Appraisal of Implementation of Fossil Fuel and … REPORT Appraisal of Implementation of Fossil Fuel...

TECHNICAL REPORT

Appraisal of Implementation of

Fossil Fuel and Renewable Energy

Hybrid Technologies in South Africa

PROCUREMENT REFERENCE NUMBER: 385

November 2017

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Executive Summary In the context of this study, hybridisation is the coupling of a renewable energy technology with an existing fossil fuel technology in order to deliver the same energy service. Hybridised energy systems are designed to replace, augment or boost conventional fossil fuel technologies with renewable energy technologies. They can achieve a reduction in the carbon intensity of fossil fuel value chains while preventing stranded assets during the transition to a lower carbon economy. This report appraises the feasibility of hybridisation of fossil fuel and renewable energy technologies in South Africa in 2017. The objectives of this study are to review the South Africa’s fossil fuel value chains and identify hybridisation opportunities with renewable energy technologies. The methodology includes an intensive literature review and analysis in order to identify such opportunities. The identified hybridisation opportunities are further investigated through a multi criteria decision analysis and techno economic review to determine which fossil fuel and renewable energy hybridisation options are most viable within South Africa. Various local and international case studies are used to provide learnings, challenges and key issues related to implementation. The study focuses on evaluation of hybridisation potential in South Africa on a facility level and does not assess hybridisation of the national grid. The opportunities and policies related to the hybridisation of electricity sources on the national grid are not areas which business has control on, and thus does not form part of this facility level hybridisation study. The fossil fuel value chains assessed include those within the energy transformation sector (electricity plants, oil refineries and coal/gas liquefaction plants) and those within the energy demand sectors (industrial, mining, transport, agricultural, commerce and public services, and residential). These value chains deliver thermal, electrical, mechanical and mobility energy services. Where these energy services can be provided by renewable energy there is potential for hybridisation of the specific value chain. Renewable energy technologies using solar (thermal and PV), small scale wind, small scale hydro, biomass (crop and waste streams) and geothermal renewable energy resources are assessed for use in hybridised systems to provide energy services. Due to current regulatory constraints related to municipal waste, this study did not investigate the possibility of utilising waste from municipal landfills as a feedstock, even though it is a resource available throughout the country. The use of geothermal energy in the hybridisation technologies is deemed not applicable to South Africa, due to the country’s geology and the low demand, considering that South Africa has a relatively mild annual temperature range with few heating and cooling degree days. Plausible hybridisation options identified are prioritised to determine the most promising solution to deliver a required energy service within each energy value chain. Prioritisation of the hybridisation options is carried out on a facility and country level. A summary of the conclusions drawn for the potential to hybridise each fossil fuel energy service with renewable energy technologies is provided below.

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Thermal energy services

Many thermal energy services are currently provided via electrical energy which is then converted into thermal energy. However, the direct use of thermal energy to provide a thermal energy service is the most efficient means and should be utilised to prevent unnecessary energy losses. Over the last decade the average standard Eskom electricity tariff price has increased by around 130%, taking inflation into account, (Eskom, 2017). It is expected that this trend will continue into the future. Thus, hybridising the provision of electrical thermal energy services such as water heating, with the use of direct solar heating, will become increasingly viable in the near future. This is in addition to the steadily decreasing cost of solar technologies. South Africa has suitable solar resources throughout the country to drive solar technology integration. This research found that for the provision of low temperature heating requirements (40°C - 100°C) the use of direct solar heating is a promising solution. Fossil fuel value chains that provide heating at such temperatures include water heating applications, pre-heating of boiler feed water for steam generation systems, heating and cooling processes, such as a building’s heating, ventilation, and air conditioning system, as well as drying processes. These systems often operate using fossil fuels such as coal, gas or fossil fuel based grid electricity. Hybridising with direct solar thermal energy will see a reduction in a portion of the energy provided by the existing fossil fuel value chain in the national energy system. Through the techno economic review, it was found that the installation of solar water pre-heating systems for boiler feed water is technically and financially feasible. The energy requirement to pre-heat the water from 20°C to 65°C was calculated using the specific heat of water. It was found that the pre-heating of water can save about 2% of the baseline energy consumption of a coal boiler. A company can expect to recover the capital investment in 5 years. If the company implementing such a project is an entity liable to pay carbon tax or if the company can claim this project as a carbon credit project this payback period can be reduced by about a year. It has been found that bioenergy is a promising renewable energy resource, where it is sustainably available, for the provision of thermal energy services. Bioenergy resources can supply energy continuously, while solar can provide energy for only about 30% of the time. As such where bioenergy is available for use, it may be a more suitable solution for thermal applications that require high power output at a constant rate. Bioenergy can be used to augment a portion of the thermal energy provided from fossil fuel systems through co-firing, for example furnaces, kilns, steam systems and water heating applications. Bioenergy can be used to achieve both high (>100°C) and low heating requirements. However, it is important to note that bioenergy resources are not available throughout South Africa and have very specific conditions that are required for financial viability. The payback period can vary from less than a year to no payback based on the cost of the bioenergy and the distance travelled, as well as the technology cost. In some cases a company may have a spare boiler onsite which can be used, thus requiring no additional capital cost. The conditions for viability include

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availability of the bioenergy resource on site or within a 20 km radius, and available at low cost, in order to compete with cheap fossil fuel resources. Bioenergy can be in the form of crop based biomass, as well as bioenergy from waste streams. South African case studies show a predominance for bioenergy from waste streams, which were generated on site. These waste bioenergy resources come at no extra cost and thus can compete with fossil fuels. However, where biomass is purchased (at costs which can be double that of the fossil fuel resource per unit of energy), the location applicability for an economically viable project is evident. Applicable sites for implementing hybridisation where biomass is purchased must be at least 1,000 km away from coal mines where the baseline fuel originates, as the transport distance for coal increases the baseline fuel price. Where crop based bioenergy is used, sufficient water for irrigation of the crops are required. In addition, it is required that the bioenergy is sustainably sourced to prevent degradation of ecosystems and prevent competition with other forms of land use. The provision of high temperature thermal energy services (>100°C) from solar resources, such as a concentrated solar thermal plant to augment steam generation in a coal fired boiler is currently not viable on an industrial scale. A price on carbon is necessary to create an incentive for investing in hybridisation of this type, as a commercially viable project. This type of hybridisation is more applicable to large scale steam generation systems such as utility-scale coal fired power stations, where a payback of around 8 years can be expected. The applicability of concentrated solar technology is limited to very specific areas (such as the vicinity around coal fired power stations), and where there is sufficient land available for implementation. Developing such a concentrated solar project is currently too risky for private commercial or industrial developers. There are however examples of smaller scale concentrated solar plants in South Africa which augment steam production and grid electricity for thermal heat applications at an industrial scale, (the project owners are not willing to share commercially sensitive information). In the few examples seen, the human technical capacity hasn’t been adequate to maintain these small scale concentrated solar systems. This adds to the uncertainty surrounding timeframes for implementation, which leads to financial risks. Electrical energy services

Electrical systems are the easiest to hybridise, with renewable electricity, as they typically do not require modifications to electrical equipment used to provide services. Currently, many of the energy services in the country are driven by electrical power, due to the historically low cost of electricity.

Due to the country’s good solar resources, and the solar photovoltaic (PV) technology cost reduction, solar PV is the most promising technology for hybridising electricity generation. The modularity available with this type of technology is also scalable. Solar PV electricity is suitable for many electrical requirements and it can be applied within any sector. The levelised cost of electricity from solar PV is competitive with municipal tariffs in South Africa. However, a grid connection is required to compensate for variable electricity supply, when storage is either not available or is

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costly. Solar PV systems for electricity provision can replace about 20% of the electricity requirements of a commercial or industrial facility from the national grid. The payback periods range between 4 to 6 years depending on the applicable grid-electricity fee structure and the demand profile. For a company with the possibility of trading carbon credits, the payback period can be reduced by about 4 months. Despite a positive outcome from the financial assessment, the roll-out of solar electricity projects has been slow. This is perhaps because of the length of the payback periods, or the barrier of the initial capital outlay. The initial capital outlay of PV technologies presents a barrier for implementation at a large scale, as many companies are attracted to projects that can show benefits in the same financial year. In addition, the regulations on small scale embedded generation have been under development up to now, and have not provided certainty to project implementers. As such, various case studies are being seen in South Africa, typically in the retail and commercial space, where power purchase agreements are signed with a third-party energy service provider who assume responsibility for the capital outlay and share risks. Regulations for small scale embedded generation for facilities smaller than 1MW were published in November 2017, and should now provide clarity for project developers going forward. Solar PV costs are on a downward trajectory as is evident from the more than 80% reduction in actual average tariffs for solar PV from the first to the last bid window in the Renewable Energy Independent Power Producer Procurement Programme. This is in addition to the historic average electricity tariff which is on a continued upward trend. As such, the feasibility of solar PV projects will continue to increase with lower investments required in the near future to deliver the same benefits. Bioenergy hybrid based electricity facilities may also be a feasible option under the right conditions. Bioenergy based electricity production is suitable for applications that require high power output at a constant supply such as electric steam systems, furnaces and reactors. There are however very specific conditions which would make this feasible, such as onsite bioenergy availability. The applicability of this type of hybridisation is therefore site specific and only appropriate where there is an available and sustainable biomass feedstock at a low cost. Small-scale wind energy and small-scale hydropower are suitable options to consider for hybridisation in remote locations, where there is either no connection to the national grid, or the extension and upgrading of the grid is costly. These technologies are less promising but viable in areas where resources are abundant, such as where there is a good wind source or a perennial stream for hydropower. These applications are therefore site specific and not applicable throughout South Africa, however there are good small-scale wind and hydropower technologies available. Limited applicable locations of such renewable energy resources and the high capital costs for these technologies prevent proliferation. Small scale wind systems have a payback of between 5 and 10 years. Faster financial returns are achieved by systems with larger capacities, however large-scale systems have not been included in this study as they are not appropriate to facility scale hybridisation in industry. There are multiple

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factors that affect the viability of such systems, including competing electricity tariffs, terrain and surrounding conditions and demand profiles. Wind options become more attractive with the existence of incentives such as carbon credits, and when combined with solar or hydroelectric systems as the variability in the provision of electricity is reduced. The viability of small hydropower is dependent on the location, access to permanent source of running water and municipal electricity tariffs. The range of municipal tariffs and the costs for micro hydropower vary significantly making implementation sensitive to location. As such payback periods for such projects can range from immediate payback up to 7 years and in some cases there is no payback. Suitable locations for micro hydropower in the country are scarce. Concentrated solar power (CSP) for electricity generation (without wheeling through the grid) is limited to companies who are prepared to make large upfront capital investments, who have large electricity requirements, are located in an area with good solar irradiation and that have available space. In comparison to current grid electricity prices, CSP electricity generation does not show financial benefits on a company level. However, a company may have different motivations for off-grid generation such as reliability of the service or environmental commitments. Mechanical energy services

Mechanical power can be used to deliver a direct force to provide useful work. Mechanical energy is used for many applications such as sawing, milling, crushing, grinding, pumping, fanning, sailing, drilling and compressing. Hydropower and wind have been used as direct kinetic energy to perform tasks such as milling of grains and pumping water for thousands of years. The competitiveness of small scale wind technologies depends on the service being provided, the location of the service and the quality of the wind resource. The most common application is the use of wind pumps for pumping water from boreholes in rural locations. Hybridised water pumping using wind to supplement electrical water pumping provides sufficient returns to be economically viable at commercially low discount rates. This type of hybridisation is suitable for facilities with existing limitations to grid electricity access. Where sustainable bioenergy resources are available and at low to no cost, steam generation from bioenergy is the most promising mechanical energy hybridisation option for motor driven systems with steam turbines. Small scale hydro systems also present promising mechanical hybridisation opportunities, where there is access to a perennial flowing stream. Steam generation from concentrated solar power is considered but is the least promising. Mobility energy services

The blending of biofuels for vehicles, ships, aviation and rail pose good opportunities to reduce transport related emissions, where biofuel resources are available. Blended fuels are limited by factors such as vehicle engine specifications, commercial supply of biofuels, transportation challenges and mandatory blending limits. A strong policy framework is however required to ensure food security and biodiversity are not compromised by the development of a sustainable biofuels market.

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Biofuel blending in the transport sector was not included in the techno-economic review due to the site-specific limiting factors which include constraints on water for biofuel crops, concerns around food security and the logistical constraints for national roll out and distribution without a supporting policy and framework in place in the country. Solar energy can support electrical auxiliary services in vehicles and thus reduce the amount of petroleum required to operate. Such electrical auxiliary services include air conditioning in trucks, cooling in refrigerated transport or electricity driven services for ships. In addition, solar PV can augment the electricity supply for electric rail services. Solar electricity is however limited by the area available on the transport vehicle exposed to solar irradiation. Overall, the augmentation of industrial application fossil fuel value chains with renewable energy technologies is an emerging trend seen internationally. The market for hybridising electricity services is much larger than the market for hybridising thermal energy services (energy consumption in industry, commerce and residential in South Africa is dominated by electricity). There is potential to develop solar thermal markets, however non-technical barriers constrain growth. Including lack of incentives and supporting policy. Globally, process heat accounts for around two thirds of final energy consumption in the industrial sector, presenting high levels of hybrid opportunities. Heat demand for South Africa’s industry sector can be estimated from the country’s energy balance to be approximately 55% of the final energy consumption. Around 52% of the heat demand globally is in the low- and medium-temperature range and thus suitable for solar or biomass thermal technologies. In order to see growth in the uptake of hybridisation projects in the South African market, policy and regulations are required to ensure an enabling environment to incentivise and support further roll out. Policy plays an important role in defining intentions for the uptake and subsequent implementation of renewable energy technologies in energy systems. This is as a result of policy driving new market opportunities, providing certainty in these investment markets, and incorporating the external benefits of renewable energy technologies into cost-benefit calculations, this is illustrated below for renewable energy markets.

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Creating an enabling environment for technology adoption must include mechanisms for both stimulation and regulation. These mechanisms should be varied to include both incentives as well as regulations for compliance to manage the uptake of renewable energy and hybridised energy systems. Currently there are no incentives that will drive the uptake of hybridised fossil fuel and renewable energy technologies in the country. It is thus recommended that government put in place an incentive scheme for hybridisation projects similar to section 12L and section 12J of the income tax act. It is suggested that government increase the capacity of the regulations on Small Scale Embedded Generation, which will provide further opportunity and help to drive the implementation of small scale hybrid systems. The implementation of pending legislation, such as the South African carbon tax and carbon offset scheme will be a driver towards the implementation of facility level hybridisation projects because these put a price on the externalities of fossil fuel use. Various key lessons and challenges are drawn from the hybrid case studies analysed. As a summary of these case studies, key reasons for implementation of hybrid projects are related to security of energy supply, positive publicity, sourcing of lower carbon alternatives, cost savings and the transformation of a waste stream into a resource. Challenges limiting the uptake of hybrid projects in the country relate to the high upfront investment cost required, lack of funding opportunities, low prices of fossil fuels, complexities with combining two or more technologies, lack of local technology support and regulatory barriers. However, the continued downward trend of capital costs of renewable energy technologies, along with the increasing local electricity prices may drive growth in the uptake of alternative energy solutions in the near future. It is recommended that a broader hybridisation implementation agenda be set through consultation with stakeholders, defining target themes and identifying sources of funding under the green economy classification. This programme can include the consideration of renewable energy hybridisation for individual and specific fossil fuel value chains in greater detail. Pilot

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projects, can form part of this programme and should be carried out in order to generate more detailed and accurate data for evaluating the business case of specific hybridisation technology applications. Further investigations within this programme should consider the use of energy storage in combination with a hybridised solution. The inclusion of energy storage solutions could further support the viability of hybridisation. In addition, research should be carried out to assess hybridisation potential through the use of a portfolio of energy technologies. This would include a mix of various renewable energy technologies hybridised to a fossil fuel technology, to improve flexibility and reduce risks related to a single supply. Overall it is concluded that hybridisation allows for technology integration rather than technology exclusion in order to contribute to a sustainable transition away from a fossil-fuel based energy sector. Hybridisation acts as a suitable arrangement to efficiently transition to a lower carbon economy while mitigating risks related to climate change. Hybridisation of fossil fuel value chains with renewable energies can reduce the risk of stranded assets, once the cost of the renewable energy competes with the fossil fuel technologies. As a result, hybridisation could play a critical role in increasing the uptake of renewable energy in existing energy systems in South Africa, and assist in the drive towards a lower carbon economy.

