natural gas position paper ethekwini municipality 2015
TRANSCRIPT
ENERGY OFFICE
3rd Floor, SmartXchange, 5 Walnut Road, Durban, 4001
P O Box 1014, Durban 4000
Tel: +27 31 311 1139, Fax: +27 31 311 1089
Email: [email protected]
www.durban.gov.za
Natural Gas Position Paper: EThekwini Municipality
Date: 3rd February 2015
Version: Final (for Publishing)
Position Paper developed by:
PricewaterhouseCoopers Incorporated
2 Eglin Road, Sunninghill, 2157, South Africa
Private Bag X36, Sunninghill, 2157, South Africa
Tel No: +27 (11) 797 400, Fax No: +27 (11) 209 5800
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List of abbreviations
AfDB African Development Bank
API American Petroleum Institute
Bbl/d Barrels per day
BCM Billion cubic metres
BOE Barrels of oil equivalent
CAGR Compound Annual Growth Rate
CBM / CBNG Coalbed Methane / Coalbed Natural Gas
CCGT Closed Cycle Gas Turbine
CCS Carbon capture Storage
CHP Combined Heat and Power
CH4 Methane
CNG Compressed Natural Gas
CO2 Carbon Dioxide
CTL Coal to Liquid
DECC Department of Energy & Climate Change
DMR Department of Mineral Resources (South Africa)
DoE Department of Energy
e Equivalent
E&P Exploration and Production
EMEPSAL ExxonMobil Exploration and Production South Africa
EIA Energy Information Administration
ER Exploration Rights
FLNG Floating LNG Terminal
FPSO Floating Production, Storage and Offloading
GEPP Gas Engine Power Plant
GHG Greenhouse Gases
GJ Giga Joule
GTL Gas To Liquid
GWP Global Warming Potential
GUMP Gas Utilisation Master Plan
GUG Gas Users Group
HDV Heavy Duty Vehicle
HFO Heavy Fuel Oil /Furnace Oil
HGV Heavy Goods Vehicle
HHV Higher Heating Value
IDZ Industrial Development Zone
IEA International Energy Agency
IEP Integrated Energy Plan
IEU Intensive Energy User
IMF International Monetary Fund
IPCC Intergovernmental Panel on Climate Change
IPP Independent Power Producer
IRPTN Integrated Rapid Passenger Transport Network
IRP Integrated Resource Plan
JCC Japanese Crude cocktail
Km Kilometre
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KZN KwaZulu-Natal
KWh Kilowatt hours
LCA Life Cycle Assessment
LFG Landfill Gas
LDV Light Duty Vehicle
LNG Liquefied Natural Gas
LPG Liquefied Petroleum Gas
MGO Marine Gas Oil
MJ Mega Joule
MMBtu Million British Thermal Units
MMcf Million cubic feet
MMscfd Million standard cubic feet per day (sometime known as “scuffs”)
MPRDA MPRDA Mineral and Petroleum Resources Development Act
MMtCO2e Million Metric tonnes of Carbon dioxide equivalent
Mtpa Million tonnes per annum
MYPD Multi-Year Price Determination
NDP National Development Plan
NG Natural Gas
NGL Natural Gas Liquid
NGV Natural Gas Vehicle
NPC National Planning Commission / Net Payback Costs
NERSA National Energy Regulator of South Africa
NEMA National Environmental Management Act
NOx Nitrogen Oxides
NWA National Water Act
OCGT Open Cycle Gas Turbine
OECD Organization for Economic Cooperation and Development
OEM Original Equipment Manufacturer
OGIP Original Gas in Place
Pa Per annum
PASA Petroleum Agency of South Africa
Psi Pounds per square inch
R South African Rand (also known as ZAR)
R/P Reserves-to-production (R/P) ratio
RSA Republic of South Africa
SCADA Supervisory Control and Data Acquisition
SOx Sulphur Oxides
Tcm Trillion cubic metre
Tcf Trillion cubic feet
TCP Technical Cooperation Permit
USD United States of America Dollar (Currency)
WRI World Resources Institute
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Glossary
AR-5 100 year
GWP
Global-warming potential calculated over a 100 years period. IPCC has published its Fifth
Assessment Report (AR-5)
Biogenic Produced or brought about by living organisms Biogenic gas is created by methane rich
organisms in marshes, bogs, landfills, and shallow sediments.
Clathrate A cage-like ice structure that traps or contains methane molecules
CNG Compressed Natural Gas – primarily methane CH4 that is pressured to 200-250Bars and
produces 28% less GHG than normal petrol.
Compression
Stations (CNG)
A compressor station is a facility which helps the transportation process of natural gas
from one location to another. Natural gas, while being transported through a gas
pipeline, needs to be constantly pressurized at intervals of 60 to 150 Km. The gas in
compressor stations is normally pressurized by special turbines, motors and engines.
Conventional Gas Conventional gas is trapped within permeable rock reservoirs, which in turn is overlain by
a layer of impermeable rock. (AfDB, 2013).
Combustion The process of igniting a fuel (typically in a boiler, incinerator, or engine/turbine) to
release energy.
Dispensing
stations
Is in essence a service station that dispenses CNG, LNG, LPG or other fuels, most
commonly associated with CNG.
Distribution (Gas
Act)
Distribution of Bulk gas supplies and the transportation thereof by pipelines with a
general operating pressure between 2 and 15 Bar (29-218 psi).
Exploration Refers to activities required to locate below the service oil and gas reservoirs. Typical
activities include seismic exploration, surface mapping, exploratory drilling and the
testing of these wells.
Fugitive
emissions
Fugitive emissions are gas losses from the upstream natural gas value chain, such as
losses from equipment leaks, venting and flaring. Also known.as ‘methane leakage’.
Gas (Gas Act) All hydrocarbon gases transported by pipeline, including natural gas, artificial gas,
hydrogen rich gas, methane rich gas, synthetic gas, coal bed methane gas, liquefied
natural gas, compressed natural gas, re-gasified liquefied natural gas, liquefied petroleum
gas or any combination thereof.
Greenhouse gas These are gases which are emitted that trap energy radiated from the sun in Earth‘s
atmosphere in turn producing the greenhouse (or warming) effect. Greenhouse gases
include water vapour, carbon dioxide and methane.
Gas Processing Processing (onsite and offsite): The act of removing assorted hydrocarbons or impurities
such as sulphur and water from recovered natural gas. Initial settling could occur in
onsite storage pipes or tanks. Natural gas is then transported offsite through gathering
lines, where further processing occurs.
Global warming
potential
Global-warming potential (GWP) is a relative measure of how much heat a greenhouse
gas traps in the atmosphere. It compares the amount of heat trapped by a certain mass
of the gas in question to the amount of heat trapped by a similar mass of carbon dioxide.
GWP is expressed as a factor of carbon dioxide.
Higher Heating
Value
The amount of energy released when a specific volume of gas is combusted completely
and all resulting water vapour is condensed. Commonly measured in units of Btu/scf or
MJ/m3.
Liquefaction (Gas
Act)
Means converting natural gas from a gaseous state to a liquid state.
Liquefied
Petroleum Gas
(LPG)
Is a mixture of certain hydrocarbons, mainly propane and butane, which are gases at
normal ambient temperatures and pressures, the liquefaction of which is achieved by
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application of pressures of a few atmospheres, and derived from natural gas processing,
crude oil refining, or from synthetic fuels production from coal.
Liquefaction The refrigeration of natural gas into LNG.
LNG Liquefied Natural Gas is a super-cooled (cryogenic) liquid cooled between -120 and -
170°C (usually around -162°C) The volume is 1/610th of natural gas
Life cycle Consecutive and interlinked stages of a product system, from raw material acquisition or
generation to end-of-life.
Mobile cascades A moveable high pressure set of storage gas cylinder system which is commonly used at
CNG filling stations.for refuelling vehicles or supplying CNG to industry.
Natural Gas
Liquid
A group of hydrocarbons including ethane, propane, normal butane, iso-butane, and
pentanes plus. It generally includes natural gas plant liquids, and all liquefied refinery
gases, except olefins.
Natural gas
liquids (NGL)
Natural gas liquids (NGL): A group of hydrocarbons including ethane, propane, normal
butane, isobutane, and pentanes plus. Generally include natural gas plant liquids, and all
liquefied refinery gases, except olefins.
Natural gas
vehicle
A natural gas vehicle (NGV) is an alternative fuel vehicle that uses compressed natural gas
(CNG) or liquefied natural gas (LNG) as a cleaner alternative to other fossil fuels. Natural
gas vehicles should not be confused with vehicles powered by propane (LPG), which is a
fuel with a fundamentally different composition.
Petroleum
Product
Any liquid petroleum fuel and any lubricants or includes any other substances which can
be used for a purpose for which petroleum fuel or any lubricant can be used.
Production Production refers to the primary production phase, once wells have been connected to
processing facilities. Hydrocarbons and waste streams are produced by wells during this
phase.
Reticulation (Gas
Act)
Division of bulk gas supplies and the transportation of bulk gas by pipelines with a general
operating pressure below 2 Bar.
Regasification
(Gas Act)
Converting LNG to a gaseous state at a re-gasification plant
Regasification Process to return LNG back into natural gaseous state. (also known as vaporisation)
Reticulation The division of bulk gas supplies and the transportation of bulk gas by pipelines with a
general operating pressure of no more than 2 bar gauge to points of ultimate
consumption, and any other activity incidental thereto, and “reticulate” and
“reticulating” have corresponding meanings.
Reserves-to-
production Ratio
Reserves-to-production (R/P) ratio is where the reserves remaining at the end of the year
are divided by that year’s production
Sequestration Carbon sequestration (storage) is the isolation of carbon dioxide (CO2) from the earth's
atmosphere.
Storage The process of containing natural gas, either locally in high pressure pipes and tanks or
underground in natural geologic reservoirs, such as salt domes and depleted oil and gas
fields for a short or long period of time.
Synfuels Synthetic fuel or synfuels is a liquid fuel, or sometimes gaseous fuel, obtained from
syngas, a mixture of carbon monoxide and hydrogen, in which the syngas was derived
from gasification of solid feedstocks such as coal or biomass or by reforming of natural
gas.
Thermogenic Thermogenic gas is created from buried organic material that is subjected to temperature
and pressure
Trading (Gas Act) Means the purchase and sale of gas as a commodity.
Transmission (Gas
Act)
Bulk transportation of gas by pipeline supplied between source of supply and the end
user (Covers distributors, reticulators and storage companies).
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Table of Contents List of figures ........................................................................................................................................................ vii
List of Tables ........................................................................................................................................................ viii
List of Images ......................................................................................................................................................... ix
1 Executive Summary ........................................................................................................................................ 1
1.1 Executive summary ............................................................................................................................... 1
1.2 Purpose and Scope ................................................................................................................................ 4
1.3 Context .................................................................................................................................................. 5
1.4 The Natural Gas value chain.................................................................................................................. 7
1.5 Natural gas reserves .............................................................................................................................. 8
1.6 Global Demand and Supply ................................................................................................................. 10
1.7 Global pricing ...................................................................................................................................... 11
1.8 Natural Gas in South Africa ................................................................................................................. 11
1.9 The role of the eThekwini Municipality .............................................................................................. 18
1.10 Summary of opportunities .................................................................................................................. 20
1.11 Combining utilisation options with demand scenarios ....................................................................... 22
1.12 Overall Conclusion .............................................................................................................................. 25
2 Natural Gas .................................................................................................................................................. 27
2.1 Introduction ........................................................................................................................................ 27
2.2 The natural gas value chain ................................................................................................................. 27
2.3 Different forms of Natural Gas ............................................................................................................ 28
2.4 Environmental Impact ......................................................................................................................... 36
2.5 Climate Change mitigation risk opportunities .................................................................................... 36
2.6 How does natural gas affect the Greenhouse Gas profile of a region ................................................ 37
3 Global Environment ..................................................................................................................................... 40
3.1 Global Trends ...................................................................................................................................... 40
3.2 Global Demand and Supply ................................................................................................................. 43
3.3 International Gas Pricing ..................................................................................................................... 48
4 Natural gas trends in South Africa ............................................................................................................... 52
4.1 Introduction ........................................................................................................................................ 52
4.2 History of the gas industry in South Africa .......................................................................................... 53
4.3 KwaZulu-Natal Gas sector history ....................................................................................................... 54
4.4 Potential of the conventional and unconventional natural gas reserves in Southern Africa ............. 56
4.5 Upstream Permits and Rights.............................................................................................................. 60
4.6 Drivers for natural gas in South Africa ................................................................................................ 61
4.7 Natural Gas Infrastructure in South Africa .......................................................................................... 66
4.8 Other new developments ................................................................................................................... 67
4.9 Natural Gas pricing in South Africa ..................................................................................................... 68
4.10 The role of traders in South Africa ...................................................................................................... 69
5 Conventional Exploration............................................................................................................................. 70
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6 Unconventional Exploration ........................................................................................................................ 72
6.1 Tight Gas ............................................................................................................................................. 72
6.2 Shale Gas ............................................................................................................................................. 72
6.3 Coalbed Methane (CBM) ..................................................................................................................... 74
6.4 Gas Hydrates ....................................................................................................................................... 75
7 Routes to Market ......................................................................................................................................... 77
7.1 Ships, Rail, Trucks transportation ........................................................................................................ 78
7.2 Pipelines .............................................................................................................................................. 78
7.3 Bottles ................................................................................................................................................. 80
7.4 Consumption and Storage ................................................................................................................... 80
8 Overview of the South African Regulatory framework: Natural Gas Sector ................................................ 84
8.1 Policies and plans ................................................................................................................................ 84
8.2 Acts and Regulations ........................................................................................................................... 86
8.3 Summary of policies, regulations and laws affecting the South African gas industry......................... 87
8.4 Regulatory oversight bodies ............................................................................................................... 96
8.5 Conclusion on Legislation .................................................................................................................... 96
9 Key Stakeholder Assessment in the Natural Gas Sector .............................................................................. 97
9.1 Key Stakeholder Assessment .............................................................................................................. 97
9.2 Key Stakeholders ................................................................................................................................. 98
9.3 Regulators ......................................................................................................................................... 108
10 Natural Gas Opportunities and Risks for eThekwini Municipality ............................................................. 109
10.1 Natural Gas risk assessment ............................................................................................................. 109
10.2 Advantages of Natural Gas ................................................................................................................ 110
10.3 Disadvantages of Natural Gas ........................................................................................................... 110
10.4 EThekwini Municipal Role ................................................................................................................. 111
10.5 Gas utilisation options ....................................................................................................................... 112
11 Appropriate response options and action plan formulation for the eThekwini Municipality ................... 115
11.1 Demand Scenarios............................................................................................................................. 115
11.2 Indicative capital costs ...................................................................................................................... 118
12 Conclusion and Next Steps......................................................................................................................... 121
Appendix A: Gas for power generation .............................................................................................................. 123
Appendix B: Gas Transportation options ............................................................................................................ 128
Appendix C: Natural gas units of measure ......................................................................................................... 138
Appendix D: NERSA maps of natural gas distribution pipelines in KwaZulu-Natal ............................................. 140
Appendix E: References ...................................................................................................................................... 144
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List of figures
Figure 1: Natural gas value chain (Source PwC) ..................................................................................................... 7
Figure 2: Reserves to production ratio (years remaining) for fossil fuels (Source BP 2014 & IEA 2012,
interpreted by PwC) ................................................................................................................................................ 8
Figure 3: Technically recoverable gas global reserves and production ratios 2013 (Source: BP Statistical Review
of World Energy 2014) ............................................................................................................................................ 9
Figure 4: Gas global past and future trends (Source: IMF World Energy Outlook 2011-2013) ............................ 10
Figure 5: Global pricing regions (Source: PwC and Booz International) ............................................................... 11
Figure 6: Key natural gas plays in South Africa (Source; PASA 2014 map adapted by PwC) ................................ 12
Figure 7: Key South African policies related to the gas industry (Source PwC) .................................................... 13
Figure 8: Natural gas development times (Source: PwC) ..................................................................................... 16
Figure 9: Natural gas value chain (Source PwC) ................................................................................................... 27
Figure 10: Reserve and production in place diagram (Source PwC) ..................................................................... 28
Figure 11: Compressed Natural gas distribution network (Source PwC) .............................................................. 30
Figure 12: Liquefied natural gas value chain (Source PwC) .................................................................................. 33
Figure 13: Scope 1 to Scope 3 emission diagram (Source PwC) ........................................................................... 37
Figure 14: GHG emission factors for fossil fuels (Source DEA, 2014) ................................................................... 38
Figure 15: Proven natural gas reserves (Source BP Statistical Review of World Energy 2014) ............................ 40
Figure 16: East Africa 2013 discoveries (Source Rystad Energy, Booz & Company analysis 2013) ...................... 42
Figure 17: Proven gas reserves in Mozambique (Source BP, ENH, EIA and OGJ 2014) ........................................ 43
Figure 18: Natural gas trade 2013 by pipeline and LNG (Source (BP Statistical Review of World Energy 2014) . 44
Figure 19: Natural gas global trading routes (Source BP Statistical Review of World Energy 2014) .................... 44
Figure 20: LNG Export projected capacity increases up to 2018 (Source BP Statistical Review of World Energy
2014 and Petroleum Economist) .......................................................................................................................... 47
Figure 21: LNG Export projected capacity increases up to 2018 (Source BP Statistical Review of World Energy
2014 and Petroleum Economist) .......................................................................................................................... 47
Figure 22: Regional global LNG exporter map (Source Petroleum Economist) .................................................... 48
Figure 23: The four main pricing regions (Source Booz International 2014) ........................................................ 48
Figure 24: Global gas price trends 1984 to 2013 (Source BP Statistical Review of World Energy 2014).............. 49
Figure 25: Global short and spot LNG trends (Source International Group of Liquefied Natural Gas Importers
2014) ..................................................................................................................................................................... 50
Figure 26: Forecast LNG prices to 2040 (Source Baker Institute RWGTM 2014) .................................................. 51
Figure 27: Main natural gas plays in South Africa (source PASA adapted by PwC 2014) ..................................... 53
Figure 28: Onshore and offshore gas plays in KwaZulu-Natal (Source PASA adapted by PwC 2014) .................. 55
Figure 29: Shale gas plays in South Africa (Source PASA adapted by PwC 2014) ................................................. 58
Figure 30: Major coalbed Methane play in South Africa (Source PASA adapted by PwC 2014) .......................... 59
Figure 31: IRP anticipated MW feedstock supply changes 2010 – 2030 (Source DoE Revised IRP 2010) ............ 61
Figure 32: IRP anticipated percentage feedstock supply changes 2010 – 2030 (Source DoE Revised IRP 2010) . 62
Figure 33: Greenhouse gas emission output for various feedstocks (Source eThekwini Municipality LEAP energy
scenarios) .............................................................................................................................................................. 62
Figure 34 OCGT and CCGT gas IRP build options (Source DoE Revised IRP 2010) ................................................ 64
Figure 35: Main gas transmission and distribution lines in South Africa (Source Dynamic Energy 2014)............ 66
Figure 36: Transnet Lily gas pipeline (Source Transnet 2012) .............................................................................. 68
Figure 37: Average gas price comparison (Source NERSA 2014) .......................................................................... 69
Figure 38: Impact and difficulty of developing resources (Source PwC) .............................................................. 70
Figure 39: Conventional and Unconventional gas structural schematic (Source EIA & US geological survey) .... 71
Figure 40: Shale gas drilling (Source Future Challenges) ...................................................................................... 74
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Figure 41: A typical Coalbed Methane well (Source Ecos Consulting 2009) ......................................................... 75
Figure 42: Capacity: Distance diagram for natural gas transportation technologies (Source PwC) ..................... 77
Figure 43: Types of storage reservoirs (Source Berkeley Lab Earth Science Division) .......................................... 81
Figure 44: Selected policies and plans affecting the gas sector (Source PwC) ..................................................... 85
Figure 45: Selected Acts and Regulations affecting the South Africa Gas Industry (Source PwC) ........................ 86
Figure 46: Key Stakeholders in the South African Gas Industry (Source PwC) ..................................................... 97
Figure 47: Gas Utilisation applications (Source PwC) ......................................................................................... 112
Figure 48: Landfill gas production (Source pngc.com) ....................................................................................... 127
Figure 49: GHG emission for NGV and conventional fuelled vehicles (Source Burnham et al. (2011)) .............. 130
Figure 50: Fuel consumption, energy and CO2 (Source DENA and US EPA) ....................................................... 130
Figure 51: Considerations required when making a decision to invest in NGV's (Source PwC) ......................... 133
Figure 52: Total well-to-propeller global warming potential for LNG & HFO (Source NTNU–Tronheim 2013) . 135
Figure 53: Option Development: HFO vs LNG Marine system design (Source NTNU- Tronheim 2013) ............. 136
Figure 54: NPC for investment and operational costs for marine shipping solutions (Source TT-Line, IMO,
Danish Maritime Authority, Rolls Royce and PwC) ............................................................................................. 137
Figure 55: Payback period for LNG solutions through fuel cost savings (Source TT-Line, IMO, Danish Maritime
Authority, Rolls Royce and PwC) ........................................................................................................................ 137
Figure 56: eThekwini municipality pipeline network (Sources NERSA adapted by PwC} ................................... 140
List of Tables
Table 1: Natural Gas Global key facts (Source BP 2014 and IEA 2012) ................................................................... 8
Table 2: South Africa gas key facts (Source BP 2014, EIA 2013, SAOGA 2014)..................................................... 12
Table 3: Energy demand be sector and fuel in eThekwini in 2010 (GJ) (Source eThekwini Municipality Energy
Office, 2012) ......................................................................................................................................................... 18
Table 4: Greenhouse gas emissions by sector and fuel in eThekwini in 2010 (metric tons of CO2 equivalent -
MtCO2e) (Source eThekwini Municipality Energy Office) .................................................................................... 20
Table 5: High level summary of options for natural gas (Source PwC) ................................................................. 21
Table 6: LNG vs Natural Gas pipeline comparison (Source NETL 2014) ............................................................... 25
Table 7: Natural gas high level terminology (Source PwC) ................................................................................... 27
Table 8: GHG emissions factors for fossil fuel (Adapted from DEA report) .......................................................... 38
Table 9: Fossil fuel emission Levels (Source EIA) .................................................................................................. 39
Table 10: The most significant oil and gas discoveries in 2013 (Source Forbes 2013) ......................................... 40
Table 11: Significant gas discoveries in 2014 (Source IHS 15/10/2014) ............................................................... 41
Table 12: Highlighted African gas exports 2013 (source BP Statistical Review of World Energy 2014) ............... 41
Table 13: Top global LNG importers 2012 and 2013 (Source Petroleum Economist 2014) ................................. 45
Table 14: LNG export facilities in 2013 and 2018 forecast (Source BP and Petroleum Economist 2014) ............ 46
Table 15: South African gas key facts (Source BP 2014, EIA 2013, SAOGA 2014) ................................................ 52
Table 16: Shale gas exploration applications (Source PASA, PwC 2014) .............................................................. 57
Table 17: New build generation capacity in MW (Source DoE Revised IRP 2010) ............................................... 64
Table 18: Summary of Policies, Regulations and Laws affecting the South African Gas Industry ........................ 95
Table 19: Key Stakeholder on the South African Natural Gas sector (Source organisations websites) ............. 107
Table 20: Intensive energy users and gas user groups, companies in KZN (Source Organisations websites) .... 107
Table 21: High Level Gas Utilisation Options (Source PwC) ................................................................................ 114
Table 22: EThekwini Municipality low, medium and high demand options (Source PwC) ................................. 117
Table 23: International refueling infrastructure costs (Brightman et al (2011)) ................................................ 118
Table 24: International LNG and CNG unloading costs (Source PwC analysis) ................................................... 119
Table 25: High level summary of options for natural gas (Source PwC) ............................................................. 120
Table 26: Choosing electricity generation technology reference card EPRI (Source EPRI)................................. 124
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Table 27: Gas power generation technology comparison (Source PwC) ............................................................ 125
Table 28:Life0Cycle Analysis of Natural Gas for Transportation Use (Source The 2014 Annual TRB Meeting
Washington) ....................................................................................................................................................... 127
Table 29: Emissions Reductions (%) of new NGVs compared to conventional fuelled vehicles (Source CARB
2012) ................................................................................................................................................................... 129
Table 30: Ocean vessels fuels meeting MARPOL VI emission standards (Source PwC 2013) ............................. 134
Table 31: Advantages and Disadvantaged of LNG in shipping (Source NTNU – Tronheim 2013) ...................... 135
Table 32: Advantages and Disadvantages of HFO in shipping (Source NTNU – Tronheim 2013) ....................... 135
Table 33: Metric unit conversion table ............................................................................................................... 138
Table 34: Natural gas energy conversion table .................................................................................................. 138
Table 35: Natural gas energy conversion table 2 ............................................................................................... 138
Table 36: Natural gas volume conversion table ................................................................................................. 139
Table 37: Natural gas volume conversion table ................................................................................................. 139
Table 38: Natural gas weight/mass conversion table ......................................................................................... 139
Table 39: Typical natural gas composition, Mole % ........................................................................................... 139
List of Images
Images 1: Source of Supply (Source PwC) ............................................................................................................ 14
Images 2: LNG Carrier (Source Seaspout-Alternatives to bunker fuel – LNG) ...................................................... 34
Images 3: CNG cylinders mobile transportation (Source: Entcgf.com) ................................................................ 80
Images 4: LNG Gas Storage (Source lngworldnews.co.za/usa-ferc-issues-report-on-land-based-lng-spills) ....... 83
Images 5: Egoli Gasholder facility (Source Egoligas.co.za) ................................................................................... 83
Images 6: Canelands / Verulam: gas distribution licence area (Source: NERSA 2014) ...................................... 141
Images 7: Phoenix: gas distribution licence area (Source NERSA 2014) ............................................................ 141
Images 8: Jacobs / Mobeni / Clairwood: gas distribution licence area (Source NERSA 2014) ........................... 142
Images 9: Merebank: gas distribution licence area (Source Nersa) ................................................................... 142
Images 10: Prospecton: gas distribution licence area (Source NERSA 2014) ..................................................... 143
Images 11: Umbogintwini: gas distribution licence area (Source NERSA 2014) ................................................ 143
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1 Executive Summary
1.1 Executive summary
The eThekwini Municipality has committed itself to reduce energy consumption and greenhouse gas emissions
and to align with levels of emissions ‘required by science’ to curb catastrophic climate change impacts. The
municipality’s Sustainability Energy Theme report has highlighted that energy consumption will increase by 70%
and greenhouse gas emissions by 42% by 2030 if business as usual scenarios continue in the eThekwini
Municipality.
1.1.1 Potential Options
The municipality is therefore considering a number of strategic interventions that could assist it in reaching the
set targets. Assessing, understanding and possibly utilising natural gas within the energy portfolio is part of the
investigation of options. The level of influence that the municipality has over gas development and utilisation is
limited. The three interventions are directly participating, significantly influence and advocacy. This can be
summarised as:
The eThekwini municipality can directly participate in natural gas infrastructure development by building
increased power generation, converting the municipal fleet to run on CNG supplied from their own depots and
through the building of an improved gas reticulation network for business, commerce and domestic use.
The municipality can significantly influence gas production in the province by entering into PPAs with IPP’s thus
making investment attractive. The municipality can create a case for infrastructure development to supply and
dispense CNG to the municipal fleet. The municipality also has the ability to incentivise business and transporters
to switch some or all of their operations to natural gas.
The municipality can encourage and advocate gas utilisation and development through mediation, education,
and encouragement of a number of stakeholders to use or build gas generation within the province. A significant
part of this would be the development of a gas road map that fits in with the objectives of the long term
integrated development plan for the Municipality.
Potential gas options considered in this study are:
Gas for power;
Gas for transportation; and
Greater industrial, commercial and residential gas utilisation.
These options only exist if gas supply can be secured. The main difficulty for the eThekwini Municipality is that
at present there is limited supply of natural gas into the province. Demand in the country further outstrips
supply. To increase the supply of natural gas a number of options are available, such as increased pressure along
the Secunda to Durban Transnet pipeline, Liquefied Natural Gas (LNG) imports, or supply via a new pipeline from
Mozambique. All of these options will require large amounts of capital investment.
Domestically natural gas could be sourced from offshore conventional gas wells along the KZN coastline, shale
gas from the Karoo or Coalbed Methane gas from the coal rich provinces to the North. Both domestic
conventional and shale gas supply options are a decade or longer away from production. In the short term
reliance will have to be placed on imports.
Guaranteed supply of gas in significant volumes is a prerequisite for increased gas utilisation. If available, this
could provide an incentive for business to switch to gas. Unfortunately this could reduce the revenue the
municipality receives from selling power to the end consumer. The loss of this revenue stream should be
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assessed next to the increased competitiveness of these businesses, the reduced strain on power generation on
the Eskom network and the associated costs and loss of revenue from rolling blackouts. The municipality should
look at innovative gas tariff reticulation solutions that could recover any lost revenue from businesses switching
from electricity to gas power.
1.1.1.1 Gas to Power options:
The municipality is not likely to benefit from large scale solar, wind, hydro or nuclear power projects. Gas-fired
powered projects are therefore the only type of large power projects that the municipality is able to directly or
indirectly influence. At present 99.6% of the power energy mix is imported and the municipality has little
influence on the sources of supply going forward unless gas powered stations are located in the area.
Gas power produced locally could be extremely attractive financially with rates lower than Eskom’s as well as
ensuring energy security.
The municipalities’ main areas of influence for gas to power are:
Locally increase the production and supply of biogas from municipal owned landfill and wastewater
sites;
Enter into wheeling off-takers power purchaser’s agreement (PPAs) with Independent power producers
(IPP), such as the Avon peaking power plant; and
The municipality own and operate, or have a third party operate a gas power plant.
Research has shown that coal powered generation produces 30% to 50% higher GHG emissions so that any change in the energy mix where coal is substituted for gas will be better for the environment. Local gas power generation would affect the GHG inventory emissions with a decrease in scope 2 emissions and an increase in scope 1 emissions, although there is net reduction overall.
1.1.1.2 Gas for Transportation option:
Recent studies have indicated that for transport it is debatable if it is cleaner option over the entire Life Cycle of
the gas value chain, however for heavy duty and high mileage fleets the higher upfront cost can be recovered
by cheaper gas fuel prices which have traditionally been 30% lower.
The municipality could consider the following initiatives:
Run public transport pilot projects to assess the benefits;
Convert the municipal fleet to run on natural gas; and
Significantly influence businesses and operators to switch to NGV via incentives.
1.1.1.3 Greater industrial, commercial and residential gas utilisation option
The use of gas for power and heat applications by business, residential, commercial and public buildings would
be a cleaner, possibly cheaper, more efficient option than using coal generated power.
The municipality has a couple of main area that it can influence:
Run pilot projects such as the conversion of major public hospitals to tri-generation to assess benefits;
Convert municipal buildings to run on gas for heating, cooling, power etc.;
Encourage increased gas reticulation networks to be built; and
Encourage businesses to switch to gas as an alternative, reduced carbon energy source.
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1.1.2 Municipality gas based demand scenarios
The study looked at three demand scenarios to assess what the municipality must do if it wants to influence the
future energy mix up to 2030.
In determining the way forward, three main demand scenarios were looked at. The three demand scenarios are:
1.1.2.1 Low Demand scenario
In the low gas demand scenario little change in the supply of gas will be required and the municipality does little
to stimulate or create demand. The proposed transport and building pilot projects will be supplied by new landfill
and wastewater sludge gas production or from the Secunda along the existing distribution network. Due to the
relatively low upfront costs of these gas initiatives the municipality should start negotiations immediately with
a particular focus on the new NGV buses for the Integrated Rapid Passenger Transport Network and buildings
with a large energy use that will can benefit from tri-generation technology and be economically viable.
1.1.2.2 Medium Demand
In the medium demand scenario the municipality would create a moderate increase in demand and an increase
in the gas supply would be required, most likely met by increased supply through the Lily pipeline. An investment
of more compression stations along the length of the Lily pipeline would be required. This option would require
the municipality to switch a significant proportion of supply from conventional energy sources to gas in their
buildings and transport fleet. The introduction of CNG into the municipal fleet will lead to opportunities for local
business to convert to NGVs, construct CNG refuelling depots on behalf of the municipality, as well as provide a
launch pad for companies to set up CNG refuelling stations as the municipal fleet conversion has created a critical
mass for future industry development. The municipality would need to commit to targets such as that all buses,
taxis and LDV in the municipal fleet must run on gas by 2025, public transport operator licences depend on a
percentage of their fleet running on natural gas and other such initiatives.
1.1.2.3 High Demand
In the high demand scenario natural gas would need to be supplied by imported LNG or via new gas pipelines
from Mozambique. The high demand case scenario would provide a business case for large infrastructure
development. The municipality needs to motivate and develop an integrated energy plan which justifies the
development and platform for long term strategic investments which include entering into gas supply offtake
agreements with an IPP or building their own gas power stations. It is unlikely that the Municipality will be able
to guarantee an off-take agreement or have finance to build its own power stations without support from the
treasury. These large power projects would provide an opportunity for the municipality to be more self-
sufficient, diversify the energy mix and manage or reduce rolling blackouts and the effect they have on the local
economy. It will allow the municipality to reduce its GHG emissions while still achieving revenue targets through
the reticulation of gas to end users.
The high demand scenario infrastructure development would also create an opportunity for large scale business
gas uptake for power and heat applications. This may also come from other intensive energy users outside the
municipality such as the aluminium smelters at Richards Bay. The large increase in demand and the related
infrastructure would be expected to be paid for by the associated industries or traders supplying the gas.
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1.1.3 Conclusion
The municipality should in all cases encourage the use of gas by some domestic, industrial and commercial
customers, through advocacy, encouraging traders, providing reticulation infrastructure and suitable bylaws.
Gas should be incorporated into an integrated energy plan taking into account the flexibility of gas as a baseload
or peak power supply, as well as other utilisation options. Natural gas creates a number of other unique
opportunities to the eThekwini Municipality with long term savings to its own transport fleet, more efficient
buildings, the development of a more competitive advantage to local business, creating a business case for the
balancing of long term strategies compared to capital cost outlay and reduced revenue must be assessed on all
options going forward. It should also note that the lead time of 2-4 years for most large infrastructure
developments must be taken into account so the Municipality must act now.
The municipality should prioritise a number of projects that they can directly control and monitor cost savings
and efficiencies, such as:
Pilot schemes with the purchase and introduction of compressed natural gas buses;
Convert major public hospitals to tri-generation; and
Increase natural gas production from Landfill and wastewater sites.
The municipality must start discussions with key stakeholders such as Eskom, Department of Energy, traders,
Independent power producers, regulators and municipal departments to find long term gas solutions and
mitigate any associated risks.
As part of the integrated development plan the energy mix, security of supply, local economic development
and greenhouse gas emissions options need to be tied and evaluated against different options so that long
term strategic goals are met. The integrated energy plan must be developed before any decisions on the role
of natural gas can be taken.
Overall natural gas has many advantages and disadvantages that need to be assessed when developing options.
Advantages, however out-weigh the disadvantages. A favourable investment climate, clearer policies and
frameworks, clear consistent regulatory oversight encouraging greater horizontal integration, incentives and
private sector partnerships will ensure that the sector flourishes and creates the socio economic benefits
envisaged by the municipality.
The remainder of this report contains a summary of the purpose and scope of this position paper, as well as
details of the natural gas industry and the opportunities that it presents.
1.2 Purpose and Scope
The eThekwini Municipality has committed to reduce energy consumption and greenhouse gas emissions and
to align with levels of emissions ‘required by science’ to curb catastrophic climate change impacts.
The municipality’s Sustainability Energy Theme report has highlighted that energy consumption will increase by
70% and greenhouse gas emissions by 42% by 2030 if business as usual scenarios continue in the eThekwini
Municipality.
It was noted that transportation accounts for 69% of the energy consumption and contributes to 39% of the
GHG emissions. Industry consumes 45% of the electricity and contributes 32% GHG emissions. Opportunities to
reduce these emissions should be explored.
The municipality is therefore looking at a number of strategies and interventions that could assist it in reaching
the set targets. Assessing, understanding and possibly utilising natural gas within the energy portfolio is part of
the investigation of options. Potential gas options include:
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Gas for power;
Gas for transportation; and
Greater industrial, commercial and residential gas utilisation.
The purpose of this report is to provide a high level overview of the natural gas industry and to explore
opportunities that the eThekwini Municipality can pursue to change the energy mix in order to achieve their
long term sustainability plans.
The main areas covered in this report are:
An overview of the international, regional, national and local trends in the natural gas sector;
An overview of the South African regulatory framework on natural gas;
Key stakeholder assessment;
Natural gas sector opportunities and risks for eThekwini Municipality;
Appropriate response options for the eThekwini Municipality; and
A high level action plan.
