sizes between 4 and 6 MMbbls, the Government Take is more than 100% and renders the development uneconomic.

In the region where Government Take renders field development uneconomic, the component of Government Take that has the greatest economic impact is royalty. In this region, income tax has a smaller impact on field economics.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.8

For the field sizes above 6 MMbbls (the minimum economic field size after Government Take), the component of Government Take that has the greatest impact is the Government’s share of profit oil. This is because as field size gets larger, so does the net cash flow. This results in an increase in the Investment Multiple based on which Government’s share of profit oil is determined.

For field sizes above 6 MMbbls, the effects of royalty and income tax decrease as field size increases. For large fields, royalty and income tax contribute proportionately very little towards Government Take as compared to share of profit petroleum.

Table 7.2 shows the effect of assuming a range of oil prices (US$18 to US$ 50 per barrel).

Table 7.2 - Effects of fiscal components on minimum developable field size

Oil price = US$50 per Oil price = US$18 per barrel Oil price = US$28 per barrel barrel Increase in Increase in Increase in minimum minimum minimum developable developable developable Cases field size field size field size Minimum caused by Minimum caused by Minimum caused by developable each fiscal developable each fiscal developable each fiscal field size component field size component field size component (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl)

Without 11.12 5.11 2.35 Government Take

with Royalty 12.07 1.74 5.78 0.67 2.63 0.28

and Government’s 12.56 0.49 5.90 0.12 2.63 ------share of profit oil

and Income Tax 14.85 2.29 6.42 0.52 2.91 0.28

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.9

Effect of Cost Recovery on field economics

The Cost Recovery Ceiling (80% in our study) has no effect on field development economics. This is because the presence of Cost Recovery Ceiling does not influence the Contractor’s net cash flows. The Contractor’s net cash flow does not change because of the combined effect resulting from the decrease in Cost Recovery (due to Cost Recovery Ceiling) and the simultaneous increase in Contractor’s share of Profit Petroleum.

The Contractor’s revenue consists of Cost Recovery and a share of Profit Petroleum. We know from Chapter 6 that Profit Petroleum is shared between the Government and the Contractor in varying proportions depending on an Investment Multiple (“IM”). The IM for any year is calculated using the Contractor’s cash flow in the previous year.

The IM for the previous year is determined by dividing the accumulated Contractor’s “Net Cash Income” by the Contractor’s accumulated “Investment”.

“Net Cash Income” equals the Contractor’s revenue (Cost Recovery plus Share of Profit Petroleum) less Contractor’s Production costs and Royalty payments.

At the beginning of field life, the Contractor does not have any Profit Petroleum. In other words, the Contractor’s share of Profit Petroleum is 100% of zero (zero because there is no Profit Petroleum until all costs have been recovered). If, in any year there is revenue remaining after all costs have been recovered, then from that year onwards Contractor’s share of Profit Petroleum is calculated according to the IM tranches.

If there were any decrease in the Cost Recovery at the beginning of field life, this would result in a corresponding decrease of the Contractor’s revenue (because at this stage, the Contractor revenue consists of only the Cost Recovery). A decrease in Contractor’s revenue (due to lower Cost Recovery) results in a corresponding decrease in the value of IM. A lower IM would cause the Contractor’s share of Profit Petroleum, in the following year, to increase/revert back to the highest level (this depends on the value of the IM).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.10

Hence, even though there is a decrease in Cost Recovery made by the Contractor (because of the Cost Recovery Ceiling), the Contractor’s net revenue remains unaffected because of the subsequent increase in the share of Profit Petroleum. In other words, the decrease in Contractor’s revenue (due to a lower Cost Recovery) is balanced by the increase in the Contractor’s share of Profit Petroleum.

Nature of Indian fiscal terms

Table 7.2 shows that the range of field sizes rendered uneconomic by the fiscal terms increases as the oil price falls. As the field development becomes more marginal, so does the effects of royalties and, to a lesser extent, income tax becomes greater. It is clear that royalties are the most damaging to marginal field development. In other words, the NELP terms are regressive for marginal field developments and royalties have the biggest influence.

The regressive nature of the NELP terms is shown more clearly in Figure 7.3, which plots the relationship between the project’s profitability (as net present value per barrel of reserves of before take net cash flow) and Government Take (as a percentage). As seen in Figure 7.3, the Government Take is high for fields with low before tax net cash flow and falls as the fields become more profitable.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.11

Figure 7.3 – Economic effects of Indian fiscal regime

140%

120%

100%

80%

60%

Government Take (%) 40%

20%

0.50 1.00 1.50 2.00 2.50 3.00 3.50 NPV of project net cash flow per barrel of reserves (US$)

7.4. Reserves deemed uneconomic because of Government Take

As stated earlier, the behaviour of the Indian fiscal regime is such that it tends to undermine the development of marginal fields. In this section, I estimate the total volume of oil that remains undeveloped in the Krishna Godavari Basin because of the regressive elements of the fiscal regime.

Discovered reserves that are not developed due to Government Take

From Table 7.2, the minimum field size required for field development to remain profitable before any form of Government Take is 5.1 MMbbls. When all forms of Government Take are included in project economics, the minimum economically developable field size is estimated to be 6.4 MMbbls.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.12

As a result, fields with recoverable reserves between 5.11 MMbbls and 6.42 MMbbls remain undeveloped because of Government Take. This is not a significant difference. However, the difference is a function of the oil price assumed. The analysis below show the effect of different oil price assumptions and the overall impact of fiscal inefficiencies on basin development.

Effect of Government Take on Krishna Godavari Basin

In order to illustrate the economic impact of NELP fiscal terms on marginal field development in Krishna Godavari Basin, I assume notionally that the basin may contain either 50, 100 or 500 fields. I assume that field size distribution of these cases is as shown in Figure 7.4.

Each of the graphs shown in Figure 7.4 shows the number of fields plotted against field size.

These graphs represent the results of Monte Carlo simulation runs carried out to determine field size distributions. I assume field distribution to follow lognormal distribution with a 90% probability that field reserves are 10 MMbbls or more and a 10% probability that field reserves are 200 MMbbls or more.

I assume that each field in the basin is represented by one run of the Monte Carlo simulation. So, when assuming that the basin would have 50 fields, I carry out a Monte Carlo simulation with 50 iterations.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.13

Figure 7.4 – Field size distribution

When basin is assumed to have 50 fields

5

4

3

2 Number of fields

Reserves (MMbbls) 1

0 50 100 150 200 250 300 350 400 450 500

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.14

Figure 7.4 (contd) – Field size distribution

When basin is assumed to have 100 fields

12

11

10

9

8

7

6

5

4 Number of fields

3

2 Reserves (MMbbls) 1

0 50 100 150 200 250 300 350 400 450 500

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.15

Figure 7.4 (contd) – Field size distribution

When basin is assumed to have 500 fields

45

40

35

30

25

20

Number of fields 15

10

Reserves (M M bbls) 5

0 50 100 150 200 250 300 350 400 450 500

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.16

Based on these distributions, the number of discoveries rendered uneconomic (left stranded) by the fiscal terms under different oil prices is as shown in Figure 7.5.

Figure 7.5 – Fields that remain undeveloped in the basin

30

25

At US$ 18 per barrel 20

15 27

10 At US$ 28 per barrel

5 5 6

Number of fields undeveloped 012 0 50 100 500 Number of fields in basin

Based on the number of discoveries left stranded by the fiscal terms, we can calculate the total volume of oil left stranded. This is shown in Table 7.3.

Table 7.3 shows that at an oil price of US$ 28 per barrel, very little oil is left undeveloped due to Government Take. As the oil price drops to US$ 18 per barrel, we find that, depending on the size of the basin, a large volume of oil can be left stranded due to the nature of the fiscal terms.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.17

Table 7.3 – Oil volumes not developed / stranded due to Government Take

Assumptions made Oil price = US$ Oil price = US$ 18 per barrel 28 per barrel Basin has 50 fields Number of fields undeveloped 2 ------Oil stranded (MMbbls) 25.80 ------% of total discoveries in the basin 4.00 % ------% of total volume of oil in the basin 5.16 % ------

Basin has 100 fields Number of fields undeveloped 6 1 Oil stranded (MMbbls) 79.80 5.15 % of total discoveries in the basin 6.00 % 1.00 % % of total volume of oil in the basin 15.96 % 1.03 %

Basin has 500 fields Number of fields undeveloped 27 5 Oil stranded (MMbbls) 349.45 29.55 % of total discoveries in the basin 5.40 % 1.00 % % of total volume of oil in the basin 69.89 % 5.91 %

7.5. Summary and conclusions

In this chapter, I analyse the economic effects of the NELP fiscal terms on field development in the Krishna Godavari Basin. For the purpose of conducting this study, I assume notionally that the basin might contain either 50, 100 or 500 fields.

Among the various components of Government Take, royalty has the most influence on economics of marginal fields. In larger sized fields, Government share of profit oil is most influential.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 7.18

The analysis conducted shows a pattern that indicates that the NELP terms are regressive for marginal field developments. The range of field sizes rendered uneconomic by the fiscal terms increases as the oil price falls and royalties have the biggest influence in determining economic field sizes.

The volume of oil left stranded increases as the size of the basin increases and, depending on the level of oil prices, I conclude that significant volumes of oil could remain undeveloped due to the nature of the fiscal terms.

Sajith Venugopal July 2005 University of New South Wales

Chapter 8

Economics of Ravva oil and gas development

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.1

8.1 Introduction

This chapter discusses the economics of Ravva field development, which is part of the Ravva production sharing contract (PSC). The PSC is located offshore the east coast of India in the Krishna Godavari Basin about 400 kilometres (“km”) north of Chennai (see Figure 8.1). The total contract area is 331 square kilometres and the water depth in the area is about 20 meters. Ravva produces both oil and gas. The gas production consists of gas associated with oil production plus gas from a separate satellite field in the south west of the contract area.

Oil production from Ravva started in 1994 and the associated gas was first produced in 1998. In 2002, non-associated gas production from the satellite field began.

Ravva crude oil is sold to a Hindustan Petroleum Corporation Ltd (HPCL) refinery located to the north at Vizag. Gas not required for platform power supply is sold to Gas Authority of India Ltd (GAIL).

Figure 8.1 – Location map

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.2

As shown in Figure 8.2, there are 7 unmanned platforms on the field (named "R-A" to "R-G"). Production is achieved using 14 oil producers, 5 gas producers and 6 water injectors. Oil and gas produced is piped to shore and treated in a dedicated processing and storage facility plant at Surasaniyanam. This onshore facility is capable of handling crude in excess of 50,000 barrels per day.

The stabilised crude is piped to an offshore loading facility located approximately 15 kilometres from the shore. The loading facility consists of a Single Point Mooring ("SPM") capable of handling shuttle tankers with capacity of up to 650,000 barrels. The shuttle tankers transport Ravva crude oil to HPCL's refinery at Vizag.

Figure 8.2 – Ravva facilities

The Oil and Natural Gas Corporation Ltd (ONGC) discovered Ravva in 1987 and subsequently carried out the initial appraisal and development work. In 1992, The Government of India decided to invite tenders for joint development and production. Videocon Petroleum Limited (VPL) and Command Petroleum (India) Pty Ltd (“Command Petroleum”) put forward initial bids and development proposals. In March Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.3

1994, Ravva Oil (Singapore) PTE Ltd (Marubeni) joined VPL and Command Petroleum in their bid.

The Command Petroleum consortium was successful in its bid and, in October 1994, the joint venture parties signed a Production Sharing Contract (“PSC”) for the joint development and production of oil and gas from Ravva. The parties paid a signature bonus of US$ 12.5 MM to ONGC.

As a result of the takeover of Command Petroleum Ltd of Australia in 1996 by Cairn Energy PLC, Cairn Energy India Ltd (“Cairn”) took over Command Petroleum’s participating interest in the field and operatorship of the joint venture.

Since 1996, participating interests in the Ravva development have been as shown in Table 8.1.

Table 8.1 – Participating interests

Oil and Natural Gas Corporation Ltd. (ONGC) 40.0% Videocon Petroleum Ltd. (VPL) 25.0% Cairn Energy India Ltd. (Cairn) 22.5% Ravva Oil (Singapore) PTE Ltd. (Marubeni) 12.5%

8.2 Assumptions

The assumptions made for economic analyses are as follows

8.2.1 Participating interest

All economic analyses have been carried out for a 100% participating interest.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.4

8.2.2 Past oil prices, production and revenues

I do not have data on the annual oil price or annual revenue received from Ravva oil sales to the present day. However, it is possible to estimate past annual gross revenues from limited published data on oil prices and oil production. This is shown in the following analysis.

Table 8.2 shows the published annual average price of Brent crude from 1994 to 2003 (reference 37) and the published annual production of oil from Ravva over the same period (reference 38). If I assume that the price of Ravva crude oil was 91% of the Brent price over that period, then the total revenue from crude sales was US$ 2,518.56 MM and the average price was US$ 21.44 per barrel (US$ 2,518.56 divided by 118.71 MMbbl). The latter corresponds to the published actual average price received for Ravva oil as given in reference (39). Therefore, I deduce that the annual revenue calculated in Table 8.2 is a reasonable estimate of the actual revenue received for Ravva oil from 1994 to 2003.

Table 8.2 – Estimates of past average annual prices for Ravva Oil

Brent price Ravva price Oil Produced Revenue (US$/bbl) (US$/bbl) (MMbbl) (US$MM) Year (published) (calculated) (published) (calculated)

1994 15.82 14.34 1.24 17.78 1995 17.02 15.43 1.06 16.36 1996 20.67 18.74 2.54 47.60 1997 19.09 17.31 12.63 218.57 1998 12.72 11.53 9.76 112.55 1999 17.97 16.29 18.02 293.56 2000 28.50 25.84 17.81 460.15 2001 24.44 22.16 17.34 384.19 2002 25.02 22.68 18.80 426.42 2003 30.61 28.00 19.51 541.39 Total 118.71 2,518.56

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.5

8.2.3 Past costs

The joint venture parties agreed to reimburse ONGC for costs incurred before the PSC was signed (past costs). The total cost incurred by ONGC in the Ravva PSC area on appraisal and development work before the PSC was signed in 1994 was approximately US$ 50MM.

8.2.4 Past and future gas prices

The associated gas from Ravva was contracted for sale from 1997 at US$ 2.47 per giga joule (“GJ”). The satellite gas was contracted for sale from 2002 at US$ 3.13 per GJ. The prices of associated and non-associated gas produced are based on information contained in reference (39).

Before 2004, I use the prices quoted above for associated and satellite gas sales. From 2004, I use escalated prices for all gas sold. I escalate associated gas and satellite gas prices at 3% per year from fiscal 2004 onwards.

8.2.5 Future oil prices

I assume that the oil prices escalate at 3% per year and that the escalation begins in year 2004. The oil price assumed for fiscal year 2004 is US$ 28.00/bbl (refer to Appendix D).

8.2.6 Future production

I have assumed that Ravva oil production is 50,000 barrels of oil per day in fiscal year 2004 as shown in Table 8.2. I do not have operator forecasts of Ravva production for later years. In the absence of this data, I assume that oil and associated gas production will decline at 15% per year after 2004. The resulting production profile is shown in Figure 8.3.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.6

Figure 8.3 – Oil production profile

60 55 Actual Forecast 50 45 40 35 30 25 20 15

10 Thousand barrels per day (kopd) Year 5 0 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018

The production profile for associated gas is as shown in Figure 8.4. As stated earlier, I assume actual production data for years before 2004 (reference 38). For years after 2004, I assume the associated gas production to decline at 15% per year.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.7

Figure 8.4 – Associated gas production profile

16

Actual Forecast 14

12

10

8

6 Gas Produced (Bcf)

4

2 Year

0 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

The production profile for satellite gas is as shown in Figure 8.5. The production profile reflects the requirements of the Ravva gas contracts with GAIL (reference 38). Gas production from Ravva’s satellite field is on a plateau until 2007 after which I assume it will decline at a rate of 30% per year.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.8

Figure 8.5 – Non - associated gas production profile

14 Actual Forecast 12

10

8

6

4 Gas Produced (Bcf)

2 Year 0 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

8.2.7 Exploration and development costs

I have assumed all field exploration and development costs incurred before 2003 based on information contained in reference (40).

8.2.8 Operating costs

I have assumed operating costs between 1994 and 1998 based on information contained in reference (41). I have assumed the real operating costs from 1998 onwards to be 7% of the real total development costs. This is a rule of thumb typical of oil and gas industry assumptions when detailed operating cost data is not available.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.9

8.2.9 Abandonment costs

I assume that real abandonment costs are notionally 25% of total development costs. Given that the latter are US$ 315.70MM, real abandonment costs would be US$ 78.90MM. From base case analysis, field abandonment is likely to occur in the year 2023 and with escalation at 3% per year, the total nominal abandonment cost at that time would be US$ 85.40MM

8.2.10 Escalation

I assume that the oil, gas prices, field development capital and operating costs escalate at 3% per year and that escalation begins in year 2004. Before 2004, I use actual or estimated prices and costs. The 3% escalation assumption is typical of oil and gas industry escalation assumptions at the time of writing.

8.2.11 Discounting

I calculate nominal Net Present Value (“NPV”) using a nominal discount rate of 10%. I consider this to be typical of discount rates used by oil/gas companies internationally. I use end year discounting and I discount to the beginning of Ravva production sharing contract (October 1994).

8.2.12 Summary of assumptions

Table 8.3 summarises the field development assumptions made for all years of the Ravva project. All price and cost data from the year 2004 in Table 8.3 are unescalated or real values. Price and cost before that date are actual or estimated actual data.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.10

Table 8.3 - Summary of assumptions ($ amounts from year 2005 are in real terms) Assoc Assoc Sat Sat Oil Oil gas gas gas gas Expl Dev Op Aband prod price prod price prod price Costs Costs Costs Costs Year Kbopd US$/bbl MMcfd US$/GJ MMcfd US$/GJ US$MM US$MM US$MM US$MM Past 50.00 1994 3.40 14.34 11.50 1995 2.90 15.43 0.50 3.00 11.72 1996 7.50 18.74 5.00 80.00 11.92 1997 35.00 17.31 5.00 108.00 11.92 1998 27.00 11.53 24.00 2.47 25.00 30.00 22.10 1999 49.50 16.29 25.00 2.47 15.00 15.00 22.10 2000 48.80 25.84 24.49 2.47 5.00 0.50 22.10 2001 47.50 22.16 34.41 2.47 5.00 34.00 22.10 2002 51.50 22.68 37.80 2.47 31.62 3.13 12.00 45.00 22.10 2003 53.46 28.00 42.38 2.47 31.62 3.13 0.30 22.10 2004 50.00 28.00 39.64 2.47 31.62 3.13 22.10 2005 42.50 28.00 33.69 2.47 31.62 3.13 22.10 2006 36.13 28.00 28.64 2.47 31.62 3.13 22.10 2007 30.71 28.00 24.34 2.47 31.62 3.13 22.10 2008 26.10 28.00 20.69 2.47 22.13 3.13 22.10 2009 22.19 28.00 17.59 2.47 15.49 3.13 22.10 2010 18.86 28.00 14.95 2.47 10.84 3.13 22.10 2011 16.03 28.00 12.71 2.47 7.59 3.13 22.10 2012 13.62 28.00 10.80 2.47 5.31 3.13 22.10 2013 11.58 28.00 9.18 2.47 3.72 3.13 22.10 2014 9.84 28.00 7.80 2.47 2.60 3.13 22.10 2015 8.37 28.00 6.63 2.47 1.82 3.13 22.10 2016 7.11 28.00 5.64 2.47 1.28 3.13 22.10 2017 6.05 28.00 4.79 2.47 0.89 3.13 22.10 2018 5.14 28.00 4.07 2.47 0.63 3.13 22.10 2019 4.37 28.00 3.46 2.47 0.44 3.13 22.10 2020 3.71 28.00 2.94 2.47 0.31 3.13 22.10 2021 3.16 28.00 2.50 2.47 0.21 3.13 22.10 2022 2.68 28.00 2.13 2.47 0.15 3.13 22.10 2023 2.28 28.00 1.81 2.47 0.11 3.13 22.10 78.90

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.11

The estimated real abandonment costs are given in Table 8.3. Details of the abandonment cost sinking fund spending are described in section 8.3.6 of this report.

8.3 PSC terms

The Ravva PSC terms are summarised in the following.

8.3.1 Contract period

The Ravva Production Sharing Contract (“PSC”) is in force for a period of 25 years up to the year 2018. The Ravva PSC terms give the contractor an option to extend the PSC term by 5 fiscal years. I have assumed that the consortium will exercise their option to extend the PSC by 5 fiscal years to 2023.

8.3.2 Compensation for import waiver

The PSC includes a provision that the Government receives a share of production as compensation for waiving import duties on equipment and other supplies. The government’s compensation for the waiver is as shown in Table 8.4.

Table 8.4 – Compensation paid to Government

Contract Year Barrels of Oil 3 200,000 4 150,000 5 100,000 6 50,000 Total 500,000

8.3.3 Production payments

The Ravva PSC requires production payments to be made to ONGC according to the schedule shown in Table 8.5.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.12

Table 8.5 – Production payments to ONGC

Cumulative Production Incremental Payments (MMbbl) (US$ MM) 25 9.0 50 9.0 75 9.0 80 1.8 85 1.8 90 1.8 95 1.8 100 1.8

The Ravva PSC also requires that after cumulative production of crude oil reaches 100 MMbbl, the production payment to ONGC is to be agreed by the parties, but is not to exceed US$1.8 million for every 5 MMbbl increment in production. The joint venture reached cumulative production thresholds and made production payments as shown in Table 8.6.

Table 8.6 – Past production payments

Cumulative production Year (MMbbl) 1998 25 2000 50 2001 80 2003 100

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.13

8.3.4 Cess and Royalty

Cess (a special tax in India) and state royalties are levied on all oil produced. For the Ravva PSC, Cess is Rupees 900 per tonne of crude oil produced and the state royalty is Rupees 481 per tonne of crude oil produced. The total (Rupees 1,381) is equivalent to US$ 4.5 per barrel assuming an exchange rate of 1US$ = 41.6 Rupees (which is the average US$-Rupee exchange rate between 1994 and 2003).

No cess applies to gas production.

The royalty on gas produced is 10% of the well-head value. The PSC does not set out in detail how well-head value is to be determined. However, well-head value is gross revenue less the cost of transport and treatment. As a first approximation, I assume that the costs of transport and treatment are approximately 20% of gross revenue and therefore that well-head value is 80% of gross revenue.