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Table of Contents 1 Evaluating existing and potential future fossil fuel value chains in South Africa and their potential for hybridisation with renewable energy ................................................................................. 1

1.1 Introduction ................................................................................................................................ 1

1.2 South Africa’s energy resources ............................................................................................... 4

1.2.1 Coal resources .................................................................................................................... 6

1.2.2 Petroleum resources .......................................................................................................... 6

1.2.3 Solar resources .................................................................................................................... 7

1.2.4 Wind resources ................................................................................................................... 9

1.2.5 Hydro resources ............................................................................................................... 10

1.2.6 Biomass and waste resources ......................................................................................... 11

1.2.7 Geothermal resources ..................................................................................................... 13

1.2.8 Nuclear resources ............................................................................................................. 15

1.3 Fossil fuel value chains in South Africa and the potential for hybridisation ................... 16

1.4 Fossil fuel energy transformation technologies ................................................................... 20

1.4.1 Electricity plants ............................................................................................................... 21

1.4.2 Oil Refineries .................................................................................................................... 28

1.4.3 Liquefaction plants .......................................................................................................... 30

1.5 Fossil fuel energy demand sectors and technologies .......................................................... 34

1.5.1 Industrial sector ................................................................................................................ 35

1.5.2 Mining sector .................................................................................................................... 44

1.5.3 Transport sector ............................................................................................................... 47

1.5.4 Agriculture sector ............................................................................................................. 51

1.5.5 Commerce and public services sector ........................................................................... 54

1.5.6 Residential sector ............................................................................................................. 58

1.6 Energy storage .......................................................................................................................... 61

1.6.1 Thermal energy storage (heat) ........................................................................................ 63

1.6.2 Thermal energy storage (cooling) .................................................................................. 64

1.6.3 Pumped storage ................................................................................................................ 64

1.6.4 Fuel cells ............................................................................................................................ 64

1.6.5 Hydrocarbon fuels as energy storage ............................................................................ 65

1.6.6 Financial viability of energy storage technologies ....................................................... 65

1.7 Technology options for hybridisation ................................................................................... 67

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1.8 Non-energy use of fossil fuel commodities .......................................................................... 68

2 Technology options for hybridisation in the South African context ........................................ 70

2.1 Introduction .............................................................................................................................. 70

2.2 Energy services ......................................................................................................................... 71

2.2.1 Electrical energy services ................................................................................................ 72

2.2.2 Heating based energy services ........................................................................................ 73

2.2.3 Kinetic energy services (mechanical power) ................................................................ 79

2.3 Renewable energy technology assessment ............................................................................ 80

2.3.1 Solar ................................................................................................................................... 81

2.3.2 Biomass ........................................................................................................................... 102

2.3.3 Wind ................................................................................................................................. 117

2.3.4 Geothermal ..................................................................................................................... 121

2.3.5 Small and micro scale hydro ......................................................................................... 128

2.4 Hybridisation potential in South Africa .............................................................................. 131

2.5 Summary of cost analyses ..................................................................................................... 135

3 Prioritising hybridisation opportunities in South Africa ........................................................... 139

3.1 Introduction ............................................................................................................................ 139

3.2 Feasibility assessment of hybridisation options in South Africa ..................................... 139

3.2.1 Methodology for selection and prioritisation of hybrid opportunities .................. 139

3.3 Hybridisation of thermal energy services............................................................................ 144

3.3.1 Facility level thermal hybridisation .............................................................................. 144

3.3.2 Country level thermal hybridisation ............................................................................ 147

3.4 Hybridisation of electrical energy services .......................................................................... 150

3.4.1 Facility level electrical hybridisation ............................................................................ 150

3.4.2 Country level electrical hybridisation .......................................................................... 152

3.5 Hybridisation of mechanical energy services ..................................................................... 154

3.5.1 Facility level mechanical hybridisation ........................................................................ 154

3.5.2 Country level mechanical hybridisation ...................................................................... 156

3.6 Hybridisation of mobility based energy services ............................................................... 158

3.6.1 Facility level hybridisation of mobility energy services ............................................ 158

3.6.2 Country level hybridisation of mobility energy services........................................... 160

3.7 The policy context of hybridisation ..................................................................................... 162

3.7.1 Global hybridisation policy context ............................................................................ 162

3.7.2 Regional hybridisation policy context ......................................................................... 164

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3.7.3 South African policy context: links to hybridisation ................................................ 166

3.7.4 Concluding notes on the South African policy context in relation to hybridisation 171

3.7.5 Policy barriers to renewable energy project development ....................................... 172

3.8 The role of hybridisation in driving and supporting policy development ..................... 174

3.9 Hybridisation trends globally ................................................................................................ 177

3.9.1 Solar energy ..................................................................................................................... 178

3.9.2 Bioenergy......................................................................................................................... 185

3.9.3 Wind energy .................................................................................................................... 190

3.9.4 Small and micro scale hydro energy ............................................................................ 191

3.9.5 Lessons learnt from unsuccessful hybridisation projects ......................................... 192

3.10 Summary of hybridisation prioritisation ............................................................................. 205

4 Techno economic review .............................................................................................................. 207

4.1 Introduction ............................................................................................................................ 207

4.2 Methodology for the techno economic review .................................................................. 207

4.2.1 General assumptions ..................................................................................................... 208

4.3 Techno economic review ...................................................................................................... 210

4.3.1 Solar techno economic review ..................................................................................... 211

4.3.2 Wind techno economic review .................................................................................... 221

4.3.3 Biomass techno economic review ............................................................................... 226

4.3.4 Hydro power techno economic review ...................................................................... 244

4.3.5 Overall conclusions from techno economic review ................................................. 247

4.4 Case studies ............................................................................................................................. 249

4.4.1 Solar PV on retail facilities in Gauteng ....................................................................... 250

4.4.2 Solar PV on Clicks head office .................................................................................... 251

4.4.3 City Power’s grid connected small scale solar PV programme ............................... 252

4.4.4 SOLTRAIN solar thermal demonstration systems .................................................. 253

4.4.5 Solar thermal for industrial processes ......................................................................... 254

4.4.6 Wind-diesel hybrid at a garnet mine in Australia ...................................................... 255

4.4.7 Power generation from sewage biogas in Windhoek, Namibia .............................. 256

4.4.8 Bio2Watt organic animal waste to electricity case study .......................................... 257

4.4.9 Biogas used for energy services in South African schools ....................................... 258

4.4.10 Harmony biogas to thermal energy project ................................................................ 259

4.4.11 Heat and power produced by biogas at Riverside Piggery....................................... 260

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4.4.12 IBERT Biogas combined heat and power facility ..................................................... 261

4.4.13 Co-firing waste coffee grounds with coal for heating services................................ 262

4.4.14 Co-firing with sustainable charcoal in Brazil’s steel sector ...................................... 263

4.4.15 Badplaas hydro pilot ...................................................................................................... 264

4.4.16 Electricity generation from methane at the Beatrix Gold Mine.............................. 265

4.4.17 Summary of key trends from case studies .................................................................. 266

5 Conclusions ..................................................................................................................................... 268

6 Recommendations .......................................................................................................................... 271

7 References ........................................................................................................................................ 272

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Table of Figures Figure 1-1: South Africa's Total Primary Energy Supply (PJ), (Department of Energy, 2014a) ..... 2 Figure 1-2: Summary of South Africa's 2010 GHG Inventory (Department of Environmental Affairs, 2014a) ............................................................................................................................................. 3 Figure 1-3: GHG emissions from South Africa’s energy consuming and transformation sectors (Department of Environmental Affairs, 2014a) ..................................................................................... 3 Figure 1-4: Typical energy pathways from source to service (REN21, 2017a) .................................. 4 Figure 1-5: IRP 2010, targeted energy mix for 2030, (Department of Energy, 2015a) .................... 5 Figure 1-6: South Africa’s DNI levels (Solargis, 2015b) ....................................................................... 7 Figure 1-7: South Africa’s GHI levels (Solargis, 2015a) ........................................................................ 8 Figure 1-8: South Africa’s mean wind speed (Wind Atlas for South Africa, 2017) .......................... 9 Figure 1-9: Areas with micro hydro potential in South Africa, (Department of Minerals and Energy, Eskom, CSIR, 2001, cited in Department of Energy, n.d.) ................................................................ 10 Figure 1-10: Small hydro power potential in the Eastern Cape of South Africa (Liu, et al 2013) . 11 Figure 1-11: Geographical limitation of plant based biomass productivity in South Africa (SAEON, 2017. South Africa’s Bioenergy Atlas) ................................................................................. 12 Figure 1-12: Transportation limitations to the use of biofuels, proximity of biomass to infrastructure (SAEON, 2017. South Africa’s Bioenergy Atlas) ........................................................ 12 Figure 1-13: Geothermal resource base map of the Karoo Basin (Campbell et al, 2016) .............. 14 Figure 1-14: Example of a fossil fuel energy value chain .................................................................... 16 Figure 1-15: South Africa's Energy Balance 2014 (International Energy Agency, 2014a) ............. 18 Figure 1-16: South Africa's final energy consumption, 2014 (International Energy Agency, 2014a) ..................................................................................................................................................................... 19 Figure 1-17: GHG emissions from South Africa’s energy consuming and transformation sectors (Department of Environmental Affairs, 2014a) ................................................................................... 20 Figure 1-18: Primary energy supply to the energy transformation sector in South Africa (Department of Energy, 2014a) .............................................................................................................. 21 Figure 1-19: Energy carriers for power generation in South Africa (Department of Energy, 2014a) ..................................................................................................................................................................... 22 Figure 1-20: Typical coal fired power station producing steam and electricity and potential areas for renewable energy hybridisation (SAAQIS, 2012a) ........................................................................ 24 Figure 1-21: Basic representation of an OCGT plant with preheating .......................................... 26 Figure 1-22: Basic representation of an OCGT plant with intercooler .......................................... 27 Figure 1-23: Energy consumed by liquefaction plants in South Africa (Department of Energy, 2014a) .......................................................................................................................................................... 30 Figure 1-24: South Africa's Demand Sectors energy consumption (Department of Energy, 2014a) ..................................................................................................................................................................... 34 Figure 1-25: Source of energy for the South African industrial sector (Department of Energy, 2014a) .......................................................................................................................................................... 35 Figure 1-26: Energy demand for the industrial sector (Department of Energy, 2014a) ................ 36 Figure 1-27: Energy end use in the industry sector (Department of Energy, 2016a) ..................... 37 Figure 1-28: Energy consumption within the mining sector of South Africa (Department of Energy, 2014a) ........................................................................................................................................... 44

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Figure 1-29: Energy consumption within the transport sector, (Department of Energy, 2014a). 47 Figure 1-30: Transport sector end use (Department of Energy, 2016a) ........................................... 48 Figure 1-31: Energy consumption within the agriculture sector, (Department of Energy, 2014a) ..................................................................................................................................................................... 51 Figure 1-32: Energy end use in Agriculture sector (Department of Energy, 2016a) ...................... 51 Figure 1-33: Energy consumption within the commerce and public services sector, (Department of Energy, 2014a) ...................................................................................................................................... 54 Figure 1-34: Commercial and public services end use of energy (Department of Energy, 2016a) ..................................................................................................................................................................... 54 Figure 1-35: Consumption of energy in the residential sector, (Department of Energy, 2014a) .. 58 Figure 1-36: Energy end use in the residential sector (Department of Energy, 2016a) ................. 59 Figure 1-37: Various applications of electricity storage in the power system (IRENA, 2015a) .... 62 Figure 1-38: Storage capacity of different energy storage systems (REN21, 2017a) ...................... 62 Figure 1-39: Generic load profile and impact of thermal energy storage. (EPRI, 2015) ............... 63 Figure 1-40: Comparing costs to energy storage benefits (IRENA, 2015a) .................................... 66 Figure 2-1: Renewable energy service provisions, (REN21, 2017a) .................................................. 71 Figure 2-2: Capacity of renewables in the global power sector in 2016 (REN21, 2017b) ............. 71 Figure 2-3: South Africa's power stations and electricity grid network, (Eskom, 2012) ................ 73 Figure 2-4: Overview of different renewable energy sources and main technologies to convert them into direct heat, and heat & power (IEA, 2014b) ...................................................................... 75 Figure 2-5: Heating and cooling applications provided by renewable energy technologies (Modified from: EPA, 2017a) .................................................................................................................................... 76 Figure 2-6: Industrial heating provided through renewable energy technologies (modified from: EPA, 2017b) .............................................................................................................................................. 78 Figure 2-7: Heat production costs of fossil fuel based and renewable energy technologies (IEA, 2014b) ......................................................................................................................................................... 79 Figure 2-8: Range of levelised costs of energy for selected commercially available renewable energy technologies compared with non-renewable energy costs, cost development 2010-2015 (REN21, 2017a) .......................................................................................................................................................... 81 Figure 2-9: Range of solar collectors (WWF, 2017) ............................................................................. 82 Figure 2-10: Solar collector technologies applicable for various industry sectors (Solar Payback, 2017) ........................................................................................................................................................... 87 Figure 2-11: Solar thermal augmentation of a steam power plant (Miller, 2013) ............................ 88 Figure 2-12: Solar thermal augmentation of combined cycle gas turbine (Miller, 2013) ................ 89 Figure 2-13: MTN's linear Fresnel concentrated solar cooling plant at head office ....................... 89 Figure 2-14: Solar thermal integration for preheating (Solar Payback, 2017) .................................. 90 Figure 2-15: Solar system supplying heat directly to an industrial process (Solar Payback, 2017) 90 Figure 2-16: Solar heat integration through steam generation (Solar Payback, 2017) .................... 91 Figure 2-17: Solar ventilation in buildings (Gan, 1998, Kaneko et al, 2010 and Ismail, 2012) ..... 92 Figure 2-18: Average prices of solar PV per bid window in the Renewable Energy Independent Power Producer Procurement Programme (Department of Energy, 2015a) .................................. 94 Figure 2-19: Reduction in tariff for new wind, solar PV and CSP, as per the Department of Energy’s REIPPPPP (Bischof-Niemz, 2017) ....................................................................................... 95 Figure 2-20: Parabolic troughs. (Source: www.seia.org) ...................................................................... 95

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Figure 2-21: Average prices of concentrated solar power per bid window in the Renewable Energy Independent Power Producer Procurement Programme. (Department of Energy, 2015a) .......... 97 Figure 2-22: Generalised reversible endothermic chemical reactions driven by solar heat to store energy (Lovegrove, 2013) ........................................................................................................................ 98 Figure 2-23: Ammonia based thermochemical electricity production (www.solar-fuels.org) ....... 99 Figure 2-24: Production and use of solar fuels (RSC, 2012) ............................................................ 100 Figure 2-25: Value chain elements of South Africa’s mitigation streams, (Department of Environmental Affairs, n.d.2) ............................................................................................................... 103 Figure 2-26: Co-firing technology options, (IEA-ETSAP and IRENA, 2015a) ........................... 104 Figure 2-27: Global share of biomass in total final energy consumption and in final energy consumption by end-use sector (REN21, 2017b) .............................................................................. 104 Figure 2-28: Energy density of biomass and coal, (IEA Technology Roadmap cited in IEA-ETSAP and IRENA, 2015a) ....................................................................................................................................... 105 Figure 2-29: Biomass-based heating costs (USD/MWhth), (IEA, 2014b) ...................................... 113 Figure 2-30: Wind pump used to pump water (http://www.ironmanwindmill.com/) ................ 120 Figure 2-31: Deep or enhanced geothermal system (EPA, 2016) ................................................... 123 Figure 2-32: Binary-cycle geothermal power plant (Tshibalo et al, 2015) ....................................... 124 Figure 2-33: Production costs of geothermal electricity (USD/MWhe) (IEA, 2011b) ................. 125 Figure 2-34: Heating mode of ground source heat pumps (EPA, 2016) ........................................ 126 Figure 2-35: Geothermal direct use (EPA, 2016) ............................................................................... 127 Figure 2-36: Geothermal heat production costs compared with electricity and natural gas-based heating (IEA, 2014b) .............................................................................................................................. 127 Figure 2-37: Typical heating and cooling costs: bioenergy and solar .............................................. 136 Figure 2-38: Typical power generation costs: hydro, wind, solar and bioenergy........................... 137 Figure 3-1: Steps of the Multi-Criteria Decision Analysis methodology ........................................ 140 Figure 3-2: Example of maturity of renewable energy technologies (IEA, 2016b)....................... 141 Figure 3-3: Hybridisation options for the provision of thermal energy, per technology category, for locations with bioenergy availability .............................................................................................. 146 Figure 3-4: Hybridisation options for the provision of thermal energy, per technology category, for locations where there is no biofuel availability ............................................................................. 147 Figure 3-5: Thermal hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations with biofuel availability ............ 148 Figure 3-6: Thermal hybridisation options at country level based on their contribution to the large emission sectors of the national GHG inventory, for locations where there is no biofuel availability ................................................................................................................................................................... 148 Figure 3-7: Hybridisation options for the provision of electrical energy, per technology category, for locations with bioenergy availability .............................................................................................. 150 Figure 3-8: Hybridisation options for the provision of electrical energy, per technology category, for locations where there is no bioenergy availability ........................................................................ 151 Figure 3-9: Electrical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations with bioenergy availability ....... 152 Figure 3-10: Electrical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no bioenergy availability ................................................................................................................................................. 153

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Figure 3-11: Hybridisation options for the provision of mechanical energy, for locations with bioenergy availability .............................................................................................................................. 155 Figure 3-12: Hybridisation options for the provision of mechanical energy, for locations where there is no bioenergy availability ........................................................................................................... 155 Figure 3-13: Mechanical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations with bioenergy availability ................................................................................................................................................................... 156 Figure 3-14: Mechanical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no bioenergy availability ................................................................................................................................................. 157 Figure 3-15: Hybridisation options for the provision of mobility services, per transportation mode, for locations with biofuel availability ................................................................................................... 158 Figure 3-16: Hybridisation options for the provision of mobility services, per transportation mode, for locations where there is no biofuel availability ............................................................................. 159 Figure 3-17: Mobility based hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no biofuel availability ................................................................................................................................................. 161 Figure 3-18: Mobility based hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no biofuel availability ................................................................................................................................................. 161 Figure 3-19: Global trends in policy instruments to support renewable energy implementation (IRENA, 2017a) ...................................................................................................................................... 164 Figure 3-20: South African renewable energy technology maturity S-Curve ................................. 174 Figure 3-21: The role of policy linked to the South African renewable energy technology maturity S-curve ...................................................................................................................................................... 175 Figure 3-22: South African renewable energy policy development linked to technology adoption rate ............................................................................................................................................................. 176 Figure 3-23: Potential of hybridisation to drive increased uptake of renewable energy ............... 177 Figure 3-24: Market growth of new installed capacity (unglazed and glazed water collectors) by region (Weiss et al., 2017) ....................................................................................................................... 179 Figure 3-25: Solar PV capacity and additions, top 10 countries, 2016 (REN21, 2017b) ............. 183 Figure 3-26: Segmentations of PV installations 2011-2015 (IEA, 2016) ........................................ 184 Figure 3-27: Global bioenergy consumption for heat, transport and electricity in 2004 and 2014 (IEA & FAO, 2017)................................................................................................................................ 186 Figure 4-1: Global weighted average utility-scale solar PV total installed costs, 2009-2025 (IRENA, 2016c)........................................................................................................................................................ 216 Figure 4-2: Capital cost break down for steam production costs for CSP (IRENA, 2012) ........ 218 Figure 4-3: Summary of levelised savings for wind electricity to substitute grid electricity for a 3.5 kW, 1 kW and 0.6 kW installation using the medium discount rate ......................................... 223 Figure 4-4: Eskom’s historic average price trend (c/kWh), (Eskom, 2017)................................... 248 Figure 4-5: Clicks' solar PV installation at the Group's Head Office. ............................................ 251 Figure 4-6: Solar panel at Thembelihle Informal Settlement (source: City Power) ...................... 252 Figure 4-7: Solar thermal systems installed at the Bergridge Park Retirement Village in Cape Town. ................................................................................................................................................................... 253