1.3 Context
Natural gas is formed from the decomposition and pressurisation of algae, plankton and other organisms and
organic material which die, and sink to the bottom of the sea and lakes. These low-lying areas are buried by
sediment and over millions of years they get buried deeper and deeper. The enormous pressure and heat from
the overlying rocks cause the organic material to break down in-situ into hydrocarbons. The hydrocarbons that
are broken down into a gas is known as natural gas. Natural gas is primarily made up of methane (CH4), although
it is also associated with a combustible mix of hydrocarbon gases such as ethane and other heavier hydrocarbons
including propane and butane.
Natural Gas is increasingly seen as an attractive fossil fuel alternative to crude oil and coal, because it is cleaner
burning than either and sufficiently versatile to be used for domestic and industrial heating and power
generation, as a direct fuel source for vehicles and as industrial feedstock for liquid fuels and other chemical
products. It is the fastest-growing fossil fuel, with global consumption increasing by 1.7% a year. Increasing
supplies of shale gas and coal-bed methane, from which Natural Gas can be extracted, will ensure that global
demand can be met.
Natural Gas is:
Shapeless without volume;
Odourless, colourless and tasteless;
Non-corrosive;
A combustible mix of hydrocarbon gases primarily made up of methane;
Lighter than air, allowing leaks or emissions to quickly dissipate into the upper layers of the atmosphere,
making it less likely to form explosive mixtures in the air;
Efficient and abundant; and
Lowest GHG emissions factor for fossil fuel combustion.
The energy content of a given amount of natural gas remains the same regardless of whether it is in the liquid
(LNG) or gaseous (CNG) state. The methane global warming potential is 21 times that of Carbon Dioxide (CO2).
Natural gas is most commonly transported to market in pipelines or as Liquefied Natural Gas (LNG).
LPG is not natural gas, but rather a by-product typically obtained from the crude oil refining process. Natural gas
(NG) when pressurised to 200-250 bars is known as Compressed Natural Gas (CNG) and when super-cooled into
a (cryogenic) liquid at around 162°C is known as Liquefied Natural Gas (LNG).
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The benefits of utilising natural gas include:
Natural gas is one of the safest, cleanest and most efficient forms of non-renewable hydrocarbon
energy;
Natural gas can serve as an efficient alternative for petrol, diesel and coal and has a lower GHG emission
and carbon footprint;
Capital costs and construction lead times for gas infrastructure are significantly lower than coal and
nuclear power stations;
Opportunities for greenfield independent power producers exist to utilise gas as a feedstock;
Gas is virtually sulphur free, which means that corrosion resulting from sulphur dioxide is non-existent
and factory equipment therefore requires less maintenance and lasts longer;
Gas is a preferred hydrocarbon energy source as it is versatile, clean burning, safe and economical and
thus can be used directly across a number of sectors; and
Gas provides grid stability in a potentially intermittent renewable energy supply environment.
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1.4 The Natural Gas value chain
The gas value chain is broken down into upstream, midstream and downstream components, as depicted below. It should be noted that the eThekwini Municipality can only
have control through by-laws over the downstream reticulation of gas pipelines to the end user. The other sectors are regulated by central governmental departments and
regulators.
Figure 1: Natural gas value chain (Source PwC)
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1.5 Natural gas reserves
The world will not run out of natural gas anytime soon as recoverable reserves are estimated to last another 240
years.
Some of the key facts about natural gas:
3.3 tcm Annual World Natural Gas Consumption (2013)
3.8 tcm Annual Natural Gas Discoveries (2000-2010 average)
186 tcm Proven World Reserve (including unconventional gas)
790-810 tcm World Technically Recoverable Natural Gas Resources
58% Proportion conventional technically recoverable natural gas reserve
42% Proportion unconventional technically recoverable natural gas reserve
3.2% Sub-Saharan % of world gas production in 2013
3.3% Sub-Saharan % of the world’s proven reserves in 2013
Table 1: Natural Gas Global key facts (Source BP 2014 and IEA 2012)
Natural gas can be classified as either conventional or unconventional. Unconventional gas includes:
coalbed methane gas;
shale gas;
tight gas; and
gas hydrates.
Recoverable conventional gas reserves have continued to increase year on year, however conventional gas now
only makes up 58% of the technically recoverable reserves. There is a shift towards unconventional gas as a
result of improved drilling techniques such as directional drilling and fracking which have made unconventional
natural gas resources commercially viable. The BP statistical 2014 annual review estimates globally technically
recoverable reserves of 810 tcm1 and this includes proven reserves, reserves growth and as yet undiscovered
reserves. This figure is about 240 times the global consumption on 3.3tcm2 in 2013.
Figure 2: Reserves to production ratio (years remaining) for fossil fuels (Source BP 2014 & IEA 2012, interpreted by PwC)
1 International Energy Agency, World Energy Outlook 2013 2 BP Statistical review of world energy 2014
113
55
240
53
0
50
100
150
200
250
Proven Coalreserves
Proven Natural Gas TechnicallyrecoverableNatural Gas
reserves
Proven Oil reserves
Reserves to production ratio (years remaining) for fossil fuels
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Three quarters of the proven natural gas reserves are found in the Middle East and Russia, although exploration
success in Sub Saharan Africa, especially Mozambique and Tanzania have raised the expectation of the reserves
in Africa to increase.
75% of proven natural gas reserves are present in the Middle East and in Russia
Figure 3: Technically recoverable gas global reserves and production ratios 2013 (Source: BP Statistical Review of World Energy 2014)
Regions Tcm Tcf
Middle East 80.3 2,835
Russia / Caspian 52.9 1,872
Asia Pacific 15.2 537
Africa 14.2 502
North America 10.8 414
South America 7.7 271
Western Europe 3.6 127
Total 185.7 6,558
240+ Years Based on current demand, the world
has over 240 years of natural gas
available
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1.6 Global Demand and Supply
Gas is likely to become a more prominent source of energy as it becomes the preferred non-renewable energy
source in the world as it replaces less clean conventional hydrocarbon sources. Many countries are moving
away from the conventional fuels of oil and coal to greener alternatives, gas will continue to benefit from this
switching. A 1.7% CAGR increase in the use of gas is expected from 2010 to 20353 (Source WEO 2009, 2011,
2013). Much of this expected increase is due to the anticipated growth in the use of natural gas for power generation.
Natural gas consumption is expected to grow considerably faster in developing countries than consumption in the
developed world.
Figure 4: Gas global past and future trends (Source: IMF World Energy Outlook 2011-2013)
The supply of natural gas into the market continues to grow with increased supply along pipelines and through
construction of new Liquefied natural gas export facilities in Australia and other countries. The US, Mozambique
and Tanzania are all likely to become natural gas exporters in the coming years as unconventional and
conventional gas developments occur. In East Africa the significant finds over the last few years are likely to be
monetised and supply from Mozambique and Tanzania is expected to commence in 2020.
3 WEO 2013 - World Energy Outlook 2013 (Released on 12 November 2013)
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1.7 Global pricing
The gas industry does not have the benefit of a single commodity price as is the case with crude oil and as a
result, Gas pricing is a complex topic. There are currently four main natural gas price regions:
Figure 5: Global pricing regions (Source: PwC and Booz International)
1.8 Natural Gas in South Africa
Natural Gas in South Africa accounts for less than 2% of the primary energy demand in South Africa. This is
forecast to grow to approximately 7% over the next 15 years, in line with the aspirations for the power sector
as described in the revised Integrated Resource Plan 2010 (IRP 20104).
South Africa’s offshore exploration has historically been limited due to the low levels of proven reserves and the
difficult drilling conditions. These difficult conditions include deep offshore fields and extremely harsh ocean
currents. Recent improvements in exploration technology, coupled with large finds in the neighbouring
countries on the west and in particular the east coast has increased the interest in exploration activity. Twenty
exploration licences have been issued by the Petroleum Agency of South Africa (PASA). To date only 0.94 tcf5
(SAOGA) natural gas reserves have been proven offshore. There is an expectation that there could be up to 60
tcf reserves in place offshore.
Non-conventional gas is likely to be a significant contributor of natural gas in South Africa with estimated technical
reserves of 390 tcf for shale gas (8th largest reserves globally)(IEA 2013) and coalbed methane estimated at 12 tcf
(12th largest globally). Coal-bed methane could possibly be supplied to the market within the next 5 years. Shale gas
is likely to take another 8 to 10 years as exploration licences get approved and exploratory drilling takes place to assess
the potential reserves.
The gas market in South Africa has grown significantly over the last 10 years with the piping of natural gas from
Mozambique. The market has grown from 50mGJ/a in 2004 to 170mGJ/a as at end June 2014 (Sasol 2014). It is
expected that the pipeline will remain the primary source of gas supply in South Africa for a number of years.
4 Updated IRP available at www.energy.gov.za 5 SAOGA reserve estimates are in cubic metres
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PetroSA will continue to utilise their diminishing reserve off Mossel Bay to feed their Gas to Liquid plant, while
the Ibhubesi field on the west coast will likely supply gas to Eskom’s’ OCGT Ankerlig power station.
0.42 tcf Annual Natural Gas Consumption (2013)
1.27 tcf Annual gas production – global ranking 62
0.96 tcf Proven RSA Reserve – global ranking about 77
403.8 tcf RSA technically recoverable Natural Gas Resources – Conventional – CBM and
shale gas
17-80 tcf Estimated recoverable shale gas reserves out of the 390tcf predicted by the EIA
0.8 tcf Conventional natural gas reserve in Namibia’s Kudu field designated for RSA
consumption
3.0 tcf Conventional natural gas reserve in Mozambique’s Pande/Temane fields
designated for RSA consumption
1% Proportion of-conventional technically recoverable natural gas reserve
99% Proportion of non-conventional technically recoverable natural gas reserve
Table 2: South Africa gas key facts (Source BP 2014, EIA 2013, SAOGA 2014)
South Africa has at present only one indigenous producing field, being the PetroSA operated block 9 Offshore
Mossel Bay. A number of exciting natural gas opportunities however exist for local natural gas production with
the primary locations being three main offshore basins, the central Karoo onshore basin and the coalbed
methane deposits in the Ecca Group, part of the Karoo Super group stratum as depicted below in figure 6.
Figure 6: Key natural gas plays in South Africa (Source; PASA 2014 map adapted by PwC)
The upstream sector will be impacted by the amended Mineral and Petroleum Resource Development Act
(MPRDA) which has a number of ambiguous requirements relating to state interests and BBBEE requirements.
The MRPDA in its present form (prior to the proposed amendments) has the State participation at 10% , in
production rights and the State only has to contribute to past costs and pays pro rata costs going forward from
the production phase. The amended MPRDA Bill will increase the state participation to 20% in exploration and
Orange basin
Karoo Shale gas
Coalbed methane
Bredasdorp basin
Tugela basin
Main natural gas areas in South Africa
Durban
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production rights for no financial consideration (free carry). Furthermore an additional uncapped state interest
could be obtained at an “agreed price” (not market value) or under a Production Sharing Agreement (PSA). It is not
clear how the State’s right to further participation would be exercised and this has created uncertainty over the
Bill.
The new Mineral and Resources Minister Ngoako Ramatlhodi’s has acknowledged these uncertainties and has
been on record saying the Bill should be sent back to Parliament for the contested clauses to be reviewed, or
have a separate Petroleum Bill drafted so as not to combine legislation affecting the hydrocarbons industry with
that affecting the mining sector. It would therefore seem likely the new MPRDA Bill will not be promulgated into
law as it stands.
South Africa wants to increase natural gas into the energy mix.
Natural gas has traditionally contributed little to the country’s primary energy mix (approximately 2 %). South
Africa is highly reliant on coal for power generation and some of its liquid fuels for transport. This has resulted
in high GHG emissions with the country being by far the largest emitter of GHG in Africa.
South Africa has four main national imperatives related to energy (DMR, 2012), namely:
• A ‘drive to diversify sources of energy and thereby reduce South Africa’s dependence on coal’;
• A ‘commitment to reduce the ‘carbon intensity’ of South Africa’s energy systems’;
• A ‘desirability of improving ‘security of supply’ by developing indigenous resources’; and
• An ‘immediate need to expand national capacity to generate electricity’.
The South African government has introduced numerous policies that aim to create guidance and plans on
how to reduce a reliance on coal and move to a low carbon economy below in Figure 7.
Figure 7: Key South African policies related to the gas industry (Source PwC)
The Department of Energy (DOE) Integrated Energy Plan (IEP) (DOE, 2013), which offers a forecast of how energy
can be optimally used in the country up to 2050, assess a number of different scenarios on how South Africa can
reduce and limit GHG emissions. One of these options includes natural gas. The overall objective of the
‘emissions limit – natural gas case’ is for South Africa to meet its ‘peak, plateau and decline’ emission trajectory
as set out in the National Climate Change Response Policy. The IEP specifically suggested that the introduction
of new natural gas sources (e.g. local offshore conventional gas, coal bed methane, shale gas, and regionally
imported natural gas into the energy supply mix as a transition fuel towards a low carbon economy). Natural gas
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was recommended as an alternative to coal and nuclear provided that the economic and environmental costs
and benefits outweigh those associated with other power sources.
The revised IRP 2010 is the primary source and driver that maps the 20-year electricity road which aims at
diversifying the country away from coal. The IRP places an emphasis on a greater contribution of renewable
energy, gas and nuclear power to source to the country’s new and uncommitted electricity generation capacity
by 2030. The aim of diversifying to a lower carbon economy is however constrained by the need for the country
to continue to be globally competitive and the effects of change on a socio economic basis as the dependence
on coal is reduced. The supply of gas locally was not fully assessed and implemented into the IRP (DME 2012) as
the country’s potential gas reserves only became apparent after the IRP was published. A review and update of
the IRP is expected on a regular basis by the DoE, and this will take into account a possible greater role for natural
gas in South Africa’s in the energy mix. Government policies and statements by national departments, Eskom,
PetroSA and other industry players have indicated that natural gas options will be investigated and address the
future energy mix in an appropriate manner.
A Ministerial Determination under section 34(1) of the electricity regulation Act was gazetted on 19 December
2012 and provided a greater emphasis towards natural gas with the OCGT (diesel) portion of the IRP baseload
being re-allocated to natural gas. The new baseload and/or mid-merit energy generation capacity of 2,652 MW
needed to contribute towards energy security will be generated from Natural Gas. Natural gas includes Liquefied
Natural Gas or Natural Gas delivered by pipeline from a Natural Gas Field, which represents the capacity
allocated to Gas CCGT (natural gas)" and "OCGT (diesel)", in the IRP for the years 2021 to 2025. This is on top of
the 474 MW natural gas already allocated to OCGT in IRP2010.
Natural gas is a viable option.
There have been a number of local and international developments that make the availability of natural gas a
viable option for South Africa. The availability of natural gas to feed the demand in South Africa could come
from a number of new sources.
Images 1: Source of Supply (Source PwC)
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Additional pipelines could link the Sasol Pande-Temane gas fields to the huge offshore gas finds in the
North of Mozambique, providing additional gas to South Africa.
A proposed pipeline from Mozambique to Richards Bay could provide a further source of gas to South
Africa.
Piped gas from the Ibhubesi gas field on the South African west coast to supply natural gas to Eskom’s
Ankerlig power station in Atlantis.
LNG supply is outstripping demand as a result of developments in North America, Australia and East
Africa. This provides opportunities for additional gas supply to South Africa. Companies such as PetroSA,
Sasol and Shell are investigating the feasibility of LNG import options. Larger ships and Floating LNG
(FLNG) and Floating Production, Storage and Offloading (FPSO) facilities provide greater flexibility into
the sector.
Coalbed methane exploration is looking promising with Molopo oil and Kinetiko Energy evaluating
results from their exploratory drilling activities.
Shale gas exploration permits are being processed by the Petroleum Agency of South Africa (PASA). This
could lead to licences being issued in 2015, fracking in 2016 and if the reserves are commercially viable
then possible production from around 2023. Shale gas technology has significantly improved over the
last few years and will assist the development of shale gas exploration and production going forward.
CNG tankers supplying natural gas from Angola to the Western Cape are being investigated.
While various supply options exist to increase the availability of natural gas in South Africa, there are a number
of significant barriers that must be overcome. These include:
Gas infrastructure is only available in four provinces, most of which is concentrated in Gauteng. KwaZulu Natal has 8 distribution licence areas which are supported by Sasol gas infrastructure and supplied to customers primarily by Spring Lights. Six of the licenced distribution areas are located in eThekwini Municipality (Canelands and Phoenix licences in the North and the Prospecton, Merebank, Umbogintwini and Jacob distribution licences situated around the South of Durban);
Uncertainties in the gas regulatory framework must be addressed to provide clarity to both
conventional and unconventional gas players;
Recent LNG Feasibility studies conducted on LNG importation into Mossel Bay concluded that it was
not a viable option due to the harsh environmental sea conditions;
Lack of large anchor customers to justify the development of domestic gas fields and related supporting
infrastructure;
Delays in the finalisation of the procurement process for baseload IPP programme;
The Department of Energy (DoE) has been working on a Gas Utilisation Master Plan (GUMP), but its
completion is now long overdue. The GUMP is meant to provide clarity and direction to potential
investors regarding the gas infrastructure and utilisation strategy for South Africa; and
Lack of proven reserves in RSA.
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The below diagram indicates a high level analysis of the likely timeline for development of the natural gas infrastructure in South Africa.
Figure 8: Natural gas development times (Source: PwC)
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Key Stakeholders
In South Africa there are a number of key stakeholders in the industry ranging from regulators, governmental
departments to parastatals, traders, producers and consumers. The main stakeholders are summarised below:
The six main regulators in the Petroleum industry are:
The Minister of Mineral Resources;
The Minister of Energy;
The Petroleum Agency of South Africa (PASA);
The National Energy Regulator;
The Transnet National Ports Authority; and
The Ports Regulator.
Consumers of gas
Approximately 80% of the gas consumption in South Africa goes into feedstock for Synfuel and Chemical
production:
Sasol gas consumes 140 MGJ/a (60%); and
PetroSA 48 MGJ/a (20%).
The other 20% is consumed by around 404 other major end users with 38MGJ/a (16%) supplied as Methane rich gas and 9 MGJ/a (4%) as natural gas. (Dynamic Energy, 2014) Transmission pipeline owners
There are three main gas transmission pipelines in South Africa:
The Rompco natural gas pipeline that supplies 80% of the natural gas into South Africa (owned 50%
by Sasol, 25% by the South African Government and 25% by the Mozambican Government);
The PetroSA offshore pipeline to its GTL plant in Mossel Bay; and
The gas transmission pipeline that pipes methane rich gas from Secunda to South Durban, owned by
Transnet.
Gas Traders
There are six main gas traders in South Africa:
Sasol gas, (pipelines);
Spring Lights and (pipelines);
Reatile (pipelines) ;
Novo Energy (CNG);
NGV Gas (CNG); and
Virtual Gas Network (CNG).
Other significant stakeholders and more detail of the stakeholders above are provided in section 4: Key
stakeholders.
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1.9 The role of the eThekwini Municipality
While it is clear that the municipality wishes to explore natural gas options in pursuit of its goals to reduce GHG
emissions, it must recognise that there are limits to what it can do. Essentially, the municipality has three
potential roles that it could play:
Direct participant: the municipality directly invests in natural gas infrastructure (e.g. power plants,
natural gas vehicles, etc.);
Influencer / Facilitator: creating the enabling environment that would support increased gas utilisation
through for example accelerating the approval processes associated with gas ventures; and
Gas advocate: raising awareness of the benefits of natural gas amongst stakeholders.
A further point that must be taken into account in defining the role of the municipality is the source of GHG
emissions, and the extent to which it can actually exercise any control over this. For example, the eThekwini
Municipality has little influence on electricity emissions as 99.6% of the supply comes from outside the
Municipality. The table below provides an indicative view of the energy demand and greenhouse gas emissions
by sector.
Sector Avgas / Jet /
Kerosene
Coal
Bitumin Diesel Electricity Petrol Paraffin LPG HFO Wood TOTAL
Residential 0 0 0 12,050,700 0 2,892,001 129,131 0 889,033 15,960,865
Commerce 0 0 1,812 10,243,287 0 1,302,610 2,358,650 35,355 0 13,941,714
Industry 0 6,829,230 660,919 16,900,905 260 446,075 0 2,021,928 0 26,859,317
Transport 2,041,936 0 41,621,019 130,181 35,821,874 0 0 51,073,640 0 130,598,650
Local Govt 0 0 461,834 1,329,154 187,082 0 0 10,881 0 1,988,951
Elec Losses 0 0 0 1,773,241 0 0 0 0 0 1,773,241
TOTAL 2,041,936 6,829,230 42,745,584 42,427,468 36,009,216 4,640,686 2,487,781 53,141,804 889,033 191,122,738
% 1.0% 3.6% 22.4% 22.2% 18.8% 2.4% 1.35 27.8% 0.5% 100%
Table 3: Energy demand be sector and fuel in eThekwini in 2010 (GJ) (Source eThekwini Municipality Energy Office, 2012)
Energy consumption in eThekwini is dominated by the transport sector (69%), followed by the industrial (14%)6,
residential (8%) and commercial (7%) sectors. Local government and electricity losses account for 1% each of
energy demand. The main areas where energy consumption can be reduced is with transportation and as such
gas can play a role as a source of fuel, although the main way to reduce energy consumption in this sector is
through an integrated transport plan that encourages greater use of public transport.
South Africa’s electricity is largely coal-fired, which is a very carbon intensive process. This means that electricity
produces more greenhouse gas (GHG) emissions per gigajoule than other fuels, such as petrol or diesel. This
accounts for the fact that although the transport sector consumes the largest amount of energy (69%), its GHG
contributions are proportionally considerably less (45%). The transport sector is followed by the industrial (23%),
residential (15%) and commercial (13%) sector emissions. Local government and electricity losses account for
2% of GHG emissions each.
The main areas that need to be targeted for GHG emission is the transport sector, however the municipality has
no control over aviation and at present no control over shipping emissions. The clearest area where the
municipality can encourage fuel switching is on road transportation. The municipality can convert their fleet to
CNG, and encourage infrastructure develop and switching to CNG through incentives, education, subsidisation
and securitisation of loans.
6 The eThekwini Municipality demand information and GHG emissions Inventory information is available http://www.durban.gov.za/City_Services/energyoffice/Pages/default.aspx
19 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Industry and commerce should be targeted and encouraged to switch to natural gas as an efficient and cleaner
alternative for a number of applications, especially thermal.
Sectors where gas can play a role
On the assumption that natural gas supply and related transmission, distribution and infrastructure are not
barriers, multiple natural gas options exist:
Buildings sector
It is important to encourage the efficient direct use of natural gas in buildings, where natural gas applications
have a lower greenhouse gas emission footprint compared with other energy sources. For thermal applications,
such as space and water heating, onsite natural gas use has the potential to provide lower-emission energy
compared with oil or propane and electricity in most parts of the country. Natural gas for thermal applications
is more efficient than grid-delivered electricity, yielding less energy losses along the supply chain and therefore
less greenhouse gas emissions.
Manufacturing sector
Combined heat and power systems are highly efficient, as they use heat energy otherwise wasted. Policy is
needed to overcome existing barriers to their deployment. Municipalities should take an active role in promoting
combined heat and power from cleaner burning gas.
Distributed generation
Natural gas-related technologies, such as microgrids, micro turbines, and fuel cells, have the potential to
increase the amount of distributed generation used in buildings and manufacturing and these technologies can
be used in configurations that reduce greenhouse gas emissions when compared with the centralized power
system as they can reduce transmission losses and use waste heat onsite.
Transportation sector
Transportation offers the greatest opportunity to reduce greenhouse gas emissions using natural gas through
fuel substitution. The substitution in fleets and heavy duty vehicles in particular is important. Passenger vehicles
due to their lower emissions and general lower yearly mileage are unlikely to be an option that will make a
significant impact. Natural gas when combusted emits fewer greenhouse gases than petrol or diesel, however it
is yet to be determined whether it really is cleaner when the entire value chain is taken into account. EThekwini’s
high GHG emissions can be significantly reduced if shipping from the port ran on LNG. If public and private taxis,
buses and HGV ran on CNG from landfill biogas the energy footprint would significantly decrease.
Feedstock for GTL and Petrochemical industries
The petrochemical industry could also use the gas as a feedstock for the production of Urea, Methanol, Ammonia
and other products. The use of natural gas would economically benefit the Municipality through the creation of
manufacturing sector jobs, as well as increased port activity related to the export of these products.
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Table 4 below shows GHG emissions by sector and fuel, together with an indication of gas substitution options
that may be available for each fuel source. We have also indicated what role (Direct, Influencer or Advocacy) the
municipality can play for each substitution option.
Sector
Energy
Demand
Avgas / Jet
Kerosene
Coal
Bituminous Diesel Electricity Petrol Paraffin LPG HFO Wood TOTAL
Residential 0 0 0 2,880,334 0 210,960 9,467 0 6,703 3,107,464
Commerce 0 0 132 2,448,330 0 95,020 172,918 2,579 0 2,718,979
Industry 0 637,086 48,100 4,039,621 19 32,464 0 147,152 0 4,904,442
Transport 142,844 0 3,059,958 31,116 2,479,903 0 0 3,717,037 0 9,430,858
Local Govt 0 0 33,976 317,692 12,940 0 0 753 0 365,361
Elec Losses 0 0 0 423,837 0 0 0 0 0 423,837
TOTAL 142,844 637,086 3,142,166 10,140,930 2,492,862 338,444 182,385 3,867,521 6,703 20,950,941
% 0.7% 3.0% 15.0% 48.4% 11.95 1.6% 0.9% 18.5% 0.0% 100%
Likelihood of
substitution Not Possible Possible Likely Likely Likely Not likely
Possible
domestic
cooking
Possible
but no
municipal
influence
Not
likely
Gas
substitution
technology
N/A
Thermal and
power
generation
CNG
transport
From various
resources
CNG
transport N/A
domestic
cooking and
Thermal
LNG for
shipping N/A
Table 4: Greenhouse gas emissions by sector and fuel in eThekwini in 2010 (metric tons of CO2 equivalent - MtCO2e) (Source eThekwini Municipality Energy Office)
1.10 Summary of opportunities An analysis of the most likely gas utilisation options is set out below. The major area where GHG emissions
reduction can be achieved through the introduction of gas is in power generation. The Municipality
unfortunately has little influence on the country’s energy mix for power generation going forward.
The main areas of influence are therefore through increased production from municipal owned landfill and
wastewater sites. The municipality could also have wheeling off-takers power purchaser’s agreement (PPAs)
with Independent power producers (IPP), such as the Avon peaking power plant. Alternatively, the municipality
can actually own and operate or have a third party operate a gas power plant. The gas power produced would
allow the municipality to have greater control over power and be extremely attractive financially with rates
lower than Eskom’s.
The municipality can influence gas utilisation by directly participating, significantly influencing and through
advocacy.
The eThekwini municipality can directly participate in natural gas infrastructure development by building
increased power generation, converting the municipal fleet to run on CNG supplied from their own depots and
through the building of an improved gas reticulation network for business, commerce and domestic use.
The municipality can significantly influence gas production in the province by entering into PPAs with IPP’s thus
making investment attractive. The municipality can create a case for infrastructure development to supply and
dispense CNG to the municipal fleet. The municipality also has the ability to incentivise business and transporters
to switch some or all of their operations to natural gas.
The municipality can encourage and advocate gas utilisation and development through mediation, education,
and encouragement of a number of stakeholders to use or build gas generation within the province. A significant
part of this would be the development of a gas road map that fits in with the objectives of the long term
integrated development plan for the Municipality.
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Below is a high level utilisation summary on the three ways that the municipality can influence gas utilisation.
EThekwini
Municipality
influence
High level utilisation summary
Direct participant Power
Landfill and wastewater natural gas production.
Build, own and operate own power plant.
Build, own and have third party operate power plants.
Conversion of municipal buildings to run on gas boilers, gas engine power installation
e.g hospitals tri-generation.
Transport
Convert municipal fleet to run on CNG.
Build dispensing depot facilities.
Domestic / Commercial / Industrial
Build and operate reticulation networks.
Influence Power
Create case for Avon IPP to switch to gas as feed stock.
PPA with IPP (guaranteed offtake agreements).
Transport
Municipal fleet create critical mass for CNG NGV network development.
Domestic / Commercial / Industry
Reduced rates for greener business.
Creation of appropriate by-laws.
Buy back excess power produced.
Increased technical training for gas applications.
Split tariffs, cheaper for business to generate own electricity from gas over certain times.
Advocacy Power
Encourage government to build gas power plants in KZN (build case as renewable,
nuclear and coal power generation outside province) – Security of supply for the
regions.
Transport
Educate about the benefits of NGV.
Facilitate loans.
Encourage LNG facility development at Port.
Feedstock
Road map – reduced red tape – manufacturing incentives and subsidies.
Domestic / Commercial / Industry
Road Map.
Educate about benefits of natural gas for power, heat, cooking and thermal.
Create a conducive environment for business with greater control to manage rolling
blackouts.
Table 5: High level summary of options for natural gas (Source PwC)
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1.11 Combining utilisation options with demand scenarios
The Municipality is at a crossroad where it requires economic growth in order to increase the number of rate
payers and be able to afford the Municipality’s long and short term visions and strategies. The Municipality
needs to undertake initiatives that significantly increase job creation while at the same time reducing
greenhouse emissions. Without job creation, the sustainability of social programmes and infrastructure
development initiatives will be threatened, reduced or cancelled due to budget restraints.
If the municipality does nothing then the gas will play a very small role in the energy mix for the municipality.
The share of gas in the national electricity mix could increase up to 7% if OCGT and CCGT proposed power sites
are all powered by gas. If the municipality does nothing then its share of gas power actually generated within
the province will be decided by those sitting elsewhere in South Africa. Power generation from renewable
energy such as wind and solar will be limited in KZN, so the province must ensure that gas powered generation
for security of supply and economic development occurs in the province.
In determining the way forward, we have considered three main demand scenarios. These scenarios highlight
what is likely to happen based on how the municipality does or does not influence either directly or indirectly
the utilisation of gas in the province. The municipal electricity demand is likely to increase from around 12GW
to 19 GW between 2010 and 2030 if economic growth targets are to be met.
The gas demand options will need to be evaluated based in the context of the overall integrated energy strategy.
The long term strategy of the municipality and related gas objectives must be defined so that each of the gas
options can be evaluated against the required criterion. Each gas option will need a pre and full feasibility study
prior to implementation.
The three scenarios considered are low demand scenario where the municipality does little to stimulate or
create demand. Medium demand is where the municipality would create a moderate increase in demand for
gas and require an increased gas supply into the province. High municipal demand would require large
infrastructure development and capital pumped into the province to increase the supply of natural gas.
1.11.1 Low Demand: gas makes up less than 5% of the energy mix in eThekwini Municipality
Allow IRP2010 to run its own course
In this scenario the Municipality does nothing and is reliant on the implementation of the revised IRP2010 and
has no influence on the creating an environment for gas power generation in the province. The province could
influence decision makers in locating gas powered CCGT and OCGT power plants in the province, which would
increase the power supply locally and rely less on electricity infrastructure outside the province.
Within this low demand scenario the municipality runs a number of small pilot projects, such as 20 new buses
for the IRPTN and a couple of municipal hospitals are switched to be powered on gas (most likely CNG). The
costs would be in the region of an extra R250,000 per bus7 and R11 million per MW for tri-generation at a
hospital8.
Own power production
The most likely source of local gas production in the short term is from landfill sites and wastewater sites. These
sites offer an excellent opportunity for the municipality to generate their own green power or use it mixed with
natural gas to power NGVs. At present the landfill gas sites supply 0.4% of the power to the eThekwini
7 National Renewable Energy Laboratory and other sources translate at 1USD to 10 Rand 8 Based on MTN’s 2 MW, R22-million methane-powered plant at its Fairland offices
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municipality and even with increased capacity it is unlikely to exceed 1%. Due to security of supply, increased
energy supply efficiencies, local job creation and the reduction in associated greenhouse gases this option should
be considered for all energy demand scenarios.
Municipal pilot projects
The gas pilot projects for municipal gas powered trigeneration hospital and CNG run buses could be supplied
from increased local landfill gas production or from the spare capacity in the lily pipeline.
The low demand option would require little municipal intervention and relatively low upfront costs and as such
the gas initiatives and negotiations should start immediately.
1.11.2 Medium Demand: gas makes up 5% to 10% of the energy mix in eThekwini Municipality
Municipal fleet conversion
The area where the municipality can have gas demand control over is through the switching of supply from
conventional energy sources to gas in their buildings and transport fleet. If the entire municipal transport fleet
was changed to gas it would change the energy mix by one half percent.
The conversion of buses and Heavy Duty Vehicles (HDV) will be cost effective assuming a gas price differential
of 20% or more is maintained below conventional fuels. Bus fleet conversions, even with the upfront capital
costs of R250,000 per vehicle, have globally been economically viable. Where necessary the municipality will
need to adapt depots to supply compressed natural gas.
Advocacy and influence transport users
The introduction of CNG into the municipal fleet will lead to opportunities for local business to convert NGVs,
construct CNG refuelling depots on behalf of the municipality, as well as provide a launch pad for companies to
set up CNG refuelling stations as the municipal fleet conversion has created a critical mass for future industry
development. The infrastructure both private and public can be used to encourage conversion of LDV, buses
and taxis to CNG.
Passenger vehicles account for 44% of the energy demand in the municipality of which 22% is associated with
public transport (57% taxis, 42% buses and 1% rail). The entire energy mix has taxis with 5.5%, buses with 4%
and commercial transport with 4%, making up around 14% of the entire energy mix that could convert to gas if
the incentives and reasons for change were persuasive, such as proven viability of the NGV over its lifespan, fleet
subsidisation or route licences being dependent on a percentage of the fleet switching to gas. The municipality
could therefore influence the uptake of gas through education, linking licences and other initiatives as every 8%
uptake in the public passenger sector changes the municipality energy mix by 1%.
Municipal buildings to be powered on natural gas
If all the municipal buildings were being powered from gas this would shift the municipalities’ energy mix by
almost one percent. The municipality would need to decide the percentage of its buildings that need to be
converted to gas. A particular focus will be on buildings with a large energy use that will can benefit from tri-
generation technology and be economically viable. Low energy use buildings will not have the same energy
saving and cost saving benefits.
The conversion of municipal buildings and the municipal transport fleet would require realistic targets and
deadlines to be set.
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Domestic, industrial and commercial use
Another area of influence is for the municipality to encourage the use of gas by some domestic, industrial and
commercial customers, through advocacy, encouraging traders, providing reticulation infrastructure and
suitable bylaws.
For the medium demand scenario to happen the municipality would need to commit to targets such as that all
buses, taxis and LDV in the municipal fleet must run on gas by 2025, public transport operator licences depend
on a percentage of their fleet running on natural gas and other such initiatives, etc.
The increased demand for gas driven by the municipal strategies would need to be supplied by an increase in
gas from landfill and wastewater sludge production and an increased supply from the Lily pipeline. This extra
gas could be provided by Sasol via Secunda or CBM production supplying gas into the Lily pipeline.
1.11.3 High Demand - gas makes up more than 10% of the energy mix in eThekwini Municipality
The main area that the municipality could have a significant effect on the municipalities’ energy mix is associated
with large infrastructural natural gas projects. The projects would require the construction of CCGT/OCGT or
gas engine power stations that get supplied by gas from new gas pipelines from Mozambique via Secunda or
Richards Bay or from LNG shipments via a new LNG import terminal at Richards Bay.
These supply options are dependent on large off-take agreements to justify the associated infrastructure
investment costs. It is unlikely that the Municipality will be able to guarantee this off-take on its own.
Recent government policies have indicated that LNG import facilities will be needed in the short to medium term
to meet the IRP2010 revised power production targets. The municipality needs to motivate and develop an
integrated energy plan which justifies the development and platform for long term strategic investments which
include entering into gas supply offtake agreements. An LNG import terminal could cost anything between R3
billion and R5 billion and therefore without at least one large guaranteed offtake agreement this project will not
happen.
Gas power generation
The municipality has three main gas power generation options. The first option is to have a private partnership
agreement (off takers) with an IPP to supply gas to the municipality via its own reticulation or Eskom network,
an example could include an arrangement with the DoE Avon peaking power station running on gas or via a
completely newly constructed power station.
The municipality could alternatively build and operate its own power plant or thirdly build and outsource the
management of gas power stations. These large infrastructure power plant infrastructure projects would
provide an opportunity for the municipality to be more self-sufficient, diversify the energy mix and manage or
reduce rolling blackouts and the effect they have on the local economy. The gas to power options will allow the
municipality to reduce its GHG emissions while still achieving revenue targets through the reticulation of gas to
end users. It has been estimated that gas engine power plants (GEPP) will cost around R14 million rand per MW9
(which is about almost 2.5 times less per MW than Medupi). The advantage of gas power stations is that they
can be built in modular units and in significantly less time that coal or nuclear power stations. Assuming that
the municipality electricity need is likely to increase from 12 GW to 19GW between 2010 and 2030 every 100MW
GEPP that the municipality directly sources its power from will increase the gas in the energy mix by around
0.5%.
