Natural Gas New Energy Resource in Sri Lankaprds-srilanka.com/pdfs/InitialNaturalGas... · Fig. 41....

Natural Gas – New Energy Resource

in Sri Lanka

Phase 1 – INITIAL NATURAL GAS UTILIZATION ROAD MAP

A report outlining a strategy for the development of a natural

gas industry in Sri Lanka

submitted to the

Petroleum Resources Development Secretariat

6th

Floor, Ceylinco House, No 69, Janadhipathy Mawatha, Colombo 00100

by the

Sri Lanka Carbon Fund (Pvt) Ltd 980/4A Wickramasinghe Place, Ethul Kotte, Kotte

Team members from SLCF:

Dr. B. M. S. Batagoda Eng. P. G. Joseph

Report author:

Dr. Janaka Ratnasiri Consultant

15 October 2014

Acknowledgement: The author gratefully acknowledges the assistance received from the

Petroleum Resources Development Secretariat team – Mr. Saliya Wickramasuriya, Ms.

Preeni Withanage and Mr. Damith Senadhira, and from the Sri Lanka Carbon Fund (Pvt) Ltd.

team – Dr Suren Batagoda and Eng. P. G. Joseph, in the preparation of the report.

Natural Gas – New Energy Resource Sri Lanka Carbon Fund

i

Document Authorization

ii


iii

Table of Contents

Document Authorization .............................................................................................................i

Table of Contents .................................................................................................................... iiii

List of Figures ...........................................................................................................................vi

List of Tables ............................................................................................................................ix

List of Boxes ..............................................................................................................................x

List of Acronyms ......................................................................................................................xi

List of Chemical Symbols ...................................................................................................... xiii

Units of Measurements ...........................................................................................................xiv

Conversion factors ..................................................................................................................xiv

Foreword ..................................................................................................................................xv

Executive Summary ................................................................................................................xvi

1. Introduction .........................................................................................................................1

1.1 Natural gas in Sri Lanka ..............................................................................................1

1.2 Terms of Reference of the study ..................................................................................1 1.3 Outline of the study .....................................................................................................2

2. Managing natural gas in Sri Lanka .....................................................................................3

2.1 Some properties of natural gas ....................................................................................3

2.2 Uses of natural gas .......................................................................................................5

2.3 Transportation of natural gas .......................................................................................6

2.4 Availability of natural gas in Sri Lanka .......................................................................9 2.5 Conversion to liquids ...................................................................................................9

2.6 Safety aspects……………………………………………………………………….10

3. Energy supply in Sri Lanka ...............................................................................................12

3.1 Total primary energy supply......................................................................................12

3.2 Biomass supply ..........................................................................................................14

3.3 Petroleum oil..............................................................................................................15

3.4 Coal combustion ........................................................................................................16

3.5 Hydro power………………………………………………………………………. 17 3.6 Non-conventional renewable energy resources .........................................................17

4. Energy demand in Sri Lanka .............................................................................................19

4.1 Household and commercial sector .............................................................................19

4.2 Agricultural sector .....................................................................................................20

4.3 Industrial sector .........................................................................................................21

4.4 Transport sector .........................................................................................................22


iv

4.5 Power sector ..............................................................................................................24

4.6 Electricity consumption and national development ...................................................28

4.7 Overall fossil fuel demand .........................................................................................30

4.8 Demand for natuarl gas as a feedstock ......................................................................31

5. Future Outlook ..................................................................................................................33


5.2 Industrial Sector .........................................................................................................34

5.3 Transport Sector ........................................................................................................35

5.4 Power sector ..............................................................................................................36

5.5 Outlook in all fuel-consuming sectors .......................................................................41

5.6 Outlook in natural gas based industries……………………………………………..43

6. Energy generation and environmental degradation ..........................................................44

6.1 Emissions from oil combustion .................................................................................44

6.2 Emissions from coal combustion ...............................................................................45

6.3 Gaseous emissions from thermal power plants .........................................................46

6.4 National emission standards ......................................................................................48

6.5 Ambient air quality standards ....................................................................................50

6.6 Impacts of emissions on human health ......................................................................51

7. Cost of externalities in energy generation ........................................................................55

7.1 Assessment of external costs .....................................................................................55

7.2 Findings of some studies on externalities ..................................................................57

7.3 Studies carried out in Sri Lanka ................................................................................58 7.4 Adoption of EU damage factors for Sri Lanka ..........................................................60

8. Phasing-in of natural gas ...................................................................................................63

8.1 Scenarios for introducing natural gas ........................................................................63


8.3 Industrial sector ………………….. ………………………………………………..65

8.4 Industries with natural gas feedstock….……………………………………………67 8.5 Transport sector .........................................................................................................71

8.6 Power sector ..............................................................................................................73

8.7 Projected demand for natural gas in all sectors .........................................................81 8.8 Distribution of natural gas .........................................................................................83

9. Benefits of utilizing natural gas ........................................................................................86

9.1 Energy security ..........................................................................................................86

9.2 Clean air for a healthy nation ....................................................................................87

9.3 Safe water to reduce health risks ...............................................................................91

9.4 Clean environment to support tourism ......................................................................91

9.5 Promoting industrial growth with low cost energy source ........................................92

9.6 Ensuring food security ...............................................................................................93

9.7 Land free of toxic metals and radioacive material ....................................................93


v

9.8 Improving the national economy ...............................................................................94

9.9 Enhancing employment opportunities .......................................................................94 9.10 Meeting international obligations ..............................................................................95

10. Export potential of natural gas ......................................................................................99

10.1 Production of gas in Asia .......................................................................................99

10.2 Supply and demand of gas in Asia…………………………………………… .... 100

10.3 Developing a gas hub in Asia……………………………………………………102 10.4 Infrastructure development for NG export………………………………………103 10.5 Providing LNG bunkering facilities…………………………………………….105

11. Alternative sourcing of natural gas .............................................................................107

11.1 Previous attempts to import LNG ........................................................................107

11.2 Terminals for importing LNG ..............................................................................107

11.3 Sites for setting up LNG terminals .......................................................................108

12. Policy interventions and Plan of Action……………………………………………..109

12.1 Policy interventions .............................................................................................109

12.2 Plan of Action ......................................................................................................110

12.3 Time frames for executing the plan .....................................................................111

13. Conclusion and recommendations ..............................................................................113

13.1 Key findings .........................................................................................................113 13.2 Recommendations ................................................................................................115

Appendix A ............................................................................................................................116

Socio-economic scenario ...................................................................................................116

A.1 The land ...................................................................................................................116

A.2 Maritime waters .......................................................................................................117

A.3 Country’s waterways ...............................................................................................119

A.4 The economy ...........................................................................................................120

A.5 Poverty level ............................................................................................................124

A.6 Demography ............................................................................................................125

A.7 The climate ..............................................................................................................129

Appendix B ............................................................................................................................131

Terms of Reference ............................................................................................................131

References ..............................................................................................................................133


vi

List of Figures

Fig. 01. Global supply of primary energy sources in 2012 ....................................................... 5

Fig. 02. Global supply of energy sources generating electricity in 2012 ................................. 6

Fig. 03. A carrier transporting LNG across oceans .................................................................. 7

Fig. 04. A bulk container for transporting CNG over short distances ...................................... 7

Fig. 05. A facility for storing LNG prior to distribution to users ............................................. 8

Fig. 06. A LNG container being transported by truck to a bulk consumer............................... 8

Fig. 07. Annual supply of total primary energy sources averaged over 2010-2012 ............... 13

Fig. 08. Total primary energy supply during 2003-2012 ........................................................ 14

Fig. 09. Biomass consumption during 2001-2012, ................................................................. 15

Fig. 10. Fossil fuels imported in 2012 .................................................................................... 15

Fig. 11. Consumption of fossil fuels in the household and commercial sector ...................... 19

Fig. 12. Contribution to real GDP from agriculture ................................................................ 20

Fig. 13. Consumption of fuel in agricultural activities ........................................................... 21

Fig. 14. Contribution to industrial GDP from different sub-sectors ....................................... 21

Fig. 15. Consumption of fossil fuels in the industrial sector .................................................. 22

Fig. 16. Growth of gasoline operated vehicles during 2003 - 2012 ........................................ 23

Fig. 17. Growth of diesel operated vehicles during 2003 - 2012 ............................................ 23

Fig. 18. Annual consumption of gasoline and diesel during 2002 – 2012.............................. 24

Fig. 19. Growth of fuel consumption for transport during 2001-2012 ................................... 24

Fig. 20. Growth of installed capacity of electricity generating units 2001-2012 ................... 26

Fig. 21. Growth of generation from different sources during 2001-2012 .............................. 26

Fig. 22. Consumption of fuels for generation of electricity – 2001-2012 .............................. 27

Fig. 23. Consumption of electricity in differet sectors – 2012 ............................................... 27

Fig. 24. Growth of electricity per capita during 2001-2013, ................................................... 28

Fig. 25. Distribution of per capita electricity consumption in Asia - 2011 ............................ 29

Fig. 26. Distribution of residential per capita electricity consumption - 2011 ....................... 29

Fig. 27. Fossil fuel consumption in different sectors during 2001-2012 ................................ 30

Fig. 28. Distribution of fossil fuel demand among different sectors - 2012 ........................... 31

Fig. 29. Forecasted growth of fuel consumption in HH&C sector ......................................... 33

Fig. 30. Forecasted growth of fuel and coal consumption in the industrial sector ................. 34

Fig. 31. Forecasted growth of fuel consumption in the transport sector. ................................ 36

Fig. 32. Forecasted growth of demand during 2013-2040 ...................................................... 37

Fig. 33. Forecaste growth of generation during 2013-2040 .................................................... 37

Fig. 34. Forecasted growth of installed capacity during 2013-2040 ....................................... 38

Fig. 35. Forecast of per capita electricity consumption in Sri Lanka ......................... ............ 38

Fig. 36. Forecasted growth of fuel consumption in the power sector. .................................... 40

Fig. 37. Projected cost of fuel consumed in the power sector under BAU case ..................... 42

Fig. 38. Projected consumption of fossil fuel in different sectors .......................................... 42

Fig. 39. Plumes of emissions released from a coal power plant in Canada ............................ 45

Fig. 40. Coal piles and emissions from a coal power plant in Texas, USA ............................ 45

Fig. 41. Annual emission of toxic heavy metals from 3700 MW coal plants ......................... 47

Fig. 42. Relationship between the cost of abatement and cost of damage.............................. 56


vii

Fig. 43. Projected consumption of fuels in the HH&C sector under NG1 scenario ............... 64

Fig. 44. Projected consumption of fuels in the HH&C sector under NG2 scenario ............... 65

Fig. 45. Projected consumption of fuels in the Industrial Sector under NG1 scenario ........... 65

Fig. 46. Projected consumption of fuels in the Industrial Sector under NG2 scenario ........... 66

Fig. 47. Projected demand in natural gas based industries under NG1 scenario………….....69

Fig. 48. Projected demand in natural gas based industries under NG2 scenario…………..... 70

Fig. 49. Projected consumption of fuels in the transport sector under NG1 scenario ............ 73

Fig. 50. Projected consumption of fuels in the Transport Sector under NG2 scenario .......... 73

Fig. 51. Annual average daily load curves during 2004 - 2011 .............................................. 76

Fig. 52. Projected fuel consumption in the power sector under NG1 scenario ...................... 78

Fig. 53. Projected fuel consumption in the power sector under NG2 scenario. ..................... 78

Fig. 54. Projected fuel consumption in the power sector under the 3 scenarios. .................... 79

Fig. 55. Projected cost of fuel consumed in the power sector under the 3 scenarios ............. 79

Fig. 56. Projected demand for NG in the power sector under NG1 and NG2 scenarios ........ 79

Fig. 57. Levelized cost of generation of electricity with coal, diesel and gas ........................ 81

Fig. 58. Projected demand of NG in all sectors under NG1 scenario ..................................... 81

Fig. 59. Projected demand of NG in all sectors under NG2 scenario ..................................... 83

Fig. 60. Proposed gas distribution network ............................................................................ 85

Fig. 61. Projected SO2 emissions from different sectors under BAU scenario ...................... 88

Fig. 62. Projected NO2 emissions from different sectors under BAU scenario ...................... 88

Fig. 63. Projected TSP emissions from different sectors under BAU scenario ...................... 88

Fig. 64. Projected SO2 emissions from different sectors under NG1 scenario ……………...89

Fig. 65. Projected NO2 emissions from different sectors under NG1 scenario ……………..89

Fig. 66. Projected TSP emissions from different sectors under NG1 scenario ……………..89

Fig. 67. Projected SO2 emissions from all sectors under different scenarios ......................... 90

Fig. 68. Projected NO2 emissions from all sectors under different scenarios ......................... 91

Fig. 69. Projected TSP emissions from all sectors under different scenarios .... …………….91

Fig. 70. Projected CO2 emissions from all sectors under different scenarios ......................... 97

Fig. 71. Forecasted global NG trade in OECD and non-OECD countries ........................... 100

Fig. 72. Forecasted NG consumption in non-OECD Asia up to 2040 .................................. 101

Fig. 73. Possible location of liquefaction plant at Trincomalee Harbour ............................. 104

Fig. 74. View of Hambantota Harbour ................................................................................. 108

Fig. 75. Proposed time frame for implementing the Action Plan ......................................... 111

Fig. A 1. The relief map of Sri Lanka………………………………………………………117 Fig. A 2. Maritime boundaries of Sri Lanka .................................................................. ........ 118

Fig. A 3. Extended EEZ claimed by Sri Lanka...................................................................... 119

Fig. A 4. Area where hydro-carbon deposits were found ...................................................... 119

Fig. A 5. Growth of Sri Lanka’s GDP during 2008 - 2013 ................................................... 121

Fig. A 6. Variation of real GDP growth rates during 2005-2013 .......................................... 121

Fig. A 7. Sectorial contributions to the GDP (current) during 2008 – 2013.......................... 122

Fig. A 8. Growth of per capita GDP (current) during 2008 – 2013 ....................................... 122

Fig. A 9. Growth of GDP (Current) forecasted up to 2017 ............................. ...................... 123

Fig. A 10. Per Capita GDP (Current Price) distribution in Asia - 2011 ................................ 123


viii

Fig. A 11. Population growth during 1901-2012 ................................................................................125 Fig. A 12. Growth of mid-year population during 1991-2013 .......................................................126 Fig. A 13. Population density (2012) distribution among the districts ........................................127 Fig. A 14. Proposed metropolitan regions and industrial zones .....................................................127 Fig. A 15. Population density in Asian countries in 2011-12. ........................................................128 Fig. A 16. Population projections up to 2101 under 3 scenarios ...................................................129 Fig. A 17. Annual average rainfall 1961-2000 ....................................................................................130 Fig. A 18. Annual average mean temperature 1961-2000 ...............................................................130


ix

List of Tables

Table 01.Calorific Values of NG of top 10 producing countries ....................................................... 4 Table 02. Typical net calorific values and carbon content in fossil fuels........................................ 4 Table 03. Basic properties of Dimethyl Ether (DME) ........................................................................ 10 Table 04. Net calorific values of common fuels as quoted in different sources .......................... 13 Table 05. Availability of fuel-wood forecasted .................................................................................... 14 Table 06. Petroleum products refined locally and imported in 2012…..……………………..16 Table 07. Commissioned and committed NCRE projects ................................................................. 18 Table 08. Pattern of fuel usage in cooking and lighting 2012/13 .................................................... 20 Table 09. Existing thermal power plants and retirement plan .......................................................... 25 Table 10. Projected fuel consumption in the HH&C and Industrial Sectors ................................ 34 Table 11. Projected generation from NCRE Plants ............................................................................. 39 Table 12. Projected fuel consumption in the transport and power sectors .................................... 41 Table 13. Summary of projected fuel consumption during 2013-2040 and its NGEq ................ 42 Table 14. Projected annual consumption of NG based products …………………………….43 Table 15. Typical emission levels from thermal power plants in EU countries .......................... 48 Table 16. Emission standards (Draft) applicable to thermal power plants in Sri Lanka ........... 49 Table 17.Standards and actual emissions of heavy metals ................................................................ 50 Table 18. Ambient Air Quality Standards in Sri Lanka ..................................................................... 50 Table 19. Health impacts due to air pollutants ...................................................................................... 53 Table 20. Damage Factors for emissions from power plants ............................................................ 58 Table 21. Average costs of generation and externalities in USA .................................................... 58 Table 22. External costs due to emissions from thermal power plants .......................................... 62 Table 23. Demand for NG in HH&C sector under NG1 and NG2 scenarios ............................... 64 Table 24. Demand for NG in the industrial sector under NG1 and NG2 scenarios ................... 66 Table 25. Demand for NG in NG-based industries under NG1 scenario…………………….68 Table 26. Demand for NG in NG-based industries under NG2 scenario…………………….70 Table 27. Demand for NG in the transport sector under NG1 and NG2 scenarios .................... 72 Table 28. Calculation of levelized cost of electricity generation ..................................................... 75 Table 29. Proposed additions of power plants under Scenario NG1 .............................................. 77 Table 30. Demand for NG in the power sector under NG1 and NG2 scenarios ......................... 80 Table 31. Demand for NG in all sectors under NG1 and NG2 scenarios ...................................... 82 Table 32. Emission factors used in pollutant emission computations ............................................ 87 Table 33. Emissions of CO2, SO2, NO2 and TSP under the 3 scenarios ........................................ 90 Table 34. Balance of payment during 2012 and 2013 ......................................................................... 94 Table 35. Emission factors and GWP values for CH4 and N2O ....................................................... 97 Table 36. Reserves and Production of NG in Asia and IOR countries .......................................... 99 Table 37. Proposed Action Plan for introducing NG in Sri Lanka................................................110

Table A 1. Maritime waters of Sri Lanka, .............................................................................117 Table A 2. Monthly mean household income in different sectors (2012) .............................124 Table A 3. Monthly mean household expenditure in different sectors (2012) ......................124 Table A 4. Poverty head count in different sectors ................................................................125


x

List of Boxes

Box 1. Common unit in energy supply .................................................................................................... 12 Box 2. Non-conventional renewable energy sources .......................................................................... 18 Box 3. Natural gas as a source of hydrogen for fuel cells ................................................................ 35 Box 4. Units for expressing pollutant emission levels ........................................................................ 49 Box 5. Formation of pollutants from power plants .............................................................................. 54 Box 6. Environment damage cost from coal power plants ................................................................ 61 Box 7. UN Framework Convention on Climate Change .................................................................... 96 Box 8. Minamata disease caused by mercury pollution ..................................................................... 98


xi

List of Acronyms

AAQ Ambient Air Quality ADB Asian Development Bank AMS Ammonium Sulphate BAU Business-as-Usual GNI Gross National Income CB Central Bank CCGT Combined Cycle Gas Turbine CCHP Combined Cooling, Heat and Power CEA Central Environmental Authority CEB Ceylon Electricity Board CHP Combined Heat and Power CI Compressed Ignition CNG Compressed Natural Gas CPC Ceylon Petroleum Corporation CPP Coal Power Plant CST Central Storage Terminal DME Dimethyl Ether DR Discount Rate EEZ Exclusive Economic Zone EIA Environmental Impact Assessment EL Economic Life EP Eastern Province EPA Environment Protection Agency ESCAP Economic and Social Commission for Asia and the Pacific ESD Energy Services Delivery EU European Union FDI Foreign Direct Investment FEV1 Forced Expiratory Volume in 1 sec FGD Flue Gas Desulphurization GCV Gross Calorific value GDP Gross Domestic Product GEF Global Environmental Facility GNP Gross National Income HC Hydrocarbons HD Human Development HDI Human Development Index HIES Household Income and Expenditure Survey IC Internal Combustion IEA International Energy Agency IOR Indian Ocean Rim IPCC Intergovernmental Panel on Climate Change ITCZ Inter-Tropical Convergence Zone LECO Lanka Electricity Company


xii

LFT Land-fall terminal LKR Lanka Rupee LNG Liquefied Natural Gas LPG Liquefied Petroleum Gas LTGE Long Term Generation Expansion MCM Minamata Convention on Mercury MR Metropolitan Region MUSD Million US Dollars NCP North Central Province NCRE Non-Conventional Renewable Energy NCV Net Calorific Value NE North East NG Natural Gas NPP National Physical Planning NWP North Western Province OECD Organization for Economic Co-operation and Development OPL Official Poverty Line PAH Polycyclic aromatic hydrocarbon PAN Peroxyacetyl nitrate PF Power Factor PHC Poverty Head Count PM10 Particulate Matter of diameter below 10 microns PM2.5 Particulate Matter of diameter below 2.5 microns PRDS Petroleum Resources Development Secretariat PV Photo-voltaic RERED Renewable Energy for Rural Economic Development SD Statistical Digest SEA Sustainable Energy Authority SI Spark Ignited SLAAS Sri Lanka Association for the Advancement of Science SLSEA Sri Lanka Sustainable Energy Authority SPM Suspended Particulate Matter ST Steam Turbine SW South West TPES Total Primary Energy Supply TSP Total Suspended Particulates UNCLOS United Nations Convention on Law of the Sea UNCTAD United Nations Conference on Trade and Development UNDP United Nations Development Program UNFCCC United Nations Convention on Climate Change USA United States of America USD United States Dollar VOC Volatile Organic Compounds WB World Bank WHO World Health Organization


xiii

List of Chemical Symbols

Al2O3 Aluminum Oxide (Alumina) As Arsenic C Carbon Cd Cadmium CH3OCH3 Dimethyl Ether CH3OH Methanol (Methyl Hydroxide) CH4 Methane CH4N2O Urea C2H5OH Ethanol (Ethyl Hydroxide) Cr Chromium CO2 Carbon Dioxide Fe2O3 Ferric (Iron) Oxide H2 Hydrogen Pb Lead Hg Mercury HNO2 Nitrous Acid HNO3 Nitric Acid H2SO3 Sulphurous Acid H2SO4 Sulphuric Acid N2O Nitrous Oxide N2O5 Dinitrogen pentoxide Ni Nickel NH3 Ammonia (NH4)2SO4 Ammonium Sulphate NO2 Nitrogen Dioxide N2O3 Dinitrogen Trioxide NOx Oxides of Nitrogen O2 Oxygen O3 Ozone SiO2 Silicon Dioxide (Silica) SO2 Sulphur Dioxide TiO2 Titanium Dioxide


xiv

Units of Measurements

Bcf Billion (109) cubic feet

EJ Exa (1018

) Joule

GWh Giga (109) Watt hour

ha hect (102) are

kcal kilo (103) calorie

kg kilo (103) gramme

km kilo (103) metre

kWh kilo (103) Watt hour

m metre MBtu Million British thermal unit

Mcf Million cubic feet

MJ Mega (106) Joule

Ml Mega (106) litre

mmBtu Million Btu Mt Million tonne

MW Mega (106) Watt

Nm3

Normal cubic metre (normalized to 0oC and 1 atmosphere pressure)

oC Degree Centigrate

PJ Peta (1015

) Joule

scf Standard cubic feet (normalized to 60oF and 1 atmosphere pressure)

t Tonne (1,000 kg) tC Tonnes of Carbon

Tcf Trillion (1012

) cubic feet

tCO2 Tonnes of Carbon Dioxide

TJ Tera (1012

) Joule

μm Micro (10-6

) metre

Conversion factors

1 Btu = 1,056 J

1 calorie = 4.1868 J

1 GWh = 3,600 GJ

1 scf (NG) = 1,000 Btu

1 PJ/y (NG) = 2.60 mscf/day


xv

Foreword

A study was assigned to Sri Lanka Carbon Fund (Pvt) Ltd to make recommendations as to the

best way in which the newly discovered energy resource in Sri Lanka – Natural Gas – could

be utilized to gain economic benefits to the country. The study is expected to look into the

following scenarios of energy consumption.

1. BAU - Business as Usual, which simply takes present consumption and forecasts future

trends using the same fossil fuels.

2. NG1 - Natural Gas will be introduced into power and other sectors where it can be used, but

energy demand growth will remain the same as in BAU. A low penetration rate will be assumed

in this scenario for household, industrial and transport sectors and for the power sector, the CEB

case for introducing natural gas in place of coal was adopted. Clearly the migration of NG into

these sectors may require policy and infrastructure changes, and these will be outlined.

3. NG2 – A high penetration rate is assumed in this scenario for the 3 sectors outlined above.

For the power sector, in addition to the gas operated power plants included in Scenario NG1,

the proposed coal power plant at Trincomalee will be replaced by natural gas power plants.

4. NG3 - Optimum take-up of NG into the domestic economy over time will yield the true

long-term economic benefit of the resource, and this scenario includes new industries and

new power plants along with the liquefaction and export of produced surplus.

In this Phase 1 report only the BAU case, NG1 and NG2 cases applied to the four sectors –

household & commercial, industrial, transport and power - will be presented. The Phase 2

report will contain the full range of options that may be available in the future.

S. Wickramasuriya


xvi


xvii

Executive Summary

Pursuant to the discovery of natural gas deposits in the sea off the Kalpitiya Peninsula, a

study was undertaken to explore ways and means of using this new energy resource in Sri

Lanka. The gas is expected to be available in 2018 at a rate of 70 Mcf/d initially to be

expanded to 140 Mcf/d in 2021 and 210 Mcf/d in 2023. Natural gas is found in many

countries around the world but local market conditions reflect the spread between wellhead,

wholesale and consumer prices.

A brief description of natural gas and its applications globally as a clean source of energy is

given. It is the preferred fuel in the domestic sector for spatial heating and cooking, in the

industrial sector for generating thermal energy and in the power and transport sectors for

generating motive power. Today, natural gas has a share of about 21-22% in the generation of

both the total energy and electricity, and the outlook is that this share will grow in the future,

particularly in Asia with an increasing demand in India, China and Japan. Natural gas is also

widely used as a feedstock in many industries including the manufacture of urea and methanol.

Natural gas is transported over land to consumers in pipelines extending thousands of

kilometres crossing national borders. Where the sources and consumers are separated by

oceans, the gas is transported in liquid form in purposely built carriers. The loading and

unloading of liquefied natural gas (LNG) require building of special terminals and deep

jetties which cost large sums of money and unless the throughput is high, such operations are

not viable. For local use, the gas is either compressed or liquefied and transported in

containers for distribution among consumers.

Hitherto, Sri Lanka has been dependent on biomass, petroleum oil, hydropower and coal for

its energy requirements, while non-conventional renewable energy resources including solar

photo-voltaic, wind, small hydro and dendro power are also being developed. The share of

hydropower as a source of electricity has been declining over the years and presently taken

over by fossil fuel sources. Sri Lanka's total energy consumed during the 10 years 2003-2012

has increased from 385 PJ to 482 PJ, showing an average annual growth rate of 2.5%. Our

electricity consumption has increased from 7,700 GWh to 11,800 GWh over the same period

showing an average annual growth rate of 5.3%. However, the country’s per capita total

energy consumption (23.7 GJ/capita in 2012) as well as electricity consumption (515

kWh/capita in 2012) are among the lowest in Asia.

The consumption of fuels in different sectors – agriculture, household & commercial,

industries, transport and power - over the period 2001-2012 was analyzed to determine the

trends. While some sectors showed positive trends, others showed irregular behaviour with

overall reduction as in the case of agriculture. The positive trends shown during the period

2008-2012 in each sector are used in making future projections up to 2040 assuming same

trends to continue. In some cases, such as kerosene and fuel oil, adjustments were made

considering their potential use in the future. The projections into the future were made in 3

different scenarios.


xviii

The overall projected consumptions in the 4 sectors (other than agriculture) up to 2040 in the

BAU scenario include 61.1 PJ (253% increase) in the household & commercial sector, 23.8

PJ (102% increase) in the industrial sector, 566 PJ (397% increase) in the transport sector and

550 PJ (593% increase) in the power sector. The total fuel consumption in all sectors will

grow from 223 PJ in 2014 to 1200 PJ in 2040. If this amount of energy were to be supplied

by natural gas, the amount required will rise from 578 Mcf/d in 2014 to 3,120 Mcf/d in 2040.

In view of the seriousness of the environmental degradation caused by coal power plants

worldwide, which has a direct impact on the health of people exposed to their emissions, a

detailed assessment of various aspects of pollution both by air emissions and from coal ash

dumps is carried out. About 10-20% of coal burnt ends up as ash which has the potential to

release tonnes of toxic heavy metals including mercury and radioactive substances into the

soil, potentially contaminating the water table.

Several studies have been carried out by other countries to quantify the damage done to the

health of people and the environment in general and expressed in terms of added costs of

generation. These are referred to as External costs, or Externality costs, because they are not

borne by the power producer. However, at a social level, they have to be borne by someone,

and therefore have been gaining increased visibility in the developed world as impacting the

quality of life. Though coal is generally said to be a cheaper source of electricity than natural

gas, when the external costs are added, the situation gets reversed. Particularly in Sri Lanka's

case, where coal is imported and natural gas is domestic.

The gas extracted from offshore wells would be brought to the shore and after purification

and compressed at the landfall site, brought through a pipeline to a terminal with storage

facility close to the primary consumption centre, possibly at Kerawalapitiya where already an

LPG storage facility already exists. Among the installed thermal power plants in the country

are 3 combined cycle gas turbine (CCGT) plants with combined capacity of 628 MW. These

currently use diesel oil, naphtha and fuel oil, and one of these is located at Kerawalapitiya

(300 MW) while the other two are at Kelanitissa, at the northern boundary of the city. The

demand for fuel for these 3 plants matches the amount of gas initially available in 2018, and

the plants could be converted for operating with natural gas at minimal cost.

Further development of the power sector using NG could be carried out under two scenarios –

NG1 and NG2. Under NG1 scenario, a number of 250 MW CCGT plants will be introduced

beginning 2022 according to the CEB Plan for adding LNG plants (Annex 7.15). Under NG2

scenario, in addition, the proposed 1000 MW coal power plants at Trincomalee (Sampur) will

be replaced by 4 of 250 MW gas-fired power plants beginning 2018. The estimated amounts

of gas required to operate the planned gas-fired power plants under NG1 scenario will be 93

Mcf/d in 2018, 322 Mcf/d in 2025, 462 Mcf/d in 2030 and 807 Mcf/d in 2040. The

corresponding figures under the NG2 scenario will be 122, 426, 565 and 910 Mcf/d,

respectively.


xix

After 2023, when the production is trebled to 210 Mcf/d, provision has been made to

introduce gas to the transport and other sectors. It is proposed that this will be carried out

under two scenarios; NG1 with low penetration and NG2 with high penetration. The

penetration levels of NG in the sectors other than power sector under NG2 scenario are taken

as doubled that considered under NG1 scenario.

The penetration of gas into the household and commercial (HH&C) sector will be deferred

until the necessary infrastructure including pipeline networks are ready. It is assumed that gas

could be introduced by 2026 under NG1 scenario with a share of 4% initially increasing up to

60% in 2040, resulting in the consumption growing from 2.2 Mcf/d in 2026 to 89 Mcf/d in

2040. Under NG2 scenario, these penetration levels will be increased commencing from 6%

in 2026 and reaching 90% in 2040, with a corresponding growth of NG consumption from

3.5 Mcf/d to 133 Mcf/d. It will be economical to construct local networks of pipelines

supplying gas to clusters of houses in housing schemes or apartment complexes. The network

could be served by gas transported as LNG, in which case regasification facilities need to be

provided at each receiving point or as pipe-borne, depending on scale.

In the industrial sector, gas could be initially supplied to users within industrial zones where

clusters of industries are present, to replace oil for thermal energy generation. A LNG

receiving point would be set up within the zone, from where the gas could be distributed to

individual industries by pipelines. The management of such distribution systems could be

entrusted to licensed operators. Under NG1 scenario, it is assumed that 4% of the combined

consumption of LPG and fuel oil will be replaced by NG, resulting in a demand for 0.9 Mcf/d

in 2023. It is expected that this demand will grow progressively to 72% or 26 Mcf/d in 2040.

Under NG2 scenario, NG demand will increase from 8% annually with 8% increments up to

2034 reaching 96% and thereafter at 100% up to 2040. This will result in NG demand

growing from 1.9 Mcf/d in 2030 up to 36.3 Mcf/d in 2040.

In non-energy applications, NG will be used as a feedstock in the manufacture of urea and

several other products based on NG as described in Section 5.6. Urea is a fertilizer which is in

high demand in the country. It is proposed to initially manufacture 1 Mt of urea annually

commencing 2025, and increase the production to 1.25 Mt in 2030 and to 1.5 Mt in 2035

under NG1 scenario. The manufacture of another fertilizer – Ammonium Sulphate (AMS)

will be undertaken commencing with a capacity of 100 kt annually from 2025, increasing it to

125 kt in 2030 and to 150 kt in 2035. In addition, the manufacture of DME will be undertaken

with a similar production rate. The three industries will require annually 81, 101 and 121

Mcf/d of NG in 2025, 2030 and 2035, respectively.

Under NG2 scenario, new industries to manufacture methanol and ethanol will be

commenced in 2025, beginning with a capacity of 1.0 Mt annually for methanol and 100 kt of

ethanol. These will be increased to 1.5 Mt and 150 kt, in 2030 and 2035, respectively. The

corresponding demand for NG for all five industries in 2025, 2030 and 2035 will then be 194,

271 and 347 Mcf/d, respectively. It is expected that the production will be used partly in local

industries and partly to export. It is expected that once NG is available, new NG-based


xx

industries will lead to emergence of a NG-based chemical industry, manufacturing a range of

products that are currently being imported.

The demand for gas in the transport sector is considered under the two scenarios – NG1 with

low penetration and NG2 with high penetration. Under NG1 scenario, NG will be introduced

at progressively increasing rates beginning at 2% from 2023, reaching 36% penetration by

2040. This will result in NG demand of 10 Mcf/d in 2023, 34 Mcf/d in 2025, 125 Mcf/d in

2030 and 530 Mcf/d in 2040. Under NG2 scenario, the corresponding demand will be 20, 68,

249 and 1059 Mcf/d, respectively. The above projections were sub-divided to give demands

for CNG and LNG separately corresponding to substitution for gasoline by CNG and diesel

oil by LNG. In addition to direct consumption of NG for transport, DME could also be used

in the transport sector. But this contribution is not considered here to avoid double counting.

Generally, CNG will be used for operating light vehicles and LNG will be used for operating

heavy vehicles including buses and trucks. In order to realize these targets, the private sector

should be encouraged to provide the necessary facilities for the vehicles to be supplied with

CNG or LNG, and the consumers provided incentive for them to shift from petroleum oil to

natural gas. An adequate number of CNG and LNG dispensing points will have to be installed

along the major highways, an essential pre-requisite for people to change over from oil to gas.

The phasing-in of NG into various sectors will result in creating a demand of 93 Mcf/d in

2018 under NG1 scenario which will increase to a demand of 1,609 Mcf/d in 2040. In order

to supply NG at this rate over a period of 22 years, the NG deposit needs to have a capacity of

6 Tcf. In the case of NG2 scenario, the demand for NG will increase from 122 Mcf/d in 2018

to 2525 Mcf/d in 2040. The deposit needs to have a capacity of 10 Tcf to supply NG at the

specified rate over a period of 22 years.

This study has also examined the various national benefits arising from the country shifting to

natural gas among which are the reduction of emission of polluting gases SO2, NO2 and TSP

as well as Greenhouse Gases including CO2, CH4 and N2O. The reduction of polluting gas

emissions will reduce the burden on the country’s health sector in treating patients seeking

treatment for respiratory ailments caused by inhaling these polluting gases and suspended

particulates. Emissions from all sectors were considered here.

In 2040 under BAU conditions, SO2 emission will be 359 kt, NO2 emissions 283 kt, TSP

emissions 22 kt and CO2 emissions 103 Mt. The NG phasing-in under NG1 scenario will result in

reducing these to 112 kt, 194 kt, 6 kt and 74 Mt, respectively, during the same timeframe. Under

NG2 scenario, these emissions will reduce to 46 kt, 154 kt, 3 kt and 65 Mt, respectively.

At the guide price points used for domestic NG – USD 15, 10 and 5 per million Btu, there is

potential to save nearly 7 billion USD under NG1 and over 8 billion USD under NG2 scenario

annually by 2040 in phasing out petroleum oil completely and coal partially in the power sector.

Similalry, in the transport sector and in the manufacture of urea, similar savings could result in

phasing in NG. In particular, operation of power plants with NG is preferred even if the cost of


xxi

externalities are not considered, in view of the escalating costs of coal in the future, and the

decreasing cost of domestic NG.

The opportunities for exporting any surplus gas in the event new deposits are found have

been examined, particularly to India by pipeline and as LNG to countries in the Far East

where the demand growth is expected to increase while conventional supplies of natural gas

in Asia are expected to decline. This will be countered by increasing unconventional (shale

gas and oil condensate) activity. With the shipping community contributing significantly to

the world's green house gas emissions by burning fuel oil, and under increasing pressure to

convert carriers to cleaner fuel, the advantages of setting up bunkering facilities at

Hambantota for LNG operated vessels is also considered.

There are many other benefits the country could acrue as a result of switching to NG among

which are: energy security, food security, improved balance of payment, clean air, unpolluted

water, land free of coal ash dumps with toxic metals and redionuclides, reducing burden in

the health sector, providing new employment opportunities and meeting obligations under

international treaties Sri Lanka has entered into.

The government will need to introduce several policy interventions to enable an NG-based

industry to develop. Some of the key issues to be considered are the regulations on safety

apects of using gas, regulating its import and distribution, making provision for using gas in

vehicles, limiting import of gasoline/diesel vehicles, licensing the operators of local pipeline

networks, levying taxes and fees on the sales, incentives for investors, approval by authorities

concerning environmental impacts in coastal areas and provision of funds for research and

developemnt activities.

All these measures will serve to increase the domestic market and build economies of scale.