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Figure 4-8: CBC solar thermal panels (photo: www.solarthermalworld.org) ................................. 254 Figure 4-9: Martin Next Generation Solar Energy Center (photo: www.cspworld.com) ............ 254 Figure 4-10: Australian Garnet's Balline Project Site in Western Australia. ................................... 255 Figure 4-11: The Bio2Watt Biogas Plant located on the Beefcor cattle feedlot (Earthworks, 2016) ................................................................................................................................................................... 257 Figure 4-12: Biogas digester tanks installed at Khangezile Primary School in Springs. Photo: eNCA/Bianca Bothma ........................................................................................................................... 258 Figure 4-13: Onsite work on Harmony Biogas Project ..................................................................... 259 Figure 4-14: Covered anaerobic lagoon at the Riverside Piggery .................................................... 260 Figure 4-15: Ibert biogas anaerobic digester and combined heat and power facility .................... 261 Figure 4-16: Typical fluidised bed combustion system (Source: www.photomemorabilia.co.uk) ................................................................................................................................................................... 262 Figure 4-17: ArcelorMittal BioEnergia Ltda’s eucalyptus plantation in Minas Gerais, Brazil. Photo: Carlos Euler ............................................................................................................................................. 263 Figure 4-18: Refurbished Badplaas hydro turbine (photo source: Nepsa Energy) ....................... 264 Figure 4-19: Methane flaring point at Sibanye-Stillwater’s Beatrix mine (photo: Sibanye-Stillwater) ................................................................................................................................................................... 265

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Table of Tables Table 1-1: Eskom’s existing power generation technologies ........................................................... 22 Table 1-2: Technical characteristics of a coal fired power plant ........................................................ 23 Table 1-3: Renewable energy hybridisation potential of coal fired power plants ............................ 24 Table 1-4: Technical characteristic of an OCGT power plant ........................................................... 26 Table 1-5: Renewable energy hybridisation potential of an OCGT power plant ............................ 27 Table 1-6: Existing oil refineries in South Africa with estimated GHG emissions (SAPIA, 2014) ..................................................................................................................................................................... 28 Table 1-7: Technical characteristic of an oil refinery ........................................................................... 29 Table 1-8: Renewable energy hybridisation potential of an oil refinery ............................................ 29 Table 1-9: Liquefaction plants in South Africa (SAPIA, 2014) .......................................................... 30 Table 1-10: Technical characteristics of liquefaction plant components .......................................... 31 Table 1-11: Renewable energy hybridisation potential of a liquefaction plant ................................ 32 Table 1-12: End use electricity consumption in the industry sector (Department of Energy, 2016a) ..................................................................................................................................................................... 37 Table 1-13: Technical characteristics of process heating technologies ............................................. 38 Table 1-14: Renewable energy hybridisation potential for processing heating technologies ......... 39 Table 1-15: Technical characteristics of industrial cooling and refrigeration technologies ........... 42 Table 1-16: Renewable energy hybridisation potential for industrial cooling and refrigeration technologies ............................................................................................................................................... 42 Table 1-17: Technical characteristics of motor driven systems equipment ..................................... 43 Table 1-18: Renewable energy hybridisation potential for motor driven system technologies ..... 43 Table 1-19: Technical characteristics of mining sector technologies ................................................ 45 Table 1-20: Renewable energy hybridisation potential for mining sector technologies ................. 45 Table 1-21: Technical characteristics of transportation modes used in the transport sector ........ 48 Table 1-22: Renewable energy hybridisation potential for the transport sector .............................. 49 Table 1-23: Technical characteristics of technologies in the agriculture sector ............................... 52 Table 1-24: Renewable energy hybridisation potential for the agriculture sector ........................... 52 Table 1-25: Technical characteristics of the technologies in the commerce and public services sector ........................................................................................................................................................... 55 Table 1-26: Renewable energy hybridisation potential in the commerce and public services sector ..................................................................................................................................................................... 55 Table 1-27: Technical characteristics of technologies in the residential sector .............................. 59 Table 1-28: Renewable energy hybridisation potential in the residential sector .............................. 60 Table 1-29: Fossil fuels used for non-energy applications (Department of Environmental Affairs, n.d.) ............................................................................................................................................................. 68 Table 1-30: Sasol non-energy products ................................................................................................ 68 Table 2-1: Renewable energy heating and cooling technologies ........................................................ 76 Table 2-2: Industrial processes and their temperature requirements (IEA-ETSAP and IRENA, 2015b) ......................................................................................................................................................... 77 Table 2-3: Typical solar components and measures ............................................................................ 83 Table 2-4: Typical solar heating and cooling costs .............................................................................. 91 Table 2-5: Typical silicon solar PV costs ............................................................................................... 94

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Table 2-6: Typical thin-film solar PV costs ........................................................................................... 94 Table 2-7: Typical concentrated solar power costs .............................................................................. 97 Table 2-8: Comparison of solar fuel costs with conventional fuel prices....................................... 101 Table 2-9: Typical biomass components and measures .................................................................... 105 Table 2-10: Summary of the ethanol producers in South Africa and Swaziland (Department of Energy, n.d.2) .......................................................................................................................................... 110 Table 2-11: Typical biomass heating and cooling costs .................................................................... 114 Table 2-12: Typical biomass power generation costs ........................................................................ 116 Table 2-13: Typical wind components and measures ........................................................................ 117 Table 2-14: Typical wind power generation costs .............................................................................. 119 Table 2-15: Typical mechanical wind power costs ............................................................................. 121 Table 2-16: Typical geothermal components and measures ............................................................. 122 Table 2-17: Typical small and micro scale hydro components and measures ............................... 129 Table 2-18: Typical small and micro scale hydropower costs .......................................................... 130 Table 3-1: Breakdown of country GHG emissions per technology category (Analysis carried out using data from South Africa’s 2010 GHG inventory, Department of Environmental Affairs, 2014a) ........................................................................................................................................................ 143 Table 3-2: Hybridisation Options included in African Nationally Determined Contributions .. 166 Table 3-3: REIPPPP key success factors and lessons for hybridisation (Adapted from Eberhard, A; Kolker, J and Leigland, J., 2014) ...................................................................................................... 168 Table 3-4: Barrier faced by project developers to localised or municipal renewable energy project development in South Africa ................................................................................................................ 173 Table 3-5: Challenges and key lessons learnt from unsuccessful hybridisation projects .............. 193 Table 4-1: General assumptions used within the techno economic technology review ............... 208 Table 4-2: Levelised savings for direct pre-heating of boiler feed water with solar thermal to substitute coal .......................................................................................................................................... 212 Table 4-3: Levelised savings for solar PV electricity to substitute grid electricity at a high average electricity price (R1.80/kWh) ................................................................................................................ 214 Table 4-4: Levelised savings for solar PV electricity to substitute grid electricity at a medium average electricity price (R1.50/kWh) .................................................................................................. 215 Table 4-5: Levelised savings for solar PV electricity to substitute grid electricity at a low average electricity price (R1.20/kWh) ................................................................................................................ 215 Table 4-6: Levelised savings for CSP electricity generation at different average electricity prices (including peak tariff) ............................................................................................................................. 217 Table 4-7: Levelised savings for CSP electricity generation at different average electricity prices (using only base tariff) ............................................................................................................................ 217 Table 4-8: Levelised savings for steam from concentrated solar to substitute coal generated steam ................................................................................................................................................................... 219 Table 4-9: Levelised savings for wind electricity (3.5 kW) to substitute grid electricity at high average electricity price (R1.80/kWh) .................................................................................................. 222 Table 4-10: Levelised savings for wind electricity (3.5 kW) to substitute grid electricity at medium average electricity price (R1.50/kWh) .................................................................................................. 222 Table 4-11: Levelised savings for wind electricity (3.5 kW) to substitute grid electricity at low average electricity price (R1.20/kWh) .................................................................................................. 222

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Table 4-12: Levelised savings for pumping water with wind pumps .............................................. 224 Table 4-13: Parameters applied for techno economic assessment of direct and indirect co-firing of a coal fired boiler with biofuel .............................................................................................................. 228 Table 4-14: Direct co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit ................................................................................................................................................. 230 Table 4-15: Direct co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit, for companies consuming smaller volumes of coal ...................................................... 230 Table 4-16: Direct co-firing of coal boiler with biomass, simple payback (years) with carbon credit benefit ....................................................................................................................................................... 231 Table 4-17: Direct co-firing of coal boiler with biomass, simple payback (years) for a carbon tax paying entity ............................................................................................................................................. 231 Table 4-18: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk ................................................................................................. 232 Table 4-19: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for companies consuming small volumes of coal .......... 233 Table 4-20: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, with carbon credit benefit ................................................. 233 Table 4-21: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for a carbon tax paying entity ........................................... 233 Table 4-22: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with medium risk, without any carbon benefits ..................................... 234 Table 4-23: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit ............................................................................................................................................ 235 Table 4-24: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit, for a company consuming small volumes of coal .................................................... 236 Table 4-25: Indirect co-firing of coal boiler with biomass, simple payback (years) with carbon credit benefit ....................................................................................................................................................... 236 Table 4-26: Indirect co-firing of coal boiler with biomass, simple payback (years) for a carbon tax paying entity ............................................................................................................................................. 236 Table 4-27: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk ................................................................................................. 237 Table 4-28: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for companies consuming small volumes of coal .......... 237 Table 4-29: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, with carbon credit benefit ................................................. 238 Table 4-30: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for a carbon tax paying entity ........................................... 238 Table 4-31: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with medium risk ......................................................................................... 238 Table 4-32: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit ............................................................................................................................................ 239 Table 4-33: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit, for a company consuming small volumes of coal .................................................... 239

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Table 4-34: Indirect co-firing of coal boiler with biomass, simple payback (years) with carbon credit benefit ....................................................................................................................................................... 240 Table 4-35: Indirect co-firing of coal boiler with biomass, simple payback (years) for a carbon tax paying entity ............................................................................................................................................. 240 Table 4-36: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk ................................................................................................. 241 Table 4-37: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for companies consuming small volumes of coal .......... 241 Table 4-38: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, with carbon credit benefit ................................................. 241 Table 4-39: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for a carbon tax paying entity ........................................... 241 Table 4-40: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with medium risk ......................................................................................... 242 Table 4-41: Levelised savings for micro hydro to substitute grid electricity: high electricity price and low hydro power costs .................................................................................................................... 244 Table 4-42: Levelised savings for micro hydro to substitute grid electricity: low electricity price and low hydro power costs ........................................................................................................................... 245 Table 4-43: Levelised savings for micro hydro to substitute grid electricity: high electricity price and high hydro power costs .................................................................................................................. 245 Table 4-44: Levelised savings for micro hydro to substitute grid electricity: low electricity price and high hydro power costs .......................................................................................................................... 245

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1 Evaluating existing and potential future fossil fuel value chains in South Africa and their potential for hybridisation with renewable energy

1.1 Introduction This report documents the work for the research project of the “Appraisal of Implementation of Fossil Fuel and Renewable Energy Hybrid Technologies in South Africa”. The first chapter aims to assess the fossil fuel value chains in South Africa and identify the opportunities for fossil fuel and renewable energy hybrid technologies. The overall report aims to provide the following:

• Identification of the potential applications of hybridisation of renewable energy and fossil fuel technologies in South Africa;

• An assessment of the technology types which are being developed to run on a mixture of fossil and renewable energies;

• Review implemented hybrid projects and plans nationally and abroad; and • Analyse the techno-economic aspects of hybridisation.

The financial resources committed to fossil fuel hybridisation with renewable energy should be in support of South Africa’s need to transform the economy to a low carbon economy. The Paris Climate Change Agreement aims to keep global warming well below 2°C and pursue all efforts to limit temperature increases to 1.5°C above pre-industrial levels. The South African government has ratified this agreement demonstrating the country’s commitment to transforming to a low carbon economy. The Government has committed to reducing its carbon emissions following a peak, plateau and decline greenhouse gas (GHG) trajectory range. The country aims to peak its emissions between 2020 and 2025 and then plateau for approximately a decade and decline thereafter. South Africa needs to implement significant mitigation actions in order to achieve such ambitious GHG emission targets. South Africa’s total energy supply is heavily reliant on fossil fuels with 72% of the primary energy supply from coal, 17% from crude oil, 4% from petroleum products, and 3% from gas, Figure 1-1. This is comparable to 200 million tonnes of coal, 160 million of oil barrels, 6,000 Ml of diesel and 5,000 Mm3 of gas.

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Figure 1-1: South Africa's Total Primary Energy Supply (PJ), (Department of Energy, 2014a)

Fossil fuels have historically played a large role in South Africa’s energy intensive economy due to the mining and processing of its rich mineral reserves. More than 90% of the primary energy is derived from fossil fuels (Figure 1-1), with 80% of the country’s GHG emissions produced from the consumption of energy sources at end use (Figure 1-2). In addition to electricity which is 90% fossil fuel dependant, about 30% of the country’s liquid fuels are produced from coal and gas which are carbon intensive processes. The country’s national GHG emissions inventory is summarised in Figure 1-2. The majority of emissions, 83%, are produced from the transformation and consumption of energy, amounting to 430 MtCO2e annually. Industry produces 8% of the emissions, Agriculture, Forestry and Other Land Use (AFOLU) 5% and the waste sector produces 3% (Department of Environmental Affairs, 2014a). With this breakdown, it is evident that the potential for driving emissions reductions within the country relies heavily on implementing mitigation actions within the energy transformation and consumption.

Coal72%

Crude Oil17%

Petroleum Products4%

Gas3%

Nuclear3%

Hydro1% Solar and Wind

<1%

Biomass<1%

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Figure 1-2: Summary of South Africa's 2010 GHG Inventory (Department of Environmental Affairs, 2014a)

The emissions related to energy can be broken down further into the various energy consuming categories, this is presented in Figure 1-3. The majority of the emissions, 62% (264 MtCO2e), are from the energy transformation within the country. The transport sector accounts for 11% of emissions (47 MtCO2e). Other sectors, including commercial, residential and agricultural account for 11% of the energy emissions (45 MtCO2e), with manufacturing industries and construction accounting for 10% (41 MtCO2e).

Figure 1-3: GHG emissions from South Africa’s energy consuming and transformation sectors (Department of Environmental Affairs, 2014a)

South Africa’s drive to a low carbon economy is being supported by several actions in the country. These include the green economy initiative, the proposed carbon tax, the draft solar energy technology roadmap, reporting regulations, the integrated resource plan and the integrated energy plan, amongst others. Notwithstanding South Africa’s continually increasing implementation of

430 MtCO2eEnergy

83%

44 MtCO2eIndustry

8%

25 MtCO2eAFOLU

5%

19 MtCO2eWaste

4%

Energy transformation

62%Transport

11%

Other sectors11%

Manufacturing industries and construction

10%

Fugitive emissions from

fuels6%

Non-specified0%

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renewable energies and energy efficiency measures, fossil fuels are forecast to remain the major source of primary energy over the next 20 to 30 years. One of the transitional strategies that should be considered in driving down the country’s emissions from a heavily fossil fuel driven economy, is the potential of implementing hybrid energy technologies. This would be to replace, augment or boost conventional fossil fuel technologies with renewable energy technologies. This report discusses the opportunities for hybridisation of South Africa’s fossil fuel value chains with renewable energy.

1.2 South Africa’s energy resources South Africa is rich in natural resources including fossil fuels, renewable resources and uranium for nuclear energy. Fossil fuels in South Africa include coal, gas and oil. Renewable energy resources in South Africa include wind; solar; hydro; biomass; and certain products classified as waste. Other potential renewable energy could be from geothermal sources. South Africa has historically relied on coal resources to supply the nation’s electricity requirements, as well as the demand from neighbouring countries and those further afar in the region. Reliance on coal might in future be reducing, largely due to the country’s strategic long term goals to transition to a lower carbon and climate resilient society. South Africa’s diverse mix of energy resources provides opportunities for the country to reach its energy and climate-related goals, which also mitigate the risks associated with energy supply and the heavy reliance on one specific energy source. Different energy resources have different characteristics and potential uses. Typical ‘conversion pathways’ from source to service are illustrated in Figure 1-4.

Figure 1-4: Typical energy pathways from source to service (REN21, 2017a)

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South Africa’s Integrated Resource Plan (IRP), developed under the Electricity Regulation Act of 2006, outlines the country’s electricity policy for the future and provides a planning framework for the management of electricity demand in South Africa. The IRP articulates the preferred electricity mix and delivery timeline with which to meet the country’s electricity needs over a 20-year planning horizon. The IRP 2010, the most recently approved plan, estimates that increased electricity demand in South Africa will require a total system capacity of 89,532 MW by 2030. In the assumptions, base case results and observations report of the updated IRP 2016 (Department of Energy, 2016c) a series of electricity demand scenarios were published, but no outcome was defined. The range of electricity demand in 2030 was forecast to be between 300,000 GWh and 390,000 GWh (Department of Energy, 2016c). Following the IRP 2010, 23.6GW is anticipated to arise from renewable resources (including hydro), illustrated in Figure 1-5.

Figure 1-5: IRP 2010, targeted energy mix for 2030, (Department of Energy, 2015a)

*Where OCGT = Open Cycle Gas Turbine; CCGT = Closed Cycle Gas Turbine, both could operate on petroleum products or natural gas The resources required to supply the country’s proposed energy mix as outlined in the IRP 2010 (Figure 1-5) are discussed in the following subsections. The base case assumptions for the 2016 IRP has not yet presented a final plan which defines capacity required from various energy sources. In the interim, research undertaken by the CSIR (2016b) finds that a mix of solar PV, wind and flexible power can supply South Africa’s baseload demand in the same reliable manner as a base-power generator. The findings of this research support the increased interest in developing renewable energy in South Africa, wherein hybridisation with fossil fuels can play an important part.