8.3.5 Cost Petroleum

Recoverable costs include all exploration, development and operating costs incurred within the boundaries of the PSC and all production payments made during field life. These costs are recoverable from project revenue after cess and royalty have been deducted. Other expenses incurred by the consortium members include the compensation for import waiver. These are not recoverable. The total of costs recovered is “Cost Petroleum”. Any cost not recovered in a particular year is carried forward for recovery in the following year.

8.3.6 Abandonment sinking fund

The Ravva PSC requires the contractors to contribute regularly to a site restoration fund so that sufficient funds are available the abandon the development at the end of its life. I refer to this as an abandonment sinking fund. Contributions are fully cost recoverable. The PSC does not stipulate how the sinking fund is to be calculated. I assume that annual contributions to the fund are made based on units of production calculation similar to a depletion allowance calculation typically used in oil and gas company accounts. That means that money is put aside in proportion to the rate at which Ravva’s reserves are produced. See Appendix E for details of the calculation.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.14

8.3.7 Profit Petroleum

The revenue remaining after Cost Petroleum is "Profit Petroleum". Profit petroleum is shared between the government and the consortium based on the Post Tax Rate of Return (“PTRR”) as shown in Table 8.7.

Table 8.7 – Profit sharing

Government share of profit Contractor share of profit PTRR this year petroleum next year petroleum next year 0% to 15% 10% 90% > 15% to 20% 15% 85% > 20% to 25% 20% 80% > 25% to 30% 25% 75% > 30% to 40% 35% 65% > 45% 60% 40%

The PTRR mechanism is a feature of a number of PSCs in India. However, unlike most other Indian PSCs, the mechanism in the Ravva PSC regime has a ratchet effect. This refers to the fact that the Government's share of Profit Petroleum cannot decrease once it has reached a particular level. I discuss this characteristic of the Ravva PSC in more detail in a later section.

As stated earlier, the sharing of profit petroleum between the Government and consortium members is based on the Post Tax Rate of Return (“PTRR”) calculation. Proportions of profit split vary depending on the consortiums’ after tax net cash flow.

For the purpose of generating an after tax net cash flow, the “notional” income tax is calculated. Notional income tax in any one year is taken as the maximum of “Normal” tax and “Minimum Alternative Tax” (“MAT”) for that particular year.

For PTRR calculations, I have assumed the notional tax rate to be weighted average tax of all companies forming the consortium. Depreciation is based on a declining balance calculation with a balloon payment in the final year of production. I assume a Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.15 depreciation rate of 20% for all development costs. This is a simplification. In practice, different depreciation rates apply to different items of equipment.

The way in which notional tax is calculated for the PTRR has been the subject of disagreement between the government and the contractors. The disagreement centers on whether the net cash flow for PTRR should be that of the consortium or that of the individual contractors. The sensitivity section of this chapter discusses how sharing of profit petroleum would be affected if the net cash flow of individual parties that form the consortium was considered as the basis for PTRR calculation.

Given below are details of how Normal tax and MAT are computed.

Computation 1

An initial calculation of notional tax is made as shown in Table 8.8

Table 8.8 – Initial Notional Tax calculation

Revenue to Consortium (A) Consortiums’ expenditures (B) Cost recovery Operating costs Profit petroleum Exploration costs Depreciation of development costs Abandonment costs Tax losses from previous years A less B multiplied by “Weighted average tax rate” equals notional tax

For the first 7 years of commercial production, there is a tax holiday for notional income tax.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.16

Computation 2

Notional Minimum Alternative Tax (“MAT”) is calculated differently for time periods between (April 1997 up to March 2000) and (March 2000 to present day). Table 8.9 provides details on calculation of Minimum Alternative Tax (“MAT”).

Table 8.9 – Minimum Alternative Tax calculation

MAT from April 1997 up to March 2000 MAT from March 2000 to present day A less B (from Table 8.8 above) A less B (from Table 8.8 above) multiplied by multiplied by (30%) (7.5%) multiplied by equals (Weighted average tax rate) MAT equals MAT

PTRR and Profit Sharing

Having determined the “notional” income tax, the PTRR is calculated by compounding the consortiums’ after tax net cash flow at different rates. The compounding rates used for this accumulation are the upper and lower limits of the PTRR tranches given in Table 8.7 above.

If the after tax net cash flow turns positive for any compound rates between 0% and 15%, the profit petroleum share to the government in the succeeding year would be 10%. If the after tax net cash flow turns positive for any compound rates between 20% and 25% and also for compound rates between 25% and 30%, then the percentage of profit petroleum to the government climbs to the next level. That is, the percentage of profit petroleum to the government would now be 25% and not 20%.

Table 8.10 gives an illustration of PTRR calculation (numbers are in US$MM and are purely illustrative).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.17

Table 8.10 – Illustration of PTRR calculation

Fiscal years Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8

Consortiums’ after tax net -30 5 30 8 10 20 20 20 cash flow

Cumulative net cash flow compounded at 0% -30.0 -25.0 5.0 13.0 23.0 43.0 63.0 83.0 15% -30.0 -29.5 -3.9 3.5 14.0 36.1 61.5 90.8 20% -30.0 -31.0 -7.2 -0.6 9.2 31.1 57.3 88.8 25% -30.0 -32.5 -10.6 -5.3 3.4 24.2 50.3 82.9 30% -30.0 -34.0 -14.2 -10.5 -3.6 15.3 39.9 71.9 40% -30.0 -37.0 -21.8 -22.5 -21.5 -10.1 5.8 28.1

Government’s share of 0% 0% 0% 10% 15% 25% 35% 60% profit petroleum next year

8.3.8 Income Tax

Income tax calculations occur in two places – a) to calculate PTRR, in which case it is a "notional" tax calculation (see above). b) to calculate actual tax paid by the consortium members.

The method by which income tax is calculated is the same for both notional and actual tax. However, the income and costs used in each case differ.

The chapter on Indian fiscal terms gives details of how income tax is calculated for petroleum development in India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.18

The actual tax paid by consortium members is a company tax based on company costs and revenues. However, for the economic analyses for this report, I calculate the actual tax on a project basis, assuming that the only asset held by the company is the Ravva development. This is a typical assumption made in oil and gas industry economic project evaluations.

8.4 Results.

The results of base case of the economics of the Ravva development are given in Table 8.11.

Table 8.11 – Results for base case.

Reserves Hydrocarbon reserves 279.05 MMboe Oil reserves 236.15 MMbbl Gas reserves 257.45 Bcf

Economic Indicators As at 1 Jan 1994 As at 1 Jan 2005 Nominal NPV at 10% US$ 482.85 MM US$ 463.41 MM Internal rate of return (IRR) 37.62 % Not applicable Capital productivity index (CPI) 0.85 1.66 Pay back period 7.08 years Not applicable Footnote – Reserves are cumulative production over economic life

The reserves estimates above would be close to proven plus probable reserves. SPE definitions of reserves are given in Appendix F.

I report total hydrocarbon reserves by converting gas into oil equivalent using the conversion factors set out in Appendix B. Appendix G contains definitions of economic indicators that are listed in Table 8.11 above. I use year-end discounting for deriving the nominal NPV. In Table 8.11, I have discounted to January 1994 and January 2005.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.19

When discounting to January 2005, the IRR cannot be calculated because we only have a positive net cash flow from year 2005.

The pay back period as at January 2005 cannot be defined. This is because, by year 2005, the consortium members have recovered all costs and expenditures that would have made the net cash flow turn negative. From year 2005 the project cash flow is positive (as shown in Figure 8.6 below).

8.4.1 Net cash flow

Figure 8.6 plots the yearly net cash flows of Ravva field against time. Figure 8.6 shows that before take net cash flow (BTNCF) is at a maximum in the year 2003, whereas the contractors’ after take net cash flow (ATNCF) is at a maximum in the year 2000. This is because of the effect of Government take on the project. A further analysis of the impact of the components of Government take is given later.

Figure 8.6 – Net cash flow against time

530

440

Before Take Net 350 Cash Flow

260

After Take Net 170 Cash Flow

80 yearlyConsortiums' (US$MM) cash net Year

-10 1994 1997 2000 2003 2006 2009 2012 2015 2018 2021

-100

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.20

8.4.2 Components of Government take

During the initial three years of production, Government take from the project are from production payments and royalty. Income tax does not come into effect until the project starts to make profit. It begins in 1997 and continues till the end of the project. The share of profit petroleum to the Government starts in 2001. This is because it is, in effect, based on net cash flow rather than profit. Even though profit sharing starts later than the other components, it yields the most revenue to the Government over the life of the project.

Figure 8.7 shows the effect the different components of Government take have on the project.

Figure 8.7 – Components of Government Take

400

350 Signature Bonus & Production Payment 300 Royalty 250

200 Income Tax 150 Share of Profit Petroleum 100

50 Paid to Government consortium by (US$MM) Year 0 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022

The total undiscounted Government take is US$ 4,396.90MM and represents 73.83% of project net cash flow.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.21

8.4.3 Sensitivities and uncertainties

In this section I investigate how changes to field development assumptions affect the value of the project. My analyses are illustrated in the form of a spider diagram.

In a later section, I also discuss the effect of the Ravva PSC terms on the economics of the project. I show the effects of opposing positions in the arbitration case heard in 2004. Finally, I carry out Monte Carlo simulation analyses to show the effects of project uncertainties on the profitability of the project.

8.4.3.1 Spider diagram

Figure 8.8 shows the effect of changes in assumptions on the value of the Ravva project. The effect of the following assumptions are examined xProduction decline rates. xOil price. xDevelopment costs. xOperating costs.

The value of the Ravva project is robust to the changes in assumptions considered. That is, the NPV remains positive in all cases.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.22

Figure 8.8 – Spider diagram

550

Decline rate after peak Oil price Operating cost 500

Development cost 450 Development cost Operating cost NPV (US$MM) at 1994

400

Oil price Decline rate after peak

350 60% 70% 80% 90% 100% 110% 120% 130% 140% Percentage Variation in parameter

Decline rate

When the production decline rate is 25% per year from 2004 (compared to 15% per year for the base case), the NPV of the project drops to US$ 419.12MM. The reduction in value occurs because the economic life of project falls to 22 years from the base case value of 30 years. There is a corresponding fall in reserves to 226.43 MMboe as compared to 279.05 MMboe in base case.

When the production decline rate is 10% per year from 2004 (as compared to 15% for the base case), the NPV of the project increases to US$ 545.95MM. This increase occurs because the economic life of the project increases to 40 years (beyond the life of the PSC). There is a corresponding increase in reserves to 344.52 MMboe.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.23

Oil price

The prices of oil and gas affect the revenue generated by the project. In the years from 1998, crude oil prices have varied between US$10 and over US$50 per barrel. The sensitivity tests carried out here assume a range of US$10 to US$50 per barrel. See Appendix D for a discussion of the oil price assumption.

Figure 8.8 shows that the value of the project increases with increases in the oil price. This is the result not only of an increase in revenues each year, but also of increase in reserves. Increases in oil price tend to lengthen field life and thereby enhance hydrocarbon recoveries.

Development cost

The nature of the PTRR regime is that it encourages expenditures early in project life. Early expenditure reduces early net cash flow for the PTRR calculation and the compounded effect of this can be to delay Government shares of profit petroleum moving to higher tranches. The PTRR mechanism can give rise to economic results that are counter-intuitive. This is illustrated in Figure 8.8 where increases in development costs can in some cases result in increases (rather than decreases) in NPV and vice- versa. Such anomalies arise when the PTRR calculation causes changes in the timing of and/or the level of the Government share of profit oil.

Figure 8.8 shows that a 30% increase in total development cost results in an increase in NPV of the project to US$ 513.63MM from US$ 482.85MM in the base case. This increase in NPV is a result of a delay in the time when the government’s share of profit petroleum becomes 60% (the maximum) from 2004 to 2006.

A 30% decrease in development costs reduces NPV of the project to US$ 472.46MM. Here, the year in which government’s achieves its maximum share of profit petroleum is brought forward by two years to 2002.

The effect of changing development costs is analysed in more detail in a later section.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.24

Operating costs

A 30% decrease in operating costs increases the NPV from US$ 482.85MM to US$ 501.41MM. The reduction in operating costs increases net cash flow in all years. However, in addition, the economic life of the project lengthens to 32 years (as compared to 30 years under base case). There is a consequent increase in reserves to 280.54 MMboe as compared to 279.05 MMboe in base case.

Increasing operating costs to 130% of the base case value decreases NPV of the project to US$ 473.98MM. The decrease in value is the result of decreases in net cash flow and a shorter economic life (28 years compared to 30 years in the base case). With higher operating costs, the reserves fall to 276.99 MMboe as compared to 279.05 MMboe in base case.

Based on discussions made above, it could be concluded that the value of Ravva project is most sensitive to the decline rate and least sensitive to operating costs. We can also conclude that the fiscal terms cause counter-intuitive sensitivities to capital costs.

8.4.3.2 PTTR effects – changing front-end development costs

As discussed earlier, investments made during early stages of the project have a large bearing on the Government's share of profit petroleum in the future.

Figure 8.9 shows how changes in development costs made before 2004 could have affected the government’s share of profit petroleum.

For the base case, the government’s share of profit oil increases to 60% in 2004. However, had the consortium made a 10% increase in development investment in all years before 2004, the government’s share of profit oil would not move to 60% until 2005 and the NPV of the project would have increased to US$ 501.50MM.

A 60% increase in development cost investment (before 2004) would have ensured that the share of profit petroleum to the government never rises above 35%.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.25

Figure 8.9 – Effect of development cost on profit petroleum

70%

65%

60% Original development cost 55%

50%

45% Increase in development cost by 10% 40%

35%

30% Increase in development cost by 60% 25%

20%

15%

10% Government's share of share Government's this petroleum profit year 5% Year 0% 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

It is not within the scope of this report to speculate on alternative investment decisions that the consortium may have made in the early years of the project. However, it is the nature of rate of return PSCs like the Ravva PSC that early investment can have a significant effect on the contractors' economics.

8.4.3.3 PTTR effects – changing mid-field life costs

One of the features of the Ravva PSC is that the Government's share of profit petroleum cannot go down once it has reached a certain level (the so-called ratchet effect). Figure 8.10 shows the consequence of this for the Ravva project when changes are made to development or operating costs later in field life.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.26

Under the PTRR mechanism, the Government’s share of profit petroleum is linked to the cumulative compounded net cash flow of the project. Therefore, if the consortium were to make investments in future years, without a ratchet effect there would be a corresponding drop in Government’s profit share. Instead, Figure 8.10 shows that the Government’s share of profit petroleum continues to follow the maximum tranche value it had reached in the previous year (ratchet effect).

Figure 8.10 – Government’s share of profit petroleum

70%

65%

60%

55% Ratchet effect 50%

45%

40%

35% No ratchet effect

30%

25%

20%

15%

10% Government's share of profit petroleum next year 5% Year 0% 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Under Ravva PSC, the only means by which the profit share of the government could drop is when future investments cause the net cumulative cash flow of the project to turn negative. Hence, the Ravva PSC discourages small investments later in field life.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.27

8.4.3.4 Arbitration

An arbitration case involving Cairn, Marubeni (the foreign companies in the consortium) and Government of India began in 2002. The issues disputed were related to the PTRR regime. For the purpose of conducting this study, I analyse the key items of dispute in isolation. The most important relates to “ONGC Carry” and the calculation of tax for PTRR (reference 42).

ONGC carry costs

The inclusion of “ONGC Carry” costs in cost recovery calculations would mean a lower PTRR net cash flow for the consortium and a corresponding delay in the year in which share of profit petroleum to the Government becomes 60%. The Government of India’s stand in the arbitration case was that ONGC Carry costs are to be excluded from cost recovery calculations.

ONGC Carry costs are costs, paid by the contractors other than ONGC until ONGC has been repaid its 40% share of past costs. ONGC Carry costs include 40% of the past costs that ONGC incurred from 1994, when development of Ravva field began, until the beginning of the Ravva contract.

Cairn and Marubeni were of the opinion that, since ONGC Carry costs are actual expenditures made by companies, they should therefore be included in the net cash flow for PTRR calculations.

The exclusion of ONGC Carry costs from net cash flow calculations increases the net cash flow of the consortium during the early years of the project. This leads to a higher share of profit petroleum to the government later in project life. This is illustrated in Figure 8.11.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.28

Figure 8.11 – Profit petroleum based on “ONGC Carry costs”

70%

65% Profit sharing when ONGC carry costs are excluded from PTRR calculations 60%

55%

50%

45%

40%

35% Profit sharing when ONGC carry costs are included in PTRR calculations 30%

25%

20%

15%

10% Government's share of profit petroleum profit of share Government's this year 5% Year 0% 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Figure 8.11 illustrates why the government opposes to the inclusion of “ONGC Carry” costs in PTRR calculations. When ONGC Carry costs are included in PTRR calculations the share of profit petroleum to the Government reaches 60% in year 2007. In contrast, when ONGC Carry costs are excluded, the Government reaches 60% profit sharing in 2004.

Tax calculation for PTRR

Another area of dispute is the definition of net cash flow when computing profit shares. The net cash flow used for PTRR includes notional tax.

Foreign companies have a higher tax rate than Indian companies and therefore would have a lower net cash flow for PTRR after notional tax than if the total consortium net cash flow was used. Therefore, if the PTRR calculation were to be based on Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.29 individual company net cash flow, then foreign companies would have a higher share of profit petroleum. For these reasons, Cairn and Marubeni’s stand in the arbitration case is that individual company net cash flows should be used for PTRR calculations.

Cairn and Marubeni’s claims are on the basis that, being foreign companies in India, they continue to pay higher taxes than the Indian companies involved.

Table 8.12 below gives the tax rates applicable to domestic/foreign companies. The weighted average tax rate is computed considering the individual participating interests of the companies that form the consortium.

Table 8.12 – Tax rates of foreign/domestic companies

Domestic company Foreign company Weighted average Year tax rate tax rate tax rate 1992-93 50.00% 50.00% 50.00% 1993-94 50.00% 50.00% 50.00% 1994-95 46.00% 50.00% 47.40% 1995-96 46.00% 50.00% 47.40% 1996-97 43.00% 50.00% 45.45% 1997-98 35.00% 48.00% 39.55% 1998-99 35.00% 48.00% 39.55% 1999-2000 38.50% 48.00% 41.83% 2000-01 39.55% 48.00% 42.51% 2001-02 35.70% 48.00% 40.00% 2002-03 36.75% 42.00% 38.59% 2003-04 35.88% 41.00% 37.67%

The Governments’ stand in the arbitration case is that they had signed the PSC with consortium and not with the individual parties that form the consortium. Therefore, the notional tax should be based on composite notional tax.

Figure 8.12 below shows profit petroleum payments to the government when individual company net cash flow and the consortiums (combined) net cash flow are considered.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.30

Figure 8.12 – Profit petroleum based on company net cash flow

70%

65%

60%

55% ONGC NCF 50%

45% Cairn NCF

40%

35% Consortium NCF 30%

25%

20%

15%

10% Government's share of profit petroleum this year this petroleum profit of share Government's 5% Year 0% 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

As shown in the Figure 8.12 above, with PTRR based on foreign company tax rates, the Government's share of profit petroleum reaches 60% in 2005. This is in contrast to the base case result, in which notional tax is based on the weighted average tax rate of the consortium, the Government's share of profit petroleum reaches 60% in 2004.

Figure 8.12, shows that ONGC would have had to pay 60% of profit petroleum to the government as early as year 2002. This is because ONGC pays less tax (as compared to Cairn or Marubeni) and therefore, has higher net cash revenue during the early stages of the project.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.31

8.4.3.5 Monte Carlo Simulation

In addition to the sensitivity analyses described above, I have examined the effect of price, production and cost uncertainties on the value of the Ravva project. I have carried out a Monte Carlo analysis to examine the effect of uncertainties in key assumptions. The Monte Carlo analysis carried out examines uncertainties based on analyses as at the beginning of the PSC.

I assume that price uncertainties to follow a lognormal probability curve. I choose the lognormal distribution because history shows that oil prices have a tendency to be skewed. However, the most likely price is towards the lower end of the range. Refer to Appendix D.

I assume cost uncertainties to follow normal probability distribution. I expect all costs to be equally as likely to be above as below by central estimate. Since cost uncertainties are assumed to be symmetrical, I assume a normal probability distribution to be the most appropriate.

I also assume all uncertainties linked to production to follow a lognormal distribution.

Oil price

I assume that uncertainty in the oil price follows lognormal probability distribution with the 10th percentile being US$ 25 per barrel and the 90th percentile being US$ 50 per barrel.

Associated gas price

I assume that uncertainty in the associated gas price follows a lognormal probability distribution with the 10th percentile being US$ 2.15 per gigajoule (GJ) and the 90th percentile being US$ 2.80 per GJ.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.32

Non-associated gas price

I assume that uncertainty in the non-associated gas price follows a lognormal probability distribution with the 10th percentile being US$ 2.80 per GJ and the 90th percentile being US$ 3.70 per GJ.

Development cost

I assume that uncertainty in development costs follows a normal probability distribution with the 10th percentile being 70% of base case estimate of US$ 315.70MM and the 90th percentile being 130% of base case estimate.

Production decline rate

I assume that uncertainty in development costs follows a lognormal probability distribution with the 10th percentile being 75% decline in production per year and the 90th percentile being 90% decline in production per year.

Figure 8.13 shows the resulting probability distribution of the NPV of Ravva project when the uncertainties described above are applied in a Monte Carlo simulation.

Figure 8.13 – Ravva NPV frequency distribution

20%

18%

16%

14%

12%

10%

8%

6%

4%

Probability (%) NPV (US$ MM) 2% 200 300 400 500 600 700 800 900 1000 1100 1200 1300

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.33

Figure 8.14 show the cumulative probability corresponding to the results given in Figure 8.13. It compares the base case value (US$ 482.85MM) against the results obtained from Monte Carlo analyses. Figure 8.14 shows that the present value (PV) of Ravva development is never negative. It was a very robust project as seen from the beginning of the PSC.

Figure 8.14 – Cumulative probability against NPV

100%

90% Standard Deviation = 171.95

80% P 90 = US$ 753.77 MM

70% Mean = US$ 528.70 MM 60% Base case estimate = US$ 482.85 MM 50%

40% P 50 = US$ 479.13 MM 30%

20% P 10 = US$ 367.06 MM 10%

Cumulative probability (%) NPV (US$MM)

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600

8.5 Summary and conclusions

In this chapter, I analyse the workings of the Ravva PSC.