They will lower the average cost of energy, accelerate demand growth, and position Sri

Lanka on a steeper development trajectory. All should be commercially viable on their own,

and not require any government subsidy.

On the other hand, if we do nothing, the country will have to face many setbacks both in the

economy and technology. Sri Lanka already spends almost 25% of the total import

expenditure on importing fossil fuels. With the high volatility of the international fuel market,

it is very likely that the fuel prices will escalate in the future putting a severe strain on our

economy. With limited land resources, there is no possibility to increase the country’s

revenue by expanding exports based on plantations. Furthermore, any escalation of conflicts

in the ME countries fueled by American interests could be a threat to our fuel supplies and

also to the employment prospects of Sri Lankan manpower in the ME, which brings in a

substantial revenue to the country. Hence, it is important to rely on domestic sources to meet

the country’s energy requirements in the future. The proliferation of coal power plants which

is the only alternative to NG power plants will cause pollution of air, water and land, with

irreparable damage caused to people’s health as well as having negative impacts on such

areas tourism and economic development.


xxii


1

1. Introduction

1.1 Natural gas in Sri Lanka

The exploration for petroleum oil in Sri Lanka commenced more than half a century ago in

the Gulf of Mannar without yielding positive results. However, recent investigations have

shown evidence of the presence of natural gas (NG) deposits in Sri Lanka’s maritime waters.

Preliminary analysis of seismic data has shown that gas deposits are found in deep waters off

Kalpitiya Peninsula. According to exploring team, its extraction will be relatively expensive,

but feasible with current technology. In order to continue with further investigations, it is

necessary to study the ways and means of utilizing this new source of energy within Sri Lanka

as well as the possibility to export depending on the extent of the deposits.

The Petroleum Resources Development Secretariat (PRDS), established by the government to

develop the country’s petroleum resources, has therefore decided to conduct a study to evaluate

the national benefits of utilizing domestic natural gas in the energy mix in place of imported oil,

liquefied petroleum gas (LPG) or coal. It is expected that the study would define (a) the sectors in

which it makes economic sense to substitute feedstock, (b) the quantity of gas required for such

substitution, and (c) policy areas that may need revision in order to phase-in gas into the national

energy scenario. In addition, PRDS requires to determine what additional industries would

become viable with domestic gas becoming a low-cost source of energy and a feedstock.

The gas deposits have been discovered off-shore from Kalpitiya Peninsula and it will be

brought to the shore by a sub-sea pipeline. The gas needs to be purified, compressed and fed

to a pipeline to be brought to a central storage terminal (CST) possibly at Kerawalapitiya. The

gas will be then distributed to consumers either by pipelines or in containers loaded with

compressed or liquefied gas depending on the demand and consumer preference.

The party undertaking the exploration is of the opinion that initially, the currently-explored

field could produce 70 million cubic feet of gas per day (Mcf/d) commencing 2018 and that

production could be increased to 140 Mcf/day in 2021 and to 210 Mcf/day in 2023. In the

meantime, further exploration in new fields will be carried out depending on the plans made

for utilization of the currently discovered gas.

1.2 Terms of Reference of the study

The terms of reference (TOR) of the study issued by PRDS are to:

1. Estimate the present use and future trends in the use of coal, oil and LPG for

electricity generation, transport application, industrial heat generation, household and

commercial sectors

2. Estimate the true Externality Cost of using different feedstock in the above sectors in

the context of Sri Lanka 3. Prepare a report outlining the national benefits, if any, of substituting domestically

produced natural gas for any or all of the purposes above, including both direct and


2

externality cost impacts. This report may contain local or international references, but

all numbers must be supported.

4. Capture any other relevant aspects which would encourage or otherwise the use of

natural gas in Sri Lanka. 5. Recommend an investment, policy and infrastructure plan to enable revenue gains

from hydrocarbon production be used to increase the use of renewable energy such

that in the long term dependency on fossil fuels of any kind is minimized. 1.3 Outline of the study

Prior to addressing the utilization of the new source of energy, it would be appropriate to

examine the country’s geographic, social and economic aspects and its position both within

the region and the globe in respect of energy utilization and development, because the two are

inter-related. A detailed description of the country’s socio-economic scenario is given as an

Appendix.

Since the subject of NG is something new in the country, a brief description of its properties and

its uses are given. Its main applications globally are in the power, spatial heating in buildings and

in industrial sector. However, the potential for its use in Sri Lanka is in the power and transport

sectors since the major consumption of petroleum oil takes place currently in these two sectors,

and the demand for NG to replace oil has been estimated. There is an opportunity for the

industrial and household & commercial sectors also to be supplied with NG as a source of thermal

energy, though a major share of energy requirements in these in two sectors come from biomass.

The demand for NG to replace oil in these two sectors also has been estimated.

NG could also be used as a feedstock in industry, particularly in the manufacture of urea,

ammonium sulphate, methanol and ethanol. The demand for NG to manufacture these

products locally has been estimated. Information on energy demand in the previous decade in

different sectors and their future projections up to 2040 are considered. The possibility of

utilizing NG in place of currently used oil and coal in these sectors is discussed assuming two

scenarios of penetration levels for each application.

The study has endeavored to obtain information on the cost of externalities due to emissions

from power plants. Estimates applicable to Sri Lanka have been determined. The national

benefits in environmental, social and economic aspects of switching to NG as a source of

clean energy is discussed. Finally, the export potential of gas both as liquefied natural gas

(LNG) and for bunkering into vessels operating on LNG, in the event a surplus is expected in

the future is also discussed.


3

2. Managing natural gas in Sri Lanka

The discovery of gas off Mannar Basin was announced by the government in 2011. However,

there appears to be a lack of appreciation by the people in Sri Lanka, including policy makers,

with regard to the potential of natural gas (NG) as a source of energy and as an industrial

feedstock. Before examining how the newly discovered gas could be used locally, it is

necessary to understand some basic facts about NG and its utilization.

2.1 Some properties of natural gas

Natural gas is a hydrocarbon gas mixture consisting primarily of methane (CH4) (90-95%),

and varying amounts of other higher alkanes –ethane (C2H6), propane (C3H8) and butane

(C4H10) - and a lesser percentage of carbon dioxide (CO2), nitrogen (N2), and hydrogen sulfide

(H2S). It is found in deep underground rock formations where generally other fossil fuels

occur. Being under pressure, a pipe driven into the deposit causes the gas to escape unassisted

to the surface. Natural gas is an energy source widely used for heating, cooking, and

electricity generation. It is also used as fuel for vehicles and as a chemical feedstock in the

manufacture of a variety of commercially important organic chemicals.

The dominant gas, methane, being the simplest hydrocarbon, burns without emitting any

unburnt carbon or hydrocarbons. It is the cleanest fuel of all fossil fuels. It is non-toxic when

exposed to in small quantities. In the event of a leak, being lighter than air with molecular

weight of 16 compared to 29 for air, NG gets dispersed quickly without posing any threat to

human life. Combustion of NG does not leave any solid residues or gaseous pollutants or

liquid effluents unlike in the case of oil or coal.

With the lowest carbon to hydrogen (C/H) ratio among fossil fuels, NG has the highest gross

calorific value (GCV) and the lowest carbon content. Since the composition varies from

country to country from where it is sourced, the C/H ratio, the density and the calorific value

are all source-dependent. Table 1 shows the typical GCV of gas sourced from top-ten

countries producing NG and their current production rates, along with their estimated

reserves. It is noted that there is a wide variation of the GCV from country to country, from

about 33.3 to 41.4 MJ/m3, with an average of 38.64 MJ/m

3 or 53.90 GJ/t.

The GCV is determined in a bomb calorimeter and the heat produced includes the latent heat

of water vapour produced during combustion. The net calorific value (NCV) which is the heat

available after combustion, is taken as 90% of the GCV for gas and this works out to 48.51

GJ/t. The GCV of natural gas is higher than that of all other fossil fuels. The NCV has to be

used in estimating the thermal energy generated from NG combustion where the water vapour

produced escapes with the flue gas thus reducing the heat available.

Table 1 also shows the calorific value of samples of NG extracted from Sri Lanka’s deposits,

in its last row. The GCV of the local NG sample is tentatively determined as 1000 Btu/scf,

according to PRDS. This is equivalent to 37.26 MJ/m3 or 51.96 GJ/t or 12,410 kcal/kg.


4

Table 1.Calorific Values of NG of top 10 producing countries

Gross Calorific Value Net Cal Value

2012 2012

Country Production1

Reserves2

kJ/m3

GJ/t GJ/t Bcm/y Bcm

USA 38,080 53.110 47.799 681 9,400

Russia 38,232 53.322 47.990 656 48,700

Qatar 41,400 57.741 51.967 160 25,100

Iran 39,356 54.890 49.401 158 33,600

Canada 38,560 53.780 48.402 157 1,754

Norway 39,600 55.230 49.707 115 2,313

China 38,931 54.297 48.867 107 3,100

Saudi Arabia 38,339 53.471 48.124 75 8,200

Netherlands 33,339 46.498 41.848 80 1,416

Indonesia 40,600 56.625 50.962 77 3,001

Mean 38,644 53.896 48.507

Sri Lanka3

37,255 51.960 46.764

In addition to being the fuel with the highest GCV, NG is known to have the lowest carbon

content among all fossil fuels which makes its carbon dioxide emission during combustion

much less than that from other fossil fuels. Table 2 shows the NCV of commonly used fossil

fuels and their carbon content per unit heat energy GJ.

Table 2. Typical net calorific values and carbon content in fossil fuels4

Fuel

Net Calorific Value Carbon CO2

kcal/kg GJ/t content emitted

kgC/GJ kgCO2/GJ

Gasoline 10,700 44.80 18.9 69.3

Diesel oil 10,340 43.29 20.2 74.1

Fuel oil 9,600 40.19 17.2 63.1

Kerosene 10,460 43.79 19.6 71.9

LPG 11,300 47.31 17.2 63.1

Naphtha 10,750 45.01 20.0 73.3

Natural Gas 11,586 48.51 15.3 56.1

Bituminous Coal 5,710 23.91 25.8 94.6

It is noted that coal has the highest carbon content per unit heat energy (25.8 kgC/GJ) while NG

has the lowest (15.3 kgC/GJ). The table also shows the amount of carbon dioxide (CO2) emitted

per unit heat energy for different fuels. Hence, shifting from coal to NG is one way of mitigating

carbon emissions, which all Parties to the UN Framework Convention on Climate Change

(UNFCCC) are expected to comply with, according to its Copenhagen Accord adopted in 2009.

UNFCCC was adopted with a view to get nations to arrest the global warming and climate


5

change arising from it by mitigating the amounts of greenhouse gases (GHG) emitted into the

atmosphere, caused principally by burning of fossil fuels.

2.2 Uses of natural gas

Today, NG is used as a source of energy, both thermal and electrical, in many countries and

also as a feed stock in a wide variety of manufacturing processes. It is the preferred energy

source because of the absence of any pollution and lower carbon dioxide emission compared

with those from other fuels. An application gaining popularity is its use as a fuel in the

transport sector where compressed natural gas (CNG) is used to power vehicles. Fig. 1 shows

the share of different sources of energy globally including NG which amounts to 560 EJ (1

EJ=1018

J) in 2012. The highest share comes from oil because of its contribution in the

transport sector. Coal comes next because of its contribution in the power sector and in

industry. Natural gas comes third with a share of 21%, and having the highest growth rate.

Fig. 1. Global supply of primary energy sources in 20125

Natural gas is used as a source of thermal energy both in industrial applications and in spatial

heating of buildings in temperate countries, particularly during winter, and in the generation

of electricity. Fig. 2 shows the contribution from different sources of energy for generating

electricity globally in 2012. Out of a total generation of 22,668 TWh of electricity, the highest

contribution of 40% comes from coal, and the second is from natural gas with a share of 23%.

Hydro power comes third with a share of 16%. Next comes nuclear power with a share of

11% while oil share is only 5%. Historically, coal was the only source of energy available for

thermal power generation, and hence its high share. Oil is used mostly in countries where coal

is not available like in Sri Lanka. In the power sector, NG has the highest growth rate and its

share is expected to reach 25% by 2025.6

Natural gas is a feedstock used to make a variety of industrial products such as fertilizer, anti-

freeze substances, plastics, pharmaceuticals and fabrics. It is also used to manufacture a wide

range of chemicals such as ammonia, methanol, butane, ethane, propane and acetic acid. Many


6

industrial processes require heat to melt, dry, bake or glaze such products as glass, steel, cement,

bricks, ceramics, tile, paper, food products and many other commodities during their manufacture

and NG is used in all these applications. It is a ready source of hydrogen in applications that need

this gas such as in fuel cell generators. With on-board facilities, it is possible to obtain hydrogen

by reforming methane present in NG in fuel-cell powered vehicles.

Fig. 2. Global supply of energy sources generating electricity in 20127

2.3 Transportation of natural gas

The bulk of NG is found in Russia, Qatar and Iran as shown in Table 1. Gas is also found in North

America, China and the Middle East (ME) and in small quantities in SE Asia, Australia, Norway,

South America and in some African countries. The gas needs to be transported from its sources to

places where it is required to generate energy and manufacture of consumer goods. Where the

source and the consumer are within the same continent, the gas is transported on land over long

distances by pipelines within territories and across national boundaries.

Across oceans, NG is transported in liquid form. Liquefaction needs cooling down to -162oC

when its volume gets reduced to 1/600 of the original volume. Traditionally, the liquefied

natural gas (LNG) is transported in special purposely-built carriers over thousands of

kilometres across oceans. Loading and unloading of LNG requires special terminals built on

jetties at least 16 m deep enabling LNG carriers to berth alongside them for feeding on-shore

terminals. Floating off-shore terminals have also been developed recently. A typical LNG

ocean carrier is shown in Fig. 3. These have capacities in the range 135,000 – 250,000 m3 and

may cost approximately USD 160 million for a smaller carrier.

In order to meet the needs of small consumers, the industry has recently developed a system

whereby LNG is filled into an insulated cylindrical tank enclosed in a steel framework that would

fit on to a standard 20 ft. container truck. A load of such containers could be transported in a

standard container carrier across oceans and once it reaches a port the containers can be unloaded

on to trucks using existing port facilities and taken direct to a yard for storage until


7

dispatched to a consumer. Such systems are commercially available today and eliminates the

use of expensive terminals8.

At the consumer site, the container is transferred on to a platform from where it could serve as

a storage system, preferably with room to keep a spare container. A gasification unit will

convert the liquid into gas and transfer the gas onto a pipeline to feed the gas to individual

consumers, be it a small power plant, an industry or a hotel or a housing scheme where the gas

has to be supplied at low pressure. Where the gas has to be supplied to a CNG dispensing

outlet, the gas is compressed and transferred in trucks to the way-side dispensing units.

For delivery over short distances, there are two options – deliver either as CNG or as LNG. In

the former, the gas is compressed and the cylinders filled with CNG are stacked into

containers for transport by road or railway. A container used for transporting CNG by road is

shown in Fig. 4. These containers are built to withstand high pressures and impacts.

Fig. 3. A carrier transporting LNG across

oceans

Fig. 4. A bulk container for transporting

CNG over short distances

LNG is also transported in bulk carriers over short distances by road or railway. This has now

been extended to supply NG to local users as an alternative to pipe-lines and CNG carriers9. LNG

has 2.4 times more energy density than CNG and require only 29 percent of the space of CNG to

store the same amount of energy. Hence, it is more economical to transport NG as LNG rather

than as CNG. Today small liquefaction plants are available which can be used to produce LNG on

small scale for feeding containers for transporting over short distances to consumers.

In the event LNG is imported in cylinders loaded into containers, the container with LNG

itself could be transferred to a consumer site. LNG could also be delivered to industries to

operate power plants or for generating thermal energy. A facility for storing LNG prior to

dispensing to vehicles is shown in Fig. 5, while Fig. 6 shows a truck transporting a load of

LNG to a consumer centre or dispensing outlets for vehicles.

In order to distribute gas extracted from Sri Lanka’s deposits within the country, there are 3

options available - transporting gas by pipelines; transport of CNG by trucks or transport of

LNG by trucks. Each option has its advantages and disadvantages. Pipelines are costly to lay


8

but needs little recurrent expenditure on maintenance and recompression and are economical

on the long-term. Transport by CNG/LNG trucks need initial investment for the fleet of trucks

and in addition, their cost of transport, expenditure on both fuel and operators need to be met.

Fig. 5. A facility for storing LNG prior to

distribution to users

Fig. 6. A LNG container being transported

by truck to a bulk consumer

The necessary infrastructure facilities that need to be provided will include compressor units

in the case of CNG and liquefaction facilities in the case of LNG. Today, LNG is the

preferred mode of transport for distribution in bulk and also as a fuel for long distance hauling

trucks and buses. Sometimes the LNG container itself is unloaded from the prime mover and

kept at the site for delivery of gas to users. The LNG also could be fed to a compressor after

gasification where the gas could be compressed to high pressure ~250 bar for supplying

dispensing units for feeding CNG vehicles.

Pipelines carrying NG are costly. A recent publication on gas transmission costs in Australia

has indicated capital costs in the range USD 42,000 – 50,000 per km.inch for distances below

1,000 km10

. In addition, non-capital costs are estimated to be about USD 18,000 per km.

Generally, gas is transported in pipelines over long distances at pressures about 25-100 bar. A

100 km long, 24 inch pipeline will therefore cost about USD 120 million taking the high end

rate. The size of the pipeline will need to be determined on the expected volume to be

transported a day. Globally, the investment required to lay a long distance, large diameter line

(46 to 60 inches), enabling a throughput of about 15 to 30 Bcm/year, currently amounts to

about $1 billion to $1.5 billion/1000 km, which is about USD 25,000 per km.inch11

. In Sri

Lanka, it may not be possible to cover the entire country with a network of pipelines, except

perhaps between principal towns. With the government’s programme to build highways in all

parts of the country, provision could be made to lay pipelines for carrying NG along highway

reservations.

However, a more plausible option is to transport the gas to distribution centres either as CNG or

as LNG. Between transport as CNG and LNG, there are advantages and disadvantages. CNG

requires storage of gas at high pressure typically 200 – 275 bar and hence require heavy tanks


9

of high tensile strength. Construction of tanks with low quality material could cause accidents

with heavy casualties as has happened recently in Pakistan where there had been several

accidents due to poor quality of material used for tanks12

.

On the other hand, LNG requires liquefaction equipment and storage tanks both on vehicles

and at distribution centres. They need to be well thermally insulated to maintain the liquid at -

162oC to keep vaporization of gas to a minimum. LNG storage pressures are typically around

3 to 10 bar. Vehicles transporting either CNG or LNG need to be constructed with special

protection features to prevent any damage to the containers and subsequently become a hazard

to people. It is to be noted that transport of CNG or LNG by container trucks is no more risky

than transporting petroleum fuel by road in bowsers.

2.4 Availability of natural gas in Sri Lanka

The study team was made to understand that commercial production of gas will commence by

2018 at a rate of 70 million cubic feet a day (Mcf/d), with the possibility of expanding the

production to 140 Mcf/d in 2021, and to 210 Mcf/d in 2023. Hence, it is necessary to plan its

consumption at matching rates. The most obvious choice for the first phase would be the

conversion of the three combined cycle gas turbine (CCGT) power plants to operate with NG.

One of these is at Kerawalapitiya (300 MW) and the other two are at Kelanitissa (165+163

MW). These 3 plants have a combined demand of about 93 Mcf/d operating at optimum

conditions. A pipeline from Kalpitiya CST could be built to carry gas to the plant at

Kerawalapitiya and to the two plants at Kelanitissa.

With the possibility of expanding the production beyond 210 Mcf/d, it is necessary to

examine and prioritize possible consumers to whom gas could be supplied. This would be

carried out once the demand aspects of energy are examined later in the discussion. In the

meantime, possible systems for distributing the gas to consumers need to be examined. The

possible consumers are power plants, transport terminals, heavy industries, large hotels,

industrial estates and townships.

2.5 Conversion to liquids

There is a fourth option available for distribution of NG to user centers by converting the gas

into a liquid which can be transported with ease. There are several candidate liquids available

but the best is Dimethyl Ether (DME). This has properties similar to those of diesel and LPG

and could be used as substitutes for them with only little modification. Table 3 gives the basic

properties of DME along with those of other fuels. Another option is to convert into methanol.

The conversion of NG to DME will circumvent the problems associated with transporting NG

as it is, without having to compress or liquefy the gas. The process starts with gasifying the

natural gas yielding syngas comprising mainly hydrogen (H2) and carbon monoxide (CO),

which are then chemically synthesized into methanol (CH3OH). In the next stage, methanol is

subject to dehydration producing dimethyl-ether (DME) (CH3OCH3). It is also possible to

produce DME directly bypassing methanol by using a special catalyst (trade proprietary).


10

Table 3. Basic properties of Dimethyl Ether (DME)

Property DME LNG LPG Diesel

Boiling Point oC -25 -162 -42 180-360

Calorific Value kcal/kg 6,900 12,500 11,000 10,500

Specific Gravity 0.73 - 0.49 0.845

Ignition Point oC 235 630 500 250

Explosion Limit % 3-17 5-15 2-9 1-7

Cetane No. 55-60 - 5 40-55

DME is a gas at normal pressure and temperature and could be liquefied under mild pressure

and filled into cylinders as done with LPG, making it easier to transport. However, there is a

certain loss of energy when converting NG into DME. The development of the technology for

the production of DME from NG could even be developed locally. It will be then possible to

use the technology for converting biomass also to DME. There are many advantages in doing

so including enhancing the efficiency of biomass utilization for cooking from about 10% to

about 40% and elimination of indoor pollution as well as convenience to the user.

There are two aspects that need to be taken note of in using DME. First is the low calorific

value (6,900 kcal/kg vs 10,500 kcal/kg for diesel oil), which means that a vehicle operating

with DME has to carry 1.5 times the quantity of diesel by weight to cover the same distance.

The other is the similarity of the cetane number with that of diesel, which means that DME

has self-igniting properties when compressed and hence its suitability for use in CI engines.

The use of DME as an automotive fuel in place of diesel oil, particularly in heavy vehicles, is

becoming popular in European countries in view of its low emission levels of pollutants. Even

when used if domestic cooking in place of LPG, it burns with a blue flame devoid of soot,

hydrocarbons and particulates causing no indoor pollution. The topic of producing DME from

NG will be further discussed later in the report.

The other option is to convert NG into petroleum-like fuels such as diesel oil and LPG.

Technology for such conversion from gas as well as from coal is already available with Sasol

in South Africa13

. In the absence of oil in the country, S. Africa is depending on this

technology to utilize its coal and gas resources as automotive fuels.

2.6 Safety aspects

Natural gas being lighter than air, gets dispersed quickly in the event of a leak, unlike in the case

of LPG which remains at ground level and pose the risk of an explosion. Such explosions do

occur when a person walking into a kitchen switches on a light when a spark that appears in


11

the switch ignites the LPG gas. Such incidents will not happen with NG, unless there is a

continuous leak and a naked flame is brought in. Such instances, though rare, have been

reported in the past, the latest being in India on 27.06.2014 when fourteen people were killed

and 20 injured in a blast and fire at a leaky gas pipeline in Andhra Pradesh, India14

. This is

obviously a case where adequate precautions had not been taken by the authorities to monitor

leaking pipelines and necessary precautions taken. Today, many sophisticated gas leak

detection systems both in-situ and remotely monitored are available and it is important that

such systems are incorporated into the system.

Even if the gas gets accumulated inside a room, it becomes flammable only if the gas-to-air

mixture remains within 5-15%. When the mixture is below 5%, there is insufficient gas to

ignite, and when the mixture is above 15%, there is insufficient oxygen for the gas to burn. Its

auto-ignition temperature is 538oC at atmospheric pressure, which is higher than that for

gasoline. Hence, it is much safer to handle than liquid fuels.

When NG is distributed to consumers, a trace odorant is added to detect any leak in the

system. In the NG industry including transport of gas through pipelines and as LNG across

oceans, strict safety procedures are adhered to so as to avoid any leakages and accidents. In its

over 60 year history of LNG transport, there has been hardly any major accident reported.

Whatever accidents happened were due to man-made errors. Overall, NG is much safer to

handle than LPG or other petroleum oils such as gasoline.

However, in the event NG is to be provided to consumers by pipelines through local networks

it is essential that public awareness campaigns are conducted to explain to the people the risks

involved and precautionary measures that need to be taken to minimize any hazards. It is also

necessary that all personnel handling distribution of gas either by trucks or by pipelines be

given a thorough training in all safety aspects that they are required to adhere to. The

authorities will have to formulate a set of guidelines and protocols to be followed by these

operators. It is also essential that all persons handling installations and maintenance of NG

distribution systems are licensed by regulatory authorities.


12

3. Energy supply in Sri Lanka 3.1 Total primary energy supply

The country’s present energy requirements are met mostly by biomass, oil, hydropower, coal

and to a less extent by non-conventional renewable energy (NCRE) sources. Biomass

contributes to about 45-50% of the total energy requirements, while oil is the next highest

source. Hydro power contributes to between 30 – 50% of the total electricity generated, but

contributes only a small fraction to the total energy supply, the actual value depending on the

way electrical energy unit is converted into a common energy unit (see Box 1). During the

past few years, contributions from NCRE sources such as wind power, solar power, mini-

hydro power and dendro power have come into the scene in a significant way.

Box 1. Common unit in energy supply

Quantities of different fuels used for generating energy expressed in their

original units, need to be converted to a common unit based on their heat

content for them to be summed up. Generally, the thermal energy unit Joule

(J) (4.1868 Joules = 1 calorie) is taken as this common unit. Every fuel -

gaseous, liquid and solid - has a specific calorific value and the heat content

of each fuel is obtained by multiplying its weight in tonne (t) by its net

calorific value (GJ/t). In the case of electricity from thermal power plants,

its energy content is taken as the thermal energy contained in the fuel burnt.

For the conversion of electricity generated from hydropower plants or from

NCRE sources, the international convention is to use the direct equivalence

of Joule and Watt which is 1 J = 1 Watt.sec or 1 Wh = 3,600 J.

In Sri Lanka however, local utilities use a factor based on the energy

content in a fuel (oil) generating an equivalent quantity of electricity in a

thermal power plant with an efficiency of 36%. This method gives an

energy content for hydro-electricity which is 2.79 times higher than that

obtained from the direct equivalence method. As a result, energy

consumption given by our utilities shows an inflated share for hydropower

and also a higher value for the total energy supplied.

The calorific values of fuels used to compute the country’s total primary energy supply (TPES)

are taken from the publications of the Sri Lanka Sustainable Energy Authority (SLSEA).

However, these are not exactly the same as those given in Ceylon Petroleum Corporation (CPC)

reports and publications of Intergovernmental Panel on Climate Change (IPCC) which provide

guidelines for the preparation of national greenhouse gas (GHG) inventories. Table 4 gives these

values quoted by these sources for commonly used fuels. These discrepancies amount to about 2-

4% which are reflected in all subsequent estimates including GHG inventories.


13

Since both the SLSEA and CEB use the oil substitution factor which gives an inflated value

for the hydro component, comparison of Sri Lanka’s power situation with other countries’

gives an unrealistic picture. These higher values are also not consistent with those given for

Sri Lanka in energy databases maintained by international organizations such as UN

Development Programme (UNDP), International Energy Agency (IEA), Economic and Social

Commission for Asia and the Pacific (ESCAP) and Asian Development Bank (ADB).

Nevertheless, in this report, for compatibility with SLSEA and CEB values, the oil

substitution factor used by them is included.

Table 4. Net calorific values of common fuels as quoted in different sources

Fuel Net Calorific Value kcal/kg

SEA15

CPC16

IPCC17

Diesel 10,500 10,180 10,350

Gasoline 10,900 10,470 10,700

Kerosene 10,500 10,390 10,690

LPG 10,600 10,960 11,300

Naphtha 10,900 10,720 10,750

Fur/Res Oil 9,800 9,830 9,600

Fig. 7 gives the breakdown of the TPES averaged over the period 2010 – 2012 expressed in

Peta-Joule (1 PJ=1015

J) using data given in SLSEA database. During this period, biomass has

contributed 44.3% to the country’s total energy requirements while oil has contributed 43.2%. Coal was introduced in significant amounts only in 2009 which has contributed to 2.5% during

2010-2012. Hydro power has contributed 8.4% to the energy supply and NCRE sources including

mini-hydro systems and wind energy plants have contributed the balance of 1.6%.

Total: 470 PJ

Fig. 7. Annual supply of total primary energy sources averaged over 2010-201218

The contributions from different sources to TPES during the period 2003 – 2012 is shown in

Fig. 8, according to which the TPES has increased from 385 PJ in 2003 to 483 PJ in 2012, a

25% increase. Hydro component has been varying from 27 PJ to 50 PJ which is dependent on


14

the country’s weather pattern. During drought years when the hydro component is low, more

thermal power is generated increasing the oil consumption during the year. One of the

country’s hydropower schemes, Mahaweli Project, also provides water for irrigation. Hence,

during drought periods, irrigation requirements may override energy generation increasing the

demand for thermal power.

An

nu

al

En

erg

y S

up

ply

PJ

600.0

Biomass Oil Coal Hydro NCRE

500.0

400.0

300.0

200.0

100.0

0.0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 8. Total primary energy supply during 2003-201219

3.2 Biomass supply

In the total energy supply, the highest contribution of 44 % comes from biomass. Most of this

supply is utilized for household cooking which is carried out in the traditional stoves whose

efficiency is not more than 10%20

. The balance energy is wasted as heat. If a more efficient

system of cooking, either energy efficient biomass stoves or LPG stoves, is used much of this

energy could be saved thus reducing the total energy supply. Another option is to convert

biomass into DME as mentioned previously.

Biomass is used in industries also, particularly in brick and tile industry as well as in tea

industry for withering plucked tea leaves. In these applications, the efficiency could be more

than about 50%. According to the Forestry Master Plan, biomass for use as fuel is obtained

from both forest and non-forest sources as shown in Table 6. Perera et.al. have estimated that

if all the agriculture residue and timber industry waste in the country are collected, the

biomass so collected would have heat content of about 63 PJ annually21

. The amounts

available as forecasted in 1995 for the period 2011-20 are also shown in Table 5.

Table 5. Availability of fuel-wood forecasted22

Source Availability in Estimate by SEA

2011-20 (kt) 2012 (kt)

Natural forests 760

Forest plantations 273

Plantations (coconut, rubber and tea) 10,091

Forest industry residues 533

Total 11,657 13,000


15

Fig. 9 shows the consumption of biomass in households and industries during 2001 – 2012,

and these data are taken from the Energy Balance Statement prepared by SLSEA. Though it

indicates the quantities of biomass used in the domestic sector and in industries separately, the

methodology of making these estimates is not given. In addition to fuel-wood, bagasse

generated in the sugar industry amounting to 130 kt in 2012 has also been used as a fuel. A

significant quantity of residue from agriculture including straw and crop residue left behind

after harvesting is also used as a fuel but it is not separately accounted for.

Bio

ma

ss c

on

sum

pti

om

kt/

y

14000

Household Industries 12000

10000

8000

6000

4000

2000

0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 9. Biomass consumption during 2001-201223

,24

3.3 Petroleum oil

Sri Lanka currently imports both crude oil and refined products. The amounts imported in

2012 are shown in Fig. 10. About 1/3 the country’s petroleum oil demand is met from crude

oil and the rest is imported on short-term contracts. The crude oil is refined at the local

refinery. Among the refined products imported, auto-diesel stands out with its share of

another 1/3 of the total oils imported. Table 6 shows the quantities of products refined locally

and refined products imported in 2012.

Avtur LPG Kerosine

4% 1% 6%

Fuel Oil Crude Oil

11% 32%

Gasoline 12%

Diesel

Total Imports : 5154 ktoe 34%

Fig. 10. Fossil fuels imported in 2012


16

Though there is a need either for expanding the capacity of the existing refinery or building a

new refinery, the high investment involved has deterred the process. The import of petroleum

products including refined products is a heavy burden on the national budget, already

claiming 26% of the total import budget in 201225

.

Table 6. Petroleum products refined locally and imported in 201226

Product Refined locally Imported

kt kt

LPG 17.44 192.6

Naphtha 70.88 -

Gasoline 151.57 574.6

Diesel 394.16 1652.2

Avtur 93.16 288.4

Kerosene 74.84 55.0

Furnace Oil 648.41 -

Fuel Oil - 563.7

Others 30.25 143.5

Total 1480.71 3470.0

3.4 Coal combustion

Coal has been used in the cement industry in quantities in the range 25-100 kt during the last

decade. With the commissioning of first phase of the coal power plant at Puttalam in 2011,

coal consumption has increased to 475 kt in 2011 and to 724 kt in 201227

. The third phase of

the plant was commissioned in September 2014. The import of coal to the western coast has

posed many problems –

Large coal carriers cannot reach close enough to coast because of the shallow sea and

hence the need to transfer to barges for transport to the coast. Transport from carriers to barge is not possible the year round because of the roughness of

the sea during South-West monsoon months.

This has necessitated storage of adequate stocks of coal to tide over the periods when such

transfer is not possible.

The use of coal for energy generation has been favoured by energy planners on the grounds

that production cost is cheaper with coal than with other sources. The introduction of coal for

power generation was delayed several decades because of the protests from the public on

social and environmental grounds. In the eighties, the CEB planned to build a coal power

plant (CPP) in Trincomalee, at a site close to the airport. With the objections raised by the Sri

Lanka Air Force and also due to environmental and other factors, the project was not pursued.

The CEB next selected a site on the southern coast near Mawella where the sea is deep, but again

due to public protests on environmental grounds, the project was not pursued. Subsequently, after

considering several sites on the west coast, the present site at Norochcholai


17

(Puttalam) was selected. However, its implementation got delayed many years again due to

public protests on both social and environmental grounds. It may be mentioned that

environmental laws requiring environmental considerations and approvals on large projects

including power plants came into force only in 1988 and hence no consideration was given for

the high pollution caused by coal.

3.5 Hydro power

Water in many of the rivers flowing from central highlands is being harnessed to generate

hydroelectricity meeting about 30-60% of country’s electricity requirements. Sri Lanka’ first

major hydro-power plant was built more than 60 years ago on the tributaries of Kelani Ganga

exploiting the height difference between two of them, Maskeliya Oya and Kehelgamuwa Oya

which flow parallel to each other. Today, there are altogether 5 major power plants in this

scheme, referred to as Laxapana Complex, with an aggregate installed capacity of 335 MW

generating an average of 1,376 GWh annually during 2001-201028

. This is 88% of the

designed aggregate generation of 1,563 GWh29

. The last power plant with a capacity of 35

MW in this complex is currently under construction at Broadlands near Kitulgala. Most of the

plants in Laxapana Complex were installed more than 50 years ago and some of them are

being rehabilitated currently.

Mahaweli Ganga has been exploited for hydro power development during 1970-2000. There

are 6 major power plants in the Mahaweli Scheme with an aggregate installed capacity of 810

MW generating an average of 1,542 GWh annually during 2001-2010. This is 58% of the

designed aggregate generation of 2,667 GWh. It may be noted that Mahaweli Scheme is a

multi-purpose project providing water for both electricity generation and irrigation in the dry

zone. The hydro power plants in the Laxapana complex and Mahaweli scheme were the main

sources of electricity generation for over 5 decades – fifties to nineties. Some major reservoirs

built under the Mahaweli Scheme several decades ago are also being rehabilitated with

funding from the World Bank. A noteworthy factor is while the CEB earns much money by

selling electricity generated in Mahaweli complex, it does not pay any money to the Mahaweli

Authority for the water it supplies and even to carry out maintenance of the facility.

3.6 Non-conventional renewable energy resources

The National Energy Policy and Strategies of Sri Lanka developed by the Ministry of Power

and Energy in 2006 has declared that the Government will endeavor to reach a minimum of

10% of energy supplied to the national grid from Non-Conventional Renewable Energy

(NCRE) resources by 201530

. The NCRE sources include small-scale (<10 MW) hydropower,

biomass including dendropower, biogas and waste, solar power and wind power. According to

the CEB Statistical Digest 2013, the generation from the private sector NCRE sources and

CEB’s wind power plants with installed capacity amounting to 366 MW, has been 1,178 GWh

in 2013, when the total generation was 11,962 GWh, giving a share of 9.85% from NCRE

sources, almost reaching the target of 10% given in the energy policy.


18

In order to promote the development of NCRE resources and to regulate the industry, the

government has established the SLSEA in October 2007. According to SLSEA statistics, there

is potential to increase the installed capacity to nearly treble the above value when all the

plants either approved or provisionally approved are commissioned. It has also been estimated

that a total of 650 MW of installed capacity of NCRE sources would be commissioned by

2015, enabling compliance with the energy policy targets. The breakdown of the expected

capacities is shown in Table 7.

Presently, the development and operation of NCER sources with capacities up to 10 MW are

assigned to the private sector. Two projects funded by the Global Environment Facility

(GEF)31

, one called Energy Services Delivery (ESD) Project implemented during 1997–2002,

and a second project - Renewable Energy for Rural Economic Development (RERED)

implemented during 2002-2007 provided the initial impetus for the development of renewable

energy industry in Sri Lanka.

Table 4. Commissioned and committed NCRE projects32

Installed Capacity MW

Category Commissioned Expected Permits Provisional

by 2013 by 2015 issued approvals

Small Hydro 243 350 190 98

Wind Power 73 230 32 20

Biomass/Waste 16.5 40 100 45

Solar PV 1.4 30 10 72

Total 334 650 332 235

Box 2. Non-conventional renewable energy sources

Renewable energy sources include both conventional and non-conventional

systems. The former includes large hydropower plants and traditional biomass

systems, while the latter includes those driven by solar radiation (photo-voltaic

and solar thermal), winds, oceans (waves, currents, tides) as well as efficient

biomass (direct combustion, gasification) and biofuel (ethanol, bio-diesel)

systems. Small hydropower systems typically below 10 MW capacity operating as

run-of-the-river projects are also included under NCRE systems.