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1.2.1 Coal resources The Department of Energy (2017a) reports that at the current production rate, there should be more than 50 years of coal supply left in South Africa. South Africa's coal reserves are estimated as 30 billion tonnes and recoverable coal reserves are estimated at 49 billion tonnes (Hartnady, 2010). Uncertainties regarding the availability of significant amounts of economically extractable coal reserves for future use means that the generally expected dependence on coal well into the foreseeable future is also uncertain. The high emission intensity of coal use is a further disincentive to develop this sector further, considering that there are diverse fuel sources available in South Africa. South Africa has committed to decarbonising the country’s energy sector, which accounts for about 80% of the country’s GHG emissions as per the South African 2010 GHG Inventory (Department of Environmental Affairs, 2014a). This strategic shift will generate significant risks and opportunities for the energy sector value chains. In particular, vast reserves of coal and existing power stations will become ‘stranded assets’, exposing the country’s economy to inadequate generation capacity, job losses in the mining sector and reduced income from coal exports if adequate alternatives are put in place. Investigations to ‘clean’ or hybridised coal resources and uses with renewable energies therefore present opportunities to conserve jobs and revenues along the coal value chain, while simultaneously reducing emissions associated with fossil fuel. 1.2.2 Petroleum resources The latest draft Integrated Energy Plan (Department of Energy, 2016a) states that natural gas presents the most significant potential in South Africa’s energy mix. The use of natural gas in open cycle gas turbines in the electricity sector, gas to liquid plants in the liquid fuel sector and for direct thermal applications in the industrial and residential sectors, positions it as a viable option in the energy mix. The Energy Information Administration (EIA) of the USA found that South Africa’s assessed resource of technically recoverable shale gas and coal bed methane resources in the Southern Karoo Basin is 485 trillion standard cubic feet (TCF), (Department of Mineral Resources, 2012). Following on this study, Petroleum Agency SA carried out an assessment which builds on the work from the EIA, which concluded that South Africa has a range of between 30 – 500 TCF of gas which may be technically recoverable (Department of Mineral Resources, 2012). These assessments are largely speculative and it will not be possible to reduce the associated uncertainty without specific exploration in the form of drilling, sampling of shales and testing of boreholes (Department of Mineral Resources, 2012). Natural gas and gas produced from coal play separate roles in the energy system, with natural gas being used as a feedstock for the production of synthetic fuels, and gas from coal as an industrial and domestic fuel (Department of Energy, 2017b). There is potential for hybridisation within the

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liquefaction plants which produce gas in South Africa, as well as potential to hybridise the technology in South Africa which operate by using gas as its energy source. 1.2.3 Solar resources South Africa has large expanses of flat terrain with high irradiation and low rainfall levels, making it ideal for solar power. For the purposes of energy generation, the main categories of solar radiation include global horizontal irradiance (GHI) and direct normal irradiance (DNI). GHI is the total amount of shortwave radiation received by a surface that is horizontal to the ground. GHI includes both DNI and diffuse horizontal irradiance. DNI is the measure of sunlight that directly strikes the solar collectors at an angle of 90 degrees, which is required for the sunlight to be focused onto the concentrated solar power receivers. The country experiences some of the highest levels of solar radiation in the world, where the annual sum of direct normal irradiation (DNI) ranges between 1 400 and 3 200 kWh/m2/year (Figure 1-6) and where the annual average global horizontal irradiation (GHI) levels range between 1 500 and 2 350 kWh/m2/year (Figure 1-7). The DNI thus translates to around between 3.84 and 8.77 kWh/m2/day. The GHI translates to around 4.11 and 6.44 kWh/m2/day.

Figure 1-6: South Africa’s DNI levels (Solargis, 2015b)

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Figure 1-7: South Africa’s GHI levels (Solargis, 2015a)

A number of solar atlases have been developed for the country, including the Southern African Universities Radiometric Network (SAURAN). This Network is equipped with top-class instrumentation to measure solar irradiation and other meteorological parameters. The measured data and the new solar maps are made publically available on www.sauran.net. South Africa’s plentiful solar resources present hybrid energy opportunities, particularly where they are paired with fossil fuel sources and as a co-benefit may mitigate GHG emissions.

http://www.sauran.net/

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1.2.4 Wind resources The Department of Energy collaborated with various partners to develop the Wind Atlas for South Africa. The Wind Atlas comprises a database of wind time-series data from 10 wind measurement stations across South Africa, a high-resolution wind resource map and an Extreme Wind Atlas. The data confirms that South Africa not only has good coastal, but also good inland wind energy potential, illustrated in Figure 1-8.

Figure 1-8: South Africa’s mean wind speed (Wind Atlas for South Africa, 2017)

The first phase of the Wind Atlas of South Africa was completed for the whole of the Western Cape and parts of Northern and Eastern Cape provinces. The second phase of the atlas is underway, which will cover the remaining areas of the Eastern Cape, KwaZulu Natal and Free State provinces. The third phase will cover the remaining areas of the Northern Cape and rest of South Africa. Interim resource maps for phases two and three are expected by early 2018. Research by the CSIR indicates that the wind resource potential in South Africa is as good as the country’s solar resource. Almost the entire country has sufficient resources with potential for high load factors (CSIR, 2016a).

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1.2.5 Hydro resources Even though South Africa is a water scarce country, opportunities for hydropower do exist. The country contains a mix of small hydroelectricity stations and pumped water storage schemes. However South Africa is a net importer of hydro power, with access to 1300MW of hydropower from the Cahora Bassa Dam in Mozambique (Department of Energy, 2016a). As a water-scarce country, during dry period South Africa won’t be able to rely on smaller-scale hydropower resources for power generation, (Department of Energy, 2016a). A Baseline Study on Hydropower in South Africa conducted in 2002 by the Department of Minerals and Energy highlights specific areas in the country that show potential for the development of all categories of hydropower, in the short and medium term. The Eastern Cape and KwaZulu-Natal in particular contain the best potential for the development of small and micro (less than 10MW) hydropower plants (Figure 1-9 and Figure 1-10 specifically looking at the Eastern Cape).

Figure 1-9: Areas with micro hydro potential in South Africa, (Department of Minerals and Energy, Eskom, CSIR, 2001, cited in Department of Energy, n.d.)

11

Figure 1-10: Small hydro power potential in the Eastern Cape of South Africa (Liu, et al 2013)

The advantages of small and micro hydro plants include their ability to be either standalone projects or hybridised with other renewable energy sources. Commercial farms therefore have hydro energy potential where there are dams on site. Further benefits can be derived from the association with other uses of water (water supply, irrigation, flood control, etc.), which are critical to South Africa’s future economic and socio-economic development. 1.2.6 Biomass and waste resources South Africa contains various bioenergy resources which range from organic waste streams to agricultural and forestry residues. Bioenergy may represents hybridisation opportunities due to small and modular nature of the relevant technology applications. There is a dispersion of the resources around the country, and thus it is very location specific and not an applicable resource everywhere. The Department of Trade and Industry recently developed and launched the South African bioenergy atlas. This atlas is a new web based tool, specific to crop based biomass and not organic waste streams. The atlas provides guidance on identifying potential woody biomass resources, particularly those that may be utilised as alternative energy sources (SAEON, 2017). These crop based resources range from various forms of woody biomass, invasive alien plants, to sugar cane and various oil producing plants (e.g. sunflowers and ground nut varieties). The resource availability of plant based biomass is presented in Figure 1-11 below.

12

Figure 1-11: Geographical limitation of plant based biomass productivity in South Africa (SAEON, 2017. South Africa’s Bioenergy Atlas)

The proximity of industry to plant based bioenergy resources is presented in Figure 1-12.

Figure 1-12: Transportation limitations to the use of biofuels, proximity of biomass to infrastructure (SAEON, 2017. South Africa’s Bioenergy Atlas)

In the Department of Energy’s (n.d) assessment of four main biomass sources (invasive alien plants, bush encroachment, bagasse and plantation forestry residues), an estimated quantity of 22.2 million tonnes is thought to be available for energy generation. However, the sparse geographical distribution and associated distances to generation units were identified as the main barrier for the utilisation of this energy source. This is a limiting factor to the use of biomass in hybridised facilities

13

and hybridisation with biomass will thus only be relevant where the sustainably sourced resources is available on a continuous basis. The co-benefits of developing bioenergy from sustainably harvested woody biomass include a reduction in fossil fuel grid electricity, reducing fire risks, overall healthier forests and increased employment opportunities. The increasing prevalence of innovative waste to energy projects in South Africa supports the premise that waste streams are a viable and sustainable energy resource. Material by-products (often classified as waste products) and organic household, municipal and industrial wastes in particular represent energy conversion opportunities. There are a broad range of technologies that can convert waste into energy to power homes, businesses, transportation and feedstock materials that can be used to manufacture new projects. Energy recovery from waste streams typically includes a thermal treatment (e.g. combustion, gasification or pyrolysis) and can be added to, or used in conjunction with, traditional fossil fuel energy conversion processes such as boilers or kilns. While South Africa has significant quantities of landfill waste and other untapped waste resources, the rollout of waste to energy projects is constrained by various factors. These factors include, among others, relatively low electricity prices combined with the relatively high capital costs of waste to energy technologies (making it difficult for waste to energy projects to compete), the diversity of waste streams and lengthy Environmental Impact Assessment and governmental approval processes (SANEDI, 2014). Due to the legislative constraints of using municipal waste, this study did not look at the possibility of utilising waste from municipal landfills as a feedstock. Overcoming the various barriers to implementation will facilitate the development of waste to energy projects. These projects may assist the country reduce its reliance on fossil fuels and reduce waste to landfills (increasingly constrained by airspace limitations). This will thereby mitigate the environmental impacts associated with both the use of fossil fuels and landfilling practices, while supporting the development of a circular economy. Such practices are essential for long term sustainability. 1.2.7 Geothermal resources Research into the use of geothermal energy to improve energy resilience is increasing internationally but has yet to be comprehensively explored in South Africa on the basis that the country is too tectonically stable (Dhansay, De Wit and Patt, 2013). Conventionally, geothermal energy applications have focused on power generation using high-temperature hydrothermal resources or enhanced geothermal systems where the heat from the earth’s molten core is converted to electricity. However, new research (Campbell, Lenhardt, Dippenaar and Götz, 2016, Dhansay et al, 2013 and Tshibalo et al, 2015) indicates that lower-temperature (below 150°C) geothermal resources are also available in South Africa (Figure 1-13).

14

Figure 1-13: Geothermal resource base map of the Karoo Basin (Campbell et al, 2016)

Geothermal heating is the direct use of geothermal energy for heating applications. Thermal efficiency in such applications is high as there is no energy conversion required, however the capacity factors tend to be low as the heat is mainly needed during winter periods. Where a heat source is readily available, the hot water or steam can be captured and piped directly into radiators or heat exchangers. In areas with low temperature geothermal resources, a ground-source heat pump can provide space heating and space cooling. Investigations are ongoing into the use of this lower-temperature geothermal energy to provide space cooling and refrigeration through absorption or adsorption cooling technologies, or for space heating. Geothermal applications may be suited to deep underground mines in South Africa, where the rock face temperatures increase with depth and can exceed 50°C. With direct-use and absorption or adsorption technologies, low-temperature geothermal resources have the potential to supply a portion of the cooling demands in buildings. In this closed-loop application cooling tubes are buried underground and draw up air which gives up some of its heat to the surrounding soil, entering the building as cooler air. The closed-loop application can be used in conjunction with typical electrical air-cooling systems, thereby reducing the electrical load. Alternatively, open-loop cooling tube systems draw air from outdoors and delivers this to the inside of the building. The benefits of this system are that it provides ventilation while cooling the building’s interior, which may also reduce the load on traditional electric air-cooling systems. There are however questions regarding the demand and economic viability of geothermal heating or cooling of industrial or residential spaces, considering that South Africa has a relatively mild

15

annual temperature ranges, limiting space heating and cooling requirements. The demand for space heating and cooling is driven by the number of heating and cooling degree days. One heating degree-day unit is given for each degree that the mean daily temperature falls below 18°C. Conversely, one cooling degree-day unit is given for each degree that the mean daily temperature rises above 18 °C (South African Weather Service, 2017). Given that South Africa typically has relatively few heating days compared with countries in the northern hemisphere, the demand for such services is not great. Lack of demand may be limiting the pursuit of geothermal energy sources considering that related activities are more capital intensive than other renewable sources in South Africa. While geothermal energy applications are not listed activities in terms of South Africa’s Environmental Impact Assessment Regulations, incidental activities such as site preparation and site construction may trigger certain listed activities contained in the regulations, for which authorisation will need to be obtained. 1.2.8 Nuclear resources Uranium is a naturally radioactive element which is used to power nuclear reactors. Uranium production in South Africa has generally been a by-product of gold or copper mining. The nuclear sector in South Africa is mainly governed by the Nuclear Energy Act 1999, Act 46 of 1999 and National Radioactive Waste Disposal Institute Act, Act 53 of 2008. These Acts are administered by the Department of Energy. South Africa currently has two nuclear reactors generating 6% of its electricity and is considering expanding its nuclear capacity. The updated draft IRP (published in November 2016) envisages a nuclear build target in its base case of 6.8 GWe, which would come online in 2037-2041, and a further 20.4 GWe by 2050 when nuclear is expected to contribute 30% of the country’s electricity capacity. Nuclear is not classified as a fossil fuel nor as a renewable energy and thus won’t be assessed for hybridisation potential in this work.

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1.3 Fossil fuel value chains in South Africa and the potential for hybridisation

Following the assessment of the energy resources in South Africa, an understanding of the fossil fuel value chains in the country is undertaken in order to assess the potential for hybridisation of these fossil fuel chains with renewable energy technologies. A fossil fuel value chain, is an energy system that operates on fossil fuel energy sources. These energy systems include all components related to the production, conversion, delivery and end-use of energy. Such an energy system can be represented as a combination of energy value chains. An example of an energy value chain is provided in Figure 1-14 (vertical lines represent commodities; rectangles represent technologies, and horizontal lines represent commodity flows).

Figure 1-14: Example of a fossil fuel energy value chain

Complex energy systems have connections between value chains as different value chains may produce or use the same commodities. Energy in its primary form (e.g. crude oil) is converted into secondary energy carriers (e.g. petrol). Certain secondary energy carriers, such as petrol or diesel, may be imported directly into an energy system. The end of the energy value chains are demand technologies which transform energy carriers into services such as light, heat, refrigeration and transportation. In order to assess the potential for hybridisation within South Africa’s fossil fuel value chains, an evaluation of existing fossil fuel value chains in South Africa is carried out. Focus is placed on assessing where renewable energy can be used to hybridise (augment or boost output) fossil fuel systems. South Africa’s fossil fuel value chains can be divided into two areas:

• Transformation technologies: energy generating plants where there is potential for boosting output of these plants with renewable energy.

• Demand sectors and technologies: energy consuming plants where there is potential for fossil fuel augmentation with renewable energies.

The country’s energy balance is presented in a Sankey diagram below in Figure 1-15. Here the total primary energy consumption is shown, along with the transformation technologies which convert the energy into useful forms for the demand sectors, the final energy consumers. Energy transformation technologies are mostly fossil fuel driven and a large portion results in power

Coal Mine Power Station Light bulb

Coa

l

Ele

ctric

ity

Ligh

t

Transformation technologies

Demand technologies

Primary fuel resource

17

losses. It is thus within these transformation technologies where renewable energy hybridisation potentials will be assessed. The energy transformation sector accounts for 62% of the GHG emissions produced within the energy consuming and transformation sectors (Figure 1-3). With this in mind, if renewable energy hybridisation interventions in the energy transformation sector are identified and rolled out, this would have a large impact on the overall emissions of the country.

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Figure 1-15: South Africa's Energy Balance 2014 (International Energy Agency, 2014a)

The total final energy consumption by the demand sectors is presented in Figure 1-16. It is within these demand sectors where various fossil fuel value chains end and provide energy to help produce useful products. There may be significant potential for renewable energy hybridisation of these currently fossil fuel reliant technologies. It is to be noted that if the electric demand side technologies can result in a 1% reduction in fossil fuel energy consumption this can results in a 3% reduction in the supply side primary energy1. For liquid fuels consumption, a reduction of demand by 1% reduces primary energy demand related to fuels by 1.6%. This is due to the low energy efficiency of coal to liquids.

1 When assuming an overall efficiency of 30% for energy transformation technologies.

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Figure 1-16: South Africa's final energy consumption, 2014 (International Energy Agency, 2014a)

20

1.4 Fossil fuel energy transformation technologies

South Africa’s energy transformation technologies account for 62% of the emissions from the energy consuming and transformation sectors in the country, as is presented in Figure 1-17. This equates to approximately 270 MtCO2e emitted annually (Department of Environmental Affairs, 2014a). The energy transformation sector thus presents significant opportunities for GHG mitigation potential in the country and a potential opportunity for renewable energy hybridisation.

Figure 1-17: GHG emissions from South Africa’s energy consuming and transformation sectors (Department of Environmental Affairs, 2014a)

South Africa’s energy transformation technologies are 97% fossil fuel driven, refer to Figure 1-18. The bulk of these energy transformational technologies, 68%, consume coal in order to produce secondary energy sources (Department of Energy, 2014a). Crude oil is primarily converted to petroleum products, this accounts for 26% of the primary energy supply.

Energy transformation

62%Transport

11%

Other sectors11%

Manufacturing industries and construction

10%

Fugitive emissions from

fuels6%

Non-specified0%

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Figure 1-18: Primary energy supply to the energy transformation sector in South Africa (Department of Energy, 2014a)

Coal is primarily used for the production of electricity, with a smaller portion consumed in liquefaction plants for production of petroleum products. Crude oil is processed in oil refineries to produce petroleum products for the country. There are also small quantities of petroleum products imported, 9,000 Ml, with 24,000 Ml produced in the country (Department of Energy, 2014a). Within the energy transformation technologies, power stations and the liquid fuels industry (particularly liquefaction plants) are the largest consumers of fossil fuels and thus if renewable energy hybridisation within these plants is possible, this could have a significant reduction in the country’s GHG emissions produced from these processes. 1.4.1 Electricity plants South Africa’s electricity production industry is highly fossil fuel dependent for provision of the country’s baseload. It is dominated by the public utility company, Eskom. South Africa controls a total installed capacity of 43 895 MW of which more than 90% is owned by Eskom (Eskom, 2016). Eskom generates, transmits and distributes electricity to industrial, mining, commercial, agricultural and residential customers and redistributors (municipalities). The country’s electricity production fleet comprises of coal fired power plants and a nuclear power plant for the baseload production. Peaking power is provided by open cycle gas turbines (OCGT), which operate on kerosene and diesel, as well as by pumped storage schemes and hydroelectric stations. The country also has various other renewable energy power plants including solar and wind plants owned and

Coal78%

Crude Oil15%

Petroleum Products

1%

Gas3%

Nuclear3%

Hydro<1%

Solar and Wind<1%Biomass

<1%

22

operated by independent power producers. The energy carriers used for power generation in South Africa are presented in Figure 1-19.