9 Sasol cost for The Sasolburg Gas Engine Power Plant opened in July 2013
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Large scale business gas uptake for power and heat applications
Large energy users switch to gas as a source for power and heat generation. This may also come from other
intensive energy users outside the municipality such as the aluminium smelters at Richards Bay. The large
increase in demand and the related infrastructure would be expected to be paid for by the associated industries
or traders supplying the gas.
1.12 Overall Conclusion
Guaranteed supply of gas in significant volumes is a prerequisite for increased gas utilisation. If available, this
could provide an incentive for business to start powering their business or generating heat from gas.
Unfortunately this could reduce the revenue the municipality receives from selling power to the end consumer.
The loss of this revenue stream should be assessed next to the increased competitiveness of these businesses,
the reduced strain on power generation on the Eskom network and the associated costs and loss of revenue
from rolling blackouts.
It is unlikely at present that GTL or petrochemical production will occur in KZN due to the high costs and
competitive advantages of Sasol and PetroSA.
Gas should be incorporated into an integrated energy plan taking into account the flexibility of gas as a baseload
or peak power supply, as well as other utilisation options. Natural gas creates a number of other unique
opportunities to the eThekwini Municipality with long term savings to its own fleet, more efficient buildings, the
development of a more competitive advantage to local business, creating a business case for the port to be
greener with LNG fuelled vessels and infrastructure and a local market which could create a conducive case for
offshore exploration.
The balancing of long term strategies compared to capital cost outlay and reduced revenue must be assessed
on all options going forward. It should also note that the lead time of 2-4 years for most large infrastructure
developments must be taken into account.
The substitution of natural gas for other fossil fuels is not the only way for the eThekwini Municipality to address
climate change and meet the targets set at COP17, because natural gas is a fossil fuel and its combustion emits
greenhouse gases and the LCA may indicate that for certain applications it may not be cleaner. The GHG
emissions associated with LNG are generally higher than piped natural gas. Fugitive emissions along the pipeline
may however increase the GHG emissions profile of piped gas. The NETL Life Cycle Greenhouse Gas Perspective
on Exporting LNG from the US summarised in the table below, shows how methane leakage over an extra
4000Km of pipeline increases the total GHG emissions to almost the same level as an LNG shipment.
Scenario Energy Input
Mj/Kg CO2 CH4
Other
GHG
Total GHG Emissions 100yr
GWP (kg CO₂e/MWh)
Natural gas along a 5000Km
European pipeline 55.5 74.8% 24.6% 0.6% 194
1000Km USA domestic pipeline
followed by LNG export to Europe 54.3 85.5% 13.8% 0.7% 211
Table 6: LNG vs Natural Gas pipeline comparison (Source NETL 2014)
The municipality should prioritise a number of projects that they can directly control and monitor cost savings
and efficiencies, such as:
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Pilot schemes with the purchase and introduction of compressed natural gas buses;
Convert major public hospitals to tri-generation; and
Increase natural gas production from Landfill and wastewater sites.
In regards to natural gas on a larger scale and the possible influence the municipality can have on the local
energy mix and socio economic development it must be assumed that natural gas is the only feedstock that
could provide significant amounts of power in the municipality. The municipality must therefore evaluate and
lobby for gas power generation in the province.
As part of the integrated development plan the energy mix, security of supply, local economic development and
greenhouse gas emissions options need to be tied and evaluated against different options so that long term
strategic goals are met.
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2 Natural Gas
2.1 Introduction
This section explains what natural gas is, provides an overview of the various parts of the value chain and the
types of natural gas available to the market.
2.2 The natural gas value chain
Figure 9: Natural gas value chain (Source PwC)
Natural gas can be confusing to understand as the terminology and measurement of natural gas is different
depending where it lies in the value chain with reserve volumes, gas volumes produced or consumed, sales and
billing measures are all different. Table 6 provides a high level terminology for gas.
Imperial Metric Conversion Factor
Reserves - Volumes Trillion cubic feet (tcf) Billion cubic metres (bcm)
28.317
Gas volume produced or consumed
Million cubic feet (MMcf), sometimes written as million standard cubic feet per day MMscfd. Sometimes known as “scuffs”
Billion cubic meters per day (bcmd)
35.494
Sales (not in volume) - unit of energy – heat energy released on combusting gas.
British thermal units (Btu) Kilojoules (KJ), and kilocalories (kcal)
1.055
Billing End user’s gas meters measures the volume of gas delivered. This volume is converted, using average calorific value per volume factor, into energy units consumed by the end user and multiplied by the price per unit.
M =1 000, MM = 1 000 000 – Roman numeral system – can be upper or lower case
Table 7: Natural gas high level terminology (Source PwC)
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Appendix B provides more natural gas conversion factors and measurements.
The value of 1tcf of gas, if produced in full and sold at $10/MMbtu is US$10 billion.
The gas industry can be confusing with varying in place volumes quoted for the same field. Companies will often
quote contingent resources or probable reserves, whereas industry sources will state reserves with an estimated
higher level of commercialisation and resource certainty, usually P90.
Figure 10: Reserve and production in place diagram (Source PwC)
The analysis of geologic and engineering data, the using of existing technology and equipment under the existing
operating conditions will determine the resources or reserves classification. Operating conditions includes
operational break-even price, regulatory and contractual approvals are often required for proven reserves
otherwise they are usually classified as probable. Price changes, regulatory and contractual conditions may
change and affect proven reserves amounts.
Technically recoverable reserves are those that are producible using current technology, although they may not
be economical in the current condition. The below diagram provides an understanding of reserves and resource
classification and the effect that commercialisation and certainty of the resources has on their classification and
reported volumes.
2.3 Different forms of Natural Gas
Natural gas distribution to the end user is primarily as methane natural gas (NG), although it can also be supplied
as CNG and LNG.
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2.3.1 Compressed Natural Gas (CNG)
CNG is not a new technology, having been in the market for over 70 years. It is widely proven and its
technological advances are constant.
CNG is made by compressing natural gas, composed primarily of methane, to less than 1% of the volume it
occupies at standard atmospheric pressure. It is stored and distributed in hard containers at high pressures of
200–275 bar (2900–4000 psi), usually in cylindrical or spherical shapes.
CNG is sometimes confused with LPG, which is liquefied propane and butane that can be compressed into a
liquid without continual refrigeration.
Compressed gas can be delivered to customers at a pipeline network or delivered to sites in compressed units
often known as a virtual pipeline.
Compressed gas is most commonly associated with natural gas pipelines and the compression of the gas near
the end user, however this is changing with players with small gas reserves near the market looking at
compressing the gas and distributing the gas via a virtual pipeline. This could be of particular interest for landfill
gas and coalbed methane reserves in South Africa.
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A view of the CNG Downstream value chain
The diagram below indicates the main types of CNG distribution after natural gas has entered a gas distribution pipeline.
Figure 11: Compressed Natural gas distribution network (Source PwC)
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CNG Stations
For transportation of natural Gas along pipelines within cities (Johannesburg – Egoli Gas) it is pushed at a
pressure of around 15 bar or even lower. For the gas to be dispensed to CNG vehicles, there are CNG stations at
various locations, where the gas is being compressed up to 250 bars initially and then dispensed to vehicles at a
pressure of 200 bars. Typically there are a number of types of CNG stations found around the world:
Online Station
Online stations are directly connected with the Natural Gas pipeline and receive gas at a relatively low
pressure of 15-20 bar and then compress it up to 250 bars with the help of a reciprocating compressor.
The pressure enhances the on board storage capacity of vehicle and this is then dispensed to vehicles
locally through CNG fuel stations dispensers at a pressure of 200 bars. Typically a CNG Online Stations
consists of following equipment:
1. CNG Compressor;
2. CNG Dispenser; and
3. Storage Cascade.
Mother Station
Mother stations are directly connected to the Natural Gas pipeline and are similar to an online station,
where it has the facility to refuel the mobile cascades which can be used on site or transported to other
site that are not connected to the natural gas pipeline. The sites can also be a retail site that dispenses
CNG directly vehicles to meet the local demand.
Daughter Station
Daughter stations do not have the connectivity to natural gas pipelines. At these stations CNG is
transported through mobile cascades (bunch of cylinders mounted on trucks) at a pressure around 250
bar and then dispensed to vehicles through CNG dispensers. CNG is made by compressing natural gas
composed of primarily of methane, to less than 1% of the volume it occupies at standard atmosphere
pressure It is stored and distributed in hard containers at high pressures of 200–275 bar (2900–4000
psi), usually in cylindrical or spherical shapes.
Daughter Booster Station
Daughter booster stations are similar to Daughter stations. However once the pressure of a mobile
cascade drops below 200 bars the customers get a lesser amount of gas and increased filling times. To
ensure that customers are not inconvenienced a booster compressor is installed in between the mobile
storage and the CNG dispenser. The booster compressor increases the pressure above 200 bar
maximises the amount of gas stored in the mobile cascade at the Daughter Booster stations.
CNG Trends
The main use of CNG is an alternative for petrol and diesel for normal vehicles (about 20.1 million NGVs exist
worldwide at the end of August 2014) (NGV Journal 201410) and is a growing around the world. CNG is the main
alternative fuel for land based natural gas vehicles.
CNG Vehicles are increasingly used in the Asia Pacific region, Europe, North and South America.
10 The number of NGV that exist varies from 15 -20 depending on industry source data
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The cost of this conversion has been a barrier for CNG use. Public transportation vehicles such as buses and taxis
are early adopters, as the payback period is quick as the increased investment is recovered in lower fuel prices,
typically around 30%. Due to cheaper fuel prices and the cleaner nature of CNG compared to traditional fuels
the market has been steadily increasing.
Navigant Research forecasts that the number of Natural Gas Vehicles (NGVs) on roads worldwide will reach 34.9
million by 2020. NGVs are fuelled by Natural Gas that has been either compressed (CNG) or liquefied (LNG). CNG
can be used for all vehicle weight classes, while LNG vehicles are limited to heavy-duty trucks because of the size
and cost of the storage equipment.
2.3.2 Liquefied natural gas (LNG)
Liquefied natural gas or LNG is natural gas (predominantly methane, CH4) that has been converted to liquid form
for ease of storage or transport. LNG is natural gas that is condensed into a liquid by cooling it to approximately
−162 °C (−260 °F) at close to atmospheric pressure (maximum transport pressure set at around 0.25 bar (3.6 psi).
As LNG takes up 1/610th the volume of natural gas in the gaseous state it is an alternative method to transport
methane from the producer to the consumer.
Gas is measured in (M3 or Ft3), but once it is converted into LNG, it is measured in mass units, usually tons or
million tons. (MMT, however the LNG industry generally uses MT to represent million tons).
LNG is generally part of the midstream sector of the natural gas value chain as it is an efficient way to transport
natural gas long distances to the downstream markets in a safe and efficient manner.
There are two types of LNG terminals: 1) terminals that convert natural gas into LNG, and, 2) terminals that
convert LNG back into natural gas. These are called liquefaction terminals and regasification terminals,
respectively. Liquefaction terminals are on the export side of transactions and regasification terminals are on
the import side of transactions.
LNG ship sizes are specified in cargo volume (typically, thousands of cubic meters), and once the LNG has been
reconverted to gas, it is sold by energy units (in millions of British thermal units, MMBtu).
LNG receiving terminals receive, store and re-gasify LNG and are either land-based (LNGT) or floating (FSRU).
An LNG train is a LNG plant's liquefaction and purification facility. The facilities usually consist of more than one
train. The output of most LNG trains is 5 mtpa (Million Metric tonnes per annum). An LNG facility producing 5
mtpa requires 243.5 bcf (6.90 bcm) of natural gas per year, equivalent to 666 MMcfd. This facility would require
recoverable reserves of approximately 5 tcf over a 20-year life. Each LNG plant consists of one or more trains to
compress natural gas into liquefied natural gas. A typical train consists of a compression area, propane
condenser area, methane and ethane areas.
A typical LNG process involves the extraction of natural gas transportation to a processing plant where it is
purified and impurities removed before the gas is cooled down in stages until it is liquefied into LNG. The LNG
is then stored in storage tanks, prior to being loaded onto LNG carriers and shipped to a distant destination
where it is offloaded and regasified (sometimes known as vaporised) back from LNG into natural gas where it is
sent by pipeline for distribution or placed in storage until it is needed.
33 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
A view of the LNG Value Chain
Figure 12: Liquefied natural gas value chain (Source PwC)
34 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
A typical LNG process involves the extraction of natural gas transportation to a processing plant where it is
purified and impurities removed before the gas is cooled down in stages until it is liquefied into LNG. The LNG
is then stored in storage tanks, prior to being loaded onto LNG carriers and shipped to a distant destination
where it is offloaded and regasified (sometimes known as vaporised) back from LNG into natural gas where it is
sent by pipeline for distribution or placed in storage until it is needed.
LNG as a transport fuel
LNG is in the early stages of becoming a fuel used in road transportation and is still in the infancy of being
evaluated and tested for on and off-road trucking, marine, and train applications. For large truck transportation
China and the US lead the way. Train applications could potentially have significant fuel cost savings benefits,
however most projects are in the evaluation process.
Marine LNG transportation is becoming popular with shipping companies’ switch fuels from HFO or build new
LNG powered vessels so that strict international emission standards and targets can be met.
LNG Transportation
LNG is usually transported to the gas consumer by specially designed refrigerated ships. The ships operate at
low atmospheric pressure (unlike LPG carriers, which operate at much higher pressures), transporting the LNG
in individual insulated tanks. Insulation around the tanks maintains the temperature of the liquid cargo, keeping
the boil-off (conversion back to gas) to a minimum. Because older ships do not have active refrigeration systems
on-board, ships use the produced boil-off gas as engine fuel. On a typical voyage, an estimated 0.1%–0.25% of
the cargo converts to gaseous phase daily.
Images 2: LNG Carrier (Source Seaspout-Alternatives to bunker fuel – LNG)
At present many LNG plants have their own dedicated fleet of LNG ships, operating a “virtual” pipeline. As a ship
is being loaded, a sister ship may be discharging its cargo, and the remaining members of the fleet are either en-
route to the buyer’s regasification facility or on the way back to the LNG plant to pick up new cargo.
Floating LNG facilities (FLNG) may be quickly moved between fields and produce gas sooner than would
otherwise be possible. Numerous concepts for floating LNG facilities have been developed along lines similar to
Floating Production, Storage and Offloading (FPSO) facilities which are now commonplace for oil production.
This allows for transportation of LNG directly from offshore facilities.
35 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
The final phase LNG value chain is the regasification terminals / facilities
LNG receiving terminals receive LNG marine vessels and store the LNG until it is required where upon it vaporised
back into methane gas and put into the local natural gas pipeline grid. The main components of a regasification
facility are:
The offloading berths and port facilities;
The LNG storage tanks;
The vaporisation process equipment to convert the LNG into gaseous phase; and
The pipeline into the local gas grid.
LNG tankers have a number of ways to offload LNG to onshore land-based regasification facility:
The most conventional method is from a berth via a fixed arm linked to an onshore facility;
Offshore away from congested and shallow ports a floating mooring system (similar to that used for
petroleum imports at Durban Harbour) via undersea insulated cryogenic LNG pipelines to an onshore
facility;
Ship-to-ship LNG. The smaller ship will berth in the port and discharge to onshore facilities or convert
LNG on-board to methane gas and pump directly into the local grid; and
LNG can also be pumped directly in to cryogenic trucks and transported locally to areas without access
to the natural gas pipeline, or can be used as a way to not occur pipeline tariff costs.
Offloaded LNG is stored in storage tanks either above ground or semi-buried, until gas is required by consumers.
Semi-buried tanks, which can be spaced closely together, are most common in Japan, where land is scarce. LNG
can also be stored on modified LNG tankers that have regasification units on board which provides the ship the
ability to discharge gas directly into the local pipeline grid. These facilities are usually known as floating and
regasification Unit (FSRU).
LNG Trends
There are presently 29 countries that export LNG with another 10 countries planning or construction LNG
producing plants. (Petroleum Economist 2014).The number of buyers and sellers is increasing and the last
decade has seen phenomenal growth in the LNG trade and this growth that is expected to continue unabated
this decade. Until recently economies of scale in LNG projects was significant as newer LNG plants were being
built with larger, more efficient trains, and, in the case of adjoining plants (such as in Qatar) have shared facilities,
thereby minimizing unit costs. Rising demand for steel and nickel, and high demand for engineering resources,
are blamed for the reversal in the long-term declining cost trend. The increase in costs and changing LNG market
prices may reduce the development of LNG export terminals.
The decision to commercialize a gas field and transport it as LNG is based on a number of factors which will
provide an indication that it will be viable:
If the distance is at least 2000 Km to 3000 Km then LNG is more viable than transporting the natural
gas by pipeline;
The gas field contains at least 3 tcf to 5 tcf of recoverable gas;
Gas production costs are less than $5/MMBtu when delivered to the liquefaction plant;
The gas contains minimal other impurities, such as CO2 or sulphur;
A marine port where a liquefaction plant could be built is relatively close to the field;
The political situation in the country supports large-scale, long-term investments;
Certain and known tax regulations in export country;
The market price in the importing country is sufficiently high to support the entire chain and provide a
competitive return to the gas exporting company and host country; and
36 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
A pipeline alternative would require crossing uninvolved third-party countries and the buyer is
concerned about security of supply.
2.4 Environmental Impact
The substitution of natural gas into the energy mix and the substitution of “dirtier coal” will have the largest
improvement on the environment whether it is used in power generation, thermal or cooling applications.
We have described the environmental benefits of natural gas as a transportation fuel earlier. Additional
environmental benefits that natural gas has over conventional transportation fuels include:
We have described the environmental benefits of natural gas as a transportation fuel earlier. Additional
environmental benefits that natural gas has over conventional transportation fuels include:
Leakages go into the air and will not pollute the groundwater or sea;
Gas is non-corrosive so pipelines require low maintenance or replacement;
Lower noise pollution than petrol and diesel engines;
Biogas production from agricultural goods yields four more times per hectare than liquid biofuels;
Lowest usage of land per MW than all other fuels except nuclear - small footprint; and
Gas power stations require relatively low levels of water and produce very little waste.
The environmental impact of the natural gas exploration, production and processing will cause methane to be
discharged into the atmosphere. Depending on the type of exploration, how the gas is transported and in what
medium the environmental effect will vary.
The effect on climate change will be discussed later although due to methane emissions along the entire LCA
natural gas vehicles can be assumed to have a similar GHG emission footprint to transportation run on
conventional fuels.
2.5 Climate Change mitigation risk opportunities
The introduction of gas in the energy mix and the substitution of coal will mitigate against climate change as
research indicates that coal combustion produces 2 times more carbon dioxide, 5 times more carbon monoxide,
5 times more nitrogen dioxide, and more than 1000 times more sulphur dioxide and other particles.
(Environmental Protection Agency, 2014)11 Natural gas production, processing and transportation, including
methane leakage (fugitive emissions), must be included into the GHG equation as it is higher when compared to
the mining and transportation of coal. Internationally the reduction in GHG over the LCA is around 40% less of
KgCO2e per MMBtu.
When assessing industrial, commercial and domestic demand the majority of the consumption and greenhouse
gas emissions are from the direct usage of electricity powered from the grid. Energy consumption for power
and heating is generally from coal so a similar assumption of at least 40% reduction occurs with switching to gas.
Transportation fuel switching does not necessarily have a climate change mitigation benefit as recent LCA
studies calculate that the processing and methane leakage along the value chain mean that petrol and diesel
engines vehicles produce the same greenhouse gas emissions. The actual combustion of the natural gas,
however create far lower COx, NOx, SOx and particle emissions so local air quality would improve. The pros and
cons of diesel, petrol and natural gas are further complicated by improving engines for all fuel types. With
11 EPA information broken down from US Average emission rates
37 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
greater control over the upstream and midstream gas sector, methane leakage can be reduced which would
then create a case for NGV reducing climate change.
For ocean going vessels it has been calculated that LNG will be the dominant fuel source as it and marine gas oil
(MGO) replace heavy fuel oil (HFO), due to lower emissions and reduced GHG emissions along the value chain
estimated at about 3%.
One of the main reasons that gas is seen as a source of energy that will mitigate climate change is that it is seen
as a “transitional” source that can be used pending the evolution of cleaner energy and renewable generation
technology.
Gas is a flexible source of power plants that can provide short-duration load, or pulse loads to support renewable
energy sources when they are not operating optimally.
2.6 How does natural gas affect the Greenhouse Gas profile of a region
Natural gas affects the profile of the GHG emitted in an area, by either increasing or decreasing the amount of
emissions based on different technologies and fuel sources used. There are benefits and disadvantages of
natural gas combustion compared to conventional fuels. Natural gas on combustion produces very small
amounts of sulphur dioxide and nitrogen oxides, virtually no ash or particulate matter, and lower levels of carbon
dioxide, carbon monoxide, and other reactive hydrocarbons. However due to methane leakage natural gas is
not necessary the environmentally friendly alternative to conventional fuels if the entire life cycle analysis is
taken into account. If natural gas was used to generate more electricity within the eThekwini Municipality, this
would cause a shift of some emissions from Scope 2 (consumption) into Scope 1 (direct consumption). This
could result in public health implications due to increased emissions and poorer air quality.
Figure 13: Scope 1 to Scope 3 emission diagram (Source PwC)
Fuel Consumption
(Stationary and Mobile fuel
combustion)
Solid Waste
Industrial processes and
Product use
Agriculture and other Land
use
Transport System
(Air and water transport
systems)
Consumption of purchased
electricity, heat, steam and
cooling by residential,
commercial and industrial
Scope 1: Direct Scope 2: Energy
Indirect
Scope 3: Other
Indirect
38 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Global Warming Potentials of Methane and CO2
On a per-mass basis, methane is more effective at warming the atmosphere than CO2. This is represented by
methane’s global warming potential (GWP), which is a factor that expresses the amount of heat trapped by a
pound of a greenhouse gas relative to a pound of CO2 over a specified period of time. GWP is commonly used
to enable direct comparisons between the warming effects of different greenhouse gases. By convention, the
GWP of CO2 is equal to one. The GWP of a greenhouse gas (other than CO2) can vary substantially depending
on the time period of interest. For example, on a 100-year time frame, the GWP of methane is about 21.43 But
for a 20-year time frame, the GWP of methane is 72.44 The difference stems from the fact that the lifetime of
methane in the atmosphere is relatively short, a little over 10 years, when compared to CO2, which can persist
in the atmosphere for decades to centuries.
Emissions from Natural Gas Combustion
On average, natural gas combustion releases approximately 40% less CO2 than coal and about 20 % less CO2
than vehicle transport fuels per unit of useful energy In addition, the combustion of coal, and other fuels emits
other hazardous air pollutants, such as sulphur dioxides and particulate matter. Therefore, the burning of natural
gas is considered cleaner and less harmful to public health and the environment than the burning of other
hydrocarbons.
Figure 14: GHG emission factors for fossil fuels (Source DEA, 2014)
When assessing the GHG emission factors for combustion only then natural gas is the cleanest burning
conventional fuel. The g CO2/ MJe or lbs/106 Btu emitted from various fuel types does vary depending on where
the source of information is obtained, however the overall variance is similar. The below figure provides an
indication of the GHG emission factors and relative comparisons with each conventional fuel type based on
figures used by the department of the environment.
GHG Emission factor Combustion variance between fuel types
Fuel Type (g C02/ MJe) Natural Gas LPG Petrol Diesel Heating Oil Sub-bituminous coal
Natural Gas 56 0% 13% 23% 32% 38% 71%
LPG 63 -11% 0% 10% 17% 22% 52%
Petrol 69 -19% -9% 0% 7% 12% 39%
Diesel 74 -24% -15% -7% 0% 4% 30%
Heating Oil 77 -27% -18% -10% -4% 0% 25%
Sub-bituminous coal 96 -42% -34% -28% -23% -20% 0%
Table 8: GHG emissions factors for fossil fuel (Adapted from DEA report)
5663
6974 77
96
Natural Gas LPG Petrol Diesel Heating Oil Sub-bit. coal
GHG Emission factor for fossil fuel combustion (g C02 equivalent per Mj)
39 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
The EIA Fossil Fuel Emission levels clearly indicate that Natural gas in all aspects of its burning is cleaner than
other fuels when used for power generation.
Pollutant Natural Gas Fuel Oil Coal
Carbon Dioxide (lbs/106 Btu) 117,000 164,000 208,000
Carbon Monoxide 40 33 208
Nitrogen Oxides 92 448 457
Sulphur Dioxide 1 1,122 2,591
Particulates 7 84 2,744
Mercury 0.000 0.007 0.016
Table 9: Fossil fuel emission Levels (Source EIA)
There are clear advantages for natural gas power generation, however consideration of the environmental
impacts of the natural gas life cycle analysis and methane and hydrocarbon leakage to the atmosphere need to
be taken into account when assessing the benefits of using natural gas. A number of studies exist although
consensus and more comprehensive quantification may be required.
40 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
3 Global Environment
3.1 Global Trends
This section of the report provides an overview of global trends in the natural gas industry, providing insight into
discoveries and reserves, supply and demand, pricing and LNG capacity.
Over the last two decades the proven reserves of gas has increased every year with an increase of 32% between
1993 and 2003 and 19% between 2003 and 2013 as noted in the figure below. This trend can be expected to
continue.
Figure 15: Proven natural gas reserves (Source BP Statistical Review of World Energy 2014)
Approximately 75% of the proven natural gas reserves are present in the Middle East and in Russia.
Although the reserves continue to increase, the rate of change decreased over the last decade. In 2013 the
number of discoveries over 500 million BOE was half that of 2012.
It has been generally disappointing for exploration in the last few years, however bucking this trend in particular
is East Africa which accounted for around 40% of all volume additions during 2013 and 2014. Africa has been a
shining light with large conventional discoveries accounting for 6 of the top 8 biggest discoveries in 2013 and 6
of the top 9 estimated discoveries in the first half of 2014 as noted in Table 10 and 11 below.
Ranking of 2013
discoveries Discovery Country Company
Est. by Tudor,
Pickering
(BOEs)
Type of find
1 Agulha & Coral Mozambique Eni 1 400 million Gas
2 Lontra oil Angola Cobalt International
Energy
900 million Oil
4 Ogo Nigeria Afren/Lekoil 850 million Oil
5 Nene Marine Congo Eni 700 million Oil, gas,
condensate
6 Tangawizi Tanzania Statoil 575 million Gas
8 Salamat Egypt BP 500 million Gas
Table 10: The most significant oil and gas discoveries in 2013 (Source Forbes 2013)
0
20
40
60
80
100
120
140
160
180
200
1980 to 2013
Proven natural gas reserves tcm
Asia Pacific
Africa
Middle East
Europe & Eurasia
Latin America
North America
3% 4%
4%
41 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Ranking of
discoveries in
2014
Discovery Country Company Type of find
1 Nyonie Deep 1 Gabon Eni Gas, condensate
2 Pin1 Tanzania Statoil Gas
3 Tubanao Tigre1 Mozambique Anadarko Gas
4 Bicuar 1 Angola Cobalt International Oil, gas, condensate
7 Taachui 1st Tanzania BG group Gas
9 Nocrus 1 Egypt BG Egypt Gas
Table 11: Significant gas discoveries in 2014 (Source IHS 15/10/2014)
New finds across all regions of Africa has heightened the spotlight on the continent and governments have been
trying to cash in on the positive sentiment by making further acreage available in numerous bidding rounds.
The African gas output has grown by 10% a year in the last decade. Most of this has been exported by Nigeria, Algeria,
Equatorial Guinea and Mozambique via LNG ships or NG pipelines. The volumes of exports are set out in the table
below:
Gas Exports Algeria NG Algeria LNG Equatorial Guinea LNG Nigeria LNG Mozambique NG
France 5.3
Spain 11.4 3.2 3.1
Turkey 3.8
Italy 11.4
Other Europe 2.0 1.1 3.8
Japan 0.6 3.0
Other Asia Pacific 0.6 2.1
South Africa 2.9 Table 12: Highlighted African gas exports 2013 (source BP Statistical Review of World Energy 2014)
Egyptian LNG supply was used to supply only the local market and in Angola technical difficulties restricted exports in
2013. Sub-Saharan African output will double in the next 6 years once Angola resolves their technical difficulties and
Mozambique and Tanzania start to export LNG from 2020. The new Sub-Saharan supply could provide the increased
natural gas that South Africa demands. East Africa accounted for around 40% of the volume additions in 2013 in an
otherwise disappointing year for gas exploration.
42 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 16: East Africa 2013 discoveries (Source Rystad Energy, Booz & Company analysis 2013)
The Oil & Gas Journal in January 2014 raised Mozambique’s proved natural gas reserves to 100 tcf, up from 4.5
tcf in 2013. If one considers ENIs estimated reserves of 85 tcf in block 4 and Anadarko’s 70 tcf the country has
155 tcf –P50 offshore reserves. The Sasol Pande & Temane onshore proven reserves are 4.5 tcf. This places
Mozambique as the third-largest proved natural gas reserve holder in Africa, after Nigeria and Algeria. (Figure
17 below).
ENH, the Mozambique national oil company, has indicated the country could have reserves up to 250 tcf which
would if proven would make it the country with the largest natural gas reserves in Africa and 7th largest in the
world.
In Figure 17 below indicates where Mozambique could possibly sit in terms of gas reserves in the world, based
on various sources.
43 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 17: Proven gas reserves in Mozambique (Source BP, ENH, EIA and OGJ 2014)
Since 2010 the proven reserves in Mozambique have steadily increased with the Anadarko and Eni led
consortiums having made significant discoveries in Areas 1 and 2 of the Rovuma Basin. Mozambique is estimated
to have reserves that are already in the top 5 countries for non-associated gas that can be easily monetised.
Despite the uncertain regulatory framework around LNG, PTT of Thailand has signed an agreement with
Anadarko to receive cargoes in 2020 from the 20 mtpa planned joint Anadarko-Eni LNG project.
At present Sasol is the only producer and exporter of gas via the ROMPCO pipeline to South Africa. Sasol has
sufficient proven reserves to supply the South African market with 120 million GJ p.a. plus 5% royalty gas for
Mozambique for around-30 years. There is a possibility that the exported capacity could be increased slightly
via this 864Km pipeline or another muted pipeline that could run next to the existing pipeline or a new pipeline
from the North of Mozambique all the way down to Richards Bay.
In Tanzania the BG and Statoil consortiums, with offshore Blocks 1, 2, 3 and 4, have indicated that 2 onshore
LNG, 10 million tonnes/year plants will be required, but it will only be operational in 2020.
The new trend in Southern and East Africa is to use natural gas to increase power generation such as the case in
Tanzania where a 542Km pipeline from Mtwara to Dar es Salaam will be completed in December 2014 and
increase the gas power generation from 40% to 80%. Tanzania has stated that they will supply the domestic
market prior to LNG exporting.
3.2 Global Demand and Supply
Gas is likely to become a more prominent source of energy as it becomes the preferred non-renewable energy
source in the world replacing less clean conventional hydrocarbon sources. As countries move away from the
conventional fuels of oil and coal to greener alternatives gas will continue to benefit from this switching. Gas
consumption is projected to increase by 50% in 25 years. Much of this increase is due to the anticipated growth in
the use of natural gas for power generation as countries take advantage of the cleaner-burning properties of this fuel.
Natural gas consumption is expected to grow considerably faster in developing countries than consumption in the
developed world.
Gas is transported to the markets in two main ways via natural gas pipelines or via LNG carriers. Figure 18 below
indicates the source of supply of gas consumed by regions around the world.
0
200
400
600
800
1000
1200
Proven Gas Reserves tcf (In relation to Mozambique's possible options)
44 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 18: Natural gas trade 2013 by pipeline and LNG (Source (BP Statistical Review of World Energy 2014)
The largest consumer of traded natural gas is Europe with 51%, followed by Asia-Pacific with 28% and North
America with 15%.
The source of supply varies substantially with Europe consuming 68% of the piped gas and North America 17%,
whereas LNG is predominantly consumed by the Asia-Pacific regions with 73%, followed next by Europe which
consumes 16%.
Overall 93% of the total, piped and LNG gas supplied to the world is traded and consumed in Europe, Asia-Pacific
and North America.
Figure 19: Natural gas global trading routes (Source BP Statistical Review of World Energy 2014)
91% 49% 90% 85% 100% 19% 69%
9%
51%
10% 15%
81%
31%
North America South &CentralAmerica
Europe Middle East Africa Asia Pacific
2013 Natural gas trade in bcm and pipeline and LNG regional split
Pipeline imports LNG imports
135 38 532 29 6 294 1,036 bcm
45 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Africa consumes less than 1% of the traded gas supplied to the world, although it produces and supplies 8% of
the global demand which accounts for 5% of the natural piped gas and 14% of the LNG. 12
The Pacific Basin is the largest consuming region importing 73% of the world trade. This is up from 69% in 2012 with
Japan and South Korea importing over 50% of the world LNG supply (37% and 17% respectively). The demand in
Europe for LNG dipped for a second year in a row with LNG imports down from 21% in 2012 to 16% in 2013 due to
weakness in the Eurozone economies and the higher prices that can be obtained by exporters on the spot and Japan
gas traded markets.
Country 2012 2013 % Change
Japan 37% 37% ≠ 0%
South Korea 15% 17% ↑ %
China 6% 8% ↑ %
Spain 6% 5% ↓ %
United Kingdom 4% 3% ↓ %
Table 13: Top global LNG importers 2012 and 2013 (Source Petroleum Economist 2014)
China has emerged as a net importer of natural gas and with a number of import terminals under construction
this is likely to continue, although the country intends to emulate the US and develop a thriving shale gas sector
that would be able to supply the countries increasing demand for natural gas. India is also expected to increase
its demand for LNG.
2013 could be considered a transition year as LNG traded volumes remained largely the same and only increased
by 0.3%, but new trading patterns started to emerge. Total production increased marginally due to unplanned
outages in Angola, Nigeria and Norway, political unrest especially in Egypt where priority was given to domestic
consumption. New facilities opened in Angola and Algeria.
Regionally the gas export traded looks somewhat different to the import profile. The largest supplier of traded
natural gas is Europe with 48%, followed by the Middle East with 16%.
12 LNG statistical data is a combination of BP and Petroleum economist data interpreted by PwC
46 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
The table below indicates which countries export LNG, what LNG facilities are under construction and likely to
be operational by 2018:
Country
Existing LNG
Export
Capacity 2013
Under
Construction
Total LNG Export
capacity
after construction
LNG export
capacity
2013
Country
Ranking
2013
Country
Ranking
2018
Qatar 77.0 77.0 26.0% 1 2
Algeria 31.2 31.2 10.5% 2 4
Indonesia 30.2 2.0 32.2 10.2% 3 3
Australia 24.2 61.8 86.0 8.2% 4 1 ↑
Malaysia 24.0 1.2 25.2 8.1% 5 6
Nigeria 21.2 21.2 7.1% 6 7
Trinidad and Tobago 15.4 15.4 5.2% 7 9
Egypt 12.2 12.2 4.1% 8 10
Oman 10.3 10.3 3.5% 9 11
Russian Federation 9.6 16.5 26.1 3.2% 10 5 ↑
Brunei 7.2 7.2 2.4% 11 12
Yemen 6.7 6.7 2.3% 12 14
Abu Dhabi 5.6 5.6 1.9% 13 15
Angola 5.2 5.2 1.8% 14 16
Peru 4.5 4.5 1.5% 15 17
Norway 4.2 4.2 1.4% 16 18
Equatorial Guinea 3.7 3.7 1.2% 17 19
Libya 2.3 2.3 0.8% 18 20
United States 1.5 18.0 19.5 0.5% 19 8 ↑
Papua New Guinea 0.0 6.9 6.9 0.0% 20 13 ↑
Colombia 0.0 0.5 0.5 0.0% 21 21
Grand Total 296.0 106.9 402.9
Table 14: LNG export facilities in 2013 and 2018 forecast (Source BP and Petroleum Economist 2014)
Demand pressures are unlikely to continue over the short to medium term. At present Qatar supplies almost a
third of the global LNG demand, then followed by Malaysia with 10%, Australia 9%, Indonesia 8%, Nigeria 7%,
Trinidad and Tobago 6% and Algeria with 5%.
The supply of LNG to the market will change over the next five years with 105 Mpta of LNG liquefaction and
export facilities under construction coming online. 60% of this increased capacity is to come from Australia who
will become the largest exporter of LNG by 2020. The US will also play a significant role with 18Mtpa under
construction and a further 31Mtpa having received FERC approval. In the US the last two years has seen a
number of LNG licences being approved with the fifth and latest in October 2014. This increased participation in
the LNG export market will have a significant impact on the price of LNG. The US could become the world’s third
largest LNG exporter within a decade and cause a shift from the current market pricing.
The Groupe International des Importateurs de Gaz Naturel Liquéfié 2013 LNG report noted that the number of
countries that exported LNG was 17, although the number importing grew by three as Israel, Malaysia, and
Singapore joined the other 26 importing countries. At present there are 86 liquefaction trains in operation and
104 LNG receiving terminals that can receive 721 Mpta. There is therefore roughly a 2.5 times disconnect with
the amount of LNG that can be supplied and that which can be received.