The Ravva field has a NPV of US$ 482.85MM as at the beginning of the PSC and US$ 463.41MM as at January 2005 (the time of writing).

From sensitivity analyses, I conclude that the value of Ravva project is most sensitive to the rate of decline in oil production and least sensitive to the operating costs. However, the NPV remains positive in all cases analysed. Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 8.34

I forecast that the Government's share of profit petroleum will reach its highest 60% from fiscal year 2004 and will remain at this level for the remainder of project life. Sensitivity analyses revealed that changing front-end costs (development) had a significant effect on the timing and level of the Government's share of profit.

Monte Carlo analyses confirms that the NPV of Ravva field is never negative given my view of the uncertainties. Based on this, I conclude that as viewed from the beginning of the PSC, the Ravva development was a highly profitable, low-risk project.

Sajith Venugopal July 2005 University of New South Wales

Chapter 9

Economics of D-1 South oil development.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.1

9.1 Introduction

This section of the chapter discusses the economics of D-1 South field development, which is part of the D-1 production sharing contract (“PSC”). D-1 South is an offshore oil field with small quantities of associated gas. The field is located offshore the western coastline of India in Mumbai Offshore Basin. It is located at a water depth of 80-90 meters (“m”) and has a total area of 255 square kilometers (“sq.km”). The field comprises of two culminations – North and South. The south culmination is believed to hold majority of the oil.

Figure 9.1 - Location map

D-1 field was discovered by ONGC in 1976. However, the field was not economically viable and remained undeveloped because the oil prices were administered under the Administered Pricing Mechanism (“APM”). In April 2002, the Government decontrolled the APM. Post APM, ONGC has begun efforts to begin production and monetise D-1 field.

A total of ten exploratory wells have been drilled at D-1 South. It is estimated that the South culmination of D-1 field has about 140 million barrels (“MMbbl”) of oil in place.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.2

ONGC plans to produce about 34 MMbbl over 10 years implying a recovery factor of 24%.

The development plan for D-1 field envisaged enhanced oil recovery using water injection. ONGC plans to install Electrical Submersible Pumps (“ESP”) right from production start for maintaining reservoir pressure and productivity. The plan is to develop the field in two phases. Phase 1 includes construction of a 12-slot single deck well and water injection platform (“WWIP”) and six wells – 3 producers and 3 water injectors. The WWIP is designed to accommodate the ESP package. Phase 2 of field development involves drilling six additional wells - 3 producers and 3 water injectors.

ONGC’s Sagar Laxmi jack-up platform is being modified to process oil from D-1 field. The 12 slot WWIP will be connected to Sagar Laxmi processing facility using a bridge. An 8-inch submarine pipeline of 1.5 kilometers (“km”) will also be laid to connect D-1 platform to a Single Point Mooring system (“SPM”). ONGC had earlier planned to repair an old SPM lying in adjacent D-18 field and relocate it to D-1 South. However, at the time of writing, it appears that ONGC plans to place a new SPM at D-1 South. Oil produced would be stored in a storage tanker from the SPM.

9.2 Assumptions

The assumptions made for economic analyses are set out below.

9.2.1 Oil prices

I assume that the oil price in fiscal year 2004 is US$ 28.00/bbl and that it escalates at 3% per year beginning in year 2005. Refer to Appendix D.

9.2.2 Future production

Figure 9.2 below, shows ONGC’s forecast of oil production from 2005 (production start). The production data is as given in ONGC’s report on D-1 field development (reference 43). There is also some marginal production of associated gas at D-1 field. ONGC plans to use this gas produced for the field’s power needs.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.3

Figure 9.2 – Oil production profile

6

5

4 Oil producedOil (MMbbl)

3

2

1

Year

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

9.2.3 Exploration costs

I do not have details on expenditures made by the operator for D-1 field exploration. However, based on exploration cost data from nearby fields, I have assumed an exploration well to cost US$ 5MM. Given the fact that, since ten exploratory wells have been drilled, I assume total exploration expenditure of US$ 50MM. Because I do not know when exploration expenditure was made, as a first approximation I assume that all exploration expenditures occur in fiscal year 2002.

9.2.4 Development costs

ONGC plans to develop D-1 field in two phases at a total expenditure of US$ 63.56MM. Phase 1 is scheduled to be completed by the end of fiscal 2005 at a cumulative expenditure of US$ 44.22MM. Phase 2 would start in fiscal 2007 and is planned to be completed by end of fiscal 2008 at a cumulative expenditure of US$ 19.34MM.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.4

Table 9.1 below gives details of field development cost. The data contained in Table 9.1 is as quoted by ONGC in its report on the D-1 field development (reference 43).

Table 9.1 – Development cost for D-1 field (US$MM)

Phase 1 Phase 2 Year 2003 2004 2005 2007 2008 Well platform 0.02 6.92 6.78 Sagar Laxmi modification 5.39 4.02 Single Point Mooring system 0.76 0.23 Pipeline 0.25 0.25 Drilling cost 8.23 10.24 8.23 10.24 Completion cost 0.23 0.23 Electrical Submersible Pump 0.64 0.64 package Environmental cost 0.13 Site investigation 0.13 Total 0.02 22.68 21.52 9.10 10.24

9.2.5 Operating costs

The operating costs for D-1 include costs for the operation and maintenance of Sagar Laxmi processing facility, the costs for water injection and processing, and the cost of hiring a storage tanker along with expenses for well maintenance and well work over.

Table 9.2 below gives details on the operating costs at D-1 field. The information given below is as quoted by ONGC in its report on the D-1 field development (reference 43).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.5

Table 9.2 – Operating costs for D-1 (in US$MM)

Water process & Well Sagar Water maintenance Work over Total Year Laxmi injection cost cost Tanker hire US$MM 2005 3.19 0.28 5.59 9.06 2006 3.19 0.29 0.28 5.59 9.35 2007 3.19 0.29 3.14 0.28 5.59 12.49 2008 3.19 0.29 0.28 5.59 9.35 2009 3.19 0.30 4.55 0.28 5.59 13.91 2010 3.19 0.55 0.56 5.59 9.89 2011 3.19 0.56 6.28 0.56 5.59 16.18 2012 3.19 0.56 0.56 5.59 9.90 2013 3.19 0.56 6.28 0.56 5.59 16.18 2014 3.19 0.56 5.59 9.34 Total 31.90 4.24 20.25 3.36 55.90 115.65

9.2.6 Abandonment costs

I assume that real abandonment costs are notionally 25% of total development costs. The latter are US$ 63.56MM and therefore real abandonment costs are assumed to be US$ 15.89MM. From the base case analysis (see below), field abandonment is likely to occur in year 2014 and the total nominal abandonment cost at that time would be US$ 21.36MM assuming escalation at 3% per year.

9.2.7 Escalation

I assume that the oil price, field development capital and operating costs will escalate at 3% per year and that escalation begins in year 2005. Before 2005, I use actual or estimated prices and costs. The 3% escalation assumption is typical of international oil and gas industry escalation assumptions at the time of writing.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.6

9.2.8 Discounting

I calculate nominal Net Present Value (“NPV”) using a nominal discount rate of 10%. I consider this to be typical of discount rates used by oil/gas companies internationally. I use end year discounting and discount to fiscal year 2002. I choose fiscal year 2002 because I assume that first expenditure for exploratory work was made in this year.

9.2.9 Summary of assumptions

Table 9.3 summarises the field development assumptions made for all years of the D-1 South project. All price and cost data from the year 2004 in Table 9.3 are unescalated or real values. Price and cost before that date are actual or estimated actual data.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.7

Table 9.3 - Summary of assumptions

Real Real Real Real Oil Oil Exploration Development Operating Abandonment production price Costs Costs Costs Costs Year MMbbl US$/bbl US$MM US$MM US$MM US$MM 2002 50.00 2003 0.02 2004 28.00 22.68 2005 2.75 28.00 21.52 9.06 2006 2.75 28.00 9.35 2007 2.75 28.00 9.10 12.49 2008 2.72 28.00 10.24 9.35 2009 5.02 28.00 13.91 2010 4.55 28.00 9.89 2011 4.10 28.00 16.18 2012 3.68 28.00 9.90 2013 3.26 28.00 16.18 2014 2.88 28.00 9.34 15.86 Total 34.46 50.00 63.56 115.65 15.86

The estimated real abandonment costs are given in Table 9.3. Details of the abandonment cost sinking fund spending are described in section 9.3.3 of this report.

9.3 PSC terms

The D-1 PSC terms are summarised in the following.

9.3.1 Cess and Royalty

Cess (a special tax in India) and state royalties are levied on all condensate produced. For the D-1 PSC, Cess is Rupees 1,800 per tonne of crude oil produced and the state royalty is Rupees 850 per tonne of oil produced. The total (Rupees 2,650) is equivalent to US$ 7.86 per barrel assuming an exchange rate of 1US$ = 46.00 Rupees.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.8

9.3.2 Cost Petroleum

Recoverable costs include all exploration, development and operating costs incurred within the boundaries of the PSC and all production payments made during field life. These costs are recoverable from project revenue after cess and royalty have been deducted. The total of costs recovered is “Cost Petroleum”. Any cost not recovered in a particular year is carried forward for recovery in the following year.

9.3.3 Abandonment sinking fund

The D-1 PSC requires the contractors to contribute regularly to a site restoration fund so that sufficient funds are available the abandon the development at the end of its life. I refer to this as an abandonment sinking fund. Contributions are fully cost recoverable. The PSC does not stipulate how the sinking fund is to be calculated. I assume that annual contributions to the fund are made based on units of production calculation similar to a depletion allowance calculation typically used in oil and gas company accounts. That means that money is put aside in proportion to the rate at which D-1’s reserves are produced. See Appendix E for details of the calculation.

9.3.4 Income Tax

The chapter on Indian fiscal terms gives details of how income tax is calculated for petroleum development in India. But, since D-1 field is not under New Exploration Licensing Policy (“NELP”) terms, the 7-year tax holiday does not apply to D-1 field.

The tax rate applied for calculation of normal tax is 35.88%.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.9

9.4 Results

The results of base case of the economics of the D-1 development are given in Table 9.4.

Table 9.4 – Results for base case.

Reserves Oil reserves 34.47 MMbbl

Economic Indicators As at 1 Jan 2002 As at 1 Jan 2005 Nominal NPV at 10% US$ 91.61 MM US$ 205.14 MM Internal rate of return (IRR) 26.49 % Not applicable Capital productivity index (CPI) 0.57 1.59 Pay back period 7.44 years Not applicable Footnote – Reserves listed are cumulative production over economic life

The reserves estimates above would be close to proven plus probable reserves. SPE definitions of reserves are given in Appendix F.

Appendix G contains definitions of economic indicators that are listed in Table 9.4 above.

I use year-end discounting for deriving the nominal NPV and have discounted to January 2002 and January 2005.

When discounting to January 2005, I only consider the net cash flow generated from year 2005 onwards. The NPV and CPI values increase because the date is closer to start of production and some costs become past costs.

The IRR cannot be calculated for net cash flow starting in 2005 because the net cash flow is positive from year 2005. The pay back period cannot be defined for net cash flow from 2005. This is because, in year 2005, the operator has recovered all costs

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.10 and expenditures that would have made the net cash flow turn negative. From year 2005 the project is cash flow positive (as shown in Figure 9.3 below).

9.4.1 Net cash flow

Figure 9.3 plots the yearly net cash flows of D-1 field against time. Figure 9.3 shows that both before take net cash flow (BTNCF) and the operator’s after take net cash flow (ATNCF) is at a maximum in the year 2009. Both cash flows are at a maximum in year 2009 corresponding to the year of peak in oil production.

Figure 9.3 – Net cash flow against time

160

140 Before Tax NCF 120

100

80

60

40 After Tax NCF

20

-20 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Operator's yearly nominal net cash (US$MM) -40 Year

-60

9.4.2 Components of Government Take

Government Take from the project is from royalty, cess and income tax. During the initial years, royalty and cess form bulk of the income to the Government. Income tax comes into effect when the project starts to make profit. Even though, the project starts to make profit right from production start, the profit is small and income tax at Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.11 this stage represents a small share of total Government Take. As the profit rises with increase in production, so does the income tax revenue to the Government.

In fiscal 2009, income tax revenue is at maximum, because peak production occurs in year 2009.

Figure 9.4 shows the effect the different components of Government Take have on the project.

Figure 9.4 – Components of Government Take

100

90

Cess 80

70

60 Royalty

50

40 Income Tax

30 Paid to Government (US$MM)

20

10 Year

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

The total undiscounted Government Take is US$ 586.64MM and represents 67% of project net cash flow.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.12

9.4.3 Sensitivity analyses

In this section I investigate how changes to field development affect the value of the project. My analyses are illustrated in the form of a spider diagram.

Figure 9.5 shows the effect of changes in assumptions on the value of D-1 project. The effect of the following assumptions are examined xProduction rates. xOil price. xDevelopment costs. xOperating costs.

Figure 9.5 – Spider diagram

110 Operating cost Oil price

100

Development cost Development cost 90

80 Fall in production rates Operating cost

70

60 NPV in US$MM at 2002

50 Oil price

40 70% 80% 90% 100% 110% 120% 130% Percentage variation in assumptions

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.13

Figure 9.5 shows that profitability of D-1 project is most sensitive to changes in oil price. Falls in production rates also have a significant effect on the NPV of D-1 project. Changes made to development and operating costs have very little effect on project profitability. This is because the NPV’s of both development and operating expenditures are very small compared to the NPV of gross revenue.

The project’s NPV is more sensitive to changes made to the operating costs than the development costs. The reason is that total operating costs include the additional cost of storage tanker hire and therefore operating costs are significantly larger than development costs.

9.4.4 Monte Carlo Simulation

In addition to the sensitivity analyses described above, I have examined the effect of price, production and cost uncertainties on the value of D-1 project. I have carried out a Monte Carlo analysis to examine the effect of uncertainties in the assumptions made. The Monte Carlo analysis carried out examines the economics of the project from the beginning of the PSC.

I assume that price uncertainties would follow a lognormal probability curve. I choose the lognormal distribution because history shows that oil prices have a tendency to be skewed, with the most likely price being towards the lower end of the range. Refer to Appendix D.

I assume cost uncertainties to follow normal probability distribution. I expect all costs to be equally as likely to be above as below by central estimate. Since cost uncertainties are assumed to be symmetrical, I assume a normal probability distribution to be the most appropriate.

I also assume all uncertainties linked to production to follow a lognormal distribution. I choose the lognormal distribution because production rates have a tendency to be skewed. There are probabilities of low and high production rates. However, the most likely production rate is towards the lower end of the range.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.14

Oil price

I assume that uncertainty in the oil price follows lognormal probability distribution with the 10th percentile being US$ 20 per barrel and the 90th percentile being US$ 50 per barrel.

Development cost

I assume that uncertainty in development costs follows a normal probability distribution with the 10th percentile being 70% of base case estimate of US$ 63.56MM and the 90th percentile being 130% of base case estimate.

Operating cost

I assume that uncertainty in development costs follows a normal probability distribution with the 10th percentile being 70% of base case estimate of US$ 115.65MM and the 90th percentile being 130% of base case estimate.

Production rate

I assume that uncertainty in production rate follows a lognormal probability distribution with the 10th percentile being 30% decline in production per year and the 90th percentile being 10% decline in production per year.

Figure 9.6 shows the resulting probability distribution of the NPV of D-1 project when the uncertainties described above are applied in a Monte Carlo simulation.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.15

Figure 9.6 – D-1 NPV frequency distribution

10%

9%

8%

7% Probability (%)

6%

5%

4%

3%

2%

1% NPV (US$MM)

0 -80 -40 40 80 -120 120 160 200 240 280 320 360 400 440 480 520 560

Figure 9.7 show the cumulative probability corresponding to the results given in Figure 9.6. It compares the base case value (US$ 91.61 MM) against the results obtained from Monte Carlo analyses.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.16

Figure 9.7 – Cumulative probability against NPV

100%

90% P90 = US$ 218.93 MM 80%

70% Standard Deviation = 95.31 Probability (%)

60% Base case estimate = US$ 91.61 MM

50% Mean = US$ 85.07 MM

40%

30% P50 = US$ 72.28 MM

20% P10 = US$ -29.34 MM 10% NPV (US$MM)

-200 -150 -100 -50 0 50 100 150 200 250 300 350 400 450 500 550 600

There is a 19% probability that the NPV is zero or negative. The mean NPV is US$ 85.07MM and the P50 NPV is US$ 72.28MM. These compare with the base case NPV estimate of US$ 91.61MM.

9.5 Summary and conclusions

In this chapter, I analyse the workings of the D-1 PSC. In doing so, I derive the NPV of D-1 field development and conduct sensitivity and Monte Carlo analyses.

The D-1 field has a NPV of US$ 205.14MM (in January 2005 terms) and US$ 91.61MM (in January 2002 terms). These are base case estimates.

Based on results obtained from sensitivity tests, the value of D-1 project is most sensitive to the oil price and is insensitive to changes made to development and

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 9.17 operating costs. Changes made to production results in a decrease in reserves and hence the profitability of the project.

The Monte Carlo analysis shows that there is a 19% probability that the NPV of D-1 field could be negative.

Based on the analyses, I conclude that the D-1 development is a profitable, project with no significant downside risk.

Sajith Venugopal July 2005 University of New South Wales

Chapter 10

Economics of PY-1 gas development

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.1

10.1 Introduction

This section of the chapter discusses the economics of PY-1 field development, which is part of the PY-1 production sharing contract (“PSC”). PY-1 is a gas field with small quantities of recoverable associated condensate. The field is located offshore the southeastern coastline of India in the Cauvery Basin. It is located in less than 75 metres (“m”) and is 18 kilometers (“km”) east of the coastal town of Porto Novo.

Figure 10.1 – Location map

PY-1 gas field was discovered by ONGC in 1980. By 1990, eight wells had been drilled within PY-1 contract area. Of these, five wells tested significant and commercial quantities of sweet gas.

The field was offered as a development field in 1993. On 6 October 1995, a 25-year PSC was signed between Government of India and a consortium made up of Mosbacher India LLC (“MIL”), Hindustan Oil Exploration Company Limited (“HOEC”) and Tata Petrodyne (“Petrodyne”). By 1997, Petrodyne had left the consortium and Energy

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.2

Equity Corporation Limited (“EECL”) joined the consortium after buying 35% participating interest from MIL. In 1999, EECL’s failure to comply with the PY-1 joint operations agreement resulted in their leaving the PY-1 field consortium. At this stage, MIL’s participating interest in the filed stood at 53.85% and HOEC’s at 46.15%. In 2004, HOEC bought MIL’s share of PY-1 field.

At the time of writing, HOEC has a 100% participating interest.

In 1997, the appraisal well PY-1-12 was drilled in the contract area. Based on information obtained from long-term production tests conducted on the appraisal well, in 1999 a plan of development (“POD”) was drafted. The POD recommended developing PY-1 gas field in 3 phases (reference 44).

The development of the PY-1 field involved installation of a nine slot well-head platform over appraisal well PY-1-12. A 52 km, 12 inch export pipeline is to be laid from the field to deliver gas at Pillaiperumalnallur (“PPN”) power generating company in Tamil Nadu. In addition to the PY-1-12 well, which would be re-entered and completed, the POD also suggested drilling 7 new wells. Other recommendations in the POD included installing facilities designed to handle a throughput capacity of 70 to 80 million cubic feet per day (“MMcfd”) of gas as well as associated condensate and water. The POD envisaged that construction would begin in 2004 and first gas is expected to be brought to shore by early 2006.

10.2 Assumptions

The assumptions made for economic analyses are as follows

10.2.1 Gas prices

The gas from PY-1 is contracted for sale from 2006. On 1 July 2003, a Gas Sale and Transportation Agreement (“GSTA”) was signed between the operator and Gas Authority of India Limited (“GAIL”). According to the GSTA, GAIL is to pay for the pipeline bringing the gas to shore. The GSTA is for a primary term of fifteen years from 2006, with one-year renewal thereafter. Table 10.1 below shows the prices at which the gas from PY-1 field has been contracted for sale. Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.3

Table 10.1 – Gas contract price

Contract price Contract price Year US$/MMbtu US$/GJ 1,2 2.355 2.230 3,4 2.450 2.320 5 to 15 2.555 2.420 Source: HOEC website

The gas prices are net of transport tariff for use of GAIL’s offshore pipeline. The gas price has been contracted at a fixed price. There is no price escalation.

10.2.2 Condensate prices

I assume that the condensate prices will escalate at 3% per year and that the escalation begins in year 2005. The condensate price used in fiscal year 2004 is US$ 27.00 per bbl. Since condensates have lesser calorific value than crude oil, I assume a discount of US$1.00 to the crude oil price. Refer to Appendix F.

10.2.3 Production

I have assumed PY-1 gas production to start at 38.49 million cubic feet per day (“MMCFD”) in year 2006 and a production plateau of 44.85 MMCFD for 7 years. The production profile reflects the requirements of PY-1 gas contract with GAIL (reference 45).

I do not have operator forecasts for PY-1 gas after the production plateau ends. However, the operator expects to yield a cumulative production of approximately 196 billion cubic feet (“Bcf”) at the end of 25 years of production. If I assume production to decline at 19% after the production plateau ends in 2013, I achieve cumulative production of 196.49 Bcf.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.4

Figure 10.2 – Gas production profile

18

16

14

12 Gas produced (Bcf) 10

8

6

4

2 Year

1997 2000 2003 2006 2009 2012 2015 2018 2021

Condensate production is associated with gas production. Therefore, condensate production is on a production plateau for 7 years starting from 2007 till 2013. I assume condensate production to be at a fixed 15% of gas production.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.5

Figure 10.3 – Condensate production profile

0.05

0.04

0.03

0.02 Condensate produced (MMbbl) produced Condensate

0.01

Year

1997 2000 2003 2006 2009 2012 2015 2018 2021

10.2.4 Exploration and development costs

I have assumed all field exploration and development costs incurred before 2005 based on information contained in references 44 and 45.

10.2.5 Operating costs

I have assumed the real operating costs to be 5% of the real total development costs. This is based on information contained in reference 44 and is a rule of thumb typical of oil and gas industry assumptions.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.6

10.2.6 Abandonment costs

I assume that real abandonment costs are notionally 25% of total development costs. Given that the latter are US$ 65MM, I assume real abandonment costs will be US$ 16.25MM. From the base case analysis (see below), field abandonment is likely to occur in year 2020 and that the total nominal abandonment cost at that time would be US$ 26.08MM assuming escalation at 3% per year.