Figure 1-19: Energy carriers for power generation in South Africa (Department of Energy, 2014a)

The 10% balance of electricity not produced by Eskom is produced by independent power producers and municipalities (Eskom, 2016). In order to assess the potential for fossil fuel hybridisation with renewable energies, we will review the fossil fuel powered power stations in the country. The existing Eskom’s fossil fuel power station technologies are summarised in Table 1-1 below: Table 1-1: Eskom’s existing power generation technologies2

Plant Type Number

of stations

Total installed capacity

(MW)

Total nominal capacity (MW)

Electricity generated (GWh/yr)

Estimated GHG

emissions (MtCO2e/yr)3

Commodity consumed

per year

Coal-fired plant 15 38 548 36 441 199 888 223 114 800 000

tonnes coal

OCGT 4 2 426 2 409 3 936 3.38 1 248 Ml of diesel and kerosene

2 Eskom Integrated Annual Report, 2016 3 Calculated using the South Africa Technical Guidelines for Monitoring, Reporting and verification of Greenhouse Gas Emissions by Industry, April 2017, Version No: TG-2016.1, found at: https://www.environment.gov.za/sites/default/files/legislations/technicalguidelinesformrvofemissionsbyindustry.pdf

2539 PJ Coal92%

45 PJ Petroleum Products

2%

150 PJ Nuclear

5%

14 PJ Hydro

1%

1.7 PJ Solar and Wind

<1%

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The GHG emissions which are emitted from the electricity generation sector in South Africa amounts to around 237 MtCO2e per year as per the South African 2010 GHG Inventory (Department of Environmental Affairs, 2014a). A high level calculation estimates that the coal fired power plants emit around 223 MtCO2e/year and the peaking OCGT power plants emit around 3.38 MtCO2e/year. 1.4.1.1 Technical characteristics of coal fired power plants South Africa’s coal-fired boilers predominantly use pulverised coal technology. Coal is crushed into a fine powder in mills and then fed into a boiler, where it combusts and burns to generate heat. The heat generates steam which turns the blades of a steam turbine connected to a generator to produce electricity. The temperate of the steam determines the efficiency of the power plant. Currently the majority of Eskom’s power plants are operated at subcritical conditions, producing steam at temperatures around 538°C and pressures around 16.5 MPa (EPRI, 2015). However the new plants in construction in the country (Medupi and Kusile) are operated at supercritical conditions, generating steam at pressures of at least 24.8 MPa with temperatures of 565-593°C (EPRI, 2015). Subcritical plants have an efficiency of about 36.5% and supercritical plants operate at about 38.5% efficiency (EPRI, 2015). The technical characteristics of a coal fired power plant are presented below. Table 1-2: Technical characteristics of a coal fired power plant

Technology Energy service Energy carrier

Service characteristics

Operating temperature (°C)

Coal fired power plant

Electricity production Coal Steam 538°C – 593°C

The major components of a coal-fired power plant include the coal-handling equipment, the steam generator (boiler), the turbine generator set, the bottom and fly ash handling systems, emission control equipment, cooling system and water management systems. The major components of a coal fired power plant are represented in Figure 1-20 with the potential areas for hybridisation marked with black dashed-lined boxes. These areas include the boiler itself, as well as auxiliary equipment on the power plant.

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Figure 1-20: Typical coal fired power station producing steam and electricity and potential areas for renewable energy hybridisation (SAAQIS, 2012a)

1.4.1.1.1 Renewable energy hybridisation options for coal fired power plants There are various opportunities for renewable energy hybridisation of a coal fired power stations. These renewable energy hybridisation potentials are presented in Table 1-3. Table 1-3: Renewable energy hybridisation potential of coal fired power plants

Technology Renewable energy hybridisation potential Factors to consider

Boiler

Direct solar heat to boost steam production (preheating of water)

• Area required for solar collectors • Costs for piping and pumping • Cleaning and maintenance of collectors • Water quality if it is used as the heat

transfer/working fluid

Heat from concentrated solar power (CSP) to boost steam production

• Reduction in efficiency • Retrofit boiler feed system

Direct co-firing with woody biomass (European Bioenergy Network. 2003. IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)

• Reduction in efficiency • Resource availability • Fuel handling mechanism • Fouling and corrosion risk • Boiler retrofitting • Additional space required for biomass logistics • Tailoring flue gas cleaning equipment • Sustainably sourcing biomass

Boiler

Auxiliary electricity consuming equipment

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Indirect co-firing with biomass (gasifier) (IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)

• Increased capital costs • Resource availability • Reduction in efficiency • Boiler retrofitting • Additional space required for biomass logistics • Tailoring flue gas cleaning equipment • Sustainably sourcing biomass

Parallel co-firing (separate biomass boiler) (IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)


Co-firing with municipal solid waste

• Proximity to landfill waste site • Reduction in efficiency • Resource availability • Fuel handling mechanism • Boiler retrofitting • Fouling and corrosion risk • Increased operating/maintenance costs • Regulatory issues for waste

Co-firing with landfill gas

• Proximity to landfill waste site • Reduction in efficiency • Resource availability • Retrofit boiler feed system • Regulatory issues for waste

Co-firing with biogas

• Reduction in efficiency • Resource availability • Technical risk in conversion • Retrofit boiler feed system • Tailoring flue gas cleaning equipment • Sustainably sourcing biomass

Auxiliary equipment

Solar PV to operate auxiliary equipment

• Intermittent supply • Resource availability

Wind power to operate auxiliary equipment


Electricity from biogas power plant to operate auxiliary equipment

• Resource availability • Technical risk in conversion • Sustainably sourcing biomass

Electricity from landfill gas power plant to operate auxiliary equipment

• Resource availability • Proximity to landfill waste site • Technical risk in conversion • Regulatory issues for waste

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1.4.1.2 Technical characteristics of open cycle gas turbine (OCGT) power plants South Africa currently has four direct fired OCGT power plants which are used to provide peaking power. An OCGT plant operates by fuel being pumped into a combustion chamber where it combusts with pressurised air. The combustion reaction produces a gas temperature of between 1000 – 1350°C (EPRI, 2015), at high pressures, which drives the turbine. In turn, the turbine drives an alternator to generate electricity. Table 1-4: Technical characteristic of an OCGT power plant

Technology Energy service Energy carrier Service characteristics Process

conditions OCGT power plant

Electricity production Kerosene Direct fired supply of heat 1 000 - 1 350°C

OCGT power plant

Electricity production Diesel Direct fired supply of heat 1 000 - 1 350°C

The major components of an OCGT power plant are the compressor, the combustion chamber, the turbine and the generator. OCGT plants can have different setups where some may have intercooling or preheating built in. These additional stages could present further opportunities for hybridisation of an OCGT plant. The basic representation of an OCGT plant with these stages are represented in Figure 1-21 and Figure 1-22. The potential areas for hybridisation are marked (with black dashed boxes), these include the fuel component, as well as the preheating or intercooling areas.

Figure 1-21: Basic representation of an OCGT plant with preheating 4

4 http://www.massengineers.com/Documents/gasturbinetheory.htm

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Figure 1-22: Basic representation of an OCGT plant with intercooler 5

1.4.1.2.1 Renewable energy hybridisation options for open cycle gas turbine power plants Renewable energy hybridisation in a direct fired OCGT power plant exists only within the fuel source used. Currently in South Africa diesel and kerosene fossil fuels are used to power the system. Thus, co-firing the fuel source with a renewable energy source will provide hybridisation of a fossil fuel OCGT power plant. The renewable energy hybridisation potential is summarised below in Table 1-3 below. Table 1-5: Renewable energy hybridisation potential of an OCGT power plant


OCGT power plant

Co-firing with biodiesel • Resource availability • Higher fuel costs • Sustainably sourcing biomass

Co-firing with biogas • Resource availability • Temperature requirements • Sustainably sourcing biomass

Co-firing with landfill gas

• Proximity of landfill and associated costs with logistics

• Temperature requirement • Regulatory issues for waste

Preheating air from compressor (to 1000°C) with solar CSP collectors before entering the combustion chamber (Okoroigwe and Madhlopa. 2015)

• Plant retrofit • Resource availability and seasonal variation of

solar irradiance. - areas with average direct normal irradiation (DNI) above 7.0 kWh/m2/day are suitable (Okoroigwe and Madhlopa. 2015)

• Capital costs

Intercooling between compressors with solar CSP collectors coupled with absorption chillers

• Plant retrofit • Resource availability and seasonal variation of

solar irradiance. - areas with average direct normal irradiation (DNI) above 7.0

5 http://www.massengineers.com/Documents/gasturbinetheory.htm

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kWh/m2/day are suitable (Okoroigwe and Madhlopa. 2015)

• Capital costs Co-firing with hydrogen gas (where hydrogen gas was produced by water splitting with solar power) (Okoroigwe and Madhlopa. 2015)

• Resource availability

1.4.2 Oil Refineries South Africa has a total of four oil refineries with a combined nameplate capacity of 508 000 barrels per day. Three of the refineries are located on the coast and one inland. Available capacity is lower than design capacity, with some of the contributing factors being planned and unplanned shutdowns and ageing of refineries. The crude oil transformed by the refineries in the country amounted to around 163 million barrels, this is equivalent to 963 PJ, which is used to produce 944 PJ of petroleum products (Department of Energy, 2014a). The oil refining process is an efficient process, producing significantly less GHG emissions when compared with the liquefaction process of coal and gas to petroleum products. Emissions from the Petroleum refining industry in South Africa amount to approximately 2.2 MtCO2e annually as per the South African 2010 GHG Inventory (Department of Environmental Affairs, 2014a). A summary of the South Africa oil refineries are presented in Table 1-6 below, with an indication of the capacity and estimated GHG emission per plant. Table 1-6: Existing oil refineries in South Africa with estimated GHG emissions (SAPIA, 2014)

Refinery Fuel Type Owners Location Capacity (barrels/day)

GHG emissions (MtCO2e/yr)6

Sapref Crude Oil BP & Shell Durban 180 000 0.78 Enref Crude Oil Engen Durban 120 000 0.52 Chevref Crude Oil Chevron Cape Town 100 000 0.43 Natref Crude Oil Sasol & Total Sasolburg 108 000 0.47 TOTAL

508 000 2.2

There are various components to an oil refinery which have the potential for renewable energy hybridisation. In order to assess hybridisation opportunities the specific technical characteristic of these components need to be analysed. These technical characteristics are provided in Table 1-7 below.

6 South Africa’s GHG Inventory for 2010 (Department of Environmental Affairs, 2014a) gives GHG emissions from oil refineries to be 2.2

MtCO2e, this has been pro-rated to each oil refinery based on its production capacity.

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Table 1-7: Technical characteristic of an oil refinery

Technology Energy service Energy carrier Service characteristics

Process conditions

Heat for distillation

Heat to drive distillation process

Intermediate process streams from processing of crude oil used as fuel source

Indirect fired heating 60⁰C to 200⁰C

Reactors - Reformers - Isomerisation - Hydrocracker

Heat to drive endothermic reactions in reactors

Intermediate process streams from processing of crude oil used as fuel source

Indirect fired heating 60⁰C to 200⁰C

1.4.2.1 Renewable energy hybridisation options for oil refineries Hybridisation of the fossil fuel value chains with renewable energy in the oil refining process, can take place in two areas. These include hybridisation of the technologies which are used for the production of heat and steam for the distillation process, as well as in the operating of the auxiliary equipment on the plant. Table 1-8: Renewable energy hybridisation potential of an oil refinery


Heat for distillation

• Heat from solar CSP plant to augment heat for distillation

• Resource availability • Retrofitting

• Co-firing with biomass, liquid biofuels or biogas

• Resource availability • Retrofitting fuel handling • Temperature requirements • Sustainably sourcing biomass

Reactors

• Heat from solar CSP plant to augment heat for reactors

• Resource availability • Retrofitting

• Co-firing with biomass, liquid biofuels or biogas

• Resource availability • Retrofitting fuel handling • Temperature requirements • Sustainably sourcing biomass

Auxiliary equipment

• Solar PV to operate auxiliary equipment


• Wind power to operate auxiliary equipment


• Electricity from biomass, liquid biofuels or biogas power plant to operate auxiliary equipment


• Electricity from landfill gas power plant to operate auxiliary equipment


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1.4.3 Liquefaction plants The majority of South Africa’s liquid fuel requirements are imported in the form of crude oil. South Africa has one coal-to-liquids liquefaction plant, owned by Sasol, which produces approximately 30% of the country’s liquid fuel requirements. South Africa also has a gas-to-liquids liquefaction plant, owned by PetroSA, which supplies around 7% of the country’s liquid fuel requirements, (Department of Energy, 2009). The South African energy balance for 2014 estimated that 868 PJ (43 million tonnes) of coal and 85 PJ (2,500 Mm3) of gas were consumed in the liquefaction process, Figure 1-23. From these processes 321 PJ (54 million barrels) of crude oil were produced. The liquefaction processes are energy intensive and can pose significant potential for renewable energy hybridisation opportunities and thus GHG emission mitigation actions.

Figure 1-23: Energy consumed by liquefaction plants in South Africa (Department of Energy, 2014a)

A summary of the country’s liquefaction plants is provided in Table 1-9 below. Here the capacities of the plants are indicated along with an estimation of the emissions from these plants. Table 1-9: Liquefaction plants in South Africa (SAPIA, 2014)

Liquefaction plant Type Owners Location Capacity

(bbl/day) GHG emissions (MtCO2e/yr)7

Sasol Synfuels (Coal-to-liquid) Sasol Secunda 150 000 45.2

PetroSA Synfuels (Gas-to-liquid) State owned Mossel Bay 45 000 13.6 TOTAL 195 000 58.8

7 The Department of Energy’s Energy Balance for 2014 was used to determine the energy consumed during the liquefaction processes in the

country. The emissions were estimated using an emission factor for coal of 55.6 tCO2e/TJ and for gas of 56.1 tCO2e/TJ (IPCC, 2006), and pro-rated to each oil refinery based on its production capacity.

868 PJ Coal91%

85 PJ Gas9%

31

There are various components to a liquefaction plant which have the potential for renewable energy hybridisation. In order to assess hybridisation opportunities the specific technical characteristic of these components are needed to be analysed. These technical characteristics are provided in Table 1-10 below. Table 1-10: Technical characteristics of liquefaction plant components

Technology Energy carrier Energy service characteristics Process conditions

Gasifier Coal To provide endothermic heat of reaction to produce syngas

Heated internally through partial combustion of gasification feedstock

Boiler Coal Production of steam for process heating 800⁰C to 1,400⁰C

Gas synthesis Natural gas Produces syngas

Heat produced by partial combustion of gas. The temperature depends on the process

Fischer-Tropsch process Syngas Produces liquid hydrocarbons

Heat produced by partial combustion of syngas. The temperature depends on the process.

Air separation plant (Air compressors and chillers)

Electricity Cooling for liquefaction of air -170°C to -200°C

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1.4.3.1 Renewable energy hybridisation options for liquefaction plants Hybridisation of fossil fuel value chains with renewable energy in liquefaction plants, can take place on the gasifier, boiler, air separation plant and on the auxiliary equipment. These hybridisation options are presented in Table 1-11. Table 1-11: Renewable energy hybridisation potential of a liquefaction plant


Gasifier • Co-gasify with biomass

• Resource availability • Logistics related to the transport of biomass to

site • Additional equipment requirements • Retrofitting • Sustainably sourcing biomass

Boiler

• Heat from concentrated solar power (CSP) to boost steam production


• Direct co-firing with woody biomass (European Bioenergy Network. 2003. IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)


• Indirect co-firing with biomass (gasifier) (IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)


• Parallel co-firing (separate biomass boiler) (IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)


• Co-firing with municipal solid waste


• Co-firing with landfill gas

• Proximity to landfill waste site • Reduction in efficiency • Resource availability • Retrofit boiler feed system

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• Regulatory issues for waste

• Co-firing with biogas


• Heat from concentrated solar power (CSP) to boost steam production


• Direct co-firing with woody biomass (European Bioenergy Network. 2003. IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)


• Indirect co-firing with biomass (gasifier) (IEA-ETSAP and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)


Gas synthesis • Solar energy can be added to

displace partial combustion of feedstock

• Cost of solar collectors and related equipment • Additional complexity

Fischer-Tropsch process

• Solar energy can be added to displace partial combustion of feedstock

• Cost of solar collectors and related equipment • Additional complexity

Air separation plant (compressors and chillers)

• Solar PV to operate cooling • Intermittent supply • Resource availability

Auxiliary equipment

• Solar PV to operate auxiliary equipment


• Wind power to operate auxiliary equipment


• Electricity from biogas power plant to operate auxiliary equipment


• Electricity from landfill gas power plant to operate auxiliary equipment


34

1.5 Fossil fuel energy demand sectors and technologies

The South African economy can be grouped into five broad energy demand sectors. These sectors are categorised as: industry (including mining), transport, agriculture, commerce and public services, and residential. The portion of energy consumption of each of these sectors is displayed below in Figure 1-24. The industrial sector has the largest share of energy consumption, accounting for around 39%. This is followed by the transport sector consuming around 35%. The residential sector accounts for around 9%, commerce and public services for 7%, agriculture for 3% and the non-energy use accounts for 2%, where the energy is converted into products such as chemicals.

Figure 1-24: South Africa's Demand Sectors energy consumption (Department of Energy, 2014a)

In the following sections, energy demand services/technologies per sector are discussed. The most common technologies for the provision of such services are identified; together with their most common working parameters, and an indication of their hybridisation potential. The analysis is done in the context of hybridisable technologies and options. The most common of these technologies across all energy consuming sectors includes the generation of heat for processing, industrial cooling and refrigeration (this includes HVAC), and energy for mechanical (motor) driven systems such as auxiliary equipment.

895 PJIndustry Sector

39%

799 PJTransport Sector

35%

76 PJAgriculture

3%

158 PJCommerce and Public

Services7%

214 PJResidential

9%

114 PJNon-specified (Other)

5%

38 PJNon-Energy Use

2%

35

1.5.1 Industrial sector Although South Africa ranks thirty-second in terms of GDP (World Bank, 2015), the country is the sixteenth highest energy consumer globally (World Bank, 2013). The country’s high-energy intensity is due mostly to an economy dominated by large scale, energy intensive primary minerals extraction and beneficiation industries. The industrial sector has an estimated annual energy consumption of 895 PJ. Energy for industries is provided in the form of electricity (45%), coal (37%), gas (11%) and petroleum products (7%).