47 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
The figures below indicate the constructed, proposed and planned LNG capacity increase globally which could
double the world’s capacity to 430Mtpa, although it is unlikely that a number of these will ever actually take
place. Figure 20 Indicates how LNG regional exportation has changed in the last 20 years and expected to change
with the completion of the LNG trains under construction by 2018 and how the LNG dynamics has changed since
1993.
Figure 20: LNG Export projected capacity increases up to 2018 (Source BP Statistical Review of World Energy 2014 and Petroleum Economist)
Figure 21: LNG Export projected capacity increases up to 2018 (Source BP Statistical Review of World Energy 2014 and Petroleum Economist)
61
180
17 10
48
36
94
565
5052
Australia USA Africa Russia Canada Other
Forecast LNG capacity increase, 2013-2018, Mtpa, 100% = 430 Mtpa
Under Construction
Proposed (Offtakes signed or FID taken
Proposed
0%
10%
20%
30%
40%
50%
60%
70%
Africa NorthAmerica
Asia Pacific Middle East South &CentralAmerica
Europe
LNG Exports from 1993 to projected 2018
1993 2003 2013 Projected 2018
48 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 22: Regional global LNG exporter map (Source Petroleum Economist)
3.3 International Gas Pricing
Four main pricing regions exist:
Japan LNG cif (JCC)– Japanese crude cocktail method linked to crude price;
US Henry Hub – Unregulated wellhead free market gas price;
UK – NBP (Europe) – A combination of crude and other energy commodities; and
China – India – Greater number of short term contracts.
Figure 23: The four main pricing regions (Source Booz International 2014)
26% 24%17% 14% 18%
2%1%
4%
28%
68%
47%
29%38%
28%
4%
21%
40%29%
17%
7%
7% 5%4%
6% 9% 6%
1993 2003 2013 Projected 2018 All proposedprojects
LNG exporters over time
Europe South & Central America Middle East Asia Pacific North America Africa
49 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
The below graph indicates how international regional gas prices have changed since 1984.
Figure 24: Global gas price trends 1984 to 2013 (Source BP Statistical Review of World Energy 2014)
The natural gas price has had a turbulent year with the Japan Liquefied Natural Gas Import Price ranging from
$15.21/MMBtu to $17.17/MMBtu in September 2014. This is a change of 10.53% from August 2014 to
September 2014 and 14.75% from one year ago. The LNG market overall has seen a lower price in the second
half of 2014 as more supply is available which in turn has also been part of the reason for the decline in European
prices as surplus LNG flows back into the system.
Likewise the US Henry Hub has fluctuated in 2014 from a high of $6.00/MMBtu to a low of $3.89/MMBtu in
September 201413 (EIA 2014). It is expected that the price during the winter will be lower than the average
$4.53/MMBtu during the 2013 winter. The price in the North America is expected to remain in this range for the
next few years as gas production continues to grow (by 5.4% in 2014 and 2.0% in 2015). Gas storage will possibly
reach 3.9 Tcf by Oct 2015 (OGJ, 2014). The re-assurance of abundant low cost natural gas has paved the way
for structural demand growth in the US, resulting in switching from coal to gas for cleaner burning gas-fired
power generation.
At the end of September the price differential between LNG the Henry Hub gas price and the Japan LNG cif price
was over $13. At this time forward contracts was agreed at $8/MMBtu.
Although prices will vary depending on seasonal demand, it is expected by analysts to stay a few dollars below
last years’ winter price as new supply in Asia Pacific will add to a market already well-supplied. Once the Egyptian
and Angola LNG supply resume and new supplies from Australia come into the market it is expected that supply
will exceed demand even more. BG group forecast that supply will exceed demand by 9.5 million tons in 2015.
Until recently the Asian-Pacific market price was linked to the crude price, however over the last few years more
flexibility has come into the market and spot or short term LNG contracts were traded. In 2013 GGGILA indicated
that 27% of the LNG traded was on a spot or short term basis. Due to the tight demand and availability of LNG
there was not a lot of flexibility in the market. It can be however expected that the trend to shorter or spot
contracts will continue into the future. Japan, Korea and Singapore have recently concluded long-term contracts
that are solely gas indexed and not linked to the crude price.
13 The EIA provides Natural gas Henry Hub spot and future price data.
0
2
4
6
8
10
12
14
16
18
20
1984 1988 1992 1996 2000 2004 2008 2012
Gas prices $/MMBtu 1984 -2013
Japan LNG cifUK -NBPUS Henry HubOECD crude price
2011 Fukushima incident and Japan nuclear capacity taken offline
2004 Tsunami
50 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Even in Europe, where a combination of crude and other energy commodities make up the gas price, we are
seeing pricing terms that are hub-based rather than indexed to oil.
The US LNG exporting companies will challenge the old pricing structure with long term contracts continuing,
but there will be increased reliance on more short-term sales. Trading arms of the companies will sell any
uncommitted capacity into the market. Overall the gas market is seeing structural changes towards a more
liberalized and liquid LNG market with a growing number of exporters and importers creating spot market
volume growth. The difficulty for future projects outside the US to secure long term contracts will be a significant
challenge to future greenfield LNG plants.
At present there is a large gap between the delivered price of North American LNG and LNG prices in Japan which is
creating a demand by local natural gas suppliers to export to Asia. Considerable risks are present for the possible new
exporter as natural gas price may increase locally while a corresponding decrease in Asian LNG prices could quickly
erase the price differentials seen today between North American and Asian natural gas markets.
A possible supply glut was not expected at the start of 2014, however the ramp up of new liquefaction capacity
over the next three years may outpace demand growth as Japanese nuclear restarts and Chinese demand
decreases on the back of poor economic growth. For Europe, this could mean a substantial increase in LNG flow
back as the worldwide spot price decreases.
While the spot market for LNG is comparatively small compared to those volumes of LNG sold under long term
contracts, future surplus-of-supply situation could lead to more deals made on a spot basis and cause a decrease
in the spot price which is artificially high while demand exceeds supply.
The majority of suppliers prefer oil-indexation because of the transparency, reliability and traditional acceptance
by all players, however consumers are looking at negotiating better, and often shorter term deals as they shop
around for lower prices.
Figure 25: Global short and spot LNG trends (Source International Group of Liquefied Natural Gas Importers 2014)
The Baker Institute has forecasted the global LNG price for the next 30 years with increased supply and US LNG
exports linking storage in the US to global market. The changing dynamics will create a very different market
0
5
10
15
20
25
30
0
20
40
60
80
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
51 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
paradigm, especially in Asia with increased trade closing global price differential although prices will prices above
the US Hub price.
Figure 26: Forecast LNG prices to 2040 (Source Baker Institute RWGTM 2014)
3.91
5.34
6.95
8.628.12
10.2911.16
10.56
12.39
0
2
4
6
8
10
12
14
2011-2020 2021-2030 2031-2040
2010$/mcf Forecast LNG export prices
Henry Hub
NBP
JCC
52 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
4 Natural gas trends in South Africa
This section of the report focuses on gas trends in South Africa, including the history of the industry, exploration
activities, pricing and drivers for natural gas in South Africa.
4.1 Introduction
Natural Gas in South Africa prior to 2004 accounted for less than 2% of the primary energy demand in South
Africa. This is forecast to grow to approximately 7% over the next 15 years to meet the growing power needs of
South Africa. The revised IRP2010 anticipates 2,370 MW of gas fired power stations by 2030. The revised IRP has
indicated 2,652MW, an increase due to some OCGT plants being fuelled by gas.
South Africa’s offshore exploration has been limited in the past due to a lack of international interest and low
levels of reserves found. Difficult drilling conditions due to the depth of the water and harsh ocean currents also
made South Africa less attractive. Recent improvements in exploration technology, coupled with large finds in
neighbouring countries on the west and in particular the east coast has increased the interest in exploration
activity. The proven offshore reserves of o.9 tcf is expected to increase as exploration activity is ramped up and
there is hope in the sector that up to 60tcf may exist.
Non-conventional gas is likely to be a significant contributor of natural gas in South Africa with estimated
technical reserves of 390tcf for shale gas (8th largest reserves globally) and coalbed methane estimated at 12tcf
the 12th largest globally). Coal-bed methane could possibly be supplied to the market within the next 5 years.
Shale gas is likely to take another 8 years as exploration licences get approved and exploratory drilling takes
place to assess the potential reserves.
The gas market in South Africa has grown significantly over the last 10 years with the piping of natural gas from
Mozambique along the Rompco pipeline being the main supply route into South Africa. The market has grown
from 50mGJ/a in 2004 to 170mGJ/a as at end June 2014 and it is expected that the pipeline will be the primary
source of gas supply in South Africa for a number of years. PetroSA will continue to utilise their diminishing
offshore reserves to feed their Gas to Liquid plant, while the Ibhubesi field on the west coast will likely supply gas
to Eskom’s’ OCGT Ankerlig power station.
0.42 tcf Annual Natural Gas Consumption (2013)
1.27 tcf Annual gas production – global ranking 62
0.9 tcf Proven RSA Reserve – global ranking about 77
403.8 tcf RSA technically recoverable Natural Gas Resources – Conventional – CBM and
shale gas
17-80 tcf Estimated recoverable shale gas reserves out of the 390 tcf predicted by the EIA
0.8 tcf Conventional natural gas reserve in Namibia’s Kudu field designated for RSA
consumption
3.0 tcf Conventional natural gas reserve in Mozambique’s Pande/Temane fields
designated for RSA consumption
1% Proportion of-conventional technically recoverable natural gas reserve
99% Proportion of non-conventional technically recoverable natural gas reserve
Table 15: South African gas key facts (Source BP 2014, EIA 2013, SAOGA 2014)
South Africa has at present only the PetroSA operated block 9 Offshore Mossel Bay that provides local gas for
South Africa. A number of exciting opportunities exist with 3 offshore basins, the central Karoo basin and the
coalbed deposits in the Ecca Group, part of the Karoo Super group stratum as noted in Figure 27 below.
53 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Simplified main offshore exploration areas in South Africa
.
Figure 27: Main natural gas plays in South Africa (source PASA adapted by PwC 2014)
4.2 History of the gas industry in South Africa
Gas was first introduced in South Africa with the construction of the Cape Gas and Coke Company in Cape Town
in 1847. Other gas plants followed in Port Elizabeth, Kimberly, Grahamstown and eventually Johannesburg in
1892 which was generated by coal gasification and the only remaining network. 14
Onshore exploration in areas of the Karoo, Algoa and Zululand Basins started in 1965 with Soekor. In 1967
offshore concessions were granted to a number of international companies which led to the discovery of gas
and condensate in the Ga-A1 well situated in the Pletmos Basin. However international companies withdrew
during the 1970s largely due to political sanctions. From the 1970s through to the early 1990’s only Soekor
explored the offshore blocks in South Africa. PetroSA discovered 1 tcf of gas in the Bredasdorp which has been
the source of gas that feeds the PetroSA GTL refinery. Although offshore areas were opened to international
investors via a Licensing Round held in 1994 little exploration was performed. Most of the offshore exploration
occurred during 1981 to 1991 where there were 181 exploration wells drilled out of the total of 300 exploration
wells in South Africa. The result of this exploration was the discovery of several small oil and gas fields, and the
commercial production of oil and gas from the Bredasdorp Basin. In the Pletmos Basin there are two
undeveloped gas fields and a further six gas discoveries. In the Orange Basin One on the west coast there has
been one small oil and several gas discoveries.
The gas market, apart from the feedstock to the GTL refinery in Mossel Bay, did not take off in a big way until
2004 with the importation of 50MJ/a of natural from Mozambique by Sasol along the 864Km Rompco pipeline.
Sasol has however been selling coal gas since the 1960s.
14 History based primarily from PASA and PetroSA’s websites
Orange basin
Karoo Shale gas
Coalbed
methane
Bredasdorp basin
Tugela basin
Main natural gas areas in South Africa
Durban
54 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
4.3 KwaZulu-Natal Gas sector history
The Geology offshore KZN consists of the Durban and Zululand offshore basins which formed and developed
during the Jurassic to early Cretaceous break-up of Gondwana.
KwaZulu-Natal Offshore history:
The hydrocarbon potential of the offshore Durban and Zululand basins were tested by only four wells.
Well Jc-B1 (1989) exhibited a minor gas show.
In 2004, South Africa enforced the new MPRDA, to encourage the international oil companies to invest
in the oil and gas exploration and production.
In 2009, Silver Wave was awarded a number of offshore blocks during the Fourth Offshore Licensing
Round from PASA including those off the KZN coast.
Recent seismic 2D and 3D data was acquired between 2011 and 2013 by PGS. The company has also
applied for a Reconnaissance permit that covers the southern offshore blocks of KZN.
In 2011 Impact Oil and Gas acquired four blocks in the Tugela Area from Silver Wave Exploration in an
offshore area east of Durban. The blocks are 2931C, 2931D, 2932C and 2932A and cover a total of
11,325 square kilometres. The blocks are located 100 kilometres east offshore of Durban in water
depths of 1,500 and 2,200 metres.
Impact also holds three technical cooperation permits (TCP’s) pertaining to a number of designated
blocks on the east coast of South Africa totalling approximately 65,000Km2.
In October 2012 ExxonMobil Exploration and Production South Africa Limited (EMEPSAL) and Impact
entered into an agreement whereby EMEPSAL would acquire a 75% participating interest in the Tugela
South Exploration Right. This was the first serious interest shown by a major multinational oil company
off the east coast of KZN. EMEPSAL are the Operators on the acreage Tugela South Exploration Right.
The Tugela North Exploration permit is presently under consideration with the same participation and
operatorship as by EMEPSAL and Impact Oil and Gas as the Tugela South Exploration Right.
Impact Oil and Gas has applied to change its technical cooperation permit to an exploration permits in
blocks 3130 in KwaZulu-Natal along with other blocks farther south.
EMEPSAL have submitted an application for exploration permit immediately south of the Tugela
EMEPSAL and Impact oil and gas acreage.
Silver Wave has applied for a deep water exploration permits in blocks 2734, 2735, 2834, 2835, 2934
and 2935 East of Richards Bay as well the block they hold on acreage in the South that straddles the
KZN and Eastern Cape provinces boundary.
In November 2013 Sasol Petroleum International exploration right permit 236 (ER236) was granted for
the 82,000-square-kilometer area running from the Border of Mozambique down to Port Shepstone
which crosses the Durban and Zululand basins.
In June 2014 Eni SpA farmed into a 40% interest of the Sasol block as well as taking over operatorship,
although at present the agreement awaits South African government approval.
Onshore KZN
Rhino Oil and Gas Exploration South Africa (Pty) Ltd., a wholly owned subsidiary of Rhino Resources, Ltd holds
Technical Cooperation Permits (TCP) for two offshore blocks in the Cape and three onshore blocks in the greater
Karoo basin at Frankfort, Pietermaritzburg and Matatiele covering 26,514Km2. The Pietermaritzburg TCP No.91
covers 15,135 Km2 and is the closest onshore block to the eThekwini Municipality that has a TCP. The EIA
technically recoverable reserves for South Africa shale gas do not include Rhino’s acreage, although the company
is hopeful that gas does exist in the formation.
55 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
The Sungu Sungu and Rhino resources Matatiele TCP for oil and gas exploration, although the focus is on shale gas also fall into KwaZulu-Natal.
Figure 28: Onshore and offshore gas plays in KwaZulu-Natal (Source PASA adapted by PwC 2014)
ENI 40% farmed into Sasol
block –June 2014 and will
act as Operator
Sasol awarded exploration
permit ER236 – November 2013
ExxonMobil submitted application for Exploration
Permit
Exploration Rights Sasol 60%
ENI 40% interest and
operatorship
Exploration Rights Impact Oil and Gas 25%
ExxonMobil 75% interest and operatorship since August 2013
Silver Wave Energy
submitted application
for Exploration Permit
Silver Wave Energy
submitted application
for Exploration Permit
Impact oil and gas submitted application for
Exploration Permit
Impact oil and Gas 25% ExxonMobil 75% and
operatorship
RhinoResources – Onshore block – Shale Gas potential
Gas plays KwaZulu-Natal
56 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
4.4 Potential of the conventional and unconventional natural gas reserves in Southern
Africa
4.4.1 South African West Coast
Block 2A the Ibhubesi field has 540 bcm of gas (equates to 19.1 tcf) with Sunbird Energy the majority shareholder
with 76% and the rest held by PetroSA. The Ibhubesi project has been identified as one of 18 major strategic
infrastructure projects under the Presidential Infrastructure Coordinating Commission.
The Ibhubesi field which is located 380 Km north of Cape Town and 105 Km offshore, investment is expected to
be around R14-billion and to produce 28.3 bcf of gas yearly over eight-years (Sunbird energy, 2013). The anchor
tenant will be Eskom’s Ankerlig open-cycle gas turbine power station which will be converted to use cheaper
natural gas instead of diesel as the feedstock. It is expected to feed the power station for about 8 years which is
significantly lower than most typical gas infrastructure projects which are expected to have gas supply for 25 to
30 years. The Kudu field in Namibia situated in the Orange Basin could supplement future gas to Ankerlig.
4.4.2 South African South Coast
Natural gas has been produced from the F-A and E-M offshore fields Mossel Bay and feeds PetroSA (GTL)
synthetic liquid fuels plant. The gas consumption is in the range of 75 million Giga Joules per annum, which equates
to 0.07 tcf per annum. However gas reserves have diminished so that the refinery produced 5.8 million barrels in 2013,
14 percent below target and about 40% of the refinery capacity.
PetroSA is part way through a five-well drilling programme called Project Ikhwezi, which aims to sustain the GTL
refinery until another source of gas is available. Initially the company had intended to import liquefied natural gas
(LNG) to South Africa to shore up supplies and potentially supply gas to Eskom’s Gourikwa diesel open cycle gas turbine
peaking power plant. In August 2014 PetroSA announced that it had decided not to pursue a floating LNG import
terminal in Mossel bay, following a study that found the proposed sites to be “technically and commercially
challenging”. PetroSA is currently evaluating various other locations, as well as gas-supply alternatives to supply its
GTL refinery.
4.4.3 Shale gas: Karoo Basin
The technically recoverable shale gas reserves in South Africa have been estimated at 390tcf by the EIA in 2013
which is the 8th largest reserves in the world. There is no clear estimate of recoverable reserves as a moratorium
has existed since 1 February 2011 which has restricted exploration and fracking. Recoverable reserves have been
estimated at between 18 and 70 tcf. Estimates vary significantly as not all gas deposits and formations are
suitable for extraction and the hydraulic fracturing technology currently available determines the ease, or
possibility, of removing the gas.
PASA announced on 27th October 2014 that the original Shale gas applicants who submitted their applications
before 1 February 2011 (Shell South Africa Upstream, Falcon Oil and Gas and Challenger Energy’s Bundu Oil and Gas)
will have their pending exploration right applications processed. The moratorium on the other applicants in the Karoo
and elsewhere would remain in place until a lifting is announced by the Mineral Resources Minister and the MPRDA
is promulgated.
This does not mean that exploratory drilling will start immediately as the companies will need to review and update
the Environmental management plans (EMP) as required by the MPRDA and to notify and consult with affected
communities and parties in respect of any such revisions. The EMPs and technical regulation process is expected to
be completed by the end of February 2015.
PASA is then expected to issue exploration licences between July and August 2015.
57 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Hydraulic fracturing a highly specialised procedure involving complex mechanical and chemical processes that
stimulates the release of gas into a well by creating increased permeability through artificial fracturing of the
shale could possibly start 12-18 months after the issue of licences. Fracking could start sometime between July
2016 and December 2016, although the public consultation process and applications to stop fracking could still
stall this process.
The exploration process is expected to take between 3 and 7 years and only once commercial viable reserves
are proven will gas infrastructure be set up which will take around two years.
Companies Application
areas PASA to process pending exploration rights
application
Shell 185,000 km2
Sasol / Chesapeake / Statoil 88,000 km2 Withdrew application that covered an area below Sunga Sunga from Bloemfontein to Port Shepstone
Anglo Coal 50,000 km2 TCP Permits
Falcon Oil (Chevron to be operator on approval of exploration permit.
30,000 km2
Challenger Energy’s Bundu Oil and Gas exploration
4,600 km2
Sungu Sungu 100,000 km2 TCP Permits include parts of KZN
Rhino Resources 3 TCPs in the Karoo 26,514 km2 TCP Permits include KZN Table 16: Shale gas exploration applications (Source PASA, PwC 2014)
Shell South Africa Upstream has committed to six exploratory wells to see if potentially commercial reserves
exist. Shell’s GM Jan Willem Eggink said there was a “good chance” that the programme, which would involve an
investment of between $150-million and $200-million, would yield results. However, he also stressed that as a
“frontier exploration” programme there was also the risk that no gas would be discovered.
Each exploratory well pad will require an area of around 150 m² and an access road. If gas was proven Shell will
proceed to development. This will involve about 2 000 wells from around 70 well pads. The pads are likely to be
4 km apart and cover an area of about 30 km² or 1% of each exploratory licence area.
The figure below highlights the shale gas areas in South Africa.
58 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 29: Shale gas plays in South Africa (Source PASA adapted by PwC 2014)
4.4.4 Coalbed Methane in South Africa
Coal bed methane exploration interest in South Africa continues to grow with 25 exploration rights awarded to
date, and some companies applying for production rights. The main companies participating in CBM exploration
in South Africa are Anglo Coal, NT Energy Africa, Molopo E&P and Kinetiko Energy. Kinetiko Energy’s Amersfoort
CBM concession is about 300 Km from Durban but situated fairly closely the Lily pipeline that brings Methane
Rich gas from Secunda through to KZN. The South African Coalbed Methane reserves are estimated at 20-30 tcf
(12th largest globally).
The coal deposits in South Africa are found within the Karoo basin and fault bounded rift basins further north.
These basins are host to large volumes of coal and where the coal concentrated with methane gas, this holds
potential for significant future sources of coalbed methane energy.
In South Africa many onshore operators have exploration rights or are applying for TCP’s. A selection of some
key players and where they have rights are indicated on the diagram below.
Sunga Sunga has applied for
2 TCP’s (100,000Km)
Shell: PASA to process pending
exploratory rights permit (3 x
30,0000Km) total block area
185,000Km)
Falcon oil and gas: PASA to process pending exploratory
rights permit (30,000Km)
Bundu oil and gas/Challenger Energy: PASA to process
pending exploratory rights permit (4,600Km)
Rhino Resources has applied
for TCP’s (26,500Km) closest
onshore block to eThekwini
Municipality
Shale Gas Plays in South Africa
59 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 30: Major coalbed Methane play in South Africa (Source PASA adapted by PwC 2014)
Apart from companies looking at the extraction of coalbed methane using conventional methods the exploration
and development of underground coal gasification (UCG) methods and Deep Biogenic Gas (DBG) are being
investigated.
It is thought that UCG could double South Africa’s recoverable or usable coal reserves as the method burns coal
far deeper than what miners can reach.
Eskom has been developing UCG for 10 years and is investing a further R1 billion ($94 million) in research over
the next five years, when it hopes to give the green light for the technology to be rolled out to more power
stations. Eskom's first UCG pilot scheme was at the former Majuba colliery which is next to the Majuba power
station in Mpumalanga.
Likewise Deep Biogenic Gas (DBG) that is believed to be produced by primitive bacteria that inhabit deep water-
bearing fissures especially found in the gold belt of South Africa could also be developed. The DBG is found in
substantial quantities within the Witwatersrand Basin and maybe exploitable in the future. However the source
and migration pathway of the gas are unusual and present significant challenges to fully define the ultimate
potential of the resources as no known analogues exist for this type of gas production globally.
4.4.5 Biogas in South Africa from landfill sites
Currently there are a few municipalities in South Africa who have Landfill Gas (LFG) to electricity projects. The
DoE REIPPP process has allocated landfill gas with a meagre 25MW (or less than 0.5% of the new renewable
NT Energy Africa
Rhino Resources TCP’s near eThekwini
and further north
Sunga Sunga has applied for
2 TCP’s (100,000Km) Shale or
CBM
Kinetiko, Badimo South East of
Secunda close to Lily pipeline
Molopo Oil and Gas in Virginia /
Evander coalfields
Anglo Coal - Waterberg
Msix is the closest CBM Exploration
Right to eThekwini municipality
Coalbed Methane plays in South Africa
60 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
energy capacity) that is expected to enter the power grid. As yet only 1 project was approved and is in the
preferred bidder’s status from the third bidding round.
The eThekwini Municipality installed the first LFG to electricity projects in South Africa at Mariannhill (1MW)
and Bisasar Road (6.5MW) which generate a total capacity of 7.5MW from 20 cylinder spark ignition engines
which, in-turn, drive a generator to produce electricity. The eThekwini Municipality had two CDM projects
registered with the UNFCCC for the 2012 GHGIE reporting period, namely the Durban Landfill-Gas-To-Electricity
Project - Marian Hill and La Mercy Landfills and Durban Landfill - Gas Bisasar Road. For the 2012 period, the
eThekwini Municipality registered 234,506 CERs for these two projects. These two main projects accounted for
the majority of the 48 GWh (0.4%) electricity generated within the municipality in 2012. The remaining 12,087
GWh utilized in the municipality was imported in the area.15
The first commercial Landfill-to-Transport Fuel project in Africa is the harvesting of methane from 3 landfill sites
at Simmer & Jack (Germiston), Weltevreden (Benoni) and Rooikraal (Boksburg) in the Ekurhuleni Municipal. The
project’s key features included the drilling of 96 vertical and horizontal gas wells in the existing landfill sites,
installation of more than 10.5 km of gas collector pipework, four gas flares and a continuous monitoring system.
The Ekurhuleni Municipal has planned five LFG to electricity systems sites which are expected to generate
approximately 17MW.
4.5 Upstream Permits and Rights
There are two primary permits and two primary rights that apply to the upstream oil and gas industry in South
Africa:
Permits:
Reconnaissance permits (RP) which are valid for a period not exceeding one year and are not renewable
nor extendable; and
Technical cooperation permits (TCP) which are valid for a period not exceeding one year and are not
renewable, nor extendable. This allows the holder exclusive rights to apply for and be granted an
exploration right. If an exploration permit for the respective area is applied for, then the technical
cooperation will remain in force until PASA approves or refuses the exploration rights application.
Rights:
Exploration rights (ER) are granted for a period not exceeding three years. The exploration right period
can be extended for a maximum of three periods, not exceeding two years each. Each renewal triggers
a relinquishment of a percentage of the exploration area usually between15-20%. Exploration rights or
a part of can be transferred / farmed out with the consent of the Minister.
Production Rights (PR) are granted for an initial period not exceeding 30 years. The holder of a
production right also has an exclusive right to apply for and be granted a renewal of the right. A
production right period cannot be extended, however they can be renewed for another period not
exceeding 30 years. A production rights or a part of can be transferred / farmed out with the consent
of the Minister.
15 The eThekwini energy office reports on their GHG Inventory emissions are updated yearly at http://www.durban.gov.za/City_Services/energyoffice/Documents/
61 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
4.6 Drivers for natural gas in South Africa
4.6.1 Power generation
The biggest driver for increased gas usage in South Africa will be as a feedstock for electricity generation and
this is being driven by a government commitment to reduce greenhouse gas emissions and the DoE’s integrated
resource plan for electricity. This does not mean that there are no other significant uses of gas, such as a
feedstock to PetroSA’s GTL refinery or heat energy to industry such as smelters.
Natural gas is expected to play a significant part in generation of electricity energy mix new build over the next
15 years up to 2030. The government is focusing on increased power generation in the form of committed and
new build from 2010 to 2030 and part of that new build includes natural gas power stations in the form of
Combined Cycle Gas Turbine (CCGT) and the conversion of open cycle gas turbine (OCGT) from using expensive
diesel to cleaner and cheaper gas as a feedstock.
Figure 31 and 32 Indicates how the IRP anticipates the energy in megawatts generated from different feedstocks
to change between 2010 through to 2030.
Figure 31: IRP anticipated MW feedstock supply changes 2010 – 2030 (Source DoE Revised IRP 2010)
0
10
20
30
40
50
60
Coal OCGT Nuclear Hydro Landfillgas
Biomass Wind Solar CCGT
IRP anticipated MW feedstock in outlook 2010 - 2030
2010 2020 2030
MW
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Figure 32: IRP anticipated percentage feedstock supply changes 2010 – 2030 (Source DoE Revised IRP 2010)
What is clear in the IRP is that although the total amount of electricity generated from Coal will increase, other
sources of energy will increase even more. As a result less than 50% of the power generated will come from coal
by 2030 and around 10% of the supply will come from OCGT and CCGT.
Utilising data from the eThekwini Municipalities Exploring the implications of different energy futures for
eThekwini Municipality up to 2030 it can be seen that GHG emissions will increase from 237 Mt CO2-eq in 2010
up to 308 Mt CO2-eq in 2021 which then decreases to 283 Mt CO2-eq in 2030. The assumption is that the
national energy picture will be mirrored by the Municipalities and that coal GHG emissions will account for the
majority of the GHG emissions and OCGT and CCGT accounting for less than 1% of all emissions.
Greenhouse gas emission output for various feedstocks 2010-2030
Figure 33: Greenhouse gas emission output for various feedstocks (Source eThekwini Municipality LEAP energy scenarios)
The Revised IRP2010 and comments from government makes it clear that cleaner cheaper gas is to become the
feedstock for diesel OCGT power stations so as to reduce costs, reduce greenhouse gases emissions and in the
long term have gas supplied from local or neighbouring countries. Eskom’s diesel fuel bill for the two OCGT
operated during the 2013/14 year was R10.5 billion which is more than 400 times that expected by the NERSA.
Government statements in the last year have indicated a greater desire for CCGT and conversion of OCGT to run
on natural gas feedstock. The price of switching to gas-fired power generation seems to be gaining ground with,
46.7%
8.0%12.8%
8.4%
0.2% 0.2%
10.3% 10.7%
2.7%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
Coal OCGT Nuclear Hydro Landfillgas
Biomass Wind Solar CCGT
IRP anticipated % feedstock outlook 2010 - 2030
2010 2020 2030
0
100
200
300
400
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
Existing coal Large Existing coal Small Supercritical coal
Fluidised Bed Combustion Coal Coal imported Small cogen - coal
OCGT liquid fuels CCGT
MtCO2/e
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long term future gas prices stabilising. There is also the possibility of future indigenous supply in the form of
shale gas or coalbed methane.
The diagram below illustrates the MW of the new build of gas powered stations in South Africa and the total
installed MW through to 2030 (assuming all new OCGT and CCGT build based on the revised 2010 IRP is powered
by gas). The first gas fired power stations are expected to start coming online in 2019 and continue to have
increased capacity almost every year thereafter.
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New build capacity generation capacity in MW as per the revised IRP2010
Figure 34 OCGT and CCGT gas IRP build options (Source DoE Revised IRP 2010)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
CCGT
0 0 0 0 0 237 237 237 0 0 0 0 0 0 474 237 948
OCGT
0 0 0 0 0 0 0 0 805 805 805 0 0 0 690 805 0
Total
0 0 0 0 0 237 474 711 1516 2321 3126 3126 3126 3126 4290 5332 6280
Table 17: New build generation capacity in MW (Source DoE Revised IRP 2010)
The revised integrated resource plan and the gazetted Minister of Energy’s ministerial determination in
December 2012 allocates the following generation capacity to gas:
The medium term risk mitigation plan with the revised IRP has 474MW between 2019 and 2020;
The revised IRP with the ministerial determination has 2,652MW to be generated from LNG or natural
gas delivered by a pipeline. This represents the capacity originally allocated to OCGT and CCGT in the
IRP between 2021 and 2025; and
The revised IRP also has 1659 MW CCGT and 1,495MW OCGT new build between 2028 and 2030.
Assuming the forecasted new electricity generation build in the revised IRP for CCGT and OCGT is all powered
by natural gas then 6,280MW of 14.8% of the new build between 2010 and 2030 will be supplied by natural gas.
7% of the total generation capacity will come from natural gas.
The gas supply and type of procurement process for power generation has not yet been determined. The
government policies are not clear, however the IPP process does allow for cross border importation, which could
be from the Kudu field in Namibia, pipelines from Mozambique or coalbed methane from Botswana. The cost
0
1000
2000
3000
4000
5000
6000
7000
Revised OCGT and CCGT new build as per the irp 2010 revised
Gas CCGT new build Gas OCGT new build Total CCGT/OCGT MW
MW
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and difficulty in security of supply are the most important gas issues that could still prevent large scale gas power
generation as envisaged in the revised IRP 2010. Without electricity generation being the anchor for
commercialisation it is unlikely that conventional or shale and coalbed methane gas resources in South Africa will be
developed.
There is a move to use LNG for power stations as it has been suggested within 4 or 5 years it could be possible
to recoup the significant capital costs associated with a liquefied natural gas (LNG) import terminal by switching
fuels to gas, such as Eskom’s diesel open-cycle gas-turbines (OCGT) in the Western Cape to gas. The final cost
would however depend of the site and type of terminal selected. Shell, Sasol and PetroSA are studying various
possible locations which will not include Mossel Bay after PetroSA confirmed that the ocean conditions are not
suitable for a floating storage and re-gasification unit. The companies are looking at other possible sites near
Saldanha Bay, off the West Coast, Coega, in the Eastern Cape, and Richards Bay, in KwaZulu-Natal.
LNG import capacity and gas fired power plants would need to be developed in parallel over a three to five year
period if the country is to meet the first IRP 2010 targets of gas powered plants starting in 2019.
4.6.2 Gas to Liquids (GTL)
PetroSA’s gas to liquid plant started production in 1992 and it can produce up to 45,000 barrels of oil equivalent of
synthetic fuels a day from the natural gas. The original 1tcf gas reserves are diminishing and thus PetroSA has
embarked on various initiatives aimed at sustaining the GTL refinery which include a five-well drilling programme
called Project Ikhwezi, as well as other alternatives such as importing LNG . In August 2014 PetroSA announced that
they will not pursue a floating LNG import terminal in Mossel bay, following a study that found the proposed sites to
be “technically and commercially challenging”. The company is however evaluating various other locations, as well as
gas-supply alternatives.
Sasol gasification process produces coal to liquids (CTL) synfuels, however in 2005 the Sasolburg operations converted
from CTL to GTL and produces 15,600bpd of synfuel. The GTL synfuel production is still dwarfed in comparison to the
160,000 bpd that Sasol 16continues to produce through its CTL process.
4.6.3 Compressed Natural Gas
Compressed natural gas has only recently been introduced in South Africa with Novo Energy and CNG Holdings
and its subsidiaries supplying and supporting CNG infrastructure and supply since late 2012. At present CNG is
supplied to only a few blue chip industrial customers as well to six refuelling stations, 2 of which are for
demonstration purposes.
The largest commercial compression and dispensing facility is Novo’s Benoni site which came on-line in
November 2012. The facility has a capacity of 850 Nm3/hour. The station has a capability to refuel a dedicated
fleet of more than 1,000 minibus taxis daily. Alternatively approximately 250,000 GJ/a can be moved offsite for
other applications. The driving force in this instance is the Benoni Taxi Association (BTA) which has committed
to convert at least 20% of its fleet by 2014 to CNG. The motivation is the price of CNG which is on between 20%
- 30% less than conventional fuel equivalents. Novo Energy’s East Rand transportation operations consists of
refuelling stations at Benoni, Edenvale (from Landfill gas) Germiston and Kew17.
VGN opened its first flagship public mother filling station in Langlaagte, in March 2014, which can feed 600-1000
vehicles daily. The Sasol natural gas is supplied via Egoli at 30 bar pressure and then the Mother Station
compresses the Natural Gas to between 200 and 250 bar. The gas can then be dispensed to NGV or fed into tube
16 Sasol production in Sasol annual report 17 CNG operational information from Novo and VGN
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trailers for transport to customer sites. The company’s’ transportation operations consists of refuelling stations
at Langlaagte and daughter stations at Pretoria and two in Soweto.
NGV supplies CNG directly in two main ways:
Compression systems that convert natural gas from the gas pipeline infrastructure into CNG; and
Commercial customers’ who are not close to the Natural Gas pipeline infrastructure, receive CNG via a
modular road transport distribution system. The virtual distribution systems are designed for customers
who are too far from an existing pipeline, larger customers within 300 km radius from a Compression
Station and smaller customers who are part of a distribution network.
The cost of converting a single taxi to enable it to use CNG fuel is about R20,000, an amount generally funded
by NGV/Novo Energy and recouped through a portion of the gas price charged at filling station.
4.7 Natural Gas Infrastructure in South Africa
Natural gas at present is almost entirely transported to customers via transmission, distribution & reticulation
pipelines.
Figure 35: Main gas transmission and distribution lines in South Africa (Source Dynamic Energy 2014)
Transmission pipelines are those that provide for bulk transportation of gas by pipeline supplied between a
source of supply and a distributor, reticulator, storage company or eligible customer, or any other activity
incidental thereto (Gas Act).