10.2.7 Escalation

I assume that the condensate price, and field development capital and operating costs escalate at 3% per year and that escalation begins in year 2005. I use actual or estimated prices and costs for years before 2005. The 3% escalation assumption is typical of oil and gas industry escalation assumptions at the present time.

10.2.8 Discounting

I calculate nominal Net Present Value (“NPV”) using a nominal discount rate of 10%. I consider this to be typical of discount rates used by oil/gas companies internationally. I use end year discounting and discount to fiscal year 1997. I choose fiscal year 1997 because this is the year first expenditure for exploratory work was made.

10.2.9 Summary of assumptions

Table 10.2 summarises the field development assumptions made for all years of the PY-1 project (Last updated December 2004). All price and cost data included in Table 10.2 are unescalated or real values.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.7

Table 10.2 - Summary of assumptions ($ amounts from 2005 are in real terms)

Associated Associated Gas Gas condensate condensate Expl Dev Op Aband production price production price Costs Costs Costs Costs Year MMcfd US$/GJ Kbopd US$/bbl US$MM US$MM US$MM US$MM 1997 2.10 1998 11.00 1999 0.80 2000 1.00 2001 0.90 2002 1.00 2003 1.00 2004 21.80 2005 38.50 2006 38.49 2.23 0.11 27.00 3.25 2007 44.85 2.23 0.13 27.00 3.25 2008 44.85 2.32 0.13 27.00 3.25 2009 44.85 2.32 0.13 27.00 3.25 2010 44.85 2.42 0.13 27.00 3.25 2011 44.85 2.42 0.13 27.00 3.25 2012 44.85 2.42 0.13 27.00 3.25 2013 44.85 2.42 0.13 27.00 3.25 2014 36.33 2.42 0.10 27.00 3.25 2015 29.43 2.42 0.09 27.00 3.25 2016 23.84 2.42 0.07 27.00 3.25 2017 19.31 2.42 0.06 27.00 3.25 2018 15.64 2.42 0.05 27.00 3.25 2019 12.67 2.42 0.04 27.00 3.25 2020 10.26 2.42 0.03 27.00 3.25 16.25

The estimated real abandonment costs are given in Table 10.2. Details of the abandonment cost sinking fund spending are described in section 10.3.3 of this report.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.8

10.3 PSC terms

The PY-1 Production Sharing Contract (“PSC”) is in force for a period of 25 years up to the year 2014. According to the agreement, the contractor has an option to extend the term by 5 fiscal years. I have assumed the consortium to exercise their option to extend the PSC by 5 fiscal years to 2019. The PY-1 PSC includes the following fiscal terms.

10.3.1 Cess and Royalty

Cess (a special tax in India) and state royalties are levied on all condensate produced. For the PY-1 PSC, Cess is Rupees 900 per tonne of crude oil produced and state royalty is Rupees 578 per tonne of condensate produced. The total (Rupees 1,478) is equivalent to US$ 3.43 per barrel assuming an exchange rate of 1US$ = 48.00 Rupees.

No cess applies to gas production.

The royalty on gas produced is 10% of the well-head value. The PSC does not set out how well-head value is to be determined in detail. However, well-head value is gross revenue less the cost of transport and treatment. As a first approximation, I assume that the costs of transport and treatment are approximately 20% of gross revenue and therefore that well-head value is 80% of gross revenue.

10.3.2 Cost Petroleum

Recoverable costs include all exploration, development and operating costs incurred within the boundaries of the PSC and all production payments made during field life. These costs are recoverable from project revenue after cess and royalty have been deducted. The total of costs recovered is “Cost Petroleum”. Any cost not recovered in a particular year is carried forward for recovery in the following year.

10.3.3 Abandonment sinking fund

The PY-1 PSC requires the contractors to contribute regularly to a site restoration fund so that sufficient funds are available to abandon the development at the end of its life. I refer to this as an abandonment sinking fund. Contributions are fully cost Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.9 recoverable. The PSC does not stipulate how the sinking fund is to be calculated. I assume that annual contributions to the fund are made based on units of production calculation similar to a depletion allowance calculation typically used in oil and gas company accounts. That means that money is put aside in proportion to the rate at which PY-1’s reserves are produced. See Appendix E for details of the calculation.

10.3.4 Profit Petroleum

The revenue remaining after Cost Petroleum is "Profit Petroleum". Profit petroleum is shared between the Government and the Contractor in varying proportions depending on an Investment Multiple (“IM”) calculation using the Contractors’ cash flow in the previous year.

The IM for the previous year is determined by dividing the accumulated Contractors’ “Net Cash Income” by the Contractors’ accumulated “Investment”.

“Net Cash Income” equals the Contractors’ revenue (Cost recovery plus Share of Profit Petroleum) less the Contractors’ Production costs and Royalty payments.

“Investment” equals the Contractors’ Exploration costs plus Development costs.

The split of profit petroleum between the Contractor and the Government is determined by the IM ratio. The IM ratio in any one year gives the profit petroleum split between the concerned parties for the next year.

Table 10.3 below, gives the profit split tranches used in PY-1 PSC for petroleum sharing.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.10

Table 10.3 –Profit split tranches for PY-1 PSC

Contractor’s share of Government’s share of Investment Multiple profit petroleum next profit petroleum next this year year year below 1.0 100% 0% 1.0 to 2.0 95% 5% over 2.0 50% 50%

The chapter on Indian fiscal terms gives details of how profit sharing is calculated for petroleum development in India.

10.3.5 Income Tax

Income tax calculations are based on the revenues and expenditures of each individual company in the PSC. The tax in any one-year is taken to be the maximum of “Normal” tax and “Minimum Alternative Tax” (“MAT”) for that particular year. The ring fence for income tax is the PY-1 PSC with the exception that failed exploration costs outside the PSC can be deducted against tax.

The chapter on Indian fiscal terms gives details of how income tax is calculated for petroleum development in India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.11

10.4 Results

The results of base case of the economics of the PY-1 development are given in Table 10.4.

Table 10.4 – Results for base case.

Reserves Hydrocarbon reserves 32.74 MMboe Gas reserves 182.46 Bcf Condensate reserves 0.53 MMbbl

Economic Indicators As at 1 Jan 1997 As at 1 Jan 2005 Nominal NPV at 10% US$ 13.64 MM US$ 80.89 MM Internal rate of return (IRR) 14.91 % 59.62 % Capital productivity index (CPI) 0.23 1.04 Pay back period 13.16 years 5.16 years Footnote – Reserves listed are cumulative production over economic life

The reserves estimates above would be close to proven plus probable reserves. SPE definitions of reserves are given in Appendix F.

I report total hydrocarbon reserves by converting gas and condensate into oil equivalent using the conversion factors set out in Appendix B. Appendix G contains definitions of economic indicators listed in Table 10.4 above.

I use year-end discounting method to derive the nominal NPV.

When discounting to January 2005, I only consider the net cash flow generated from year 2005 onwards. The NPV, IRR and CPI values increase because the date is closer to start of production. There is a decrease in the pay back period because the cost to be recovered is only US$ 38.50MM (expenditure in fiscal 2005) as compared to US$

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.12

65.00MM, which is the cumulative expenditure for the whole project starting from 1997. A lower cost gives a faster recovery from project revenues.

10.4.1 Net cash flow

Figure 10.4 plots the yearly net cash flows of PY-1 field against time. Figure 10.4 shows that before take net cash flow (BTNCF) is at a maximum in the year 2010, whereas the contractors’ after take net cash flow (ATNCF) is at a maximum in the year 2008. This is because of the effect of Government take on the project. A further analysis of the impact of the components of Government take is given later.

Figure 10.4 – Net cash flow against time

50.0

40.0

Before Tax NCF 30.0 After Tax NCF 20.0

10.0

-10.0 1997 2000 2003 2006 2009 2012 2015 2018 2021 Year -20.0

-30.0

Operator's (US$MM) net cash nominal yearly -40.0

-50.0

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.13

10.4.2 Components of Government take

During the initial two years of production, Government take from the project comes from royalty, cess and income tax. Income tax comes into effect when the project starts to make profit. The share of profit petroleum to the Government starts in 2008. This is because it is, in effect, based on net cash flow rather than profit. Even though profit sharing starts in 2008, this component yields the most revenue to the Government over the life of the project.

Figure 10.5 shows the effect the different components of Government Take have on the project.

Figure 10.5 – Components of Government Take

30

25

Profit Petroleum

20

15 Royalty + Cess

10 Paid to Government (US$MM)

5 Income Tax Year

1997 2000 2003 2006 2009 2012 2015 2018 2021

The total undiscounted Government Take is US$ 191.60MM and forms 62.38% of project net cash flow.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.14

10.4.3 Sensitivity analyses

In this section I investigate how changes to key parameters affect the value of the project. Findings from my analyses are illustrated in the form of a spider diagram. Finally, I carry out Monte Carlo simulation analyses to show the effects on the NPV of the project of combining parameter variations.

10.4.3.1 Spider diagram

Figure 10.6 shows the effect of changes in assumptions on the value of PY-1 project. The effect of the following assumptions are examined xProduction decline rates. xDevelopment costs. xOperating costs.

I do not bring changes in gas prices as these are fixed according to the contract. Condensate production is minimal and hence any changes made to condensate prices have little effect on the value of PY-1 project. The value of PY-1 project is robust to the changes in assumptions considered. That is, the NPV remains positive in all cases.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.15

Figure 10.6 – Spider diagram

25

20 Decline rate after Development cost production plateau

15 Operating cost Operating cost

Decline rate after 10 production plateau Development cost

5 NPV in US$MM at 1997

0 70% 80% 90% 100% 110% 120% 130% Percentage variation in assumptions

Decline rate

When the production decline rate is 30% per year from 2014 (compared to 19% per year for the base case), the NPV of the project drops to US$ 12.27MM. The reduction in value occurs because the economic life of project falls to 22 years from the base case value of 24 years. There is a corresponding fall in reserves to 28.78 MMboe as compared to 32.74 MMboe in base case.

When the production decline rate is 13% per year from 2014 (as compared to 19% for the base case), the NPV of the project increases to US$ 14.88MM. This increase occurs because the economic life of the project increases to 28 years (beyond the life of the PSC). There is a corresponding increase in reserves to 38.49 MMboe.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.16

Development cost

Figure 10.6 shows that a 30% increase in total development cost results in a decrease in NPV of the project to US$ 7.08MM from US$ 13.64MM in the base case. A 30% decrease in development costs increases NPV of the project to US$ 20.18MM. Under some circumstances, an increase in development costs change the profit sharing tranches, reduce Government Take and thereby increases the value of the project. The wave pattern shown by the development cost variable is due to the effects of Government Take.

Operating costs

A 30% decrease in operating costs increases the NPV from US$ 13.64MM to US$ 16.41MM. The reduction in operating costs increases net cash flow in all years. However, in addition, the economic life of the project lengthens to 26 years (as compared to 24 years under base case). There is a consequent increase in reserves to 33.72 MMboe as compared to 32.74 MMboe in base case.

When operating costs are increased to 130% of the base case value, there is a decrease in NPV of the project to US$ 11.25MM. The decrease in value is the result of decreases in net cash flow as well as a shorter economic life (23 years compared to 24 years in the base case). With higher operating costs, the reserves fall to 32.07 MMboe as compared to 32.74 MMboe in base case.

10.4.3.2 Monte Carlo Simulation

In addition to the sensitivity analyses described above, I have examined the effect of price, production and cost uncertainties on the value of PY-1 project. I have carried out a Monte Carlo analysis to examine the effect of uncertainties in the assumptions made. The Monte Carlo analysis carried out examines the economics of the project from the beginning of the PSC.

As stated earlier, I do not vary gas prices as they are fixed as per the contractual agreement signed between the operator and GAIL.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.17

I assume cost uncertainties to follow a normal probability distribution. I expect all cost variations are equally likely to be above as below by central estimate. Since cost uncertainties are assumed to be symmetrical, I assume a normal probability distribution to be the most appropriate distribution.

I also assume all uncertainties linked to production to follow a lognormal distribution. I choose the lognormal distribution because production rates have a tendency to be skewed. There are probabilities of low and high production rates. However, the most likely production rate is towards the lower end of the range.

Development cost

I assume that uncertainty in development costs follows a normal probability distribution with the 10th percentile being 70% of base case estimate of US$ 65.00MM and the 90th percentile being 130% of base case estimate.

Production decline rate

I assume that uncertainty in production rate follows a lognormal probability distribution with the 10th percentile being 30% decline in production per year (after production plateau ends) and the 90th percentile being 10% decline in production per year (after production plateau ends).

Figure 10.7 shows the resulting probability distribution of the NPV of PY-1 project when the uncertainties described above are applied in a Monte Carlo simulation.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.18

Figure 10.7 – PY-1 NPV frequency distribution

8%

7%

6%

5%

4% Probability (%) 3%

2%

1% NPV (US$MM)

-6 0 6 12 18 24 30 36

Figure 10.8 show the cumulative probability corresponding to the results given in Figure 10.7. It compares the base case value (US$ 13.64 MM) against the results obtained from Monte Carlo analyses.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.19

Figure 10.8 – Cumulative probability against NPV

100%

90% Standard Deviation = 6.62

80% P 90 = US$ 22.57 MM

70% Mean = US$ 13.88 MM 60%

50%

Probability (%) P 50 = US$ 13.90MM

40% Base case estimate = US$ 13.64 MM

30%

20% NPV (US$MM) 10% P 10 = US$ 5.61 MM

-6-4-20 2 4 6 8 10121416182022242628303234363840

The NPV is zero or negative for all probabilities below 2.20%. Our base case NPV estimate is US$ 13.64MM. From Figure 10.8, it is clear that our base case estimate is closer to the mean than the P50 NPV (value at 50% probability). The mean is US$ 13.88MM and the P50 NPV is US$ 13.90MM.

10.5 Summary and conclusions

In this chapter, I analyse the workings of the PY-1 PSC. I derive the NPV of PY-1 field development and conduct a sensitivity and Monte Carlo analyses.

I found that PY-1 field has a NPV of US$ 80.89MM (in January 2005 terms) and US$ 13.64MM (in January 1997 terms). These are base case estimates.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 10.20

Based on results obtained from sensitivity tests, the value of PY-1 project is most sensitive to the development costs and least sensitive to operating costs. Changes made to decline rate results in an increase in economic reserves. However, fiscal effects of PY-1 field limit any substantial gain in NPV for the operator.

The Monte Carlo analysis results discussed above show that the NPV of PY-1 field is a profitable, low risk project – there is 98% chance of a positive NPV.

Sajith Venugopal July 2005 University of New South Wales

Chapter 11

Economics of KG-DWN-98/3 gas development

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.1

11.1 Introduction

This chapter discusses the economics of the KG-DWN-98/3 field development, which is part of the KG-DWN-98/3 production sharing contract (“PSC”). The PSC is located offshore the eastern coastline of India in the Krishna Godavari Basin between 40 and 60 kilometres (“km”) south east of Kakinada. It is has a range of water depths from 400 to 2,700-metres (“m”) and has a total area of 7,645 square kilometres (“sq km”).

Figure 11.1 – Location map

The KG-DWN-98/3 block was offered for exploration and development under round one of the New Exploration Licensing Policy (“NELP”). A consortium consisting of Reliance Industries Limited (“RIL”) and Niko Resources Limited (“NIKO”) won exploration and development rights to the block. A PSC for KG-DWN-98/3 block was

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.2 signed between the Government of India (“GOI”) and the consortium in April 2000 with RIL and NIKO having participating interests of 90% and 10% respectively.

RIL began Phase I of the exploratory drilling programme in April 2002. In October 2002, RIL announced that it had discovered natural gas in the very first exploration well. This was the first natural gas discovery by an Indian private company and was the largest discovery of natural gas from a single field in 2002.

By March 2003, a total of eight exploration wells had been drilled in the block. Phase II of exploratory drilling began in December 2003. Six new wells were drilled in this phase (reference 46). At the time of writing, RIL had announced that they had made twelve natural gas discoveries from the fourteen exploration wells drilled in KG-DWN- 98/3.

However, at the time of writing, RIL had declared commercial only three of the twelve gas discoveries made in KG-DWN-98/3. The discoveries declared commercial are associated with the wells Dhirubhai 1, 2 and 3.

I have assumed that the KG-DWN-98/3 field has 14 trillion cubic feet (“Tcf”) of gas reserves at the proven plus probable level. In November 2004, RIL had its field development plan approved by the Directorate General of Hydrocarbons (“DGH”). The development plan indicates that RIL plans to develop the KG-DWN-98/3 field with a total expenditure of US$ 2.36 billion (reference 47). Gas produced from the field is to be transported to an onland processing facility at Kakinada using a 40km 24-inch pipeline. The operator is also in talks with the GOI for permission to lay a 48-inch pipeline for transporting treated gas from Kakinada to the demand centers in India.

RIL had recently won a supply tender to supply gas to National Thermal Power Company’s (“NTPCs”) Kawas and Gandhar power plants in Gujarat.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.3

11.2 Assumptions

The assumptions made for economic analyses in this chapter are set out below.

11.2.1 Participating interest

All analyses have been carried out for a 100% participating interest.

11.2.2 Future gas price

The operator won a tender to supply gas to National Thermal Power Corporation’s (“NTPCs”) power plants at a price of US$ 3.13 per giga joule (reference 48). I assume this price in the economic analyses described below.

11.2.3 Future production

The operator has so far declared commercial three of the twelve discoveries made at KG-DWN-98/3 field. During the first phase of production, the operator plans to produce the 7.5 Tcf reserves it associates with wells Dhirubhai 1 and 3 at the proven plus probable level. In contrast, international consultants DeGoyler & McNaughton (“D&M”), commissioned by the operator to verify the reserves independently have estimated that the proven plus probable reserves for Dhirubhai 1 and 3 to be 6.174 Tcf. (reference 49)

I assume that Phase I of production will result in recovery of 6.174 Tcf and that during Phase II of production, the operator will recover an additional 7.826 Tcf. This gives a recovery of 14 Tcf in the two phases of production, which corresponds to the operator's estimate of proven plus probable reserves.

Production profile

The KG-DWN-98/3 field will be developed in two phases as set out below.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.4

Phase I

The operator plans to begin production in year 2008, with an initial production rate of 257.8 billion cubic feet per year (“Bcf/yr”). After two years, the operator plans a production rate of 515.5 Bcf/yr for 7 years. In year 2017, the operator plans production to peak at 902.2 Bcf and decline thereafter (reference 48).

I assume that Phase I of production will result in recovery of 6.174 Tcf. If I assume production to decline at 25% after the last year of peak production in year 2017, then cumulative production of 6.174 Tcf is achieved by 2019. Table 11.1 contains details of production in Phase I.

Table 11.1 – Production profile of Phase I production

Published data* Published data* Year (Bcf per year) (MMCMD) 2008 257.8 (P) 20.0 (P) 2009 257.8 (P) 20.0 (P) 2010 515.5 (P) 40.0 (P) 2011 515.5 (P) 40.0 (P) 2012 515.5 (P) 40.0 (P) 2013 515.5 (P) 40.0 (P) 2014 515.5 (P) 40.0 (P) 2015 515.5 (P) 40.0 (P) 2016 515.5 (P) 40.0 (P) 2017 902.2 (P) 70.0 (P) 2018 676.6 (A) 52.5 (A) 2019 471.0 (A) 80.0 (A) Total (Bcf) 6,174.0

* All data published had production rates reported in million cubic meters per day (“MMCMD”). (P) - Published, (A) – Assumed.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.5

Phase II

I assume that during Phase II production, cumulative production will be 7.826 Tcf. with Phase II production starting when Phase I production ends. I assume that there will be a production plateau of 5 years in Phase II.

Gas treatment facilities at Kakinada are being designed for a capacity of 1,031 Bcf/yr (reference 50). Therefore, I assume that peak production in Phase II production would be at 1,031 Bcf/yr before declining at 25% per year.

Production profile for Phase I and Phase II

Figure 11.2 – Gas production profile

1600

1400

Gas production in Phase 2 1200 (assumed)

1000

Gas production in Phase 1 800 (assumed data)

Gas production in Phase 1 600 (published data)

400 Production rate (Bcf per year)

200 Year 0 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.6

11.2.4 Exploration costs

Planned exploration in KG-DWN-98/3 involves drilling fourteen wells – eight in Phase I and six in Phase II. Based on figures reported in NIKO’s annual reports, NIKO with a 10% participating interest, spent US$ 28.8MM during these two exploration phases. Hence the total exploration expenditure for a company with 100% participating interest would have been US$ 288MM. A total expenditure of US$ 288MM for exploration drilling and associated seismic surveys would translate to an average exploration cost of US$20.6MM per well.

11.2.5 Development costs

The operator plans to spend US$ 2.36 billion to develop 14 Tcf. It plans to drill 35 production wells in the area of Dhirubhai 1 and 3. These wells would then be completed subsea using six manifolds. Each manifold would accommodate five to six wells.

The operator plans to lay a 40km, 24-inch pipeline to bring gas from the field to a planned processing facility at Kakinada. Once in place, the operator then plans to transport treated gas to demand centers in western and central India using a 48-inch pipeline (reference 48).

The operator plans to invest US$ 500MM in the first phase of field development (reference 51). I assume that the operator would spend this and the remaining investment as shown in Table 11.2. Since Phase II of gas production is likely to start in year 2019, I assume some expenditure to be made in the years immediately preceding 2019.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.7

Table 11.2 – Expenditure made for field development

Year Amount (US$MM) 2005 500.0 2006 465.0 2007 418.5 2008 293.0 2009 170.9 2010 128.2 2014 173.0 2015 105.7 2016 42.3 2017 38.1 2018 25.3 Total 2,360.0

11.2.6 Operating costs

I have assumed the real operating costs to be 7% of the real total development costs. This is a rule of thumb typical of oil and gas industry costing assumptions.

11.2.7 Abandonment costs

I assume that real abandonment costs are notionally 25% of total development costs. Given that the latter are US$ 2,360MM, I assume real abandonment costs will be US$ 590MM. From the base case analysis (see below), field abandonment is likely to occur in year 2028 and the total nominal abandonment cost at that time would be US$ 1,199.3MM assuming escalation at 3% per year.