Figure 1-25: Source of energy for the South African industrial sector (Department of Energy, 2014a)

Worldwide, three quarters of the industrial energy use is related to the production of energy-intensive commodities such as ferrous and non-ferrous metals, chemicals and non-metallic mineral materials (UNIDO, 2010). The South African scenario doesn’t deviate much from the global scenario. Iron and Steel is the highest energy consuming subsector, utilizing 20% of the energy consumed by the industrial sector. It is followed by Mining and Quarrying with 18%, the Chemical and Petrochemical subsector (16%) and the non-ferrous metals sector (9%). The remaining of the industrial energy consumption is comprised of a mix of different industries such as: Food and tobacco, paper and pulp, construction, machinery, textiles, wood and wood products, transport equipment, and others (Figure 1-26).

36

Figure 1-26: Energy demand for the industrial sector (Department of Energy, 2014a) Energy related emissions from the industry sector in South Africa (including mining) amount to around 459 MtCO2e per year as per the South African 2010 GHG Inventory (Department of Environmental Affairs, 2014a). Within the South African industry, energy is required to provide various services. These services include process heating, industrial cooling and refrigeration, to drive power-motor systems, ventilation and air conditioning and other auxiliary services such as lighting or water heating. A representation of the energy end use in the industrial sector is presented in Figure 1-27. This break down excludes mining, which will be discussed in a separated section, due to the differences in the source of energy and technologies.

242 PJNon-specified (Industry)

27%

180 PJIron and Steel

20%164 PJMining and Quarrying

18%

147 PJChemical and Petrochemical

16%

77 PJNon-Ferrous

Metals9%

58 PJNon-Metallic Minerals

7%

9 PJPaper Pulp and Print

1%

7 PJFood and Tobacco

1%

6 PJConstruction

1%

2 PJMachinery

<1%

1 PJWood and Wood

Products<1% 0.8 PJ

Transport Equipment<1%

0.5 PJTextile and Leather

<1%

37

Figure 1-27: Energy end use in the industry sector (Department of Energy, 2016a)

When looking at electricity consumption in the industry sector, the greatest amount of electricity is used by the Iron and Steel industry for process heating. Additional large users of electricity for process heating include other manufacturing industries and the non-ferrous metals production (i.e. aluminium smelting). Other important consumers of electricity are the coal mining industry, material handling during the gold mining production, the running of pumping systems and compressors (see Table 1-12). Table 1-12: End use electricity consumption in the industry sector (Department of Energy, 2016a)

38

A more detailed description of the energy demanding technologies and services provided is presented below for the main types of energy activity. The main energy activities in the industrial sector include: process heating, industrial cooling and refrigeration, HVAC, and motor driven systems. 1.5.1.1 Process Heating Process heating involves the provision of thermal energy to facilitate a temperature dependent chemical or physical reaction of one or more materials. The most common process heating technologies include steam generation systems, boilers, furnaces and kilns, cooking ovens or heating chambers. Low (<150°C) and medium temperature (150-400°C) applications are typically supplied via steam, while high temperature applications (>400°C) are usually provided in the form of direct heat. In order to assess the renewable energy hybridisation potential of these technologies a description of the technologies used for process heating, the most common energy carrier and the characteristics and conditions for operation are presented in Table 1-13. Table 1-13: Technical characteristics of process heating technologies

Technology Energy carrier Service characteristics Process conditions

Electric steam system Electricity

Steam used as energy carrier for large variety of applications

200°C 12bar steam Direct fired steam

system

Coal

Oil

Gas Electric Furnaces

- Induction furnace - Resistance heating - Submerged arc

furnace - Molten glass - Annealing chamber

Electricity Electric heating

400-1400°C 3 phase electricity 380V

Direct fired furnaces - Blast furnace - Basic oxygen furnace - Reverberating

furnace - Molten glass - Annealing chamber

Coal or coke

Direct fired heating 400-1700°C

Direct fired furnaces Oil Direct fired furnaces

- Molten glass Gas

Electrolysis cells - Aluminium

production - Chlor-alkali

production - Metal plating

Electricity

Heat Electrolytic process needs 5V direct current. Aluminium production needs 5-6V, 100 000 Amps.

The heating effect of the large currents keeps the cells temperature >1000°C.

Direct fired kiln - Cement Coal Direct fired heating 1000 - 1400°C

39

Technology Energy carrier Service characteristics Process conditions - Lime - Rotary dryers

Coking Oven Coal

The coking battery generates its own heat through the partial combustion of the coal fed into the oven.

1000 - 1400°C

Heating chambers

Electricity Resistance heating of chambers with electricity

60-160°C Coal

Direct fired heating of chambers Paraffin

Gas

1.5.1.1.1 Renewable energy hybridisation options for process heating technologies Renewable energy could be widely applied in industrial applications for process heating. Some of the most promising alternatives include biomass, solar thermal systems for process heat, and heat pumps. A summary of the hybridisation potential for the above technologies is provided in Table 1-14. Substitution or augmentation of thermal systems with renewable energy requires the concentration of the renewable energy resource to increase the energy density. For biomass the energy density is 13-18MJ/kg (dry basis) whereas coal has a calorific value between 15 and 28 MJ/kg (local low grade coal for electricity production and export coal). The conversion of biomass to charcoal is one method. Solar energy needs to be concentrated by several orders of magnitude to provide a sufficiently concentrated energy source, requiring space for solar collectors. Table 1-14: Renewable energy hybridisation potential for processing heating technologies

Technology Renewable energy hybridisation potential

Factors to consider

Electric steam system

Solar PV energy used for water preheating • Resource availability

Solar PV or wind energy for electricity generation

• Resource availability • Intermittent nature

Concentrated solar collectors for heat production

• Resource availability • Intermittent nature

40


Factors to consider

Direct fired steam system (coal)

Direct co-firing with biomass (NREL, n.a.)

• Resource availability and transport • Reduction in efficiency • Fuel handling mechanism • Slagging, fouling and corrosion risk • May require separated injection systems • Additional space for biomass processing (i.e. resizing)

and storage • Increase of over-fire air and fuel feeder speeds • Tailoring flue gas cleaning equipment • Reuse or disposal of ash • Sustainably sourcing biomass


• Gasification technologies not yet in maturity state • Resource availability and transport • Reduction in efficiency • Adjustment of the combustor to handle increased

volumetric throughput of lower energy content gas • Flame stability risk • Corrosion and clogging risk • May require a parallel burner for the biogas • Modifications of gas feed pressure, and gas/air ratio • Backup biomass storage • Tailoring flue gas cleaning equipment • Sustainably sourcing biomass


• Increased capital costs • Resource availability and transport • Reduction in efficiency • Retrofitting • Additional space required for biomass logistics • Tailoring flue gas cleaning equipment • Sustainably sourcing biomass

Direct fired steam system (oil/diesel)

Co-firing with biofuels (Makaire et al, 2011)

• Slightly lower efficiency • Resource availability • Corrosion risk • Viscosity of the biofuel • Additional storage of fuel and additional need for oil

heaters • Burner adjusting and changes in fuel injection pressure • Sustainably sourcing biomass

Direct fired steam system (gas)

Co-firing with biogas (Krich et al, 2005)

• Modification of carburettor • Flame stability risk • Increase of maintenance • May require a parallel burner for the biogas • Modifications of gas feed pressure, and gas/air ratio • Backup biogas storage • Sustainably sourcing biomass

Electric Furnaces

Solar PV/wind energy for electricity generation

• Resource availability • Space availability for solar/wind energy installations • Investment in energy storage equipment • Control systems switch between grid and renewable

power

41


Factors to consider

Combined heat and power plant (CHP) for electricity generation using bio and fossil fuel

• Technology in early stages of implementation • Increased capital cost • Modification to heat cycle within the process • Sustainably sourcing biomass

Direct fired furnaces (coal/coke)

Substitution of coal blend by biofuel (bio-coke) (NRCAN, 2016)

• Fuel handling mechanism • Resource availability and economics. • Suitable for small scale blast furnaces. • It does not have the same mechanical stability as coke. • Sustainably sourcing biomass

Iron ore reduction with hydrogen • Early stages of technology

Direct fired furnaces (oil)

Co-firing with biodiesel

• Resource availability • Reduction in efficiency • Adjustment of the combustor to handle increased

volumetric throughput of lower energy content fuel • Flame stability risk • Corrosion and clogging risk • Tailoring flue gas cleaning equipment • Sustainably sourcing biomass

Direct fired furnaces (gas)

Co-firing with biogas (Krich et al, 2005)

• Modification of carburettor • Flame stability risk • Increase of maintenance • May require a parallel burner for the biogas • Modifications of gas feed pressure, and gas/air ratio • Backup biogas storage • Sustainably sourcing biomass

Electrolysis cells

Solar/wind energy to provide electricity for electro-winning

• Resource availability • Investment in energy storage equipment

Direct fired kiln Co-firing with biomass

• Resource availability • Pre-treatment and surveillance of biomass. • Potential impacts on air pollutants’ emissions • Sustainably sourcing biomass

Coking Oven No renewable energy potential n/a

Heating chambers

Co-firing with biomass

• Resource availability • Pre-treatment and surveillance of biomass. • Sustainably sourcing biomass

1.5.1.2 Industrial cooling and refrigeration Some industrial processes require cooling. The most common applications for cooling requirements include air conditioning, refrigerators and freezers. These are typically electricity driven which in South Africa is fossil fuel based. Thus assessing the technologies which provide cooling can allow for the potential for hybridisation of such equipment to be carried out. The technical characteristics of the industrial cooling and refrigeration systems are provided in Table 1-15.

42

Table 1-15: Technical characteristics of industrial cooling and refrigeration technologies


Refrigerators, chillers and cooling chambers Electricity Fresh produce cooling

chambers 5 to 0°C

Freezers Electricity Frozen food storage -15°C to -30°C

Air conditioning Electricity Evaporative cooler Ambient temperature to 15°C

1.5.1.2.1 Renewable energy hybridisation options for industrial cooling and refrigeration technologies

Renewable energy hybridisation of industrial cooling and refrigeration systems can be carried out by hybridising the electricity supply. The hybridisation options for such systems are provided in Table 1-16. Table 1-16: Renewable energy hybridisation potential for industrial cooling and refrigeration technologies


• Refrigerators, chillers and cooling chambers

• Freezers • Air conditioning

Hybridise the electricity supply with renewable energies (solar PV, wind, biomass, etc.)

• Intermittent supply • Resource availability • Sustainably sourcing biomass

Concentrated solar powered absorption chillers

• Limited usage for steady cooling requirements • Intermittent absorption cycle behaviour • Dependence on environmental parameters • Decreased efficiency • Equipment retrofitting • Additional control systems • Maintenance of a cooling tower

Biomass powered absorption chillers

• Resource availability • Dependence on ambient conditions • Decreased efficiency • Equipment retrofitting • Additional control systems • Maintenance of a cooling tower • Sustainably sourcing biomass

Pre-cooling of the feed to a conventional chiller with a solar powered absorption chiller

• Dependence on ambient conditions • Decrease efficiency • Equipment retrofitting • Additional control systems

Mechanical power from wind or micro hydro

• Equipment retrofitting • Space availability • Resource availability

43

1.5.1.3 Mechanical power/Motor driven systems Numerous industrial processes require motor driven appliances such as compressors, pumps, conveyors for the plants operation. This type of equipment is usually the auxiliary equipment which is used for an industrial plant operation. Such equipment is most commonly powered by grid electricity. An analysis of the motor driven equipment technology is provided in Table 1-17. Table 1-17: Technical characteristics of motor driven systems equipment


Auxiliary equipment - Compressors - Pumps - Conveyor belts - Fans

Electricity Motor powered equipment 50 Hz, 380 Volts

1.5.1.3.1 Renewable energy hybridisation options for motor driven system technologies Because the auxiliary equipment is run with electricity, the hybridisation options consist of mainly electricity generation from renewable sources such as solar PV, wind or biomass. These hybridisation options are summarised in Table 1-18. Table 1-18: Renewable energy hybridisation potential for motor driven system technologies


Auxiliary equipment - Compressors - Pumps - Conveyor belts.

Solar PV/ wind/biomass generated electricity to operate auxiliary equipment

• Intermittent supply • Resource availability • Retrofit of equipment • Capital investment • Sustainably sourcing biomass

Electricity from biogas power plant to operate auxiliary equipment

• Resource availability • Technical risk in conversion • Retrofit of equipment • Capital investment • Sustainably sourcing biomass

Mechanical power from windmills or water turbines


44

1.5.2 Mining sector The South African mining sector consumes around 164 PJ of energy annually (Department of Energy, 2014a). It is reliant mostly on electricity (for 64% of its energy supply, equivalent to 30 GWh) and petroleum products (for 36% of its energy supply, equivalent to 1500 Ml). The most common petroleum product used in the mining industry is diesel. Smaller portions of coal and gas are also consumed. Refer to Figure 1-31 for the energy consumption breakdown in the mining sector.

Figure 1-28: Energy consumption within the mining sector of South Africa (Department of Energy, 2014a)

The focal areas for mining are extraction (mainly petroleum and electricity driven), material handling (mainly driven by petroleum products) and beneficiation (where energy source is dependent on the process). Electricity is used to primarily power electric motor driven systems for the mining process. These include pumps (9.23% of total energy use in the mining sector), compressors (10.73%), chillers and fans to provide deep mine cooling (8.82%) and some continuous materials transporting equipment (conveyors and slurry lines), (Department of Energy, 2016a). Other processes, including crushers, grinding and separation equipment accounts for around 12.85% of the energy use in the mining sector. Petroleum products are used predominantly for the transport of ore and waste materials from the mining pits to the processing plants. Materials handling, which includes both diesel fuel transport in trucks and the transport with electrical equipment accounts to around 26% of the energy consumption in the mining sector, (Department of Energy, 2016a).

45

In order to assess the potential for hybridisation in the mining sector, an understanding of the technical characteristics of the fossil fuel consuming equipment used in the mining sector is required, as is provided in Table 1-19. Table 1-19: Technical characteristics of mining sector technologies


Compressors Electricity Compressed air as a source of power for drilling, digging and loading 6 – 8 Bar

Power motor driven systems • Pumps • Chillers • Fans • Auxiliary

equipment

Electricity

• Pumps used for the dewatering of mining pits or transporting of water;

• Chillers used to provide cooling underground and in buildings

• Fans used for ventilation underground

• Processing systems used for conveyor belts, slurry lines, crushers and grinders

3 phase, 50Hz, 380 - 520V 8

Trucks Diesel Ore and waste materials transportation Consumed in internal combustion engine.

1.5.2.1 Renewable energy hybridisation options for the mining sector technologies Hybridisation of the fossil fuel value chains with renewable energy in the mining sector can be carried out on the vehicles operating on petroleum products, as well as to the compressors and to all electric motor driven equipment. The renewable energy hybridisation options are presented in Table 1-20. Table 1-20: Renewable energy hybridisation potential for mining sector technologies


Compressors Solar PV powered compressor • Intermittent supply • Resource availability

Compressors Hydro powered equipment (high pressure water generated by gravity in mine)

• Change in technology • High maintenance costs

Power motor driven systems • Pumps • Chillers • Fans • Auxiliary

equipment

Hybridise with hydropower (where electricity is generated by turbines powered by the water flowing down mine shaft to underground)


Hybridise electricity supply to the mine with solar PV (Dougherty, 2017)


Hybridise electricity supply to the mine with solar CSP including an energy storage component (Dougherty, 2017)

• Resource availability

Hybridise electricity supply to the mine with wind power


8 Note that large underground mines in South Africa run on 520 Volts

46


Hybridise electricity supply to the mine with biogas power plant


Hybridise electricity supply to the mine with landfill gas power plant


Direct driven pumps, or fans with mechanical power from windmills


Trucks

Blending of diesel with 1st generation biodiesel (B5) (Department of Environmental Affairs, 2014b)

• Resource availability • Impact on vehicle efficiency • Sustainably sourcing biomass • Engine warranty

Blending of diesel with 2nd generation biodiesel (B50) (Department of Environmental Affairs, 2014b)

• Resource availability • Impact on vehicle efficiency • Sustainably sourcing biomass • Engine warranty

Dual fuel supply, where truck is powered by petroleum product and with biogas

• Retrofitting • Resource availability • Impact on vehicle efficiency • Sustainably sourcing biomass • Engine warranty

Hybrid diesel electric vehicle (where the electricity is generated by a renewable energy source, e.g. wind, solar, biogas etc.)

• Retrofitting • Resource availability • Sustainably sourcing biomass

Power the air-conditioning system of the truck with a renewable energy based fuel, such as biogas or solar

• Retrofitting • Resource availability • Sustainably sourcing biomass

47

1.5.3 Transport sector The transport sector in South Africa is heavily reliant on fossil fuel based petroleum products, 98% of the transport sectors energy source. A small portion of electricity is consumed in the sector, 2%, along with an even smaller portion of coal, <1% (Department of Energy, 2014a). On an annual basis the transport sector consumes around 799 PJ of energy, typically sourced from 20,000 Ml of petroleum products, 3.6 GWh of electricity and 22,000 tonnes of coal, (Department of Energy, 2014a). The majority of the energy is consumed in road transportation (88%), refer to Figure 1-29, international civil aviation consumes around 8% of the sectors energy, with domestic air transport consuming 2% and rail transport consuming around 2% of the energy. If hybridisation within road transportation is possible, this could have a significant reduction in the GHG emissions from the transport sector in South Africa.

Figure 1-29: Energy consumption within the transport sector, (Department of Energy, 2014a)

Marine engines for domestic navigation are run by diesel and HFO, however, the proportion of energy consumption is significantly smaller than the categories mentioned above. The South African energy balance for 2014 did not include domestic navigation in its assessment. However from the national energy balance for 2012 domestic navigation consumes 1.5 PJ, or approximately 38 Ml of petroleum products (Department of Energy, 2012). The dominant fuel used in the transport sector is petrol, amounting to 52% of the energy resources used. Diesel is the second most dominant fuel used, accounting for 36%, with jet fuel accounting for 10% and electricity only 2%, Figure 1-30.