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In South Africa the main transmission pipelines are:
±1100 km transmission pipeline network owned and operated by Sasol Gas;
865 km transmission pipeline from Mozambique to Secunda owned by ROMPCO The 26” pipeline cost
$549 million to construct between 2002 to 2004 and is designed to deliver 120mGJ/a at 124 bar;
573 km Lily transmission pipeline owned by Transnet running from Secunda to Durban. The 16-18”
methane rich pipeline had a capacity of 23 mGJ/a and spare capacity in 2012. The operating pressure
is between 40-53bar. Spare capacity along pipeline is not known, although with increased compression
the capacity of pipeline could increase; and
±100 km pipeline owned by PetroSA for the transmission of gas for own use to GTL plant in Mossel Bay.
Distribution pipelines distribute bulk gas supplies and the transportation of gas at general operating pressure of
more than 2 bar gauge, but less than 15 bar as per the Gas Act.
Sasol Gas has a couple distribution pipelines from Secunda that connects Pretoria, Johannesburg, and Sasolburg,
as well as a distribution network that links off the Transnet gas transmission pipeline to customers in KZN.
Reticulation in theory means the division of bulk gas supplies and the transportation of bulk gas by pipelines
with a general operating pressure of no more than 2 bar gauge to points of ultimate consumption, and any other
activity incidental thereto as per the Gas Act of 2004. However operating pressure in the reticulation network
in place does exceed 2 bar.
The main reticulation systems in South Africa exist in Johannesburg and Port Elizabeth and consist of:
±1200 km gas reticulation network owned by Egoli Gas and regulated by the City of Johannesburg; and
±58 km of gas reticulation network owned by Easigas in PE (not regulated ito Gas Act) and delivers LPG.
4.8 Other new developments
At the end of 2013 Sasol announced that it would be increasing the capacity of the pipeline from Mozambique
at a cost of R1.98bn to cope with the growing demand for gas. South Africa gets Natural Gas from existing natural
gas fields in the southern part of Mozambique, via the 865km Sasol Gas Pipeline.
Egoli gas is expanding their gas network with an 8 km 26” pipeline in Gauteng which can supply MTN (1.5Mgj/a
year) of natural gas by 2015 (10 MW power capacity).
Feasibility studies for additional gas pipelines are being investigated and this includes one that could run directly
from Northern Mozambique to Richards Bay. The 2013 feasibility study for this 2,800km GASNOSU 36”to 42”
gas pipeline was estimated to cost USD 7 billion.
The diagram below shows a high level overview of the transmission and distribution pipeline network running
from Secunda through to Durban.
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Figure 36: Transnet Lily gas pipeline (Source Transnet 2012)
Appendix D provides more detailed maps of the Sasol gas distribution network in the eThekwini municipality.
4.9 Natural Gas pricing in South Africa
Natural gas supplied to the general market has primarily come from Mozambique along the ROMPCO pipeline.
The 10 year Sasol Regulatory Agreement that expired on 25 March 2014 created the platform for Sasol to import
gas and recover development costs and take precedence over the Gas Act. All licensees are now subjected to
the same regulatory provisions as set out in the Gas Act No. 48 of 2001 and NERSA has powers to approve
maximum gas prices for all licensees, but not regulate the maximum price. (Gas amendment Bill).
The expiry of the Sasol agreement in 2014 has meant that Sasol Gas shifted from its current market value pricing
approach to a non-discriminatory pricing regime.
Although most of the clauses in the Agreement have expired, clause 4 still requires Sasol Gas to supply a
minimum of 120 million gigajoules of gas to South African markets for a period of 25 years until 2026.
Customers can negotiate actual prices up to the maximum levels approved by NERSA. There is very little
horizontal integration of suppliers in South Africa, and the regulator has only approved maximum prices for four
traders. A fifth is trying to enter the market:
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Sasol Gas Ltd – R117.69/GJ on 26 March 2013;
Virtual Gas Network (VGN) – R278/GJ on 29 July 2013;
Novo Energy (Pty) Ltd – R246/GJ on 9 December 2013;
Spring Lights Gas – R123/GJ on 27 February 2014; and
Realtile has applied for a licence to supply methane rich gas – R150/GJ on 07 April 2014 to areas in
KwaZulu-Natal. (Yet to be approved).
Figure 37 highlights how South Africa’s class 3 price in Gauteng as at March 2013 (4,001 GJ-40,000 GJ pa,
including Sasol tariffs) is compares to EU industrial tariffs (10,000 – 100,000 GJ pa) (R/GJ translated using Oanda
average yearly historical rates). This highlights the competitive nature of South Africa’s gas pricing when
compared to European prices.
Figure 37: Average gas price comparison (Source NERSA 2014)
4.10 The role of traders in South Africa
To provide gas to the market, a company must be licenced by NERSA if gas is supplied above 2 bar. Gas Traders
are also responsible for unearthing new markets for gas consumption, and thereby creating the demand for
upstream investment. To unearth new markets, a trader engages potential customers, establishes their energy
requirements, and convinces them of the advantages of gas. After negotiating and concluding a supply
agreement with a customer, a trader arranges the supply of piped gas to the customer’s site.
Gas traders in KZN are reliant on both Sasol Gas and Transnet Pipelines for the provision of the network
infrastructure for the supply of gas. Traders who utilise the network will be required to make contributions to
the cost of the infrastructure that connects its customers, although these distribution assets at present still
remain the property of Sasol Gas.
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5 Conventional Exploration
The purpose of this section of the report is to explain the upstream exploration, production process and activities
as it relates to conventional gas.
Natural gas can be produced from reservoirs through conventional and unconventional exploration and
production methods. Conventional gas is trapped in a permeable and porous reservoirs below a layer of rock
that will not allow the gas to migrate upwards. Until recently gas production occurred from these reservoirs as
it was easier, cheaper and the technology available made it commercially viable. All other gas exploration is
classified as unconventional and will be discussed in the next section.
Figure 38 below indicates the difficulty of developing gas through conventional and unconventional exploration
and production methods. The diagram also shows the level of costs required to develop fields with the cheapest
being for conventional gas reserves as it less complex and expensive to drill for conventional gas assuming similar
drilling conditions.
Figure 38: Impact and difficulty of developing resources (Source PwC)
Conventional gas has been the primary source of gas production since the 1900’s. It is gas that is trapped in
tectonically formed structures in folded and faulted sedimentary layers. Conventional Natural Gas resources
can be easily extracted and developed and generally located and trapped as small volumes. The gas is trapped
within an impermeable reservoir rock, which is trapped beneath a layer of impermeable rock.
Conventional exploration is where wells are drilled into highly porous and permeable formations of sandstones
and carbonates which produce commercial quantities of gas at a commercial flow rate without stimulation
techniques.
Conventional Gas
Tight Gas
Coal Bed Methane
Shale Gas
Gas Hydrates
Low High
Conventional permeable porous reservoirs
Resource quality-
commercial viability
High
Resource volumes
Low
Impact of technology development costs
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There are a number of factors which need to be present for conventional gas accumulations, including:
Source: an organic rock which is composed of either marine or terrestrial organic debris that has been
compacted by layers of overlying rocks over long periods of time. The overlying rocks (overburden)
causes an increase in pressure and temperatures as the organic material at depth converts in
hydrocarbons and becomes a liquid (oil) or a gas.
Migration: The hydrocarbons are able to migrate upwards along faults or within interconnected
formation pore spaces to lower pressure areas until they reach a ‘trap’ and accumulate.
Trap: This is essential to the accumulation of the hydrocarbons into a specific area. A trap or seal is
commonly a non-porous or impermeable layer of rock that will not allow the penetration of any gas or
fluid (usually a shale). It is also commonly folded to form an umbrella shape or faulted to juxtapose
rocks that will restrict any gas or fluid flow.
Reservoir: is the rock of high porosity and permeability that holds the hydrocarbons below the trap.
Typical gas reservoir formations are sandstones, siltstones and carbonates such as dolomites and
limestone. Due to plate movements and reservoirs can be found below the surface onshore and
offshore.
Conventional natural gas will come from three main sources:
Crude oil wells can produce associated gas. This gas can exist separate from the crude oil in the
underground formation, or be dissolved in the crude oil (hydrocarbon liquids). Condensate produced
from oil wells is often referred to as lease condensate.
Dry gas wells: These wells typically produce only natural gas and do not contain any hydrocarbon
liquids. Such gas is called non-associated gas. Condensate from dry gas is extracted at gas processing
plants and, hence, is often referred to as plant condensate.
Condensate wells: These wells produce raw natural gas along with natural gas liquids, such gas is
also non-associated gas and often referred to as wet gas.
Figure 39: Conventional and Unconventional gas structural schematic (Source EIA & US geological survey)
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6 Unconventional Exploration
The section of the report explains unconventional gas exploration and covers tights gas, shale gas, coalbed
methane and gas hydrates.
Unconventional gas refers to gas produced from shale and rocks with low permeability such as tight gas and
coal-bed methane. Unconventional natural gas resources are harder to develop, located in large volumes and
more expensive to extract due the impermeable nature of the reservoir formations.
Unconventional gas may have high levels of natural gas liquids with the exception of coalbed methane gas which
tends to be very ‘dry’ with high proportion of methane. Natural gas may have low or high levels of carbon dioxide
and high and low levels of sulphur (i.e.: ‘sweet or sour’). In South Africa the unconventional and conventional
gas has low levels of sulphur.
Because unconventional reservoirs have low permeability, artificial stimulation methods to increase gas flows,
such as mechanical or chemical ‘fracking’, is often required before the wells are able to produce commercial
quantities of gas at a commercial flow rate.
It has only recently become more economical to exploit unconventional gas due to the breakthrough of
horizontal drilling and improved fracking techniques.
The four main types of unconventional gas reservoirs are explained below.
6.1 Tight Gas
In a conventional reservoir (most commonly sandstone) the pores are interconnected so gas is able to flow easily
through the rock. In tight sandstones, siltstones and carbonates there are smaller pores, which are poorly
connected resulting in very low permeability.
Tight Gas is generally considered an unconventional source of natural gas as it requires some sort of stimulation
process to successfully produce commercial gas flow rates and produce commercial gas volumes. To make these
tight gas wells economical it is important to optimize both the number of wells drilled, as well as the drilling and
completion procedures for each well. A well in a tight gas reservoir will produce less gas over a longer period of
time than one expects from a well in a conventional reservoir. Tight gas reservoir developments will therefore
have many more wells (or smaller well spacing) than conventional wells to be economical and be able to extract
a large percentage of the original gas in place (OGIP).
In tight carbonates such as dolomites and limestones and sandstones with carbonation cement acidising
stimulation treatments and chemical fracking will be used to increase the connectivity of the reservoir and
consequently enhance well production.
The stimulation methods can be similar to those used for shale gas.
6.2 Shale Gas
A shale gas reservoir is anorganic-rich shale that is both the source and the reservoir rock. The source and
reservoir rock properties are fairly non-porous and impermeable thus trapping the hydrocarbons in situ and
allow for no gas migration. Gas is held in the shale not only in tiny pores, but also in a solid solution bound onto
the rock grains. To produce from shales the tiny pores need to be connected through the introduction of an
artificial fracture system, and lowering the pressure in the rock (through production) to allow the gas in solid
solution to become gaseous and flow.
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Unlike conventional gas production, shale gas potential is not confined to limited traps or structures, and may
exist across large geographic areas such as the Karoo in South Africa.
Shale gas requires different extraction methods from conventional gas.
The physical difficulties related to the extraction of shale gas have in the past prevented the gas from being
extracted as they were not economically viable through traditional drilling methods and techniques. With the
advances in extraction technologies shale gas extraction became are viable. The main two advances are the
ability to drill horizontally and induced hydraulic fracturing (hydro-fracking, commonly termed “fracking or
“fraccing”)”. These extraction methods are used to exploit these pockets of shale gas (EIA, 2012a; DMR, 2012).
Hydraulic fracturing is a highly specialised procedure involving complex mechanical and chemical processes. The
extraction process requires reservoir stimulation whereby significantly large quantities of a base fluid, usually
water mixed with a small fraction of sand and chemicals (usually around 0.5 %), are pumped into the reservoir
with sufficient pressure to create artificial fractures in the shale (AfDB, 2013). The fractures are necessary to
increase the permeability of the rock allowing the gas to flow from the pockets to the well (DMR, 2012). The
sand in the base fluid prevents the fractures from closing once the hydraulic fracturing is completed (Branosky,
et al., 2012).
Fracking is a contentious issue in arid areas such as the Karoo as up to 17 million litres of water are needed to
drill and complete a typical deep shale gas well. This is a once off consumption and is equivalent to the amount
of water consumed by a 1,000 megawatt coal-fired power plant in 12 hours (F.Spellman, 2012). The main
concern raised by opponents to shale gas exploration is that groundwater could become polluted during the
processes of drilling, hydraulic fracturing, gas production and subsequent abandonment of a gas wells.
Baker Hughes, a large multinational service company, implemented a policy of disclosing all the chemicals used
in its fracking operations. This is the final step in the US of the gas industry becoming more transparent as the
online database until now did not have information on certain chemicals and the amounts used in the fracking
process. The fracking process has been more controlled in Europe and as such less chemicals are used in the
fracking process. This is likely to be the approach used in South Africa.
The diagram below illustrates a typical shale gas well expected in South Africa where fresh water aquifers are
drilled through. Steel pipe well casing is inserted into a drilled section of a borehole and cemented in place. As
the borehole gets drilled deeper, smaller diameter casing sections are inserted within the previous casing.
The cement is intended to isolate the casing from groundwater and prevent natural gas from leaking up around
the outside of the pipe, a condition that can potentially allow gas to enter the groundwater supply or cause gas
to escape at the surface. The well is drilled vertically to around 1500-2500m and then horizontally along the
formation bedding planes for another couple of thousand metres. Once the well has been drilled the casing,
cement, and a short distance into the shale is perforated. After perforation the shale is fracked in stages and
only once all the sections have been fracked, are the plugs drilled so that gas flows to the surface and production
begins. The exploration companies in South Africa have indicated that one drilling pad will be used to drill
multiple wells so as to reduce the drilling footprint of the operations on the Karoo.
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Figure 40: Shale gas drilling (Source Future Challenges)
6.3 Coalbed Methane (CBM)
Methane is found in all coal deposits as a by-product of the coal formation process. Historically, this methane
was considered a safety hazard in the coal mining process and was purposely vented to the atmosphere.
Companies are now looking at recovering methane from coal bed deposits that are too deep to mine
economically.
Coalbed Natural Gas (CBNG), or Coalbed Methane (CBM) wells produce gas from the coal seams which act as
both the source and the reservoir. Natural gas can be sourced by thermogenic alterations of coal or by biogenic
action of indigenous microbes on the coal. Coal beds have become an attractive prospect for development
because of their ability to retain large amounts of gas. Coal is able to store six times more gas than an equivalent
volume of rock common to conventional gas reservoirs.
CBM wells typically do not produce as much gas as conventional wells.
There are some horizontally drilled CBM wells and some that receive hydraulic fracturing treatments. Wells
generally produce dry gas although they may also produce water as well as natural gas.
CBM reservoirs are mostly shallow as the coal matrix does not have the strength to maintain porosity under the
pressure of significant overburden thickness.
CBM deposits are used for CO2 sequestration (Carbon storage) because CO2 molecules injected into the
formations displace CH4 methane molecules from coal, which in turn generates greater CBM production.
Freshwater aquifer
Borehole with multiple layers of cemented casing. The casing seals off hydrocarbon communication with the formations.
Horizontal drilling
Fractured shale formations in
the Karoo at 1500-2500m
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Methane is loosely bound to coal and held in place by the water in the coal deposits. The water contributes
pressure that keeps methane gas attached to the coal. In CBM development, water is removed from the coal
bed (by pumping), which decreases the pressure on the gas and allows it to detach from the coal and flow up
the well.
Figure 41: A typical Coalbed Methane well (Source Ecos Consulting 2009)
In the initial production stage of coalbed methane, the wells produce mostly water. Eventually, as the coal beds
near the pumping well are dewatered, the volume of pumped water decreases and the production of gas
increases. Depending on the geological conditions, it may take several years to achieve full-scale gas production.
Generally, the deeper the coal bed the less water present, and the sooner the well will begin to produce gas.
Water removed from coal beds is known as produced water. The amount of water produced from most CBM
wells is relatively high compared to conventional gas wells because coal beds contain many fractures and pores
that can contain and move large amounts of water.
The use of hydraulic fracturing is used as a primary means of stimulating gas flow in CBM wells and it is the use
of horizontal drilling techniques that have made coalbed methane gas reserves commercial viable.
6.4 Gas Hydrates
Gas hydrates are naturally occurring, crystalline, ice-like substances composed of gas molecules (methane,
ethane, propane, etc.) held in a cage-like ice structure clathrate.
The formation and stability in the subsurface of these structures are constrained by a relatively narrow range of
high pressure and low temperature and depend on the influx of free gas and the amount of gas dissolved in the
pore fluid.
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They are found abundantly worldwide in the top few hundred meters of sediment beneath continental margins
at water depths between a few hundred and a few thousand metres. They are present to a lesser extent in
permafrost sediments in Arctic areas.
In the marine environment the gas hydrate stability zone is determined by water depth, seafloor temperature,
pore pressure, thermal gradient and the gas and fluid composition. The base of the zone in which hydrate can
exist is limited by the increase in temperature with depth beneath the seabed.
It is estimated that a significant part of the Earth's fossil fuel is stored as gas hydrates, but as yet there is no
agreement on proven reserves or how to extract the reserves commercially.
The DoE in the US has recently launched a 4-year, marine research project to gain a better understanding of
methane hydrate-bearing sediments volumes and accurately assess the commercial production potential.
Gas Hydrates are also being researched to see if natural gas can be frozen in the presence of water to create
hydrates that will allow 181 times more natural gas storage in a given area than with conventional reservoir
storage methods.
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7 Routes to Market
This section of the report provides insight into the means of getting natural gas to markets and covers
distribution, transmission and storage of natural gas.
Once natural gas has been processed it needs to be stored and distributed to a location for consumption. To
decide on the best types of technology to use a number of factors need to be taken into consideration such as
the size of the reserves and the distance to the market.
Capital investment decisions will be made on the efficient and effective movement of natural gas from one
producing/importing region to a distant consumption region as this requires an extensive and elaborate
transportation and storage system. Transportation of natural gas is also closely linked to its storage as natural
gas being transported to a distant location will be required when required.
The technology choices for the utilisation of gas in general is also determined by considering the combination of
reserves and distance to market, as demonstrated in the simplistic diagram below:
Figure 42: Capacity: Distance diagram for natural gas transportation technologies (Source PwC)
Gas can be brought to market either as gas molecules, (NG pipe, LNG, CNG), electrons (gas to power) or Synfuels
(GTL). The most common method of transportation to market occurs either via pressurised natural gas pipelines
or LNG transportation. LNG is especially common over long distances in excess of 2,500 Km. It is estimated that
LNG is ten times more costly to transport than crude oil, and nearly three times more costly than piped natural
gas. As a result LNG is only viable for large distances.
LNG is not only more costly to transport to market than NG via a pipeline over short distance, but it is also has
higher associated GHG emissions. The NETL 2014 GHG LNG emissions report noted that piped natural gas GHG
emissions are between 33-37 AR-5 100 year GWP (kg CO2e/MWh) for every 1000Km primarily due to methane
leakage. LNG Liquefaction, tanker transport from America to Europe, unloading and re-gasification emissions
totalled 108 AR-5 100 year GWP (kg CO2e/MWh) most of which was in the form of CO2, except during the
regasification process.
The markets for natural gas are often far removed from the reserves they need to be transported. The majority
of the globally traded gas is transported to the markets by pipelines 69% or by LNG carriers 31%.
Gas can be routed to market may be via different storage and transportation methods that will be discussed
below.
Pipeline LNG
CNG / GTW/ NGL
10.0
Capacity
(BCM) 1.0
0.1
1000 - 3000 100
Distance Km
GTL
Small scale LNG / GTL
CNG Shipping
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7.1 Ships, Rail, Trucks transportation
The transportation of natural gas by “Virtual pipelines” such as by road, rail and sea can be more economical
than using pipelines. In situations such as South Africa with limited infrastructure and in areas of low demand
pipelines may not be viable. Different technologies will be used to overcome pipeline constraints.
LNG is the primary way that natural gas is transported globally by ships, road and rail today.
LNG is transported by large specially designed marine vessels with specially insulated cryogenic tanks that keep
the gas in liquid form via auto-refrigeration.
The global LNG shipping fleet consisted of 393 vessels in 2013. LNG ships can carry up to 266,000 m3 although
the average delivery volume is around 130,000 m3 per cargo. There is a declining cost trend emerging for LNG
transport with vessel rates reaching $100,000 in 2013, 25% below 2012 levels. (BG-group, 2014)
Less common is the transportation of LNG overland, using trucks with cryogenic tanks that hold volume of
around 35 mᶟ.
The transportation of LNG by rail is limited globally, but is expected to grow.
Once LNG has been transported to its market destination it will be regasified back to natural gas and distributed
into natural gas pipelines for use by the end user or stored for later use.
CNG is the technology choice for natural gas transportation over shorter distances where pipelines do not exist
as the infrastructure to compress the gas is significantly cheaper than that of LNG. CNG is economically viable
where the reserves and market size is relatively small.
Small scale CNG shipping over short distances has begun, however large scale CNG shipping has not yet been
operationally proven and economical viable.
CNG is primarily seen as an option to deliver gas by road on a small scale through mobile cascades at a pressure
around 250 (200-275) bar. CNG will be stored and dispensed to vehicles and industry through CNG dispensers
or decompressed and feed to the consumer as natural gas. This option is particularly attractive where pipeline
networks are nearby but cannot supply gas to the end consumer.
CNG modular units are cheaper than the expensive cryogenic tankers required for LNG and the required
compressors are cheaper than the High capital costs associated with refrigeration and gasification of LNG.
7.2 Pipelines
There are three major types of pipelines along a typical piped transportation route: the gathering system
(wellhead to processing plants), large bulk cross regional pipeline transmission systems and distribution systems.
Distribution systems can be split into larger high pressure networks and smaller lower pressure networks that
are stepped down at the “City gate” as they reach urban areas. Transmission, distribution and reticulation
networks are also likely to have different rules and tariffs associated with their usage and access by third parties.
7.2.1 Gathering Pipelines to processing plants
The gathering system consists of low pressure, small diameter pipelines that transport raw natural gas from the
wellhead to the processing plant. This may be applicable in South Africa with the development of CBM and Shale
gas in the future. If the gas is sour a specialised gathering pipeline needs to be installed from the wellhead to
the processing plant.
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7.2.2 Bilk Pipelines (Transmission)
Bulk pipelines are characterised by the size of the pipeline and the distance that they carry natural gas across
country and provincial, regional boundaries.
The volume of gas that can be transported in a pipeline depends on two main factors: the pipeline operating
pressure and pipe diameter.
Most transmission pipelines operate at pressures of more than 60 bar, and some operate as high as 125 bar.
The Rompco pipeline in South Africa operates at 124 bar, whilst the Lily pipeline operates between 40-54 bar.
High pressure can reduce the volume of the natural gas being transported up to 600 times, as well as creating a
force to propel the natural gas through the pipeline. High operating pressures are maintained by compressor
stations along the pipeline and depending on the length of the pipeline and the topography the compressor
stations may be installed at intervals of 150 Km to 200 Km. The compressors are fuelled by gas from the pipeline.
Although natural gas in pipelines is considered ‘dry’ gas, it is not uncommon for a certain amount of water and
hydrocarbons to condense out of the gas stream while in transit, thus liquid separators at compressor stations
ensure that the natural gas in the pipeline is as pure as possible. The gas is monitored by sophisticated systems
such as Supervisory Control and Data Acquisition (SCADA) systems which monitor and control the flow of gas at
various points along the pipeline electronically.
Transmission pipelines are usually between 16 and 48 inches (40 and 122cm) in diameter with 6 to 16 inch (15
to 40cm) lateral pipelines delivering natural gas to the distribution networks.
Increasing pressure requires larger and thicker pipes, larger compressors, and higher safety standards, all of
which substantially increase the capital and operating expenses of a system.
7.2.3 Piped Reticulation, Distribution
Distribution and reticulation pipelines are not distinguished from one another international as they can often
mean the same thing and be the final step in delivering gas to the end user. In South Africa the Gas Act in its
present form has distributed piped gas at between 2-15 bars, whereas reticulated piped gas is below 2 bars for
ultimate consumption and not regulated by NERSA, but instead by the municipalities.
In essence distribution pipelines are larger in diameter and transport the gas at higher pressures than the
reticulation networks, although reticulation in South Africa to customers can be above 2 bar.
While large gas users such as gas-fired power stations and large industries obtain their gas supply directly from
the gas transmission pipeline, other users such as small and medium sized industries, commercial and domestic
users usually obtain their gas supply from their local gas distributor. Gas distributors need extensive gas
distribution pipeline networks within industrial and urban areas. For safety reasons, the gas is distributed at a
lower pressure and is odourised to allow users to detect gas leaks easily.
Typical delivery of natural gas to domestic customers will be depressurised at the ‘citygate’ to less than 2 bar
where it is scrubbed and filtered to ensure low moisture and particulate content.
The main reticulation systems in South Africa exist in Johannesburg and Port Elizabeth and consist of:
±1100 Km gas reticulation network owned by Egoli Gas and regulated by City of Johannesburg municipal
bylaws
±58 Km of gas reticulation network owned by Easigas in Port Elizabeth (not regulated ito Gas Act) and
delivers LPG.
Capital costs of reticulation are between R1.8 million per kilometre for small diameter pipelines and up to
around R4.8 million per kilometre for large diameter pipelines.
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7.3 Bottles
Natural gas in the form of methane is not bottled, however CNG can be dispensed from small modular units.
Daughter stations that do not have connectivity to natural gas pipeline will get CNG transported through mobile
cascades (i.e bunch of cylinders mounted on trucks). The compressed gas will be transported at around 250 bar
in a horizontal position on a chassis or trailer.
Images 3: CNG cylinders mobile transportation (Source: Entcgf.com)
LPG is not considered a natural gas, and is commonly distributed in bottles and used primarily for heating and
cooking processes in South Africa. LPG is supplied for industrial, commercial and other large volume sites in Bulk
storage vessels or dumpy tank storage vessels. For other applications such as domestic and leisure use the LPG
will come in 48kg, 19kg, 9kg, 6kg, 4,5kg, 3,2kg and 1,2kg domestic cylinders.
7.4 Consumption and Storage
Gas storage is used to meet load variations. Gas is injected into storage during periods of low demand and can
be withdrawn from storage during periods of peak demand or when needed. It is also used for a variety of
secondary purposes, including:
Balancing the flow in pipeline systems to ensure the pressures are kept to maintain operational
integrity;
Maintaining contractual balances to ensure volumes required are stored or delivered as required by
suppliers;
Levelling production over periods of fluctuating demand. Producers use storage to store any gas that is
not immediately marketable, typically over the summer when demand is low and deliver it in the winter
months when the demand is high;
Market speculation. Producers and marketers use gas storage as a speculative tool, storing gas when
they believe that prices will increase in the future and then selling it when it does reach those levels;
Insuring against any unforeseen accidents. Gas storage can be used as an insurance that may affect
either production or delivery of natural gas. These may include natural factors or malfunction of
production or distribution systems;
Meeting regulatory obligations. Gas storage ensures to some extent the reliability of gas supply to the
consumer at the lowest cost, as required by the regulatory body. This is why the regulatory body
monitors storage inventory levels in certain countries; and
Reducing price volatility. Gas storage ensures commodity liquidity at the market centres. This helps
contain natural gas price volatility and uncertainty.
The main ways that natural gas is stored on a long term or short term basis are:
Bulk storage reservoirs with three main types — depleted gas reservoirs, aquifer reservoirs and salt
cavern reservoirs where natural gas is injected into the reservoirs;
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LNG storage facilities onshore or on LNG ships;
Above ground gasholders (or gasometer);
LNG storage facilities onshore or offshore on LNG ships; and
Line packing pressurising up transmission pipelines.
7.4.1 Bulk Storage reservoirs
Underground reservoirs are the most commonly used way of storing natural gas for strategic purposes although
LNG storage is becoming more popular as a source to meet peak demand.
There are three main ways types of reservoir to store huge volumes of gas.
Figure 43: Types of storage reservoirs (Source Berkeley Lab Earth Science Division)
A. Salt formations: Underground salt formations are well suited to natural gas storage. Salt caverns allow
very little of the injected natural gas to escape from storage unless specifically extracted. The walls of
a salt cavern are strong and impervious to gas over the lifespan of the storage facility.
Once a suitable salt structure is discovered it needs to be developed by pumping fresh water into the
borehole. The solution mining process dissolves the salt and leave a void full of saline water that is
pumped back to the surface. The process continues until the cavern is the desired size. Once created,
a salt cavern offers an underground natural gas storage vessel with very high deliverability. Salt caverns
are usually much smaller than the other underground storage facilities. Salt caverns cannot hold the
large volumes of gas necessary to meet base load storage requirements. Multiple quick withdrawals
and injections are possible in salt caverns making them useful in emergency situations or during short
periods of unexpected demand surges. Although construction is more costly than depleted field
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conversions when measured on the basis of dollars per thousand cubic feet of working gas, the ability
to perform several withdrawal and injection cycles each year reduces the effective cost.
B. Aquifer reservoirs: are underground, porous and permeable rock formations that act as natural water
reservoirs and in some cases they can be used for natural gas storage. The geological and physical
characteristics of aquifer formation are not known ahead of time and a significant investment has to go
into investigating these and evaluating the aquifer’s suitability for natural gas storage.
If the aquifer is suitable, all of the associated infrastructure must be developed from scratch, which
makes it the most expensive underground natural gas storage reservoir to produce. Since the aquifer
initially contains water there is little or no naturally occurring gas in the formation and of the gas
injected some will be physically unrecoverable, thus up to 80% of the total gas volume must be used as
a cushion. Only when gas prices are very low will this type underground storage facility be used.
C. Depleted gas reservoirs are the most common form of underground storage as gas is stored natural gas
fields reservoirs that have produced all their economically recoverable gas. It is generally the cheapest
and easiest to develop, operate, and maintain as it allows the re-use, with some modification, of the
existing infrastructure which reduces the start-up costs and time. In order to maintain working
pressures in depleted reservoirs, about 50 percent of the natural gas in the formation must be kept as
cushion gas. However, since depleted reservoirs were previously filled with natural gas
and hydrocarbons, they do not require the injection of gas that will become physically unrecoverable
as this is already present in the formation. This provides a further economic boost for this type of
facility, particularly when the cost of gas is high.
7.4.2 Small scale storage
Small scale natural gas storage comes in the form of LNG storage facilities, above ground natural gasholder
facilities or line packing pressurising up transmission pipelines. The advantages over gas reservoirs is that a
significant portion of the gas stored does not need to remain in situ (cushion gas).
A. LNG facilities provide delivery capacity during peak periods or as and when market demand requires
natural gas. LNG is a liquid thus the storage tanks hold about 600 times more gas in a given space than
underground storage reservoirs and the can be delivered almost immediately into the natural gas value
chain. LNG storage facilities can be onshore, or offshore on LNG marine vessels, thus they are located
close to the market.
Stored LNG can be vaporised and transported as natural gas via local pipeline systems or trucked to
customers as and when required.
The advantage of LNG being trucked to customers is that it will avoid any pipeline tariffs that may exist
and have been approved by the gas regulator.
A disadvantage to LNG storage facilities are that they more expensive to build and maintain than
developing new underground storages.
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Images 4: LNG Gas Storage (Source lngworldnews.co.za/usa-ferc-issues-report-on-land-based-lng-spills)
B. Above ground natural gasholder facilities. Gas holders can store gas above ground and are largely for
balancing and supplying gas quickly into the grid at peak times. These facilities are not considered as
strategic storage facilities due to the small gas volumes stored in these structures. The gas is held at
low pressures generally between 20-40 bars. Globally countries are not building new gasholders as
LNG or reservoir storage is preferred.
Gasholders hold a large advantage over other methods of storage. They are the only storage method
which keeps the gas at the required municipal pressure. At present above ground natural gasholder
facilities are the only type of natural gas storage in South Africa.
Egoli Gas main storage-station is at Cottesloe with 3 larger gasholders capable of storing around 10 mcf
of natural gas. Secondary smaller storage facilities with 7 high-pressure gas vessels are at Langlaagte.
Images 5: Egoli Gasholder facility (Source Egoligas.co.za)
C. Line packing pressurising up transmission pipelines. Increased pressure will compress more gas into a
given volume. Line packing is where additional pressure above the normal operating pressure is applied
to the gas in a pipeline so that more can be stored for short time and released during anticipated peak
demand periods.
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8 Overview of the South African Regulatory framework: Natural Gas Sector
The regulatory framework for natural gas is quite extensive, and includes a wide range of policies, legislation
and regulations. These elements are summarised in this section of the report.
8.1 Policies and plans
The following is a summary of the various policies and regulations which are relevant to the development of gas
sector and its uses in the economy. These initiatives, laws and regulations and have been adopted by the SA
government in recent years.
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Figure 44: Selected policies and plans affecting the gas sector (Source PwC)
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8.2 Acts and Regulations
Figure 45: Selected Acts and Regulations affecting the South Africa Gas Industry (Source PwC)
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8.3 Summary of policies, regulations and laws affecting the South African gas industry
The table below summarises, policies, regulations and local government power associated with the South African
gas industry and they have been classified under P for Policy, LG for Local government and L for legislation and
regulations.
Summary of policies, regulations and laws affecting the South African gas industry
P Energy White Paper of 1998 and
subsequent Energy White papers
It is the overarching policy that promotes fuel diversification mix in RSA
energy mix
The main objectives:
Increasing access to affordable energy services
Improving energy governance by the State
Encourage competiveness in the industry for economic growth
Manage energy related environmental and health impacts
Securing supply through diversity
Promotes fuel diversification in the SA energy mix, and recognises natural
gas as an attractive option for SA.
It provides the basis for the development of the National Integrated
Energy Plan (IEP).
L National Energy Act (Act 34 of
2008)
The Act was legislated to ensure that diverse energy resources are
available, in sustainable quantities at affordable prices to the South
African economy.
It supports economic growth and poverty alleviation, while taking into
account environmental management requirements and interactions
amongst economics sectors.
This act makes provision for the development of the Integrated Energy
Plan and the formation of the South African National Energy
Development Institute, (SANEDI), whose functions are to undertake
energy efficiency measures.
P The National integrated Energy
Plan (IEP)
The IEP provides a roadmap of the future energy landscape for SA which
guides future energy infrastructure investments and policy development
is looking to address eight objectives for the energy industry in South
Africa, one of which is ‘minimise emissions from the energy sector’.
The IEP proposes options for meeting South Africa’s current and future
needs. It optimises the use of various energy sources. A natural gas case
was model to assess the impact of using natural gas to facilitate a
transition to a low carbon economy.
The plans purpose and objectives are anchored in the National Energy
Act.
P Integrated resource plan (IRP) 2010
(published under the Energy
Regulation Act 2010-2030)
The IRP 2010’s revised balanced scenario sets out specific targets for new
build and retirement of different energy sources. It is the roadmap for
electricity generation from 2010 to 2030 showing technologies and
timelines. The plan provides a guideline on the energy mix, including
nuclear, coal renewable energy and gas and the entire electricity
generation capacity outlook for the next 20 years.
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Summary of policies, regulations and laws affecting the South African gas industry
The plan has an emphasis on renewable energy, although it also includes
coal on condition that energy efficient and cleaner technologies such as
carbon capture and storage are implemented. Gas power stations were
allocated 3,126 MW of base load and/or mid-merit CCGT generation
capacity between 2019 and 2025 and 1,659 MW CCGT in 2028-2030.
P National Development Plan 2012
(NDP)
Recognises gas as an alternative fuel which can assist RSA’s move to a low
carbon economy.
The NDP priorities a number of constructing infrastructure projects
including LNG to power combined-cycle gas turbines.
It encourages in an environmentally friendly way the exploration of gas
(feedstock), including investigating shale and coal bed methane reserves.
If states that gas reserves if proven and environmental concerns
alleviated, then development of these resources and gas-to-power
projects should be fast-tracked.
For transport it hints at offering companies incentives for using delivery
vehicles powered by LNG.
P Industrial Action Policy Plan (IPAP2) Aligns to NDP and coordinated development of African regional
infrastructure and integrated value chains and acknowledges
contribution of gas to the energy mix including the potential of shale gas.
P Energy Security Master Plan (2007) Integration opportunities between electricity supply and primary energy
carriers exist as far as the use of coal, gas, LP Gas, LNG and other liquid
fuels. Ensuring optimal energy balances.
P Medium Term Strategic
Framework, MTSF(2014-2019)
The plan by the government to implement the National Development
Plan. It is a prioritisation framework aimed at focusing all government
efforts on a set of manageable programmes that guides the planning and
the allocation of resource across all spheres of government. It details a 5-
year rolling expenditure and revenue plan for national and provincial
departments. It includes the increasing of electricity supply by 10,000MW
of which 474MW would be from natural gas.
