Natural Gas Position Paper eThekwini Municipality 2015

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

http://en.wikipedia.org/wiki/Natural_gas

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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


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.


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.


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:


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).


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)


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


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


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)


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

http://www.energy.gov.za/


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


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)


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.


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)


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.


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

http://www.durban.gov.za/City_Services/energyoffice/Pages/default.aspx


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.


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.


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.


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)


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


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.


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


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:


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.


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)


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.


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.


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)


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


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.


A view of the LNG Value Chain

Figure 12: Liquefied natural gas value chain (Source PwC)


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.


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


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


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


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)


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.


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%

http://www.forbes.com/companies/cobalt-international-energy/



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.



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.


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)


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


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


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.


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


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


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


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


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


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.


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


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.

http://www.2b1stconsulting.com/ioc/

http://www.2b1stconsulting.com/natural-gas/


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


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.

http://www.engineeringnews.co.za/topic/ibhubesi-company

http://www.engineeringnews.co.za/topic/ibhubesi-company

http://www.engineeringnews.co.za/topic/cape-town

http://www.engineeringnews.co.za/topic/gas-company

http://www.engineeringnews.co.za/topic/eskom

http://www.engineeringnews.co.za/topic/gas-company

http://www.engineeringnews.co.za/topic/drilling

http://www.engineeringnews.co.za/topic/project

http://www.engineeringnews.co.za/topic/gtl-refinery


http://www.engineeringnews.co.za/topic/liquefied-natural-gas

http://www.engineeringnews.co.za/topic/lng

http://www.engineeringnews.co.za/topic/south-africa

http://www.engineeringnews.co.za/topic/supply-gas


http://www.engineeringnews.co.za/topic/open-cycle-gas-turbine-peaking-power-plant

http://www.engineeringnews.co.za/topic/open-cycle-gas-turbine-peaking-power-plant


http://www.engineeringnews.co.za/topic/mossel-bay

http://www.engineeringnews.co.za/topic/shell

http://www.engineeringnews.co.za/topic/south-africa-region

http://www.engineeringnews.co.za/topic/falcon-oil-and-gas

http://www.engineeringnews.co.za/topic/energy

http://www.engineeringnews.co.za/topic/oil-and-gas

http://www.engineeringnews.co.za/topic/resources


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.


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


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


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/


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


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


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.


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


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

http://www.engineeringnews.co.za/topic/liquefied-natural-gas



http://www.engineeringnews.co.za/topic/turbines-company

http://www.engineeringnews.co.za/topic/western-cape

http://www.engineeringnews.co.za/topic/shell

http://www.engineeringnews.co.za/topic/saldanha-bay-natural-feature

http://www.engineeringnews.co.za/topic/west-coast-natural-feature

http://www.engineeringnews.co.za/topic/eastern-cape

http://www.engineeringnews.co.za/topic/natal



http://www.engineeringnews.co.za/topic/drilling

http://www.engineeringnews.co.za/topic/project



http://www.engineeringnews.co.za/topic/mossel-bay


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).


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.


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:


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.


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


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)


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.


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.


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


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.


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.


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


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.


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.


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;


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

http://en.wikipedia.org/wiki/Salt_dome

http://en.wikipedia.org/w/index.php?title=Salt_cavern&action=edit&redlink=1


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.

http://en.wikipedia.org/wiki/Hydrocarbon


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.


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.


Figure 44: Selected policies and plans affecting the gas sector (Source PwC)


8.2 Acts and Regulations

Figure 45: Selected Acts and Regulations affecting the South Africa Gas Industry (Source PwC)


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.



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.



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.



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



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.



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



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.


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



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.


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.


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



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.


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.


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)


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.


Type

sector

Active


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


Type

sector

Active


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


Type

sector

Active


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:


Type

sector

Active


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.


Type

sector

Active


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


Type

sector

Active


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


Type

sector

Active


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

http://www.sapga.co.za/

http://www.sagas.co.za/

http://www.sacga.za.org/


Type

sector

Active


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


Type

sector

Active


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)


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.


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


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.


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


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.


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.


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)


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 socioeconomic 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


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


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


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


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


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


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)


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.


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


Ethekwini municipality influence

High level utilisation summary and demand requirements

Municipal fleet create critical mass for CNG NGV network development (Medium)


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)


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)


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, socioeconomic 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;


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.


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.


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


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)


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


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)


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.


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.


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


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.



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



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)


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.


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


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.


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)


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


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 %


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


Images 6: Canelands / Verulam: gas distribution licence area (Source: NERSA 2014)

Images 7: Phoenix: gas distribution licence area (Source NERSA 2014)


Images 8: Jacobs / Mobeni / Clairwood: gas distribution licence area (Source NERSA 2014)

Images 9: Merebank: gas distribution licence area (Source Nersa)


Images 10: Prospecton: gas distribution licence area (Source NERSA 2014)

Images 11: Umbogintwini: gas distribution licence area (Source NERSA 2014)


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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)

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