702 PJRoad88%

64 PJInternational Civil

Aviation8%

16 PJDomestic Air

Transport2%

16 PJRail2%

1 PJNon-specified

(Transport)<1%

0.3 PJPipeline Transport

<1%

48

Figure 1-30: Transport sector end use (Department of Energy, 2016a)

The transport sector accounts for around 11% of the national GHG emission inventory, as presented in Figure 1-3. This amounts to around 47.6 MtCO2e emitted annually as per the South African 2010 GHG Inventory (Department of Environmental Affairs, 2014a). In order to assess the potential for hybridisation in the transport sector, an understanding of the technical characteristics of the fossil fuel consuming transportation modes used in the country is required, Table 1-21. Table 1-21: Technical characteristics of transportation modes used in the transport sector

Transportation mode Energy carrier Energy service

characteristics

Emissions from this transportation mode (Department of Environmental Affairs, 2014a)

Road Diesel or petrol Transportation of people 43.4 MtCO2e

Rail Electricity Transportation of goods or people 0.5 MtCO2e

Diesel Transportation of goods Aviation Jet fuel Transportation of people 3.6 MtCO2e Navigation Diesel or HFO Transportation of goods Non specified

49

1.5.3.1 Renewable energy hybridisation options for the transport sector Hybridisation of fossil fuel transportation modes with renewable energy typically includes fuel blending opportunities, dual-fuel opportunities and diesel-electric hybrid vehicles. The renewable energy hybridisation options are presented in Table 1-22. Table 1-22: Renewable energy hybridisation potential for the transport sector

Transportation mode

Renewable energy hybridisation potential Factors to consider

Road - diesel

Fuel blending with biodiesel (Department of Environmental Affairs, 2014b)

• Resource availability • Efficiency of vehicle • Sustainably sourcing biomass • Engine warranty

Dual-fuel with biogas (Department of Environmental Affairs, 2014b)

• Retrofitting • Resource availability • Efficiency of vehicle • Sustainably sourcing biomass • Engine warranty

Dual-fuel with landfill gas

• Retrofitting • Resource availability • Efficiency of vehicle • Regulatory issues for waste • Engine warranty

Hybrid renewable electric – diesel vehicle • Retrofitting • Resource availability • Infrastructure

Road - petrol Bioethanol blending

• This may not reduce overall emissions as the short chain hydrocarbons removed from the blending have to be burnt elsewhere in the country as a fuel

• Sustainably sourcing biomass • Engine warranty

Rail - coal Co-firing with biomass • Resource availability • Efficiency • Sustainably sourcing biomass

Rail - diesel

Biofuels blending (Department of Environmental Affairs, 2014b)

• Resource availability • Efficiency • Engine warranty

Hybrid diesel electric, where electricity is renewable energy powered (Department of Environmental Affairs, 2014b)

• Retrofitting • Resource availability • Infrastructure • Sustainably sourcing biomass • Engine warranty

Biogas dual-fuel (Department of Environmental Affairs, 2014b)


Rail – Electric Solar PV powered trains • Resource availability • Intermittent supply

Aviation – jet fuel

Biofuel blending (Department of Environmental Affairs, 2014b)

• Resource availability • Efficiency

50

Transportation mode

Renewable energy hybridisation potential Factors to consider

• Sustainably sourcing biomass

Navigation - diesel

Biofuels blending (Department of Environmental Affairs, 2014b)

• Resource availability • Efficiency • Sustainably sourcing biomass • Engine warranty

Hybrid diesel electric, where electricity is renewable energy powered (Department of Environmental Affairs, 2014b)

• Retrofitting • Resource availability • Infrastructure


• Retrofitting • Resource availability • Sustainably sourcing biomass • Efficiency of vehicle • Engine warranty

51

1.5.4 Agriculture sector The agricultural sector in South Africa is also reliant predominantly on fossil fuels. On average the agricultural sector consumed around 75PJ of energy each year, (Department of Energy, 2014a). Of this energy consumption, 68% constitutes petroleum products (1,300 Ml) and 31% constitutes electricity consumption (6.3 GWh). Only a small portion of coal is used, approximately 1% of the total energy consumption.

Figure 1-31: Energy consumption within the agriculture sector, (Department of Energy, 2014a)

The large consumption of petroleum products (predominantly diesel) is used for traction and other farming machinery as well as for the transportation of produce. Traction accounts for the majority of the energy use in the agricultural sector, accounting for around 67% of the energy end use (Department of Energy, 2016a). The majority of the remaining energy end use is in the form of electricity to provide, irrigation, materials handling, process heating, industrial cooling and lighting, etc., Figure 1-32.

Figure 1-32: Energy end use in Agriculture sector (Department of Energy, 2016a)

0.6 PJCoal1%

51 PJPetroleum Products

68%

23 PJElectricity

31%

52

The agriculture sector contributes around 3.3 MtCO2e of GHG emissions to South Africa’s overall energy related emissions (Department of Environmental Affairs, 2014a). In order to assess hybridisation potentials in the agricultural sector an analysis of the technology types and their energy carriers are carried out in Figure 1-28. Table 1-23: Technical characteristics of technologies in the agriculture sector

Technology Energy carrier Energy service characteristics

Tractors Diesel Traction

Trucks Diesel Transportation of produce

Power motor driven equipment Electricity

• Auxiliary equipment o Post harvesting processing o Material handling o Lighting o Geysers

Pumps Electricity Pumps to provide irrigation and water supply

Heating and cooling technology Electricity • Heating technology for heating

• Chillers for cooling 1.5.4.1 Renewable energy hybridisation options for the agriculture sector The hybridisation potential within the agriculture sector exists in the diesel consuming transportation equipment (trucks and tractors) as well as in the electricity consuming equipment, which provides for cooling and heating requirements as well as other auxiliary equipment such as pumps, lighting, materials handling etc. These hybridisation opportunities are presented in Table 1-24. Table 1-24: Renewable energy hybridisation potential for the agriculture sector


Tractors Biodiesel fuel blending (Department of Environmental Affairs, 2014b)


Trucks

Biodiesel fuel blending (Department of Environmental Affairs, 2014b)




Hybrid renewable electric – diesel vehicle • Retrofitting • Resource availability

53


• Infrastructure

Heating, drying and cooling equipment for produce processing

Biogas digester to produce heat for heating or cooling (with absorption chiller)

• Resource availability • Sustainably sourcing biomass

Solar or biogas-powered cold storage, refrigeration, cooling and chilling (SEED, 2016)

• Intermittent supply • Resource availability • Sustainably sourcing biomass

Solar thermal energy for drying of produce or greenhouse heating (Chel, 2011) (SEED, 2016)


Combined heat and power plants fed with biogas (Chel, 2011)


Biomass co-fired boilers (Chel, 2011) • Resource availability • Sustainably sourcing biomass

Pumps

Solar or wind-powered pumping and irrigation (SEED, 2016). • Resource availability

Mechanical power from windmills or micro hydro


Power motor driven equipment: • Post harvesting

processing • Materials

handling • Lighting • Geysers

Micro-hydro power to operate electrical equipment on farm • Capital intensive

Solar PV to operate electrical equipment on farm

• Intermittent supply • Resource availability • Capital intensive

Wind power to operate electrical equipment on farm

• Intermittent supply • Resource availability • Capital intensive

Electricity from biogas power plant to operate electrical equipment on farm

• Resource availability • Technical risk in conversion • Capital intensive • Sustainably sourcing biomass

Solar water heaters to provide hot water to farm houses

• Capital cost • Home ownership (split

incentive barrier9) Hybridising lighting by allowing natural light ducting in farm packing houses, warehouses and storage rooms

• Retrofitting of roofs

Biomass powered milling, pressing, grinding (SEED, 2016)

• Resource availability • Retrofitting • Sustainably sourcing biomass

Mechanical power from windmills for powering milling, pressing or grinding processes


9 The split incentive barrier refers to a situation where the expense required for an intervention/conversion is split from the person getting the

benefit. An example is when the owner of the house has to pay the cost of solar water heaters, but the tenant gets the benefit

54

1.5.5 Commerce and public services sector The commerce and public services sector in South Africa consumes around 158 PJ of energy on an annual basis. The sector relies heavily on grid electricity, 85% of total energy consumed (37.5 GWh). Smaller portions of coal, petroleum products and gas are also consumed (Department of Energy, 2014a). Refer to Figure 1-33 for the energy consumption breakdown in the sector.

Figure 1-33: Energy consumption within the commerce and public services sector, (Department of Energy, 2014a)

The grid electricity consumed is predominantly generated from coal sources (around 92%, see Figure 1-19). Space heating and cooling are the major consumers of electricity (accounting for 34% of total energy consumed) in the sectors, and are supplemented by gas sources. Water heating (21%) and lighting (14%) predominantly use electricity, which is used for cool storage and water pumping. Cooking accounts for 17% of the total energy consumed, and is powered predominantly by electricity and some gas. Refer to Figure 1-34 for the end use of energy in the commerce and public services sector.

Figure 1-34: Commercial and public services end use of energy (Department of Energy, 2016a)

55

The commerce sector is estimated to contribute around 17 MtCO2e to the national energy emissions in 2010 (Department of Environmental Affairs, 2014a). Electricity accounts for the largest source of GHG emission from this sector. Coal contributes a small portion and is typically used as a direct energy source for thermal purposes. The various technologies used in the commercial and public services sector are presented in Table 1-25. These technologies can be assessed for hybridisation opportunities as they are fossil fuel consumers in this sector. Table 1-25: Technical characteristics of the technologies in the commerce and public services sector


Boilers

Coal

Water heating Diesel

Oil

Geyser Electricity

Space heaters Electricity

Space heating LPG

Refrigerators Electricity Cooling

HVAC Electricity Cooling/heating

Stoves Electricity

Cooking LPG

Light bulbs Electricity Lighting

1.5.5.1 Renewable energy hybridisation options for the commerce and public services

sector The hybridisation potential within the commerce and public services sector exist with respect to the space and water heating, cooling, lighting and cooking technologies. The majority of the potential exists within the electric consuming equipment. An overview of the hybridisation opportunities within this sector are provided in Table 1-26. Table 1-26: Renewable energy hybridisation potential in the commerce and public services sector


Boilers – coal

Heat from concentrated solar power (CSP) to boost steam production


Direct co-firing with woody biomass (European Bioenergy Network. 2003. IEA-ETSAP

• Reduction in efficiency • Resource availability • Fuel handling mechanism

56


and IRENA, 2013b. IEA-ETSAP and IRENA, 2015a)

• Fouling and corrosion risk • Boiler retrofitting • Additional space required for biomass

logistics • Tailoring flue gas cleaning equipment • Sustainably sourcing biomass


• Increased capital costs • Resource availability • Reduction in efficiency • Boiler retrofitting • Additional space required for biomass



• Increased capital costs • Resource availability • Reduction in efficiency • Boiler retrofitting • Additional space required for biomass


Co-firing with waste




Boilers – diesel/oil

Co-firing with biofuels (Makaire et al, 2011)

• Slightly lower efficiency • Resource availability • Corrosion risk • Viscosity of the biofuel • Additional storage of fuel and additional

need for oil heaters • Burner adjusting and changes in fuel

injection pressure • Sustainably sourcing biomass


• Slightly lower efficiency • Resource availability • Corrosion risk • Retrofitting • Additional storage of fuel and additional

need for oil heaters • Burner adjusting and changes in fuel

injection pressure

57


• Sustainably sourcing biomass

Geyser Solar water heaters to provide hot water

• Capital cost • Split incentive barrier

Electric equipment • Space heaters • Stoves • Lights • Refrigerators

Solar PV to operate electric equipment


Wind power to operate electric equipment


Electricity from biogas power plant to operate electric equipment


Space heaters - LPG Co-firing with biogas • Reduction in efficiency • Resource availability • Sustainably sourcing biomass

Refrigerator and HVAC systems


• Limited usage for steady cooling requirements

• Intermittent absorption cycle behaviour • Dependence on environmental parameters • Decreased efficiency • Equipment retrofitting • Additional control systems • Maintenance of a cooling tower



Stoves - LPG Co-firing with biogas • Reduction in efficiency • Resource availability • Sustainably sourcing biomass

Light bulbs Hybridising lighting by allowing natural light ducting in commercial buildings

• Retrofitting

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1.5.6 Residential sector There are currently approximately 16 million households in South Africa, which is expected to increase to 19-20 million by 2030 (Department of Energy, 2016b). The residential sector in South Africa consumes around 214 PJ of energy on an annual basis. The sector relies heavily on grid electricity (accounting for around 84% of total residential energy consumed, equivalent to 49 GWh). Additional energy sources include coal, petroleum products, renewables (solar and wind) and gas (Department of Energy, 2014a). Refer to Figure 1-35 for the energy consumption breakdown in the sector.

Figure 1-35: Consumption of energy in the residential sector, (Department of Energy, 2014a)

Grid electricity (which is largely generated from coal) is the major source of energy consumed by the residential sector. Cooking is the most energy intensive activity accounting for 38% of the end use of energy in the sector, Figure 1-36. Cooking is typically powered by a combination of electricity, coal, LPG and paraffin. As per the commerce and public service sectors, space heating and cooling are also major energy consuming activities (accounting for 28% of total energy consumed), which are typically powered by electricity, LPG and gas. Water heating (21%) uses a mix of electricity and coal. Lighting, cool storage, electrical equipment, pool pump and laundry activities all typically use electricity. Refer to Figure 1-36 for the end use of energy in the residential sector.

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Figure 1-36: Energy end use in the residential sector (Department of Energy, 2016a)

The residential sector is estimated to contribute around 24.8 MtCO2e to the national energy emissions in 2010 (Department of Environmental Affairs, 2014a). Electricity used for cooking, space and water heating accounts for the largest source of GHG emissions. Additional sources of GHGs can be attributed for coal use, typically for heating purposes, followed by LPG and paraffin use. The various technologies used in the residential services sector are presented in Table 1-27. These technologies can be assessed for hybridisation opportunities as they are fossil fuel consumers in this sector. Table 1-27: Technical characteristics of technologies in the residential sector


Stoves

Electricity

Cooking Coal

LPG

Paraffin

Geysers

Electricity

Water heating LPG and natural gas

Coal

Light bulbs Electricity Lighting

Space heaters

Electricity

Space heating LPG and natural gas

Coal

HVAC Electricity Cooling/heating

Refrigerators Electricity Cooling

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1.5.6.1 Renewable energy hybridisation options for the commerce and public services sector

There are potential areas for hybridisation within the residential sector. These include hybridisation of the electrical equipment, cooking appliances, lighting, water heating, space heating and cooling and refrigeration. The potential hybridisation areas for the residential sector are covered in Table 1-28. Table 1-28: Renewable energy hybridisation potential in the residential sector


Electric equipment • Stoves • Lights • Space heaters • Refrigerators

Solar PV to operate electric equipment • Intermittent supply • Resource availability

Wind power to operate electric equipment


Electricity from biogas power plant to operate electric equipment


Stoves – Coal, paraffin, LPG

Co-firing with biomass, liquid biofuels or biogas


Geyser Solar water heaters to provide hot water • Capital cost • Split incentive barrier

Light bulbs Hybridising lighting by allowing natural light ducting in commercial buildings • Retrofitting

Refrigerator and HVAC systems


• Limited usage for steady cooling requirements

• Intermittent absorption cycle behaviour

• Dependence on environmental parameters

• Decreased efficiency • Equipment retrofitting • Additional control systems • Maintenance of a cooling tower



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1.6 Energy storage The hybridisation of fossil fuels and renewable energy in South Africa may be further enhanced through the addition of energy storage components. The International Renewable Energy Agency (IRENA, 2015a) advises that countries considering a transition to power systems based on renewables between now and 2030 must carefully consider storage opportunities. Energy storage is a critical component of IRENA’s global roadmap for advancing renewable energy, because storage mitigates the risks associated with the variability of energy supplies and may be applied along the entire value chain of the energy system, from generation support to transmission and distribution support and end-customer uses. However, energy storage does imply an energy conversion which is accompanied by energy losses. An inherent property of fossil fuels is that they are stored energy. The advantage of this is that they are available on demand. The disadvantage is that they require space to be stored such as stockpiles, storage tanks and other storage facilities. Renewable energies on the other hand are variable in supply and can only be stored if first converted to another form. The hybridisation of the two different types of energy allows for the advantages of both of these characteristics to be brought together. For the purposes of this report, the scope of investigation has been limited to a discussion of the technologies that are suitable for generation and system-level applications in South Africa, such as wholesale energy services and integration with renewable energy systems, as defined by the Electric Power Research Institute (2015). Energy storage at wholesale level refers to utility-scale storage systems for bidding into energy, capacity and ancillary services markets. The integration of energy storage with renewables refers to utility-scale storage which provides renewables time shifting as well as load and ancillary services for grid integration. These attributes allow for the mitigation or management of the variability of electricity supply associated with renewable energy sources. A “one-size-fits-all” energy storage technology does not exist. There are various different types of technologies that are used throughout the value chain, from supply side to demand side. These technologies have different characteristics, some that can supply short term energy storage for electricity stability and others that can supply seasonal storage for several months.

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Figure 1-37: Various applications of electricity storage in the power system (IRENA, 2015a)

The various energy storage capacities of the different technologies are presented below in Figure 1-38.

Figure 1-38: Storage capacity of different energy storage systems (REN21, 2017a)

Energy storage applications are determined by the specific context and outcome requirements. The following energy storage examples are discussed further because they are either currently in use in South Africa or could feasibly be used in the near future.

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1.6.1 Thermal energy storage (heat) The International Energy Agency (2014b) advises that thermal energy storage of this nature could be feasibly applied to CSP installations. These types of hybrid systems that incorporate the use of both electricity and thermal energy storage have the potential to maximise resource use efficiency. Already in use in South Africa, heat based thermal energy storage has been coupled with concentrating solar power in a number of large scale facilities which have been commissioned under the Department of Energy’s Renewable Energy Independent Power Producers Procurement Programme. Facilities such as Kaxu Solar One (100 MW with 2.5 hours of storage); Xina Solar One (100 MW with 5 hours of storage); Redstone (100 MW with 12 hours of storage) and Bokpoort (50 MW with 9.3 hours of storage) utilise molten salt for thermal energy storage. Heat gathered during the day when solar is at its peak is stored in the molten salts. This heat is subsequently used to produce steam, after sunset, which powers turbines that generate electricity for longer periods than just during day time hours. A generic load profile and impact of thermal energy storage applied to a solar power station is provided in Figure 1-39. The yellow line represents the thermal heat (primary y-axis) that is collected during the day. The orange line represents the net electricity that is produced by a solar field coupled with storage. The generic profile illustrates the ability to extend the generation of solar power beyond daylight hours through the application of thermal energy facilities. . The differences in the scale of the primary and the secondary axes are related to the period over which the stored energy is used to generate electricity and the energy efficiency of the overall process. The overall efficiency of the whole power station is the ratio of the area under the dark blue curve and the area under the orange curve. The ratio of the areas under the dark blue and the yellow curves indicates the energy loses due to the solar collectors whereas the ratio of the areas under the light blue and green curves indicate the losses due to storage.