P Multi-Year Price Determination
(MYPD3) Feb 2013
The MYPD3 was a five-year plan by Eskom that aims to ensure a
predictable, longer-term price structure. In February 2013 NERSA allowed
tariffs increases of on average by 8% from April 1, 2013, to March 31,
2018. In September 2014 the National Treasury indicated that
government would support Eskom’s application to the NERSA for “tariff
adjustments above the MYPD3 increases” and that it is likely that higher
tariff increases may come in from 01 April 2015. The higher costs are due
to new build, renewable energy and the increased diesel costs to power
OCGT power stations and the cost to change them to feed off gas.
P Gas Utilisation Master Plan (GUMP)
2014
Framework for investment in gas-supporting infrastructure and outlines
the role that gas could play in the electricity, transport, domestic,
commercial and industrial sectors.
GUMP will assess the bottlenecks and capacity constraints of existing gas
infrastructure and plan for further gas infrastructure development
particularly to enable gas to power development.
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Summary of policies, regulations and laws affecting the South African gas industry
Overall it looks at gas Infrastructure measures required to develop and
improve South Africa’s ability to have gas as one of the sources of supply
to ensure energy security.
At present GUMP is awaiting government approval.
P Renewable Energy White paper on
Energy (2003 – 2007 – 2011)
The papers inform the public and the international community of the
Government’s goals and objectives for the optimal use of renewable
energy and reduce South Africa’s reliance on electricity from coal. It
stipulates the need for diversification for energy resources and commits
the Government to a number of actions to ensure that alternative energy
becomes a significant part of South Africa’s energy portfolio.
The measures include fiscal mechanisms, regulatory instruments, and
standards to promote R&D and investment in renewables and
educational programs to raise public awareness.
It requires future energy policies to consider the environmental, health
energy efficiency and energy conservation’ within the integrated
Resource Planning (IRP) framework from both supply and demand side in
meeting energy service needs.
The 2003 study first highlighted the technologies to be implemented first,
based on the level of commercialisation of the technology and natural
resource availability and this included landfill gas extraction;
The White Paper on Renewable Energy Policy’s position with respect to
renewable energy is based on the integrated resource plans
P National Climate Change Response
flagship programme,
The programme advocates CNG use and recognises the transport sector’s
role in contributing to the reduction of greenhouse-gas emissions in
South Africa
P National Climate Change Response
White Paper (2011)
Kyoto Protocol (2005) and
Copenhagen Conference of Parties
(2011).
The South Africa government strategy to make a contribution towards
greenhouse gas emissions mitigation is encapsulated in the National
Climate Change Response White Paper (2011). This was after the
commitment made by South Africa at the Copenhagen Conference of
Parties (2009) to take appropriate national actions to curb greenhouse
gas emissions.
The Kyoto Protocol and Copenhagen Conference committed South Africa
to an emissions trajectory that peaks at 34% below a “Business as Usual”
trajectory in 2020 and 42% in 2025.
L Income Tax Act (ITA) section 12D
and 12C
The Income Tax provides for business to depreciate their assets Gas
pipelines at 10% pa over 10 years - Section 12D.
Power plant at 20% pa (by virtue of the fact that it is a facility for use in a
manufacturing process) over 5 years – Section 12C.
In specific instances there are additional investment incentives such as
the promulgation of industrial development zones (IDZ’s) which will have
a tailored package of fiscal related tools, such as VAT exemption for
production that is not entering the domestic market e.g. imported inputs
for a production platform for export to the global market.
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Summary of policies, regulations and laws affecting the South African gas industry
LG Constitution RSA (1996), section
156(2)
Provides Local government powers on air pollution, building regulations,
electricity and gas reticulation, municipal planning.
Provides for democratic and accountable government and the provision
of services to communities in a sustainable manner
The Greater Johannesburg
Transitional Metropolitan Council
Gas Supply by-laws, 28 June 2000
This is the only Metropolitan with by-laws related to gas distribution and
supply in South Africa.
The definition of distribution" means the transportation of gas through
distribution pipelines and associated facilities to points of ultimate
consumption for the purpose of trading in gas, and any other activity
incidental thereto, and distribute and distributing have corresponding
meanings which at present is at odds to the definition in the Gas Act
which was only promulgated later. The licence also does not stipulate any
restriction on the operating pressure of the pipeline to points of ultimate
consumption.
LG Constitution Schedule 4 and 5
powers to Local government
The constitution provides local government a number of powers with
which natural gas maybe effected
Firefighting/disaster management
Promotion safe and healthy environment
Local economic development
Air pollution
Public facilities
Municipal public transport
Municipal planning
Electricity and gas reticulation
LG Fiscal Powers Act Local government has regulatory powers with electricity reticulation and
powers to impose a tax on electricity.
LG White paper on Local Government
(1998)
This white paper requires local government to develop sustainable
energy solutions.
LG Municipal Systems Act (2000) Framework for planning, performance management: IDPs, service
delivery at affordable tariffs for all.
LG Municipal Finance Management
Act No. 56 of 2003 (MFMA) s120
and s33(1) of the Municipal Asset
Transfer Regulations published in
terms of the MFMA (GNR. 878 of
22 August 2008, Government
Gazette No. 31346
Agreement between IPP and municipality for use of Municipal land used
to generate power is required – Any project utilising landfill gas or
municipal land generating power it must go through the usual
departmental approval and tender processes if it goes via the REIPPPPP
refer to Part B, Qualification criteria for bidders section 2.3.2.
LG If municipal land is used to supply power then it is more complex, than if
the land is owned privately. IPP offtake will firstly need to follow a normal
tender / RFP procurement process if the municipality requires to take IPP
power into their energy mix. Secondly the municipality would require
national treasury approval to guarantee the Capex and offtake. Provincial
/ Municipal bond issues might be possible. If the IPP power generated
Does not go directly in the municipality reticulation system then it will
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Summary of policies, regulations and laws affecting the South African gas industry
need to go via Eskom’s infrastructure which creates added complexity
and additional wheeling charges.
L National Energy Regulator Act 40 of
2004
This Act establishes the National Energy Regulator of South Africa
(“NERSA”), the regulatory authority tasked with the administration and
enforcement of the Gas Act 48 of 2001 and the Petroleum Pipelines Act
60 of 2003 and undertake the functions set out in section 4 of the
Electricity Regulation Act of 2006.
L Electricity Regulation Act (Act 4 of
2006) (ERA)
The Act established a national regulatory framework for the electricity
supply industry which made the National Energy Regulator (NERSA) the
custodian and enforcer of the national electricity regulatory framework
and states that NERSA must encourage energy efficiency initiatives.
L The Gas Act 2001, Act 48 of 2001 Promotes the orderly development of the piped gas industry. The Act establishes NERSA as the gas regulator, custodian and enforcer of governs the piped gas industry.
Currently the scope of regulations cover all hydrocarbon gases transported by pipeline, including natural gas, artificial gas, hydrogen rich gas, methane rich gas, synthetic gas, coal bed methane gas, liquefied natural gas, compressed natural gas, re-gasified liquefied natural gas, liquefied petroleum gas or any combination thereof.
Regulated license activities are required for the construction, operation, conversion of gas transmission, storage, distribution, liquefaction or re-gasification facilities as well as trading in gas.
Registered activities are defined for gas producers, gas importers, those engaged in transmission of gas for their own use, gas reticulation and piping LPG from a bulk storage tank or cylinder at below 2 Bar.
The Gas Act allows NERSA to impose license conditions with the following framework set out in section21 of this Act
At present the Gas Act excludes:
Upstream gathering lines,
LNG liquefaction,
LNG transportation by ships, road and rail,
CNG, and
Distribution and transmission infrastructures above 15 Bar.
The Gas Amendment Bill was approved by Cabinet and open for public comments since 17 April 2013. The aim is to:
Review compliance monitoring and enforcement,
Address changes in the gas landscape,
New technological advancements in both conventional and non-conventional gas,
Changes in transportation medium such as LNG and CNG, and
NERSA to regulate the distribution and re-gasification tariffs.
L Piped Gas Regulations, Gazette
29702, 20 April 2007
Part of the Gas Act it outlines the price determination principles for
determining the maximum price methodology. It allows NERSA to review
the maximum-piped gas applications and request amendments to the
maximum price, although it may not set prices.
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L Gas Rules 2009 Amendments to the Gas Act detailed the general requirements for the
documentation and licenses to be submitted to NERSA. It also details the
objection process and consultation process with effected interested
parties.
L The Sasol Regulatory Agreement
(until 25 March 2014)
NERSA had regulated gas prices in terms of this Agreement between 2005
and 2014. It provided limited access to Sasol Ltd’s owned transmission
pipelines including the ROMPCO pipeline.
The agreement continues to provide an obligation to Sasol’s Gas to
supply 120mGj/a until 2029.
L Gas pricing mechanism The pricing structure has moved away from the Market Value Pricing
(MVP) and now provides two approaches to approving maximum prices
for gas molecules:
1. Use a number of energy price indicators to determine the gas energy
(GE) price – in the absence of a fully developed competitive gas market
in South Africa.
2. Pass- through (or cost-build up) to cater for two options:
a) new entrants. e.g., importers of LNG, developers of domestic gas
sources, etc.
b) transition for incumbents and traders along the value chain after gas’
first entry into the transmission, distribution system.
L Gas Regulators Levies Act 2002, Act
75 of 2002
The purpose of the levies is to part fund NERSA’s general administrative
and other costs and are annually reviewed.
L Maximum refinery gate price of
liquefied Petroleum Gas –
Regulation No. R.377 2008 -
This sets the Maximum LPG Gate price that can be charged by the
refineries and has been effective from 2 April 2008.
The Petroleum Pipeline Act 60 of
2003 (including petroleum pipeline
regulations No.30905) PPA
Promotes competition in the construction and operation of petroleum
pipelines, loading facilities and storage facilities for crude, liquid
petroleum fuel and lubricants. It therefore excludes Gas in most cases
although the Act requires a licence for the construction of bulk storage
facilities, which at present creates an overlap between this Act and the Gas
Act.
L The Mineral and Petroleum
Resources Royalty Act, 28 of 2008
Provides for the imposition of a royalty on the transfer (disposal or
consumption) of mineral resources which includes gas extracted from
South Africa. The maximum royalty percentage is 5% for refined and 7%
for unrefined mineral resources. No distinction is made between onshore
and offshore production.
L The Mineral and Petroleum
Resources Royalty (Administration)
Act, 29 of 2008
Deals with the administration of the Royalty Act.
L Mineral and Petroleum Resource
Development Act (MPRDA)
The Mineral and Petroleum Resources Development Act 2002 is the
overall regulatory framework for the upstream oil and gas industry. There
is also a separate set of regulations enacted in 2004 that describes
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procedures in applying for and acquiring, and operating a petroleum
licence.
It makes all minerals (including gas as no distinction made between
different hydrocarbons) the property of the nation.
It provides for the Minister the powers to expropriate land for production
and exploration.
The aim of the new MRPDA Bill is to prescribe international industry
practices and standards to enhance safe exploration and production of
shale gas. It tries to ensure that fracking will be conducted "in a socially
and environmentally balanced manner“.
L Environmental Conservation Act The environmental Conservation Act provides for the effective protection
and controlled utilization of the environment.
L Occupational Health and Safety
Act, 85 of 1993
Health and safety issues relating to Midstream and downstream facilities
are primarily covered by this Act.
L Mine Health and Safety Act 29 of
1996
Health and safety issues relating to upstream facilities are primarily
covered by this Act.
L National Environmental
Management Act (NEMA), 107 of
1998,
National Environmental
Management Laws Amendment
Bill, 2011).
Amendment to Environmental
Impact Assessment Regulations
Listing Notice 2 of 2010 -
Government Notice R923 in
Government Gazette 37085
NEMA is the environmental framework legislation which provides for
environmental management. Other specific environmental management
Acts were promulgated to deal with specific mediums of the
environment, namely the National Environmental Management:
Protected Areas Act, 2003 (Act No. 57 of 2003) (NEM: PAA), the National
Environmental Management: Biodiversity Act, 2004 (Act No. 10 of 2004)
(NEM: BA), the National Environmental Management: Air Quality Act,
2004 (Act No. 39 of 2004) (NEM: AQA), the National Environmental
Management: Integrated Coastal Management Act, 2008 (Act No. 24 of
2008) (NEM: ICMA) and the National Environmental Management: Waste
Act, 2008 (Act No. 59 of 2008) (NEM: WA).
The Act specifically identifies the construction of facilities or
infrastructure for the refining, extraction or processing of gas, oil or
petroleum products, but excludes facilities for the refining, extraction or
processing of gas from landfill sites.
The transportation of dangerous goods in gas form, outside an industrial
complex, using pipelines, exceeding 1000 metres in length, with a
throughput capacity of more than 700 tons per day.
The construction of an island, anchored platform or any other permanent
structure on or along the sea bed.
Any activity which requires a mining, exploration or production right or
renewal thereof as contemplated in the MPRDA.
L National Environmental
Management Act: Integrated
The Act establishes a system of integrated coastal and estuary
management in RSA, including norms, standards and policies, in order to
promote the conservation of the coastal environment. The Act
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coastal management Act
(NEM:ICMA), 24 of 2008
determines the responsibilities of organs of state in relation to coastal
areas and prohibits incineration and controls dumping at sea as well
details on other adverse effects on the coastal environment and thus
applies to oil and gas sector activities.
L National Environmental
Management Act: Air Quality Act,
39 of 2004 (NEM:AQA)
The act requires all spheres of government to ensure the protection of
the air quality environment. It includes protection, enhancement,
prevention of the ambient air quality for the sake of securing an
environment that is not harmful to the health and well-being of people.
Regulations regarding air dispersion modelling air quality consistency
were promulgated in July 2014.
L National Environmental
Management Act: Waste Act Waste
Act, 59 of 2008 (NEM:WA)
Regulate the classification, mechanisms, duties, timeframes and
management of waste.
L National Water Act Regulates water resource management to ensure equal rights to all and
sustainability of the nation’s water resources. It determines activities and
licences required for water rights.
L Marine Pollution (Control and Civil
Liability) Act
Provides for the protection of the marine environment from pollution by
oil and other harmful substances, and for that purpose to provide for the
prevention and to determine liability in certain respects for loss or
damage caused by the discharge of oil from ships, tankers and offshore
installations; and to provide for matters connected therewith such as
responsibilities.
There are a number of other Maritime Acts that would also apply to the
transportation of gas.
P Convention on Bio-Diversity, (1992)
and the Kyoto Protocol, (1997)
South Africa is a signatory to the Convention on Bio-Diversity, (1992) and
the Kyoto Protocol, (1997). In addition, the following legislation and
policy statements have been approved, which has an important bearing
on sustainable (green) transport: and can be linked to other acts such as
National Road Traffic Act, (1996);
National Land Transport Act, (2009);
Energy Efficiency Strategy, 2005;
White Paper on National Transport Policy, (1996);
National Climate Change Response White Paper, (2011).
L National Road Traffic Act, (1996); To provide for road traffic matters, which shall apply uniformly
throughout the Republic for matters connected therewith including the
transportation of petroleum products.
L National Land Transport Act,
(2009);
Prescribes national principles, requirements, guidelines, frameworks and
national norms and standards that must be applied uniformly in the
provinces. It also aims to consolidate land transport functions and locate
them in the appropriate sphere of government.
L White Paper on National Transport
Policy, (1996);
The vision was to provide safe, reliable, effective, efficient, and fully
integrated transport operations and infrastructure and meet the
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government strategies for economic and social development whilst being
economically and environmentally sustainable.
Petroleum and Liquid Fuels Charter
2004
The Charter for the Petroleum Industry was signed in 2004 and targeted
a 25% HDSA workforce by 2010. It also applies to the upstream segment
of the value chain where rights owners are required to aim to have no
less than 1 10% (9%+1%) undivided HDSA interest.
L SANS codes There a number of SANS codes related to the gas industry.
L Carbon Taxes-2016/2017 It is envisaged that a carbon tax, proposed by the National Treasury, will
be implemented on 1 January 2016 at a rate of R120 per ton of carbon
dioxide equivalent (CO2e) on direct emissions and will increase by 10%
pa.
The Tax has been delayed a number of times. New changes expected will
include reducing Eskom’s tax liability and addressing concern about
international competitiveness, including a formula to adjust the basic
percentage tax-free threshold to reward over performance. When
introduced it may push the economy onto a lower-carbon growth
trajectory.
International Maritime
Organisation’s (IMO) International
Convention for the prevention of
pollution from ships (MARPOL VI)
May 2005
MARPOL VI requires reduced SOx and NOx emissions from exhaust fumes
from ocean vessels in the Emission Control Areas (ECAs) of the North Sea,
Baltic Sea the US, Canada and US Caribbean
Sulphur limits in ECA areas:
July 1 2010 to 1 January 2015 = 1.0% m/m3
After 1 January 2015 = 0.1% m/m3
Sulphur limits in other sea areas:
July 1 2012 to 1 January 2020 = 3.5% m/m3
After 1 January 2020= 0.1% m/m3
Table 18: Summary of Policies, Regulations and Laws affecting the South African Gas Industry
8.3.1 Draft Regulations and Policies
At present there are a number of potential legislation amendments to key Acts that affect the oil and gas sector
in South Africa. Acts which will be reviewed / amended during the financial year 2014/2015 that will affect the
gas industry are:
The Petroleum Products Act 120 1997 which will address regulatory gap;
The Gas Act 2001 will include methane and gases from other sources;
The government also plans to pass the National Strategic Fuel Stock policy, which will set the regulatory
framework for the storage of fuels by government and the industry;
The Mineral, Resource Petroleum Development Bill that aims to align the MRPDA with the Geoscience
act and remove any ambiguities’ that exist within the Act;
The piped gas regulations Sasol gas tariff applications are set from 2014-2017 after which time they will
be reviewed again with the aim to increase competition in the market; and
NERSA Act setting out it future role and responsibilities in the industry.
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8.4 Regulatory oversight bodies
The eThekwini Municipality using the present Gas act is required to regulate the reticulation of gas under 2 bar
and create bylaws similar to the Greater Johannesburg Transitional Metropolitan Council Gas Supply bylaws
promulgated on 28 June 2000.
8.5 Conclusion on Legislation
There are a number of policies and plans that are all indicating that natural gas will play an important part in
South Africa’s energy mix going forward. The Integrated response plan and ministerial determinations have
proposed that part of the new power generation new build between 2019 and 2030 will be for gas.
The upstream industry is in its infancy with numerous international and local companies looking at exploration
and future production from onshore Shale gas and CBM reserves as well as conventional gas from offshore
reserves as exploration companies’ drill in new and deeper water. The amended MPRDA aims at clarifying future
upstream activity, while the amended Gas Act will ensure that all gas activities including those associated with
new technology are covered and regulated by NERSA.
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9 Key Stakeholder Assessment in the Natural Gas Sector
There is a wide range of stakeholders in the natural gas sector in South Africa. This section identifies the most
important Government and Private sector stakeholders.
9.1 Key Stakeholder Assessment
The Gas industry has a number of key stakeholders ranging from government departments, parastatal entities,
regulators and industry players.
High level analysis of key stakeholders in the upstream, midstream and downstream gas sector in South Africa
is highlighted in the figure below.
Figure 46: Key Stakeholders in the South African Gas Industry (Source PwC)
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9.2 Key Stakeholders
The key stakeholders nationally and those which could play a role on the gas sector in the eThekwini Municipality
are summarised below:
The key for the table:
Type of stakeholder: G=Government, T=Trader, R= Regulator, P = Producer, O = Other.
Sector of stakeholder : U = Upstream, M = Midstream, D = Downstream
Type
sector
Active
in KZN Summary of key stakeholders in the Natural gas sector
G
UMD
N CEF Upstream to
Downstream
The CEF Group mandate is to invest in and develop gas and gas
infrastructure in a manner which is commercial and can attract
investment. CEF manages the operation and development of the oil
and gas assets and operations of the South African
government. Under CEF there are a number of government
subsidiaries that implement CEFs mandate and these include iGas,
PetroSA, Petroleum Agency of South Africa, Oil Pollution Control SA
and the Strategic Fuel Fund.
G
MD
N iGas - Downstream iGas is the official state agency for the development of the
hydrocarbon gas industry in comprising liquefied natural gas and LPG
in South Africa.
iGas is in the process of being merged into PetroSA so that the joint
existing capabilities will strengthen the states value proposition in
the gas sector.
G
UMD
N The Petroleum oil and
gas corporation of South
Africa (PetroSA) –
Upstream to
Downstream
PetroSA was formed in 2002 upon the merger of Soekor E and P (Pty)
Limited, Mosgas (Pty) Limited and parts of the Strategic Fuel Fund.
PetroSA is a subsidiary of the Central Energy Fund (CEF), which is
wholly owned by the State and reports to the Department of Energy.
PetroSA is the South African National Oil Company (NOC) and has been
given the mandate by cabinet to lead developments in gas
infrastructure in the Western Cape.
PetroSA owns one of the worlds’ largest Gas to Liquid (GTL) refinery
with a capacity of 45,000 bbp/d and has produced around 70 MMbbl
crude oil & 1 Tcf of natural gas to date.
NERSA recently granted regulatory approval to PetroSA for a five well
gas drilling exploratory programme. The Ikhwezi project will cost
US$1-2bn with the aim of securing feedstock to sustain the company's
Mossel Bay GTL refinery. The F-O field has estimated reserves of 28.3
bcm of natural gas which would augment the gas feedstock supply to
the GTL refinery until another source of gas can be found.
The company produces oil from the Oribi, Oryx and Sable fields. Gas
and condensate is produced at the offshore EM, EBF and FA fields.
PetroSA also owns 40% of block 1 that covers 19,922sq km of the
Orange Basin along the north-western maritime border with Namibia.
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Active
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The company has an upstream presence in South Africa, Equatorial
Guinea and Ghana.
The MRPDA currently provides the State 10% in production rights,
although the amendment Bill in its present form would give PetroSA
20% free carry in exploration and production rights and the possibility
of obtaining more at an agreed price.
GR
U
N Petroleum Agency of
South Africa (PASA)
PASA has the responsibility to promote the exploration and
exploitation of natural oil and gas, both onshore and offshore, in
South Africa and to undertake the necessary marketing, promotion
and monitoring of operations. It regulates the upstream industry and
performs all the advisory, compliance, evaluating and administrative
roles. It makes recommendations to the Minister of mineral resources
on all rights and permit applications.
G
MD
N Transnet (Formally
known as Petronet)
Transnet owns, operates, manages and maintains a network of 3
000km of high-pressure petroleum and gas pipelines, on behalf of the
South African government. The main pipeline is Transnet’s Lily
pipeline that runs 573 KM from Secunda to Durban.
G
MD
Y The Transnet National
Port Authority
Transnet National Ports Authority is a division of Transnet Limited and
is mandated to control and manage all eight commercial ports in South
Africa including Durban and Richards Bay.
G
MD
Y The Ports Regulator The Ports Regulator was established in terms of the National Ports Act,
act number 12 of 2005. The Regulator is a key component of the ports
regulatory architecture envisaged in the National Commercial Ports
Policy. The Ports Regulator mainly regulates pricing and other aspects
of economic regulation, including promotion of equity access to ports
facilities and services and the monitoring of the industry’s compliance
with the regulatory framework.
G
MD
Y Ethekwini Municipality
energy office
The Energy Office (EO) is a branch within the Treasury Cluster and
under the Finance, Pensions and Major Projects Unit. The EO
was launched in early 2009 in response to the National Power
Conservation Program which set energy saving targets between 10%
and 15% across all sectors in South Africa
The Energy Office (EO) is responsible for conceptualising and initiating
projects in Renewable Energy, Energy Efficiency and Climate Change
Mitigation (Reducing GHG emissions)
http://www.durban.gov.za/City_Services/energyoffice/
GR
MD
N The National Energy
Regulator (NERSA)
Midstream and
downstream
Section 3 of the National Energy Regulator Act, 2004 (Act No. 40 of
2004) set up NERSA to regulate the Gas industry. NERSA regulates
using the Gas Act, 2001 (Act No. 48 of 2001), Petroleum Pipelines Act,
2003 (Act No. 60 of 2003) and related Levies Acts. NERSA Regulates
the midstream industry, the SASOL/Mozambique pipeline and
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Type
sector
Active
in KZN Summary of key stakeholders in the Natural gas sector
evaluates and approves the maximum price tariffs for gas distribution
on natural gas above 2 bar.
NERSA’s mandate is anchored in four Primary Acts:
National Energy Regulator Act, 2004 (Act No. 40 of 2004)
Electricity Regulation Act, 2006 (Act No. 4 of 2006)
Gas Act, 2001 (Act No. 48 of 2001)
Petroleum Pipelines Act, 2003 (Act No. 60 of 2003)
and 3 Levies Acts:
Gas Regulator Levies Act, 2002 (Act No. 75 of 2002)
Petroleum Pipelines Levies Act, 2004 (Act No. 28 of 2004)
Section 5B of the Electricity Act, 1987 (Act No. 41 of 1987)
G
D
N Department of
Transport
Downstream
The National Road Traffic Act and the National Road Traffic
regulations on the transportation of dangerous goods by tankers are
administered by the Department of Transport.
G
UMD
N Department of Labour Administers the Occupation and Health and it regulations as well as
the labour relations Act and Basic conditions of employment.
G
UMD
N Department of
Environmental Affairs
As well as provincial environmental authorities are responsible for the
environmental laws and Environmental Impact assessments (EIA)
especially on mid and downstream oil and gas sector.
G
D
N Local Government -
Municipalities Reticulation and tariffs for electricity – The source of supply is irrelevant.
G
MD
Y Eskom In 2002 Eskom was converted from a statutory body into a public company in terms of the Eskom Conversion Act 13 of 2001.
Eskom is the South African power utility parastatal.
Eskom generates approximately 95% of the electricity used in South Africa and approximately 45% of the electricity used in Africa.
Stakeholder Assessment in the Natural Gas Sector
The company is divided into generation, transmission and distribution divisions. The company generates, transmits and distributes electricity to industrial, mining, commercial, agricultural, residential and redistributors,
Additional power stations and major power lines are being built to meet rising electricity demand in South Africa. Eskom will continue to focus on improving and strengthening its core business of electricity generation, transmission, trading and distribution.
G
D
N South African National
Energy Development
Institute (SANEDI)
The South African National Energy Development Institute (SANEDI) is
a state owned entity that was established as a successor to the
previously created South African National Energy Research Institute
(SANERI) and the National Energy Efficiency Agency (NEEA). The main
function of SANEDI is to direct, monitor and conduct applied energy
research and development, demonstration and deployment as well to
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Active
in KZN Summary of key stakeholders in the Natural gas sector
undertake specific measures to promote the uptake of Green Energy
and Energy Efficiency in South Africa.
GR
MD
N Department of Energy Focuses on energy issues and aims to effectively implement policy and
to ensure secure and sustainable provision of energy for socio-
economic development.
The Minister of Energy has powers and functions over the main Acts
and regulations that will affect the gas industry. The Minster is
entrusted to govern the Central Energy fund Act, Petroleum Products
Act, Gas Act and its regulations, Petroleum Pipelines Act, Petroleum
Pipelines Levies Act, National Energy Regulator Act, Electricity
Regulation Act and National Energy Act.
GR
U
N Department of Mineral
Resources
In July 2009 “the Department of Minerals and Energy (DME)” split into
two departments, the Department of Mineral Resources (DMR) and
the Department of Energy (DoE).
The department focuses on South Africa’s natural resources
regulations with the aim of enabling a globally competitive,
sustainable and meaningfully transformed minerals sector in South
Africa.
The minister approves all exploration and production upstream
permits and licences.
The Department is the custodian of the upstream industry and has
powers and functions entrusted in terms of a number of Acts, some of
which affect the gas sector such MPRDA, the Mine Health and Safety
Act and Geosciences Act.
T
UMD
Y Sasol Gas – Trader and
pipeline network
operator
Sasol Petroleum International is an international integrated energy
and chemicals company based in South Africa that has more than 33
000 people working in 37 countries.
Sasol Gas is one of four area that make up Sasol’s South African energy
cluster, the others being Sasol Mining, Sasol Synfuels and Sasol Oil .
Sasol, uses, supplies and owns most the distribution gas networks in
South Africa.
The company owns 50% of the Rompco pipeline which brings natural
gas from the Pande and Temane gas fields in southern Mozambique to
Secunda.
Sasol is one of 3 licenced gas pipeline traders.
Sasol Gas directly supplies NG and MRG to approx.375 large industrial
customers in MP, FS, GP and KZN.
NERSA has also approved transmission tariffs and a trading margin for
Sasol Gas which must be added on the actual price offered to the
customer. The approved transmission tariffs are applicable to three
zones, namely:
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Active
in KZN Summary of key stakeholders in the Natural gas sector
Zone 1 – R5.09/GJ – Secunda – Gauteng
Zone 2 – R14.20/GJ – Witbank – Middleburg
Zone 3 – R5.61/GJ – KwaZulu-Natal
The approved tariff by Nersa for Sasol Gas Ltd of R117.69/GJ was approved on 26 March 2013.
Sasol Gas is the sole supplier of natural gas in Gauteng, but Egoli
Gas distributes the majority. Apart from PetroSA’s own use from its
offshore fields, Sasol is the only supplier of natural gas in South
Africa. Supplying 80% of the consumed gas in South Africa via
natural gas or methane rich pipelines. Sasol’s petrochemical and
GTL plant consumes 60% of the gas in South Africa.
In June 2014 the company entered into a joint venture with Eni to
explore 82,000 Km2 offshore of South Africa's east coast for
hydrocarbons. Under the terms of the deal Eni acquired a 40% interest
in the exploration permit and was handed operational rights.
Sasol owns a 140MW gas engine power plant (GEPP) which is the
largest natural gas-fired power plant in Africa and has been fully
operational since July 2013. There are three sections with six turbines.
T
D
Egoli Gas subsidiary of
Realtile
Since 2009 Egoli has been the natural gas reticulator licensee
accredited to distribute piped natural gas to the Greater Johannesburg
Metropolitan (GJM). The company owns a 1,100 km a gas reticulation
network that is regulated by City of Johannesburg and its Municipal
bylaws
The company’s aim is “to improve the promotion of natural gas as an
alternative form of energy for the Greater Johannesburg Metropolitan
area.
The natural gas comes via Sasol’s, Secunda plant in Mpumalanga and
is then directed to a high-pressure bulk-storage facility at Langlaagte
in Johannesburg. Egoli’s gas intake and distribution are then
automatically controlled and reticulated to Egoli Gas’s Cottesloe plant.
It is then stored in low-pressure holders before being distributed to
more than 8 000 homes and businesses across the city through an
extensive 1,200 Km underground gas pipeline network. The company
is in the process of building a 8Km 26” gas distribution pipeline that is
expected to supply MTN.
G
D
Spring Lights Gas (SLG) -
Trader
SLG is reliant on both Sasol Gas and Transnet Pipelines for the
provision of the network infrastructure for the supply of gas from
Sasol Synfuels in Secunda. SLG use the local Sasol pipeline
infrastructure to on-sell Methane Rich Gas (MRG) directly to about 23
customers in KZN from Newcastle through Richards Bay and as far as
Umbogintwini in the south of Durban.
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SLG will often make contributions to the cost of the infrastructure that
connects its customers, although these distribution assets remain the
property of Sasol Gas.
In July 2013 Sasol Gas disposed of its 49% share in Spring Lights Gas
for a purchase consideration of R474 million.
NERSA has approved SLG licence with the maximum gas price set at –
R123/GJ on 27 February 2014.
T
D
N Realtile Trader Reatile has not yet started operating but intends to supply gas in
Gauteng and Kwa-Zulu Natal and has applied for a licence with NERSA.
The Reatile Group is 65% owned by the directors and 35% by Standard
Bank. The Group owns four subsidiaries.
Vopak (30% owned by group). Vopak is the world's largest
independent tank storage provider, specialising in the storage and
handling of liquid chemicals, gases and oil products
Reatile Trading began operating in mid-2007 as a wholesaler of
petroleum products. The company currently supplies petroleum
products to most key petroleum players in the country, including Sasol
Oil, Total South Africa and PetroSA
Reatile Gaz (55% owned by group). Reatile Gaz (d is a major supplier
of LPG within Southern Africa.
Egoli Gas (100% owned by group). Egoli Gas is a natural gas reticulator
and services more than 7500 domestic, central water heating,
commercial and industrial businesses.
T
D
N Novo Energy - Trader NOVO is an integrated gas company specialising in delivering
comprehensive fuel solutions to vehicular, industrial, commercial and
residential customers by making use of compressed natural gas
(“CNG”) technology.
NOVO’s activities include the sourcing of gas from conventional
suppliers (pipelines) or the development of its own alternative or
unconventional methane sources (biogas sources, coal bed methane
and unconventional biogenic) through the cleaning, compression and
distribution of the CNG.
Further activities include the establishment, ownership and operation
of the required gas infrastructure such as gas compression stations,
dispensing stations for vehicles and pipelines for the supply of gas to
customers.
NOVO has 3 NGV filling station at Benoni, Edenvale and Germiston
with Kew NGV service station being launched later in 2014
The first NGV public CNG filling/dispensing station in South Africa
started in Benoni on 27th November 2012. The facility has a capacity
of 850 Nm3/hour. The station has a capability to refuel a dedicated
fleet of more than 1,000 minibus taxis. At present NOVO supplies CNG
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in KZN Summary of key stakeholders in the Natural gas sector
fuel in Gauteng to 669 converted NGVs, mostly taxis. Alternatively
approximately 250,000 GJ/a can be moved offsite for other
applications.
NOVO’s network of Natural Gas Vehicle (NGV) gas dispensing stations
are located in Gauteng. The company has expansions planned for the
Freestate and KwaZulu-Natal provinces.
T
D
N CNG Holdings CNG Holdings was established in 2005 to exploit opportunities in the
natural gas industry, in partnership with SANERI, a former subsidiary
of the Central Energy Fund. The IDC holds a 26% share, Sakhikusasa, a
BEE company 30% and other private investors 44%. It subsidiaries are
NGV Gas (Pty) Ltd, Virtual Gas Network and CNG Technology (Pty) Ltd.
T
D
N NGV Gas (Pty) Ltd –
subsidiary of CNG
Holdings
NGV supplies gas via CNG mobile gas storage and transportation
system. The company has converted mostly petrol taxis to run also on
CNG.
Natural Gas Vehicles (Pty) Ltd (NGV Gas) specialises in providing
turnkey solutions to all fleet owners who want a proven and eco-
friendly energy source that is cleaner and more cost-effective than
petrol, diesel and Liquid Petroleum Gas (LPG).
T
D
N Virtual Gas Network -
subsidiary of CNG
Holdings
Virtual Gas Network (VGN), a division of CNG Holdings and CNG
Technology, since 2009, in an ongoing initiative to help establish CNG
infrastructure for the automotive industry.
VGN supplies Natural Gas in CNG form via special tubes transported
on trailers. These modular road transport system safely and
economically transports Natural Gas to customers in the industrial and
commercial sectors. It also assist customers wishing to set up internal
gas distribution networks, and power generation systems (such as co-
generation and tri-generation projects). At present CNG mobile gas
storage and transportation system are supplied four industrial
customers in Gauteng.
G
D
N CNG Technology (Pty)
Ltd - subsidiary of CNG
Holdings
CNG Technology (Pty) Ltd is a dedicated equipment supply and service
organisation for the Compressed Natural Gas (CNG) industry.
CNG provides the required equipment for natural gas filling stations
and the virtual gas distribution system. The company also supplies the
necessary equipment and expertise to convert petrol and LPG-
powered vehicles to run on CNG.
It further provides funding for conversion kits and in 2014/15 will have
converted and funded 1 000 taxis operating in Gauteng.
CNG Technology also holds the rights for various makes of conversion
kits and technologies that can be installed into petrol- and diesel-
operated vehicles. A natural gas conversion kit gives the vehicle
105 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Type
sector
Active
in KZN Summary of key stakeholders in the Natural gas sector
operator the flexibility to use petrol or Natural Gas at the flick of a
switch, or dual-fuel diesel displacement on diesel vehicles.
The South African National Energy Research Institute has been
partnering with energy company VGN since 2009, in an ongoing
initiative to help establish CNG infrastructure for the automotive
industry.