Non-renewable energy systems include those burning fossil fuels and utilizing

nuclear fuels. Of the NCRE sources, strictly only hydropower systems (renewed

by precipitation) and biomass systems (renewed by replanting) are renewable

while the rest are operational all the time so long as the Earth System exists.

Hence, these could be classified as inexhaustible sources while non-renewables

are exhaustible sources. However, sources such as solar PV, wind and small

hydro, are unable to provide energy at all times, due to natural fluctuations in

cloud cover, wind regimes and precipitation, respectively.


19

4. Energy demand in Sri Lanka

Energy is the driving force behind all other sectors – economy, agriculture, household and

commercial, industry, transport and power. All these sectors could operate efficiently and

economically only if primary energy could be provided in a reliable and affordable manner.

While biomass is used mostly for generating thermal energy in households and industries,

petroleum oil is used for generating motive power in the transport sector and for operating

thermal power plants driven by steam/gas turbines and diesel engines. Petroleum oil including

fuel oil, liquid petroleum gas (LPG) and kerosene are used in industries for generating thermal

energy and as a feedstock while in households LPG and kerosene are used for cooking and

lighting purposes, respectively. A small amount of LPG is used in the transport sector also.

The energy consumed in each of the key sectors is discussed below as these are the areas in

which NG could be made use of as an alternative source of thermal energy.

4.1 Household and commercial sector

Among the fossil fuels consumed in the household and commercial (HH&C) sector are mostly

LPG for cooking and kerosene for lighting and cooking. Small amounts of diesel and fuel oil

are also used in the commercial sub-sector. Biomass is used widely for cooking in households,

but it is not considered in this study. Fig. 11 shows the amounts of different fuels consumed

during 2001 – 2012. There has been a general decline in the overall fuel consumption during

2001-2007, but thereafter there has been a positive trend. Between 2008 and 2012, the overall

fuel consumed in the sector has increased at an average rate of 8.3%. Between 2001 and 2012,

the population has increased from 18.80 million to 20.28 million, which is a 7.88% increase.

However, neither the LPG consumption nor the kerosene consumption has showed a

corresponding increase during this period.

An

nu

al

con

sum

pti

on

TJ

20000 Kerosene LPG Diesel F.Oil

18000

16000

14000

12000

10000

8000

6000

4000

2000

0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 11. Consumption of fossil fuels in the household and commercial sector33

Table 8 shows the pattern of fuel usage in cooking and lighting in households, according to the

Household Income and Expenditure Survey 2012/13 conducted by the Census and Statistics

Department. The data given therein show that there is much scope for penetration of LPG into

semi-urban and rural areas, and the consumption of biomass for cooking will bound to decline.


20

It is also likely that kerosene consumption for both lighting and cooking will decline with the

penetration of electricity and LPG into rural and estate areas.

Table 8. Pattern of fuel usage in cooking and lighting 2012/1334

Sector Cooking (Percent) Lighting (Percent)

Firewood LPG Kerosene Electricity Kerosene

RE

Urban 35.2 55.5 9.2 97.0 2.7 0.4

Rural 85.7 12.0 2.3 87.5 11.3 1.6

Estate 95.3 2.4 2.3 82.8 16.9 0.2

National 77.5 19.0 3.5 88.9 10.1 1.1

4.2 Agricultural sector

Sri Lanka was traditionally considered to have an agricultural economy. However, today the

contribution from the agricultural sector to the national GDP is the least as shown in Fig. A7.

There has been a regular growth of this contribution from agricultural activities to the GDP at an

average rate of 3.8%, as shown Fig. 12. According to SLSEA data, only a negligible amount of

fuel is consumed by the agriculture sector, despite many activities in the agricultural sector today

are mechanized as illustrated in the population of land vehicles given in Fig. 17.

GD

P f

rom

Ag

ri M

illi

on

LK

R

350,000

300,000

250,000

200,000

150,000

100,000

50,000

-

Av Growth Rate : 3.82%

2005 2006 2007 2008 2009 2010 2011 2012

Fig. 12. Contribution to real GDP from agriculture

In areas where there are large extents of paddy-land such as Ampara, Polonnaruwa and

Kurunegala districts, mechnized harvestors are being used regularly. However, fuel used for these

applications are not recorded separately and hence cannot be accounted for correctly. A proper

estimate of energy used in the agriculture sector could be undertaken by working out the specific

energy required to produce one tonne of rice, made tea, processed rubber and coconut and

determing the total energy from the total production of each of these produce annually.

A high percentage of agriculture in the dry zone is carried out under lift irrigation systems where

water is extracted from deep or sub-surface wells using high capacity water pumps. These are


21

operated with diesel or kerosene purchased from wayside retail outlets and as such no separate

records are maintained on such uses.

All these activities need fuel to operate and one would expect that the demand for fuel for

agriculture also will show a growth corresponding to the growth in agriculture output shown

in Fig. 12. However, the consumption of fuel under agriculture has recorded a regular decline

from 2005, except in 2010, as shown in Fig. 13. This may be due to the fact that fuel for

agriculture would have been obtained from wayside fuel outlets where the amount sold is

recorded under transport sector and not under agriculture sector. Agriculture contributes a

significant share for the GDP and as such even in the energy consumption in this sector one

would expect a corresponding contribution.

An

nu

al

con

sum

pti

on

TJ

700.00

Diesel F.Oil

600.00

500.00

400.00

300.00

200.00

100.00

- 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 13. Consumption of fuel in agricultural activities35

4.3 Industrial sector

The industrial sector has contributed between 29.4% and 31.5% to the national GDP during 2007-

2012. Fig. 14 gives the contributions of value addition in different sub-sectors during 2007

– 2012 based on 2002 prices. These show an average growth of 5.86% during this period.

LK

R

500000

450000

400000

Average growth rate : 5.86%

Food & Bev

Va

lue

ad

dit

ion

Mil

lio

m 350000

Textile & App 300000

Chem & Rubb

250000 Minerals

200000 Machinery 150000 Other 100000

50000

0 2007 2008 2009 2010 2011 2012

Fig. 14. Contribution to industrial GDP from different sub-sectors36


22

The highest contribution has come from the Food, Beverage and Tobacco sub-sector, while

Textiles & Apparel and Chemical and Rubber too has made significant contributions.

However, contribution from other industrial sub-sectors, particularly the high energy intensive

industries has been minimal. As shown in the Appendix, the contribution from the industry

sector to GDP has been lower than that from the services sector.

Fuel used in the industrial sector comprised kerosene, diesel, fuel oil, LPG, coal and biomass.

The consumption of the fuels other than biomass during 2001-2012 is shown in Fig. 15. Coal

is used in the cement industry. While the industrial contribution to economy shows an annual

growth of 5.86% during 2007-2012, the fuel consumption in the sector does not show a

corresponding growth; it has been a negative growth during 2005 – 2011, while only 2001-

2003 and 2011-2012 periods show positive growths. Between 2001 and 2012, there has been a

increase in the overall fossil fuel consumption varying between 13,525 TJ in 2001 and 14,409

TJ in 2012, while there has been ups and downs in between.

Fig. 15. Consumption of fossil fuels in the industrial sector37

4.4 Transport sector

During the last decade there has been a rapid growth of vehicle usage both gasoline operated

and diesel operated. As shown in Fig. 16, among the gasoline operated vehicles, motor cycle

population has far exceeded that of the rest. The total gasoline operated vehicle population

showed an annual growth in the range 7.0 – 14.5 % with an average of 11.3%.

The freedom of mobility for the youth that is available with the motor cycle is responsible for

the rapid growth of motor cycle population, while the availability of compact gasoline

operated motor cars at an affordable price for the middle class also has contributed to their

growth. In addition, the granting of duty concessions to the public servants for the import of

motor vehicles is another factor responsible for this growth. Unlike in developed countries,

people in Sri Lanka tend to use a motor car for at least two decades and hence the fleet

contains a high fraction of aged vehicles. Natural Gas – New Energy Resource Sri Lanka Carbon Fund

23

Veh

icle

Po

pu

lati

on

Mil

lio

n

4.5

4

Motor Cars Motor Tricycle Motor Cycles 3.5

3

2.5

2

1.5

1

0.5

0

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 16. Growth of gasoline operated vehicles during 2003 - 201238

In the case of diesel oil operated vehicles, their population showed a much slower growth as

shown in Fig. 17, than that shown for gasoline operated vehicles. Their annual growth was in

the range 3.0 – 8.4 % with an average of 6.3%. The dual-purpose vans, lorries and land

vehicles more or less equally shared the population while the bus population is much less.

Veh

icle

Po

pu

lati

on

Mil

lio

n

1.2

Buses Dual purpose Lorries Land vehicles

1

0.8

0.6

0.4

0.2

0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 17. Growth of diesel operated vehicles during 2003 - 201239

With the growth of vehicle population as shown above, a corresponding growth in their fuel

consumption is expected. Fig. 18 shows the consumption of diesel and gasoline separately for the

period 2002 – 2012. While data on gasoline consumption show somewhat a similar growth rate as

in the case of gasoline operated vehicle population, data on diesel consumption however shows a

marked different behavior. Between 2002 and 2004 and also between 2007 and 2008, diesel

consumption shows a negative growth. These curves also imply that the annual distance travelled

by the diesel vehicles is much higher than that of gasoline operated vehicles. It could be that

diesel oil consumed in other sectors including agricultural, fisheries and industrial were recorded

under transport as these would have been purchased from way-side fuel outlets.


24

Fig. 18. Annual consumption of gasoline and diesel during 2002 – 201240

The combined consumption of diesel and gasoline is shown in Fig. 19 for the period 2001-

2012. Though the population of vehicles was increasing monotonically, the fuel consumption

does not appear to follow the same pattern as it could be subject to other factors such as price

escalation of fuel.

An

nu

al

con

sum

pti

on

PJ

120.0

Diesel Gasoline 100.0

80.0

60.0

40.0

20.0

-

2001 2002 2003 2004 2005 2006 2007 2008

2009 2010 2011 2012

Fig. 19. Growth of fuel consumption for transport during 2001-201241

4.5 Power sector

The term power sector is being used by policy makers and the general public to refer to the

electricity generation sector though it is not technically correct. Electricity is one form of

energy, while power refers to the rate of generation of energy whether electrical or otherwise.

Nevertheless, in this report, the term power sector will be used to describe the electricity

generation sector for the benefit of those who are familiar with it.

Up to about early nineties, almost all of the country’s electricity requirements were met from

hydro power plants except for the few thermal power plants in existence prior to the hydro era. In

recent years however, about 40-60% was met from hydro and the balance from thermal power

plants. These comprised a variety of oil-fired plants including compression-ignited (IC) or


25

diesel plants, steam turbines or gas turbines fired with either diesel oil or fuel oil or naphtha.

The gas turbines are of either low-efficient single cycle or high-efficient combined cycle type.

The fraction of hydro power generated also depends on the amount of water diverted from

Mahaweli Ganga for irrigation, which limits the water available for power generation.

Since 2011, power plants with coal-fired steam turbines (ST) were introduced and these were

the key players in the generation of electricity in the country as given in CEB’s Long Term Generation Expansion (LTGE) Plan. The present mix of generation technology comprises

diesel-oil/fuel-oil/residual-oil fired diesel plants, diesel-fired gas turbine plants, diesel/fuel oil-

fired combined cycle plants and the latest coal-fired power plants. The details of these thermal

power plants are shown in Table 9.

Table 9. Existing thermal power plants and retirement plan42

Power Plant Commis Installed Ouput

Retire’t

Operator Technology -sioned capacity 2010 Location Year

Year MW GWh

Kelanitisa CEB Gas Turbine 1981/82 5x20 26.18 2014

Kelanitissa CEB Gas Turbine 1997 115 27.10 2023

Sapu’kanda A CEB Diesel 1984 4x20 360.42 2020

Sapu’kanda B CEB Diesel 1997/99 8x10 480.35 2025

Sapugaskanda Lakdhanavi Diesel 1997 24 126.18 2013

Sapugaskanda Asia Power Diesel 1998 51 325.00 2018

Chunakam CEB Diesel 1999 8 55.74

Colombo Col-Power Diesel 2000 60 460.96 2015

Jaffna Nort-Power Diesel 2000 30 2018

Kelanitissa CEB CCGT 2002 165 493.30

Matara Ace Power Diesel 2002 20 154.72 2018

Horana Ace Power Diesel 2002 20 163.22 2018

Kelanitissa AES Ltd CCGT 2003 163 464.13 2023

Puttalam Heladhanavi Diesel 2003 100 643.82 2015

Embilipitiya Ace Power Diesel 2004/05 100 640.46 2015

Kerawa’pitiya West Coast CCGT 2008/10 300 547.10

Puttalam CEB St’m Turb 2011 300

The growth of installed capacity of electricity generating units during 2001-2012 is shown in

Fig. 20. For most years, the installed capacity of hydro and thermal power plants appear to be

similar.The insatlled capacity of large hydropower plants has reached 1,355 MW, and with

two more plants under construction at Broadlands (35 MW) and Uma Oya (120 MW), the

total installed capacity will reach 1,510 MW. Two more plants are included in CEB’s LTGE

Plan as candidate projects for future implementation, one at Deniyaya on Gin Ganga (49 MW)

and another at Moragolla on Mahaweli Ganga (27 MW). Work on a new irrigation project has

already commenced at Moragahakanda with two reservoirs, one built across Kalu Ganga


26

(Matale District) and second across Amban Ganga with a link tunnel. The project also includes

building a hydropower plant with capacity 25 MW43

. However, it is not included in CEB plans.

C

ap

aci

ty M

W

1800

1600 Hydro Thermal NCRE

1400

1200

1000

800

600

400

200

0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 20. Growth of installed capacity of electricity generating units 2001-201244

While the installed capacities are more or less similar for hydro and thermal plants, their

generation outputs differ widely, thermal energy dominating over the hydro energy except in

one or two years as seen in Fig. 21. The droughts occuring frequently imposing limits on

hydro power generation would have been one reason for this disparity.

An

nu

al

gen

era

tio

n G

Wh

9000

8000 Hydro Thermal NCRE

7000

6000

5000

4000

3000

2000

1000

0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 21. Growth of generation from different sources during 2001-201245

A variety of petroleum fuels – diesel oil, fuel oil, residual oil, naphtha and coal are used for

the generation of electricity. Their annual consumption for the generation of electricity for the

period 2001 – 2012 are shown in Fig. 22. The fuel consumption shows somewhat an inverse

relationship with the hydro-power generation shown in Fig. 21 as expected.

The consumption of electricity by different sectors during 2012 is shown in Fig. 23. It is seen

that the highest consumption is in the domestic sector having a share of 39% while the

industrial sector has consumed only 34%. This shows the low level of industrial base in the

country, which is also evident from the fact that the peak in the daily consumption pattern

takes place during the lighting time of 1900 – 2230 h.


27

An

nu

al

Fu

el C

on

sum

pti

on

P

J

80.00 Fuel Oil Diesel Res Fuel Naphtha Coal

70.00

60.00

50.00

40.00

30.00

20.00

10.00

0.00 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Fig. 22. Consumption of fuels for generation of electricity – 2001-201246

Comme rcial

Other

2%

25%

Dome stic 39%

Industries Total: 10,407 GWh 34%

Fig. 23. Consumption of electricity in differet sectors – 201247

It is an irony that the domestic sector which has the highest annual electicity consumption

among all consumer sectors nationally is consuming on an average only 63 units of per

household in 2013. Even though CEB has claimed that in 2010 the fraction of households

given electricity connections was only 88%, a report of household survey conducted in

2009/10 and published by the CBSL gives the fraction of households using electricity for

lighting as 85.3% nationally and 95.5% in the urban sector.

As such, there is much scope for increasing the demand in the domestic sector by increasing

the household consumption rate and also by increasing the number of households provided

with electricity connections which is only 96% in 2013. There are two reasons for the low

household consumption rate. One is the simple life style of most people who are satisfied to

use only the minimum appliances including a radio, TV, smoothing iron and a refrigerator in

addition to essential uses such as lighting. The other is the high tariff applicable to heavy

consumers which is an disincentive for people to use even moderate power consuming

appliances. Another reason for the total house-hold consumption to remain low is the

relatively high cost of appliances such as water heaters, air-conditioners, washing machines

etc. that consume moderate amounts of electricity.


28

4.6 Electricity consumption and national development

An indicator of a country’s development both in terms of economy and technology is its per

capita electricity consumption. Its growth in Sri Lanka during 2001-2012 is shown in Fig. 24.

The consumption is minimal because of the reasons given in the previous section.

Fig. 24. Growth of electricity per capita during 2001-201348,49

In 2012 and 2013, per capita consumption has reached 515 and 519 kWh/capita, respectively50

.

However, in most countries in Asia, except for a very few, this is far greater than Sri Lanka’s

as shown in Fig. 25 which gives the per capita electricity consumption values for 2011 for

Asian countries. When compared with these countries, Sri Lanka’s per capita electricity

consumption is way down close to the bottom of the list being ahead of only a few least

developed countries such as Cambodia, Myanmar, Bangladesh and Nepal. In almost all

developed countries in Asia, this value is above 2000 kWh/capita which is considered to be

the minimum required for a modern society needs51

.

According to a report published in 2007 by the Asian Development Bank (ADB) titled

“Energy for All”52

, a strong correlation is shown to exist between per capita energy,

specifically electricity, consumption, and levels of human development (HD). This report is of

the view that a minimum consumption of 4,000 kWh/capita is required for a country to

achieve a “decent” quality of living indicated by the HD index of 0.9. Sri Lanka’s HD Index

for 2012 has been only 0.715, and this has brought Sri Lanka into mid-way (92nd) out of 186

countries with HDI ranging from 0.955 (Norway) to 0.304 (Niger)53

. Sri Lanka is slightly

above the world average of 0.694 but is the highest in South Asia having an average of 0.558.

The ADB report further says that people living in countries with less than 1000 kWh/capita

consumption are considered to live in abject poverty and Sri Lanka is in this category. The

report has identified the challenge for these countries as not just to extend their electricity

networks to entire population and add incremental generation capacity as required, but the

ability to increase national incomes rapidly enough for people to actually be able to afford the

high cost of electricity.


29

Fig. 25. Distribution of per capita electricity consumption in Asia - 201154

In view of the extremely high cost of installing the capacity required to provide 4,000

kWh/capita level of electricity consumption, the report recommends that the developing

countries may set national per capita target of at least 2,000 kWh (corresponding to an HDI

level of 0.8) by 2015. For Sri Lanka, this is nearly a fourfold increase from the current level.

A more relevant factor that reflects the actual living standard of people is the per capita

electricity consumption in the domestic/household/residential sector. Fig. 26 gives these

values for 2011 for countries in Asia which are significantly lower than the overall per capita

electricity consumption shown in Fig. 25.

Fig. 26. Distribution of residential per capita electricity consumption - 201155

Sri Lanka with only 191 kWh/capita is in the bottom half even in this case and the disparity

between the less developed countries and developed countries in Asia is evident here. This

figure is consistent with the monthly household consumption of 67 kWh if each household

comprises 4.5 persons on an average. Sri Lanka is currently among the least consuming


30

countries and to reach the next tier of countries occupied by Thailand, Malaysia and countries

in the Far East, it has to increase its residential per capita electricity consumption by a factor

more than three. This is linked to the fact that most Sri Lankans’ earning capacity does not

permit them to purchase modern electrical appliances considered essential in developed

countries or invest on items that would make life comfortable such as air-conditioners.

According to a survey conducted in Sri Lanka in 2009/1056

, even the basic appliances are

being used only by a fraction of households; eg. radio (81%), television (80%), refrigerator

(40%), washing machine (13%), fans (51%) and video cassette player (36%). The high tariff

applicable to households consuming middle tiers of energy is also a disincentive for people to

invest on high current consuming appliances such as room air-conditioners and cookers.

4.7 Overall fossil fuel demand

The combined fossil fuel consumption in the household, agricultural, industrial, transport and

power sectors during 2001-2012 is shown in Fig. 27. Only the consumption of petroleum fuel

including LPG, gasoline, diesel, naphtha, kerosene, fuel oil and residual oil are considered. It

is noted that the major contributions come from the transport and power sectors. The

consumptions in the other three sectors – industry, household and agriculture – have remained

stagnant below 20 PJ, while the growth of overall consumption was demonstraded only by the

above two sectors – transport and power.

Fig. 27. Fossil fuel consumption in different sectors during 2001-2012

The breakdown of direct fuel consumption by these sectors for 2012 is shown in Fig. 28. The

largest share of 55.3% is consumed by the transport sector, second with a share of 29.0% is

consumed by the power sector, third with a share of 9.3% share is consumed by the domestic

& commercial sector while 6.3% consumed by the industries sector. The least share is

consumed by the agricultural sector with a contribution of only 0.1%. Both in the industrial

and household sectors, a major contribution to the energy demand comes from biomass

combustion and hence the low contribution from petroleum fuels in these sectors. However, in

the present analysis, contribution from biomass has been excluded.


31

HH & Com Industry

10% 6%

Power 29%

Transport

55%

Agriculture 0%

Total : 183.5 PJ

Fig. 28. Distribution of fossil fuel demand among different sectors - 2012

One sector that has not been included in the energy database is the Fisheries Sector.

According to Ministry of Fisheries and Aqautic Resources Statistics, Sri Lanka’s fisheries

fleet in 2013 had approximately 30,500 motorized boats comprising 24,000 one-day fibreglass

boats, about 4,200 multi-day boats and other traditional motorized boats. The average

gasoline consumption of a single day small boat has been estimated to be 1,500 litres

annually57

, and that of a large boat 25,000 litres annually58

. These work out to an annual

demand of 30 kt of gasoline and 100 kt of diesel. These are signifiacnt amounts when

compared with 750 kt of gasoline demand and 1,500 kt of diesel demand in the transpor

sector. Sri Lanka has about 20 fisheries harbours and 17 of these have fuel dispensing outlets.

Hence, it is possible to keep records of fuel consumption in the fisheriess sector.

4.8 Demand for natural gas as a feedstock

Natural gas is used as a feedstock in the manufacture of many chemical products. A basic

products that is manufactured from NG is ammonia (NH3), from which several fertizers

including urea (CO(NH2)2) and Ammonium Sulphate ((NH4)2SO4) are manufactured. These

fertilizers are widely used in Sri Lanka for several crops. Sri Lanka has imported 768 kt of

urea in 201159

. Assuming the consumption of urea will have an annual growth rate of 2.5%,

its consumption in 2014 is estimated to be 827 kt. In 2011, Sri Lanka has imported 66.65 kt of

ammonium sulphate for use as a fertilizer60

, which could have arisen to about 71 kt in 2014.

There is a potential to manucture both these fertilizers from natural gas in Sri Lanka in the

future. In both these cases, first ammonia is produced from NG and subsequently it is

converted to urea and ammonium sulphate (AMS).

Among the other products that can be manufactured from natural gas are methanol and ethanol,

also referred to as methyl alcohol (CH3(OH)) and ethyl alcohol (C2H5(OH)), respectively.

Methanol is toxic to humans when ingested, while ethanol is the main ingredient in liquor that

people consume. Methanol is the key industrial product manufactured from NG and traded world-

wide. Methanol has direct applications as a transport fuel, source of hydrogen in fuel-


32

cells and as a denitrifiction agent in waste water refining and as a trans-esterification agent in

biodiesel manufacture. It is also the key building block in the manufacture of a variety of

products such as formaldehyde, acetic acid and ethylene. Formaldehyde is used in the

manufacture of a wide range of industrial products such as paints, adhesives, resins and foam

material. In 2011, Sri Lanka has imported 9.86 kt of methanol worth USD 5.41 million worth

of methanol61

. A value of 10 kt has been assumed as the amount imported in 2011.

The manufacture of potable spirits is the key application of ethanol. It also has the potential

for use as a blend in motor vehicle fuel. In 2013, Sri Lanka has imported 10.42 million litres

or 8.42 kt of ethanol, while manufacturing about 11 million litres through distillation of local

agricuture products sourced from coconut, palmirah and sugar cane crops62

. The manufacture

and import of ethanol are regulated by the Exercise Department as they are heavily taxed.

About 600 t of ethanol are also used annually for the manufacture of industrial products such

as cosmatics and surface coatings. A value of 9.5 kt has been assumed for 2014 imports.

Ethanol when dehydrated yields ethylene. It is used as a raw material in the production of

polymers such as polyethylene, polyethylene terephthalate, polyvinyl chloride, and

polystyrene. These polymers are used in a wide variety of industrial and consumer markets

such as the packaging, transportation, electrical/electronic, textile, and construction industries.

It is envisaged that once NG is available in the country, industrialists would venture into

manufacture of these products from NG, provided some incentives are granted initially in

view of the high investments required to set up these plants.


33

5. Future Outlook

In order to plan for future energy needs in all sectors, it is necessary to make forecasts based

on some accepted methodologies. In Sri Lanka, such estimates are being made regularly only

in the power sector and the criterea used for these forecasts are described in their LTGE Plan.

Occasional studies are sometimes carried out in the transport sector also, but these do not

describe the basis for making the forecasts63

. In the absence of any accepted and reliable

methodologies except in the case of the power sector, the trends that had prevailed during the

past few years were used to make the forecasts for the future assuming the same trends to

continue in the future as well.


The fuels used in the HH&C sector, other than biomass, are LPG, kerosene, diesel oil and fuel oil.

Their consumptions from 2001 to 2012 were shown in Fig. 11, and their growth rates during the

last few years were found to be 6.2% for LPG, 5.3% for kerosene, 4.8% for diesel and 3.8% for

fuel oil. The estimated growth rate of LPG is consistent with that forecasted by one of the LPG

suppliers in the country, which is between 5-7% annually64

. However, with the subsitution of

kerosene with electricity for lighting and LPG for cooking, the growth of kerosene consumption

could be much less than the trends shown in the past few years and may be assumed to be 2%.

However, with more households shifting from biomass to LPG for cooking, its growth will

increase to 7%. Future forecasts for the growth of consumption of these fuels in the HH&C sector

asssuming annual growth rates of 7% for LPG, 2% for kerosene, 5% for diesel and 4% for fuel oil

are shown in Fig. 29. Values are also tabulted in Table 10.

Fig. 29. Forecasted growth of fuel consumption in HH&C sector

The combined consumption of LPG and kerosene which is 15.6 PJ in 2014 is expected to

grow up to 31.2 PJ in 2020 and 66.8 PJ in 2040. As shown in Table 8, in 2012 only 55% of

households in urban areas used LPG for cooking and only 12% in rural areas and hence there

is much scope for its growth. It is expected that the penetration of LPG to rural areas would

take place by switching from biomass to LPG for cooking in those areas.


34

5.2 Industrial Sector

The growth of industry depends on many factors including fiscal policies, political will,

foreign investments, infrastructure development, general economic growth and concessions

granted by foreign countries towards import of goods from developing countries. Though

economists have developed various mathematical models to make forecasts for future

industrial growth, they also depend on many factors that are not known with certainty. Hence,

a more practical approach than above is to extrapolate the trends over the last five years into

the future. As shown in Fig. 15, there has been a positive trend in the consumption of fuel oil

(0.42%), diesel oil (0.88%), LPG (6.25%) and kerosene (6.75%) in industries. Coal used in

the cement industry is assumed to have a 4% growth. Fig. 30 shows their growth projected up

to 2040 at the same average rates prevailed during 2008-2012. Values are tabulated in Table

10, which also gives the projections for the HH&C sector.

Fig. 30. Forecasted growth of fuel consumption in the industrial sector

Table 10. Projected fuel consumption in the HH&C and Industrial Sectors

Year HH&C Sector - BAU - PJ/y Industrial Sector - BAU - PJ/y

K'sene LPG F Oil Diesel

Total Coal F. Oil Diesel K'sene LPG Total

2014 5.72 9.85 1.27 0.60 17.43 3.14 6.36 3.04 1.10 1.42 15.05

2016 5.95 11.27 1.37 0.66 19.25 3.39 6.41 3.09 1.25 1.60 15.75

2018 6.19 12.91 1.48 0.72 21.30 3.67 6.47 3.15 1.42 1.81 16.52

2020 6.44 14.78 1.60 0.80 23.62 3.97 6.52 3.20 1.62 2.04 17.36

2022 6.70 16.92 1.73 0.88 26.23 4.29 6.58 3.26 1.85 2.30 18.28

2024 6.98 19.37 1.87 0.97 29.19 4.64 6.63 3.32 2.11 2.60 19.30

2026 7.26 22.18 2.03 1.07 32.53 5.02 6.69 3.38 2.40 2.94 20.42

2028 7.55 25.39 2.19 1.18 36.31 5.43 6.74 3.44 2.74 3.32 21.66

2030 7.86 29.07 2.37 1.30 40.59 5.87 6.80 3.50 3.12 3.74 23.03

2032 8.17 33.28 2.56 1.43 45.45 6.35 6.86 3.56 3.55 4.23 24.55

2034 8.50 38.10 2.77 1.58 50.96 6.87 6.92 3.62 4.05 4.77 26.23

2036 8.85 43.62 3.00 1.74 57.21 7.43 6.97 3.69 4.61 5.39 28.09

2038 9.20 49.94 3.24 1.92 64.31 8.04 7.03 3.75 5.26 6.08 30.16

2040 9.58 57.18 3.51 2.12 72.38 8.70 7.09 3.82 5.99 6.86 32.46


35

5.3 Transport Sector

Data on fuel consumption in the transport sector during 2008-2012 given in Fig. 19 shows

growth rates of 4.85% for diesel and 8.22% for gasoline. Assuming the same growth trends

will continue in the future, the demand for diesel and gasoline in the transport sector up to

2040 was computed and shown in Fig. 31. By 2040, diesel consumption will reach 253 PJ and

gasoline consumption will reach 313 PJ. The corresponding values for 2020 will be 98 PJ for

diesel and 64 PJ for gasoline. These correspond to 2635 Ml of diesel and 1870 Ml of gasoline,

respectively. The projected fuel consumption values in the transport sector up to 2040 are

given in the Table 12 along with those of the power sector.

According to Gunaruwan65

, the diesel vehicle fleet in Sri Lanka will consume 4419 Ml of diesel

and forecasts consumption of 3,737 Ml of gasoline on motor car operation by 2020. These are

approximately 1.7 times the forecasted value in this study for diesel and nearly twice that

forecasted for gasoline for the same period. These higher growth rates have been arrived at

considering the rapid economic growth of the country along with expansion of the road network

enabling people to move about much easier in the future. It must be borne in mind that the present

development being carried out in vehicle technology may introduce new systems such as fuel-cell

operated vehicles in place of IC engine driven vehicles within the next few decades. Fuel cells

operate on hydrogen and oxygen. While oxygen can be sourced from air, H2 can be obtined from

several sources. One is electrolysis of water using direct current, which can be generated from

stand-alone wind turbines or solar PV systems. Another is NG (see Box 3).

Box 3. Natural gas as a source of hydrogen for fuel cells

Fuel-cells are electro-chemical systems which generate electricity when hydrogen

(H2) and oxygen (O2) are supplied to the cell, producing only water vapour as

exhaust gas; that is producing absolutely zero pollution. Oxygen is sourced from

air, and H2 could be sourced in one of several ways; firstly by direct feeding H2 gas

from gas outlets, secondly by feeding natural gas (NG) or thirdly from methanol.

From the last two, H2 is obtained through on-board reforming. It is also possible to

fire normal SI engines using H2 as a fuel.

The United Nations Industrial Development Organization (UNIDO) has established

in 1994 the International Centre for Hydrogen Energy Technologies (ICHET) in

Turkey with the mission of demonstrating viable applications of hydrogen energy

technologies. A number of projects have been implemented to demonstrate the

viability of using H2 as the source of energy. Among these are projects to promote

operation of 3-wheelers in New Delhi, H2 fed hybrid buses in Turkey and fuel-cell

based stand-by power systems, all using H2 generated from renewable sources such

as wind turbines and solar PV systems.


36

Fig. 31. Forecasted growth of fuel consumption in the transport sector.

5.4 Power sector

The forecasting of future demand in the power sector was carried out to conform with CEB

LTGE Plans, as described below.

Forecasting demand, generation and capacity

Of all the energy consuming sectors, regular long-term forecasts are carried out only in the

power sector. As described in the LTGE Plan, the demand forecasts had been made using

separate models for domestic, industrial, general purpose and other sub-sectors, where the

demand for the ensuing year was expressed as a linear function of the sub-sector demand in

the previous year and GDP in the ensuing year. The average price of electricity and the

number of consumers were also taken into consideration in the case of the domestic sector.

Different sets of coefficients were used in each sub-sector. In a study sponsored by the World

Bank on the Environmental Issues in Sri Lanka’s Power Sector, models for forecasting future

electricity demand have been developed based on log-linear relationships but has ended up

with more or less similar results66

.

The LTGE Plan 2014 has worked out forecasts for the demand, generation and peak capacity

for the period 2013-2037 under base load conditions (Table 3.3) as well as for several other

cases. For the former, the growth rates vary from 4.0% to 8.7% for demand and from 4.0% to

7.45 for generation. Over the entire period these average out to 5.2% for demand, 5.1% for

generation and 5.0% for capacity. In this study, the forecasted demand, generation and

capacity growths were estimated using these average growth rates and their actual values as

given in the CEB Statitical Digest for 2013. These forecasts ar given in Figs. 32, 33 and 34,

respectively. These follow closely the corresponding curves given in the 2014 LTGE Plan.

Though the CEB has assumed an average gowth rate of 5.2% for the demand and 5.1% for

generation, the actual generation during the period 2008-2013 has grown only by 3.91%. This

shortfall in generation has been mainly due to the low demand. The system peak demand in

2012 has been in the range 2000 - 2,200 MW which occur between 1900h – 2100h, while it


37

remained at about 1,000 MW between the hours 0100h and 0430h67

. During the major part of

the day between 0900h and 1800h, the demand has been between 1,500 and 1,600 MW.

Unless there is concurrent growth of energy intensive industries in the short-term, it is

unlikely that these targets could be achhieved.

Fig. 32. Forecasted growth of demand during 2013-2040

Fig. 33. Forecaste growth of generation during 2013-2040

There are several other projects such as electrification of railways which could improve the

efficiency of railway operation and enhance the electricity demand, particularly during the

daytime. Another option available to reduce the disparity in demand during night-time and

early hours of the day is to operate pumped-storage systems which would use surplus

electricity available during early hours to pump water to a high elevation and use that water to

operate the same system in reverse to generate hydropower during peak hours. Though it may

not reduce the total peak demand, it will reduce the thermal contribution saving money spent

on expensive fuel. This will also enable operation of the coal power plants at high load factor

during low-demand hours.


38

Fig. 34. Forecasted growth of installed capacity during 2013-2040

Fig. 35 gives the growth of per capita electricity consumption expected up to 2040 based on

the demand growth forecasted above, and the population projections corresponding to

medium growth given in Figure A16, with the yearly values interpolated from the decadel

given theirin These population projections show a peak of 21.88 million in 2031. From the

current value just above 500 kWh/capita, it will cross the 1000 kWh/capita mark in 2027 and

the 1,500 kWh/capita mark in 2035.

Fig. 35. Forecast of per capita electricity consumption in Sri Lanka

Even by 2040, the per capita consumption will reach only 1,920 kWh, falling short of the

ADB target of 2,000 kWh/capita necessary for achieving high HDI of 0.8. At the current rate

of consumption, it is a long way to reach even this halfway mark towards a level of decent

living as enumerated by ADB. However, if there is rapid industrialization particularly with

energy intensive industries, this target could be reached at an earlier date.

Sri Lanka is ahead of many other countries in Asia and other developing countries in terms of

electrification of households, with the value reaching 96% in 2013 as given in CEB Statistical

Digest 201368

. Yet, it does not add significantly to the overall consumption because of the very

low domestic consumption rate, which is on an average only 63 kWh per month per household in

2013. Even the average consumption by industries is only about 5,242 kWh/month/industry.


39

Nationally, the major consumption is in the domestic sector with 39% share while the industry

share is only 34% in 2012, as shown in Fig. 23.

On the other hand, in an industry based economy, the major share of load pattern comes from

the industries sector peaking during daytime. It is therefore essential that the country launches

a rapid industrialization programme for which foreign direct investment (FDI) needs to be

solicited. To attract FDI sources with energy intensive industries, the country should not only

have the capacity to generate the required amount of energy, but also be able to do that

without any interruptions or fluctuations. In today’s context, a factor equally important is to

ensure that power generation causes minimum damage to the environment by mitigating

emission of large quantities of carbon dioxide.

Forecasting NCRE resources

The LTGE Plan also gives the status of NCRE project development as at end of 2012, details

of which are given in Table 11. These figures are somewhat different to those given by

SLSEA (Table 7). Out of the total capacity of 314 MW installed by the end of 2012, 227 MW

were in mini-hydro systems, 74 MW were in wind systems, 11.5 MW were in biomass/waste

systems. These systems are expected to grow up to 1047 MW by 2032 when the total

generation from these systems is expected to be about 3,557 GWh annually. However, one

impediment for the growth of NCRE development has been the lack of a firm commitment by

the country’s utilities to absorb energy generated from these sources.