11.2.8 Escalation

I assume that field development capital and operating costs will escalate at 3% per year and that escalation begins in year 2005. Before 2005, I use actual or estimated

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.8 prices and costs. The 3% escalation assumption is typical of oil and gas industry escalation assumptions at the time of writing.

11.2.9 Discounting

I calculate nominal Net Present Value (“NPV”) using a nominal discount rate of 10%. I consider this to be typical of discount rates used by oil/gas companies internationally. I use end year discounting and, for full cycle economics, discount to fiscal year 2002. I choose fiscal year 2002 because this is the year in which the first exploration expenditure was incurred.

11.2.10 Summary of assumptions

Table 11.3 summarises the field development assumptions made for all years of the KG-DWN-98/3 project. All price and cost data from the year 2004 in Table 11.3 are unescalated. Prices and costs before that date are actual or estimated actual data.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.9

Table 11.3 - Summary of assumptions

Real Real Real Real Gas Gas Exploration Development Operating Abandonment production price Costs Costs Costs Costs Year Bcf US$/GJ US$MM US$MM US$MM US$MM

2002 102.9 2003 61.7 2004 123.4 2005 257.8 3.13 500.0 165.2 2006 257.8 3.13 465.0 165.2 2007 515.5 3.13 418.5 165.2 2008 515.5 3.13 293.0 165.2 2009 515.5 3.13 170.9 165.2 2010 515.5 3.13 128.2 165.2 2011 515.5 3.13 165.2 2012 515.5 3.13 165.2 2013 515.5 3.13 165.2 2014 515.5 3.13 173.0 165.2 2015 515.5 3.13 105.7 165.2 2016 515.5 3.13 42.3 165.2 2017 902.2 3.13 38.1 165.2 2018 676.6 3.13 25.3 165.2 2019 1,031.1 3.13 165.2 2020 1,031.1 3.13 165.2 2021 1,031.1 3.13 165.2 2022 1,031.1 3.13 165.2 2023 1,031.1 3.13 165.2 2024 1,031.1 3.13 165.2 2025 773.3 3.13 165.2 2026 580.0 3.13 165.2 2027 435.0 3.13 165.2 2028 322.5 3.13 165.2 590.0 Total 14,000.0 288.0 2,360.0 3,469.2 590.0

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.10

The estimated real abandonment costs are given in Table 11.3. Details of the abandonment cost sinking fund spending are described in section 11.3.3 of this report.

11.3 PSC terms

The KG-DWN-98/3 PSC terms are summarised in the following.

11.3.1 Royalty

Since KG-DWN-98/3 is a deepwater development, the royalty rate for first seven years of commercial production is 5% of well-head value. After the first seven years, the royalty on gas produced is 10% of the well-head value.

The PSC does not set out how well-head value is determined in detail. However, in general, well-head value is gross revenue less the costs of transport and treatment. As a first approximation, I assume that the costs of transport and treatment are approximately 20% of gross revenue and therefore that well-head value is 80% of gross revenue.

11.3.2 Cost Petroleum

Recoverable costs include royalties, all exploration, development and operating costs incurred within the boundaries of the PSC. According to the KG-DWN-98/3 PSC, there is a limit set for cost recovery, referred to here as the “Cost Recovery Ceiling”. The “Cost Recovery Ceiling” for the KG-DWN-98/3 PSC is 90%. Thus, the revenue available for cost recovery in any one year is 90% of project revenue (reference 52).

The total of costs recovered is “Cost Petroleum”. Any cost not recovered in a particular year is carried forward for recovery in the following year.

11.3.3 Abandonment sinking fund

The KG-DWN-98/3 PSC requires the contractors to contribute regularly to a site restoration fund so that sufficient funds are available the abandon the development at the end of its life. I refer to this as an abandonment sinking fund. Contributions are fully cost recoverable. The PSC does not stipulate how the sinking fund is to be

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.11 calculated. I assume that annual contributions to the fund are made based on units of production calculation similar to a depletion allowance calculation typically used in oil and gas company accounts. That means that money is put aside in proportion to the rate at which the KG-DWN-98/3 field’s reserves are produced. See Appendix E for details of the calculation.

11.3.4 Profit Petroleum

The revenue remaining after Cost Petroleum is "Profit Petroleum". Profit petroleum is shared between the Government and the Contractor in varying proportions depending on an Investment Multiple (“IM”) in the previous year.

The IM for the previous year is determined by dividing the accumulated Contractors’ “Net Cash Income” by the Contractors’ accumulated “Investment”.

“Net Cash Income” equals the Contractors’ revenue (Cost recovery plus Share of Profit Petroleum) less the Contractors’ Production costs and Royalty payments.

“Investment” equals the Contractors’ Exploration costs plus Development costs.

Profit petroleum is shared between the Contractor and the Government depending on the IM. Table 11.4 shows the profit sharing for the KG-DWN-98/3 PSC (reference 53). The table 11.4 shows that there is a large drop in the Contract’s share of profit petroleum when the IM value exceeds 2.5. This feature of the PSC arrangement could distort investment decisions because it might encourage additional expenditure or reduced production as the year approaches when the GOI's profit share leaps to 85%.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.12

Table 11.4 –Profit split tranches for KG-DWN-98/3 PSC

Contractor’s share of Government’s share of Investment Multiple profit petroleum next profit petroleum next this year year year below 1.5 90% 10% 1.5 to 2.0 84% 16% 2.0 to 2.5 72% 28% over 2.5 15% 85%

The chapter on Indian fiscal terms gives more detail on how profit sharing is calculated in Indian PSCs.

11.3.5 Income Tax

The chapter on Indian fiscal terms gives details of how income tax is calculated for petroleum development in India.

The rate for normal tax is 33.66%.

Minimum Alternative Tax (“MAT”) is levied at a rate of 8.42%.

The above rates are as quoted in the 2005 Indian Budget (reference 54).

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.13

11.4 Results.

The results of base case of the economics of the KG-DWN-98/3 development are given in Table 11.5.

Table 11.5 – Results for base case.

Reserves Gas reserves 14 Tcf

Economic Indicators As at 1 Jan 2002 As at 1 Jan 2005 Nominal NPV at 10% US$ 1,703 MM US$ 2,582 MM Internal rate of return (IRR) 24.40 % 31.15 % Capital productivity index (CPI) 0.58 0.72 Pay back period 10.1 years 6.8 years Footnote – Reserves are equal to the cumulative production over economic life.

The reserves estimates above would be close to proven plus probable reserves. SPE definitions of reserves are given in Appendix F.

Appendix G contains definitions of the economic indicators used in Table 11.5.

When discounting to January 2005, I only consider the net cash flow generated from year 2005 onwards. The NPV, IRR and CPI values increase because the date is closer to start of production.

There is a decrease in the pay back period because the cost to be recovered is only US$ 515MM (expenditure in fiscal 2005) as compared to US$ 803MM, which is the cumulative expenditure for the whole project starting from 2002. A lower cost gives a faster recovery from project revenues.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.14

11.4.1 Net cash flow

Figure 11.3 plots the yearly net cash flows of the KG-DWN-98/3 field against time. Figure 11.3 shows that the operator’s before take net cash flow (“BTNCF”) is at a maximum in years 2019 to 2021. This is because gas production is at a maximum in these years. The operator’s after take net cash flow (“ATNCF”) is at a maximum in the year 2011.

Figure 11.3 – Net cash flow against time

3600

3000

BTNCF 2400

1800

ATNCF 1200

600

Year Operator's yearly nominal net cash (US$MM) 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 -600

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.15

11.4.2 Components of Government Take

Government take from the project is from royalty, profit sharing and income tax. Royalty starts to rise from year 2015 and is at maximum in the years from 2019 to 2024. This is because, until year 2015 royalty is calculated at 5% of well-head value, and from year 2015 onwards it is calculated at 10% of well-head value. Royalty is highest between 2019 and 2024 because gas production is at a maximum in these years.

Profit sharing yields the most revenue to the Government over the life of the project. The GOI's share of profit petroleum in absolute terms is at a maximum in year 2019. This is because the profit share to Government is 85% in this year.

Income tax is at a maximum in year 2015. This is because, until year 2015, the operator enjoys a tax holiday for seven years for the “Normal Income Tax” and only pays Minimum Alternate Tax (“MAT”). From year 2015 onwards, the operator starts to pay the maximum of “Normal Income Tax” and MAT. There is a decrease in income tax from year 2016 onwards because, from this year, the profit share to the Contractor goes down to 15%.

Figure 11.4 shows the effect the different components of Government Take have on the project.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.16

Figure 11.4 – Components of Government take

3000

2500 Profit Petroleum

2000

1500

Income Tax

1000 Paid to Government US($MM)

500 Royalty Year

18 2002 2004 2006 2008 2010 2012 2014 2016 20 2020 2022 2024 2026 2028 2030

The total undiscounted Government Take is US$ 26.22 billion and represents 75.8% of project net cash flow.

11.4.3 Sensitivity analyses

In this section I investigate how changes to field development assumptions affect the value of the project. My analyses are illustrated in the form of a spider diagram as shown in Figure 11.5. The effect of the following assumptions are examined - xProduction rates. xDevelopment costs. xOperating costs.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.17

I do not change gas prices in the sensitivity analyses because a contractual agreement is in place for gas to be sold at a price of US$ 3.13 per GJ.

Figure 11.5 – Spider diagram

2000

1900 Decline rate after Operating Cost production plateau

1800 Development Cost

Decline rate after production plateau 1700 NPV in US$MM at 2002

1600

Development Cost Operating Cost

1500 70% 80% 90% 100% 110% 120% 130% Percentage variation in assumptions

Decline rate

In the base case I recover 14 Tcf gas and assume that production declines at a rate of 75% per year. The decline in production sets in after production plateau ends in each of the production phases.

When the production decline rate is 60% per year, which is 80% of the decline rate of 75% per year used in the base case, the NPV of the project drops to US$ 1,584 MM compared to the base case value of US$ 1,703 MM. The reduction in value occurs because the economic life of project increases to 27 years from 21 years with the same economic recovery (14 Tcf). Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.18

With a production decline rate of 90% per year, which is 120% of the decline rate of 75% used in the base case, the NPV of the project increases to US$ 1,731.18MM. This increase occurs because the economic life of the project decreases to 19 years compared to 21 years for base case. The value of the project increases because we achieve target reserves of 14 Tcf of gas from the field in a shorter period.

Development cost

Figure 11.5 shows that the NPV of the project is most sensitive to changes made to development cost. The wave pattern shown by the development cost variable is a result of the effects of Government Take.

A 30% decrease in development cost decreases the NPV of the project to US$ 1,675.67MM (compared to 1,702.86MM for the base case). This is a result of an increase in the Government’s share of profit petroleum. When the development cost is reduced by 30%, the profit petroleum share to the Government reaches 85% in year 2013 (compared to 2016 for the base case).

The NPV of the project is at a maximum when there is a 5% decrease in development costs. The NPV of the project increases to US$ 1,833.67MM (compared to 1,702.86MM for the base case). The NPV increases because the Government's share of profit petroleum reaches 85% in year 2015.

A 30% increase in development costs decreases the NPV of the project to US$ 1,648.63MM. In this case, even though there is a decrease in Government Take from 75.8% to 72.1%, this is offset by the increased costs.

Operating costs

A 30% decrease in operating costs increases the NPV from US$ 1,702.86MM to US$ 1,914.08MM. The reduction in operating costs increases net cash flow in all years.

When operating costs are increased to 120% of the base case value, there is a decrease in NPV of the project to US$ 1,597.75MM. The net cash flow decreases because of the increase in the operating costs with no change in the shares of profit petroleum.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.19

When operating costs are increased to 130% of the base case value, there is an increase in NPV of the project to US$ 1,742.64MM (compared to US$ 1,597.75MM when operating costs are at 120% of base case value). The net cash flow increases even with a 130% increase in operating costs because there is a corresponding increase in the Contractor’s share of profit petroleum. This is illustrated in Figure 11.6 shown below.

Figure 11.6 – Operating cost sensitivity

120%

105%

90%

75% Base case

60%

45%

Operating cost is at 130% 30% of base case value Contractor's share of profit petroleum (%) 15% Time

0% 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Figure 11.6 shows that when the operating cost are increased to 130% of the base case value, the Contractor’s share of profit petroleum reaches the 15% tranche in year 2016. It remains at this tranche for a year before reverting back to the 72% tranche in year 2017. From year 2018 onwards, the profit petroleum share to the Contractor falls back to the 15% tranche. Thus the share of profit petroleum to the Contractor is greater in year 2017 (as compared to the base case). This results in a substantial increase in the NPV of the project.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.20

11.4.4 Monte Carlo Simulation

In addition to the sensitivity analyses described above, I have examined the effect of production and cost uncertainties on the value of KG-DWN-98/3 project as at the beginning of the project.

I assume that all costs are equally as likely to be above as below by central estimate. Since cost uncertainties are assumed to be symmetrical, I assume a normal probability distribution to be the most appropriate. I assume all uncertainties linked to production to follow a lognormal distribution. I choose the lognormal distribution because production rates have a tendency to be skewed.

Development cost

I assume that uncertainty in development costs follows a normal probability distribution with the 10th percentile being 70% of base case estimate of US$ 2,360MM and the 90th percentile being 130% of base case estimate.

Operating cost

I assume that uncertainty in development costs follows a normal probability distribution with the 10th percentile being 70% of base case estimate of US$ 165.20MM and the 90th percentile being 130% of base case estimate.

Production rate

I assume that uncertainty in production rate follows a lognormal probability distribution with the 10th percentile being 65% decline in production per year and the 90th percentile being 90% decline in production per year.

Figure 11.7 shows the resulting probability distribution of the NPV of KG-DWN-98/3 project when the uncertainties described above are applied in a Monte Carlo simulation.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.21

Figure 11.7 – KG-DWN-98/3 NPV frequency distribution

20%

18%

16%

14%

12% Probability (%)

10%

8%

6%

4%

2% NPV (US$MM)

1000 1200 1400 1600 1800 2000 2200 2400

Figure 11.8 shows the cumulative probability corresponding to the results given in Figure 11.7. It compares the base case value (US$ 1,702.86 MM) against the results obtained from Monte Carlo analyses.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.22

Figure 11.8 – Cumulative probability against NPV

100%

90%

80% P 90 = US$ 1,780.03 MM Standard Deviation = 110.97 70%

60% Our estimate = US$ 1,702.86 MM P 50 = US$ 1,648.37 MM 50%

40% Mean = US$ 1,644.92 MM

30% Cumulative probability (%)

20% P 10 = US$ 1,491.85 MM

10% NPV (US$MM)

1000 1200 1400 1600 1800 2000 2200

Our base case NPV estimate is US$ 1,702.86MM. This estimate is closer to the P50 NPV (value at 50% probability) than the mean. The P50 NPV is US$ 1,648.37MM and the mean is US$ 1,644.92MM.

11.5 Summary and conclusions

In this chapter I analyse the economics of the KG-DWN-98/3 gas discovery.

A unique feature of KG-DWN-98/3 PSC is the arrangement for profit sharing. The Contract’s share of profit petroleum falls to 15% when the IM value reaches above 2.50. This feature of the KG-DWN-98/3 PSC could distort investment decisions because it might lead to expenditure and production planning decisions that otherwise might not be made ignoring the effect of the PSC.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 11.23

The KG-DWN-98/3 field has a NPV of US$ 2,582.30MM (in January 2005 terms) and US$ 1,702.86MM (in January 2002 terms). These are base case estimates.

Based on results obtained from sensitivity tests, the value of KG-DWN-98/3 project is most sensitive to changes in development costs. The phasing of development expenditure has a large influence over the profit between the contractor and the government.

The Monte Carlo analysis results discussed above show that the NPV of KG-DWN-98/3 field is extremely robust with little risk of the project's value becoming negative because of adverse changes in costs and production.

Sajith Venugopal July 2005 University of New South Wales

Chapter 12

Economics of exploration

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.1

In this chapter, I present the results of economic analyses of exploring for and developing crude oil and gas discoveries in India.

12.1 Objectives

The economic analyses are based on hypothetical, but representative field developments. The objectives for conducting the economic analyses are as set out below x To examine the effects of the Indian fiscal regime. x To show the profitability of field development over a range of reserves and to determine minimum economic reserves for future field development. x To determine the minimum reserves in an undrilled prospect required to justify exploration drilling.

12.2 Cases analysed

The cases analysed are relate to the exploration and development of discoveries in regions adjacent to the fields listed in Table 12.1 below.

Table 12.1 – Cases analysed

Area Product PSC assumption Ravva Oil Shallow Offshore – East coast of India D-1 Oil Shallow Offshore – West coast of India PY-1 Gas Shallow Offshore – East coast of India KG-DWN-98/3 Gas Deepwater Offshore – East coast of India

I make projections of future after tax net cash flows based on hypothetical, but representative field developments. I arrive at the future after tax net cash flows

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.2 based on the assumption that each case study being analysed employs the fiscal and cost assumptions similar to those set out for the field closest to it (refer to Chapters 8, 9, 10 and 11). In other words, I use the fiscal and cost assumptions set out in Chapter 8 when conducting economic analysis of exploring for and developing discoveries in regions close to Ravva field.

I present all the results of my analysis in terms of net present value (“NPV”) of net cash flow per barrel or per thousand cubic feet of reserves.

In a later section of this chapter, I explain the economic and development assumptions and the methodology used for conducting economic analysis.

12.3 Approach

For each of the cases analysed I carry out the following steps x I assume all costs related to exploration and field development to be similar to those set out in chapters describing the economics of the fields listed in Table 12.1 above. x I make assumptions on oil/gas pricing and development cost scheduling. x I carry out cash flow analyses based on the assumption that fiscal terms set out in the Chapters 8, 9, 10 and 11 apply to the respective exploration and field development cases considered. x I conduct sensitivity analyses of field development based on the assumption that a discovery has been made. x I determine the minimum prospect reserves as a function of the probability of drilling success using expected value analyses.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.3

12.4 Assumptions

The economic and field development assumptions made for the economic analyses are as set out below

12.4.1 Economic assumptions

The economic assumptions made for the economic analyses of the base cases are as follows x I assume that the oil price in fiscal year 2004 is US$ 28.00 per barrel and that it escalates at 3% per year beginning in year 2005. Refer to Appendix F. x I assume that the gas price in fiscal year 2004 is US$ 3.00 per thousand cubic feet escalating at 3% per year beginning in year 2005. As suggested in the Energy Market Chapter, gas prices on the east coast of India range between US$ 2.50 per thousand feet and US$ 3.62 per thousand cubic feet. Hence, for the purpose of conducting this study, I have assumed the base case gas price to be the average of the above-mentioned gas prices. x I assume all capital and operating costs to escalate at 3% per year beginning in year 2005. x I calculate the nominal net present values using a discount rate of 10%.

Cost assumptions

I assume that each exploration well in shallow offshore areas will cost US$ 5MM and those drilled in the deepwater areas will cost US$ 20MM. Chapters 8, 9, 10 and 11 gives more information of the exploration expenditure made at the fields listed in Table 12.1.

For the base case economics, I assume the total field development costs to be similar to that set out in Chapters 8, 9, 10 and 11. When analysing the economics of a potential field, for example in regions close to Ravva field, I assume the following

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.4

I relate the development costs of a hypothetical discovery in regions close to the Ravva field to the development cost spend at Ravva. For this, I use the information that I have about the initial peak production rate of Ravva field. I know that Ravva field had an initial peak production rate of 35,000 barrels of oil per day (“bopd”). Hence, I assume that the cost of developing a field with a peak rate of X thousand bopd (“kbopd’) would be

Costs for X kbopd = Costs for 35 kbopd * (X/35)^0.7

Cost assumptions for the other exploration areas are made in a similar way.

Sensitivity assumptions

In the diagrams shown in this chapter, the base case economics are shown as bold curves. The sensitivity analyses show the effect of varying the following key economic input parameters x Oil/gas price x Development costs x Peak well production rate and x Fiscal terms.

Oil and gas prices and the development costs are varied between 70% and 130% of the value considered for base case analysis. This translates to a lower oil price sensitivity of US$ 19.60 per barrel and an upper oil price sensitivity of US$ 36.40 per barrel. Similarly, the lower and upper gas price sensitivities are US$ 2.10 per thousand cubic feet and US$ 3.90 per thousand cubic feet.

I vary the peak well production rate between 50% and 200% of the value considered for the base case.

As regards the fiscal sensitivities, I examine the sensitivity of field development economics to a reduction in the rate of royalty to zero percent and an increase in the

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.5

Contractor’s share of profit oil/gas to 100%. I do not change income tax because it has much less impact as compared the other fiscal terms.

12.4.2 Market assumptions

I assume that there is a market for all gas being produced. The chapter on Energy Market gives details of the projected demand for gas in India.

12.4.3 Exploration and development assumptions

I assume that all exploration spending would be made in the first 3 years of project life.

I have assumed that production in oil field developments would be phased as shown in Table 12.2 below. For gas field developments it has been assumed that production would start in the fifth year of project life and continue at peak rate for 25 years.

For oil field developments I have assumed that 35% of total development costs would be spent in the third year of project life, 30% in the fourth year, 25% in the fifth year and 10% in the sixth year.

For gas field developments I have assumed that 10% of total development costs would be spent in the third year of project life, 50% in the fourth year, 35% in the fifth year and 5% in the sixth year.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.6

Table 12.2 – Appraisal, production and development cost phasing – Oil fields Economic assumptions

Oil price – US$ 28 per barrel (Refer to Appendix D). Exploration cost – Since the oil fields considered are for shallow offshore regions, I assume each exploration or appraisal well to cost US$ 5MM. Development cost – I scale all costs up or down using a 0.7 Power Rule. Development assumptions Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Exploration/Appraisal well phasing fields less than 10 million barrels Number of wells 1 fields less than 50 million barrels Number of wells 2 1 fields less than 100 million barrels Number of wells 2 2 fields greater than 100 million barrels Number of wells 2 2 2

Production phasing fields less than 10 million barrels % of peak* 100% Decline fields less than 50 million barrels % of peak* 50% 100% 100% Decline fields less than 100 million barrels % of peak* 25% 50% 100% 100% 100% 100% Decline fields greater than 100 million barrels % of peak* 25% 50% 100% 100% 100% 100% 100% 100% Decline

Development cost phasing % of total 35% 30% 25% 10% Fiscal assumptions

Royalty rate 10% Royalty rate is 10% of well head value of crude oil. Well head value is assumed to be 80% of gross revenue generated from crude oil sales. Cost recovery ceiling 100% Government’s share of profit oil 10% when Investment Multiple reaches 1.5 20% when Investment Multiple reaches 2.0 30% when Investment Multiple reaches 2.5 40% when Investment Multiple reaches 3.0 50% when Investment Multiple is over 3.5

Income tax rate 41% Tax rate for Foreign companies

*Peak production is assumed to be 5% of initial reserves per year

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.7

Table 12.2 (continued) – Appraisal, production and development cost phasing – Gas fields Economic assumptions

Gas price – US$ 3 per thousand cubic feet (Refer to section 12.4.1). Exploration cost – For gas fields in regions close to PY-1 field (shallow offshore), I assume each exploration or appraisal well to cost US$ 5MM. For gas fields in regions close to KG-DWN-98/3 field (deepwater offshore), I assume each exploration or appraisal well to cost US$ 20.57MM.