O
D
Y South African piped gas
association (SAPGA) -
South African Gas
Association (SAGA)
SAPGA’s aim is to be the foremost Gas Support Body in Southern
Africa and promote the safe use and efficient supply of methane
based gas within Southern Africa - http://www.sapga.co.za or ,
http://www.sagas.co.za/
O
D
Y South African
Compressed gas
association (SACGA)
The objectives of the Southern Africa Compressed Gases Association
(SACGA) are related to the safety and technical aspects of the
production, distribution and use of compressed gases
http://www.sacga.za.org/
O
D
Y Southern African
Qualification and
Certification Committee
for Gas (SAQCC Gas)
SAQCC Gas is a section 21 company that has been formed by four
Member Associations LPGASASA, SACGA, SARACCA and SAGA to
establish a central database which displays details of registered and
authorised Gas Practitioners to work on gas and gas systems. The
SAQCC-Gas has been officially appointed and mandated by the
Department of Labour to register gas practitioners, on their behalf,
within the following gas industries:
Natural Gas (SAGA)
Liquefied Petroleum Gas (LPGASASA)
Air Conditioning and Refrigeration Gas (SARACCA)
Compressed Gasses (SACGA)
O
D
Y Liquefied Petroleum Gas
Safety Association of
Southern Africa
(LPGASASA)
LPGASASA is section 21 non-profit organisation that represents many
companies that are involved in LPG installations, distribution,
retailing, hardware and appliances. The Association's aim is to ensure
the sustainable growth of the liquefied petroleum gas industry
through compliance with best safety and business practices.
O
D
Y South African Oil and
Gas Alliance (SAOGA)
SOAGA is dedicated to promoting the upstream and midstream
sectors of the oil and gas value chain, primarily in South Africa and
regionally in Southern Africa. It is a National organization although its
focus is primarily in the Western Cape.
O
D
Y Gas User Group (GUG) The Gas User Group (GUG), which represents 13 large domestic
manufacturers- ArcelorMittal South Africa, Ceramic Industries,
Columbus Stainless, Consol, Corobrik, Distribution and Warehousing
Network, Ferro Industrial Products, Illovo Sugar, Mondi, Nampak, NCP
Alcohols, PFG Building Glass and South African Breweries.
P
U
Y Impact Oil and Gas Impact Oil & Gas is a company whose business model is based on
securing substantial interests in exploration licences, acquiring seismic
data to identify potential drilling locations and then farming down the
company’s interest by bringing in a large operator which helps
106 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Type
sector
Active
in KZN Summary of key stakeholders in the Natural gas sector
monetise their investment. The company started in 2010 and has a
25% participation in the Tugela North and South Exploration rights as
well as blocks further south.
P
U
Y Silverwave Energy PTE
Ltd
Silver Wave Energy was awarded 30 South African offshore blocks of
which 6 are in the deepwater block east of the Sasol / Eni acreage the
company also holds acerage in the far south of the KZN offshore blocks
as well as areas off the Eastern Cape and Western Cape. The company
is based in Myanmar and has submitted applications for exploration
permits.
P
U
Y ExxonMobil Exploration
and Production South
Africa Limited
(EMEPSAL)
EMEPSAL has a number of offshore blocks in South Africa situated
offshore KZN. It has a 75% participation right to the exploration rights
and operatorship of the Tugela North and South blocks in the Zululand
basin. EMEPSAL has submitted for an exploration permit for the
50,169 Km2 offshore acreage it operates in the Durban basin.
ExxonMobil is the largest publically traded oil and gas company in the
world with a presence around the globe.
P
U
Y ENI ENI is a major multinational oil and gas company that has recently
farmed in to the Sasol offshore block East of Durban. It has a 40%
interest and operatorship of this exploration 82.202km2 block. Eni is
an integrated company that operates across the entire energy chain,
employing 82,300 people in 85 countries. Eni part of a consortium in
Mozambique has total resources discovered in Area 4 of the Rovumba
basin estimated at 85 tcf and is looking to export LNG possibly as early
as 2020.
P
U
Y Rhino Resources Rhino Oil And Gas Exploration South Africa (PTY) Ltd., a wholly owned
subsidiary of Rhino Resources, Ltd., holds Technical Cooperation
Permits (TCP) two for offshore blocks in the Cape and three onshore
blocks in the Karoo basin at Frankfort, Petermaritzburg and Matatiele
covering 26,514km2. The Petermaritzburg TCP No.91 covers 15,135
km2 and is the closest onshore block with a TCP to the eThekwini
Municipality.
O
M
Y GDF Suez GDF Suez is the largest independent power producer in the world with
147,000 employees in 70 countries. The peaking power plants GDZ
consortium members are GDZ Suez (38%), Legend Power Solutions
(27%), of South Africa; Mitsui & Company (25%), of Japan and the
Peaker Trust (10%), representing black economic-empowerment and
community interests, The consortium is building two diesel peaking
power plants, the Avon Peaking Power and the Dedisa Peaking Power.
The term of each Power Purchase Agreement (PPA) will cover a period
of 15 years with Eskom being the buyer of power. The Avon site is
designed for peaking operation and emergency situations. It is located
near Shakaskraal (45 Km North-East of Durban). The plant is expected
to be completed in 2016 having taken 2.5 years to build. Total capacity
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Type
sector
Active
in KZN Summary of key stakeholders in the Natural gas sector
will be around 670 MW and designed to allow for a future fuel change
to gas and conversion to combined cycle technology (CCGT).
p
D
N Molopo Oil Molopo oil is a company that is developing coalbed methane. Onshore
production of gas in Virginia (Free State) is imminent from its reserves
(11.5Bcf 1P and 28.7Bcf 2P). The gas is to be converted into CNG and
power underground trains. The CNG engines are to replace the existing
diesel engines in their gold mines so that miners' exposure to
potentially harmful emissions and fuel costs are reduced.
Table 19: Key Stakeholder on the South African Natural Gas sector (Source organisations websites)
The table below indicates the intensive energy users and gas user group companies that have significant
operations in Kwa-Zulu Natal: GUG stands for gas user group and IEU for Intensive Energy Users:
Company Description
Operations in
KZN
GUG IEU
Air Liquide (Pty) Ltd An industrial and medical gas company. Providing solution to customers by
integrating on-site generation and/or bulk supply.
BHP Billiton SA Ltd Aluminium smelters in Richards bay - Hillside and Bayside. The company is a
huge user energy user.
Corobrik
Head office in Durban, with three regional offices in Durban, Johannesburg.
Corobrik has grown to be the leading brick manufacturer, distributor and
marketer of clay bricks, clay pavers and associated allied building products
in South Africa.
FerroIndustrial
Products A local manufacturer and supplier of a specialised range of colours and
coatings – Small part of business in eThekwini municipality.
Illovo Sugar
Ilovo Sugar now produces 90% of its own energy requirements from
renewable resources. The company’s main business is the production of raw
and refined sugar and syrups, production of furfural, furfuryl alcohol,
Agriguard, diacetyl, 2.3-pentanedione and ethanol.
In KZN the company has three agricultural estates, four sugar factories, one
refinery, three wholly-owned downstream plants, a 50% share in a distillery
and 30% investment in a further sugar factory and refinery.
NCP Alcohols
A leading producer of high quality fermentation alcohol for the South African
and International beverage, cosmetic and pharmaceutical markets based in
eThekwini municipality.
Mondi Ltd Paper mill in Durban and a pulp and linerboard mill and wood chipping plant
in Richards Bay.
SAPPI South Africa Paper mills on east coast, Springs, Barberton and Ngodwana(Nelspruit).
Table 20: Intensive energy users and gas user groups, companies in KZN (Source Organisations websites)
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9.3 Regulators
The regulatory bodies enforce rules and regulations, supervise, monitor and impose oversight for the benefit of
the public. The aim is to promote the orderly development of the industry as mandated by associated acts and
regulations.
In the petroleum value chain there are six different economic regulators (excluding Health, Safety and
Environment):
The Minister of Mineral Resources;
The Minister of Energy;
The Petroleum Agency of South Africa (PASA);
The National Energy Regulator (NERSA);
The Transnet National Ports Authority; and
The Ports Regulator.
Currently three have their status currently under review which creates confusion and lack of alignment and
synchronization.
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10 Natural Gas Opportunities and Risks for eThekwini Municipality
This section looks at a number of natural gas opportunities and risks for the eThekwini Municipality that the
Municipality can directly or indirectly influence. Each gas utilisation has associated risks and benefits. Large solar,
wind, hydro and nuclear power solutions are not likely options in the municipality. As a result natural gas
development options should be examined. If the municipality wants greater control over the power produced,
then natural gas is the most likely option to pursue. To ensure energy security the eThekwini municipality must
assess the risk of not starting to build appropriate gas infrastructure in the immediate future as power projects
have long lead times.
.Our assessment of the natural gas opportunities for the eThekwini Municipality assumes that there are no
supply constraints. This assumption is obviously not correct, but does allow for developing an unconstrained
view of what could be possible.
10.1 Natural Gas risk assessment
When assessing the opportunities there will be associated risks with each option that needs to be evaluated,
these include:
Transport Risk: Can infrastructure be developed to transport supply to the point of demand;
Technology Risk: Some of the technologies are still relatively new and must be fully proven;
Price Risk: The fuel price differential required to make it viable and are subsidies required;
Adoption Risk (Demand Risk): Low uptake for NGVs, domestic, commercial and industrial use;
Skills Risk: not enough skills to perform the conversions or manage the technology and infrastructure;
Supply Risk: Lack of natural gas supply for all of the municipalities opportunities;
Alternative Fuel Risk: Are the benefits from gas real;
Financial Risk: Low appetite by private sector infrastructure development - service stations, storage,
import facilities and pipelines;
Exchange rate Risk: Natural gas may need to be imported and paid for in foreign currency;
Environment / Climate change risk: Is gas a cleaner option over the entire natural gas value chain;
Sustainability Risk: Will the introduction have the environmental impact and fit with other strategic
initiatives;
GHG carbon Emission Risk: Natural gas zero status is revised thus gas does not reduce the municipality
emissions;
Carbon tax Risk: Delayed: No tax benefits for motorists or CDM credits not available renewable gas
production;
Competition Risk: Lack of competition;
Regulatory Risk: Price not regulated once out of the gas pipeline, lack of congruence with current
legislations;
Socio-Economic Risk: The impact of the technology will not have the desired benefit on the local
communities;
Energy Security Risk: Delay in building new infrastructure causes supply shortages;
Revenue Risk: Loss of electricity revenue versus a loss of revenue due to rolling blackouts, business
confidence and growth; and
Security of Supply: Does the municipality have other options to directly influence the energy mix.
Overall assessing the infrastructure dilemma and how to tackle critical barriers the opportunities and risks need
to be evaluated so that an enabling environment is created for natural gas development. A joint approach should
be followed where the municipality engages with stakeholders such as gas suppliers/ traders, equipment
110 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
providers, vehicle manufacturers, haulage, taxi and passenger fleet operators (public and private), financial
institutions, end users, government stakeholders, regulators, and municipal and provincial departments so that
natural gas development is managed in an appropriate manner.
There are eleven areas that need to be addressed for each option:
Security of supply in sufficient quantities at a reasonable price;
Technology has to be proven as an economic and feasible option to the stakeholders;
Possible demand needs to be demonstrated so that there is an appetite to invest;
The environmental impacts and carbon emissions need to be established and communicated;
The investment climate needs to be made attractive to investors, incentives, subsidies, road maps etc;
Funding in sufficient levels to kick start development must be available;
Socio- economic impact needs to benefit the communities;
Regulations, policies and plans providing clear direction and congruence with one another are required;
Time taken for appropriate infrastructure development;
What type of control does the municipality want?; and
Does the gas development fit into the municipalities’ long term objectives based on the integrated
development plan.
10.2 Advantages of Natural Gas
Energy efficient;
Lower equipment maintenance cost;
Power stations can be built in modules over a period of time;
Building gas power stations much quicker than coal or nuclear;
Cheaper transportation costs;
Convenience when piped to location;
Environmentally cleaner than other fossil fuels – Cleaner air;
Reliable;
Safe;
World supply of 250 years means that the risk of supply in the short term is low;
Diversity and security of supply - fuel price stability;
Flexibility and can be used continuously or for peaking demand;
Stimulate economic activity and related industry (many manufacturing applications);
Could be sourced locally in the future;
Pathway to Hydrogen (technology & infrastructure platform); and
Build local skills capacity while creating new jobs job creation.
10.3 Disadvantages of Natural Gas
Current local demand exceeds supply;
Costly to establish infrastructure;
Local availability limited;
High upfront costs;
GHG emissions along the life cycle are similar to other transportation mediums;
Pricing uncertainty, including oil indexation;
Lead time to supply; and
Not easily portable.
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10.4 EThekwini Municipal Role
The three ways that the Municipality can influence the developing of the gas sector are as a:
Direct participant: The municipality directly invests in natural gas infrastructure (e.g. power plants,
natural gas vehicles, etc.);
Influencer / Facilitator: Creating the enabling environment that would support increased gas utilisation
through for example accelerating the approval processes associated with gas ventures; and
Gas advocate: raising awareness of the benefits of natural gas amongst stakeholders.
10.4.1 Direct Participant
The main areas where the Municipality can directly participate in the natural gas sector as an operator, gas user
or both are:
Landfill and wastewater gas production of renewable natural gas from their owned sites for use in
power generation or natural gas vehicles;
Creation of new reticulation networks to new industrial, commercial and residential developments;
Switching coal and oil boilers at municipal buildings to gas that produces electricity and capture
emissions for using in cooling the buildings;
Development of a green development zone for green businesses including gas;
Converting government vehicles to CNG;
Building a CNG refuelling facility to power municipal fleet and kick starting infrastructure for NGV
development;
Creating storage and pipeline network for feeding LNG ships at the port;
Hospitals and other large public buildings to switch to tri-generation;
Building and operating gas power plants; and
Building and having third party manage power plant operations.
10.4.2 Influencer
The municipality also is an enabler that influences infrastructure development and investment by:
The creation of gas by-laws;
Reduce red tape and fast track gas applications;
Fleet conversion, provide incentive for private refuelling NGV infrastructure;
Subsidies to public transport operators based on CNG conversion;
Provide municipal sites for refuelling or storage;
IPP – wheeling agreement to purchase gas produced electricity directly from Avon peaking power
station (Create economic reason to switch to gas);
Subsidise gas tariffs;
Reduce rates to green companies;
Industrial development zone for green business, including gas;
Road map for gas development and policies;
Road map for green development18 to encourage international expertise;
Award commercial, industrial and domestic tenders to suppliers that include gas infrastructure; and
Partnerships with businesses to develop renewable gas production, such as land fill gas.
18 Note that not all natural gas options may be considered greener along the life cycle analysis, such as natural gas vehicles
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10.4.3 Advocacy
The third way that the municipality can influence the gas sector is through an advocacy role:
Road map for green development to encourage international expertise;
Inform taxi associations of the economic benefits for change;
Identify benefits of gas and encourage users to switch;
Educate users of the benefits of natural gas and the differences with LPG;
Educate and dispel negative perception regarding the safety of CNG and natural gas;
Provide specific gas related training (up skill work force);
Facilitate loans from financial institutions; and
Set emission targets for shipping – linked to international targets, LNG storage and piping network
development as well as provide sites.
10.5 Gas utilisation options
Likely gas supply options within the eThekwini Municipality will be discussed in the remainder of this section.
Figure 47: Gas Utilisation applications (Source PwC)
10.5.1 Piped gas supplying domestic, industrial and commercial
For heat, cooking and cooling purposes:
Continued or increased supply along the Lily pipeline supplied via Secunda – increase pressure from 40-
53 bar with more compression stations along line;
Coalbed methane feed into the Lily pipeline;
New gas pipeline from CBM fields such as Kinetiko’s Amersfoort area that is 300KM from Durban;
The most likely source of provincially produced gas in large quantities is likely to come from
conventional drilling off the coast;
Development of the Gasnosu pipeline from Northern Mozambique through to Richards Bay and
extended down into Durban;
Shale gas could be piped to the eThekwini municipality, but unlikely as major exploration is in the Karoo
and more likely to be piped to PE or Mossel Bay; and
LNG imports via Richards bay piped as natural gas into distribution pipeline.
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10.5.2 Gas to Wire
This will mostly come from outside the eThekwini Municipality (Power generation):
Shale gas is likely to be converted into power at sites near to production (new power plants);
Coalbed Methane into new power plants;
Coalbed Methane to supply existing Eskom power plants – converted from coal or diesel;
Landfill sites gas (Only able to supply small amounts, at present about 0.4% of eThekwini Municipalities
demand);
LNG imports via Richards Bay supply gas to power plants; and
Increased pipeline capacity, new pipelines from Secunda or Mozambique supplying gas to power plants
in KZN or other provinces.
10.5.3 Feedstock
Gas to GTL plant (unlikely as it is more likely to be situated in Gauteng or Mossel Bay) processed into
liquid fuels however no GHG benefits to the Municipality; and
Petrochemical plants such as chemical and fertiliser plants would have no GHG benefit to the
Municipality, however there would be many socioeconomic benefits.
10.5.4 Transportation
LNG (Primarily transportation – ocean going vessels):
LNG imports via a Richards bay terminal (transported by trucks) to refuelling stations or to the Port of
Durban; and
Storage at the port.
CNG for road transportation:
CNG as mother or daughter refueling stations, depending on location of pipeline networks (Most likely
gas supply would be via LNG exportation or Lily pipeline);
Landfill, Manure-Based Anaerobic Digestion and Wastewater Treatment Sludge biogas to mix with CNG
or LNG to lower emissions including GHG emissions below that of conventional fuel; and
Own fleet, buses, taxis and HDV haulers conversion.
Appendix B provides greater information on gas transportation options
10.5.5 High Level Utilisation
The high level utilisation option plan in table 21 provides an overview for the municipality. For each option there
is an indication of the impact that the option will have on GHG emissions, the role that the municipality could
possibly play, the benefits and barriers, as well as the indicative costs associated with each option. A more
detailed discussion of these utilisation options at a generic level is set out in Appendix A. Section 11 of this report
builds on these options, and provides a recommended set of options based on three distinct demand scenarios.
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High level natural gas utilization option development for the eThekwini Municipality
Key: = Better / low; = Indifferent / Moderate; Worse / High
Natural gas utilization options for the eThekwini Municipality
GHG LCA Position
COx, NOx, SOx Position
Municipality Role Direct (D) Influencer (I) Facilitate (F)
Barriers Benefits Cost Rm Low ˃100 Medium 100-1000 High˂1000
Volume and type of gas
Transport NGV Passenger cars Taxis Buses HDV Rail Shipping
↓ or≠
A
↓
A
(D)Build infrastructure, convert fleet,
(D)LFG Biogas (I) Incentives,
provide land (F) OEM in KZN (F) negotiations
Higher NGV upfront costs Lack of infrastructure Resistance to change Lack of choice - No RSA OEMs Range between refuelling stops LCA GHG emissions the same as
conventional fuels High Mileage to be viable
Cheaper fuel 20-30% Low life cycle costs Mix Biogas with CNG Cleaner and safe NGV and Novo Energy in RSA Carbon emission taxes
Low
A
Low to Moderate
- A
CNG LNG
Power generation ↓
A
↓
A
(D) LFG (I) Avon change to
gas (F) Local and
national Govt policies engagement
Eskom ownership Lack of REE power generation in
KZN– Gas DoE IPP focus on RE Wholesale price deregulation
Large reduction in GHG Policy, plans etc, government
commitment RE power flexibility support New build cheaper and quicker
than coal Cheaper feedstock
High
A
High
A
Piped NG
Feedstock Chemicals Synfuels (GTL)
↑
A
↑
A
(I) - IDZ (F) – Encourage
usage (F) Road map
Very high Cost – Competing against PetroSA in Mossel Bay and Sasol in Gauteng - Synfuels
Industry commitment
High levels of job creation Port – exports Refineries not meeting EuroV
standards – existing pipeline Manufacturing opportunities
High
A
High
A
Piped NG
Domestic Use ↓
A
↓
A
(D) By-Laws (I) Infrastructure (F) campaigns
Lack of piping infrastructure Lack of knowledge Financing
6 areas have piping network systems
Cleaner - piped to source.
Low to Medium
-
Low
A
Piped NG Industry / Commerce
↓
A
↓
A
(D) By-Laws (F) more supply (F) Road map
Lack of gas infrastructure network
Financing
Existing gas network Cheaper fuel source Good thermal applications Cogeneration
Low to Medium
- A
Moderate
A
Piped NG
Municipal Large Buildings e.g. hospitals
↓
A
↓
A
(D) build / conversion
Cost of conversion Infrastructure Budget restraints
Tri-generation Municipality commitment to
greener economy
Low to Medium
- A
Low
A
Piped NG
Table 21: High Level Gas Utilisation Options (Source PwC)
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11 Appropriate response options and action plan formulation for the eThekwini
Municipality
When assessing appropriate opportunities the Municipality must look at the entire integrated energy plan prior
to making any decision on the role that gas must play in the energy mix. The integrated energy plan must set
gas objectives which are clearly defined so that options are considered against set criterion.
11.1 Demand Scenarios
For the purposes of this report, and in the absence of a comprehensive and integrated energy strategy, we have
devised three potential demand scenarios which were used to recommend appropriate response options. These
options have been informed by the utilisation options that have been discussed previously. Only those that the
municipality can significantly affect are considered appropriate response actions upon which to formulate an
action plan. For example the municipality could not directly influence the ports authority to have LNG storage
and pipelines built during the present port construction upgrade with the aim that ocean going vessels would in
the future run on LNG. It also has no influence over the construction of GTL facilities.
The three demand scenarios are: In the low gas demand scenario little change in the supply of gas will be required. The proposed pilot
projects will be supplied by new landfill and wastewater sludge gas production or from the Secunda
along the existing distribution network;
In the medium demand scenario an increase gas supply would be required and most likely met by
increased supply through the Lily pipeline. An investment of more compression stations along the
length of the Lily pipeline would be required. (if this is technically feasible); and
In the high demand scenario natural gas would need to be supplied by imported LNG or via new gas
pipelines from Mozambique either directly via Richards Bay or Secunda. The high demand case scenario
would provide a business case for large infrastructure development.
High level natural gas demand options influenced directly or indirectly by the eThekwini Municipality
LOW DEMAND
Utilisation option High level Description Key Stakeholders Indicative timeframe and costs (based on recent RSA projects where available)
IRP CCGT and OCGT new power generation build
In the low demand scenario the municipality does nothing and allow the gas IPP PPA process to occur with no municipal intervention
The energy mix change will happen as per IRP2010 with no guarantee of where the power plants will be located
Department of Energy Independent power
producers Eskom
3 -5 years from start of government procurement process
R14 million per MW Gas supply not known
Landfill gas and wastewater production
The municipality will ramp up and/or start production at landfill and wastewater sites.
The gas can be utilised for transport, heat or power generation.
The gas is locally produced with positive socio- economic and environmental benefits.
Municipal cleansing and solid waste unit
Municipality electricity division
Private partnerships
1 year All sites landfill and
wastewater sites evaluated immediately.
Increased local natural gas production
NGV pilot projects The municipality starts a pilot project on purchase of new buses for the IRPTN.
Other HDV options such as waste removal trucks
Evaluation of benefits and disadvantages. Municipality depots upgraded to supply CNG Only 1 or 2 refuelling depots would need gas
compression dispensers
Energy Department Transport department
and authority OEMs negotiations CNG solution companies
Novo/VGN dispensing and conversion
Within a year Purchase based on IRPTN R250,000 additional
capex cost per bus. R20-30,000 car/taxi
conversions
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LOW DEMAND
Refuelling compression and dispensers R4million to R20 million
Supplied by landfill gas / wastewater sludge gas production or from spare gas supply in lily pipeline
Large building pilot projects
The municipality converts a number of buildings to be powered on gas, with an emphasis on tri-generation. Particular focus on hospitals
Evaluation of the benefits and disadvantages. Gas via existing pipelines, possible extension
of reticulation pipeline network.
Private partnerships Health Department Electricity department
1 – 2 years R11m per MW if gas
engines power generation
Supplied by landfill gas / wastewater sludge gas production or from spare gas supply in lily pipeline
MEDIUM DEMAND Requires increase local gas production and capacity along the Lily pipeline
Utilisation option High level Description Key Stakeholders Indicative timeframe and costs
Convert municipal fleet to CNG
The municipality would convert their entire transport fleet to run on CNG. The extra upfront capital costs would only be viable for long distance non passenger cars.
The LCA of CNG is considered neutral Would require a number of refuelling
stations across the municipality, own and operated by municipality or private companies.
Pipeline and virtual networks required Needs to be part of the IRPTN process
Energy Department Transport department
and authority OEMs negotiations CNG solution companies
Novo/VGN dispensing and conversion
Start within a year, all replacement vehicles to run on CNG.
Purchase based on IRPTN rollout schedule
R250,000 additional capex cost per bus
R20-30,000 car/taxi conversions
Large dispensing sitesR20 to 25 m.
Daughter stations R2 to R4 million
Require increase local gas production and increased capacity along Lily pipeline.
Convert municipal buildings to be powered by gas
The municipality converts a number of buildings to be powered on gas, with an emphasis on tri-generation. Particular focus on hospitals and large energy use buildings
Evaluation of the benefits and disadvantages for various size buildings and their operation
Need to get gas via pipeline or mobile CNG cascades
Private partnerships Health Department Electricity department Transnet
1 – 15 years R11m per MW if gas
engines power generation
Mobile cascades R2 m, transporters R4 m.
Reticulation network R2 – R4 m depending on pipeline requirements
Supplied by landfill gas / wastewater sludge gas production or from spare gas supply in lily pipeline
Significant influence in encouraging switching to NGVs
The municipality can encourage private investment in refuelling stations by creating demand with own fleet conversion and encouragement of other private business infrastructure development
The municipality can influence and advocate gas conversion through a number of solutions such as subsidisation, providing land for refuelling sites, educating users on cost saving benefits and only providing route licences to operators who convert a percentage of their fleet to NGVs
Energy Department Transport departments –
Road, rail etc OEMs negotiations CNG solution companies
Novo/VGN dispensing and conversion
Gas traders (including 5 traders existing today)
Within a year Purchase based on IRPTN R250,000 additional
capex cost per bus. R20-30,000 car/taxi
conversions Large dispensing sitesR20
million. Supplied by Landfill gas /
wastewater sludge gas production or from
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MEDIUM DEMAND Requires increase local gas production and capacity along the Lily pipeline
Domestic, industrial and Industry increased gas uptake
The municipality can provide gas infrastructure with new developments or to significantly important industries. Uptake dependent on infrastructure, cost advantages and guaranteed supply
The municipality can encourage use through education, charging electricity prices higher than those it would cost to use gas
Assist other traders to enter gas supply market
Gas could trade in future gas supply Possible loss of electricity revenue, but
creates economic growth for businesses due to competitive advantages.
Incentives for business to switch to gas power generation, due to high split electricity tariffs or an environment where excess power is brought by the Municipality
Energy Department Intensive energy users Gas user associations All industry using thermal
applications Gas traders including 5
traders existing today) NERSA Transnet CNG solution companies
Start 1 -2 years R2 – R4m per Km for local
gas pipeline network expansion
Virtual gas networks provided through mobile CNG solutions
HIGH DEMAND Would require a guaranteed large offtaker and significantly increased supply via LNG import
facilities or new gas pipelines from sources such as Mozambique and CBM. Large Infrastructure development required prior to meeting local demand
Utilisation option High level Description Key Stakeholders Indicative timeframe and costs
New gas powered generation in municipality
In this scenario large scale volumes of gas are required and the municipality directly influences where new gas powered stations are built and has greater control over its energy gas emissions and supply. Greater localisation of electricity supply. The municipality must have these options clearly defined and road mapped in the integrated energy plan. Three main options exist: Power purchase agreements with
Independent power producers (including Avon power plant which is under construction).
Municipal owned and operated power plants
Municipal owned with third party operated For each of the options the municipality must decide how the gas powered plants will be utilised. Decisions will include if it will be used for baseload, for peak shaving or a combination of both. The municipality would be able to charge industry electricity tariffs as they do now.
Department of Energy Independent power
producers Eskom Treasury /Finance
department
3 -5 years from start of government procurement process
R14 million per MW for Gas engine powered plants
Gas supply needs to be guaranteed via LNG imports, increased capacity via new or existing pipelines.
Table 22: EThekwini Municipality low, medium and high demand options (Source PwC)
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11.2 Indicative capital costs
When making appropriate decision capital costs play a significant role as municipalities only have a finite amount
of capital. An indicative estimate of the capital costs for various infrastructure projects that might be expected
in South Africa are as follows.
11.2.1 Cost of gas assumption
Gas costs USD 11 per BTU.
11.2.2 Pipelines:
Transmission 26” Pipeline:
o R22m per kilometre ( USD 1 Billion – 500 km – 26” – 160 PJ/a); and
o New compression stations: Unknown.
Small Distribution and Scale Pipelines
o R 2m per kilometre: small diameter; and
o R 5m per kilometre: large diameter.
CNG and LNG refuelling stations (virtual pipeline) in South Africa:
o Mother stations: R 25m;
o Transporters: R 4m; and
o Daughter stations: R 2m.
Size (Kg/d) - (L/a) Size CNG Station LNG Station L-CNG Station
500 - (200,000) Small R2.8m R1.3m R2.6m
1,000 - (400,000) Medium R3.5m R1.6m R3.5m
5,000 - (2,000,000) Large R6.2m R4.6m R8.8m
10,000 - (4,000,000) Very Large R12.3m R6.2m R14.1m
Table 23: International refueling infrastructure costs (Brightman et al (2011))
11.2.3 Conversion costs of Vehicle to CNG
Taxi conversion from Petrol to NGV cost R20,000 (lower than the R30,000 it would cost in the US);
New passenger vehicles cost between R40,000 to R80,000 more than conventional cars (CNG);
New buses could be up around R250,000 incremental cost (CNG);
New trucks could be around R250,000 incremental cost; and
New rail locomotives approximately R11 million incremental cost (LNG)
11.2.4 LNG import facilities
LNG and CNG costs for the midstream value chain from processing, transportation to unloading (excluding
upstream and downstream). The unloading and regasification costs would be the most relevant investment costs
for South Africa as the product will be imported until sufficient supply is found locally.
Size of investment for a 500mscf/d plant
CNG LNG
Reserves Small to modest Large
Unloading costs /regasification USD16-20 million USD 375-750 million (onshore)
Floating and regasification units (FSRU) 50% less
USD 280-300 million vessel costs.
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Table 24: International LNG and CNG unloading costs (Source PwC analysis)
PetroSA has estimated that capital costs for their proposed LNG import terminal at Mossel Bay would have cost
between USD 375 million to USD 510 million.
11.2.5 Gas powered plants
When assessing gas power plants the size, cost, use, plant efficiency, length of power purchase agreement,
payback period, emission reduction and a number of other options such as modular stage development in stages
need to be assessed and full pre and full feasibility studies performed.
The Avon OCGT power plants construction will cost around R11 million per MW. A 15-year power purchase
agreements (PPAs) with Eskom for the two OCGT power plants currently being built (335 MW Dedisa plant, in
the Eastern Cape, and the 670 MW Avon facility) in KwaZulu-Natal with a combined capacity of 1 GW and a
combined investment of around R11 billion.
The recently completed Sasol GEPP cost R14 million per MW.
No recent CCGT plants have been built in South Africa, although costs range from R7 million to R 20 million.
11.2.6 Gas powered tri-generation at hospitals
The cost is around R11 million per MW.
Below is a high level utilisation summary on the three ways that the municipality can influence gas utilisation.
Utilisation options
The Municipality can directly participate, significantly influence or through advocacy have a bearing on the
utilisation options and gas demand required and this is summarised in the table below:
Ethekwini municipality influence
High level utilisation summary and demand requirements
Direct participant Power
Landfill and wastewater natural gas production (Low)
Build, own and operate own power plant (High)
Build, own and have third party operate power plants (High)
Conversion of municipal buildings to run on gas boilers, gas engine power installation e.g hospitals tri-generation. (Pilot projects - Low Demand; Conversion of significant proportion of the municipal buildings - Medium demand )
Transport
Convert municipal fleet to run on CNG (Pilot project - Low demand: Conversion of entire fleet - Medium Demand
Build dispensing depot facilities (Low to Medium)
Domestic / Commercial / Industrial
Build and operate reticulation networks (Medium)
Influence Power
Create case for Avon IPP to switch to gas as feed stock (High)
PPA with IPP (guaranteed offtake agreements) (High)
Transport
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Ethekwini municipality influence
High level utilisation summary and demand requirements
Municipal fleet create critical mass for CNG NGV network development (Medium)
Domestic / Commercial / Industry
Reduced rates for greener business (Low to Medium)
Creation of appropriate by-laws (Low to High)
Buy back excess power produced (Medium)
Increased technical training for gas applications (Low to High)
Split tariffs, cheaper for business to generate own electricity from gas over certain times. (Medium)
Advocacy Power
Encourage government to build gas power plants in KZN (build case as renewable, nuclear and coal power generation outside province) – Security of supply for the regions. (High)
Transport
Educate about the benefits of NGV (Low)
Facilitate loans (Low to High)
Encourage LNG facility development at Port (High)
Feedstock
Road map – reduced red tape – manufacturing incentives and subsidies (Low to High)
Domestic / Commercial / Industry
Road Map (Low to High)
Educate about benefits of natural gas for power, heat, cooking and thermal (Low to High)
Create a conducive environment for business with greater control to manage rolling blackouts (Low to High)
Table 25: High level summary of options for natural gas (Source PwC)
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12 Conclusion and Next Steps
Natural gas must be seen as part of total energy solution within the energy mix and can be used for multiple
applications.
The main difficulty for the eThekwini Municipality is that at present there is limited supply of natural gas into
the province and the demand in the country outstrips supply.
An integrated energy plan must be developed before any decisions on the role of natural gas can be taken.
The demand for gas is most likely to come from power generation. The municipality can passively accept the
IRP 2010 and allow national government, departments and Eskom to control the construction of gas power
station, or the municipality can actively influence future construction and location of gas power generation into
the province.
The main advantage of gas power being located in the province is that the municipality will be less reliant on
power from elsewhere, it can have greater control on its energy mix as well as benefit from a socio-economic
growth in the form of employment and business growth.
Natural gas is a cheaper and cleaner option than new build coal power stations.
For transport it is debatable if it is cleaner option over the entire Life Cycle of the gas value chain, however for
heavy duty and high mileage fleets the higher upfront cost can be recovered by cheaper gas fuel prices.
Feedstock for large industry, such as petrochemical and Gas to Liquid plants require huge upfront costs and large
supplies of natural gas, so these options are not viable to the municipality.
There are certain options that should be investigated immediately and these include:
The feasibility of increased local gas production from landfill and wastewater sites;
Pilot projects to evaluate gas powered buses as part of the integrated rapid passenger transport
network;
Pilot projects with gas tri-generation at hospitals to evaluate benefits; and
Creation of suitable gas bylaws.
The municipality should also be in discussion with key stakeholders such as Eskom, Department of Energy,
traders, Independent power producers, regulators and municipal departments to find long term gas solutions
and mitigate any associated risks.
The appetite for gas in the medium and high municipality demand option scenarios should be evaluated and
tied into the overall integrated energy plan objectives and vision for the municipality.
The municipality needs evaluate each gas option in respect to the integrated development plan from a climate,
environment, financial, socio- economic and control over energy mix perspective.
The following hurdles will have to be overcome by the municipality:
Determination of how gas fits into the integrated energy plan for the municipality;
Significant upfront capital required for infrastructure development, and associated financing
challenges;
Current lack of gas infrastructure;
The municipality has limited resources for competing priorities;
Potential loss of revenue as businesses switch to gas and buy less electricity;
The lack of incentives/subsidies to encourage investment in gas infrastructure projects;
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Natural gas emissions from different sources need to be clearly understood and defined;
Regulations and policies are being amended so there is a lack of congruence of policies and regulations
GUMP, MPRDA and gas act not finalized;
Lack of coordination by various government departments lead to misalignment of legislation regulating
gas;
Lack of policy drive on the increased use of natural gas in core economic sectors (Electricity industry
and transport sector);
Debate on the greenhouse gas emission benefit of natural gas when the entire value chain is taken into
consideration;
Lack of horizontal integration and competition hindering growth; and
Negative perception on safety and performance of NGVs.
Overall natural gas has many advantages and disadvantages that need to be assessed when developing options.
Advantages significantly out-weigh the disadvantages. A favourable investment climate, clearer policies and
frameworks, clear consistent regulatory oversight encouraging greater horizontal integration, incentives and
private sector partnerships will ensure that the sector flourishes and creates the socio economic benefits
envisaged by the municipality.
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Appendix A: Gas for power generation
Gas utilisation options and their benefits are discussed below in more detail to provide a greater understanding
on various options that the municipality could follow.
Gas for power generation
Moving into the future, South Africa’s energy choices will not only be carbon constrained, but also cash
constrained with ever-increasing geo-political complexity and associated security of supply challenges.
Technology choices will also have to be made which are proven or low risk, have public support and are
financeable. The full extent of South Africa’s nuclear new build aspiration (9600 MW) will be challenging in this
regard from a cost, schedule and skills perspective. Utilisation of indigenous and carbon benign energy carriers
will therefore be an imperative to ensure sustainable and affordable security of supply. This will present a sizable
opportunity for gas-fired power generation and specifically CBM.