Table 11. Projected generation from NCRE Plants69

Commisioned Committed Cumulative Projected

Installed Installed Installed Generation

Plant Capacity Capacity Capacity GWh

MW MW MW (2032) in 2032

Mini-hydro 227 153 450

Wind 74 31 380

Biomass/waste 11.5 66 93

Solar PV 1.4 124

Total 314 250 1,047 3,557

In a more recent study undertaken as part of a Master Plan on Renewable Energy

Development, the maximum potential of RE in the entire country has been assessed as 2,400

MW of biomass power, 873 MW of mini-hydro power, 6,000 MW of solar PV power and

5,600 MW of wind power70

. The government has decided to develop 375 MW of this wind

power capacity at Mannar Island, by assigning different blocks to potential investors.

In other countries, development of NCRE systems are granted many concessions including rebates

on the capital, duty concessions on imports and tax benefits on investments on NCRE systems,

which are lacking in Sri Lanka. However, a serious impediment against the growth of


40

the NCRE systems is the hazzle that investors are required to go through to get clerance by

many government and local governemnt organizations where no accepted and transparent

guidelines prevail for granting clearance. Another serious drawback is the lack of capacity in

the grid substations to absorb energy from NCRE systems. These issues had been addressed in

the stakeholder workshop on RE that was held recently (see reference 70).

Long term generation expansion plans

The CEB, in its latest LTGE Plan covering the period 2013 – 2032, has given the forecasts for the

demand and installed capacity up to 2032 under several scenarios; base case, high demand case,

low demand case, limited coal case with NG plants added etc. The original Plan forecasts demand

and peak capacity up to 2037, with corresponding values of 37,873 GWh for demand and 7,962

MW for peak capacity. The generation forecast has been 41,804 GWh by 2037.

The LTGE Plan of 2013 gives a Revised Base Case 2012 as an addendum in Annex 11 to the

report, and in this study, provisions given in this Plan are considered as BAU case. According

to this Plan, the thermal addditions (beyond Puttalam) by 2032 will be 4,430 MW, comprising

14 coal power plants (12x300 MW + 2x250 MW) and 4 gas tubine plants (3x75 MW + 1x105

MW), making the total thermal capacity available by 2032 to be 5,795 MW including 900

MW of Puttalam Power Plant and the 2 CCGT plants remaining. The forecasts for peak

demand made by CEB shows that by 2037, capacity of 7,962 MW should be in place under

base load scenario. This is extended to 2040 by adding one 300 MW plant every year after

2032 to match with the capacity forecasts given in Fig. 34.

Fig. 36. Forecasted growth of fuel consumption in the power sector.

Fuel consumption forecasts – Business-as-usual case

The consumption of fuel including coal, diesel and fuel oil necessary to fire the power plants

included in the plan each year up to 2040 are given in Fig. 36. It is assumed that the coal power

plants will have efficiencies of 35%, plant factors of 75% and the corresponding figures for gas

turbines to be 30% and 60%, respectivly, and for CCGT plants these figures were taken as 46%

and 90%, respectively. Of the existing thermal plants, only the three CCGT plants are considered

with one plant to be retired in 2023, as given in the LTGE Plan. Naphtha was not


41

considered separately. The projeted consumption values of different fuels under this scenario

referred to as the Business-as-Usual (BAU) case is given in Table 12.

Table 12. Projected fuel consumption in the transport and power sectors

Year Transport Sector Cons. PJ/y Power Sector Consumption PJ/y

Diesel Gasoline Total Coal Diesel F. Oil Total

2014 73.8 40.1 113.9 40.5 20.2 18.5 79.3

2016 81.1 47.0 128.1 60.8 34.4 18.5 113.8

2018 89.2 55.0 144.2 94.6 41.1 18.5 154.2

2020 98.1 64.4 162.5 135.2 41.1 18.5 194.7

2022 107.8 75.5 183.3 175.7 41.1 18.5 235.3

2024 118.5 88.4 206.9 216.2 31.0 18.5 265.8

2026 130.3 103.5 233.8 236.5 31.0 18.5 286.0

2028 143.2 121.2 264.5 277.1 31.0 18.5 326.6

2030 157.5 142.0 299.4 297.3 31.0 18.5 346.8

2032 173.1 166.3 339.4 337.9 31.0 18.5 387.4

2034 190.3 194.7 385.0 378.4 31.0 18.5 427.9

2036 209.2 228.1 437.3 419.0 31.0 18.5 468.5

2038 230.0 267.1 497.1 459.5 31.0 18.5 509.0

2040 252.8 312.8 565.7 500.1 31.0 18.5 549.6

The cost of fuel consumed was estimated assuming the prices of fuel in 2013 had been USD/t

1047 for diesel oil, USD/t 664 for fuel oil and USD/t 134 for coal. The prices were increased

for subsequent years assuming price escallations of 2.5% annually for oil and 5% for coal.

The cost of generating electricity under BAU case with these fuel price increase is given in

Fig. 37. Under above pricing, with an estimated coal consumptiom of 19 Mt in 2040, the

country will have to spend over USD 9,500 million annully on coal import by 2040 to feed all

the coal power plants, or about LKR 1,230 billion annually (at current exchange rate).

5.5 Outlook in all fuel consuming sectors

In the foregoing, consumption of fossil fuel in different sectors were estimated and future

demand in these sectors were determined based on extrapolation of current trends. Fig. 38

shows the summary of projected consumption of fossil fuel in different sectors from 2013 to

2040 under BAU scenario, and the values are tabulated in Table 13.

In the foregoing, energy demand in different sectors were estimated considering only the

fossil fuel combustion excluding biomass contribution. In both HH&C and industrial sectors,

biomass is the dominant fuel. Hence, the share of these two sectors without biomass appear

small compared to transport and power sectors. Under BAU scenario without biomass, the

overall fuel consumption will increase from 226 PJ in 2014 to 1227 PJ by 2040.

Correspondingly, the gas demand will increase from 587 Mcf/d to 3,191 Mcf/d by 2040 if all

fossil fuels consumed are to be substituted by natural gas. Natural Gas – New Energy Resource Sri Lanka Carbon Fund

42

Fig. 37. Projected cost of fuel consumed in the power sector under BAU case

Fig. 38. Projected consumption of fossil fuel in different sectors

Table 13. Summary of projected fuel consumption during 2013-2040 and its NGEq

Year Fuel consumption PJ/y NGEq

HH&C Industry Transport Power Total Mcf/d

2014 17.6 15.1 113.9 79.3 225.9 587

2016 19.7 15.8 128.1 113.8 277.4 721

2018 22.0 16.6 144.2 154.2 337.0 876

2020 24.7 17.4 162.5 194.7 399.3 1038

2022 27.6 18.4 183.3 235.3 464.6 1208

2024 31.0 19.4 206.9 265.8 523.1 1360

2026 34.7 20.6 233.8 286.0 575.1 1495

2028 39.0 21.8 264.5 326.6 651.9 1695

2030 43.8 23.2 299.4 346.8 713.3 1855

2032 49.2 24.8 339.4 387.4 800.8 2082

2034 55.4 26.5 385.0 427.9 894.9 2327

2036 62.3 28.4 437.3 468.5 996.6 2591

2038 70.2 30.6 497.1 509.0 1106.9 2878

2040 79.1 32.9 565.7 549.6 1227.4 3191


43

These figures shown in the last column of Table 13 give the daily requirement of NG if the

entire thermal energy requirement is to be obtained from NG combustion, replacing diesel oil,

kerosene, gasoline, LPG, fuel oil, residual oil, coal and naphtha referred to as NGEq. However,

it is not possible to achieve these targets in the short term. Hence, it is necessary to work out a

schedule for undertaking a phased program to shift from presently used fossil fuels to NG in a

cost-effective manner.

5.6 Outlook in NG-based industries

In Section 4.8, industries that could be developed using NG as a feedstock were described, along

with their current consumption levels in Sri Lanka. Based on these values, their future outlook has

been determined assuming annual growth rates of 2.5% for urea and AMS and 5% for the rest in

consistent with the country’s economic growth, and these are given in Table 14.

Table 14. Projected annual consumption of NG based products

Year Projected consumption kt

Urea

AMS Methanol

Ethanol

2014 827 71.1 11.6 10.0

2016 869 74.7 12.8 11.0

2018 913 78.5 14.1 12.2

2020 959 82.4 15.5 13.4

2022 1008 86.6 17.1 14.8

2024 1059 91.0 18.9 16.3

2026 1112 95.6 20.8 18.0

2028 1169 100.4 22.9 19.8

2030 1228 105.5 25.3 21.8

2032 1290 110.9 27.9 24.1

2034 1355 116.5 30.7 26.5

2036 1424 122.4 33.9 29.3

2038 1496 128.6 37.3 32.3

2040 1572 135.1 41.2 35.6


44

6. Energy generation and environmental degradation

The uncontrolled emission of polluting gases from fossil fuel combustion over the last century

for the generation of energy is considered to be the primary cause for the degradation of the

planet’s air quality affecting people’s health and well-being. It is a well-recognized

fundamental human right that all people should have free access to air and water of acceptable

quality. These emissions have also contributed to global warming and in turn caused climate

change, through the accumulation of the key GHGs which are carbon dioxide (CO2), methane

(CH4) and nitrous oxide (N2O), in the atmosphere. The average mean surface temperature of

the planet was found to have increased by 0.76oC over the last century and is expected to rise

by at least another 2.4oC by the turn of this century under medium scenario of emissions

71.

This is attributed to emission of GHGs from combustion of fossil fuels mainly for energy

generation. These aspects are described below.

6.1 Emissions from oil combustion

Under petroleum oil, the present study considered different fractions such as gasoline, diesel

oil, kerosene, liquefied petroleum gas (LPG), furnace oil, heavy oil and residual oil.

Combustion of these fuels primarily emit CO2 and several other gases including carbon

monoxide (CO), a range hydro-carbons (HCs), methane (CH4) and several oxides of nitrogen

(NOx) comprising mostly nitric oxide (NO) and nitrogen dioxide (NO2), as well as suspended

particulate matter (SPM). The SPM emission depends on the ash content in the fuels.

Gasoline (Petrol) is used exclusively in the transport sector to operate vehicles fitted with

spark-ignited engines. Diesel oil is used mainly in the transport and power sectors. It is also

used to a lesser degree in the agricultural, industrial and commercial sectors. In addition to the

above emissions, diesel combustion also emits sulphur dioxide (SO2) depending on the

sulphur content in the fuel. Petroleum exhausts are also known to include a variety of benzene

derivatives which are said to be carcinogenic72

. Combustion of heavy oils – furnace oil and

fuel oil - also emits visible quantities of unburnt HCs and carbon particles appearing as

smoke. The ash content present in oil also gives rise to emissions of SPM classified as

particulate matter (PM) of diameter either below 10 μm (PM10) or below 2.5 μm (PM2.5).

The heavier fractions – heavy oil, fuel oil, furnace oil or residual oil – are used in the power,

industrial and commercial sectors. Their GCV is significantly lower than those of diesel and

gasoline, and could contain high ash residue and hence could emit large amounts of SPM.

Their sulphur content is also rather high (2-4%) and hence, the flue gas could contain high

amounts of SO2. These fuels are used for firing thermal power plants and in industries because

of their low cost.

LPG is widely used as a cooking fuel in the urban and semi-urban sectors. It is also used heavily

in industries and in the commercial sector. A small fraction is used for operating vehicles fitted

with SI engines. LPG burning causes less pollution than burning of gasoline or diesel. A by-

product of the petroleum refinery is naphtha which is used in Sri Lanka for operating combined


45

cycle gas turbines in the generation of electricity. The levels of polluting emissions are less

with naphtha than with other fuels.

6.2 Emissions from coal combustion

Coal has been used widely for centuries as a source of heat in countries where it is available.

Today, it is used mostly in the power sector and to a lesser degree in the industrial sector

particularly in steel and cement industries. Combustion of coal gives rise to a variety of HCs, SO2

and oxides of nitrogen similar to what is emitted from oil combustion. Combustion of coal with a

high ash content – 10 to 20% - results in large quantities of fly ash being emitted through the

stacks as well as bottom ash collected at the bottom of the furnace. It is important that the coal

purchased for operating the CPPs should not have more than 10% ash. As in the case of diesel, the

ash present in coal gives rise to SPM emissions. Electrostatic precipitators or fabric filters are

used to reduce emission of fly ash to about 1% or less. Visuals of pollutants released from CPPs

having no emission control systems are shown in Figs. 39 and 40.

Fig. 39. Plumes of emissions released from

a coal power plant in Canada73

Fig. 40. Coal piles and emissions from a

coal power plant in Texas, USA74

Fly ash is the finer material (65% to 80%) of coal ash and its properties vary greatly with the

source of coal burned and the type of ash filter. Fly ash is a source of phosphorus, potassium,

sulfur, boron, and other metals or metalloids; e.g., mercury, cadmium, lead, arsenic, selenium,

etc75

. Fly ash is composed of solids made of silica (SiO2), alumina (Al2O3), ferric oxide

(Fe2O3), and titanium oxide (TiO2). About 35% to 75% of the fly ash from mechanical

collectors and precipitators typically has a diameter of less than 10 microns76

.

In addition to ash, coal has high content of sulphur, which varies from source to source.

Generally, it is in the range 0.5 - 4%. Combustion of coal generates sulphur dioxide (SO2) and

the amount emitted depends on the sulphur content in the fuel. Several technologies such as

wet scrubbing or flue gas desulphurization (FGD) using lime stone are used to reduce SO2

emissions. These processes generally reduce the efficiency of the plant and increases its

capital and operational costs, and hence not favoured very much by plant operators. The use

of lime in precipitating out SO2 produces a slurry of calcium sulphate and sulphite which

itself are pollutants released with the effluent discharged from the plant. Sourcing of lime

stones itself could cause environment problems.


46

One of the metals present in fly ash released from coal CPPs having high impact on the health

of people is mercury. After being released to air, mercury gets deposited on land and water

bodies through precipitation and enters the water cycle. Within the water body, mercury gets

transformed to its organic form of methyl-mercury by certain bacteria. Methyl-mercury

accumulates as it moves up the food chain and reaches the highest concentrations in long-

living fish species. Human exposure to the neurotoxic methyl-mercury is mainly derived from

the consumption of contaminated fish77

. Increased levels of methyl-mercury in fish have been

shown in the proximity of coal power plants. In view of this danger from mercury emissions,

the UNEP has taken the initiative to draft a convention for the control of mercury emissions

and it was adopted by nations in 2013 (see Box 8).

The large quantities of ash collected over the years from coal power plant sites pose a threat to

human health due to the presence of toxic heavy metals including mercury as well as radio-

nuclides. During combustion these substances do not get destroyed, but are released to the

environment either as fly-ash blown with the flue gas through the stacks or as bottom ash

collected at the bottom of the furnace. These are then transferred to a storage pond where it is

kept until disposed. In Sri Lanka with limited land extent, identifying suitable land for the

disposal of coal ash and other pollutants without raising environmental or social issues would

indeed be a problem.

According to a publication of the International Energy Agency on Environmental and Health

Impacts of Electricity Generation released in June 2002, combustion of coal in a CPP could

release a variety of toxic heavy metals into the soil. According to this report, the amounts

released during the generation of one GWh of electricity are typically 323 g of zinc, 220 g of

lead, 117 g of mercury, 110 g of nickel, 114 g of chromium, 76 g of arsenic, 29 g of cobalt

and 5 g of cadmium78

. It is necessary to analyze the ash samples from the Puttalam CPP to

determine the actual extent of emission of these heavy metals into the environment from the

plant. When purchasing coal shipments, it is also necessary to specify the maximum amounts

of these heavy metals and radioactive substances that could be present in coal.

The 900 MW Puttalam CPP when in full operation is expected to generate annually about 6,300

GWh at 80% plant factor. The CEB in its 2013 LTGE Plan has announced that by 2032 another

14 CPPs (12x300 MW + 2x250 MW) of aggregate capacity 4,100 MW would be installed in the

country under revised base case scenario. This means that when all these power plants are in

operation, more than 4 times the amounts of toxic heavy metals emitted from the Puttalam CPP

will be released to the environment annually by 2032, as shown in Fig. 41. No effort has been

made either by the CEA or the CEB to assess the impacts of such emissions of toxic heavy metals

either on the health of the people or on the environment in general.

6.3 Gaseous emissions from thermal power plants

The combustion of fuel causes its main constituents, carbon (C) and hydrogen (H2) to react

with oxygen drawn from air releasing energy. Oxygen and nitrogen present in air inside the Natural Gas – New Energy Resource Sri Lanka Carbon Fund

47

combustion chamber could react at elevated temperatures producing a variety of O-N products

such as NO, NO2, N2O3 and O2N5, commonly known as oxides of nitrogen (NOx). The amounts of

constituents emitted from the exhaust of energy-generating units depend on many factors

including the type of fuel, trace substances present, burner type, emission control technologies etc.

It is mandatory today to have emission control equipment installed in power plants to reduce the

level of emissions within prescribed limits to prevent pollution of the environment.

Fig. 41. Annual emission of toxic heavy metals from 3700 MW coal plants

The principal gas emitted is CO2 resulting from oxidation of carbon present in the fuel. The

amount of CO2 emitted depends on the carbon content of the fuel, which is 25.8 gC/MJ for coal,

20.2 gC/MJ for oil and 15.3 gC/MJ for gas, as given in the IPCC publication79

. The gC is

converted to gCO2 by multiplying by 3.667, being the ratio of their molecular weights. The SO2

emitted depends on the sulphur content in the fuel, which could vary from 0.5% for diesel, 1.5%

for low sulphur fuel oil and 0.7–2.0% or higher for coal. The amount of S released is converted to

SO2 emission by multiplying by a factor of two, being the ratio of their molecular weights.

The amount of NO2 emitted depends on the burner design and the combustion technology.

With specially designed burners for NG, it is possible to keep the emission of NOx at a very

low level. In the case of NG, there is no sulphur or any ash present, and as such there is no

SO2 or particulates emitted from NG fired plants.

The European Environment Agency in 2008 carried out a study on pollutants emitted from

over 400 thermal power plants within the Union in which mitigation measures were in place

to varying degrees. The average levels of these emissions in respect of different types of

power plants are given in Table 15. It is noted that the CO2 emission from a NG plant is only

59% of that emitted from a coal power plant and that the levels of SO2 and particulates

emitted from it are negligible as NG combustion does not generate any solid residue or ash.

In another study carried out in North America including Canada, USA and Mexico in 2004

covering several hundreds of power plants found that on an average thermal power plants emit

3.79 g/kWh of SO2, 1.66 g/kWh of NOx, 0.023 g/MWh of mercury and 893 g/kWh of CO2.80

The emissions from the individual power plants are also reported. However, the results are not


48

given separately for different technologies but lumped together, it is not possible to adopt

these values in the present report.

Table 15. Typical emission levels from thermal power plants in EU countries81

Source Typical Polluting Emission mg/MJ

CO2 SO2 NO2 TSP

Coal-fired ST 94,600 765 292 1,203

Diesel-fired CCGT 74,100 228 129 2

Fuel oil-fired CCGT 77,400 1,350 195 16

Nat. Gas-fired CCGT 56,100 0.7 93 0.1

6.4 National emission standards

Most countries as well as several multilateral agencies have adopted standards on air (gaseous)

emissions in order to regulate their release into the atmosphere. These polluting gases could be

emitted from power, industrial and transport sectors. In this respect, there are two sets of

standards; one specifies the maximum permissible quantities of pollutants that each plant is

permitted to emit, and the other specifies the maximum permissible concentrations of pollutants

that could be present in ambient air referred to as the ambient air quality (AAQ).

The CEA had formulated emission standards for stationary sources including thermal power

plants sometime back, and these have been updated recently. These standards are, however,

yet to be gazetted to make them enforceable. The updated standards are expressed in units of

mg/Nm3 whereas the previous draft had expressed them in mg/MJ. Table 16 gives the up-

dated standards in mg/Nm3 units along with the values converted to mg/MJ units, using

conversion factors given in the World Bank Publication on Thermal Power: Guidelines for

New Plants (see Box 4)82

. These updated standards are very much stricter than the previous

set of standards, almost 50% reduction for limits of NO2 and SO2.

It is the responsibility of the plant operator to install instruments that continuously monitor

emissions, and have the summary readings made available to the regulatory agency for

examination regularly. The data are also required to be made available to the local authority,

which is a condition given for approving the EIA report. However, data on Puttalam CPP

emissions are not available for public scrutiny. Efforts made by the study team to obtain these

data from relevant authorities were not successful.

The Environment Protection Agency (EPA) of USA has recently adopted new regulations on

emission of heavy metals from thermal power plants. Table 15 gives these new standards

along with the rates of typical emissions referred to earlier, which are about 30 – 80 times

higher than the maximum permitted in the standards. Natural Gas – New Energy Resource Sri Lanka Carbon Fund

49

Table 16. Emission standards (Draft) applicable to thermal power plants in Sri Lanka83

Pollutant Maximum permissible Maximum permissible

emissions in mg/Nm3

emissions in mg/MJ*

Fuel Oil Coal Gas Oil Coal Gas

Technology CCGT ST CCGT CCGT ST CCGT

Oxides of Sulphur 850 850 75 238 298 20

Oxides of Nitrogen 450 650 250 126 228 68

Particulate Matter 150 150 100 42 53 27

* Converted from mg/Nm3 values given in draft standards

Box 4. Units for expressing pollutant emission levels

There are several ways of expressing emission levels from power plants. The

pollutant levels are generally measured using probes inserted into the stack and

these measure the amounts of pollutants present in the flue gas as a mixing

ratio expressed in parts per million (ppm) and also the flue gas velocity. Using

the latter, the mixing ratio is converted into quantities emitted per unit volume

of flue gas. The results are expressed in grammes (g) of pollutant present in a

normal cubic metre (g/Nm3) of flue gas, which is the volume adjusted for 0

oC

temperature and 1 atmosphere pressure. Sometimes, operators and standards

regulatory agencies express emission standards as grammes emitted per unit

thermal energy input expressed as g/MJ; or as grammes emitted per unit

electrical energy output expressed as g/kWh, in addition to expressing them as

parts per million (ppm). This makes it difficult for direct comparison of a

plant’s performance with standards if these are given in different units.

The conversion from one unit to another is also not straight forward because

the volume of flue gas generated from combustion depends on the fuel burnt

and conversion from input energy to output energy depends on the efficiency

of the plant. These conversion factors worked out for typical plants are given in

a World Bank Publication on Thermal Power Guidelines and these have been

adopted in this study. This publication gives flue gas generated from burning of

1 GJ of coal, oil and gas as 350, 280 and 270 Nm3, respectively. For power

plants with efficiencies of 50% and 35%, provision of thermal energy input of

1 GJ results in the generation of electrical energy outputs of 139 and 97 kWh,

respectively.

The Sri Lanka draft standards also has specified maximum limits expressed in mg/Nm3 for

the release of some of heavy metals from any source and these are also included in Table 17.


50

Table 17. Standards and actual emissions of heavy metals

Metal US EPA Emission Actual Draft Sri Lanka

Standard84

Emission Emission standard emitted

g/GWh Rate g/GWh mg/Nm3

Lead 9.1 220 0.2

Mercury 1.4 117 0.01

Chromium 3.2 114

Nickel 1.8 110

Arsenic 1.4 76 0.1

Cobalt 0.9 29

Cadmium 0.2 5 1

6.5 Ambient air quality standards

Sri Lanka’s Ambient Air Quality (AAQ) standards were first gazetted in 1994. They were

subsequently amended in 2008, and those relevant to power plants are given in Table 18. Also

given in the Table are World Health Organization (WHO) Guidelines for global air quality,

amended in 200585

. It is seen that Sri Lanka’s standards for PM10 and PM2.5 are more than

twice less stringent than those recommended by WHO. Even though the AAQ set of standards

has specified the maximum concentrations of PM10 and PM2.5 that could be present in

ambient air, the emission standards specify only the levels of total particulate matter. It is also

unlikely that these two parameters are monitored on the plant stacks separately.

Table 18. Ambient Air Quality Standards in Sri Lanka86

Maximum Permissible Level

Pollutant Averaging μg/m3

Time Sri Lanka WHO (2005)

(Amended 2008) Guidelines

Annual 40

Nitrogen Dioxide 24 h 100

08 h 150

01 h 250 200

24 h 80 20 08 h 120

Sulphur Dioxide 01 h 200

10 min 500

PM10 Annual 50 20 24 h 100

50

PM2.5 Annual 25 10

24 h 50

25

The AAQ values resulting from a power plant can be estimated using a dispersion model.

Relevant meteorological and topographical data have to be fed to the model along with the

plant’s emission data and the model will then determine the worst case scenarios of


51

concentration levels anticipated from the given emission levels. Approval will be granted for

the project only if the AAQ values estimated are within the AAQ standards. Enforcement of

the AAQ standards imposes restriction on the number of emission generating units – power

plants or industries – that could be located in close proximity.

It may be noted that according to the EIA report of the Puttalam CPP, the dispersion model

had estimated one-hour concentration of SO2 within the air-shed resulting from all 3 units of

the plant to be 162 μg/m3, which is 80% of the maximum permitted

87. Many uncertainties

existing in dispersion model estimates and variability of wind regime could result in instances

when the actual values could exceed the permitted standards. This also excludes the present

site for installing additional coal power plants planned in the CEB’s LTGE Plan, which has

scheduled to install 12 coal power plants each with capacity 300 MW. It is very likely that the

site of the present CPP could be considered to install one or two of these plants.

6.6 Impacts of emissions on human health

Some of the key pollutants emitted from power plants and their health and environmental

impacts are described below.

Oxides of Nitrogen

Oxygen and nitrogen present inside combustion chambers operating at elevated temperatures

react with each other yielding a mixture of N-O compounds, mainly NO and NO2 , the former

being the dominant species accounts for more than 90% of the oxides of nitrogen emitted.

These two oxides taken together is commonly known as NOx. Once released into the air, NO

gets oxidized into NO2 by available oxidants, particularly ozone, O3. The UV radiation

present at ground level photo-dissociates NO2 back into NO and O. The latter in turn

combines with O2 to form O3 (see Box 5). The presence of reactive organic compounds in

polluted air enhances the production of ozone at ground level contributing to the formation of

smog in urban areas. Smog can burn lung tissue, exacerbate asthma, and make people more

susceptible to chronic respiratory diseases88

.

Oxides of nitrogen reacting with rain water yields nitric acid (HNO3) and nitrous acid (HNO2)

resulting in acid rain. These reactions could also produce other nitrogenous species, such as

peroxyacetyl nitrate (PAN) and nitrated organic compounds reacting with hydrocarbons. Nitrates

and HNO3 when deposited on the ground cause adverse impacts on people’s health and on

ecosystems89

. On the basis of human controlled exposure studies, the recommended short-term

guidance value is for a one-hour average NO2 daily maximum concentration of 200 µg/m3. The

long-term recommended guidance value, based on epidemiological studies of increased risk of

respiratory illness, is an annual average of 40 µg/m3, as recommended by WHO

90.

Sulphur Dioxide: Sulphur Dioxide is emitted from industrial thermal plants and thermal power plants when

operated with sulphur containing fuels such as coal or petroleum oils including residual fuels

or fuel oil. These emissions also originate from diesel vehicles when operated with diesel oil


52

containing sulphur. SO2 causes acid rain, which damages crops, forests, and soils, and acidifies

lakes and streams. Both short-term exposure to high levels and long-term exposure to low levels

of SO2 concentrations have resulted in prevalence of respiratory ailments and changes in

pulmonary functions in humans such as wheezing, reduction in FEV1 (Forced Expiratory Volume

in 1 sec) function and shortness of breath. WHO recommends maximum limits of 20 µg/m3 for 24

hour exposure while permitting peak exposure up to 500µg/m3 for 10 minutes.

Particulate Matter

Particulate Matter comprises two types, those in which 50% of the particles have their

aerodynamic diameter below 10 µm denoted by PM10, and those in which the corresponding

value is 2.5 µm denoted by PM2.5. They are emitted during combustion of fuels with high ash

content and also from various crushing and grinding operations. Biomass burning also emits

high volume of particulates. Various devices such as electrostatic precipitators, bag filters and

cyclonic separators are available to filter out the particulates. Particulate matter emitted from

fuel combustion is referred to either as suspended particulate matter (SPM) or total suspended

particulates (TSP).

These devices trap more than 99% of the particulates directed to the stacks at least initially,

but with time their efficiency may drop allowing higher amounts to escape from the stacks.

Further, there could be selective trapping allowing more of larger particles to get filtered, and

more of smaller particles including PM2.5 to escape. The 2005 WHO Guidelines recommend

maximum values of 20 (Annual) and 50 µg/m3(24 hour)for PM10. The corresponding values

recommended for PM2.5 are 10 and 25 µg/m3, respectively. Table 19 describes the type of

ailments caused by exposure to various emissions released from thermal power plants.

Beyond direct health costs on mortality and morbidity, hospital admissions due to pollution-

induced illness also results in economic damages from lost days of work or school and lower

productivity on the job.

It is important to prevent PM2.5 particles escaping, because these particles once inhaled could get deposited deep in the lung tissues and interfere with its functioning. According to a WHO

study, 5% of cardiopulmonary deaths worldwide are due to particulate matter pollution91

. A

study by USA EPA shows that an increase of 10 µg/m3 in PM2.5 concentration decreases the

lung function FEV1 by 3.4% among asthmatic children92

. In another study on effects of air

pollution on cancer, reproductive and cardiovascular effects, it was found that for every 10

µg/m3 increase in PM2.5 concentration, there has been an 8-18% increase in cardiovascular

deaths in USA93

.

In 2010, soot from U.S. coal-fired power plants was estimated to have caused 23,600 premature

deaths and more than 500,000 cases of respiratory illness94

. Soot and other pollutants such as

SO2, CO, and NOx, all pose threats to well-being, including higher mortality rates, more hospital

admissions, restricted activity days, and increased expenditures on medications for respiratory

problems. According to WHO, diesel engine exhaust fumes cause cancer and belong in the same

potentially deadly category as asbestos, arsenic and mustard gas and regular exposure to diesel

fumes is as likely to cause cancer as passive smoking95.


53

Table 19. Health impacts due to air pollutants96

Primary Pollutants Secondary Impacts

Pollutants

Particulate Matter of Cardio-pulmonary morbidity

diameter below 10 (cerebrovascular hospital admissions,

micron and 2.5 congestive heart failure, chronic bronchitis,

micron chronic cough in children, lower respiratory

(PM10, PM2.5) symptoms, cough in asthmatics,

mortality: reduction in life expectancy due to

short and long term exposure

SO2 cardio-pulmonary morbidity

(hospitalization, consultation of doctor,

asthma, sick leave, restricted activity),mortality

SO2 sulfates like particles

NOx morbidity(respiratory, eye irritation)

NOx nitrates like particles

NOx+VOC ozone morbidity(respiratory hospital admissions,

restricted activity days, asthma attacks, symptom

days),

PAH, diesel soot, cancers

benzene, 1,3,-

butadiene

CO morbidity (cardio-vascular),

mortality (congestive heart failure)

Dioxins Cancers

As, Cd, Cr, Ni Cancers, other morbidity

Hg, Pb morbidity (neurotoxic)

Radionuclides

According to an article appearing in the Scientific American in December 200797

, "the fly ash

emitted by a coal power plant carries into the surrounding environment 100 times more

radiation than a nuclear power plant producing the same amount of energy." The article

further says that “Fly ash uranium sometimes leaches into the soil and water surrounding a

coal plant, affecting cropland and, in turn, food. People living within a "stack shadow"—the

area within a half- to one-mile (0.8- to 1.6-kilometer) radius of a coal plant's smokestacks—

might then ingest small amounts of radiation. Fly ash is also disposed in landfills, abandoned

mines and quarries, posing a potential risk to people living around those areas”.

At the Annual Session of the Sri Lanka Association for the Advancement of Science (SLAAS)

held in December 2013, a paper was presented by two scientists attached to the Nuclear Science

Department of University of Colombo, reporting that coal ash samples collected from the


54

Puttalam CPP contained radioactive nuclides of Uranium, Thorium and Potassium with

specific activities about 4 times that of world average for coal for the first two and about 7

times for the third98

. Their impact on the health of the people exposed has not been assessed.

Box 5. Formation of pollutants from power plants

Some of the chemical reactions taking place inside the combustion chamber and in air

contributing to the formation of pollutants and acid rain are given below.

Inside the combustion chamber

O2 + N2 O2 + M O + N2 NO + O

S + O2

In air

NO +

NO +

NO +

NO2 + O +

NO2 + NO2 + SO2 +

+ Heat → NO + NO

+ Heat → O + O + M (M: Neutral molecule)

+ Heat → NO + N

+ M → NO2 + M

+ Heat → SO2

O + M → NO2 + M

NO + O2 → NO2 + NO2

RnO2 → NO2 + Rn-1O (Rn: CH3, C2H5, C3H7 etc.)

UV → NO + O (Photodissociation)

O2 + M → O3 + M (Ozone causing smog)

O → NO + O2

N → NO + NO

2O2 → SO3 + SO3

During rain

SO2 + H2O

SO3 + H2O

NO2 + H2O

2NO2 + H2O

3NO2 + H2O

→ H2SO3 Sulphurous Acid

→ H2SO4 Sulphuric Acid

→ H2NO3 Nitrous Acid

→ HNO2 + HNO3 Nitrous & Nitric Acids

→ 2HNO3 + NO Nitric Acid Natural Gas – New Energy Resource Sri Lanka Carbon Fund

55

7. Cost of externalities in energy generation

External costs or externalities are generally costs associated with a production process but not

borne by the plant operator. Such costs may include cost of damage to the environment and

costs on healthcare incurred on treating people affected by adverse impacts caused by the

production process. The government may have to intervene to restore any damage done to the

environment and also meet healthcare expenses. The affected people will have to bear

themselves the suffering due to any ailments arising from exposure to the adverse impacts for

which they may not receive any compensation. The estimation of such costs involves a

complex procedure.

7.1 Assessment of external costs

The economic cost to the country due to environmental damage and people’s health damage

depends on the type of the environment affected and on the number of people exposed to the

adverse impacts. Thus, a power plant located in an urban area causes a greater damage than

one located in a rural area. Likewise, a country with a low population density will have lower

external costs compared to that in a more densely populated country.

The assessment of external costs includes the following steps:

Estimating the quantity of emissions released from the source.

Modelling the chemical transformation and dispersion of the emissions. Modelling the resultant pollutant exposure to humans, animals, crops, materials,

and other affected systems. Determining the extent of damage to those affected by exposure to pollutants.

Monetizing the resulting damage.

Such an exercise would involve a team comprising the following professionals:

Professionals involved in the power plant operation who would estimate the emissions

under varying conditions such as changing operating conditions and fuel types,

Software professionals who would determine the dispersion of pollutants under

varying external conditions such as winds, ambient temperature and other atmospheric

and climate parameters, and also determine the profiles of enhanced pollutant

concentrate levels within the air-shed area.

Medical professionals who would estimate the extent of damage done to the health of

exposed people, particularly the elderly, sick and children, including estimates of

increased incidence of respiratory ailments, hospital admissions, indoor treatments and

premature deaths resulting from such enhancement of pollution levels.

Agricultural professionals who would estimate the impact on crops and soils due to

enhanced air pollution and other occurrences such as acid rain.

Archeological professionals who would estimate the impact on archeological sites due

to enhanced pollution levels.


56

Construction professionals who would estimate the impact of enhanced pollution on

buildings and other structures.

Economists and financial professionals will thereafter have to convert the damage done to the

health of people and other areas into monetary terms. Here too, the professionals are faced

with the problem of not having guidelines on assigning monetary values to these factors; for

example valuing human life lost prematurely due to air pollution. The question arises – should

the value of human life be universal or depend on the country’s economy – higher the

economy, higher the value?

A method that is being adopted to estimate environmental and health damage cost is to work

out the abatement cost that is required to lower the pollution to a level that would cause only

tolerable damage. There is a relationship between the cost of damage and cost of abatement,

as shown in Fig. 42. If there is no pollution control in a project, abatement cost is nil but the

damage cost is high. On the other hand, if the pollution level is brought down to near zero, the

damage cost is minimal but the abatement cost is high which the polluter may not be able to

afford.

Fig. 42. Relationship between the cost of abatement and cost of damage

There has to be a trade off when emission standards are fixed at a level that would make the

pollution level tolerable and the abatement cost affordable. The US EPA has estimated that on

an average for 1990 - 2020, for every dollar spent on reducing air pollution by implementing

their Clean Air Act, the health burden will get reduced in USA by USD 3099

.

Another method is to assess the incidence of health impacts in a sample of exposed population,

identify the ailments caused by air pollution and estimate the costs involved in treating such

patients. There are many studies on externalities, particularly those associated with power plants

conducted in countries in the West, but there are only a few reported from countries in the East.

Yet another method adopted is to inquire from the public as to how much they are willing pay

to avoid falling sick, which is referred to as the Willingness to Pay (WTP) methodology. This

is considered a quick way to assess the impact on health of people instead of going through

rigorous epidemiology studies. However, Cookson100

reported that “responses (to questions


57

given to respondents) are vulnerable to all sorts of psychological biases and heuristics. In a

healthcare context, it is thus highly implausible to interpret responses to WTP questions in

terms of a well-behaved individual utility function of the kind required by standard welfare

economic theory”. This method is somewhat similar to auctioning an item when the owner is

not certain of its value. The amount people are willing to pay may not be the real value but a

false value decided by the demand from the society.

7.2 Findings of some studies on externalities

The Conservation Action Trust, Mumbai and Greenpeace after conducting a joint study on the

health damage caused by the power sector in India, has released a report titled “Coal Kills -

An assessment of Deaths and Diseases caused by India’s Dirtiest Energy Sources”, estimating

the health impacts and their costs for a number of ailments caused by coal plant emissions.