Development cost – I scale all costs up or down using a 0.7 Power Rule. Development assumptions Year 1 2 3 4 5 6 7 8 9 101112131415 Exploration/Appraisal well phasing fields less than 10 billion cubic feet Number of wells 1 fields less than 50 billion cubic feet Number of wells 2 1 fields less than 100 billion cubic feet Number of wells 2 2 fields greater than 100 billion cubic feet Number of wells 2 2 2

Production is assumed to be over 25 years fields less than 10 million barrels % of peak* Production is assumed to be at 100% of peak rate for 25 years fields less than 50 million barrels % of peak* Production is assumed to be at 100% of peak rate for 25 years fields less than 100 million barrels % of peak* Production is assumed to be at 100% of peak rate for 25 years fields greater than 100 million barrels % of peak* Production is assumed to be at 100% of peak rate for 25 years

Development cost phasing % of total 10% 50% 35% 5% Fiscal assumptions Royalty rate 5% or 10% For fields in shallow water, royalty rate is 10% of well head value. For those in deepwater areas, royalty rate is 5% of well head value for the first seven years and increases to 10% of well head value thereafter. Well head value is assumed to be 80% of gross revenue generated from gas sales. Cost recovery ceiling 100% Government’s share of profit oil 10% when Investment Multiple reaches 1.5 20% when Investment Multiple reaches 2.0 30% when Investment Multiple reaches 2.5 40% when Investment Multiple reaches 3.0 50% when Investment Multiple is over 3.5

Income tax rate 41% Tax rate for Foreign companies *Peak production is assumed to be 70% multiplied by (Initial gas reserves) divided by (Number of years = 25 in our case)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.8

12.5 Net Present Value per barrel or per thousand cubic feet graphs

The results of the economic analyses are presented as graphs showing the net present value per barrel or per thousand cubic feet. The net present value is based on the nominal after tax net cash flow of the Contractor. Cash flow calculations are carried out from the time a discovery is made until the end of the economic life of field development.

The horizontal axes shows the range of reserves for which the net present value per barrel or per million cubic feet values have been calculated.

Figure 12.1 contains an example set of four such graphs. The graphs show the results obtained when the sensitivities are applied. Each graph shows the results of base case economics as well as the sensitivities.

From the graphs shown in Figure 12.1, we can also identify the minimum economic reserves obtained for the discovery. The minimum economic reserves are the points where the net present value per barrel or per thousand cubic feet becomes zero as reserves are reduced.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.9 0.40

Figure 12.1 – An example of net present value per million cubic feet graphs0.40 0.35

Development costs sensitivity0.35 Gas price sensitivity 0.30

0.30 0.25 0.25 Gas price = US$ 3.90 per Mcf 0.20 Development cost at 70% 0.20 0.15 Gas price = US$ 3.00 per Mcf 0.15 0.10 0.10 p r tho ndcu c feet ( /Mcf) Gas price = US$ 2.10 per Mcf 0.05 Development cost at 130% NPV e usa bi $ Development cost at 100% 0.05 Reserves (Bcf) feet cubic per thousand ($/Mcf)NPV Reserves (Bcf) 0.000.40 0.400.00 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 0.35 Fiscal terms sensitivity0.35 Peak well production sensitivity

0.30 0.30 Profit split at 100% 0.25 0.25 Peak production rate at 200% 0.20 No Royalty 0.20

Peak production rate at 100% 0.15 0.15

0.10 Indian PSC 0.10 Peak production rate at 50%

0.05

NPV per thousand cubic feet ($/Mcf) feet cubic thousand NPV per 0.05 NPV per thousand cubic ($/Mcf) feet Reserves (Bcf) Reserves (Bcf) 0.00 0.00 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.10

12.6 Minimum prospect reserves graphs

The net present value per barrel or per thousand cubic feet graphs are based on the assumption that a discovery has been made. They ignore the risks and costs associated with the exploration required to make a discovery.

In contrast, the minimum prospect reserves graphs incorporate the cost of exploration and risk associated with exploration. They show the minimum prospect reserves versus the probability of drilling success. The minimum prospected reserves graphs are based on the expected value calculations. The expected value is calculated using the net present value derived from cash flow analyses. The expected value indicates whether the decision to drill an exploration well in the area is economically justified or not. The expected value is calculated as follows

(Net present value of development of discovery) * (Probability of success) Expected = less value (Net present value of exploration costs) * (Probability of failure)

A positive expected value indicates that the decision to drill the exploration well is profitable. For the purpose of conducting the analyses, I carry out the following steps x I vary the reserves. x I calculate the net present values of field development for the different reserves cases. x I calculate the expected values for given probabilities of success. x I calculate the minimum prospect reserves for a given probability of success by defining points where the expected value first becomes zero.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.11

Figure 12.2 contains an example set of four minimum prospect reserves graphs. The curves in these graphs show the minimum anticipated prospect reserve size for a given probability of success. Any field size lower than that shown by the curve would result in a negative expected value and therefore should not be drilled.

Each of the four minimum prospect reserves graphs shows the results of base case economics as well as the sensitivities.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.12 Figure 12.2 – An example of minimum reserves graphs 800 800

700 Development costs sensitivity700 Gas price sensitivity

600 600

500 500

400 400 Gas at US $ 2.10 per Mcf 300 300 Development cost at 130% 200 200 Gas at US $ 3.00 per Mcf Gas at US $ 3.90 per Mcf Development cost at 100% 100 100 Minimum prospect reserves (Bcf) reserves prospect Minimum Minimum prospect reserves (Bcf) Development cost at 70% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 800 Probability of drilling success (%) Probability of drilling success (%) 800 Fiscal terms sensitivity Peak well production sensitivity 700 700

600 600

500 500

400 400 Peak production rate at 50%

300 300 Peak production rate at 100% Indian PSC 200 200 No royalty Peak production rate at 200% 100 100 Minimum prospect reserves (Bcf) Minimum prospect (Bcf) Minimum reserves Profit split at 100% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.13

12.7 Offshore eastern India – Ravva area - Oil exploration and field

development economics

Figure 12.3 gives the results of the economic analyses conducted for the base case development of representative oil discoveries in the regions close to the Ravva field – offshore eastern India. The results presented in Figure 12.3 are over a range of field reserves.

Figure 12.4 gives the minimum prospect reserves required to justify exploration drilling for a given probability of success. The minimum prospect reserves for a given probability of drilling success are calculated based on the economics shown in Figure 12.3.

The key results of the economic analyses conducted for the base case field development is given in Table 12.3 below.

Table 12.3 – Base case economic analyses results - Oil offshore eastern India (Ravva area)

Maximum net present value (US$ per barrel) 2.78

Minimum field reserves (Million barrels) 12

Minimum prospect reserves (Million barrels) 17.30 at 20% probability of success

Minimum prospect reserves (Million barrels) 11.70 at 50% probability of success

The results of sensitivity analyses carried out are given in Figure 12.5 and Figure 12.6. The sensitivity analyses are carried out for variations in development costs, oil price, fiscal terms and peak well production rate.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.14

The results represented in Figure 12.5 show that the economics of field development are most sensitive to changes made to the oil price and the fiscal terms. However, the economics are also sensitive to changes in development costs within a +/- 50% range. In contrast, changes made to the peak well production rate parameter triggers minimal changes in field development economics.

The oil price sensitivity graph in Figure 12.5 shows that when the oil price drops to US$ 19.6 per barrel (70% of the base case), the maximum net present value per barrel decreases. At this oil price, the maximum net present value per barrel is US$ 1.73 per barrel as compared to US$ 2.78 per barrel shown in Table 12.3 above.

The fiscal terms sensitivity graph shows that if the Contractor’s share of profit oil was 100%, then the maximum net present value per barrel would be US$ 5.31 per barrel. With very low reserves, the net present value per barrel is at a maximum for fields that operate under a regime with no royalty. This is because royalty is a regressive impost.

Figure 12.6 shows that changes made to the development costs, the oil price and the peak well production rate have a significant impact on exploration economics.

The oil price sensitivity graph in Figure 12.6 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 18 to 47 MMbbls.

The development cost sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 21 to 41 MMbbls.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.15

Figure 12.3 – Base case oil field development economics for offshore eastern India

4 Ravva area

3

2 NPV ($/bbl) barrel per 1

Reserves (MMbbl) 0 0 20 40 60 80 100 120 140

Figure 12.4 – Base case oil exploration economics for offshore eastern India

50 Ravva area

40

30

20

10 Minimum prospect reserves (MMbbl) reserves prospect Minimum

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.16

Figure6 12.5 – Sensitivity of oil field development economics for regions6 near Ravva field (shallow offshore eastern India)

Development costs sensitivity Oil price sensitivity 5 5 Ravva area Ravva area 4 4

3 3 Development cost at 70% Oil price = US$ 36.40 per barrel

2 2 Oil price = US$ 28 per barrel Development cost at 100% NPV per barrel ($/bbl) barrel per NPV NPV per barrel per NPV ($/bbl) 1 1 Development cost at 130% Oil price = US$ 19.60 per barrel 6 6 Reserves (MMbbl) Reserves (MMbbl) 0 0 0 20 40 60 80 100 120 140 0 20 40 60 80 100 120 140 5 5 Fiscal terms sensitivity Peak well production sensitivity Ravva area 4 Ravva area 4

Profit split at 100% 3 3

No Royalty Peak rate at 200% 2 2 NPV per barrel ($/bbl) NPV perNPV ($/bbl) barrel Indian PSC 1 1 Peak rate at 100%

Reserves (MMbbl) Peak rate at 50% Reserves (MMbbl) 0 0 0 20406080100120140 0 20 40 60 80 100 120 140

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.17

Figure 12.6 – Sensitivity of oil exploration economics for regions near Ravva50 field (shallow offshore eastern India) 50

Development costs sensitivity Oil price sensitivity 40 40 Ravva area Ravva area

30 30

Oil at US $ 19.60 per barrel Development cost at 130% 20 20

pr l Oil at US $ 28 per barrel Development cost at 100% 10 10

Development cost at 70%

Minimum prospect reserves prospect (MMbbl) Minimum Oil at US $ 36.40 per barrel Minimum rospect (MMbb eserves ) 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) 50 Probability of drilling success (%) 50 Fiscal terms sensitivity Peak well production sensitivity

40 Ravva area 40 Ravva area

30 30

Peak production at 50%

20 20 Indian PSC Peak production at 100%

Profit split at 100% 10 10 ium r (M Peak production at 200% Min m prospect eserves M bbl) No royalty Minimum prospect Minimum reserves (MMbbl) 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.18

12.8 Offshore western India – D-1 area - Oil exploration and field

development economics

Figure 12.7 gives the results of the economic analyses for the base case development of representative oil discoveries in the regions close to the D-1 field – offshore western India. The results presented in Figure 12.7 are over a range of field reserves. The discontinuities in the curve relate to the particular production profiles assumed and have no significance in the context of this exercise.

Figure 12.8 gives the minimum prospect reserves required to justify exploration drilling for a given probability of success. These are calculated based on the economics shown in Figure 12.7.

The key results of the economic analyses conducted for the base case field development is given in Table 12.4 below.

Table 12.4 – Base case economic analyses results - Oil offshore western India (D-1 area)

Maximum net present value (US$ per barrel) 3.18

Minimum field reserves (Million barrels) 4

Minimum prospect reserves (Million barrels) 10 at 20% probability of success

Minimum prospect reserves (Million barrels) 6 at 50% probability of success

The results of sensitivity analyses carried out are given in Figure 12.9 and Figure 12.10. The sensitivity analyses are carried out for changes made to the development costs, the oil price, the fiscal terms and the peak well production rate.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.19

The results shown in Figure 12.9 show that the economics of field development are most sensitive to changes made to the oil price and the fiscal terms. Field development is found to be relatively insensitive to changes made to development costs and peak well production rate.

The oil price sensitivity graph in Figure 12.9 shows that when the oil price drops to US$ 19.6 per barrel (70% of the base case), the maximum net present value per barrel decreases to US$ 2.14 per barrel as compared to US$ 3.18 per barrel shown in Table 12.4 above.

The fiscal terms sensitivity graph shows that if the Contractor’s share of profit oil were 100%, then the maximum net present value per barrel would be US$ 6.40 per barrel. For very low field reserves, the net present value per barrel is at a maximum for fields that operate under a regime with no royalty. However, over the full range of reserves considered, the elimination of royalty has a smaller effect on field economics than the elimination of profit oil sharing.

Figure 12.10 shows that changes made to the oil price have a significant impact on exploration economics. The economics of exploration are sensitive to adverse changes made to the development cost within a +/- 20% range. However, they are found to be largely insensitive to the changes made on the peak well production rate or the fiscal terms.

The oil price sensitivity graph in Figure 12.10 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 12 to 39 MMbbls.

The development cost sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 17 to 23 MMbbls.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.20

Figure 12.7 – Base case oil field development economics for offshore western India

4 D-1 area

3

2 NPV per barrel ($/bbl) barrel NPV per 1

Reserves (MMbbl) 0 0 20 40 60 80 100 120 140

Figure 12.8 – Base case oil exploration economics for offshore western India

50 D-1 area

40

30

20

10 Minimum prospect reserves (MMbbl) reserves prospect Minimum

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.21 Figure 12.9 – Sensitivity of oil field development economics for regions near D-1 field (shallow offshore western India) 7 7 Development costs sensitivity Oil price sensitivity 6 D-1 area 6 D-1 area 5 5

4 4

Development cost at 70% 3 Oil price = US$ 36.40 per barrel 3

Oil price = US$ 28 per barrel 2 Development cost at 130% 2 NPV per barrel ($/bbl) barrel NPV per NPV per ($/bbl) barrel Development cost at 100%

1 1 Oil price = US$ 19.60 per barrel 7 Reserves (MMbbl) Reserves (MMbbl) 7 0 0 6 0 20406080100120140 0 20406080100120140 6 Fiscal terms sensitivity Peak well production sensitivity 5 D-1 area 5 D-1 area

4 Profit split at 100% 4

3 No Royalty 3 Peak rate at 200%

2 2 NPV per ($/bbl) barrel Indian PSC NPV per ($/bbl) barrel Peak rate at 100% 1 1 Peak rate at 50% Reserves (MMbbl) Reserves (MMbbl) 0 0 0 20 40 60 80 100 120 140 0 20 40 60 80 100 120 140

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.22 Figure 12.10 – Sensitivity of oil exploration economics for regions near D-1 field (shallow offshore western India) 50 50

Development costs sensitivity Oil price sensitivity 40 40 D-1 area D-1 area 30 30

20 20 Oil at US $ 19.60 per barrel

Development cost at 130% Oil at US $ 28 per barrel

10 Development cost at 100% 10 Oil at US $ 36.40 per barrel Minimum prospect reserves prospect Minimum (MMbbl) Minimum prospect reserves (MMbbl) reserves prospect Minimum Development cost at 70% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) Probability of drilling success (%) 50 50 Fiscal terms sensitivity Peak well production sensitivity

40 D-1 area 40 D-1 area

30 30

20 20

pevb Indian PSC Peak production at 100%

10 10 Peak production at 50% Profit split at 100% Minimum rospect r ser es (MM bl) No royalty Minimum prospect reserves (MMbbl) reserves prospect Minimum Peak production at 200% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) Probability of drilling success (%) Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.23

12.9 Offshore eastern India – PY-1 area - Gas exploration and field

development economics

Figure 12.11 gives the results of the economic analyses for the base case development of representative oil discoveries in the regions close to the PY-1 field – offshore eastern India. The results presented in Figure 12.11 are over a range of field reserves.

Figure 12.12 gives the minimum prospect reserves required to justify exploration drilling for a given probability of success. These are calculated based on the economics shown in Figure 12.11.

The key results of the economic analyses for the base case field development are given in Table 12.5 below.

Table 12.5 – Base case economic analyses results - Gas offshore eastern India (PY-1 area)

Maximum net present value (US$ per thousand cubic feet) 0.17

Minimum field reserves (Billion cubic feet) 63

Minimum prospect reserves (Billion cubic feet) 138 at 20% probability of success

Minimum prospect reserves (Billion cubic feet) 75 at 50% probability of success

The results of sensitivity analyses are given in Figure 12.13 and Figure 12.14. The sensitivity analyses are carried out for changes made to the development costs, the gas price, the fiscal terms and the peak well production rate.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.24

The results in Figure 12.13 show that the economics of field development are most sensitive to changes made to the gas price and the fiscal terms. They are less sensitive to changes made to the peak well production rate as well as to development costs within a +/- 50% range.

The gas price sensitivity graph in Figure 12.13 shows that when the gas price increases to US$ 3.90 per thousand cubic feet (130% of the base case), the maximum net present value per thousand cubic feet increases to US$ 0.27 per thousand cubic feet as compared to US$ 0.17 per thousand cubic feet shown in Table 12.5 above.

The fiscal terms sensitivity graph shows that if the Contractor’s share of profit gas were 100%, then the maximum net present value per thousand cubic feet would be US$ 0.34 per thousand cubic feet. At very low reserves, the net present value per thousand cubic feet is at a maximum for fields that operate under a regime with no royalty. However, across the full range of reserves considered, the elimination of royalty has a smaller effect on field economics than the elimination of profit petroleum sharing.

Figure 12.14 shows that changes made to the gas price have a significant impact on exploration economics. The economics are also sensitive to changes made to the peak well production rate and are affected significantly when the peak well production rate falls to 50% of the base case value. They are less sensitive to changes made to the development costs and the fiscal terms.

The gas price sensitivity graph in Figure 12.14 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 200 to 700 Bcf.

The peak well production rate sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 200 to 500 Bcf.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.25

Figure 12.11 – Base case gas field development economics for offshore eastern India

0.40 PY-1 area 0.35

0.30

0.25

0.20

0.15

0.10

NPV per thousand cubic feet ($/Mcf) feet cubic thousand NPV per 0.05 Reserves (Bcf) 0.00 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560

Figure 12.12 – Base case gas exploration economics for offshore eastern India

800 PY-1 area 700

600

500

400

300

200

Minimum prospect reserves (Bcf) 100

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.26 Figure 12.13 – Sensitivity of gas field development economics for regions near PY-1 field (shallow offshore eastern India) 0.40 0.40

0.35 Development costs sensitivity0.35 Gas price sensitivity

0.30 PY-1 area 0.30 PY-1 area

0.25 0.25 Gas price = US$ 3.90 per Mcf 0.20 Development cost at 70% 0.20

Gas price = US$ 3.00 per Mcf 0.15 0.15

0.10 0.10

per t per f nd cubic et /Mcf) Gas price = US$ 2.10 per Mcf 0.05 Development cost at 130% 0.05 NPV housa e ($ 0.40 Development cost at 100% Reserves (Bcf) NPV per thousand cubic feet ($/Mcf) 0.40 Reserves (Bcf) 0.00 0.00 0.35 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 0.35 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 Fiscal terms sensitivity Peak well production sensitivity 0.30 PY-1 area 0.30 PY-1 area Profit split at 100% 0.25 0.25 Peak production rate at 200% 0.20 0.20 No Royalty Peak production rate at 100% 0.15 0.15

0.10 0.10 Indian PSC Peak production rate at 50%

PV pe0.05 ousand i $ 0.05 NPV per thousand cubic ($/Mcf) feet N r th cub ( c feet /Mcf) Reserves (Bcf) Reserves (Bcf) 0.00 0.00 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.27

Figure 12.14 – Sensitivity of gas exploration economics for regions near800 PY-1 field (shallow offshore eastern India) 800

700 700 Development costs sensitivity Gas price sensitivity 600 600 PY-1 area PY-1 area 500 500

400 400 Gas at US $ 2.10 per Mcf 300 300 Development cost at 130%

m prospectm reserves200 cf) 200 Gas at US $ 3.00 per Mcf Gas at US $ 3.90 per Mcf Development cost at 100% 100 100 Minimum prospect Minimum (Bcf) reserves

MinimuDevelopment cost at (B 70% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 800 Probability of drilling success (%) 800 Probability of drilling success (%) Fiscal terms sensitivity Peak well production sensitivity 700 700

600 PY-1 area 600 PY-1 area

500 500

400 400 Peak production rate at 50% 300 300 Peak production rate at 100%

pro pe reserves cf) Indian PSC 200 200 Peak production rate at 200% No royalty mum s ct (B

ni 100 100 Minimum prospect reserves (Bcf) reserves prospect Minimum Mi Profit split at 100% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.28

12.10 Offshore eastern India – KG-DWN-98/3 area - Gas exploration and

field development economics

Figure 12.15 gives the results of the economic analyses conducted for the base case development of representative oil discoveries in the regions close to the KG-DWN- 98/3 field – deepwater offshore eastern India. The results presented in Figure 12.15 are over a range of field reserves.

Figure 12.16 gives the minimum prospect reserves required to justify exploration drilling for a given probability of success. These are calculated based on the economics shown in Figure 12.15.

The key results of the economic analyses of the base case are given in Table 12.6 below.

Table 12.6 – Base case economic analyses results - Gas offshore eastern India (KG-DWN-98/3 area)

Maximum net present value (US$ per thousand cubic feet) 0.25

Minimum field reserves (Billion cubic feet) 1400

Minimum prospect reserves (Billion cubic feet) 1100 at 20% probability of success

Minimum prospect reserves (Billion cubic feet) 840 at 50% probability of success

The results of sensitivity analyses are given in Figure 12.17 and Figure 12.18. The sensitivity analyses show the effect of variations in development costs, gas price, fiscal terms and peak well production rate.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.29

The results in Figure 12.17 show that the economics of field development are most sensitive to changes made to the fiscal terms and the peak well production rate. However, to a lesser extent they are sensitive to changes made to the gas price and to changes made to development costs within a +/- 50% range.