Electricity generation technologies all have advantages and disadvantages. Renewable technologies such as solar
and wind use “free” resources and don’t produce harmful greenhouse gases, but are not always available when
needed and require significant amounts of land. Technologies such as coal and nuclear produce electricity in
large quantities reliably around the clock, but result in significant greenhouse gases (in the case of coal) and
long-term waste disposal considerations (in the case of nuclear). Natural gas has the benefit of being able to
generate large quantities of reliable power and have lower greenhouse gas emissions than coal, no waste
disposal problems of nuclear and can be used in peaking power stations or in combination with solar power.
The EPRI’s Prism recognised trade-offs and emphasize the importance of a diverse array of technologies for
reducing carbon dioxide (CO2) emissions while economically and reliably meeting electricity demand and
complying with existing environmental regulations. When properly applied as part of an integrated portfolio, all
generation technologies play useful roles that capitalize on their strengths.
The table below compares the various power generation technologies, and demonstrates the suitability and
benefits of natural gas for power generation.
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Coal Coal w/CCS*
Natural Gas
Nuclear Hydro Wind Biomass Geothermal Solar
Construction cost New plant construction cost for an equivalent amount of generating capacity
5 7 4 0 6 5 6 7 6
Electricity cost Projected cost to produce electricity from a new plant over its lifetime
4 6 4 5 7 6 6 6 7
Land use Area required to support fuel supply and electricity generation
6 6 5 4 6 7 0 5 7
Water requirements Amount of water required to generate equivalent amount of electricity
0 0 6 0 6 4 0 6 4
CO2 emissions Relative amount of CO2 emissions per unit of electricity
0 5 6 4 4 4 5 5 4
Non-CO2 emissions Relative amount of air emissions other than CO2 per unit of electricity
0 0 6 4 4 4 7 5 4
Waste products Presence of other significant waste products
0 0 4 6 4 4 7 5 4
Availability Ability to generate electricity when needed
4 4 4 4 6 0 4 4 0
Flexibility Ability to quickly respond to changes in demand
6 6 4 7 4 0 6 5 0
More favourable ←4−−−5−−−6−−−7−−−0→ Least favourable
Table 26: Choosing electricity generation technology reference card EPRI (Source EPRI)
Natural gas-fired electric generation and natural gas-powered industrial applications offer a variety of
environmental benefits and environmentally friendly uses over coal powered electricity generation, including:
Fewer Emissions: Combustion of natural gas, used in the generation of electricity, industrial boilers, and
other applications, emits lower levels of NOx, CO2, and particulate emissions, and virtually no SO2 and
mercury emissions. Natural gas can be used in place of, or in addition to, other fossil fuels, including
coal, oil, or petroleum coke, which emit significantly higher levels of these pollutants;
Reduced Sludge: Coal-fired power plants and industrial boilers that use scrubbers to reduce SO2
emissions levels generate thousands of tons of harmful sludge. Combustion of natural gas emits
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extremely low levels of SO2, eliminating the need for scrubbers, and reducing the amounts of sludge
associated with power plants and industrial processes; and
Reburning: This process involves injecting natural gas into coal or oil fired boilers. The addition of
natural gas to the fuel mix can result in NOx emission reductions of 50 to 70 percent, and SO2 emission
reductions of 20 to 25 percent.
Cogeneration: The production and use of both heat and electricity can increase the energy efficiency
of electric generation systems and industrial boilers, which translates to the combustion of less fuel and
the emission of fewer pollutants. Natural gas is the preferred choice for new cogeneration applications.
Combined Cycle Generation – Combined-cycle generation units generate electricity and capture
normally wasted heat energy, using it to generate more electricity. Like cogeneration applications, this
increases energy efficiency, uses less fuel, and thus produces fewer emissions. Natural gas-fired
combined-cycle generation units can be up to 60 percent energy efficient, whereas coal and oil
generation units are typically only 30 to 35 percent efficient.
Fuel Cells: Natural gas fuel cell technologies are in development for the generation of electricity. Fuel
cells are sophisticated devices that use hydrogen to generate electricity, much like a battery. No
emissions are involved in the generation of electricity from fuel cells, and natural gas, being a hydrogen
rich source of fuel, can be used. Although still under development, widespread use of fuel cells could
in the future significantly reduce the emissions associated with the generation of electricity.
Flexible power generation: Natural gas power plants can adjust load daily, ramping up and down with
demand and balancing the intermittent production of renewable energy sources.
Natural gas can be supplied to power stations in a number of ways although it is predominantly supplied through
a large transmission pipeline. There are three main types of large scale gas power plants:
Open Cycle Gas Turbines (OCGT);
Combined Cycle Gas Turbines (CCGT); and
Gas Engines.
The table below compares these gas technologies with reference to the gas reserves required, capital intensity,
speed to market and the role that the eThekwini Municipality can play with respect to each option.
Gas power generation options
(100MW plants, except LFG with 10MW)
Reserves required BCF
L= >1000 M=100-1000
S =< 100
Capital Intensity
and efficiencies
Capital Intensity ($m)
L = > 75 M = 50-75
S = < 50
Speed to Market
(months) Fast = <36 M = 36-48 Slow = >48
Comments eThekwini influencer /
Enabler
OCGT–(Peaking) New build
$53m $/KW 534 34%
Good for peaking power
Own and build / IPP PPAs
OCGT- (Peaking) Conversion to gas
34%
Avon IPP N.E of Durban. Local
Through IPP PPA and
CCGT – (base load and peaking)
$78m $/KW 781 54%
30% more EE and emits around half the CO2 of coal.
N/A
Gas engine –reciprocating (base load and peaking)
$67m $/KW 667 47%
Can be built quickly in small modular units.
Own and build / IPP PPAs
Landfill gas – power generation
CDM credits available and considered as RE.
Enabler increase production
Table 27: Gas power generation technology comparison (Source PwC)
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Power Plant Technologies:
A more detailed description of each of the technologies mentioned in the table above is set out below.
Open Cycle Gas Turbine OCGT
Combustion turbines are another widespread technology for centralized power generation in a combustion
turbine, compressed air is ignited by burning fuel (e.g., diesel, natural gas, propane, kerosene, or biogas) in a
combustion chamber. The resulting high-temperature, high-velocity gas flow is directed at turbine blades, which
spin a turbine driving the air compressor and the electric power generator. Combustion turbine plants are
typically operated to meet peak load demand, as they can be switched on relatively quickly. Another advantage
is their ability to be a firm backup to intermittent wind and solar power on the grid, if needed. The typical size is
100 to 400 MW, and their thermal efficiency is slightly higher than steam turbines at around 35 to 40 percent.
Combined Cycle Gas Turbines - CCGT
A basic combined-cycle power plant combines a combustion turbine and a steam turbine in one facility.
Combined-cycle plants waste considerably less heat than either turbine alone. As combustion turbines operate
at higher temperatures, it creates increasing amounts of exhaust heat which is captured and used to boil water
for a steam turbine generator, thereby creating additional generation capacity from the same amount of fuel.
Combined-cycle plants have thermal efficiencies in the range of 50 to 60 percent. Historically, they have been
used as intermediate power plants, supporting higher daytime loads; however, newer plants are providing
baseload support. Cutting edge natural gas combined-cycle power plants are coming online with thermal
efficiencies at 61 percent with a correspondingly smaller emission of greenhouse gases; these plants are able to
cycle on and off more frequently (than most of the installed power plant fleet) to more efficiently complement
intermittent renewable generation.
Gas Engine
The plants are based on modular engine units that can use various gaseous fuels and run even in the most
challenging ambient conditions. Sometime called reciprocating engines, they employ the expansion of hot gases
to push a piston within a cylinder, converting the linear movement of the piston into the rotating movement of
a crankshaft to generate power. Reciprocating engine sizes for power generation modules range from 4 to 20
MW and have an efficiency of 46-49%.
Biogas including Landfill gas
Biomethane can be produced from a variety of sources by the breakdown of organic material in the absence of
oxygen and sources include sewage, municipal solid waste, and farm waste. Biomethane is the fuel that is
produced by removing any impurities from the biogas. And unlike fossil fuels, which are considered a finite
resource, the natural gas produced from these sources is a renewable resource and can be used in all natural
gas applications. It has been identified by the government as a renewable source of energy for electricity
generation. The capture and combustion of landfill gas stops methane emissions to the atmosphere, and reduces
GHG into the atmosphere in terms of the Clean Development Mechanism (CDM).
Landfill gas (LFG) is released as a result of the decomposition of refuse at landfill sites and is composed of 50-
60% methane gas, 50 - 40% carbon dioxide and a small percentage of non-methane organic compounds. The
methane gas (CH4) found in LFG is a greenhouse gas (GHG) that has a high global warming potential (GWP), 21
times as high as the same unit of CO2. LFG can be prevented from entering the atmosphere by extracting the
gas and converting the CH4 component into an energy source. CH4 is a high energy clean burning gas which is
suitable for Combined Heat and Power (CHP) electricity generation and natural gas processing where it can be
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compressed or liquefied for use in the transportation sector. The Argon national laboratory has estimated the
processing to be extremely efficient with low methane leakage as noted in the table below:
Landfill Gas pathway
Natural gas processing efficiency: 94.4%
CHP electrical and thermal efficiency: 30% and 50%, respectively
CH4 leakage rate in NG processing: 2%
Compression efficiency: 97.1%
Liquefaction efficiency: 96.4% Table 28:Life0Cycle Analysis of Natural Gas for Transportation Use (Source The 2014 Annual TRB Meeting Washington)
A typical Landfill gas production process, although the LFG can also be used for transportation.
Figure 48: Landfill gas production (Source pngc.com)
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Appendix B: Gas Transportation options
Land Transportation
Natural gas can be used as source of fuel to power natural good vehicles (NGV) using either LNG or CNG. Both
types of gas whether it is liquefied or compressed have their advantages and disadvantages which will be
discussed below. Natural gas can be used as substitute for conventional transport fuels (diesel and petrol).
When looking at Natural gas transportation there are 3 types of NGVs namely:
Dedicated NGV: These are vehicles designed and manufactured by the manufacturers (e.g. Mercedes
Benz, Volvo, Ford, Honda, General Motors and Toyota) or existing can be converted to only use natural
gas as vehicle fuel.
Bi-fuel NGV: These are petrol vehicles that have been converted from using petrol to using either petrol
or natural gas.
Dual-fuel NGV: These are diesel vehicles that have been converted from using diesel only, to using
either diesel or a combination of diesel and natural gas. Within diesel vehicles a small amount of diesel
is required with the natural gas to ensure the ignition of fuel.
Natural gas vehicles can either run on CNG or LNG depending on type of vehicle design or conversion.
The two main types of natural gas used to power transportation also require different types of refueling
infrastructure for NGV as briefly described below:
CNG stations comprising pressurised dispensers, compressors capable of delivering gas above 200 bar
and either a pipeline to the grid or delivery by mobile cascades. The higher the pressure delivered by
pipeline to the dispenser the cheaper it is to compress the CNG. Where a piped grid connection is not
available remotes stations have trailer delivered mobile cascades which are delivered from a mother
station to the daughter stations. This type of mother daughter scenario requires at least two trailers
operating in tandem.
LNG stations comprise leak tight dispensers and a cryogenic tank for storing LNG. Road tankers usually
have a capacity of 40-80 m3 (Typical LNG re-fuelling stations can handle around 50 vehicles per hour in
the US).
There is a global trend to move towards more NGVs, with it often sited that natural gas is the cleanest burning
alternative transportation fuel available today that can economically power light, medium, and heavy-duty
vehicle applications as well as many non-road applications, such as rail and marine vehicles. Whether in the form
of compressed natural gas (CNG) or liquefied natural gas (LNG), natural gas is a proven alternative fuel that
significantly improves local air quality and reduces greenhouse gases (GHG).
Natural gas vehicles generally emit 13–21 percent fewer GHG emissions than comparable gasoline and
diesel vehicles on a well-to-wheels basis.
Medium and heavy duty natural gas engines were the first engines to satisfy U.S. Environmental
Protection Agency’s (EPA) demanding 2010 emission standards for nitrogen oxides (NOx).
The light-duty Honda Civic Natural Gas held the American Council for An Energy-Efficient Economy’s
(ACEEE) title of “Greenest Vehicle” for eight consecutive years. Compared to its gasoline-burning
counterpart, the 2013 version of the Civic Natural Gas produces 80 percent fewer emissions of non-
methane hydrocarbons 50 % less NOx emissions and 67% less carbon monoxide than its gasoline
counterpart.
Increase in methane emissions are more than offset by substantial reduction in CO2 emissions.
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When evaluating fuel performance and greenhouse gas emissions for NGV it can be measured in two ways:
Tank to Wheel basis (TTW) often known as tailpipe measurement; or
Well to Wheel (WTW) which encompasses the entire Life-cycle (In most cases this stops on combustion
from the NGV).
The California Air Resources Board (CARB) has conducted extensive analysis on this issue. CARB concludes that
a CNG fuelled vehicle emits 20 to 29 percent fewer GHG emissions than a comparable gasoline or diesel fuelled
vehicle on a well-to-wheel basis. More recent studies indicate that these benefits may be somewhat reduced by
higher levels of fugitive methane emissions occurring in the upstream production and distribution of natural gas.
According to the latest analysis that factors in these higher emissions, NGVs still produce about 13–21 percent
fewer GHG emissions than comparable gasoline and diesel. For natural gas vehicles that run on biomethane,
the GHG emissions reduction approaches 90 percent.
LD Car LD Truck School Bus Heavy Duty Trucks (v. Diesel)
CNG v. Petrol CNG v. Diesel CNG LNG LNG Dual Fuel
GHG 13% 14% 13% 13% 13% 21%
NOx 16% 16% 16% 40% 40% 40%
PM10 (2007) 50% 12% 21% 22%
Table 29: Emissions Reductions (%) of new NGVs compared to conventional fuelled vehicles (Source CARB 2012)
This positive view is not held by all with a number of studies indicating that that there is cost benefit, but not
an environmental benefit.
Gas Use
Gas used to power NGVs primarily comes in the form of compressed natural gas (CNG) although in China and
the US there is a growing demand for long distance HDV being powered on LNG. For CNG the energy used to
compress the gas as well as end-use combustion is approximately 60.04 g CO2e per MJ. The calculation is made
up by combustion of 56.10 gCO2e/MJ (DEA 2014) and compression of 3.94 gCO2e/MJ (Argonne Laboratory
2013).
In terms of direct use in vehicles, the fuel economy is reduced when substituting natural gas for petrol or diesel
because of increased vehicle weight due to the storage of on-board CNG cylinders and because of reduced
engine efficiency. Burnham et al. (2011) estimates the fuel economy of petrol cars to be reduced by between 5
% to 10 % when fuelled by CNG. Transit buses are expected to have between a 10 % to 20 % reduction in fuel
economy when run on CNG compared to diesel (Burnham, et al., 2011). However, it is expected than
technological advances into the future may well improve the efficiency of CNG vehicles (Edwards, et al, 2011).
In the LCA study conducted by Burnham et al. (2011), it was concluded that the total GHG emissions emitted per
kilometre between CNG and diesel (buses) and petrol (cars) were not significantly different. The estimated GHG
emissions were approximately 220 g CO2e per kilometre for cars and 2 000 g CO2e per kilometre for buses for
both CNG and diesel (Figure 49). Since the Burnham report the EPA have issued lower fugitive methane emission
values that decreased by almost 40% in the production stage, or around 5% of the overall total for the mid and
upstream sector.
Figure 49 provides an indication that the grams of CO2 per km for buses and passenger cars are similar if the
entire Life cycle analysis is taken into account.
130 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 49: GHG emission for NGV and conventional fuelled vehicles (Source Burnham et al. (2011))
Fuel comparison of energy and grams per CO2 per km do vary upon source, however the below figure indicates
that natural gas powered vehicles will have a reduced emissions footprint than when using conventional
transportation fuels. In all studies the use of biogas as CNG or LNG to fuel NGV will have a significant effect on
reducing greenhouse gas emissions in areas where these vehicles are fuelled.
Figure 50: Fuel consumption, energy and CO2 (Source DENA and US EPA)
NGV Conclusion
The GHG and cost benefits for natural gas in the transportation sector is low. Potential savings exist, primarily
for medium and heavy-duty trucks, long distance fleet vehicles, buses and taxis. If natural biogas from landfill or
wastewater sludge production is mixed in a 20 / 80% ratio with natural gas then it will be a cleaner fuel than
conventional fuels.
The below table highlights the differences as well as the benefits and disadvantages of using CNG and LNG as a
transport fuel compared to conventional petrol/diesel.
In all cases it is assumed that the NGV travel large distances on a yearly basis, at least 50,000km per annum.
The life cycle cost analysis is based on an assumption that the 20-30% price differential between conventional
and natural gas power vehicles continues.
0
25
50
75
100
125
150
175
200
gCO2/Km (W to W) Petrol Equivalent=100
131 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Considerations LNG CNG Diesel /Petrol / HFO for
shipping
Fuel supply in South Africa - 2014
None at present Challenging only in Gauteng. Can have mobile cascades. eThekwini natural gas supply limited
Abundant supply, with few issues. Two major refineries in Durban.
Global fuel supply 250 years 250 years 50 years
Potential of fuel supply from local sources in the future.
High expectations from CBM, Shale gas and conventional offshore resources
High expectations from CBM, Shale gas and conventional offshore resources
Low expectations except for Gas Conversion into Synfuels via GTL plants
Bio-gas - landfill gas mixing with fuel
Expensive less likely Probable Probable
Bridging fuel for other technologies
Possible Possible n/a
Infrastructure None at present Lack of transmission and distribution pipelines in the Municipality.
Abundant
Small scale infrastructure
None at present Can be dispersed via mother and daughter stations.
Technology Requires refrigeration, regasification and storage facilities
Requires high compression ranging from 200 -275 bar.
Old proven technology
Fuel Price differential Usually around 20-30% less than Diesel or Petrol
Usually around 20-30% less than Diesel or Petrol
More expensive fuel option
Vehicle range on a tank of fuel
Preferred alternative fuel when maximum range is required (600Km)
Preferred for vehicles with lower mileage and back to base operations (Trucks 250Km, cars 400Km Honda Civic)
Largest range (trucks 1,500Km and cars around 700Km)
Vehicle Weight - Size Preferred for heavy weight vehicles
Preferred for light and medium vehicles
Use for all vehicles
Tank Space Preferred where tank space is limited
Maybe preferred if there is space for many tanks – 3 times tank space of LNG
3 times less tank space compared to CNG
Refuel Time Preferred where fuel time needs to be minimised
Preferred if there is plenty of time to refuel
Preferred where fuel time needs to be minimised
Large Refuelling stations (R2 million in US – lower than expected in RSA)
R25 million (R4 million in US)
R1 million – R5 million
Refuelling stations - availability
No infrastructure – require national infrastructure on major highways
Limited infrastructure in Gauteng – Preferred if next to gas pipeline – Can be based within regions
Readily available
Home Refuelling Not possible Could possibly have depot/home installation from wall mounted low pressure compressor - Expensive
Not possible- Only applicable to farms and large industrial users with own storage tanks.
132 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Considerations LNG CNG Diesel /Petrol / HFO for
shipping
Fleets Size Number of vehicles required to make refuelling sites economically viable
Number of vehicles required to make refuelling sites economically viable
N/A. Viable as infrastructure already exists.
Initial upfront costs of NGV vehicles (from manufactured or converted)
Highest upfront costs Lower than LNG, but higher than conventional fuels – New vehicle R40,000-R80,000 more – Conversions R20,000-R30,000 for passenger cars and taxis
Lower than gas
Distance travelled viability
Very high mileage Moderate high annual mileage
Viable for all modes of transport with low mileage
Payback period based on 100,000Km - Taxis
7-8 years 3 Years N/A
Passenger cars LCA cost comparison
Not economically viable Not economically viable Economically most viable
LDV/Taxis LCA cost comparison
Not viable Cheapest option More expensive than CNG
Buses / Municipal waste vehicles etc LCA cost comparison
Not Viable Cheaper than LNG and conventional fuels
More expensive than CNG
HDV LCA cost comparison
Economically viable for long distances
Economically viable for shorter distances
LCA higher
Rail cars LCA cost comparison
Not economically viable Not economically viable Economically most viable
Vehicle lifespan Not known
CNG increases vehicle lifespan as they operate using a cleaner fuel.
Known
Maintenance costs Not Known Lower, but might be higher
Manufacturers in South Africa. OEMS
Unlikely Manufactures looking at OEM production. 180 Worldwide.
Wide choice
Resale / residual value No market No market Mature market
Toxicity / Pollution Non-toxic with lower environmental risks on leakage/spills
Non-toxic with lower environmental risks on leakage/spills
Higher pollution risk on spills.
Groundwater Very low contamination Very low contamination High contamination levels possible
Safety Lighter than air so disperses – Special cryogenic equipment required
Lighter than air so disperses – Higher pressures involved
Issues well known
Average GHG Emissions based on LCA gCO2e/Km for light delivery vehicles (LDV = including South African Taxis
Similar to conventional fuels (CARB study 13% less)
142-168 Similar to diesel and petrol. – (CARB study 14% less)- (Sanedi study 25% less on tailpipe emissions)
145-149 similar to natural gas
133 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Considerations LNG CNG Diesel /Petrol / HFO for
shipping
LDV CO2 - EPA and other studies
11-25% Lower Higher emissions but improving
CO – LDV EPA and other studies
90-97% less than diesel
75% less than petrol
Higher emissions but improving
LDV NOx EPA and other studies
35-60% lower tailpipe emissions (CARB 16% less)
Higher emissions but improving
LDV Particle matter Extremely low (CARB 12% less)
Higher particle emissions but improving
Heavy duty vehicles (HDV) analysis Tail pipe analysis
HDV CO – Cenex HDV 2.223 higher than conventional fuels
Lower than conventional fuels
1.176 – Higher than NGV
HDV NOx - Cenex 0.539 - lower than conventional fuels
Lower than conventional fuels
3.799 - Higher than NGV (7 x higher than LNG trucks)
HDV Particle matter – Cenex
0.002 Lower than conventional fuels
0.069 (35 x higher than LNG trucks)
HDV Unburnt Hydrocarbons – Methane slip
0.127 – being addressed by OEMs (Higher)
Higher than conventional fuels
0.032 4 x Lower than natural gas
HDV Life cycle costs E’000
252-285 cheaper than diesel
Cheaper than diesel 330-344
Carbon tax Considered a “green energy solution” thus avoids carbon tax.
Considered a “green energy solution” thus avoids carbon tax.
Rate based on OEM vehicle emissions
Energy Efficiency Higher octane fuel than petrol so more compression and efficiency (Debateable)
Higher octane fuel than petrol so more compression and efficiency (Debateable)
Reduced by 5-10% for cars and 10-20% for buses (Debateable)
ESCO possibilities Only likely with large fleet sizes and high fuel cost differential.
Only likely with large fleet sizes and high fuel cost differential.
N/A
Conversion possibilities Only for HDV
Most internal combustion engines, diesel or petrol can convert to use CNG.
Primarily conversion of petrol vehicles in South Africa
N/A
New employment opportunities
Construction of facilities. Construction of facilities. Conversion of existing vehicle to run on CNG – expertise already in South Africa. More people dispensing fuel
N/A
Figure 51: Considerations required when making a decision to invest in NGV's (Source PwC)
134 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Sea Transportation
LNG Versus HFO
The consumption of HFO in the eThekwini municipal area is high due to the significant port activity in Durban.
SAPIA liquid fuel sales obtained from the DoE indicate sales of three liquid fuels for international marine
transportation namely, Marine Automotive Diesel (diesel in the LEAP analysis), Marine Diesel Oil (oil in LEAP
analysis), and Marine Fuel Oil (MFO in LEAP analysis). The fuel accounts for 26.7% of the energy use and 17.7%
of the energy emissions in the eThekwini Municipality, thus switching to alternative fuels such as LNG would
reduce CO2, NOx and SOx emissions. Internationally LNG ocean vessels are replacing HFO vessels for economic
and environmental reasons.
A significant driver to LNG is the MARPOL VI emission targets which require reduced SOx and NOx emissions
from exhaust fumes from ocean vessels. The emissions must be down to 0.1% m/m3 by January 2015 in ECA
areas and other seas by 1 January 2020. This means that vessels have four alternatives:
Convert to LNG (Long distances);
Convert to CNG (shorter distances and not common);
Burn costlier Marine Gas Oil (MGO); and
Install scrubbers to remove SOx from exhaust emissions (still need to dispose of waste sulphur).
LNG potential to meet strict international shipping emission targets mean that LNG at present is the only fuel
that can meet all the targets set for 2020 as noted in table 24 below: LNG can meet these tough reduction targets
and thus will grow in the maritime sector.
SOx (2015 ECA) NOx (2016 ECA) CO2 (Globally
2020) Life cycle costs $m
Emission reduction targets
-90% -80% -20%
HFO no scrubber 0 0 0 19
Conventional Fuel (HFO) + scrubber
-90% -0% +0.5 to 1% 31
Low sulphur Fuel (MGO)
-90% -0% -0% 26
LNG -100% -90% -20% 24 Table 30: Ocean vessels fuels meeting MARPOL VI emission standards (Source PwC 2013)
An Environmental Life Cycle Assessment of LNG and HFO as Marine Fuels by Lars Laugen at the Norwegian
University of Science and Technology Department of Marine Technology (NTNU–Tronheim) indicated that LNG
gas engines have the low emission of NOx, compared to diesel engines, however retrofitting is not an option.
There have been challenges on the methane slip, which again means that the resulting CO2 reduction is not
necessarily that effective. Another problem is the additional space required to store LNG as noted by Wärtsilä
report which states that LNG at 10 bar will require up to 4 times the space compared to HFO.
In the NTNU–Tronheim study LNG had a lower global warming potential than HFO. Total GHG emission of 127 g
CO2-eq/ton Km for LNG is narrowly better than HFO at 130.13 g CO2-eq/ton Km. Figure 52 shows that LNG as
fuels contributes to less CO2 equivalents than HFO in all phases of the supply chain except from the
transportation phase. In the transportation phase it becomes clear that the methane leakage creates a greater
carbon footprint for LNG than it does for HFO.
135 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 52: Total well-to-propeller global warming potential for LNG & HFO (Source NTNU–Tronheim 2013)
The overall results from the study showed that LNG is marginally better than HFO when it comes to GWP, far
better for acidification potential and relatively less energy consuming. It is therefore seen upon as a cleaner fuel
than HFO.
The bullet points below shows some of the main advantages (left) and disadvantages (right) for LNG as a shipping
fuel.
Advantages LNG Disadvantages LNG
Meets Tier III and ECA requirements • Cleaner and less pollution • Predicted to be cheaper than HFO • Spills will disappear when in contact with water • Low hazard • Low maintenance • Stored at atmospheric pressure • More gas reserves than oil
Lack of Infrastructure and associated costs • Methane slip • Skilled and trained crew to operate with LNG as fuel • Few places to bunker making route scheduling less optimized • Availability • Safety equipment • Extra space required on-board the vessel Loading times
Table 31: Advantages and Disadvantaged of LNG in shipping (Source NTNU – Tronheim 2013)
Advantages HFO Disadvantages HFO
Can install a scrubber to fulfil IMO requirements • Okay to use HFO outside ECA • Availability • Can be used with NG in dual fuel engines • Refineries will most likely continue to produce residual oils
Does not meet Tier III and ECA requirements • Oil spills • Higher maintenance costs than LNG • High GWP and acidification potential • Strong localized effects
Table 32: Advantages and Disadvantages of HFO in shipping (Source NTNU – Tronheim 2013)
The below diagram provides a summary of the primary energy consumption for LNG and HFO pathways in gram
fuel per ton Km along the LCA which highlights that HFO grams per ton Km is 50% more than LNG.
1.97.5
30.4
87.2
127.0
14.2
0.0
17.2
98.8
130.1
0
20
40
60
80
100
120
140
Extraction Liguefaction Transport Ferry Engine Total
gCO2e/ton Km
LNG
HFO
136 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 53: Option Development: HFO vs LNG Marine system design (Source NTNU- Tronheim 2013)
The PwC article “LNG as a fuel, the next best thing in 2013” assessed net payback costs (NPC) in the marine
sector and noted that HFO is cheaper than LNG shipping, but HFO with a scrubber and MGO fuelled vessels
required to meet new environmental regulations would be more expensive. LNG vessels have higher upfront
costs, but due to lower fuel costs the extra capital investment will be recovered in 4.2 years and 3.2 years when
compared to HFO with scrubbers and MGO vessels, thus making them attractive to the industry.
137 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Figure 54: NPC for investment and operational costs for marine shipping solutions (Source TT-Line, IMO, Danish Maritime Authority, Rolls Royce and PwC)
Figure 55: Payback period for LNG solutions through fuel cost savings (Source TT-Line, IMO, Danish Maritime Authority, Rolls Royce and PwC)
It would seem likely that South African ports will need to have LNG storage facilities which supply the future LNG
shipping fleets so that international regulations are met. CNG vessels are less likely as they are smaller than LNG
vessels and only viable for short distances. The most likely scenario could be gas importation from Mozambique
or Angola via such ships.
15.2
24.726.0
19.3
0.0
5.0
10.0
15.0
20.0
25.0
30.0
HFO fuelledships (w/oscrubber)
HFO fuelledships (w
scrubber)
MGO Fuelledship
LNG Fuelledship
NPC (M Eur)
4.2
3.2
0
1
2
3
4
5
Repayment time forLNG solution vs HFO
fuelled ships wscrubber
Repayment time forLNG solution vs MGO
fuelled ships
Payback (years)
138 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Appendix C: Natural gas units of measure
Natural Gas units of conversion factors
Natural gas units of measure are frequently misunderstood as the amount of energy, volumes and weight
measurements are different depending on the technology and where in the world it is being discussed. The
tables below indicate common conversion factors.
Symbol Number Standard form
Ab
bre
viat
ion
Kilo (Thousand) K 1,000 10 3
Mega (Million) M 1,000,000 10 6
Giga (Billion) G 1,000,000,000 10 9
Tera (Trillion) T 1,000,000,000,000 10 12
Peta (Quadrillion) P 1,000,000,000,000,000 10 15
Table 33: Metric unit conversion table
GJ kWh Btu (therm) toe kcal
Ener
gy
Gigajoule (GJ) 1 277.78 9.47817 0.02388 238,903
Kilowatt-hour (kWh)
0.0036 1 0.03412 0.00009 860.05
British Thermal Unit (Btu)
0.10551 29.307 1 0.00252 25,206
Tonne oil equivalent (toe)
41.868 11,630 39.683 1 10,002,389
Kilocalorie (kcal) 0.000004186 0.0011627 0.000039674 0.0000001 1
Table 34: Natural gas energy conversion table
J GJ Btu kWh GWh
Ener
gy
Joule (J) 1 10-9 9.47-4 2.8-7 2.8-13
Gigajoule (GJ) 109 1 1.0566 278 2.8-4
British Thermal Unit (Btu) 1055.9 1.066 1 2.9334 2.933-4
kWh 365 36-4 3409.5 1 10-6
GWh 3611 362 34.18 106 1
Table 35: Natural gas energy conversion table 2
L m3 cu ft Imp. gallon US gallon Bbl (US)
Vo
lum
e
Litres, (L) 1 0.001 0.03531 0.21997 0.26417 0.00629
Cubic metres (m3) 1000 1 35.315 219.97 264.17 6.2898
Cubic feet, ft 3) 28.317 0.02832 1 6.2288 7.48052 0.17811
Imperial gallon 4.5461 0.00455 0.16054 1 1.20095 0.02859
US gallon 3.7854 0.003785 0.13368 0.83267 1 0.02381
Barrel (US) bbl 158.99 0.15899 5.6146 34.972 42 1
139 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Table 36: Natural gas volume conversion table
Bcm NG
Bcf NG Mtoe MtLNG TBtu Mboe
Vo
lum
e
Billion cubic metres NG
1 35.3 0.9 0.74 35.7 6.60
Billion cubic feet NG
0.028 1 0.025 0.021 1.01 0.19
Million tonnes of oil equivalent
1.11 39.2 1 0.82 39.7 7.33
Million tonnes of LNG
1.36 48.0 1.22 1 48.6 8.97
Trillion British Thermal units
0.028 0.99 0.025 0.021 1 0.18
Million barrels of oil equivalent
0.15 5.35 0.14 0.11 5.41 1
Table 37: Natural gas volume conversion table
Kg Tonne (t) ton (UK) ton (US) lb
Wei
ght/
mas
s
Kilogram, kg 1 0.001 0.00098 0.00110 2.20462
tonne, t (metric tonne) 1000 1 0.98421 1.10231 2204.6237
ton (UK, long ton) 1016.0464 1.01605 1 1.12000 2240
ton (US, short ton) 907.18 0.90718 0.89286 1 2000
Pound, lb 0.45359 0.00045359 0.0004464 0.00050 1
Table 38: Natural gas weight/mass conversion table
Calorific Value = the amount of energy released during combustion expressed as energy divided by the volume
of that specific substance, MJ/M3 or MJ/l.
A typical Natural gas composition varies depending on the source of the conventional gas as noted in the table
below:
Typical Natural gas composition, Mole %
Non-associated gas Associated gas
Dry Gas Gas condensate
Carbon dioxide 0.5 2.5 1.0
Nitrogen 1.1 1.0 1.0
Methane 94.4 86.5 68.0
Ethane 3.1 5.5 15.0
Propane 0.5 3.0 9.0
Iso Butane 0.1 0.3 2.0
Normal-butane 0.1 0.7 3.0
Pentane + 0.2 0.5 1.0
Total 100.0 100.0 100.0
Table 39: Typical natural gas composition, Mole %
140 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Appendix D: NERSA maps of natural gas distribution pipelines in
KwaZulu-Natal
The below diagram indicates the limited natural gas distribution pipeline network in the eThekwini municipality
and the six gas licence distribution areas regulated by NERSA.
Figure 56: eThekwini municipality pipeline network (Sources NERSA adapted by PwC}
The six below maps show a detailed picture of the licenced distribution pipelines in the eThekwini Municipality
as shown by the red pipelines. The higher pressure transmission pipeline is noted in blue.
EThekwini Municipality pipeline networks
Canelands / Verulam
Phoenixi
Jacobs / Moeni / Clarewood
Merebank
Umbogintwini
Prospecton
141 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Images 6: Canelands / Verulam: gas distribution licence area (Source: NERSA 2014)
Images 7: Phoenix: gas distribution licence area (Source NERSA 2014)
142 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Images 8: Jacobs / Mobeni / Clairwood: gas distribution licence area (Source NERSA 2014)
Images 9: Merebank: gas distribution licence area (Source Nersa)
143 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Images 10: Prospecton: gas distribution licence area (Source NERSA 2014)
Images 11: Umbogintwini: gas distribution licence area (Source NERSA 2014)
144 | P a g e N a t u r a l G a s P o s i t i o n P a p e r
Appendix E: References
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group.com/480/about-us/lng/global-lng-market-overview-2013-14-/
Berkeley Lab Earth Science Division What is Carbon Capture and Storage (CCS)? 2013 http://esd.lbl.gov/research/programs/gcs/outreach.html Berkeley Lab Earth Science Division)
BP, 2014, BP Statistical review of world energy 2014, available at http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy.html Bradbury, J. et al., 2013. Clearing the air: reducing upstream greenhouse gas emissions from US natural gas systems. Working Paper., available at: http://www.wri.org/publication/ clearing-the-air: World Resources Institute. Brandt, A.R., et al., 2014. Methane Leaks from North American Natural Gas Systems. Science. available at: http://www.sciencemag.org/content/343/6172/733.summary Branosky, E., Stevens, A. & Forbes, S., 2012. Defining the shale gas life cycle: a framework for identifying and mitigating environmental impacts. A Working Paper., Washington DC: World Resources Institute. Broderick, J. & Anderson, K., 2012. Has Shale Gas Reduced CO2 emissions? available at: http://www.tyndall.ac.uk/sites/default/files/broderick_and_anderson_2012_impact_of_shale_gas_on_us_energy_and_emissions.pdf: Tyndall Centre for Climate Change Research. Burnham, A. et al., 2011. Life cycle greenhouse gas emissions of shale gas, natural gas, coal, and petroleum. Environmental Science and Technology, available at: http://pubs.acs.org/doi/pdfplus/10.1021/es201942m, doi: 10.1021/es201942m. CGG, 2014, Gas hydrates, available at http://www.cgg.com/default.aspx?cid=3527 Centre for climate and energy solutions, 2013, Leveraging Natural Gas to Reduce Greenhouse Gas Emissions, available at http://www.c2es.org/publications/leveraging-natural-gas-reduce-greenhouse-gas-emissions DECC, 2013. Potential Greenhouse Gas Emissions Associated with Shale Gas Extraction and Use, London: UK Department of Energy & Climate Change. DECC, 2012 Guidelines to Defra / DECC’s GHG Conversion Factors for Company Reporting: Methodology Paper for Emission Factors, available at https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/69568/pb13792-emission-factor-methodology-paper-120706.pdf Department of Environmental Affairs, 2014. Research Project - Greenhouse gas emissions associated with shale gas, available at
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