The study, in particular, found that during 2011-2012,

Emissions from Indian coal plants resulted in 80,000 to 115,000 premature deaths costing

between USD 3,300 and 4,600 million annually. Child (< 5 years) mortality to be 10,000 costing USD 420 million annually. More than 633 million cases of respiratory and chest ailments costing USD 1,400 million. More than 20 million asthma cases costing USD 420 million annually from exposure to

total PM10 pollution. Additional health impacts included hundreds of thousands of heart attacks, emergency

room visits, hospital admissions, and lost workdays caused by coal-based emissions. The monetary cost associated with these health impacts exceeds USD 3.3 to 4.6 billion per

year.

A report on Scientific Evidence of adverse Health Effects from Coal Use in Energy Generation by

Erica Burt et. al, of University of Illinois released in 2013 describes the results of several studies

on health damage costs of coal power plants expressed as external costs101

. In one study by

Epstein, the external cost was found to be UScts18/kWh, which includes 14 cts. for health costs, 3

cts. for climate change and 1 ct. for other costs. The report also refers to a study carried out in

member countries of the European Union (EU) in which the external cost averaged in the range

€cts 1.6 – 5.8/kWh or UScts 2.2 – 8.0/kWh covering several countries in the EU102

.

As part of the EU study, Rabl and Sparado reported a series of damage factors corresponding

to emissions of gaseous pollutants as well as heavy toxic metals as applicable to countries in

the EU, and these are listed in Table 20 corresponding to 2000 prices. A paper by Greenstone

and Looney has summarized the costs of electricity generation by different sources in USA

and the associated costs of externalities including both health impacts and climate change

impacts. The generation costs comprise discounted annual cost of the capital, fuel costs and

operational and maintenance costs. There is no fixed value nationally as these components are

site-specific and the fuel cost could vary from time to time. Hence, the values given are only

indicative and these are given in Table 21.


58

Table 20. Damage Factors for emissions from power plants103

Pollutant Damage Factor Pollutant Damage Factor

€/kg €/kg

Sulphur Dioxide 2.94 Arsenic 80.0

Nitrogen Dioxide 2.91 Cadmium 39.0

Particulate PM10 11.72 Chromium 31.5

Particulate PM2.5 19.54 Lead 1,600

Carbon DioxideEq 19.0 Nickel 3.8

Table 21. Average costs of generation and externalities in USA104

Costs in UScts/kWh

Plant

Direct Health Climate External Total

Costs

Impacts

Change

Costs

Existing Coal 3.2 3.4 2.2 5.6 8.8

Advanced pulverized Coal 6.2 3.4 1.9 5.3 11.5

Existing NG 4.9 0.2 1.0 1.2 6.1

NG - fired CCGT 5.5 0.2 0.8 1.0 6.5

It is noted that electricity from coal power plants becomes more expensive when externality

costs are added. With advanced pulverized coal combustion, the plant becomes more efficient

reducing the carbon emission but enhances the capital cost. In both cases, external costs of

power from coal plants are more than five times higher than those from gas plants. The

addition of external costs makes coal electricity 85-175% higher than that without, while with

NG it is only 18-24% higher than that without. Furthermore, the external costs of coal plants

are more than 5 times those of NG plants. With the diect cost of generation as shown, the

study further shows that with the cost of externalities added, electricity from coal would cost

about 2.75 times more than its generation cost, and that from gas would cost only 20% more.

Though electricity from coal is said to be cheaper than that from NG, when the external costs

are added, the position gets reversed.

7.3 Studies carried out in Sri Lanka

The only study reported on the impact of air pollution on health conducted in Sri Lanka is one

by Senanayake et. al.105

which is on the relationship between incidence of children’s

wheezing and air pollution. They found a direct correlation between the number of children

admitted to hospitals for respiratory ailments and the level of air pollution in the city.

The monetary values of consultations, medication and hospital visits will also vary with the

country. In countries like Sri Lanka where healthcare is not paid for by the public, the cost is

borne by the government. In 2013, Sri Lanka government has spent almost LKR 100 billion on

recurrent expenditure on healthcare106

. It is also reported that out of all hospital admissions,


59

nearly 10% are patients suffering from respiratory ailments107

. In the absence of other data, one

may therefore assume that the cost of treating patients suffering from respirtory ailments would

cost about LKR 10 billion annually. In the event of enhanced air pollution due to operating more

coal power plants, it is likely that additional expenditure of the order of several tens of billion

rupees may have to be spent by the governemnt in treating these patients.

The World Bank (WB) Office in Colombo with a view to ascertain the impact of building coal

power plants in Sri Lanka had commissioned a study on the Environmental Issues in Sri

Lanka’s Power Sector in 2008 and the report presenting the findings was released in 2010108

.

It was envisaged that such a study would involve a detailed analysis of the distribution of

pollutant concentration within the airsheds of the two power plants at Puttalam and Sampur

using dispersion models and determine their impacts both on the health of the people living in

the exposed areas and also on crops grown, as these airsheds are within the most productive

agricultural area in the country. However, no such studies have been carried out, and instead,

the topic of environmental impacts has been covered just in one paragraph reading as follows:

“While simple air quality models are routinely used in environmental assessments to ensure

compliance with ambient air quality standards, many of the most damaging pollutants arise

during long range atmospheric pollution (such as small sulphate particles formed as oxidation

products of SO2). The result is that the source of a significant portion of ambient sulphates in

Sri Lanka is coal burning power plants in India and a significant portion of the emissions from

Sri Lankan coal projects will either be blown into the ocean or end up in other countries. In

any event, in a monsoonal climate, dispersion from tall stacks will be very wide: the Puttalam

site is in one of Sri Lanka’s windiest locations. Moreover, air quality concentrations in

densely populated urban areas will be largely determined by transportation sector emissions,

and in the specific case of fine particulate matter, confounded by road dust”.

Though emissions from India’s power plants are blamed for any pollution in Sri Lanka, the

statement has not been supported by any study done either in Sri Lanka or India. The

paragraph also refers to emissions getting blown into the ocean under monsoon climate and

implies they cause no impact within the country. However, the fact is that during SW

monsoon winds blow from Puttalam carrying emissions towards the interior of the country

depositing the pollutants in the NWP and NCP, and during NE monsoon, winds blow from

Sampur carrying emissions towards the interior depositing the pollutants in the EP and NCP.

For most parts of the year, NCP gets battered by both monsoon winds which carry with them

pollutants released from the two CPPs. This region will receive pollutants year round except

perhaps during the two inter-monsoon periods. But, the WB report has not addressed this

issue in a scientific manner but has dismissed the environmental impacts as unimportant.

In order to understand the extent to which winds carry air-borne pollutants within this region, it is

necessary to develop a dispersion model incorporating relevant meteorological and weather data

into it. A dispersion model could have quantified these deposition rates both spatially and

temporally and determine their impacts on the health of people and crops, but no such analysis has

been done in the said WB report. The rest of the 227 page report deals with justifying the


60

findings of the CEB LTGE Plan in favour of coal as fuel and reviewing it, without addressing

the main objectives given in the terms of reference of the study.

The same WB report has made a misleading statement to underestimate the health impacts of

CPP emissions. With regard to external costs, the report says: “Rigorous epidemiological

studies are even more complicated, and consequently are few – except in the EU, the USA,

and more recently in China (where the scale of air pollution damages from local particulate

and SO2 emissions was extremely high). Not surprisingly, there are very large uncertainties in

the published studies, and estimates of damage costs per kWh vary by orders of magnitude, as

shown in Table 10, these range from 6 €-cent/kWh (about 10 UScents/kWh) to 0.1 €-

cent/kWh”.

The report, in its Table 10 (see Box), quotes several values for external costs for coal plants

taken from other studies including a value of 0.1 €-cent/kWh for which a reference has been

given to another WB report published in 2000 and authored by Lvovsky et.al.109

It gives the

damage costs for individual emissions of SO2, particulates and NOx emissions expressed in €/t

of emissions, giving reference to the same WB report. It is noted that these values are total

outliers compared to results given in other studies. Strictly, these results obtained in highly

populated cities in developing countries (Bangkok, Manila, Mumbai, Santiago and Shanghai)

should be even higher than the results of other studies which were conducted in Europe, rather

than lower by more than an order of magnitude.

The issue here is that when an incorrect value is quoted, it gets picked up in another report

and later gets accepted as a true value. For example, CEB in its 2013 LTGE Plan in discussing

the social and environmental damage scenario (Section 7.11), has quoted a monetary value for

the social and environmental damage as 0.1 €-cent/kWh taken from the2010 WB report. It is

noted that CEB has decided to quote only the least out of the values from 6.0–0.1€-cent/kWh

given for damage cost in Table 10 of the said WB report. It is an obvious effort to undermine

the cost of health damage of coal power in order to justify the proliferation of coal power

plants in the country. In its 2013 LTGE Plan, CEB has presented a case where social and

environment damage cost was supposed to have been incorporated (Annex 7.20). However,

this plan is no different to other coal-based plans obviously because of the unrealistic low

value of the external cost that CEB has adopted.

7.4 Adoption of EU damage factors for Sri Lanka

When estimating damage costs due to emissions from power plants, the total damage depends on

the population exposed. In a study on Hidden Costs of Electricity undertaken by the Australian

Academy of Technological Sciences and Engineering110

, the EU data were scaled down to match

the lower population density in Australia than that in Europe where the population density was

estimated to be 100 persons/km2. In Sri Lanka, the average population density as found in 2012

census is 323 persons/km2, while those in Puttalam and Kurunegala Districts which are likely to

get exposed to emissions from the Puttalam CPP are 264 and 348 persons/km2, respectively.

Hence, the damage factors in EU given in Table 20 are scaled up by


61

a factor of 3, being the ratio of the average population density in NW Province and that of EU.

These scaled up damage factors applicable to Sri Lanka are given in Table 22, expressed in

UScts/g units.

Box 6. Environment damage cost from coal power plants

Data given in the World Bank commissioned Report on Environmental Issues in Sri

Lanka’s Power Sector, 2011.

Economic Consulting Associates Limited (ECA), RMA and ERM.

Table 10

SO2 Particulates NOx Total damage

Region (€/tonne) (€/tonne) (€/tonne) cost for coal (€-cent/kWh)

Croatia, Zagreb(a) 13,483 24,218 19,265 6.0

ExternE(c) 10,450 15,400 15,700 4.8

UK, ExternE(b) 6,820 14,060 5,740 2.0

Portugal, ExternE (e) 4,959 5,975 5,565 1.8

EU DG Env. (Beta Database)(d) 5,200 14,000 4,200 1.6

World Bank, Six Cities Study (f) 96 1,723 255 0.1

(a) Ekonerg Study, Table 6.4-6, 2002 (b) AEA, Power Generation and Environment, UK Perspective, Report AEAT 3776, 1998

(c) J. Spadaro and A. Rabl, Air Pollution Damage Estimates: the cost per kg of pollutant, Ecole des Mines de

Paris, Centre d’Energetique (d) M. Holland and P. Watkiss, Estimates of the marginal external costs of air pollution in Europe: Benefits Table Database:BeTa, EU DG Environment, 2001 (e) CEETA, Implementation in Portugal of the ExternE accounting Framework, 1998. Table 3.20. (f) K. Lvovsky, G. Hughes, D. Maddison, B. Ostrp and D. Pearce, Environmental Costs of Fossil Fuels, A Rapid Assessment Method with Application to Six Cities, World Bank, Environment Department, Paper 78, October 2000,

In order to estimate the damage costs, it is necessary to apply the respective damage factors to

each of the emission factors NOx, SO2 and PM applicable to power plants operated with

different fuels. Though several thermal power plants have been in operation in Sri Lanka for

many years, no data are available on their emission factors. The CEB’s LTGE Plan gives

emission factors for thermal power plants (Section 9.4) but these are not based on actual

monitored values of existing plants. The Australian study referred to earlier gives averaged

emission factors for coal and gas power plants based on data from several existing plants, and

these are adopted in this report. However, most developed countries do not use diesel oil for

thermal power generation and data for diesel plants are not available from international

sources. Hence, emission factors for diesel plants and GT plants are taken from the CEB

LTGE Plan (Table 9.6).

The values given in units of g/MJ are converted to values in g/kWh assuming efficiencies of 35%

for the CPP, 46% for CCGT plants and 30% for GT plants. The emission factors for SO2 are

based on sulphur content in each fuel. These emission factors (EF) estimated for each fuel and

technology are used in calculating the scaled up damage costs (DC) for Sri Lanka based on


62

damage factors given in Table 20 applicable in EU countries. These damage costs (DC),

calculated using the following formula are given in Table 22.

DC (UScts/kWh) = 3.0*1.31*EF (g/kWh)*DF (€/kg)/10.

The factor 3 accounts for the high population density in the NCP (306/km2) over that in

Europe (100/km2) and the factor 1.31 converts Euro into US Dollars. The damage cost due to

each of the pollutant is determined by substituting the relevant DF (Table 20) and EF (Table

22) values in the above equation. The total damage cost due to a particular power plant is

obtained by summing up the individual components due to each pollutant. The resulting

values are given in the last column of Table 22 for different types of power plants.

Table 22. External costs due to emissions from thermal power plants

Sulphur Emission Factor External

Plant Fuel content g/kWh Cost

%

UScts/kWh SO2 NO2 PM

ST Coal 0.7 5.46 3.09 0.41 11.70

CCGT Diesel 0.5 1.76 2.19 0.04 4.70

CCGT F. Oil 1.5 5.72 2.19 0.09 9.48

GT Diesel 0.5 2.70 3.36 0.06 7.22

CCGT NG - - 0.34 0.02 0.48

Damage Factor applicable 1.15 1.14 4.61

to Sri Lanka (UScts/g)

The highest contribution to the damage cost comes from SO2 impacts for both coal and fuel

oil operation. It is also noted that the damage cost from NG operated plant is negligible

compared to that from the rest.


63

8. Phasing-in of natural gas

Once NG is commercially produced and brought to the shore, it has to be utilized directly as

an energy source or converted to a solid (urea) or liquid (methanol) which can be stored and

kept for later utilization. This section discusses various options available for this purpose.

8.1 Scenarios for introducing natural gas

The first priority for phasing-in NG is to operate the existing 3 CCGT plants with NG. The

expected initial supply of NG at 70 Mcf/d would be just sufficient to operate the three plants

during most parts of the day. Once the supply increases, gas could be used to operate other

existing gas turbine plants and introduce the use of gas in future power plants and also in

other sectors such as transport, industries and household & commercial sectors. Being a new

commodity in Sri Lanka, people may not readily accept NG as a new source of energy though

it has many benefits. It is assumed that NG penetration will take place under two scenarios,

referred to as NG1 and NG2 scenarios.

Under NG1 scenario, low level of penetration of NG has been assumed, while a high level has

been assumed under NG2 scenario, except in the power sector where the two scenarios were

selected based on two cases given in CEB’s LTGE Plan, one coal based and the other NG based. In non-energy application, under NG1 scenario, it is planned to commence a few industries,

and additional industries will be added under NG2 scenario.


In the HH&C sector, LPG, Kerosene, diesel and fuel oil are consumed, but the dominant

consumption is LPG. It is therefore assumed that only LPG which is used for generating

thermal energy will be replaced by NG. However, NG cannot be supplied in compressed form

in portable cylinders to consumers as in the case of LPG. The options available are:

(a) Supply NG to consumers in cluster of individual households, apartment complexes and

commercial establishments through local pipeline networks connected and serviced by a central

storage unit (CSU) which receives its NG supply in CNG/LNG bulk carriers. Private sector

operators could be licensed to service such central units. They will be required to supply the gas to

individual consumers and also undertake the installation and maintenance of the network.

(b) Convert NG to DME and distribute it in domestic cylinders as in the case of LPG using the

same infrastructure and distribution system. The cylinders and cooking stoves may need some

modification for use with DME. This option enables early penetration of NG to outstations.

It is assumed that the supply of gas to the HH&C sector may not commence immediately after

the gas is made available. It will take a few years of gestation in view of the time required for

infrastructure development and for the system to get accepted by the people and safety aspects

looked into by relevant authorities. It is therefore assumed that the penetration will commence

in 2026 at two levels, NG1 and NG2 scenarios. In the NG1 scenario, the consumption of LPG


64

is replaced in the first year at 4% and the share will increase progressively up to 60% by 2040

at an annual increment of 4%. Correspondingly, the consumption of LPG will decline. The

growth of annual consumption of LPG and gas under NG1 scenario is shown in Fig. 43.

In the NG2 scenario, it is assumed that the penetration of NG will be enhanced commencing

at 6% in 2026 and ending at 90% in 2040, with a corresponding decline in the consumption of

LPG. The fuel consumption under NG2 scenario is shown in Fig. 44. The projected fuel

consumption in the HH&C sector under the two scenarios is also shown in Table 23, along

with the daily demand for NG expressed in million cubic feet.

Fig. 43. Projected consumption of fuels in the HH&C sector under NG1 scenario

Table 23. Demand for NG in HH&C sector under NG1 and NG2 scenarios

NG1 NG2

Year

LPG NG NG LPG NG NG

PJ/y PJ/y Mcf/d PJ/y PJ/y Mcf/d

2026 21.29 0.89 2.31 20.84 1.33 3.45

2027 21.83 1.90 4.94 20.88 2.84 7.37

2028 22.34 3.05 7.92 20.82 4.55 11.84

2029 22.82 4.35 11.30 20.65 6.49 16.88

2030 23.25 5.81 15.12 20.35 8.69 22.58

2031 23.64 7.46 19.41 19.91 11.15 29.00

2032 23.96 9.32 24.23 19.30 13.92 36.20

2033 24.21 11.39 29.63 18.52 17.03 44.27

2034 24.38 13.72 35.66 17.53 20.49 53.28

2035 24.46 16.31 42.40 16.31 24.36 63.35

2036 24.43 19.19 49.90 14.83 28.68 74.56

2037 24.27 22.40 58.25 13.07 33.47 87.03

2038 23.97 25.97 67.52 10.99 38.80 100.89

2039 23.51 29.93 77.81 8.55 44.71 116.25

2040 22.87 34.31 89.20 5.72 51.26 133.28


65

8.3 Industrial sector

In the overall energy scenario, the projected fossil fuel consumption in the industrial sector is

very low compared to that of the power and transport sectors as evident in Table 13, since

most of the energy requirement is met from biomass. Industries presently using fuels such as

LPG and fuel oil for thermal energy generation could be given the facility to use NG in place

of these fuels. Initially, the large number of industrial zones could be provided with

CNG/LNG transported in bulk carriers for kept at a CSU built within the zone. The individual

industries could be supplied with gas using a local network of pipelines.

Fig. 44. Projected consumption of fuels in the HH&C sector under NG2 scenario

NG will be introduced for industries commencing 2023 under two scenarios, NG1 and NG2.

Under the former, NG will be introduced replacing LPG and fuel oil at the rate of 4% of their

consumption initially increasing progressively up to 72% by 2040 with an annual increments

of 4%. It is expected that the gas penetration will be similar as in the case of HH&C sector.

Correspondingly, the consumption of LPG and fuel oil will decline. Fig. 45 shows the growth

of consumption of NG along with those of other fuels including LPG, fuel oil, diesel and

kerosene, jointly labelled as oil labelled as oil, and coal. The consumption of coal, diesel and

kerosene will however remain unchanged.

Fig. 45. Projected consumption of fuels in the Industrial Sector under NG1 scenario


66

Under the NG2 scenario, the penetration of NG will be undertaken more aggressively

commencing at 8% of LPG and fuel oil consumption and ending at 96% in 2034 with annual

increments of 8% and thereafter remaining at 100%. The resulting growth of NG consumption

and the rest of fuels labelled oil is shown in Fig. 46. The projected consumption values are

given in Table 24 along with amounts of NG in Mcf/d required for replacing the demand for

fuel oil and LPG under the two scenarios.

Fig. 46. Projected consumption of fuels in the Industrial Sector under NG2 scenario

Table 24. Demand for NG as fuel in the industrial sector under NG1 and NG2 scenarios

NG1 NG2

Year Coal Oil Gas Coal Oil Gas

PJ/y PJ/y PJ/y Mcf/d PJ/y PJ/y PJ/y Mcf/d

2023 4.46 13.95 0.36 0.94 4.46 13.59 0.72 1.88

2024 4.64 13.92 0.74 1.92 4.64 13.18 1.48 3.84

2025 4.83 13.89 1.13 2.94 4.83 12.76 2.26 5.88

2026 5.02 13.86 1.54 4.00 5.02 12.32 3.08 8.01

2027 5.22 13.84 1.97 5.11 5.22 11.87 3.93 10.23

2028 5.43 13.82 2.41 6.28 5.43 11.40 4.83 12.55

2029 5.65 13.80 2.88 7.49 5.65 10.92 5.77 14.99

2030 5.87 13.79 3.37 8.77 5.87 10.41 6.75 17.54

2031 6.11 13.77 3.89 10.11 6.11 9.88 7.78 20.23

2032 6.35 13.76 4.43 11.53 6.35 9.33 8.87 23.05

2033 6.61 13.75 5.01 13.01 6.61 8.75 10.01 26.03

2034 6.87 13.75 5.61 14.58 6.87 8.14 11.22 29.17

2035 7.15 13.74 6.25 16.24 7.15 7.98 12.01 31.23

2036 7.43 13.74 6.92 17.99 7.43 8.30 12.36 32.13

2037 7.73 13.73 7.63 19.85 7.73 8.64 12.72 33.08

2038 8.04 13.73 8.39 21.82 8.04 9.01 13.11 34.09

2039 8.36 13.72 9.19 23.91 8.36 9.40 13.52 35.16

2040 8.70 13.72 10.05 26.12 8.70 9.81 13.95 36.28


67

8.4 Industries with natural gas feedstock

If surplus NG is available with the expansion of its production, several new industries could

be commenced which use NG as feedstock, as discussed in Section 4.8. Among these are the

manufacture of urea, ammonium sulphate, DME, methanol, ethanol and acetic acid. Many of

these industries require manufacture of Ammonia first, which is converted later to Methanol.

Urea is one of the key fertilizers in demand in the country. The manufacture of 1 tonne of urea

is estimated to consume approximately 23 kcf of NG111

. The cost of manufacturing urea from

NG can be estimated based on the plant cost and the NG cost. According to the Fertilizer

Department of India, a typical urea plant of capacity 500,000 t/y will cost about USD 200

million112

. Applying the annuity factor of 0.106 corresponding to a 10% discount and 30 year

economic life, the annual cost of the plant will be USD 42/t. The cost of the feedstock NG for

manufacturing 1 t of urea under the 3 price scenarios (USD 5, 10 & 15 per million Btu) will

be USD 118, 236 and 354 per tonne. With the annual plant cost added, and a 10% of the plant

annual cost assumed for the other costs including labour, fuel, operation and maintenance, the

3 prices will now increase to USD 164, 282, and 400 per tonne, respectively.

A recent call for bids by SL Government for the purchase of urea has brought in offers with

prices around USD 550 per tonne113

. Therefore, even with the high price of USD 15/million

Btu for NG, the manufacture of urea using NG as the feedstock is profitable. Since surplus

NG will be available for the manufacture of urea only after about 2025 when the NG price is

expected to come down to USD 5/million Btu, the saving from manufacturing urea from NG

will be USD 386 per tonne. Currently, the government provides a subsidy of LKR 42.5 billion

annually for fertilizers issued to farmers, selling the fertilizer at about 1/3 the cost. If urea, the

principal fertilizer, could be manufactured at about 1/3 the present purchase price, the

government could withdraw the subsidy entirely.

The National Fertilizer Secretariat has reported that the consumption of urea in 2011 has been

768 kt114

. As discussed in Section 4.8, urea demand in 2014 is estimated to be 827 kt. With

more agricultural activities undertaken, it is likely the demand for urea will grow, but it will

be slowed down in view of the non-availability of land for new activities. A growth rate of

only 2.5% is therefore assumed and the resulting projections are given in Table 14, which

gives 827 kt/y in 2014, 1,059 kt/y in 2024 and 1,572 kt/y in 2040. The corresponding

projections for NG demand will be 52.1 Mcf/d, 66.7 Mcf/d and 99.0 Mcf/d, respectively.

NG based Industries under NG1 Scenario

Under NG1 scenario, it is proposed to build a plant to manufacture urea which is in high demand

in the country. It is anticipated that sufficient quantities of NG to feed such an industrial venture

will become available in 2025. Since the demand for urea in 2024 will be 1.06 Mt, it is proposed

that a urea plant of capacity 1 Mt/y be built in 2025. This will consume 63 Mcf of NG a day. As

the demand increases, the plant capacity could be increased to 1.25 Mt in 2030 and 1.5 Mt in

2035. The corresponding NG consumption will be 71 Mcf/d and 95 Mcf/d.


68

As discussed in Section 4.8, Sri Lanka has imported 66.65 kt of Ammonium Sulphate (AMS) in

2011. At 2.5% annual growth, its consumption is 2014 is 71.1 kt and 135.1 kt in 2040. NG is first

converted to Ammonia which is then used in the manufacture of AMS. The process requires 40

kcf of NG for the manufacture of 1 t of Ammonia115

. Considering the molecular weights of

Ammonia (32) and AMS (132), and that 2 Ammonia molecules are required to form one molecule

of Ammonium Sulphate ((NH4)2SO4), the manufacture of 1 t of AMS will require 10 kcf of NG.

Hence, the projected consumption of NG to manufacture above quantities of AMS will range from

1.95 Mcf/d in 2014 to 3.70 Mcf/d in 2040. Under NG1 scenario, a AMS plant of capacity 100 kt/y

will be built in 2025, which will be increased to 125 kt/y in 2030 and to 150 kt/y in 2035, with

corresponding NG consumption of 2.7, 3.4 and 4.7 Mcf/d.

In Section 2.5, it was reported that NG could be converted to a liquid fuel such as Dimethyl

Ether (DME) which could be used as a substitute for diesel oil and LPG. A process has been

developed to produce DME from NG using a more efficient methodology whereby a 200 t of

DME could be produced in a day using 11 Mcf/d of NG116

. Hence it is proposed that Sri

Lanka commences production of DME in 2025 at a rate 100 kt/y and thereafter increase it into

125 kt/y in 2030 and 150 kt/y in 2035. The corresponding NG consumption rates will be 15.1,

18.8 and 22.6 Mcf/d, respectively. These production rates and the corresponding rates of NG

consumption are shown in Table 25. The gas demand rates are shown graphically in Fig. 47.

Table 25. Demand for NG in NG based industries under NG1 scenario

Year NG demand under NG1 scenario Mcf/d

Urea AMS DME Total

2025 63.0 2.7 15.1 80.8

2026 63.0 2.7 15.1 80.8

2027 63.0 2.7 15.1 80.8

2028 63.0 2.7 15.1 80.8

2029 63.0 2.7 15.1 80.8

2030 78.8 3.4 18.8 101.0

2031 78.8 3.4 18.8 101.0

2032 78.8 3.4 18.8 101.0

2033 78.8 3.4 18.8 101.0

2034 78.8 3.4 18.8 101.0

2035 94.5 4.1 22.6 121.2

2036 94.5 4.1 22.6 121.2

2037 94.5 4.1 22.6 121.2

2038 94.5 4.1 22.6 121.2

2039 94.5 4.1 22.6 121.2

2040 94.5 4.1 22.6 121.2


69

Fig. 47. Projected demand in NG-based industries under NG1 scenario

NG based Industries under NG2 scenario

Sri Lanka has imported approximately 10 kt of methanol in 2011. Table 14 gives the projected

demand of methanol assuming an annual growth rate of 5% from the value of 11.6 kt/y in

2014 to 41 kt/y in 2040. The corresponding requirements of NG for its manufacture ranges

from 1.2 Mcf/d to 4.1 Mcf/d, assuming manufacture of 1 t/y of methanol requires 100 scf/d of

NG117

. Methanol is a starting material in the manufacture of a wide range of chemical

products as described in Section 4.8, and hence is in high demand worldwide, with a global

annual production of about 100 Mt118

. When Trinidad and Togo (TT) discovered NG more

than a decade ago, its first priority was to build a methanol plant and to export the product,

which enabled them to be the sole supplier of methanol in the American Continent and the

fourth globally. TT recently commenced work on a new methanol plant with a capacity of 1

Mt/y of methanol consuming 100 Mcf of NG a day at a cost of USD 850 million119

. Out of

this amount, 140 kt of methanol is converted into DME yielding 100 kt annually.

It is therefore proposed that under NG2 scenario, Sri Lanka too ventures into large scale

manufacture of methanol, building a 1 Mt/y capacity plant in 2025, both to support a local

chemical industry and also to export any surplus. All the chemical and plastic products that

are being imported currently could then be produced locally providing employment to many.

It is more convenient to export surplus gas after converting it into methanol than exporting the

gas itself. As the demand increases, the production too could be expanded to 1.50 Mt/y in

2030 and 2.0 Mt/y in 2035, as shown in Table 26. The corresponding NG consumption rates

will be 100, 150 and 200 Mcf/d, respectively.

Ethanol, which is the other product considered in Section 4.8, is already manufactured in the

country, distilling it from coconut, palmyrah and sugar cane extracts and also imported to cater to

the liquor industry. Its outlook under BAU scenario provides its consumption increasing from 10

kt in 2014 to 36 kt in 2040 (Table 14). In recent years, the demand for ethanol has increased

world-wide with its blending with gasoline and has an attractive export market. Under NG2

scenario, it is proposed to build an ethanol plant with capacity 100 kt/y, beginning 2025, to meet

the local demand as well as for export. In a new micro-organism based technology, NG is first

converted to Syngas which in turn is converted into ethanol, producing 21 t of ethanol annually


70

from 1 Mcf of NG consumed daily120

. The demand for NG would then be 13 Mcf/d. It is

envisaged that the demand for ethanol will increase to 150 kt/y in 2030 and to 200 kt/y in 2035,

and in turn the demand for NG to 20 Mcf/d in 2030 and 26 Mcf/d in 2035. Their annual values are

shown in Table 26. Under NG2 scenario, the consumption of NG for the manufacture of the three

items under NG1 scenario as well as that required for the manufacture of methanol and ethanol

will be included, as shown in Table 26. These are graphically shown in Figs. 48.

Table 26. Demand for NG in the NG-based industries under NG2 scenario

Year Demand under NG2 scenario Mcf/d

NG1 Methanol Ethanol Total

2025 80.8 100 13.1 193.9

2026 80.8 100 13.1 193.9

2027 80.8 100 13.1 193.9

2028 80.8 100 13.1 193.9

2029 80.8 100 13.1 193.9

2030 101.0 150 19.7 270.7

2031 101.0 150 19.7 270.7

2032 101.0 150 19.7 270.7

2033 101.0 150 19.7 270.7

2034 101.0 150 19.7 270.7

2035 121.2 200 26.2 347.4

2036 121.2 200 26.2 347.4

2037 121.2 200 26.2 347.4

2038 121.2 200 26.2 347.4

2039 121.2 200 26.2 347.4

2040 121.2 200 26.2 347.4

Fig. 48. Projected demand in NG-based industries under NG2 scenario


71

8.5 Transport sector

In many countries, both developed and developing including India, vehicles are operated using

NG. In Sri Lanka too NG could be introduced to operate vehicles. Here, there are three options;

first using CNG, second using LNG, and the third using DME. Generally, the first is used in light

vehicles including 3-wheelers while the second is used in heavy vehicles including buses. The

third option of DME could be used as a substitute for diesel. In addition to being more economical

than using diesel or gasoline, use of NG does not cause air pollution.

If the gas and the necessary infrastructure is made available, the adoption of the new system

will be governed by market forces. Currently, gasoline is available at about LKR 170 a litre

which works out to LKR 4.90 per MJ or USD 40 per million Btu, while diesel available at

LKR 121 a litre works out to LKR 3.25 per MJ or USD 26 per million Btu. On the other hand,

even if NG is offered at USD 15/million Btu, the cost per MJ will be only LKR 1.85.

Therefore, even after taxes, profit margins, transport and infrastructure costs are added in, NG

could be sold to vehicles at a very competitive price. Later when the price of NG drops to

US$ 5/million Btu, the benefits could be passed down to the consumer.

In 2012, Sri Lanka has imported about 3,000 buses, 30,000 cars and 100,000 three-wheelers

(figures are rounded off in view of high year-to-year variability). Their annual consumption of

fuel, assuming a bus runs on an average 340 km a day121

, a car and a 3-wheeler run on an

average 50 km a day for 240 days a year, is estimated to be 4.5 PJ, which is about 4.4% of the

total consumption of 101 PJ in the transport sector in 2012. The balance is consumed by the

existing fleet. Once the necessary infrastructure is provided to supply vehicles with CNG at

least at a few outlets in the city, the import of new CNG vehicles could be encouraged, and it

is anticipated that at least 50% of the imports will be CNG vehicles. Vehicles with factory-

fitted accessories for CNG operation are available both in India and Japan and these may be

given duty concessions as an incentive for them to be purchased.

The international trend today for operating long-distance buses and trucks by gas is to use

LNG as it is more economical than operating with CNG. Generally, in buses, CNG tanks are

mounted on the roof top, raising the centre of gravity, which makes CNG vehicles less stable

than other vehicles when negotiating bends. Also, in the event of an accident, CNG vehicles

pose a greater threat than LNG vehicles. However, the worst drawback is the long filling time;

LNG vehicles take no more than the time taken to refill a normal diesel vehicles whereas

CNG vehicles would take a few hours. With the expansion of the expressways and the

increasing demand for luxury buses, the government could encourage the use of LNG in

luxury buses plying on expressways and also on other long-distance routes.

Fig. 31 gives the projected fuel consumption in the transport sector under BAU scenario based

on historical growth rate of 4.85% for diesel and 8.22% for gasoline. It is assumed that CNG

will be available for use in the transport sector after 2023. It is expected that the conversion

including the import of new CNG/LNG vehicle will be slow at the beginning as people are

generally hesitant to adopt something new. As in the case of HH&C and Industries sectors,

introduction of NG in the transport sectors is considered under two scenarios, NG1 and NG2.


72

Under the former, it is assumed that the conversion rate will grow with a share of 2% of oil

consumption at 2023 and increase at increments of 2% each year with a share of 36% up to

2040. With the growth of NG consumption, there will be a corresponding decline in the

consumption of petroleum oil. The consumption of both CNG and LNG are shown in Fig. 49

separately along with the residual consumption of diesel and gasoline.

In the second scenario NG2, NG consumption will grow with a share of 4% at 2023 and increase

at increments of 4% each year with a share of 72% up to 2040. There will be a corresponding

decline in the consumption of oil. Table 27 gives these projections for the two scenarios for the

period 2023 – 2040. The Table also shows the amount of NG required daily to meet this demand.

These projections are estimated based on conversion of conventional vehicles fitted with IC

engines. These fuel consumption patterns for NG2 scenario are shown in Fig. 50.

Table 27. Demand for NG in the transport sector under NG1 and NG2 scenarios

NG1 NG2

Year Oil NG Oil NG

PJ/y PJ/y Mcf/d PJ/y PJ/y Mcf/d

2023 190.8 3.9 10.1 186.9 7.8 20.2

2024 198.6 8.3 21.5 190.3 16.6 43.0

2025 206.7 13.2 34.3 193.5 26.4 68.6

2026 215.1 18.7 48.6 196.4 37.4 97.3

2027 223.8 24.9 64.6 198.9 49.7 129.3

2028 232.7 31.7 82.5 201.0 63.5 165.0

2029 242.0 39.4 102.4 202.6 78.8 204.8

2030 251.5 47.9 124.6 203.6 95.8 249.1

2031 261.4 57.4 149.2 204.0 114.7 298.3

2032 271.5 67.9 176.5 203.6 135.8 353.0

2033 281.9 79.5 206.8 202.4 159.0 413.5

2034 292.6 92.4 240.3 200.2 184.8 480.5

2035 303.6 106.7 277.4 196.9 213.3 554.7

2036 314.8 122.4 318.3 192.4 244.9 636.7

2037 326.3 139.9 363.6 186.5 279.7 727.2

2038 338.0 159.1 413.6 179.0 318.1 827.2

2039 349.9 180.3 468.7 169.7 360.5 937.4

2040 362.0 203.6 529.5 158.4 407.3 1058.9

It is to be noted that development of fuel-cell operated vehicles are in progress and it is likely

they will be on the roads in the near future within the period under consideration. If NG is

available by that time, it will be possible to operate them on Sri Lankan roads also, as the

required H2 could be obtained from NG using on-board reforming facility. In such a situation,

the demand for gas could increase further.


73

Fig. 49. Projected consumption of fuels in the transport sector under NG1 scenario

It is to be noted that gas will become the dominant fuel under Scenario NG2, unlike in the

case of NG1. Correspondingly, the cost of fuel will get reduced by shifting to gas operation.

Fig. 50. Projected consumption of fuels in the Transport Sector under NG2 scenario

8.6 Power sector

The third stage of the Puttalam CPP was commissioned in September 2014. This would result

in increasing the capacity of the plant to 900 MW. There would probably be surplus power

available in the country since the demand may not increase suddenly to match the supply.

Once NG is available in 2018, the three CCGT plants are expected to be converted to operate

with NG. The grid controller therefore will have the option of connecting the grid to the new

CPP plants or to the NG-fired CCGT plants. Since CEB operates on least-cost basis, it is

necessary to determine the cost of generating coal power and NG power on a levelized field.

The levelized costs (LC) of electricity generation from coal, diesel and NG fuels are therefore

determined. This takes into consideration the specific annual cost of the capital invested on

the plant, cost of fuel, costs of fixed and variable operation and maintenance.

Levelized cost of generation

The first step in determining the levelized cost of a project is to convert the initial capital cost

into an annual cost, using the standard formula122

:


74

Annual cost of capital = Overnight cost * DR * (1+DR)^EL /((1+DR)^EL - 1),

where, DR = Discount Rate (Generally taken as 10%)

EL = Economic Life of plant (30 years for a power project)

Overnight cost = Capital cost + Interest during construction.