The gas price sensitivity graph in Figure 12.17 shows that when the gas price increases to US$ 3.90 per thousand cubic feet (130% of the base case), the maximum net present value per thousand cubic feet increases to US$ 0.34 per thousand cubic feet as compared to US$ 0.25 per thousand cubic feet shown in Table 12.6 above.

The fiscal terms sensitivity graph shows that if the Contractor’s share of profit gas were 100%, then the maximum net present value per thousand cubic feet would be US$ 0.47 per thousand cubic feet. By comparison, the elimination of royalty has a smaller effect on field economics than the elimination of profit petroleum sharing.

Figure 12.18 shows that changes made to the gas price and the peak well production rate have a significant impact on exploration economics. The economics are less sensitive to changes made to the development costs. At low reserves, exploration economics is almost insensitive to changes made to fiscal terms.

The gas price sensitivity graph in Figure 12.18 shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 990 to 2,800 Bcf.

The peak well production rate sensitivity graph shows that at 10% probability of drilling success, the range of minimum prospect reserves varies between 1,000 to 2,800 Bcf.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.30

Figure 12.15 – Base case gas field development economics for deepwater offshore eastern India

0.40

0.35 KG-DWN-98/3 area

0.30

0.25

0.20

0.15

0.10

NPV per thousand cubic feet ($/Mcf) feet cubic thousand NPV per 0.05 Reserves (Bcf)

0.00 0 2000 4000 6000 8000 10000 12000 14000

Figure 12.16 – Base case gas exploration economics for deepwater offshore eastern India

4000

3500 KG-DWN-98/3 area

3000

2500

2000

1500

1000

Minimum prospect reserves prospect Minimum (Bcf) 500

0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.31

Figure0.45 12.17 – Sensitivity of gas field development economics for regions near KG-DWN-98/3 field (deepwater offshore eastern India) 0.45

0.40 Development costs sensitivity0.40 Gas price sensitivity 0.35 0.35 KG-DWN-98/3 area KG-DWN-98/3 area 0.30 0.30 Development cost at 70% 0.25 0.25 Gas price = US$ 3.90 per Mcf 0.20 0.20

0.15 0.15 Gas price = US$ 3.00 per Mcf Development cost at 130% 0.10 0.10 Gas price = US$ 2.10 per Mcf

NPV per($/Mcf) feet cubic thousand 0.05

NPV per thousand cubic feet ($/Mcf) 0.05 Development cost at 100% Reserves (Bcf) Reserves (Bcf) 0.00 0.00 0.45 0.45 0 2000 4000 6000 8000 10000 12000 14000 0 2000 4000 6000 8000 10000 12000 14000 0.40 0.40 Fiscal terms sensitivity Peak well production sensitivity

0.35 0.35 Profit split at 100% KG-DWN-98/3 area 0.30 KG-DWN-98/3 area 0.30 Peak production rate at 200% 0.25 0.25

No Royalty 0.20 0.20

0.15 0.15 Peak production rate at 100% Indian PSC

0.10 0.10 NPV thousand per ($/Mcf) feet cubic NPV per ($/Mcf) feet cubic thousand 0.05 0.05 Reserves (Bcf) Peak production rate at 50% Reserves (Bcf) 0.00 0.00 0 2000 4000 6000 8000 10000 12000 14000 0 2000 4000 6000 8000 10000 12000 14000

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.32 Figure 12.18 – Sensitivity of gas exploration economics for regions near KG-DWN-98/3 field (deepwater offshore eastern India) 4000 4000 3500 3500 Development costs sensitivity Gas price sensitivity

3000 3000 KG-DWN-98/3 area KG-DWN-98/3 area 2500 2500 Gas at US $ 2.10 per Mcf 2000 2000 Development cost at 130% Development cost at 100% Gas at US $ 3.00 per Mcf 1500 1500

1000 1000 Gas at US $ 3.90 per Mcf

500 500 Minimum prospect reserves (Bcf) reserves prospect Minimum

Minimum prospect reserves (Bcf) Development cost at 70% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) Probability of drilling success (%) 4000 4000 3500 Fiscal terms sensitivity Peak well production sensitivity 3500 3000 KG-DWN-98/3 area 3000 KG-DWN-98/3 area 2500 2500 Peak production rate at 50% 2000 2000

1500 Peak production rate at 100% 1500 Indian PSC 1000 Profit split at 100% 1000

500 500 Minimum prospect reserves (Bcf) prospect Minimum reserves Minimum prospect reserves (Bcf) No royalty Peak production rate at 200% 0 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Probability of drilling success (%) Probability of drilling success (%)

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.33

12.11 Summary and conclusions

This chapter discusses the economics of field development and exploration in representative areas across India. The areas analysed are regions close to the Ravva oil field (shallow offshore, east coast), the D-1 oil field (shallow offshore, west coast), the PY-1 gas field (shallow offshore, east coast) and the KG-DWN-98/3 gas field (deepwater, east coast). The economic analyses was conducted using an oil price of US$ 28 per barrel and a gas price of US$ 3 per giga joule.

Based on the results of the economic analyses I conclude that the minimum field reserves needed to justify field development of an oil field in shallow water areas is lower for fields located on the west coast than on the east coast of India. This is mainly due to the variations in well costs, production rates and other development assumptions.

In the case of gas field developments on the east coast, I conclude that the minimum economic field reserves required to justify gas field development in shallow water areas of India is significantly smaller as compared to that in the deepwater regions. This is because the economics of exploration require significantly larger discoveries to overcome the larger costs of exploration and development involved with deepwater fields.

Sensitivity analyses revealed the following when changes were made to key parameters such as the development costs, the oil/gas price, the peak well production rates and the fiscal terms

Development cost sensitivity

When changes were made to the development costs, it was found that field development economics in regions around the Ravva oil field, the PY-1 gas field and the KG-DWN-98/3 gas field was affected within a +/- 50% range. Changes made to the development costs had little or no affect on the field development economics of fields in regions close to the D-1 field.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page 12.34

Oil/Gas price sensitivity

It was found that changes to the oil/gas prices had a large impact on field development economics of all the cases that were analysed. This behaviour could be linked to the volatility of the energy market in India. This is because price determines the gross revenue from field development.

Peak well production sensitivity

Changing the peak well production rates had minimal impact on the economics of developing oil fields in areas close to Ravva and D-1. However, it had a significant impact on the economics of developing gas fields in regions close to PY-1 and KG- DWN-98/3 fields. This is because of the larger production plateaus that are assumed for gas field developments as compared to those assumed for oil developments.

Fiscal terms sensitivity

It was found that changes made to the fiscal terms had more or less the same impact on the economics of field development in all of the cases analysed. Across the range of reserves considered, the elimination of royalty had a smaller effect on field economics than the elimination of profit petroleum sharing. However, eliminating royalty was more beneficial to the development of small fields.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page A.1

Appendix A – Sedimentary basins of India

Table A.1 – Category wise classification of sedimentary basins of India

Category Name of Basin Area (square kilometers) Onland Offshore Total

I Cambay 51,000 2,500 53,500 Assam Shelf 56,000 ------56,000 Rajashtan 126,000 ------126,000 Mumbai Offshore ------116,000 116,000 Krishna Godavari 28,000 24,000 52,000 Cauvery 25,000 30,000 55,000 Assam-Arakan Fold Belt 60,000 ------60,000 Sub Total 346,000 172,500 518,500

II Kutch 35,000 13,000 48,000 Andaman-Nicobar 6,000 41,000 47,000 Sub Total 41,000 54,000 95,000

III Himalayan Foreland 30,000 ------30,000 Ganga Valley 186,000 ------186,000 Vidhyan 162,000 ------162,000 Saurashtra 52,000 28,000 80,000 Lakshadweep ------94,000 94,000 Mahanadi 55,000 14,000 69,000 Bengal 57,000 32,000 89,000 Sub Total 542,000 168,000 710,000

IV Karewa 3,700 ------3,700 Spiti-Zanskar 22,000 ------22,000 Satpura-South Rewa-Damodar 46,000 ------46,000 Narmada 17,000 ------17,000 Deccan Syneclise 273,000 ------273,000 Bhima-Kaladgi 8,500 ------8,500 Cuddapah 39,000 ------39,000 Pranhita-Godavari 15,000 ------15,000 Bastar 5,000 ------5,000 Chhattisgarh 32,000 ------32,000 Sub Total 461,200 ------461,200

Total 1,390,200 394,500 1,784,700

Deep water (beyond 400 meter water depth) 1,350,000 1,350,000

Grand Total 1,390,200 1,744,500 3,134,700

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page B.1

Appendix B – Conversions

Length 1 metre = 3.281 feet = 39.37 inches 1 kilometre = 0.621 miles

Volume 1 barrel = 0.159 cubic metres 1 cubic metre = 35.31 cubic feet

Volume/ weight equivalents Crude oil 1 metric tonne = 7.33 barrels LPG liquids 1 metric tonne = 11.60 barrels Naphtha 1 metric tonne = 8.50 barrels Motor Spirit 1 metric tonne = 8.45 barrels Kerosene Oil 1 metric tonne = 7.74 barrels Diesel 1 metric tonne = 7.46 barrels Furnace/Fuel Oil 1 metric tonne = 6.66 barrels Bitumen 1 metric tonne = 6.08 barrels Light Distillates (pool) 1 metric tonne = 7.76 barrels Middle Distillates (pool) 1 metric tonne = 7.50 barrels Heavy Distillates (pool) 1 metric tonne = 7.76 barrels

Gas, oil and equivalent fuel values 1 barrel of oil equivalent = 5,500 to 6,000 cubic feet of natural gas 1 tonne of petroleum products = 1.060 metric tonne of oil equivalent 1 tonne coal = 0.615 metric tonne of oil equivalent 1 trillion cubic feet of gas (TCF) = 23.31 million metric tonne of oil equivalent

Source – International Energy Agency Statistics. Ministry of Petroleum and Natural Gas, India.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page C.1

Appendix C – Blocks offered under NELP

In this appendix, I give a list of all the blocks offered during various bidding rounds of the New Exploration Licensing Policy (“NELP”).

NELP 1 A total of 24 blocks were offered under the first round of bidding of NELP. Of these, 3 blocks have been relinquished. Details of all blocks offered under NELP 1 are given in Table C.1 below.

Table C.1 – Blocks offered under first round of NELP

Date of Sl. Awardee+ Signing Area No Basin Block Name (Participating Interest) Contract (Sq.Km) Offshore - Deep water 1 Krishna Godavari KG-DWN-98/1 RIL (100) 12-04-2000 10,810 2 - Do - KG-DWN-98/2 CEIL (100) 12-04-2000 7,438 3 - Do - KG-DWN-98/3 RIL (90) & NIKO (10) 12-04-2000 7,645 4 - Do - KG-DWN-98/4 ONGC (85) & OIL (15) 12-04-2000 7,455 5 - Do - KG-DWN-98/5 ONGC (100) 12-04-2000 6,735 6 Mahanadi - NEC MN-DWN-98/2 RIL (100) 12-04-2000 7,195 7 - Do - MN-DWN-98/3 ONGC (100) 12-04-2000 7,492 Total Area 54,770 Offshore – Shallow 8 Gujarat – Kutch GK-OSN-97/1 RIL (100) 12-04-2000 1,465 9 Saurashtra SR-OSN-97/1 RIL (100) 12-04-2000 5,040 10 Mumbai MB-OSN-97/3 RIL (100) 12-04-2000 5,740 11 - Do - MB-OSN-97/4 ONGC (70) & IOC (30) 12-04-2000 13,954 12 - Do - MB-OSN-97/2 RIL & NIKO * ------13 Kerala – Konkan KK-OSN-97/2 RIL (100) 12-04-2000 19,450 14 - Do - KK-OSN-97/3 ONGC * ------15 Cauvery CY-OSN-97/1 MIL (35). HOEC (30) & EEIPL 08-01-2001 3,705 (35) 16 - Do - CY-OSN-97/2 OIL * ------17 Krishna Godavari KG-OSN-97/4 RIL (100) 12-04-2000 4,020 18 - Do - KG-OSN-97/3 RIL (100) 12-04-2000 2,460 19 - Do - KG-OSN-97/2 RIL (100) 12-04-2000 4,790 20 - Do - KG-OSN-97/1 ONGC (100) 12-04-2000 2,785 21 Mahanadi – NEC MN-OSN-97/3 ONGC (85) & GAIL (15) 12-04-2000 4,065 22 - Do - NEC-OSN-97/2 RIL (90) & NIKO (10) 12-04-2000 10,755 23 - Do - NEC-OSN-97/1 OAO GAZPROM (50) & GAIL 03-10-2000 7,779 (50) Total Area 86,008 Onshore 24 Ganga Valley GV-ONN-97/1 ONGC (70) & IOC (30) 12-04-2000 27,562 Total Area 27,562 Grand Total 168,340 * Blocks were relinquished, + Refer to Table C.7 for company names Source: 2003-2004 Annual Report, Directorate General of Hydrocarbons, India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page C.2

NELP 2

A total of 23 blocks were offered under the second round of bidding of NELP. Of these, 5 blocks have been relinquished. Details of all blocks offered under NELP 2 are given in Table C.2 below.

Table C.2 – Blocks offered under second round of NELP

Awardee+ Date of Sl. (Participating Signing Area No Basin Block Name Interest) Contract (Sq.Km) Offshore - Deep water 1 Kerala – Konkan KK-DWN-2000/1 RIL (100) 17-07-2001 18,113 2 - Do - KK-DWN-2000/2 ONGC & GAIL * ------3 - Do - KK-DWN-2000/3 RIL (100) 17-07-2001 14,889 4 - Do - KK-DWN-2000/4 ONGC (100) 17-07-2001 26,149 5 Gujarat - Saurashtra GS-DWN-2000/1 ONGC (100) 17-07-2001 13,937 6 - Do - GS-DWN-2000/2 ONGC (85) & GAIL (15) 17-07-2001 14,825 7 Mumbai MB-DWN-2000/1 ONGC (85) & IOC (15) 17-07-2001 11,239 8 - Do - MB-DWN-2000/2 ONGC (50), IOC (15), OIL (10), 17-07-2001 19,106 GAIL (15) & GSPCL (10) Total Area 118,258 Offshore – Shallow 9 Gujarat – Saurashtra GS-OSN-2000/1 RIL (90) & HEPI (10) 17-07-2001 8,841 10 Mumbai MB-OSN-2000/1 ONGC (75), IOC (15) & 17-07-2001 18,414 GSPC (10) 11 Kerala – Konkan KK-OSN-2000/1 ONGC * ------12 Cauvery CY-OSN-2000/1 ONGC (100) 17-07-2001 4,400 13 - Do - CY-OSN-2000/2 ONGC (100) 17-07-2001 3,530 14 Bengal WB-OSN-2000/1 ONGC (85) & IOC (15) 17-07-2001 6,700 15 Mahanadi – NEC MN-OSN-2000/1 ONGC (100) 17-07-2001 5,047 16 - Do - MN-OSN-2000/2 ONGC (40), IOC (20), GAIL 17-07-2001 6,199 (20) & OIL (20) Total Area 53,171 Onshore 17 Ganga Valley GV-ONN-2000/1 ONGC & IOC * ------18 West Bengal WB-ONN-2000/1 ONGC & IOC * ------19 Rajasthan RJ-ONN-2000/1 OIL (100) 17-07-2001 2,535 20 Assam – Arakan AS-ONN-2000/1 RIL (90) & HEPI (10) 17-07-2001 6,215 21 Cambay CB-ONN-2000/1 GSPCL (60) & GAIL (40) 17-07-2001 1,424 22 CB-ONN-2000/2 NIKO * ------23 Mahanadi MN-ONN-2000/1 OIL (40), IOC (20), GAIL 17-07-2001 7,900 (20) & ONGC (20) Total Area 18,074 Grand Total 189,503 * Blocks were relinquished, + Refer to Table C.7 for company names Source: 2003-2004 Annual Report, Directorate General of Hydrocarbons, India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page C.3

NELP 3

A total of 23 blocks were offered under the third round of bidding of NELP. Details of all blocks offered under NELP 3 are given in Table C.3 below.

Table C.3 – Blocks offered under third round of NELP

Awardee+ Date of Sl. (Participating Signing Area No Basin Block Name Interest) Contract (Sq.Km) Offshore - Deep water 1 Kerala – Konkan KK-DWN-2001/1 RIL (90) & HEPI (10) 04-02-2003 27,315 2 - Do - KK-DWN-2001/2 RIL (90) & HEPI (10) 04-02-2003 31,515 3 - Do - KK-DWN-2001/3 ONGC (100) 04-02-2003 21,775 4 Cauvery CY-DWN-2001/1 ONGC (80) & OIL (20) 04-02-2003 12,425 5 - Do - CY-DWN-2001/2 RIL (90) & HEPI (10) 04-02-2003 14,325 6 Cauvery - Palar CY-PR-DWN-2001/3 RIL (90) & HEPI (10) 04-02-2003 8,600 7 - Do - CY-PR-DWN-2001/4 RIL (90) & HEPI (10) 04-02-2003 10,590 8 Palar PR-DWN-2001/1 RIL (90) & HEPI (10) 04-02-2003 8,255 9 Krishna Godavari KG-DWN-2001/1 RIL (90) & HEPI (10) 04-02-2003 11,605 Total Area 146,405 Offshore – Shallow 10 Gujarat – Saurashtra GS-OSN-2001/1 ONGC (100) 04-02-2003 9,468 11 Kerala – Konkan KK-OSN-2001/2 ONGC (100) 04-02-2003 14,120 12 - Do - KK-OSN-2001/3 ONGC (100) 04-02-2003 8,595 13 Krishna Godavari KG-OSN-2001/1 RIL (90) & HEPI (10) 04-02-2003 1,100 14 - Do - KG-OSN-2001/2 RIL (90) & HEPI (10) 04-02-2003 210 15 - Do - KG-OSN-2001/3 GSPCL (80), GEO (10) & 04-02-2003 1,850 JEPL (10) Total Area 35,343 Onshore 16 Assam – Arakan AA-ONN-2001/1 ONGC (100) 04-02-2003 3,010 17 - Do - AA-ONN-2001/2 ONGC (80) & IOC (20) 04-02-2003 5,340 18 - Do - AA-ONN-2001/3 ONGC (85) & OIL (15) 04-02-2003 110 19 - Do - AA-ONN-2001/4 ONGC (100) 04-02-2003 645 20 Himalayan HF-ONN-2001/1 ONGC (100) 04-02-2003 3,175 Foreland 21 Rajasthan RJ-ONN-2001/1 OIL (70) & ONGC (30) 04-02-2003 3,507.11 22 Cambay CB-ONN-2001/1 ONGC (100) 04-02-2003 215 23 Pranhita - Godavari PG-ONN-2001/1 ONGC (100) 04-02-2003 6,920 Total Area 22,922.11 Grand Total 204,670.11 + Refer to Table C.7 for company names Source: 2003-2004 Annual Report, Directorate General of Hydrocarbons, India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page C.4

NELP 4

A total of 20 blocks were offered under the fourth round of bidding of NELP. Details of all blocks offered under NELP 4 are given in Table C.4 below.

Table C.4 – Blocks offered under fourth round of NELP

Date of Sl. Awardee+ Signing Area No Basin Block Name (Participating Interest) Contract (Sq.Km) Offshore - Deep water 1 Gujarat – Saurashtra GS-DWN-2002/1 ONGC (100) 06-02-2004 21,450 2 Kerala – Konkan KK-DWN-2002/2 ONGC (80) & HPCL (20) 06-02-2004 22,810 3 - Do - KK-DWN-2002/3 ONGC (80) & HPCL (20) 06-02-2004 20,910 4 Krishna Godavari KG-DWN-2002/1 ONGC (70), OIL (20) & BPCL 06-02-2004 10,600 (10) 5 Mahanadi – NEC MN-DWN-2002/1 ONGC (70), OIL (20) & BPCL 06-02-2004 9,980 (10) 6 - Do - MN-DWN-2002/2 ONGC (100) 06-02-2004 11,390 7 - Do - NEC-DWN-2002/1 RIL (90) & HEPI (10) 06-02-2004 25,565 8 - Do - NEC-DWN-2002/2 ONGC (100) 06-02-2004 15,465 9 Andaman - Nicobar AN-DWN-2002/1 ONGC (100) 06-02-2004 10,990 10 - Do - AN-DWN-2002/2 ONGC (100) 06-02-2004 12,495 Total Area 161,655 Onshore 11 Assam – Arakan AA-ONN-2002/1 GAIL (80) & ENPRO FINANCE 06-02-2004 1,680 (20) 12 - Do - AA-ONN-2002/3 ONGC (70) & OIL (30) 06-02-2004 1,460 13 - Do - AA-ONN-2002/4 ONGC (90) & OIL (10) 06-02-2004 1,060 14 Ganga Valley GV-ONN-2002/1 CPIL (50) & CESL (50) 06-02-2004 15,550 15 Rajasthan RJ-ONN-2002/1 OIL (60) & ONGC (40) 06-02-2004 9,900 16 Cambay CB-ONN-2002/1 ONGC (70) & CEGB1 (30) 06-02-2004 135 17 - Do - CB-ONN-2002/2 JEPL (30), GSPCL (60) & GGR 06-02-2004 125 (Part A & B) (10) 18 - Do - CB-ONN-2002/3 GSPCL (55), JEPL (20), PPCL 06-02-2004 285 Part (A & B) (15) & GGR (10) 19 Cauvery CY-ONN-2002/1 ENPRO FINANCE (30), GAIL 06-02-2004 680 (50) & GSPCL (20) 20 CY-ONN-2002/1 ONGC (60) & BPCL (40) 06-02-2004 280 Total Area 31,155 Grand Total 192,810 + Refer to Table C.7 for company names Source: 2003-2004 Annual Report, Directorate General of Hydrocarbons, India

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page C.5

NELP 5

A total of 20 blocks were offered under the fifth round of bidding of NELP. Details of all blocks offered under NELP 5 are given in Table C.5 below. At the time of writing, no company had placed any bids for any of the blocks listed below.