The data necessary for these calculations were obtained from the CEB’s LTGE Plan 2013, in

respect of capital cost, costs of coal and oil, costs of fixed and variable operation and

maintenance. The cost of coal given in the CEB 2013 SD report was escalated to 2018 prices

assuming 5% annual increase in the future. Diesel price was escalated from 2013 prices at

2.5% annually. The locally found gas is expected to be available for commercial utilization

only in 2018 at a price of US$ 15/million-Btu initially, and later to be reduced to US$

10/million-Btu in 2021 and US$ 5/million-Btu in 2023, respectively.

The efficiencies of the coal and diesel CCGT plants were taken mostly from the CEB LTGE

report. An efficiency of 50% is assumed for NG operated CCGT plants, 46% for diesel and

fuel oil operated CCGT plants, 30% for gas turbine plants (GT) and 35% for coal power

plants. Today, NG fired CCGT plants having efficiencies as high as 60% are available, but

when operated in tropical countries, the value has to be de-rated to about 55%, but

considering the efficiencies at which the current CCGT plants are operated, an efficiency of

50% is assumed. Plant factors are assumed to be 75% for coal and 90% for CCGT and 60%

for GT plants. These levelized cost calculation values are determined for 3 cases using the

above formula and the prices of coal and NG described above and the findings are shown in

Table 28. The cost of externalities due to health impacts are taken from Table 22.

The specific cost of generating electricity corresponding to the 3 prices of NG referred to

above are UScts/kWh 5.03, 8.44 and 11.85 while that for coal power is UScts/kWh 9.16 and

that for diesel is UScts/kWh 20.75. This means that considering only the direct costs, NG

power is available at a lower price than with coal in 2018 when coal price was escalated to

USD 174, except when NG costs USD 15/million Btu.

If the cost of externalities given in Table 22 are added, NG power becomes UScts 12.33 – 5.51 per

kWh corresponding to NG prices of UScts 15-5 per million-Btu, compared to UScts 20.86 per

kWh for coal power. NG power is therefore cheaper than coal power for all 3 cases when the cost

of externalities is included. The corresponding figure for diesel operated plant is UScts 25.45 per

kWh with externalities added. Thus, the shifting of power generation from oil to NG is more than

justified even without taking into consideration the cost of externalities.

Phasing-in NG power plants

From the foregoing, it is clear that operation of the 3 CCGT plants with NG is more economical

than operating with coal. Hence, for phasing in NG plants into the system, the obvious choice is to

first convert the 3 CCGT plants, two at Kelanitissa (165 MW & 163 MW) and the third at

Kerawalapitiya (300 MW) for operation with NG once the gas becomes available in 2018. Under

optimum conditions (90% plant factor and 50% efficiency) these 3 plants will consume


75

36 PJ equivalent of fuel annually, and this energy can be provided by a daily supply by 93

Mcf/day of gas. However, if the initial production is limited to 70 Mcf/day, it may not be

possible to operate them to deliver maximum output.

Table 28. Calculation of levelized cost of electricity generation

Plant Plant

Econ

Annual

Cost Anu’al Cost

Plant Capit Overni- Disco of incre- of capital .Life Capital

Plant

Capa al ght cost -unt fuel ment fuel

Fuel cost of cost type -city Cost USD rate USD/ of USD/

USD plant USD MW USD/ /kW % t price t

Million years million kW

2013 % 2018

CCGT Diesel 300 824 247.08 935.12 30 10 29.76 1,047 2.5 1,185

ST Coal 300 1,658 497.34 1964.99 30 10 62.53 134 5 171

CCGT NG 300 824 247.08 935.12 30 10 29.76

CCGT NG 300 824 247.08 935.12 30 10 29.76

CCGT NG 300 824 247.08 935.12 30 10 29.76

Table 28 contd.

Annual

Annual Annual

Variab Total Coast of Total

Cost of

-le Fuel Cost of external

Elect Effic- Fuel Plant Cost with Gas PF O&M Cost produc ities

Output iency Consu- Cost Ex’ies USD/ % Cost UScts tion (Health)

GWh/ye % mption UScts/ UScts/ MBtu

UScts/ / kWh UScts/ UScts/

ar

t/year kWh kWh kWh

kWh kWh

90 2,586.0 46.0 456,100 1.258 0.436 18.47 20.75 4.70 25.45

80 2,102.4 35.0 819,993 3.173 0.559 5.24 9.16 11.70 20.86

5.00 90 2,365.2 50.0 339,016 1.258 0.308 3.41 5.03 0.48 5.51

10.00 90 2,365.2 50.0 339,016 1.258 0.308 6.82 8.44 0.48 8.92

15.00 90 2,365.2 50.0 339,016 1.258 0.308 10.23 11.85 0.48 12.33

However, this would not cause any problem because of the low demand during early hours of

the day from about 0100h to 0500h, which is not more than 1000 MW. The coal plants meant

to supply the base load without interruption are expected to supply this power throughout.

Hence, the energy from the CCGT plants will have to be curtailed during this period to match

the demand. This would result in reducing the demand from about 94 Mcf/day to about 75

Mcf/day, though by 2018, the situation with respect to minimum demand may change.

With the availability of NG after 2018, the options of substituting new coal power plants with

NG power has to be considered. A policy decision has to be taken as to whether to build the

proposed coal power plants at Sampur or build NG power plants instead, if NG is available

locally in adequate quantities. The construction of the Sampur power plant has been delayed

for many years and its EIA report has still not been submitted. Further, there had been many

adverse reports about the unsuitability of the plant offered by none other than the CEB

professionals123

. It is known that Indian coal has low calorific value and high ash content. It

76

appears that India will get the benefit of the electricity generated leaving behind the burden of

pollution generated in Sri Lanka.

Another aspect that needs to be looked into is whether the present system could accommodate

another large coal power plant. The yearly average daily load curves of the present system for

the period 2004-2011 taken from the CEB LTGE Plan is shown in Fig. 51, according to which

the demand during the early hours of the day from 0100h to 0500h is around 1000 MW.

Judging from its growth in the past, it may reach 1,500 MW by another 5 years. The present

CPP with 900 MW capacity and the hydro power plants that need to be operated mandatorily

could meet this demand. Coal power plants are meant to operate continuously during the day

with maximum load for optimum efficiency. If another CPP is added, it may not be possible

to operate while meeting this criterion, whereas a CCGT operating with NG could operate

under varying load factors unlike a CPP and would be a better option.

Fig. 51. Annual average daily load curves during 2004 - 2011124

Section 5.4 describes the expansion of the power sector according to the Revised Base Case

2012 in the Addendum to LTGE Plan 2013, and this is referred to as the business-as-usual (BAU) scenario. For developing Sri Lanka’s thermal power system utilizing NG after

converting the three CCGT plants to NG operation in 2018, two options are proposed, referred

to as Scenario NG1 and NG2. Scenario NG1 is based on the CEB case given as Annex 7.15 of

LTGE Plan, according to which 12 NG plants each of 250 MW will be introduced annually

beginning 2022 except that in 2023, there will be 2 units of 250 MW added, making the total

capacity operating with NG to be 3,000 MW. In 2018, 3 coal plants each of 250 MW, and in

2019, one coal plant of 250 MW will be added. In addition, one 75 MW GT plant and one 105

MW GT plant will be added in 2015 and one 105 MW GT plant added in 2017. These 3 GT

plants will also be converted to NG operation from 2023. This plan is extended to 2040 by

adding annually one 250 MW NG plant after 2032, making a total of 5,000 MW of NG

capacity installed. In the BAU scenario, as included in CEB Plan, the 163 MW CCGT plant is

to be retired in 2023. However, in the NG1 scenario when the CCGT plants will be operated

with NG, its retirement will be deferred till 2033 when it will complete 30 years of operation.

This plan is reproduced in Table 29.


77

Table 29. Proposed additions of power plants under Scenario NG1125

Year New Hydro Plants New Thermal Plants Retired Thermal

Plants

2015 1x300 MW Coal

75+105 MW GT - Diesel

2016 Broadlands 35 MW 260 MW Diesel

Uma Oya 120 MW

2017 1x105 MW GT - Diesel

2018 Moragolla 27 MW 3x250 MW Trinco Coal 131 MW Diesel

2019 1x250 MW Trinco Coal 157 MW Diesel

2020

2021

2022 1x250 MW NG

2023 2x250 MW NG 151 MW Diesel

2024 Gin Ganga 49 MW 1x250 MW NG

2025 1x250 MW NG 36 MW Diesel

2026 1x250 MW NG

2027 1x250 MW NG

2028 1x250 MW NG

2029 1x250 MW NG

2030 1x250 MW NG

2031 1x250 MW NG

2032 1x250 MW NG

2033 1x250 MW NG 163 MW CCGT

2034 1x250 MW NG

2035 1x250 MW NG

2036 1x250 MW NG

2037 1x250 MW NG

2038 1x250 MW NG

2039 1x250 MW NG

2040 1x250 MW NG

In the LTGE Plan, it is envisaged to install a total of 1000 MW CPP comprising three 250 MW

coal plants to be added in 2018 and one 250 MW coal plant to be added in 2019 at Sampur. Under

NG2 scenario, it is proposed that the coal power plants at Sampur be replaced by NG plants of

equal capacity in 2018 and 2019, respectively. This expected optimistic situation is feasible only

if a large NG deposit is found within this time frame. Further the location of these NG plants

could be on the west coast in close proximity to the pipeline. The fuel consumption values under

the 2 scenarios are given in Figs. 52 and 53, and also in Table 30.


78

In view of the many adverse impacts of coal power plants, it is desirable to replace the

Sampur CPP with NG power plants and if adequate NG supplies are not available locally, it is

worth importing the NG requirements and shift from coal power to gas power.

Fig. 52. Projected fuel consumption in the power sector under NG1 scenario

Fig. 53. Projected fuel consumption in the power sector under NG2 scenario.

Both scenarios will have a coal contribution from the 900 MW Puttalam plant, while only

NG1 scenario will have a coal contribution from the Sampur plant. Both scenarios will have

oil contribution from the three CCGT plants up to 2017, and from the three GT plants up to

2022. In Table 30 are also shown the volume of NG required daily to generate the same

amount of energy consumed shown for the natural gas component. The projected fuel

consumption under the 3 scenarios – BAU, NG1 and NG2 – are shown in Fig. 54. In view of

the higher efficiencies of the CCGT plants, it is anticipated that there would be a significant

reduction of fuel consumption under NG1 and NG2 scenarios.

The projected cost of imported coal is estimated assuming its price to escalate at an annual rate of

5% from a price of USD 134/t paid in 2012, while that of oil is estimated assuming its price to

escalate at an annual rate of 2.5% from a price of USD 1047/t paid in 2013. The costs of fuel

consumed under the 3 scenarios, BAU, NG1 and NG2 are shown in Fig. 55. Under the BAU

conditions, the cost of fuel consumed in the power sector will be more than USD 11,500 million

by 2040, while it will be below USD 4,000 million when using NG. Further, the cost of

externalities will almost be nil and the government could save large sum of money by avoiding


79

expenditure on health care of people exposed to pollution generated by coal power plants and

suffering from various ailments caused by such exposure.

Fig. 54. Projected fuel consumption in the power sector under the 3 scenarios.

Fig. 55. Projected cost of fuel consumed in the power sector under the 3 scenarios

Natural gas will be the key fuel used under scenarios NG1 and NG2. The annual demand of

NG under these scenarios up to 2040 is shown in Fig. 56. The consumption in 2040 will be

807 Mcf/d under NG1 scenario while it is 910 Mcf/d under NG2 scenario.

Fig. 56. Projected demand for NG in the power sector under NG1 and NG2 scenarios


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Table 30. Demand for NG in the power sector under NG1 and NG2 scenarios

Total fuel consumption PJ/y

NG demand - NG demand -

Year NG1 scenario NG2 scenario

BAU NG1 NG2 PJ/y Mcf/d PJ/y Mcf/d

2014 79.3 79.3 79.3

2015 113.8 110.9 110.9

2016 113.8 110.9 110.9

2017 120.4 117.5 117.5

2018 154.2 148.2 125.8 35.6 92.7 47.0 122.2

2019 194.7 188.8 154.2 35.6 92.7 75.4 196.0

2020 194.7 188.8 154.2 35.6 92.7 75.4 196.0

2021 215.0 188.8 154.2 35.6 92.7 75.4 196.0

2022 235.3 203.0 168.4 49.8 129.6 89.6 232.9

2023 275.8 243.3 193.8 93.2 242.3 132.9 345.6

2024 275.8 242.5 207.9 107.4 279.2 147.1 382.5

2025 296.1 256.7 222.1 121.6 316.1 161.3 419.4

2026 296.1 270.9 236.3 156.4 406.7 175.5 456.3

2027 316.4 285.1 250.5 167.3 435.1 189.7 493.2

2028 336.6 299.3 264.7 164.2 426.8 203.9 530.1

2029 336.6 313.5 278.9 178.3 463.7 218.1 567.0

2030 356.9 327.7 293.1 192.5 500.6 232.3 603.9

2031 377.2 341.9 307.3 206.7 537.5 246.5 640.8

2032 397.4 356.1 321.5 220.9 574.4 260.7 677.7

2033 407.7 361.0 326.4 225.9 587.2 265.6 690.6

2034 427.9 375.2 340.6 240.1 624.1 279.8 727.4

2035 448.2 389.4 354.8 254.2 661.0 294.0 764.3

2036 468.5 403.6 369.0 268.4 697.9 308.2 801.2

2037 488.8 417.8 383.2 282.6 734.8 322.4 838.1

2038 509.0 432.0 397.4 296.8 771.7 336.6 875.0

2039 529.3 446.2 411.6 311.0 808.6 350.7 911.9

2040 549.6 460.4 425.8 325.2 845.5 364.9 948.8

Costing under the coal and NG scenarios

The levelized cost of electricity generation was discussed in a previous section. These rates

are now applied to the generation each year from 2013 to 2040, with the cost of fuel adjusted

for inflation. For coal, beginning with the 2012 price given in CEB SD 2013, estimates are

made up to 2040, assuming 5% annual escalation of price. For NG, three cases of prices are

assumed as suggested by PRDS, USD 15/million Btu from 2018 to 2022, USD 10/million Btu

from 2023 to 2024 and USD 5 per million Btu from 2025 and thereafter. Fig. 57 gives the

levelized cost for generation of electricity from coal, diesel and gas.


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Fig. 57. Levelized cost of generation of electricity with coal, diesel and gas

The saving on cost of fuel alone with NG amounts to about USD 7 billion a year under NG1

scenario and USD 8 billion a year under NG2 scenario, by 2040. As seen in Fig. 57, the

specific levelized cost of coal electricity is higher than with natural gas commencing 2021.

One reason for this reversal of costs is that the cost of coal has escalated from USD 134/t in

2012 to USD 241/t in 2025 (5% annual increase) while the cost of NG has dropped from USD

15/million Btu in 2018 to USD 5/million Btu in 2025.

8.7 Projected demand for natural gas in all sectors

The anticipated consumption of NG in the four sectors - household & commercial, industrial,

transport and power sector under NG1 Scenario beyond 2018, as given in Tables 23, 24, 26,

27 and 30 for the HH&C, Industrial, Transport and Power sectors, respectively is given in

Table 31 and graphically in Figs. 58 and 59 for NG1 and NG2, scenarios respectively.

Fig. 58. Projected demand of NG in all sectors under NG1 scenario

It is noted that the main consumers will be the power and transport sectors. The commencement of

utilizing NG in sectors other than the power sector has been staggered to match closely the

production schedule of NG from the current explorations. It is noted that the consumption in

HH&C and Industrial sectors are much lower than those in the Power and Transport sectors.


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In Table 31, the amount of NG introduced to generate energy in different sectors under NG1

and NG2 Scenarios including NG required for urea manufacture is given. The demand is

expected to grow from 93 Mcf/d in 2018, 725 Mcf/d in 2030 to 1,598 Mcf/day by 2040 under

NG1 scenario. Under NG2, the corresponding demand values are 122, 1164 and 2,525 Mcf/d,

respectively, by 2040.

Table 31. Demand for NG in all sectors under NG1 and NG2 scenarios

Year NG Demand under NG1 - Mcf/d NG Demand under NG2 - Mcf/d

Power Trans Indus HH&C Total Power Trans Indus HH&C Total

2018 92.7 93 122.2 122

2019 92.7 93 196.0 196

2020 92.7 93 196.0 196

2021 92.7 93 196.0 196

2022 129.6 130 232.9 233

2023 242.3 10.1 252 345.6 20.2 1.9 368

2024 279.2 21.5 0.9 302 382.5 43.0 3.8 429

2025 316.1 34.3 1.9 352 419.4 68.6 199.8 688

2026 406.7 48.6 83.8 2.3 541 456.3 97.3 201.9 3.5 759

704.4 435.1 64.6 84.8 4.9 589 493.2 129.3 204.2 7.4 834

741.3 426.8 82.5 85.9 7.9 603 530.1 165.0 206.5 11.9 914

2029 463.7 102.4 87.1 11.3 665 567.0 204.8 208.9 17.0 998

2030 500.6 124.6 88.3 15.1 729 603.9 249.1 288.2 22.7 1164

2031 537.5 149.2 109.8 19.4 816 640.8 298.3 290.9 29.1 1259

2032 574.4 176.5 111.1 24.2 886 677.7 353.0 293.7 36.3 1361

2033 587.2 206.7 112.6 29.6 936 690.6 413.5 296.7 44.4 1445

2034 624.1 240.3 114.0 35.7 1014 727.4 480.5 299.8 53.5 1561

2035 661.0 277.3 115.6 42.4 1096 764.3 554.7 378.7 63.6 1761

2036 697.9 318.3 137.5 49.9 1204 801.2 636.7 379.6 74.9 1892

2037 734.8 363.6 139.2 58.3 1296 838.1 727.2 380.5 87.4 2033

2038 771.7 413.6 141.1 67.5 1394 875.0 827.2 381.5 101.3 2185

2039 808.6 468.7 143.1 77.8 1498 911.9 937.4 382.6 116.7 2349

2040 845.5 529.5 145.1 89.2 1609 948.8 1058.9 383.7 133.8 2525

In industries under NG1 scenario, the use of NG both as a fuel in place of fuel oil and LPG and as

a feedstock in the manufacture of urea, AMS and DME were included. Under NG2 scenario,

enhanced penetration of NG as a fuel as well as additional requirements as a feedstock in the

manufacture of methanol and ethanol were included. The relevant consumption rates were

proposed targeting export markets for these two products. It is also envisaged that the availability

of these products which form the basic raw materials in the manufacture of a wide range of

chemical products will serve as an inducement for a local chemical industry to grow.


83

Fig. 59. Projected demand of NG in all sectors under NG2 scenario

The PRDS expects delivery of NG from deposits already discovered at the rate of 70 Mcf/d during

2018 – 2020, at 140 Mcf/d during 2021 and 2022, and at 210 Mcf/d from 2023 onwards. In order

to realize these demands, ie. 1,609 Mcf/d by 2040 under NG1 scenario and 2,525 Mcf/d under

NG2 scenario, it is necessary to have sufficient deposits which could be extracted economically.

With the values tabulated above, the quantities available for extraction over a time period of 22

years would be 6 Tcf under NG1 scenario and 10 Tcf under NG2 scenario. To sustain the

consumption for another 10 year period under NG2 scenario, the deposits should have a capacity

of another 10 Tcf. After exploring for new deposits, it is hopeful that additional supplies could be

obtained to sustain the anticipated demand. In order to utilize the NG supplies beginning 2018, it

is necessary to plan out the strategies and have necessary policies in place.

8.8 Distribution of natural gas

Currently, exploration for gas is taking place in the sea off Kalpitiya Peninsula. It is planned

to lay the pipeline to reach the shore at Norochchole, close to the site of the Puttalam CPP.

Gas brought in has to be purified including removal of any condensate and compressed before

sending off to the city. For this purpose, a land-fall terminal (LFT) comprising a purifier unit

and a compressor will have be built at a site in close proximity to the point of landing of the

sub-sea pipeline bringing gas. The purified gas is then compressed to about 100 bar for

transmission using pipelines to the Central Storage Terminal (CST) close to the city possibly

at Kerawalapitiya. A convenient path for laying the pipeline would be the reservation along

the Puttalam railway line. Another option is to lay a sub-sea pipeline along the coast from

Norochchole to Kerawalapitiya, which would avoid any problems in land acquisition. It is

expected that some storage tanks will be built at Kerawalapitiya to store an adequate buffer

quantity of gas under pressure before it is delivered to consumers.

In order to supply NG to the various consumers as described earlier, it is necessary to build a

distribution system comprising a combination of a pipeline network and a transfer system by

bulk carriers transported by road or by rail to key consumer points. The bulk carrier could be

carrying either CNG or LNG, as each type has its own merits. Between CNG and LNG, LNG

has a higher energy density than CNG, being 450 kg/m3 for the former and 130 kg/m

3 for the

latter, respectively. The LNG deliveries could be less frequent than CNG deliveries.


84

An LNG container carries 63% of the energy that a diesel bowser of the same capacity carries,

whereas a CNG container carries only 18%. Hence, LNG transport is more economical than

transporting CNG and it may be necessary to build also a liquefaction plant at the CST.

Today, small scale liquefaction plants capable of producing outputs up to 50 t of LNG per day

are available at costs in the range USD 2-3 million126

. They have a very low overhead too.

NG supplied by pipelines is generally delivered from CST to consumer units at a pressure of

about 20 bar. It will therefore be necessary to install suitable pressure regulators to supply the

gas to consumer units at a lower pressure - between 0.02 and 2 bar - according to the

requirements of the consumer. In summary, establishing a network system for the distribution

of NG to consumers will generally comprise the following steps:

1. Laying the main pipeline from the LFT in Kalpitiya Peninsula to the CST at K’pitiya

carrying gas at a pressure of about 100 bar, possibly along the railway line reservation or

as a sub-sea pipeline along the coast. 2. Laying pipelines from the CST to Kerawalapitiya CCGT power plant and to Kelanitissa

CCGT power plants, delivering the gas at a pressure of about 2 bar. 3. Establishing a low-pressure compressor unit at LFT and a high pressure compressor at

CST to feed CNG bulk carriers for transport in containers either by road or rail. 4. Establishing a NG liquefaction unit at CST and facilities for loading LNG into carriers for

transporting to LNG consuming points. 5. Establishing CNG/LNG dispensing outlets along major highways to feed CNG/LNG

operated vehicles, receiving gas supplies from CNG/LNG containers. 6. Establishing LNG storage and re-gasification units at heavy consumer points such as

industries and hotels and also at townships, receiving gas supplies from LNG containers

(In towns where railway transport is available, these points could be established close to

the railway stations). 7. Laying local pipeline networks required for supplying gas to industries in industrial estates

and houses at housing schemes at appropriate pressure from the LNG storage units. 8. Laying pipelines to sites of new NG operated CCGT power plants from the CST to supply

gas at 2 bar pressure.

The above distribution system could be established as illustrated in Fig. 60.

Industries and hotels could be supplied with gas at a pressure of 1 bar, while households could be

supplied with gas at about 0.02 bar. Power plants need a gas supply at a higher pressure of about 2

bar. For supplying to vehicles, the gas could be transported to gas outlets installed along highways

using either CNG or LNG bulk carriers. In the long term, explore the possibility of laying

pipelines from the CST to major cities or heavy consumer point which will eliminate the inter-city

transport of CNG/LNG in containers. The operation of local NG networks could be entrusted to

licensed parties who could be made responsible for the installation and maintenance of pipelines,

coordinate supplies from CST, monitoring of consumption and collecting the revenue. There

should be a body established to regulate the distribution of gas among consumers including

issuing licenses to operators of piping networks, handling the sale of gas


85

to operators and collection of the revenue from them and to be responsible for the entire gas

distribution and marketing system including safety aspects. It is extremely important that the

necessary safety procedures are in place and safety protocols followed including proper training of

operators before the actual gas distributions are commenced, as outlined in Section 2.5.

From CST Main Pipeline – Pressure ~ 20-100 bar To other cities

Supply to

Supply to gas

Supply to industries townships outlets and power plants

Regulator

Regulator

Liquefaction Compressor 20/4 Plant -163

oC Pr: 250 bar 20/4

Pr: 4 bar

Pr: 4 bar

Storage

Storage

LNG

CNG

4/1

4/0.

4/.02

4/1

4/1

4/2

Carrier Carrier

Industry

Hotels

Houses LNG CNG

Industry 1 Industry 2 Power Plant

Storage

Storage

Heavy Light

Vehicles

Vehicles

Fig. 60. Proposed gas distribution network127


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9. Benefits of utilizing natural gas

Natural gas is an indigenous clean, low-cost source of energy. There are many benefits in

using NG. It has the potential for use in the generation of energy in all sectors – household &

commercial, industries, transport and power. Combustion of NG in vehicles, industries and

power plants causes reduced emissions of polluting gases which are harmful to human health

and the environment. In addition, the use of locally sourced NG will result in economic

benefits such as energy security, new employment opportunities and use as a feedstock for

various industries.

9.1 Energy security

As shown in Fig. 7, out of the total primary energy supply during 2010-2012, the indigenous

sources comprising biomass (44%), hydropower (8%) and NCRE (2%) had contributed 54%.

The balance, comprising petroleum oil (43%) and coal (3%), was imported. The cost of

import of fossil fuels accounts for on an average 25% of all imports in 2012 and 2013128

.

Both petroleum and coal prices are highly volatile depending not only on the supply and

demand factors but also on regional geo-politics. The transport sector depends entirely on oil,

while the power sector currently depends mostly on oil and coal.

The political situation in the ME countries which are the main suppliers of petroleum oil is

extremely volatile. Frequent conflicts occur in these countries and if these escalate there is a

possibility that our oil supplies could get disrupted. Sri Lanka is already affected by economic

sanctions imposed against Iran who was the major supplier of Sri Lanka’s crude oil

requirements in the recent past. Before sanctions were imposed, Iran was also willing to

supply NG to Sri Lanka and also offered to assist us to install a NG fired power plant, but all

these proposals could not be pursued because of American sanctions and the situation appears

to be getting worse day by day.

Sri Lanka is also under threat from UN and other super powers bringing economic sanctions

for alleged human rights violations. It should be remembered that already economic sanctions

have been imposed on several countries depriving them of food, drugs and other essential

goods, which itself is a violation of human rights. It is therefore essential that Sri Lanka

develop its own energy resources without having to depend on external sources which can get

disrupted any moment. The shift from imported oil to domestic NG as a source of energy will

ensure energy security for the country.

Concurrent to NG exploration, an effort needs to be made to develop and exploit NCRE

resources along with rehabilitation of the grid to accommodate NCRE generated energy. It is

also necessary to improve the efficiency of extraction of energy from biomass in household

applications which is currently at a very low value, typically below 10%. One possibility is to

produce DME from biomass which could then be filled into cylinders and use for household

cooking. This will enable meeting domestic requirements of energy with a lesser amount of

biomass.


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9.2 Clean air for a healthy nation

Clean air is essential for man’s healthy life. What he inahales needs to be free of toxic constituents

that will endanger the normal functioning of his vital organs. As shown in Table 18, pollutants

emitted from diesel operated vehicles and thermal power plants, particularly coal and petroleum

oil-fired power plants, could cause many respiratory ailments and also malignancy in humans.

Currently, Sri Lanka governemnt spends nearly LKR 100 billion on recurrent expenditure in the

health sector129

. According to the Bulletin of the Ministry of Health, patients treated for

respiratory ailments constitute about 10%, which means that the annual expenditure on treating

patients with respiratory ailments could be about LKR 10 billion.

The introduction of NG in all sectors as described in previous sections will reduce the

emission of the key GHG which is CO2 and other air pollutants which are SO2, NO2 and total

suspended particulates (TSP). These are produced mainly from the transport and power

sectors while the contributions from other sectors - household & commercial sector and

industrial sector are rather small. Their emission levels are computed based on the energy

consumption values of different fuels in each sector projected up to 2040 as given in Tables

23 (HH&C), 24 (Industrial), 27 (Transport) and 30 (Power). The emission factors depend on

the fuel as well as the final application. The factors used in the computation for the four

sectors for each of the fuels consumed, taken from the 2006 IPCC Guidelines are given in

Table 32. Sulphur content in oils are taken from CPC Product Specifications.

Table 32. Emission factors used in pollutant emission computations

Emission Factor130

Sulphur131

Fuel CO2 NO2 g/GJ

TSP g/GJ

Percent

g/MJ

Sector All HH Ind Tran Pwr HH Ind Tra Pwr Ind Tra Pwr

Diesel 76,300 100 200 250 280 5 5 5 5 0.3 0.3 0.3

Fuel oil 79,690 100 200 280 13 13 11 3.0 1.5

Gasoline 69,300 100 150 - -

LPG 63,100 100 100 - -

K’sene 71,900 100 - 0.3

Coal 97,460 300 300 10 40 1.0 0.7

NG 57,790 50 150 150 150 - - - - -

HH: Household & Commerce; Ind: Industries; Tran: Transport; Pwr: Power

The emissions of each of these polluting gases SO2, NO2 and TSP from these sectors under BAU

scenario are shown in Figs. 61, 62 and 63, respectively. The corresponding emission levels under

NG1 scenario are shown in Figs. 64, 65 and 66, respectively. While the power sector is the major

source of all emisssions, the transport sector comes second. The contributions from household &

commerce and industrial sectors are very much less than those from the power and transport

sectors. As indicated in the above Table, coal gives the highest emission of CO2 and NG the

lowest per unit energy supplied. Emission of SO2 depends on the sulphur content


88

in the fuel and the values assumed are shown in the last two coulmns for the industrial and

power sectors. NG does not produce any SO2. Emission of NO2 from NG is lower than from

other fuels except in the case of transport sector. NG does not produce any particulates at all.

Fig. 61. Projected SO2 emissions from different sectors under BAU scenario

Fig. 62. Projected NO2 emissions from different sectors under BAU scenario

Fig. 63. Projected TSP emissions from different sectors under BAU scenario


89

Fig. 64. Projected SO2 emissions from different sectors under NG1 scenario

Fig. 65. Projected NO2 emissions from different sectors under NG1 scenario

Fig. 66. Projected TSP emissions from different sectors under NG1 scenario

The emission levels of CO2 and the three key pollutants – SO2, NO2 and TSP under the 3

scenarios – BAU, NG1 and NG2 from all sectors up to 2040 are shown in Table 33 and also in

Figs. 67, 68 and 69. Conversion of power generation from a coal based system to a NG based

system and shifting of transport fuels from diesel and gasoline to NG would reduce the emission

of all pollutants, particularly SO2 and TSP. In the power sector, under BAU case, coal is the


90

primary fuel while NG is the primary fuel for new plants to be added under NG1 and NG2

scenarios. As a result, the emission of SO2 and TSP will be limited beyond 2023 when the

NG takes over as the dominant fuel.

Table 33. Emissions of CO2, SO2, NO2 and TSP under the 3 scenarios

BAU NG1 NG2

Year CO2 SO2 NO2 TSP CO2 SO2 NO2 TSP CO2 SO2 NO2 TSP

Mt kt kt kt Mt kt kt kt Mt kt kt kt

2014 18.2 77.2 49.2 2.4 17.4 77.2 49.4 2.43 17.4 77.2 49.4 2.4

2016 22.5 91.4 61.3 3.3 21.3 91.0 61.0 3.34 21.3 91.0 61.0 3.3

2018 27.7 111.9 76.3 4.8 25.5 102.5 73.7 4.48 22.9 63.2 65.2 3.1

2020 33.2 135.2 92.5 6.5 30.8 104.3 89.9 6.15 26.0 65.1 73.6 3.2

2022 38.9 158.6 109.2 8.1 33.3 106.4 96.6 6.21 28.6 67.1 80.3 3.2

2024 44.9 182.3 126.4 9.8 37.1 104.7 105.7 6.15 32.2 63.3 88.4 3.1

2026 49.2 195.5 138.3 10.7 40.7 105.5 114.6 6.18 35.6 61.6 95.9 3.1

2028 55.9 219.6 156.9 12.4 44.5 106.3 124.0 6.21 39.1 59.7 103.5 3.1

2030 60.9 233.3 170.3 13.3 48.6 107.3 134.0 6.24 42.8 57.4 111.4 3.1

2032 68.4 258.0 190.8 15.0 52.9 108.3 144.7 6.27 46.7 54.6 119.5 3.0

2034 75.6 281.7 210.4 16.6 57.1 109.3 154.7 6.31 50.4 51.3 126.4 3.0

2036 84.1 307.1 233.2 18.4 62.1 110.4 167.0 6.34 54.8 49.5 135.2 3.0

2038 93.3 332.9 257.5 20.1 67.6 111.5 180.2 6.37 59.6 48.1 144.4 2.9

2040 103.2 359.2 283.4 21.9 73.6 112.7 194.5 6.40 64.7 46.1 153.8 2.9

Fig. 67. Projected SO2 emissions from all sectors under different scenarios

It is noted that under BAU case there will be a massive amount of SO2, NO2 and TSP emitted

into the atmosphere, which would cause irreparable damage to health of people as described

in the previuous section. With an NG based power system, there is no such danger. It is noted

that emissions of NO2, SO2 and TSP are greatly reduced under NG1 and NG2 scenarios.


91

Fig. 68. Projected NO2 emissions from all sectors under different scenarios

Fig. 69. Projected TSP emissions from all sectors under different scenarios

9.3 Safe water to reduce health risks

Regular intake of clean water is also essential to keep our body functioning properly. The

emission of mercury from coal power plants is said to find its way in to the waterways and

finally into the diet of people through fish they consume. Fig. 41 shows the amounts of toxic

metals including arsenic and mercury that could get added to the soils in the air-shed areas of

the coal power plants and these could finally find their way into the water table and

contaminate water drawn by people for drinking.

With NG operated power plants, there is absolutely no possibility of any such contamination

of water causing damage to the health of people. The huge expenditure that the government

incurs annually on treating patients suffering from diseases caused by drinking contaminated

water could be averted if NG is used for the future energy generation in place of the large

number of coal power plants that would pollute the soil and the water table.

9.4 Clean environment to support tourism

When people plan to go on holidays, they would look for places that are clean and free of any

pollution. According to the Tourism Development Strategy 2011-2016 prepared by the Ministry

of Economic Development, government envisages that the number of tourists arriving in the


92

country to grow up to 2.5 million by 2016 from the present value of 1 million, and to 4.0

million by 2020 bringing an anticipated revenue of USD 8,000 million annually132

. Such a

growth in tourist arrivals could be achieved only if the country could offer a clean

environment free of pollution of air, water and land.

Coal power plants are generally located near the coasts in order to facilitate unloading of coal

from carriers and transport to the power plant. Already a plant has been built at Norochcholai

while another is planned at Sampur near Trincomalee. Both these are in close proximity to

Kalpitiya and Nilaweli, respectively, which have been identified for development of tourism.

Already building of necessary infrastructure including hotels and highways have commenced

in these areas.

If the government is serious about attracting tourists to these areas, these areas shoud be declared

pollution-free areas and not build coal power plants in proximity to them that would pollute the

air, soils and waterways. If NG power plants are built instead, that fact could be given publicity

and used in tourism promoting literature which would attract more tourists. The use of NCRE

systems by the hospitaility sector to power their premises should be encouraged.

9.5 Promoting industrial growth with low cost energy source

Under the proposed National Physical Plan shown in Fig. A14, a large number of industrial

estates are to be established to promote the growth of industries, each such estate providing

necessary infrastrucure within one location for setting up industries. These industrial estates

need both energy and steam. Small CCGT power plants operating with NG could be built

within these industrial estates to meet their electricity requirements. They could be operated as

combined heat and power (CHP) systems whereby steam is generated using waste heat of the

power plant. Such systems could enhance the overall efficiency of the system to about 90%. It

will also reduce the line losses incurred when bringing power from distant places. Currently,

losses in the elecricity supply amount to about 12%.

NG could be used for generating thermal energy directly as required in such applications as

furnaces, kilns, ovens more efficiently and with less impact on the environment than what is

possible when burning petroleum oil or biomass. Bettter control on the performance including

temperature control could be achieved with NG which would improve the quality of the

product and reduce rejects from the production lines. If a clean source of energy is availabe to

industries, it should be possible to attract more foreign direct investments (FDI) for industries.

Natural gas serves as a feedstock for many industries. Already, the possibility of manufacture

of urea from NG has been considered as it has a ready market as a fertilizer in the country. In

addition, many other NG based industries could be undertaken that would provide added

employment opportunities and enhance the economic growth in the country.


93

9.6 Ensuring food security

Sri Lanka’s highest productive agricultural land is in the NWP, NCP and EP. Both paddy and

subsidiary crops are grown extensively in these provinces. The governemnt has spent a vast

amount of money in providing irrigation facilities to these provinces by diverting Mahaweli

Ganga into the NCP and distributing the water across the land. This has enabled the farmers to

cultivate their land the year round.

One reason for the high agricultural productivity in these 3 provinces is the fact that they receive

high solar insolation throughout the year with minimum cloud cover. The land being flat, there is

little erosion which maintains the fertility of the soil without getting degraded. The emissions

from the coal power plants already established in the west coast off Puttalam and the proposed

plant at Sampur near east coast south of Trincomalee could change this situation.

Polluting emissions from these power plants after getting dispersed from the plants will get

deposited across the land causing adverse impacts on the crops and other vegetation. During

SW monsoon months, pollutants emitted from the Puttalam plant will get blown to the interior

and deposited on farmland in the NWP and NCP. Similalrly, during NE monsoon months,

pollutants from the Sampur plant will get blown to the interior and get deposited in farmland

in the EP and NCP.

Coal combustion leads to the contamination of agricultural soils through deposition of tons of

metals annually on croplands, leading to possible decreased crop yields and heavy metal

accumulation in edible crops. With the CEB’s plans to continue to install more and more coal

power plants, it will be difficult to maintain pollution-free agricultural lands to grow crops. If

the productivity of the land gets degraded, it will be a threat to the food security in the

country. Substitution of the planned coal power plants with NG power plants will ensure that

the land will be kept free of pollution and in turn ensure food security.

9.7 Land free of toxic metals and radioacive material

As descibed in Section 6.3, combustion of coal leaves about 10% or more of the quatity burnt

as ash. This ash contains many toxic heavy metals including mercury, arsenic and cadmium. Fig. 41 gives the amounts likely to be deposited on the country’s soil. Furthermore, coal ash

contains significant amounts of radioactive substance verified by researchers of University of

Colombo (see p. 52). Dumping of these toxic material all over the country when over 4,500

MW of planned coal power plants are built is a crime against the future genertations when

alternatives are available.

The proposed coal power plants having the above capacity will generate over 1 million tonnes of

ash annually, assuming 10% ash content in coal. Unlike large countries like USA, China or India

where coal is used heavily, Sri Lanka is a small country where the land is highly congested and

inadequate for people to live and grow food crops. The municipal councils already find it difficult

to find land to dispose solid waste generated by people. As such, there is absolutely no land

available away from human habitation to dump coal ash containing toxic radioactive


94

material. If NG is used for power generation there will be no such solid waste accumlated and

the country will be free of toxic and radioactive substances.

9.8 Improving the national economy

There is a wide deficit in the balance of payment of the country as shown in Table 34, which has

been LKR 432,368 million in 2012 and LKR 151,385 million in 2013. This deficit is covered by

loans from foreign multilateral financial institutions. The outstanding external debt of the country

in 2013 was USD 39.7 billion133

or LKR 5,160 billion, which is the cumulative debt over the

years.This amounts to 59% of the GDP and does not reflect well of the country’s economy. The

government currently spends about 25% of the total import bill on petroleum fuel. This is an

impediment on the development of the economy. Any further enhancement of expenditure on

importing oil would cause an added burden on the country’s economy.

Table 34. Balance of payment during 2012 and 2013134

Item Million LKR Source

CBSL AR 2012 2013

Imports 2,441,879 2,323,128 Table 75

Exports 1,245,531 1,344,054 Table 65

Remittances 763,980 827,689 Table 85

Total Income 2,009,511 2,171,743

Deficit 432,368 151,385

If commercially exploitable gas deposits are found within the country’s territory including

off-shore, this dependency on foreign energy resources could be minimised and the possibility

of widening the balance of payment could be averted. Development needs more energy and

any increase in fuel imports will be at the expense of import of other essential consumer

goods such as food and drugs. If fuel could be sourced locally, much foreign exchange could

be saved which could be used for importing other essential goods. In the event larger deposits

of NG are found in blocks yet to be explored, any surplus NG could be exported which could

help in meeting the current deficit in the balance of payment which is shown in Table 34.

9.9 Enhancing employment opportunities

The develpoment of indutries using NG as a feedstock, its transmission across the country and

local distribution within townships and industrial estates would necessitate deployment of

large number of trained personnel. They need to be recruited from among those with basic

technical training and thereafter given specialised training to handle the work involved. They

must also be trained in every safety aspect including training in handling accidents caused due

to any leakage. Hence, the programme for their recruitment has to commence well before the

actual phase-in activities take place.

It is estimated that initial building of infrastructure, susequent operation and maintenance of

pipeline networks would require several thousands of technical persons. Also there are other


95

value added benefits through participation and development of national labour, knowledge,

technology, services and research capabilities to the entire society subject to exploitation of

our own NG resources. The possibility for developing new industries using NG as feedstock

has the potential to create thousands of direct employment opportunities at all levels –

technical, support services and management and many more indirect employment

opportunities in marketing and servicing the products manufactured.

9.10 Meeting international obligations

There are two international treaties concerning emissions and releases from coal power plants,

which the Parties are obliged to comply with. One is on GHG emissions and the other is on

mercury releases. Shifting from coal to NG as a source of energy will enable compliance with

both these conventions.

UN Framework Convention on Climate Change (UNFCCC)

The UNFCCC has been ratified by almost all nations and has come into force many years ago.

Under the convention, previously only the developed country Parties are required to reduce

emissions of GHGs as specified under the legally binding Kyoto Protocol of the Convention.

It has now been superseded by the Cancun decision, according to which, developing countries

are also required to take “nationally appropriate mitigation actions in the context of

sustainable development aimed at achieving a deviation in emissions relative to business-as-

usual emissions in 2020”, and to report the same to the UNFCCC Secretariat. The decision

also requires developed countries to provide funding to developing countries for

implementing mitigation mechanisms once the developing countries inform the Secretariat

their mitigation strategies.

With the increase in the dependence on coal for generation of electricity, Sri Lanka’s CO2emission from the power sector is likely to increase from a value of about 6 million tonnes (Mt) annually in 2010 to about 25 Mt/year by 2025 under base case scenarios given in CEB’s

LTGE Plan. This is a 333% increase. While the 2025 amount could be considered as the

business-as-usual emissions, the country should have had in place a mitigation strategy to

reduce emissions by shifting to NG for future power generation.

In Sri Lanka, the current level of emissions are at a minimum with 0.78 tCO2Eq/capita135

, and

there is no possibility of reducing emissions further relative to the current levels. What Sri

Lanka could do is to reduce future emissions and show it as a reduction relative to future

business-as-usual (BAU) scenario. Many countries have adopted this strategy in reporting

their mitigation targets to the UNFCCC Secretariat.

The emission reductions mentioned above refer to aggregate reductions in the emissions of

the key GHG gases present in the atmosphere - CO2, CH4 and N2O. These emissions are

aggregated considering their global warming potentials (GWP) and expressed in terms of

CO2Eq values determined using the following formula. Natural Gas – New Energy Resource Sri Lanka Carbon Fund

96

[CO2Eq] = [CO2] + [CH4]*GWPCH4 + [N2O]*GWPN2O

GWPCH4 andGWPN2O refer to the global warming potentials of CH4 and N2O respectively,

relative to that of CO2 over a 100 year time frame136

. The values of CH4 and N2O emissions

were obtained for each generation scenario – BAU, NGI and NG2 – discussed earlier using

the GHG emission factors for different fuels which are shown in Table 35. This table also

gives the relevant GWP values.

Box 7. UN Framework Convention on Climate Change

The UNFCCC was adopted by Nations in 1992 with the objective of stabilizing the

greenhouse gas (GHG) concentration in the atmosphere at a level that would

prevent dangerous interference with the earth’s climate system. The convention

imposed restrictions on developed country Parties to limit their emissions of GHGs

to specified amounts within the time period 2008-2012, as given in the Kyoto

Protocol on Climate Change adopted in 1997. Developing country Parties were

exempted from this requirement originally, who were only required to take climate

change considerations into account when formulating relevant policies and actions.

According to a decision taken at the Parties’ meeting held in Cancun in December

2010, all Parties are required to reduce their emission of GHGs which include CO2

CH4, N2O and several other industrial gases. Under this decision, both developed

and developing country Parties are required to declare their own reduction targets

voluntarily. According to UNFCCC website, already 45 countries have declared

their targets of emission reduction but Sri Lanka has not yet done so. This could

result in Sri Lanka not receiving preference for any assistance from climate change

funding mechanisms.

The contribution from CH4 and N2O to global warming potential from energy and allied

sectors is rather small, being about 0.4% only. Hence, only the CO2 contribution has been

considered in the study. Fig. 70 shows the CO2 values obtained under the 3 scenarios. It may

be noted that a reduction of 15% relative to BAU values could be achieved under NGI

scenario by 2024, and a 26% reduction under NG2 scenario. Adopting such a mitigation

strategy has far reaching implications for the country. Sri Lanka currently depends on various

funding mechanisms such as International Monitory Fund (IMF), World Bank (WB) and

Asian Development Bank (ADB) as well as bilateral agreements to secure finances to meet its

development goals, both short-term and long-term. Natural Gas – New Energy Resource Sri Lanka Carbon Fund

97

Table 35. Emission factors and GWP values for CH4 and N2O137

Fuel Emission Factor g/GJ

CH4 N2O

Diesel 3 0.6

Fuel oil 3 0.6

Coal 1 1.5

Natural gas 1 0.1

GWP relative 21 310

to CO2

Fig. 70. Projected CO2 emissions from all sectors under different scenarios

One of the pre-conditions that these lenders or donors insist is our compliance with various

international conventions such as those on the protection of human rights, copy rights and

environment. Presently, Sri Lanka has to make a great effort to safeguard its good name in

respect of human rights allegations. In years to come, compliance with internationally agreed

environment treaties will take a similar position at funding negotiations. Therefore, increase

of emissions without an appropriate mitigation strategy will certainly not be in the best

interest of the country.

Minamata Convention on Mercury

The Minamata Convention on Mercury (MCM) is the latest international convention adopted

to protect human health and the environment from human activities. It relates to the control of

release of mercury and mercury compounds into the environment. It was adopted in October

2013 with signatures received from 91 countries and the EU138

. (Sri Lanka is not among the

signatories). Once the MCM is ratified by 50 nations, it will come into force. According to

Article 9.4 of MCM, A Party with mercury sources shall take measures to control its releases

and may prepare a national plan setting out the measures to be taken to control releases and its

expected targets, goals and outcomes for submission to the Conference of the Parties within

four years of the date of entry into force of the country to the Convention.


98

Box 8. Minamata disease caused by mercury pollution

The first case of children and adults getting afflicted by a neurological syndrome

was discovered in 1956 in Minamata, Japan. The symptoms shown included

ataxia, numbness in the hands and feet, general muscle weakness, narrowing of the

field of vision, and damage to hearing and speech. In extreme cases, insanity,

paralysis, coma, and death could follow within weeks of the onset of symptoms.

This neurological disorder was referred to as the Minamata disease as its cause

was not known at the beginning.

Later investigations revealed that effluent containing methyl-mercury had been

released from a chemical factory into the close by Bay and people who consumed

fish caught from the Bay had suffered from this disorder. It had taken more than 3

years for doctors to identify the causal factor of the disease to mercury waste

released from the factory, but it had taken more than half a century for preventive

measures to be implemented and affected people compensated. The latest measure

to prevent such incidents is the adoption of Minamata Convention on Mercury

(MCM) adopted in 2013.

Mercury is among several heavy metals found in coal ash as shown in Fig. 41, which gives

the amount of heavy metals that would be released when all the coal power plants amounting

to 3,700 MW are in place under the BAU case. According to this Figure, annually 3 t of

mercury will be released into the environment and this could leach into the water table and

contaminate drinking water sources. It could also get into the food chain through intake by

fish and cause neurological disorders139

. In USA, more than 50% of mercury emitted into the

environment had originated from coal power plants140

. In Sri Lanka too, with the proposed

addition of coal power plants, there could be significant amounts of mercury emitted into the

environment. However, Sri Lanka will be required to control emission of mercury once it

becomes a Party to the convention. The best strategy to follow to limit mercury emissions is

to convert all existing and planned coal power plants into NG operated power plants.


http://en.wikipedia.org/wiki/Neurology

http://en.wikipedia.org/wiki/Muscle_weakness

http://en.wikipedia.org/wiki/Field_of_view

http://en.wikipedia.org/wiki/Field_of_view

http://en.wikipedia.org/wiki/Insanity

http://en.wikipedia.org/wiki/Insanity

http://en.wikipedia.org/wiki/Paralysis

http://en.wikipedia.org/wiki/Coma

http://en.wikipedia.org/wiki/Death

99

10. Export potential of natural gas

In the event gas exploration is extended to additional fields and new deposits are found, Sri

Lanka could explore the possibility of exporting any surplus gas to countries in Asia where

there is a high demand. However, before taking such a decision, it is necessary to consider the

situation with regard to demand and supply of gas in the region and its market.

10.1 Production of gas in Asia

Natural gas is produced in several countries in Asia and Indian Ocean Rim (IOR) countries

where it is used for domestic purposes or exported either as gas through pipelines across land

or as LNG in carriers across oceans. Their estimated deposits and production rates are shown

in Table 36. Three new-comers to NG production in the region are Tanzania, Papua New

Guiney (PNG) and Myanmar. Tanzania is planning to export LNG to Asian countries at a

well-head price of gas at USD 3/million Btu141

. With the cost of liquefaction and freight

added, the cost to a buyer in the Far East is estimated to be USD 10.7/million Btu. Out of the

16 countries in the region producing NG, only 7 countries export currently, of which

Indonesia is the leading exporting country.

Table 36. Reserves and Production of NG in Asia and IOR countries142

Country Reserves 2012 Production Res/Prod Exports

143

Tcf Bcm Bcm/y Years Bcm/y

Afghanistan 1.750 49.55 4.94 10.0

Australia 27.850 788.51 55.78 14.1 24.7

Bangladesh 6.489 183.72 20.11 9.1

Brunei 13.800 390.71 12.44 31.4 8.81

China 107.000 3,029.45 102.74 29.5 3.21

India 40.745 1,153.60 47.61 24.2

Indonesia 141.060 3,993.77 76.24 52.4 42.33

Japan 0.738 20.89 4.99 4.2

Korea 0.250 7.08 35.77 0.2

Malaysia 83.000 2,349.94 61.72 38.1 30.79

Mozambique 4.500 126.33 3.82 33.1 3.50

Myanmar 10.000 283.13 11.91 23.8 8.29

NZ 0.976 27.63 4.37 6.3

Pakistan 26.620 753.68 39.14 19.3

PNG 5.483 155.24 3.53 44.0

Philippines 3.480 98.53 2.90 34.0

Taiwan 0.220 6.23 10.24 0.6

Tanzania 0.230 6.46 0.86 7.5

Thailand 10.589 299.80 36.98 8.1

Vietnam 24.700 699.32 7.71 90.7

Myanmar has commenced exporting gas to China in 2013 at the rate of 500 Mcf/day at a price of

USD 9/million Btu through a pipeline having a capacity of 12 Bcm/year. Myanmar is also

exporting gas at the rate of 300 Mcf/day to Thailand at a price of US$ 11/million Btu. The well-


100

head price at the off-shore well Shwe is USD 7.46/million Btu. China is importing gas from

Turkmenistan at a price of USD 9.84/million Btu in 2013. According to the latest agreement

entered into by China with Russia, it was reported that 38 Bcm/year of NG will be imported

for 30 years from Siberia along a 2,500 mile pipeline at a cost around USD 10/kcm (or USD

9.91/million Btu) though the exact price had not been disclosed144

.

The latest entry into the field of LNG export in Indian Ocean Rim (IOR) countries is Papua

New Guinea, where Exxon-Mobile has built NG exploring and LNG exporting facilities with

an investment of USD 19 billion. The first shipment of LNG was delivered to Japan in May

2014. The facility has a capacity to export 6.9 Mtpy of LNG, amounting to a total of 9 Tcf of

NG over a period of 30 years145

. An economic analysis of the project has been carried out

assuming a mid-price of USD 9.35 per million Btu.

10.2 Supply and demand of gas in Asia

In Asia, natural gas has been traded in the past under long-term contracts, with gas prices

linked to crude oil prices with some discount. Asia's natural gas markets are much less

integrated than those in Europe and North America, with fewer pipelines, which are governed

by a number of different countries and regulations. However, there have been some recent

changes in Asian markets. Asian buyers have gained more destination flexibility, and the

volumes of LNG bought and sold on the spot market under short-term contracts have

increased. Asian buyers have signed contracts to buy LNG from the United States, at prices

linked to the Henry Hub price rather than to oil prices. At the same time, s-curves (contract

terms that limit the price to what the seller demands and what the buyer can afford to pay)

have been virtually eliminated from contracts in Asia since 2008, helping to sustain prices

well above those in both North America and Europe. According to US Energy Information

Administration (EIA), the global trade in NG is projected to grow at a higher rate among non-

OECD countries than among OECD countries, as seen in Fig. 71.

Fig. 71. Forecasted global NG trade in OECD and non-OECD countries146


101

The U.S. EIA projects that over the 2010-2040 period, the total natural gas consumption of all

the OECD-member nations in Asia will increase from 6.7 to 9.9 trillion cubic feet (Tcf) per

year. However, even stronger consumption growth is expected to occur in those Asian nations

that are not members of the OECD including China and India, The EIA projects that natural

gas consumption in these countries will increase from 14 to 36 Tcf per year over the 2010-

2040 period, as shown in Fig. 72. This is an average growth rate of 3.3% per year.

Fig. 72. Forecasted NG consumption in non-OECD Asia up to 2040147

Forecasts from Japan's Institute of Energy Economics (IEEJ) suggest that Asia's LNG demand

will increase from 180 million tonnes/year (tpy) in 2013 to 360 million tpy by 2040. As of

early 2014, DOE had issued permits for five potential US LNG export projects, with total

capacities equivalent to 65-70 Mtpy that could come on line between 2015 and 2025. Asia's

oil-linked, spot LNG prices in were USD 16-17/million Btu, which is well above Europe's

USD 9-11/million Btu and US Henry Hub's USD 4.50/million Btu. With liquefaction and

transportation cost estimated to cost roughly USD 6/million Btu to supply LNG from USA to

Asia, US gas at current prices would be highly competitive in Asia's market, according to a

gas market analyst148

. According to this analysis, an increase in the US price of natural gas

and of a decline in the price of LNG in Asia toward USD 12-13/million Btu could be expected

as new supplies emerge from Australia, Russia, the US, Canada, and offshore East Africa.

Another oil and gas analyst at Global Data, expects a large boom in LNG exports from

Australia and projects that Australia will overtake Qatar and become the world's primary

liquefied natural gas (LNG) exporter by the end of the decade. These exports will be arriving

at Asian-Pacific markets which are in great need for energy, especially LNG. The Asian LNG

demand is expected to rise by 165% to 370 million tpy from 2010 to 2025149

. In Japan

specifically, all 48 nuclear reactors were shut down because of the Fukushima crisis, and as a

result Japan is compelled to make their LNG purchases in the spot market at very high prices,

more than double the prices elsewhere.

The demand for NG and its spot price will depend on the season as well. For example, the spot

prices in Japan which were in the range USD 18-19/million Btu during 2013 winter has dropped

to about USD 12/million Btu in Spring 2014 according to a news report150

. According to a more


102

recent report, spot prices of LNG for delivery in September 2014 to Far East has dropped further

to USD 10.70 per million Btu151

. According to the latest report by Reuter152

, however, the spot

price of LNG in Asia has started its seasonal climb reaching USD 14.80/million Btu in early

September, a gain of 41 percent from the three-year low of USD 10.50 reached in July.

10.3 Developing a gas hub in Asia

Recent increases in natural gas supplies have provided an opportunity for the development of

competitive natural gas markets, and global development of shale gas could hasten the advent

of competitive pricing regimes around the world. Regulated natural gas prices and prices

linked to oil are gradually giving way to competitive natural gas pricing, as seen first in North

America and then in the United Kingdom. As regional Asian trade and consumption of LNG

and natural gas increase, it is virtually inevitable that a natural gas hub will also develop in

Asia, even if it is not currently apparent how or where. China, Japan, and Singapore have

expressed interest in developing such a hub153

.

In the meantime, Singapore has been developing its capacity to serve as an LNG hub by

building capacity to import LNG (on long-term contract), store as LNG, reload LNG to

carriers and export at spot market rate on demand. Already a facility, built at a cost of USD 1

billion (approx.) to trade 3.5 Mtpy annually, is in operation since May 2013154

. An extension

with capacity up to 6 Mtpy is being built, which will be expanded to handle 9 Mtpy of LNG

trade annually155

. Considering the wide difference between the prices on long-term contracts

and spot market prices, the return would easily cover the heavy investment on the project.

In view of the anticipated increasing demand for LNG in the Far East, LNG suppliers in the

West are considering setting up of LNG storage facilities in South East Asia156

. Since, Sri

Lanka is close to the international shipping routes, Sri Lanka could offer its port and other

infrastructure facilities to establish a LNG storage system in Southern Sri Lanka. A proposal

for establishing an energy hub in Trincomalee for importing LNG and supplying gas to India

through a pipeline was submitted by Ratnasiri in June 2010 to authorities including the

Central Bank and the Ministry of Power and Energy, but not pursued157

. Coincidentally,

Singapore commenced work on their LNG hub in June 2010.

Natural gas has accounted for about 10% of India's overall energy consumption in 2012. India's

NG consumption averages 2.0% annual growth from 2010 to 2040, which is lower than for all

other energy sources except coal and is only one-fifth of the 10.0% annual growth rate for nuclear

energy consumption during the period. This results largely from supply constraints, including

continued obstacles to reaching agreement on the construction of three pipelines that India was

planning for years to secure NG from Iran, Turkmenistan, and Myanmar which failed to

materialize so far. In India, due to non-availability of gas, almost 35% of the power plant capacity

remains unutilized and these plants then need to resort to naphtha as a substitute fuel which is

excessively costly. Some of the power plants, which were planned and are in the process of being

commissioned face the problem of non-availability of gas158

.


103

A study on Prospects for LNG Imports to India undertaken by a private research team has

found that in the next few years, the outlook for the supply–demand balance in the

international LNG market in Asia is expected to become increasingly tight, in which case

India will have to be willing to pay higher prices to secure additional LNG cargoes. Over the

longer term, there is sufficient potential in the Middle East and the Asia Pacific, including

Australia, to bring LNG to India159

. It therefore appears that the market for NG will exist in

India for decades to come. This would provide an opportunity to capture this potential market

if Sri Lanka finds new gas discoveries as it would appear that the demand for LNG in Asia

would surpass the supply in the future.

10.4 Infrastructure development for NG export

In order to consider export of NG, a minimum feed gas deposit of 1 Tcf is required which

could produce 0.8 Mtpy of LNG for 20 years. This is generally considered as the smallest size

accepted for export. Hence, a production rate of 5 Mtpy of LNG will require a gas-field size

of approximately 6 Tcf. If such a field is located, two options are available for its export; one

is to dispatch gas through a pipeline to India, and the other is to convert the gas into LNG and

offer it in the spot market which fetches a high price.

The shortest path for a pipeline from the NW coast of Sri Lanka to India will have to cross the

Gulf of Mannar. However, this region has been declared as a Marine National Park by the

Tamil Nadu State Government and laying a pipeline across it could have adverse impacts. It is

one of the world’s richest regions from marine bio-diversity perspective and the first marine

Biosphere Reserve in Southeast Asia. The Biosphere Reserve comprises 21 islands with

estuaries, mudflats, beaches, forests of the near shore environment, including marine

components like algal communities, sea grasses, coral reefs, salt marshes and mangroves160.

Hence, the pipeline may have to be taken to the Northern tip of the country overland

bypassing the sanctuary and cross the Palk Strait to India.

The export of LNG in the conventional manner requires building a liquefaction plant and

loading the cryogenic liquid into LNG carriers for which a deep jetty with minimum depth of 16 m is required. The sea off Sri Lanka’s NW coast is rather shallow and hence is not the best

location for building an LNG terminal. Hence, a pipeline will have to be laid from the NW

coast to Trincomalee where the deep harbour can easily accommodate a terminal. However, if

gas is discovered off the Eastern coast in sufficient quantities, it will facilitate exporting

liquefied gas from Trincomalee.

The construction of a liquefaction plant and the terminal as well as its management could be

assigned to an investor as a BOT project without the government incurring any expenditure on

building the necessary infrastructure. Fig. 73 shows the possible location of the liquefaction

plant at the Trincomalee Harbour where the sea is deep.

The National Physical Planning Department has developed the NPP for 2030 in which it has

been proposed that the future metropolis be built enclosing Trincomalee – Anuradhapura –


104

Polonnaruwa – Dambulla quadrangle. Many industries are also expected to be built within this

area. Hence, the proposed pipeline will also assist in bringing NG to the region to meet its

increasing energy demand as well.

LNG Plant

Fig. 73. Possible location of liquefaction plant at Trincomalee Harbour

The gas production cost typically varies from USD 0.25/million Btu to more than USD

1.0/million Btu. A production cost of less than USD 1.0/million Btu is desirable to make the

LNG option economically feasible. The contribution of the liquefaction plant cost to the cost

of delivery of LNG ranges from USD 1.5 to 2.0/million Btu. The cost of the liquefaction plant

is a significant component of the cost of the LNG chain; hence, cost reduction of the

liquefaction facility is an important issue.

The fleet of tankers for an LNG project is a significant portion of the total cost of the LNG

chain. The number of ships and, hence, the cost of shipping is dependent on the distance

between the liquefaction facility and the market. A typical contribution of the shipping cost to

the cost of delivered LNG is approximately USD 0.5 to 1.2/million Btu. The receiving

terminals with tanks, vaporization equipment, and utilities contribute approximately USD 0.3

to 0.4/million Btu to the delivered price of LNG.

The cost of a liquefaction plant was in the range USD 200-250 per Mtpy up to about 2010161

.

Liquefying the gas, carrying it to its destination and re-gasifying it can cost between USD 4

and 7/million Btu, a lot more than the USD 2.50/million Btu that the gas itself currently sells

in America. Building a liquefaction facility is highly capital-intensive. Chevron’s Wheatstone

LNG project in Australia, approved last September, will cost AD 29 billion (USD 30 billion)

for a capacity of 8.9 Mtpy, more than a quarter of the country’s total gas production162

. One

of the new-comers to LNG suppliers among the IOR countries is Mozambique, where more

than USD 30 billion has been invested to build the liquefaction facility to produce 20 Mtpy of

LNG, with the first exports due to start in 2018163

. Around 180 Tcf of gas has been found in

Mozambique’s offshore Rovuma Basin, enough to supply Germany, Britain, France and Italy

for 18 years.


105

10.5 Providing LNG bunkering facilities

An emerging trend in the shipping industry is to operate vessels with LNG, mainly driven by

environmental concerns and requirements to reduce emissions. One impediment against its

growth is the paucity of ports providing LNG bunkering facilities. According to Wärtsilä, “the

regulations imposed by international shipping authorities such as International Maritime

Organization (IMO) require all international vessels to reduce emissions including NOx and

SOx so that the use of cheap high sulphur fuel oil as a fuel for shipping will have to be phased

out and use expensive 0.5%S diesel oil unless expensive emission control equipment are

installed.

The only other viable option is the use of LNG for shipping operation. Those keen to use LNG as

a fuel are waiting for the supply infrastructure to improve and those tackling LNG bunkering

provision are citing a lack of demand as limiting progress, and as a solution to this impass new

LNG bunkering stations are being championed across northern Europe”164

. Nevertheless,

global ports expect to see LNG account for 13% of the bunker fuel market supply by 2020

and 24% by 2025, according to a Lloyd's Register report Monday165

.

Recently, Singapore has been developing LNG storage facilities and jetties for berthing LNG

carriers with a view to supplying LNG on spot market to countries in the Far East where there is a

heavy demand for LNG. With the availability of LNG storage facilities, Singapore has pioneered

the provision of LNG bunkering facilities in Singapore Port. In order to attract vessels for

bunkering, Singapore Port has completed an LNG bunkering Technical Standards and

Procedures study with Lloyd’s Register166

.

Bunkering facilities for LNG would require provision for berthing of LNG operated vessels

alonside the jetty where the LNG tanks are built and for transfering LNG from the storage tanks to

the vessels. Additional storage tanks will have to be built to cater to ships than what is planned for

internal use. Since the main international shipping route lies close to Sri Lanka’s southern coast,

Hambantota could serve as a convenient bunkering port for ships that operate on LNG.

There are two options for supplying the necessary LNG for bunkering. One is to source it

from domestically extracted gas and the other is to source it from imports. Naturally, the

economies of scale, local production rates and trends in pricing of LNG in inernational spot

and long-term markets would determine the best option. In the event adeqaute supplies could

be sourced from local sources, it is necessary to take the gas to Hambantota from

Kerawalapitiya where the Central Storage Terminal (CST) is expected to be built.

Though in the long term a pipeline may appear a better option, particularly because of the

existence of the expressway from K’pitiya to H’tota, as an interim measure until a proper

market and the necessary infrastructure are developed, it may be possible to transport the gas

to Hambantota by making use of newly developed LNG containers. This requires building a

liquefaction plant at Kerawalapitiya, which are available today at competetitive prices as

discussed earlier. The fleet of containers acquired for this purpose could be deployed for

transport LNG to other areas once the pipeline is laid after establishing its viability.


106

The Port of Singapore has recorded bunker sales of 42,700 kt in 2012, out of which 33,685 kt

has been for furnace oil. On the other hand, Sri Lanka’s bunkering volume in 2012 has been

only 217 kt of furnace oil and 54 kt of marine gas oil. It is therefore assumed that initially

commencing from 2023, 10% of the total demand for bunkering or 27 kt equivalent will be

met from LNG. Necessary storage and LNG loading facilities will have to be developed

within the port area. This amount could be expanded at 10% annually depending on the

supply and demand for LNG. The success of bunkering facilities at Hambantota will depend

not only on the availability of LNG at a competitive price but also on other facilities that

Hambantota could offer to vessels calling for services.


107

11. Alternative sourcing of natural gas

Many countries having their own NG resources such as USA, China and India resort to

importing NG in the form of LNG for various reasons; economic, diversity of supplies,

meeting shortfall of production etc. Even if adequate supplies of NG may be available from

local sources within foreseable future, it may be necessary to consider opportunities for

importing NG in the event the government policies and market forces favour such importing.

11.1 Previous attempts to import LNG

Several unsolicited proposals had been submitted by various parties (eg. Enron, Shell) to the

government during the last two decades for importing LNG, but were not given serious

consideration. The import of LNG requires building special terminals costing several

hundreds of millions of dollars and such terminals are viable only if there is a throughput of at

least 1 Mtpy of gas sufficient to operate a 1000 MW power plant. Since the country did not

have this amount of demand in the past, these proposals did not receive the support of the

electricity utility.

In late 2002, the government called for expressions of interest (EOI) through press notices for

building a power plant of capacity 3x300 MW giving gas as one option. Later it was cancelled

and fresh proposals were called for power plants operating only on coal. However, the matter

was not pursued even for a coal plant as a follow up to the call for EOI despite the fact that

potential investors had to incur heavy expenditure for visiting the sites and preparing the

proposals.

In 2006, the government on a Cabinet decision decided to accept an offer from the Government of

Iran to build a LNG terminal and a 300 MW NG power plant at Mirissa, one of the few locations

where the sea is deep near the shore167

. There had been even an exchage of delegations at

ministerial level but the project could not be pursued in view of the economic sanctions imposed

by UN against Iran. Though in possession of the second largest conventional NG deposit in the

world after Russia, Iran is unable to get the technology to liquefy the gas and export to other

countries in view of the sanctions imposed by USA led UN. More recently, prospective investors

had submitted proposals to make use of Hambantota harbour to import LNG for power and other

applications, but there had been no firm commitments expressed.

11.2 Terminals for importing LNG

Generally, LNG is transported across oceans in purposely built carriers (see Fig. 3). Special deep

(minimum 16 m depth) jetties are required to berth LNG carriers and transfer the LNG to storage

tanks built on-shore, from where it is re-gasified and distributed to consumers. Such transfer of

LNG takes place through rigid pipes (appropriately articulated) connecting the carrier with the

storage tank on the jetty; hence the need to berth the carrier alongside the jetty. The construction

of terminals involve dredging, building cryogenic storage tanks, re-gassing facilities and gas

storage tanks, and these are expensive exercises. A terminal planned to be built in Shanghai with

capacity of about 3.0 Mtpy is estimated to cost in the range USD 900


108

million168

. However, this is not an additional burden because the cost of the terminal could be

easily met from the savings earned by building a NG fired CCGT power plant in place of a

coal power plant, which is the option if there is no gas.

According to Table 28 giving the levelized cost of generating electricity, a 300 MW coal plant

will cost USD 497 million while a similar capacity NG fired CCGT plant will cost only USD

250 million, with a difference of USD 247 million. If the terminal is planned for a throughput

for a 900 MW plant capacity, the saving on the plant capital will be USD 741 which is more

than adequate to build a medium size LNG terminal and other infrastructure necessary.

11.3 Sites for setting up LNG terminals

Sri Lanka has two locations suitable for setting up terminals for importing LNG – the natural

deep harbour at Trincomalee and the newly-built inland harbour at Hambantota (Fig. 74).

While Trincomalee harbour may require some infrastructure development to bring LNG

carriers close to the jetty, at Hambantota such facilities are already in place with deep jetties

available for berthing LNG carriers. In the event the government decides to export NG as

discussed in Section 10.4, facilities will have to be built for liquefying NG for exporting.

Fig. 74. View of Hambantota Harbour

The cryogenic LNG storage tanks need to be built on the jetty enabling transfer of LNG direct

from the carrier to the tank using insulated pipelines in the form of an arm, extending from the

carrier to the tank. Close to the LNG storage tank a gasification unit needs to be built from

where the liquid is gasified by bringing it to ambient temperature under a controlled heat

exchanging system. Gas storage tanks are necessary to hold the gas in transit.

The most economical way of utilizing the gasified LNG is to build facilities that may

consume NG in substantial quantities in close proximity to the terminal. Such facilities may

include a gas-fired combined cycle gas turbine (CCGT) power plant, a fertilizer (urea) plant

and other chemical plants that may require natural gas as feed stock. Building a CCGT power

plant close to the LNG re-gasification unit has the advantage that air drawn to the power plant

could be pre-cooled by passing it through the heat exchanger which will enhance the

efficiency of the power plant.


109

12. Policy interventions and Plan of Action 12.1 Policy interventions

The government will have to make several policy interventions enabling a NG-based industry

to develop. Among the key issues to be considered are the following:

The supply of natural gas which is a potentially hazardeous substance into the country, its

distribtion by pipelines, storing in large outdoor tanks either in compressed state at high

pressure or in liquid state at vey low temperature, and their transport in mobile containers

across the country need strict regulation and monitoring.

The use of NG as a transport fuel needs to be incorporated into the Motor Traffic Act, and

appropriate regulations need to be brought in to regulate its distribution through

dispensing units along highways.

A decision needs to be taken to limit the import of new vehicles to those operating on

CNG/LNG once facilities for filling vehicles with these fuels are established by providing

tax incentives and duty concessions.

The distribution of gas through a local network of pipelines and feeder points served by

LNG containers at every township and granting licenses to parties to operate such

facilities need to be regulated and monitored by an appropriate authority. Every person

involved in the management of the distribution network needs to be properly trained.

Personnel engaged in the distribution of NG by pipelines or by containers need to be

properly trained in handling emergency situations and made aware of the hazardous nature

of gas. Every local authority responsible for fire control needs to be informed about the

intoduction of NG into their area of service.

The laying of pipelines in the sea and bringing it to the shore and thereafter to a storage point

would need the approaval and monitoring by several organizations among which are:

o Marine Environment Pollution Authority (MEPA)

o Central Environmental Authority (CEA)

o Coast Conservation and Development Department (CCDA)

o Environmental Authority of the NW Provincial Council o Divisional Secretary of the relevant DS Division.

It is a mandatory requirement to get an environment impact assessment (EIA) study

conducted on the above operations and seek approval of the relevant project approving

authority after submitting the same for public comments.


110

The Minstry of Finance will have to decide on incentives in terms of duty concessions and

other tax rebates to be granted to investors who would invest on building local pipeline

networks, CNG/LNG dispensing units along highways to serve motor vehicles operating on

such fuel, and in other applications in order to accelearte the penetration of the use of NG.

The Ministry of Finances will have to decide on any taxes and levies to be imposed on the

sale of CNG/LNG as well as piped NG in such a way as to develop the industry during its

nascent peiod.

A portion of the revenue collected from such taxes and levies should be set apart to

establish and operate a research and development (R&D) unit within the authority

handling the import and distribution of natural gas.

The relevant authority will have to conduct an aggressive awareness campaign to educate

the public on the benefits and advantages of shifting to NG as a fuel for energy generation,

transport and household cooking and heating, and also on the risks involved and the need

to take safety measures.

12.2 Plan of Action

The action plan proposed for the implementation of the NG phase-in programme is given in Table 37.

Table 37. Proposed Action Plan for introducing NG in Sri Lanka

Target Task Description of Tasks Action by

Seek approval of the Cabinet of Ministers for PRDS,

November

1

introducing NG as a new source of energy in all sectors Presidential

2014 and as feedstock for industry, its distribution via a Secretariat

network of pipelines and container trucks

Obtain clearance from the relevant authorities for laying MEPA,

March 2 the sub-sea pipeline and a land pipeline from the M/F&AR,

2015 Kalpitiya Peninsula to K’pitiya and acquisition of CEA &

necessary land for building the proposed infrastructure NWPC

Conduct a detailed feasibility study for building:

3 the proposed receiving terminal including a

June 2015 purification and compression plant (PCP) at the PRDS point of landfall in the Kalpitiya Peninsula,

4 the proposed pipeline from the receiving terminal to

the central storage terminal (CST) at K’pitiya,

possibly along the railway line reservation

December 5 Conduct an EIA study and submit the same to the PRDS,

2015 project approving authority after obtaining public CEA

comments


111

June 6 Complete the design work and acquisition of land for PRDS

2016 constructing the PCP, CST and the pipelines from CST

and to Kelanitissa power plant site.

Award the tenders for:

December 7 executing the civil engineering work after calling for

2016 competitive quotations from reputed contractors and

PRDS 8 purchase of equipment for the PCP and CST, including purification and compression equipment,

safety equipment including leak monitoring &

alerting systems and fire-fighting equipment

December 9 Complete building the PCP, CST and the pipelines PRDS

2017

10 Install the necessary plant and machinery in the PCP PRDS

June and CST, conduct tests and performance evaluation of

2018 the equipment and the pipeline and obtain certification

by an accredited agency.