Table C.5 – Blocks offered under fifth round of NELP

Sl. Area No Basin Block Name (Sq.Km)

Offshore - Deep water 1 Kerala - Konkan KK-DWN-2003/1 18,245 2 - Do - KK-DWN-2003/2 12,285 3 Krishna Godavari KG-DWN-2003/1 3,288 4 Mahanadi MN-DWN-2003/1 17,050 5 Andaman - Nicobar AN-DWN-2003/1 9,970 6 - Do - AN-DWN-2003/2 13,110 Total Area 73,948 Offshore – Shallow 7 Cambay CB-OSN-2003/1 2,394 8 Saurashtra GS-OSN-2003/1 5,970 Total Area 8,364 Onshore 9 Assam – Arakan AA-ONN-2003/1 81 10 - Do - AA-ONN-2003/2 295 11 - Do - AA-ONN-2003/3 275 12 Ganga Valley GV-ONN-2003/1 7,210 13 Vindhyan VN-ONN-2003/1 3,585 14 Rajasthan RJ-ONN-2003/1 1,335 15 - Do - RJ-ONN-2003/2 13,195 16 Cambay CB-ONN-2003/1 635 (Part A & B) 17 - Do - CB-ONN-2003/2 448 18 Deccan Syneclise DS-ONN-2003/1 3,155 19 Krishna Godavari KG-ONN-2003/1 1,697 20 Cauvery CY-ONN-2003/1 957 Total Area 32,868 Grand Total 115,180

Source: NELP V, Ministry of Petroleum & Natural Gas website

Table C.6 below gives a summary of blocks offered/under operation after various NELP bidding rounds.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page C.6

Table C.6 – Summary of blocks offered under NELP

Rounds Blocks Offered PSC Signed Under Operation

NELP 1 24 24 21

NELP 2 23 23 18

NELP 3 23 23 23

NELP 4 20 20 20

NELP 5 20 ------

Total 110 90 82

A complete list of all the Company names is given in Table C.7 below in an alphabetical order.

Table C.7 – Company names

BPCL - Bharat Petroleum Corporation Limited CEGB1 - Cairn Energy Gujarat Block – 1 CEIL - Cairn Energy India Private Limited CESL - Cairn Energy Search Limited CPIL - Cairn Petroleum India Limited EEIPL - Energy Equity India Petroleum Private Limited ENPRO FINANCE - Enpro Finance Private Limited GAIL - Gas Authority of India Limited GEO - Geo Global Resources (India) Incorporated GEECL - Great Eastern Energy Corporation Limited GGR - Geo Global Resources (Barbados) Incorporated GSPCL - Gujarat State Petroleum Corporation Limited HEPI - Hardy Exploration & Production (India) Incorporated HPCL - Hindustan Petroleum Corporation Limited IOC - Indian Oil Corporation Limited JEPL - Jubilant Enpro Private Limited MIL - Mosbacher India LLC NIKO - Niko Resources Limited OIL - Oil India Corporation Limited ONGC - Oil & Natural Gas Corporation Limited PPCL - Prize Petroleum Company Limited RIL - Reliance Industries Limited

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page D.1

Appendix D – Oil price assumption

I have chosen to use a US$ 28 per bbl as the real oil price in year 2004 terms for all the bases case economic analyses carried out for this thesis. The background and basis for this assumption is set out below.

At the time of writing in early 2005, crude oil prices have exceeded US$ 50 per bbl and occasionally US$ 60 per bbl in nominal terms. It is generally accepted that recent high prices high prices are the result surging demand from fast growing large economies like China and India on top of growing demand from highly developed western economies. This situation has been exacerbated by unpredictable disruptions in crude oil supply from Iraq and there is generally acknowledged to be a risk premium associated with political uncertainties in the Middle East.

It is only recently that nominal oil prices have moved to such high levels. Some commentators believe that a high price regime will be long lasting and that we are witnessing the end of the era of cheap oil. Others consider that the long term price will fall in real terms. Many oil and gas companies currently assume a long term real price in the range US$ 25 to US$ 35 per bbl depending on the purpose for which they are making the assumption.

To assist in gaining perspective, I carried out a regression analysis to determine an appropriate crude oil price to use in the analyses for this thesis. This analysis uses recent historical price data for Brent crude oil shown in Figure D.1. I chose Brent crude for the analysis, because the quality of the crude oil in the basins I analyse is similar to that of Brent.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page D.2

Figure D. 1 – Historical oil prices

55 50 45 40 35

30 Oil price (US$/bbl) 25 20 15 10

5 Year 0 2001 2002 2003 2004

* Prices quoted are of Brent Crude (from January 2001 to December 2004). Source: - World Bank

The analysis shows that the best-fit curve to the historical oil price data is a lognormal distribution. The distribution has a mean of US$ 28 per bbl and indicates that 90% of the time the oil price exceeded US$ 20.50 per bbl and 10% of the time, the oil price exceeded US$ 38.37 per bbl.

Given that the mean of the oil price distribution from the regression analysis is US$ 28 per bbl and that this falls in the range of oil price assumptions currently used in the oil and gas industry, I have elected to use this as a base-case price assumption to illustrate the economics of oil field developments in India. However, I acknowledge that the range of price uncertainty is large and, in the body of the thesis, I have also carried out probability analyses in which the oil price varies between US$ 20 per barrel and US$ 50 per bbl.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page E.1

Appendix E – Abandonment sinking fund calculation

In most PSCs that operate under the Indian NELP regime, the contractors must contribute regularly to a site restoration (or sinking) fund so that sufficient funds are available to abandon the development at the end of its life. I assume that annual contributions to the fund are made based on units of production method. Table E.1 below gives an illustration of how the calculations for annual contributions to the site restoration fund are carried out.

Table E.1 – Illustration of abandonment sinking fund calculation

Item Total

Total development cost (US$MM) 380 Example data

Total abandonment cost (US$MM) 95 Assumption (25% of Total development cost from above)

Year 12 3 4 5 6 Production profile (assumption) 65 5 15 25 20 (MMbbl per year)

Reserves produced each year as a 100% 8% 23% 38% 31% percentage of total reserves (percentage)

Annual contribution made to the site 95 7.31+ 21.92+ 36.54+ 29.23+ restoration fund (US$MM)

+ Value obtained by multiplying the abandonment cost (= US$95MM) by percentage of reserves produced each year.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page F.1

Appendix F – Reserves definitions

This appendix summarises the reserves definitions adopted by the Society of Petroleum Engineers (“SPE”) and World Petroleum Council (“WPC”) on Petroleum Reserves Definitions. Data included in this appendix is made available by SPE on their official web page. This appendix also includes the definitions of technical/commercial reserves and potential resources.

1 Reserves

“Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. Reserves may be attributed to either natural reservoir forces and energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.

All reserves involve some degree of uncertainty, depending chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively greater degrees of uncertainty in their recoverability."

1.1 Proved reserves

“Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations.

If a single best estimate (deterministic method of estimation) of reserves is made, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page F.2

If a range of reserve estimates and their associated probabilities are generated (probabilistic method of estimation), there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.”

1.2 Unproved reserves

“Unproved reserves are based on geologic and/or engineering data similar to that used in the estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved.

Unproved reserves may be further classified as probable reserves and possible reserves. The uncertainties associated with reserve estimation can be expressed by allocating appropriate quantities of reserves to the probable and possible classifications.”

1.3 Probable reserves

“Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable.

When probabilistic methods of estimation are carried out, there should be atleast a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.”

1.4 Possible reserves

“Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves.

When probabilistic methods of estimation are carried out, there should be atleast a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.”

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page F.3

2 Reserve status categories

Reserves status categories define the development and producing status of wells and reservoirs. Proved reserves can be categorized as developed or undeveloped.

2.1 Developed reserves

“It is expected that developed reserves would be recovered from existing wells including reserves behind-pipe. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor.

Developed reserves may be sub-categorized as producing or non-producing reserves.”

2.2 Producing reserves

“It is expected that those reserves sub-categorized as producing would be recovered from completion intervals, which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.”

2.3 Non-producing reserves

“Reserves sub-categorized as non-producing include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from xcompletion intervals which are open at the time of the estimate but have not started producing, xwells which were shut-in for market conditions or pipeline connections, or xwells not capable of production for mechanical reasons.

It is expected that behind-pipe reserves would be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.” Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page F.4

2.4 Undeveloped reserves

“It is expected that undeveloped reserves would be recovered xfrom new wells on undrilled acreage xfrom deepening existing wells to a different reservoir, xwhere a relatively large expenditure is required to recomplete an existing well, or install production or transportation facilities for primary or improved recovery projects.”

3 Other definitions

3.1 Technical/Commercial reserves

According to An Oil and Gas Handbook (1992) of Bank of Scotland, technical and commercial reserves are defined as follows

3.2 Technical reserves

Technical reserves are theoretically producible at a gross operating margin by, for example, normal primary or secondary recovery methods.

3.3 Commercial reserves

Commercial reserves are restricted to volumes of oil or gas recoverable at an acceptable profitability.

3.4 Potential resources

Potential resources are volumes of oil and/or gas that is anticipated can be produced from a basin. The estimates are based on data obtained from regional geological and/or geophysical surveys, exploration drilling, and improved recovery methods to be employed in the future.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page G.1

Appendix G – Economic Indicators

In this appendix, I summarise the definitions of economic indicators as set out in Petroleum Economics by Guy Allinson, 2002. The economic indicators used to interpret results of economic analysis include the following xNet Present Value ("NPV") xInternal rate of Return ("IRR") x Capital Productivity Index ("CPI") x Payback period

1 Net Present Value (NPV)

Present value can be defined as the “Equivalent value today of a sum of money received or spent sometime in the future. The present value of a cash flow occurring sometime in the future is known as the Net Present Value (NPV) of that future cash flow”. (Petroleum Economics by Guy Allinson, 2002).

Alternatively NPV can also be defined as difference between the present value of benefits and the present value of costs. It is a measure of how much money we stand to gain by putting our money into a particular project as compared to putting it in an alternative investment.

In order to make such a comparison, it is necessary for us to, discount to the present value using a discount rate equal to the interest rate received for an investment at alternative investments. Table G.1 shows how the formula used to calculate Net Present Value of a cash flow stream.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page G.2

Table G.1 – Net Present Value of cash flow stream

Total NPV = (NCF)1 + (NCF)2 + (NCF)3 + ………. + (NCF)n (1+r)1 (1+r)2 (1+r)3 (1+r)n

where NPV = Net Present Value

and NCF1 = the net cash flow at the end of year 1

NCF2 = the net cash flow at the end of year 2

NCF3 = the net cash flow at the end of year 3

NCFn = the net cash flow at the end of year n r = the discount rate (similar to bank interest rate) Source: Petroleum Economics by Guy Allinson, 2002

Table G.2 contains an illustration of how NPV is calculated at 10% discount rate for a given cash flow (numbers used are in US$MM and are purely illustrative). In the illustrative example shown below I use year-end discounting method.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page G.3

Table G.2 – Illustration of Net Present Value calculation

Year end 0 1 2 3 4 Project net cash flow -200 120 100 90 80

Using formula from Table G.1 above, we get

Total NPV = -200 + 120 + 100 +90 +80 (1+10%)0 (1+10%)1 (1+10%)2 (1+10%)3 (1+10%)4

= -200 + 109.1 + 82.6 + 67.6 + 54.6

= 113.9

As stated earlier, the positive value of NPV suggests that we would gain (US$ 113.9MM) by investing money in the project as compared to investing it in a bank.

2 Internal Rate of Return (IRR)

The Internal rate of return (IRR) is the discount rate at which NPV of a project becomes zero.

IRR indicates the discount rate below which any investment made would result in a positive NPV and above which would result in a negative NPV.

IRR calculation is done using equation set out in Table G.1. However, the IRR is found by trial and error, graphically or by iteration using a computer.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page G.4

3 Capital Productivity Index (CPI)

Capital Productivity Index (CPI) can be defined as the ratio of “Net Present Value” and “Present value of capital expenditure”.

4 Payback period

Payback period is defined as the time taken by the project’s positive net cash flow to recoup initial capital expenditures.

Every project has a negative net cash flow during early stages of project life because of initial investments made. Payback period is the time period taken by the project to achieve a positive cumulative net cash flow.

An illustration of payback period calculation is given in Table G.3, (all numbers used are in US$MM and are purely illustrative). I assume that the annual net cash flows are spread evenly over each year.

Table G.3 – Illustration of payback period calculation

Year 1 Year 2 Year 3 Year 4 Project net cash flow (US$MM) -100 -150 +100 +200

Cumulative net cash flow (US$MM) -100 -250 -150 +50

Payback period = 3.75 years

The fraction of the year to payout = 150 = 0.75 years 200

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page H.1

Appendix H – Letter from Petrowatch

PETROWATCH Market intelligence from the oil, gas and power sector in India

84 U.G.F, World Trade Centre, Babar Lane, –100 001. Tel: (011) 2341 4181, Fax: (011) 2341 4182

26 June 2005

This is to confirm that PETROWATCH INFORMATION (INDIA) PVT LTD has no objection to the use of its name as a source of material/data for any academic work carried out by Sajith Venugopal.

Yours sincerely

Deepak Mehta Managing Director PETROWATCH INFORMATION (INDIA) PVT LTD

PETROWATCH is a Trade East Product. Trade East Ltd is incorporated in England. No: 3373699. VAT: 673103653 Tel: +44 (0) 20 7221 1501; Fax: +44 (0) 20 7792 4511E-mail: [email protected], Internet: www.petrowatch.com Registered Office: 8A Arundel Gardens, Notting Hill, London W11 2LA, United Kingdom

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page R.1

References

1. Manorama Yearbook 2004. 39th edition, Malayala Manorama. Pages 499 - 502.

2. MSN Encarta - India. Cited 24-01-2005, Available from: http://encarta.msn.com/encyclopedia_761557562_16/India.html.

3. India, World Fact Book 2004. Cited 24-01-2005, Available from: http://www.cia.gov/cia/publications/factbook/geos/in.html.

4. Economy of India, Cited 20-11-2004. Available from: http://en.wikipedia.org/wiki/Economy_of_India.

5. General Review. Economic Survey 2003-2004, Cited 21-11-2004, Pages 3 - 7. Available from: http://indiabudget.nic.in/es2003-04/chapt2004/chap11.pdf.

6. Thirty-Ninth Report - Standing Committee on Petroleum and Chemicals (2003). April 2003. Pages 6 - 12.

7. Economic Data – India, Cited 22-11-2004. Available from: http://www.gesource.ac.uk/worldguide/html/912_economic.html.

8. Roads - The Ground Realities, in India Infoline Infrastructure Report - April 2001. Pages 39 - 53.

9. Road and Road Transport. Economic Survey 2003-2004, Cited 21-11-2004, Pages 184 -186. Available from: http://indiabudget.nic.in/es2003- 04/chapt2004/chap95.pdf.

10. About Indian Railways – Evolution, Cited 25-11-2004, Ministry of Railways website. Available from: http://www.indianrailways.gov.in.

11. Status Paper on Indian Railways. May 2002, Ministry of Railways. Pages 5 - 10.

12. Growth of Civil Aviation. Economic Survey 2003-2004, Cited 25-11-2004, Page S- 29. Available from: http://indiabudget.nic.in/es2003-04/chapt2004/tab129.pdf.

13. Ports. Economic Survey 2003-2004, Cited 25-11-2004, Pages 188 - 190. Available from: http://indiabudget.nic.in/es2003-04/chapt2004/chap96.pdf.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page R.2

14. Transmission network. Cited 27-11-2004, Ministry of Power website.

15. Power. Economic Survey 2003-2004, Cited 25-11-2004, Pages 174 - 179. Available from: http://indiabudget.nic.in/es2003-04/chapt2004/chap92.pdf.

16. Telecommunications. Economic Survey 2003-2004, Cited 27-11-2004, Pages 180 - 183. Available from: http://indiabudget.nic.in/es2003- 04/chapt2004/chap93.pdf.

17. "Refining and Operations - Ready Reckoner", Pages 4.1 - 4.3. April 2004, Petrowatch Database, Available from: http://www.petrowatch.com/database/government/government068.html.

18. Oil and Gas: Refining and Exploration to steel the show, in India Infoline Infrastructure Report - April 2001. Pages 67 - 73.

19. Pipelines. Indian Oil Corporation Limited Company website, Cited 01-12-2004, Available from: http://www.iocl.com/business_pipeline.asp.

20. Jayaram, A., "In the pipeline", in Businessworld, Cited 24-01-2005. Available from: http://www.businessworldindia.com/oct0603/indepth_oil.asp.

21. "Crude Production and Imports/Exports - Ready Reckoner", Pages 2.1 - 2.3. April 2004, Petrowatch Database, Available from: http://www.petrowatch.com/database/government/government068.html.

22. Commodity Balance of Petroleum and Petroleum Products. Economic Survey 2003-2004, Cited 25-11-2004, Page S - 30. Available from: http://indiabudget.nic.in/es2003-04/chapt2004/tab130.pdf.

23. Petroleum Statistics, Table 35, Basic Statistics. Ministry of Petroleum and Natural Gas website, Cited 18-10-2004, Page 30. Available from: http://petroleum.nic.in/petstat.pdf.

24. “Comprehensive overview of Indian oil sector”. October 2002, Petrowatch Database, Available from: http://www.petrowatch.com/database/government/government061.html.

25. "Auto Fuel Policy Report", Table 8.1 - BIS specifications, Page 115, Ministry of Petroleum and Natural Gas, Available from: http://petroleum.nic.in/ch_8.pdf.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page R.3

26. Quality Specifications for Aviation Turbine Fuels. Bharat Petroleum Corporation Company website, Cited 16-09-2004, Available from: http://www.bharatpetroleum.com/aviation/avi_turbine.asp.

27. "Auto Fuel Policy Report", Table 8.2 - BIS specifications, Page 117, Ministry of Petroleum and Natural Gas, Available from: http://petroleum.nic.in/ch_8.pdf.

28. Fuel oil specifications. Petroleum Bazaar website, Cited 18-09-2004. Available from: http://www.petroleumbazaar.com/Fo/Fospec.htm.

29. Petroleum Statistics, Table 10, Basic Statistics. Ministry of Petroleum and Natural Gas website, Cited 18-10-2004, Page 11. Available from: http://petroleum.nic.in/petstat.pdf.

30. "Refining and Operations - Ready Reckoner", Pages 4.1 - 4.3. April 2004, Petrowatch Database, Available from: http://www.petrowatch.com/database/government/government068.html.

31. LNG Terminals. Lycos Asia - India Infoline, Cited 25-09-2004. Available from: http://regi.5paisa.com/lyas/refi/proj/lngp.shtml.

32. “Coal Bed Methane - List of Awarded Blocks”. Directorate General of Hydrocarbons website, Cited 20-09-2004. Available from: http://www.dghindia.org/cmb_listofblocks.html.

33. Petroleum Statistics, Table 31, Basic Statistics. Ministry of Petroleum and Natural Gas website, Cited 18-10-2004, Page 28. Available from: http://petroleum.nic.in/petstat.pdf.

34. “HPCL's LPG” in Oil and Gas Update, Vol VI.No.7. August 2003, J.Sagar Associates. Page 7.

35. "Significant Statistics about Coal and Lignite". Coal Statistics, Ministry of Coal website, Cited 13-09-2004, Available from: http://coal.nic.in/0203anx4.pdf.

36. "Company-Wise Coal Dispatches and Vendibles During Last Five years". Coal Statistics, Ministry of Coal website, Cited 13-09-2004. Available from: http://coal.nic.in/0203anx7.pdf.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page R.4

37. Selected Crude Oil prices. Energy Information Administration website, Cited 04- 08-2004. Available from: http://www.eia.doe.gov/emeu/international/crude1.html.

38. Annual oil production at Ravva field. Cairn Energy Company website, Cited 09-08- 2004. Available from: http://www.cairn- energy.plc.uk/operations/eastern_india/production.shtml.

39. "Oil Sales - Ravva oilfield (Joint Venture Monthly Report)". November 2003, Petrowatch Database, Available from: http://www.petrowatch.com/database/upstream/upstream071.html.

40. Ravva - Various Budget Summary Reports, Petrowatch Database.

41. M. Nainan, Chief Editor, Petrowatch Database, August 2004.

42. "Cairn and Marubeni seek arbitration over Ravva tax - Archives 2002 - Volume 6, Issue 14". Cited on 20-08-2004, Petrowatch Database, Available from: http://www.petrowatch.com/database/2002/14.html.

43. "ONGC's Feasibility Report for D1 South", Petrowatch Database, Available from: http://www.petrowatch.com/database/upstream/upstream042.html.

44. "Feasibility Report for PY-1 development", access to document granted by Deepak Mehta (Managing Editor - Petrowatch).

45. "GAIL to pay $2.35 - $2.55 per mmbtu for PY-1 gas - Archives 2003 - Volume 7, Issue 10". Cited on 06-02-2005, Petrowatch Database, Available from: http://www.petrowatch.com/database/2003/10.html.

46. Rasheed, S.M., "Reliance plans for gas production from KG basin", in Business Column, The Hindu. Cited on 18-11-2004, Available from: http://www.thehindu.com/2004/11/03/stories/2004110304881600.htm.

47. "Development plan approved for KG-DWN-98/3 - Archives 2004 - Volume 8, Issue 17". Cited on 20-11-2004, Petrowatch Database, Available from: http://www.petrowatch.com/database/2004/17.html.

Sajith Venugopal July 2005 The economics of petroleum exploration and development in India Page R.5

48. "Reliance’s $2.3bn plan to produce deepwater KG gas - Archives 2004 - Volume 8, Issue 7". Cited on 04-07-2004, Petrowatch Database, Available from: http://www.petrowatch.com/database/2004/07.html.

49. "Reliance to invest Rs 107 bn in gas field", in The Mumbai Grapevine - Published by Mumbai-Central.com. Cited on 29-11-2004, Available from: http://mumbai- central.com/grapevine/msg01679.html.

50. "RIL to begin production from Krishna-Godavari field in Mar’08", in Business Column, Daily Excelsior. Cited on 17-03-2005, Available from: http://www.dailyexcelsior.com/web1/05jan18/busi.htm#6.

51. "RIL may pump $500 m to produce gas in AP", in Business Column, The Tribune - Online Edition. Cited on 17-03-2005, Available from: http://www.tribuneindia.com/2004/20040616/biz.htm#5.

52. "Article 15.9 of KG-DWN-98/3 field PSC", access to document granted by Deepak Mehta (Managing Editor - Petrowatch).

53. "Article 16 of KG-DWN-98/3 field PSC", access to document granted by Deepak Mehta (Managing Editor - Petrowatch).

54. "Indian Budget 2005", Page 21. March 2005, Ernst & Young (India).

Sajith Venugopal July 2005