October 11 Launch a public awareness campaign on the benefits of PRDS

2018 using gas and safety aspects

October 12 Supply gas to the PCP and inaugurate the project. PRDS

2018

12.3 Time frames for executing the plan

The implementation of the above action plan requires the time frame given below to be followed. The proposed time frame is given in Fig. 75.

Task 2014 2015 2016 2017 2018

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

1

2

3

4

5

6

7

8

9

10

11

12

Fig. 75. Proposed time frame for implementing the Action Plan


112

This means that if the gas is available at the well head in mid-2018, work needs to be

commenced immediately to the get the necessary clearances, approvals, designs and award of

contracts for building the pipeline and storage facility and have them constructed ready to

receive gas in the second half of 2018. The main responsibility for facilitating these tasks rests

on the PRDS.


113

13. Conclusion and recommendations

13.1 Key findings

Natural gas has the potential to replace the currently used fossil fuels which amounts to the

equivalent of 222 PJ in 2014 (Table 13). The demand for petroleum fuel is expected to grow up to

about 393 PJ in 2020, 700 PJ in 2030, and 1,200 PJ in 2040. However, due to limitations in the

NG production, which is 70 Mcf/d at the commencement of the project, the phase-in of NG will

have to be done in stages. Beginning 2018 when commercial production begins, it is proposed to

operate the 3 existing CCGT power plants with NG which would require 93 Mcf/d of NG for

optimum operation. Phasing-in of NG in different sectors will be staggered to match the

availability, beginning from power sector in 2018, transport and industrial sectors in 2023 and

household and commercial sector in 2026. The manufacture of urea and other NG-based products

such as ammonium sulphate, DME, methanol and ethanol from NG will commence in 2015. The

demand for NG in each of these sectors is given in Table 31 and replicated below.

Phasing-in of NG will be carried out first in the power sector under two scenarios, one after

building Sampur coal power plant (NG1) and the other before (NG2). Under NG1 scenario,

demand for NG will be 93 Mcf/d in 2018, 316 Mcf/d in 2025, 501 Mcf/d in 2030 and 846 Mcf/d

in 2040. Under NG2 scenario, the corrresponding demands will be 122, 419, 604 and 949 Mcf/d,

respectively. For the implementation of the Sceanrio NG2, if adequate supplies of NG is not going

to be available domestically, LNG could be imported on a fast track basis as described in Ch. 11,

possibly making use of the new technology of transporting LNG in containers.

It is proposed to introduce NG for the transport sector in 2023 when NG production is expected to

increase to 210 Mcf/d, by providing facilities to supply both CNG and LNG for operating vehicles

on these fuels. The demand under NG1 scenario will be 10, 125 and 530 Mcf/d in 2023, 2030 and

2040, respectively. The corrponding figures under NG2 scenario will be 20, 249 and 1059 Mcf/d,

respectively. It is expected that once the infrastructure to supply these fuels are made available,

imports will be limited only to these vehicles, by providing some incentives for their purchase. It

is hoped that luxury buses and heavy vehicles operating on long distance routes will operate on

LNG while new light vehicles will be encouraged to operate on CNG. Facilities for converting

existing vehicles for CNG operation will be provided with duty concessions for the import of the

necessary accessories. The operation of NG dispensing outlets for vehicles is expected to be

undertaken by licensed operators in the private sector.

The demand for industrial and household sectors is very much less than those in the transport

and power sectors. Nevertheless, facilities will be provided to supply NG through local

pipeline networks served by LNG bulk containers. The demand in the HH&C sector for NG

under NG1 scenario is estimated to be 2, 15 and 89 Mcf/d in 2026, 2030 and 2040,

respectively. The corresponding figures under NG2 scenario will be 4, 23 and 134 Mcf/d,

respecively. It is planned to phase-in NG in the industrial sector by replacing partly the use of

fuel oil and LPG for thermal applications beginning 2023 with a consumption of 1, 9 and 26

Mcf/d in 2023, 2030 and 2040, respectively under NG1 scenario. The corresponding figures

under NG2 scenario will be 2, 18 and 36 Mcf/d, respectively.


114

In non-energy applications, NG will be used as a feedstock in the manufacture of urea and

several other products based on NG as described in Section 5.6. Urea is a fertilizer which is in

high demand in the country. It is proposed to initially manufacture 1 Mt of urea annually

commencing 2025, and increase the production to 1.25 Mt in 2030 and to 1.5 Mt in 2035

under NG1 scenario. The manufacture of another fertilizer – Ammonium Sulphate (AMS)

will be undertaken commencing with a capacity of 100 kt annually from 2025, increasing it to

125 kt in 2030 and to 150 kt in 2035. In addition, the manufacture of DME will be undertaken

with a similar production rate. The three industries will require annually 81, 101 and 121

Mcf/d of NG in 2025, 2030 and 2035, respectively.

Under NG2 scenario, new industries to manufacture methanol and ethanol will be commenced

in 2025, beginning with a capacity of 1.0 Mt annually for methanol and 100 kt of ethanol.

These will be increased to 1.5 Mt and 150 kt, in 2030 and 2035, respectively. The

corresponding demand for NG for all five industries in 2025, 2030 and 2035 will then be 194,

271 and 347 Mcf/d, respectively. It is expected that the production will be used partly in local

industrie and partly to export. It is expected that once NG is available, new NG-based

industries will lead to emergence of a NG-based chemical industry, manufacturing a range of

products that are currently being imported.

The phasing-in of NG into various sectors will result in creating a demand of 93 Mcf/d in

2018 under NG1 scenario which will increase to a demand of 1,609 Mcf/d in 2040. In order to

supply NG at this rate over a period of 22 years up to 2040, the NG deposit needs to have a

capacity of 6 Tcf. In the case of NG2 scenario, the demand for NG will increase from 122

Mcf/d in 2018 to 2525 Mcf/d in 2040, with a corresponding deposit of 10 Tcf to supply NG at

the specified rate over a period of 22 years.

The phasing-in of NG will result in the reduction of emission of polluting gases SO2, NOx and

TSP as well as Greenhouse Gases including CO2, CH4 and N2O. The reduction of polluting

gas emissions will reduce the burden on the country’s health sector in treating patients seeking

treatment for respiratory ailments caused by inhaling these polluting gases and suspended

particulates. These emissions were computed for fuels consumed in all sectors.

In 2040 under BAU conditions, SO2 emission will be 359 kt, NO2 emissions will be 283 kt,

TSP emissions will be 22 kt and CO2 emissions will be 103 Mt. The NG phasing-in in 2040

under NG1 scenario will result in reducing these to 112 kt, 195 kt, 6 kt and 74 Mt,

respectively.The NG phasing-in in 2040 under NG2 scenario will result in reducing these to

46 kt, 154 kt, 3 kt and 65 Mt, respectively (see Table 33).

With the anticipated prices of NG offered to the government – USD 15, 10 and 5 per million Btu,

there is potential to save billions of rupees in phasing-out petroleum oil and even coal in the

power sector. The total expenditure on fuel in the power sector in 2040 under BAU scenario is

estimated to be USD 11.5 billion, while it is USD 4.6 billion under NG1 scenario and USD 3.4

billion under NG2 scenario. Similalry, in the transport sector and in the manufacture of urea,

similar savings could result in phasing in NG. In particular, operation of power plants with NG


115

is preferred even if the cost of externalities are not considered, in view of the escalating costs

of coal in the future. There is potential to save billions of rupees by manufacturing urea and

other products from NG instead of importing them as done presently.

There are many other benefits the country could acrue as a result of switching to NG among

which are: energy security, food security, improved balance of payment, clean air, unpolluted

water, free of coal ash dumps with toxic metals and redionuclides, meeting international

obligations etc. Opportunities for exporting NG and also products manufactured with NG in

the event there is surplus as well as possibilities for importing gas if there is a shortfall are

also considered. The possibility of providing bunkering facilities for LNG vessels at

Hambantota is also considered.

13.2 Recommendations

In view of the many aspects in which the country would benefit by utilizing natural gas discovered, the following recommendations are made for early execution of the project. As shown in the time frame chart, prompt action is needed to meet the 2018 target of its delivery.

Initiate action promptly to seek the approval of the government for the project and clearance from authorities highlighting both the benefits and the risks.

Finalize the strategy for bringing in gas to the city either in a pipeline laid along the railway reservation or in a sub-sea pipeline laid off-shore along the coast.

Initiate action to acquire necessary land at Kalpitiya Peninsula for building the PCP, Railway Department for laying the pipeline from Puttalam to Kandana.

Alternatively, seek approval of the Coast Conservation and Development Department for laying sub-sea pipeline along the coast from Norochchole to Kerawalapitiya.

Acquire necessary land at Kerawalapitiya for building the CST and for laying pipeline from CST to Kelanitissa and to Kerawalapitiya CCGT plant.

Undertake a detailed feasibility study for the project including designing of the necessary infrastructure and initiate action to award the contracts to reputed contractors to execute the civil works.

Purchase the necessary plant and machinery including safety equipment for the PCP, CST and the pipelines from reputed suppliers after calling competitive bids and get them installed within the time frame given.

Finalize the agreement with the 3 CCGT power plant operators for the purchase of gas once gas is made available.

Seek approval of the government for the policy interventions outlined earlier.


116

Appendix A

Socio-economic scenario

The utilization of NG in the country requires an understanding of the country’s socio-

economic situation which is described below.

A.1 The land

Sri Lanka is an island nation in the Indian Ocean located about 80 km southeast of the Indian

Subcontinent lying on the same continental shelf as India. In addition to the mainland, the

country has 113 small islands, lying close to the Northern Peninsula and Kalpitiya Peninsula.

Nearly half of them are below 100 ha in extent and only six are over 1000 ha with the largest

having an extent of 12,600 ha169

.

The mainland has a maximum length of 435 km in N-S direction and maximum width of 240

km in E-W direction and lies within the co-ordinates 5o 55’ N & 9

o 50’N; 79

o 42’ E & 81

o

53’ E. It covers a total area of 65,610 km2, including 62,705 km

2 of land area and 2,905 km

of inland water bodies170

. On the basis of elevation and salient landforms, the country is

divided into the following main topographical regions, as shown in Fig. A1.

• The central highlands • The southwest (SW) lowlands • The east and southeast (SE) lowlands • The northern and north-central (NC) lowlands • The coastal fringe

The coastal fringe, according to the latest version of the Coastal Zone Management Plan –

2004171

published in 2006, is the land bordering the coast extending up to 30 m contour172

.

The shoreline extends 1,620 km including the shorelines of bays and inlets, but excluding

lagoons173

. The SW lowlands receive high annual rainfall and is the home for the majority of

people. Several major rivers flow to the sea over the SW lowland which during periods of

heavy rain are subject to floods.

The conspicuous topography of the SW lowlands is the elongated parallel ridges running in

the north-south direction, which are cut by the rivers flowing east to west originating from the

central highlands. The east and SE lowlands comprise undulating plains with isolated hills

with flat tops. The NC lowlands are somewhat similar to those in the east. The land over most

of the country, other than the central highlands, is almost flat undulating with gentle slopes.

The NC and Eastern lowlands have the highest agricultural productivity in view of the high

solar insolation over this land.

The central highland is the source of many waterways comprising a very fragile ecosystem where

landslides occur whenever heavy rainfall is received. The country has 14 peaks above 2,000 m

elevation with Pidurutalagala the highest with 2,524 m elevation. However, it does not originate a

single waterway whereas two of the country’s major rivers, Kelani Ganga (145 km)


117

and Kalu Ganga (129 km) originate from the Adam’s Peak (2,243 m), the 5th

highest peak,

and two more, Mahaweli Ganga (335 km) and Walawe Ganga (138 km), from its vicinity.

Fig. A1. The relief map of Sri Lanka

A.2 Maritime waters

Sri Lanka has sovereign rights to a total extent of approximately 517,000 km2 of maritime

waters. This consists of Historic waters (extending up to the maritime boundary between Sri

Lanka and India in the northwest and north), Internal Waters lying landwards beyond the

semi-circles at bays and lagoons, Territorial sea (extending up to 12 nautical miles except in

the north and northwest), Contiguous zone (extending up to 12 km from the territorial sea)

and the Exclusive Economic Zone (EEZ) (extending up to 200 nautical miles except where

intercepted by the Indo-Sri Lanka maritime boundary) and excluding historic waters, as

shown in Table A1 and Fig. A2.

Table A1. Maritime waters of Sri Lanka174

,175

Description Extent km2

Reference

Internal waters 1,570 174

Historic waters 12,060 174

Contiguous waters 19,620 174

Territorial waters 21,500 175

Exclusive Economic Zone 517,000 175


118

Within the EEZ, Sri Lanka has sovereign rights to all living and non-living resources lying in

waters or the sea bed or the sub-soil and to conduct any activity for the exploration of these

resources. Its continental shelf is rather narrow having a width of only about 20 km and a

depth of only 70 m, except in the north and northeast where it merges with India’s. The

continental shelf covers 26,000 km2 or little less than half the land area of the country.

Beyond this shelf, the sea bed drops to more than 900 m within 3 km. Gulf of Mannar where

oil exploration was carried out is a rather shallow area.

Fig. A2. Maritime boundaries of Sri Lanka176

Sri Lanka has filed a claim with the UN for ownership of an extended oceanic area based on

the depth of sediment present around the country, in terms of provisions in the United Nations

Convention on the Law of the Sea (UNCLOS). Investigations carried out using seismic

surveys and satellite gravity anomalies have revealed that Sri Lanka can claim seabed rights

over a considerable wide area of approximately 1.4 million km2. Its southern margin lies

about 800 km from the coast extending beyond the equator as shown in Fig. A3.

Sri Lanka has conducted extensive explorations for hydro-carbon resources in the Gulf of

Mannar commencing in the sixties. The government has announced the discovery of natural

gas deposits though the actual extents are yet to be determined. Several more blocks have

been identified as potential sources of oil and gas, but contracts for their explorations are yet

to be awarded. The current study has been undertaken with a view to determine the

advantages - technically, economically and environmentally - of utilizing the gas discovered

enabling the policy makers to take a decision regarding whether to pursue the explorations or

discontinue. Fig. A4 shows the area where explorations have been conducted. Though several

blocks have been identified as possible sources of hydrocarbons, so far explorations have been

conducted only in one block.


119

Fig. A3. Extended EEZ claimed by Sri Lanka177

Fig. A4. Area where hydro-carbon deposits were found178

A.3 Country’s waterways

Sri Lanka has 103 rivers, most of which flow in radial directions from the central highlands (except for the Mahaweli Ganga). Their catchments vary from a few tens of square kilometers

to over 10,000 km2. There are 17 river basins with more than 1,000 km

2 in extent with the

highest a little over 10,000 km2, that of the Mahaweli Ganga, the country’s longest river.

Their distribution may be classified as follows179

.

• 07 major rivers have catchments above 2,000 km2,

• 21 rivers have catchments between 500 and 2,000 km2,

• 32 rivers have catchments between 100 and 500 km2,

• The balance (43) rivers have catchments below 100 km2.


120

The Mahaweli Ganga, the longest river in the country discharges an annual mean run-off of

nearly 9,000 Mm3, which is approximately 20% of the total run-off of all rivers. These rivers

carry large amounts of sand and silt essential for beach nourishment. Some of the larger rivers

are subject to frequent flooding when intense rainfall occurs, particularly in areas subject to

south-western monsoonal activity. Only the few major rivers maintain a flow during the entire

year, while the rest demonstrate a highly seasonal flow, corresponding to the seasonal

variability of rainfall.

The central highlands rising to a height of more than 2,000 m is the source of many of the

rivers in the country. However, there has been a regular decline in the forest cover in the

highlands due to their conversion into plantations and agricultural activities and this has

resulted both in the incidence of flash floods during heavy rainfall and in the increase of the

sediment load in the down-streams. In built up areas, industrialists and the public in general

have been dumping solid and liquid waste into waterways which finally end up in rivers.

Though the government commenced a “Clean Rivers” programme sometime back to

minimize such river pollution, it does not appear to be very effective.

Mining of sand is an economic activity that is carried out intensively in major rivers causing

much environmental damage. Though the activity is regulated through a permit scheme, over

exploitation is carried out to meet the high demand for sand in the construction industry

sometimes violating the regulations. It has been estimated that sand mined from rivers in the

Western Province was about 6 million cubic metres (Mcm) in 2001 and is expected to

increase up to 12 Mcm by 2006180

.

In addition to the natural waterways, many man-made waterways are found in the country,

particularly in the North-Central Province (NCP) where irrigation canals had been built many

centuries ago to carry water collected in man-made reservoirs to farming areas. This canal

system was expanded a few decades ago with the diversion of the country’s main river Mahaweli Ganga to take its water to the water-deficient NCP. A network of canals is also

found in the Western Province built by the Dutch to transport goods and timber across river

basins. These canals have also helped in draining out storm water collected in low-lying areas

outside the capital city.

A.4 The economy

The Central Bank of Sri Lanka (CBSL) describes the country’s economy in terms of the

monetary value of its Gross Domestic Production (GDP). It is calculated either based on the

current price each year or based on a reference year constant price to remove distortion due to

inflation. Fig. A5 gives these two sets of GDP values – current price based and 2002 price

based - from 2008 to 2013 expressed in Billion LKR. With the inflation factor removed, the

constant price GDP, referred to as real GDP, shows a slower growth (6.68%) compared to that

based on current price (14.51%). For comparing the year to year economic growth rates,

generally the constant price based GDP or real GDP is used.


121

Fig. A6 shows the real growth rates of the GDP during 2005 – 2013. In 2006, the growth rate

was 7.7%, and it has dropped to 3.5% in 2009. In the subsequent two years, it has recovered

to 8.0% and 8.2%, respectively, but was able to maintain a growth rate of only 6.4% in 2012.

In 2013, it has gained slightly to 7.25%.

Bil

lio

n L

KR

10000

9000 GDP( Current) GDP (2002) 8674

7579

8000 Av real GDP growth : 6.68%

7000 Av current GDP growth: 14.51% 6544

6000 5604

4835

5000 4411

4000

2864 3045 3266 2646

3000 2366 2449

2000

1000

0

0

2008 2009 2010 2011 2012 2013

Fig. A5. Growth of Sri Lanka’s GDP during 2008 - 2013181

Fig. A6. Variation of real GDP growth rates during 2005-2013182

The GDP is also worked out for each economic sector such as agriculture, industries and

services. These are again divided into various sub-sectors and GDP worked out for each of

them separately for the benefit of policy makers. Fig. A7 shows the breakdown of the GDP

among the 3 broad sectors – agriculture, industries and services for the period 2008-2013. The

highest contribution comes from the services sector, followed by industries and agriculture.

The belief that Sri Lanka’s economy is agriculture based is no longer valid, as agriculture has

contributed only 11% to the economy in 2012. The services sector has contributed nearly 60%

while the industrial sector has contributed a little over 30% in 2012. However, all 3 sectors

have exhibited positive growth rates during this period. The Industry sector grew by 10.3%,

contributing substantially to the expansion of the economy in 2012 with the construction sub-

sector contributing 21.6% in 2012 from 14.2% in 2011, according to the Central Bank reports.


122

Cu

rren

t G

DP

Bil

lio

n L

KR

10000 Services Industry Agri

9000

8000

7000

6000

5000

4000

3000

2000

1000

0 2008 2009 2010 2011 2012 2013

Fig. A7. Sectorial contributions to the GDP (current) during 2008 – 2013183

A common indicator used in comparing economies of countries is their GDP per capita based

on current price values expressed in US Dollars (USD). These values for Sri Lanka are shown

in Fig. A8 for the period 2008 – 2013, during which period the GDP per capita has increased

from USD 2,014 in 2008 to USD 3,280 in 2013. Another indicator is Gross National Product

(GNP) which is the GDP with any overseas income during the year added to it. Sometimes,

this could be negative in which case, the GNP is slightly less than the GDP.

Fig. A8. Growth of per capita GDP (current) during 2008 – 2013184

Sometimes GNP is referred to as the Gross National Income (GNI). The international

monetary organizations generally classify countries based on their per capita GDP or per

capita GNP. According to UN Conference on Trade and Development (UNCTAD),

economies are categorized into three subgroups based on their average per capita GDP: high-

income (above USD 4,500), middle-income (between USD 1,000 and USD 4,500) and low-

income (below USD 1,000).

Thus, Sri Lanka currently falls into the category of a middle-income country. However, the GDP

based per capita income should not be mixed up with the real per capita income of people.

According to a Household Income and Expenditure Survey carried out in 2012, the average

income per household in Sri Lanka was found to be LKR 46,207, and with an average household

size of 3.9 persons, the average per capita income works out to USD 1,093 in 2012185

.


123

According to the 2013 Annual Report of CBSL, the country’s economy is projected to expand

at a rate of 7.5% in 2013 and gradually move to a higher growth trajectory of over 8% in the

medium term. With the projected rapid economic growth, Sri Lanka is expected to surpass the

USD 5,000 threshold of per capita income by 2017, reaching a value of USD 5,485 in 2017,

as shown in Table A9.

Fig. A9. Growth of GDP (Current) forecasted up to 2017186

The situation of Sri Lanka’s economy in comparison to that of the region is shown in Fig. A9,

which shows per capita GDP for countries in Asia. Sri Lanka’s per capita GDP appears to be

below even 1/10th

the GDP of countries like Singapore, Hong Kong and Japan.

Fig. A10. Per Capita GDP (Current Price) distribution in Asia - 2011187

CBSL makes only short term forecasts on GDP and these are shown in Fig. A9, according to

which the real GDP will grow to USD 5,485/capita by 2017. An international agency – Trading


124

Economics – does long term forecasts on all countries. According to their forecasts, Sri Lanka’s

GDP/capita will rise to USD 3508 by 2015, USD 5470 by 2020 and USD 10,788 by 2030188

.

A.5 Poverty level

As determined in the 2012 census, Sri Lanka has about 5.2 million households, stratified into

three distinct sectors – urban, rural and estate. Households within municipal and urban council

areas fall under the urban sector while the rest excluding the estates fall under the rural sector.

The three sectors urban, rural and estate comprised 22%, 72% and 6% of the population,

respectively. The estate community comprising workers employed by the plantation

companies live in housing provided by the respective companies.

The Household Income and Expenditure Survey (HIES) conducted by the Census and

Statistics Department in 2012 provided information on the household income and expenditure

in these 3 sectors. The income details are shown in Table A2, while those of expenditure are

shown in Tables A3.

Table A2. Monthly mean household income in different sectors (2012)189

Household Mean per Mean per

Sector Mean House- capita capita

Income hold Size Income income

LKR/month LKR/month USD/month

Urban 68,336 4.0 17,150 134.40

Rural 42,184 3.8 11,003 86.23

Estate 31,895 4.1 7,719 60.49

National 46,207 3.9 11,932 93.51

Table A3. Monthly mean household expenditure in different sectors (2012)190

Average monthly HH expenditure LKR

Sector Total Food

Fuel & Transport

Lighting

Urban 59,001 18,513 3,165 6,226

Rural 37,561 14,704 1,433 3,119

Estate 29,779 14,779 1,332 2,138

National 40,889 15,358 1,724 3,607

Sri Lanka’s poverty level expressed as the Poverty Head Count (PHC) has been declining

over the years from 22.7% in 2002 to 6.5% in 2012. PHC is the ratio of the population living

below the official poverty line (OPL) to the total population within the sector. During the last

decade the OPL was considered to be LKR 1,423 a month.

Table A4 gives the fraction of the population living below this level of income in each of the

three sectors. The most significant improvement is in the estate sector where the PHC has


125

improved by nearly 5 fold, whereas in the other two sectors, it has increased by only about 3-

fold. This is mainly because of the increase in wages paid to plantation workers and also due

to the fact that more and more young people from estates seek employment in cities.

Table A4. Poverty head count in different sectors

Sector Poverty Head Count %

2002 2012

Urban 7.9 2.4

Rural 24.7 7.5

Estate 30.0 6.2

National 22.7 6.5

The household expenditure on fuel and lighting has been only a small fraction in all three sectors

– being 5.4% in urban, 3.8% in rural and 4.8% in estate households. The national level

expenditure has been only 4.2%. One reason for this low expenditure is due to the fact that

most households (77%) use firewood for cooking and for the majority electricity for lighting

is provided at subsidized rates. On the other hand, expenditure on transport has been a little

higher, being 10.6%, 8.3% and 7.2% for the three sectors, respectively with the national level

value of 8.8%191

.

A.6 Demography

Sri Lanka has a rather high population considering the small land area resulting in a high

density of population. The country’s population is enumerated at census generally held once

in 10 years and its growth from the beginning of the last century is shown in Fig. A11.

Fig. A11. Population growth during 1901-2012192

The census expected to be taken at the beginning of each decade was interrupted once during

World War II and again during the insurrection in early 1990s. The last census to be taken in

2011 had to be delayed due to some logistic problems and was taken only in 2012. Population

has grown from about 3.5 million at the beginning of the last century to 20.28 million in 2012,


126

nearly 6 fold increase. The average annual growth rate has declined from nearly 3% in the

fifties of the last century to about 0.7% during the last decade.

The mid-year population values are estimated based on birth and death rates for the periods in

between census years. Fig. A12 shows these values for the period 1991-2013, covering two

census years 2001 and 2012. The census is conducted by the Census and Statistics

Department while the mid-year population is published by CBSL based on data on births and

deaths provided by the Registrar General’s Department.

It is noted that the annual population increments for the year prior to the census year; that is

during 2000 -2001 and again during 2011 – 2012, have taken negative values. The growth

from 1991 to 2000 has shown an average value of 1.13%, while that between 2000 and 2011

has been -1.60%. Similarly, from 2001 to 2011 there has been an average growth of 1.05%,

while that between 2011 and 2012, it has been -2.8%, giving an overall decline for the decade.

Whether this negative change shown in the year prior to the census year is a real change or a

result of an incorrect estimate for previous years need to be verified. For the population to

show such a negative growth, either the birth rate should suddenly decrease or the death rate

increase. Since the 2001 and 2012 values are based on the census, it could be that the previous

years’ values are over-estimates. One factor that appears to have been overlooked is the

numbers who have permanently emigrate.

Fig. A12. Growth of mid-year population during 1991-2013193

Sri Lanka’s average population density as determined at the 2012 census has been 323 persons per

square kilometer. It has a wide variation within the country with over 10 times the national

average in the Colombo District being 3,438 per km2 and close to one tenth in Mulathiv District

being 38 per km2. Fig. A13 shows the distribution of population density within the country. The

highest densities are in the 3 districts in the Western Province. The distribution of population

generally follows the rainfall pattern of the country, the natural topography and natural forest

cover. The Colombo District with high commercial and administrative activities have the highest

density. In view of the increased demand for resources including land, water and energy required

to maintain a high population density in the Western Province (WP) and the possible adverse

impacts on the environment, the National Physical Planning Department (NPPD) in its


127

new National Physical Plan (NPP) has proposed that there should be a shift in the population

away from WP into areas where the population is low.

Fig. A13. Population density (2012) distribution among the districts

The districts in dry and forested areas have the least density, while those in the hilly areas also

have low density. The districts in wet areas in the western and southern provinces have high

densities and to even out this disparity, new metropolitan areas have been proposed. New

metropolitan regions (MR) proposed are expected to relieve the pressure from the Western

Province. These are shown in Fig. A14 giving the locations of the proposed new Metropolitan

Regions.

Fig. A14. Proposed metropolitan regions and industrial zones194


128

Some of the features of the new plan are:

• Future major MR will be the region bounded by Trincomalee, Anuradhapura,

Polonnaruwa and Dambulla. • Second major MR will be around Hambantota and the third in Ampara. • Development within the fragile central hills above 300m contour will be controlled. • Due considerationwill be given to availability of water and low impact on environment. • New industrial zones will be established away from the Western Province.

The population densities in Asian countries, except the two metropolitan states Singapore and

Hong-Kong, are shown in Fig. A15. Sri Lanka is within the upper 1/3 of the distribution list.

The demand for resources including land, water and energy is therefore is greater per land

area than in most other Asian countries. This also has implications on the impact on the

environment due to developmental activities.

Fig. A15. Population density in Asian countries in 2011-12195

.

Population projections made up to the end of this century by de Silva196

shows a decline in

the growth rate and this is expected to cause the population to reach a peak in about 3 decades

as shown in Fig. A16. These projections made under 3 scenarios – high, medium and low –

show peak values of 23.3 million in 2041, 21.9 million in 2031 and 20.9 million in 2021,

respectively. The projections commence in 2001 and have forecasted for 2011, three values

which are 20.774 million, 20.558 million and 20.221 million under high, medium and low

scenarios. The enumerated value for 2012 has been 20.278 million, which is closer to the low

scenario forecast. If the same trend continues, the future population will follow a path a little

above the low scenario forecast. This means that the population by the end of this century

could be below 15 million.


129

Po

pu

lati

on

(M

illi

on

)

High Medium Low

25

20

15

10

5

0 2001 2005 2011 2021 2031 2041 2051 2061 2071 2081 2091 2101

Fig. A16. Population projections up to 2101 under 3 scenarios

A.7 The climate

Sri Lanka is a tropical humid country with its rainfall pattern governed by the South Asian

monsoon winds. The SW quadrant receives more than 2,500 mm of rainfall annually during the

months from May to September when SW monsoon winds prevail. The NE monsoon winds bring

less than 1,750 mm of rainfall annually to most parts of the rest of the country during the months

from December to February. The southwesterly winds from the southern hemisphere and the

northeasterly winds from the northern hemisphere converge over an area known as the Inter-

Tropical Convergence Zone (ITCZ) causing large-scale convective activity.

During SW Monsoon, ITCZ lies to the north of Sri Lanka, while during NE Monsoon, it lies

to the south. In between the two monsoons, ITCZ lies over Sri Lanka bringing in heavy rains

resulting from the convective activity. While the monsoons bring rain either to SW part of the

country or to NE, convective activity during the inter-monsoons bring rain to all parts of the

country. The annual rainfall received in the country averaged over the period 1961-2000 is

shown in Fig. A17. This clearly shows the demarcation of the wet zone covering the SW

quadrant receiving rainfall in excess of 2500 mm a year.

The annual mean surface air temperature of the island is in the range 20 oC – 30

oC, with an

average of about 27 oC. It shows a diurnal variation in the range 5 – 10

oC, with a maximum

temperature attained in early afternoon, and the minimum shortly before sunrise, depending

on the elevation. There are considerable diurnal, seasonal and spatial variations in the

temperature leading to important region-specific patterns.

In the lowlands, the temperature rarely drops below 20 oC. It may exceed 30

oC and increase

up to 35 oC during prolonged droughts, particularly in the extreme north-west and south-east

corners where the rain fall is a minimum. The mean annual temperature at higher elevations

declines being governed by the adiabatic lapse rate, reaching a mean annual temperature of

about 15 oC at the high elevation station Nuwara Eliya (1,890 m). The annual average mean


130

temperature map constructed based on observations made at the 18 stations is shown in Fig.

A18. The reduced temperature in the central hilly areas is clearly marked.

Annual Average Rainfall -1961-2000

10

9.5

9 5600

5300

5000

8.5 4700

4400

4100

8 3800

3500

3200

7.5 2900

2600

2300

7 2000

1700

6.5 1400

1100

800

6

5.5 79 79.5 80 80.5 81 81.5 82

Fig. A17. Annual average rainfall Fig. A18. Annual average mean temperature

1961-2000197

1961-2000

The tropical climate in the country has a bearing on the energy demand. Unlike in temperate

countries, Sri Lankans in general do not have to spend energy for spatial heating during cold

months. However, there is a necessity for spatial heating in high elevations where the monthly

mean temperature remains around 16oC the year round and the night-time temperature falling

below 10oC. In the low lands which occupy most of the country, day-time temperature

exceeds 30oC and the humidity remains between 80% and 90%. Under such a humid

environment, it would be desirable if the temperature and humidity of living surroundings

could be controlled to more comfortable values. However, this requires high expenditure of

energy which would make investment on air-condition (AC) systems beyond the reach of the

majority of people. Even if the systems are installed, their operation is expensive under the

present tariff on electricity.


131

Appendix B

Terms of Reference for the evaluation of the National Benefits from the Production of

Domestic Natural Gas from the Offshore Mannar Basin

The Petroleum Resources Agreement (PRA) signed between the Government of Sri Lanka

and Cairn requires Sri Lanka to have first call on any produced hydrocarbons (the Domestic

Market Obligation, or DMO), and Sri Lanka currently does not have an established natural

gas market (as opposed to crude oil, of which approximately 12 million barrels are imported

annually), it is imperative that studies are launched immediately to determine (a) whether Sri

Lanka requires the use of locally produced natural gas for domestic purposes or whether it

wishes to export all production, and (b) if so, how much, in what sectors, and over what

period of time. Unless the domestic requirement is accurately stated, it will not be possible for

Cairn or any other operator to market the balance reserves internationally. Unlike oil, in which

a thriving spot market exists, the logistics and cost of gas production generally require long-

term contracts to be in place prior to development. In other words, gas reserves usually need

to be pre-sold prior to investment in production infrastructure. This will most certainly be the

case for Sri Lanka, a completely unproven gas province with no track record of production

and export, and the absence of clear policy to allow monetization of reserves may well

preclude oil and gas companies even from making initial exploration investment.

The PRDS therefore wishes to conduct a study to evaluate the national benefits of utilizing

domestic natural gas in the energy mix in place of imported oil, LPG or coal. It is hoped that

this would define (a) the sectors in which it makes economic sense to substitute feedstock, (b)

the quantity of gas required for such substitution, and (c) policy areas that may need revision

in order to phase gas into the national economy. In addition, PRDS wishes to understand what

additional industries may become viable with domestic gas production becoming a low-cost

source of energy.

For this purpose PRDS has identified the Sri Lanka Carbon Fund (Pvt) Ltd. (SLCF) as the

most suitable institution to undertake this study for the following reasons:

(a) SLCF is a State institution functioning under the Ministry of Environment and

Renewable Energy; (b) SLCF has amongst its staff experienced engineers and environmental economists (c) SLCF is actively pursuing a path to make Sri Lanka a truly low carbon country by

promoting low carbon fuels and environmentally benign projects. It is thus able to

capture and quantify all external costs attributable to various fuel sources holistically

and without bias, an essential part of long-term economic planning.

Terms of Reference of the assignment

6. Estimate the present use and future trends in the use of coal oil and LPG for electricity

generation, transport application, industrial heat generation, household and

commercial sectors


132

7. Estimate the true Externality Cost of using different feedstock in the above sectors in

the context of Sri Lanka 8. Prepare a report outlining the national benefits, if any, of substituting domestically

produced natural gas for any or all of the purposes above, including both direct and

externality cost impacts. This report may contain local or international references, but

all numbers must be supported. 9. Capture any other relevant aspects which would encourage or otherwise the use of

natural gas in Sri Lanka. 10. Recommend an investment, policy and infrastructure plan to enable revenue gains

from hydrocarbon production be used to increase the use of renewable energy such

that in the long term dependency on fossil fuels of any kind is minimised.

Study Guidelines

Total producible reserves: 2 Tcf (2 trillion standard cubic feet)

Initial production rate: 70 mmcfd (70 million standard cubic feet per day)

Pricing in production tranches:

0-200 Bcf US$ 12/mmBTU

200 Bcf - 1 Tcf US$ 9.5/mmBTU

1 Tcf > 2 Tcf US$ 7/mmBTU

>2 Tcf US$ 5/mmBTU

The SLCF may make any other assumptions, in consultation with the PRDS and any other

relevant organisation, and state these assumptions clearly where necessary.

The above figures are indicative only, and serve to indicate that the cost of domestic

production will fall over time, as the market matures and infrastructure is depreciated. The full

potential of the Mannar and Cauvery basins is thought to be considerably in excess of this.

The SLCF may also consider global pricing trends, and highlight, where appropriate,

opportunities for export of LNG, which will take into account the cost of setting up

liquefaction plants as required.

Deliverables

The entire scope of work may be addressed over a period of time, in phases, as required.

However, the initial NG utilization road map, and economic benefit analysis and short-term

policy recommendations need to be submitted to the PRDS within 30 days.

S. Wickramasuriya Director General - Petroleum Resources Development Secretariat Office of the President


133

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157 Ratnasiri, J. 2010. Establishing an energy hub in Trincomalee. The Island. 2nd and 3rd June, 2010.

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179 Perera, M.P. 1997.Vithanage, P.W. 1997. Relief and Drainage in Arjuna’s Atlas of Sri Lanka

(Eds. Somasekaram, T., Perera, M.P., de Silva, M.B.C. and Godellawatta, H.). Arjuna Consulting Co.

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Perera, M.P., de Silva, M.B.C. and Godellawatta, H.). Arjuna Consulting Co. Ltd., Dehiwala p. 16A

181 CBSL. 2013. Annual Report 2013. Central Bank of Sri Lanka. Colombo 00100. 182 ibid. 183 ibid 184 ibid. Tables 1&2 185 C&S Department. 2014. Household Income and Expenditure Survey 2012/13 – Preliminary

Report, Census and Statistics Department, Colombo.

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Statistics, Colombo 00300. p. 16 190 ibid. p. 30 191 ibid. p. 40 192 C&S Dept. 2013. Population of Sri Lanka by District. Census and Statistics Department.

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http://www.indexmundi.com/map/?v=21000&r=as&l=en 196 De Silva, W. I. (2007). A Population Projection of Sri Lanka for the New Millennium 2001 Trends and Implications. Institute of Health Policy, Colombo 197 Meteorology Department. 2010.Report on Climate Analysis submitted to the Climate Change

Division, Ministry of Environment and Natural Resources. Department of Meteorology.Colombo 00700


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