Figure 1-39: Generic load profile and impact of thermal energy storage. (EPRI, 2015)

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By charging storage facilities with energy generated from renewable sources, South Africa has the opportunity to reduce its national greenhouse gas emissions and its dependence on fossil fuels. The use of energy storage further assists in mitigating the supply limitations of renewable energy sources, which serves to remove barriers to the implementation of these technologies and therefore supports the scaling up of their use. 1.6.2 Thermal energy storage (cooling) Thermal energy storage related to cooling, is the cooling of substances to act as a heat sink at a later stage. Such a system acts as a battery for a building’s air-conditioning system. It uses standard cooling equipment, plus an energy storage tank to shift all or a portion of a building’s cooling needs to off-peak, night time hours. During off-peak hours, ice is made and stored inside energy storage tanks. The stored ice is then used to cool the building occupants at a later stage. Such systems can allow for better power profile management, to reduce additional energy requirements during peak periods. Cooling with ice thermal storage can be a more cost-effective, reliable system approach to cooling buildings, and provides a steady source of low temperature fluids for process cooling applications (EVAPCO, 2007). 1.6.3 Pumped storage The most common form of existing electricity storage (99% of installed capacity) in the power sector is attributed to pumped-storage hydroelectricity (IRENA, 2015a). IRENA’s global renewable energy roadmap further suggests that the total capacity will increase from 150 GW in 2014 to 325 GW in 2030. South Africa has implemented a number of pumped water storage schemes, where water is pumped up to a dam using grid electricity. The pumping water is typically done in off-peak periods. During peak hours, when extra electricity is needed, the water is released through a turbine that drives an electric generator. Peak hours are usually between six and eight in the morning and evening. In the 2015/16 financial year Eskom provided 2919 GWh from 1400 MW capacity of pumped storage power stations (Eskom, 2016). The benefits of pumped storage hydroelectricity is that start up can occur within a few minutes, meaning that pumped storage can be used to provide balancing and reserve to systems which comprise variable renewables such as solar and wind. The main disadvantage of pumped storage relates to the relatively low efficiency of around 70-80%, as well as geographical restrictions and water availability in South Africa’s water scarce environment. 1.6.4 Fuel cells Fuel cells convert chemical potential energy (energy stored in molecular bonds) into electrical energy. Hydrogen is the most common fuel used where, natural gas or biogas are reformed to produce hydrogen. Hydrogen South Africa (HySa) is a long-term (15-year) programme initiated by the Department of Science and Technology. HySA’s aim is to conduct research into the development and

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commercialisation of hydrogen and fuel cell technologies in South Africa. Research indicates that there are hydrogen technologies that have potential to provide energy storage and peaking power through the electrolysis processes. It is likely that fuel cells in South Africa will be applied in a similar way to batteries to provide a distributed storage solution for variable renewable energy sources. This could present an opportunity for the South African energy system to take advantage of declining renewable energy costs. 1.6.5 Hydrocarbon fuels as energy storage Hydrocarbon fuels present excellent energy storage opportunities. Coal, oil and natural gas formed millions of years ago from the remains of living materials. South Africa’s energy mix is dominated by fossil fuels, largely coal-based. Fossil fuels have the potential to be stored on site for use as and when required. Thus it is a good solution to implement a hybridised system, where the renewable energy can be utilised as and when it is available and the stored fossil fuel can be used during intermittent supply of renewables. Fossil fuel is thus a stored form of energy which can overcome the necessity of having an energy storage technology on site. Fossil fuels therefore contain the storage potential that renewable energies lack. Fossil fuels may thus be used to effectively and efficient complement the generation of renewable energy. 1.6.6 Financial viability of energy storage technologies The costs, particularly those storing electricity, have been one of the main factors inhibiting the large-scale rollout of energy storage systems. IRENA (2015a) however expects global costs to decline rapidly from around 2020, due to growing demand for energy storage technologies and the associated manufacturing capacity expansion. The level at which energy storage technologies reach grid parity should be distinguished from the level at which renewable energy technologies reach grid parity. Grid parity related to renewables occurs when the renewable energy source can generate power at a levelised cost of electricity that is less than, or equal to, the price of purchasing power from the electricity grid. Energy storage technologies will however become viable (i.e. reach grid parity) once their costs compete with the cost of peaking power. The reason for this methodology is related to the periodic use of energy storage technologies, as opposed to their use in generating baseload electricity. The World Energy Council (2016) expects the cost of energy storage applications to reduce by as much as 70% by 2030. The cost typically depends on the technology, location and application of the energy storage option. Comparing different energy storage options may be facilitated by undertaking a levelised cost of storage analysis which enables comparison between different types of storage technologies, in terms of average cost per stored kWh. The World Energy Council advises that the decision to implement energy storage technologies should also be seen in the context of the co-benefits, such as the ability to provide reliable and flexible power supplies. Considering that it is difficult to assess the economic and technical benefits and obstacles to implementing electricity storage systems, IRENA has developed a methodology to rank the different value propositions for storage and any incentives associated with supporting these functions (Figure 1-40).

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Figure 1-40: Comparing costs to energy storage benefits (IRENA, 2015a)

In considering the various energy storage measures described in this report, it is evident that that the deployment and integration of energy storage with hybrid energy projects in South Africa have the potential to advance a reliable, efficient, cost-effective and clean power sector.

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1.7 Technology options for hybridisation Hybridisation options of fossil fuel value chains are dependent on the process conditions under which the fossil fuels are used. The options considered in this study are shown in the table below:

Energy service Process conditions Technology options for hybridisation

Heating

60°C to 100°C

• Solar water heaters • Biomass to heat • Biogas to heat • Geothermal direct use

>100°C

• Concentrated solar power • Biomass to heat • Biogas to heat • Deep geothermal

Cooling 10°C to 20°C

Absorption chillers driven by • Solar water heaters • Concentrated solar power • Geothermal direct use • Deep geothermal

Chilling 2°C to 10°C

Absorption chillers driven by • Solar water heaters • Concentrated solar power • Biomass to heat • Biogas to heat • Geothermal

Kinetic energy

Electric motors

Electricity from renewable sources • Solar PV • Wind • Biomass to electricity • Biogas to electricity

Internal combustion engines

• Biogas • Bioethanol • Dimethyl ether • Biodiesel • Vegetable oil

Mechanical power to pumps, etc. • Micro hydro • Windmills

Non-fuel uses

Monomer production • Bioethanol to ethylene • Bioplastics such as cellulose acetate,

polylactic acid, etc.

Reductants • Biomethane to hydrogen for metal

production • Charcoal for metal production

https://en.wikipedia.org/wiki/Cellulose_acetate

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1.8 Non-energy use of fossil fuel commodities Some fossil fuel commodities also have non-energy uses and may be used for the production of other products. This is summarised in Table 1-29. Table 1-29: Fossil fuels used for non-energy applications (Department of Environmental Affairs, n.d.)

Use Example of fuel types Product/process

Feedstock

Natural gas, oils, coal Ammonia, cyanide Naphtha, natural gas, ethane, propane, butane, gas oil, fuel oils

Methanol, olefins (ethylene, Propylene), carbon black

Coal Calcium carbide

Reductant

Petroleum coke Carbides

Coal, anthracite, petroleum coke Titanium dioxide

Metallurgical cokes, pulverised coal, natural gas Iron and steel (primary)

Metallurgical cokes Ferroalloys

Petroleum coke, pitch (anodes) Ferroalloys, aluminium

Metallurgical coke, coal Lead

Metallurgical coke, coal Zinc

Non-energy Product

Lubricants Lubricating properties

Paraffin waxes Miscellaneous (e.g. coating)

Bitumen (asphalt) Road paving, roofing, water proofing White spirit (mineral turpentine, petroleum spirits, industrial spirit), some aromatics Solvents (printing, paint, dry cleaning)

Monomers Acetylene, ethylene, propylene, styrene, etc. used in the production of plastics and other polymers

Sasol operates liquefaction plants and produce petroleum products. During processing, large amounts of fossil fuels are consumed, and a portion of this fossil fuel produces non-energy products. These non-energy products include chemicals and co-products as shown in Table 1-30 (Sasol, 2016): Table 1-30: Sasol non-energy products

Gas and chemical products Co-products from recovery and beneficiations

• Alcohols • Olefins • Polymers • Solvents • Surfactants • Co-monomers

• Ammonia • Tar acids • Sulphur • Green and calcined coke • Tars and pitch • Explosives

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Gas and chemical products Co-products from recovery and beneficiations

• Methanol • Ammonia

• Fertilisers

While the non-energy uses of fuels bear considerable properties for products in the economy, they will not be investigated further as the scope of this report focusses on the use of fuels for their energy purposes.

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2 Technology options for hybridisation in the South African context

2.1 Introduction Interest in hybridising renewable sources of energy with fossil fuel sources in order to generate electricity and heating or cooling is increasing domestically and internationally, and this report explores mature and proven technologies that deliver these services. The supply of renewable power into the national grid has been excluded from the scope of this report, as the national renewables procurement programme of large scale renewable power in South Africa has been the focus of various other studies. The aim of this report is therefore to investigate how hybrid systems can increase the rollout of renewable energy technologies in the country, with a view to transitioning to a low-carbon economy through the provision of energy services that are sustainable, accessible and affordable. This chapter aims to assess the various renewable energy technology options for hybridisation of South Africa’s fossil fuel value chains (which were covered in Chapter 1 of this report). An overview of the various energy services that can be delivered by renewable energy sources is provided, followed by a detailed assessment of the renewable energy technologies which can provide these energy services. The renewable energy technologies assessments discuss typical costs; resource availability; technology availability; supply chain or logistics constraints; technology acceptability; technology maturity and the economies of scale required in order for the various technologies to be considered viable. This chapter concludes with the mapping of the renewable energy technologies that can be used to hybridise South Africa’s fossil fuel value chains.

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2.2 Energy services Renewable energy sources have the potential to provide different energy services. A summary of the conversion of primary renewable energy sources into energy services is provided in Figure 2-1. The energy services discussed here include electricity, heating and cooling and kinetic energy (mechanical power).

Figure 2-1: Renewable energy service provisions, (REN21, 2017a)

Renewable energy provided an estimated 19.3% of global energy consumption by 2015. Growth in the renewables market has continued in 2016, where the power sector experienced the greatest increases. The split of renewables in 2016 in the global power sector is presented in Figure 2-2.

Figure 2-2: Capacity of renewables in the global power sector in 2016 (REN21, 2017b)

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The growth of renewables in 2016 in the heating and cooling and transport sectors was comparatively slow (REN21, 2017b). The following subsections outline South Africa’s different energy services and describe the extent to which hybrid renewable energy and fossil fuel systems currently feature and in the future have potential to feature in the provision of these services. 2.2.1 Electrical energy services Electrical energy services in South Africa are used to provide a range of lighting, charging, heating, cooling and mechanical applications in the country’s industrial, commercial and residential sectors. South Africa’s electricity sector is predominantly coal-based. As a result, the sector is emissions intensive and accounts for roughly 45% (233,208 tCO2e) of the country’s total emissions inventory (518,239 tCO2e), as per the latest Greenhouse Gas (GHG) Inventory for 2010 (Department of Environmental Affairs, 2014a). The hybridisation of services that use grid based electricity with renewable energy sources has the potential to reduce South Africa’s national emissions inventory. In particular, heating and cooling demands in South Africa (which are typically met by electrical means) can be met by renewable resources such as solar, geothermal or biomass. Examples of hybrid electrical opportunities include, but are not limited to, the installation of rooftop solar on commercial or residential buildings which can deliver electrical services including lighting, charging heating and/or cooling. Space cooling requirements around the world are typically delivered through electricity based technologies. These rising cooling demands have resulted in higher peak electricity requirements, which has increased interest in solar cooling opportunities in countries with large solar potential (REN21, 2017b). South Africa has made strides in the last decade with regards to electricity generation from renewable sources. By the end of 2016, 5% of the country’s total electricity capacity was generated by renewable sources (REN21, 2017b), where 2 738 MW had reached commercial operation by 30 September 2016 (Independent Power Producer Procurement Programme Office, 2016). Efforts are ongoing to increase this amount, supported by research undertaken by the CSIR (2016b) which finds that a mix of renewables, notably solar PV and wind, could feasibly (technically and economically) supply South Africa’s baseload demand in the same reliable manner as a base-power generator. One of the ways that South Africa is supporting efforts to increase the renewables market is through the development of Renewable Energy Development Zones, where wind and solar PV development can occur in concentrated zones. The zones are located in in the Overberg (Western Cape), Komsberg (Western Cape), Cookhouse (Eastern Cape), Stormberg (Eastern Cape), Kimberley (Free State/Northern Cape), Vryburg (North West), Upington (Northern Cape) and Springbok (Northern Cape). These areas will have various investor benefits, such as the ability to undertake Basic Assessments, instead of full Environmental Impact Assessments, because the Basic Assessments cover the requisite scope.

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South Africa’s renewable energy resources have been mapped in section 1.2 of this report. The maps present ideal locations where these energy sources can be found and potentially used for hybridisation. For the purposes of hybridising standalone fossil fuel power stations, applicable renewable energy technologies will need to be located in close proximity to the fossil fuel-fired power stations located in South Africa. The locations of the existing power stations are illustrated in Figure 2-3.

Figure 2-3: South Africa's power stations and electricity grid network, (Eskom, 2012)

An assessment of the hybridisation opportunities and key cost components related to solar PV, concentrated solar power, biomass power plants (including landfill gas power plants and waste to energy facilities) wind farms, geothermal and micro hydro power stations are described further in section 2.3. 2.2.2 Heating based energy services Energy for heating accounted for around 50% of the world’s overall energy consumption in 2016, (REN21, 2017b). Heating includes water heating, space heating, cooking and heat for industrial processes. Internationally energy consumption for cooling is considerably lower. Both heating and cooling demands can be met by the direct use of renewable energies.

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Globally around 25% of heating services are provided by renewable energy sources (REN21, 2017b), with more than two-thirds of this provided from traditional biomass in developing countries. Focusing only on modern renewable energy, bioenergy accounts for almost 90% of renewable direct heat use, solar thermal represents around 8%, and geothermal accounts for 2%, (REN21, 2017b). The majority of the heat provided by renewable energy technologies is consumed by industrial users (56%), a smaller portion (5%) is consumed by commercial district heating systems. A substantial portion, slightly less than 40% is consumed by households, in modern biomass stoves and in solar thermal heat systems. Energy used for space cooling accounts for around 2% of the world’s energy consumption, where the majority of space cooling is delivered by electrical appliances. Rising demands for cooling have not resulted in the rise of non-electric renewable energy based cooling technologies. This is mainly due to electricity-based cooling technology’s installation flexibility and cost competitiveness. A variety of renewable energy sources can be used to contribute to heat and cooling provisions, through two central methods. These methods include 1) the direct use of renewable energy sources for heating or cooling of buildings or industry, or 2) renewable energy can be used to produce electricity, which in turn can be used to produce heat or cooling either directly or by operating a heat pump. An overview of the various potential processes to convert renewable energy to heat and cooling is provided in Figure 2-4.

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Figure 2-4: Overview of different renewable energy sources and main technologies to convert them into direct heat, and heat & power (IEA, 2014b)

Globally the implementation of hybrid heating and cooling systems continued to increase in 2016, (REN21, 2017b). In 2016, solar thermal technologies were often coupled with different technologies to guarantee a secure supply of heat. Solar thermal energy use for heat was the fastest‐growing market over the last decade. South Africa’s industrial processes currently rely heavily on coal for industrial heating. Other heating and cooling requirements in the country are generally provided via electricity. Heating is

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required for various operations, these include industrial process heating, space heating, hot water heating, and pool heating. Cooling is required for space cooling and industrial refrigeration based cooling. Heating and cooling can be provided through various renewable energy technologies and the hybridisation of these with existing fossil fuel technologies is possible. Renewable energy technologies have the potential to produce different temperatures, using different renewable energy resources. These are summarised in Table 2-1: Table 2-1: Renewable energy heating and cooling technologies

Resource Technology Application

Solar

Concentrating solar Heating/cooling

Evacuated tube Heating/cooling

Flat-plate collector Heating

Transpired air collector Heating

Unglazed collector Heating

Geothermal

Deep geothermal Heating/cooling

Geothermal direct use Heating/cooling

Heat pump Heating/cooling

Biomass Woody biomass technologies Heating/cooling

A summary of the heating and cooling applications and the potential renewable energy technologies that can provide these heating applications at different working temperatures is provided in Figure 2-5.

Figure 2-5: Heating and cooling applications provided by renewable energy technologies (Modified from: EPA, 2017a)

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Focussing specifically at the industrial sector and its heating and cooling requirements, a summary of heating requirements for the different industrial sectors is provided in Table 2-2 below. Table 2-2: Industrial processes and their temperature requirements (IEA-ETSAP and IRENA, 2015b)

Industrial sector Unit operation Temperature

range (°C) Average temperature range (°C)

Heat Intensiveness

Food

Drying 30-90

30-120 Low

Washing 60-90

Pasteurising 60-80

Boiling 95-105

Sterilising 110-120

Heat Treatment 40-60

Beverages

Washing 60-80

60-90 Low Sterilising 60-90

Pasteurising 60-70

Paper Industry

Cooking and Drying 60-80

60-150 Low Boiler feed water 60-90

Bleaching 130-150

Metal Treatment

Treatment, electroplating, etc. 30-80 30-80 Low

Bricks Curing 60-140 60-140 Low-medium

Textile Industry

Bleaching 60-100

40-180 Low-medium

Dyeing 70-90

Drying, de-greasing 100-130

Washing 40-80

Fixing 160-180

Pressing 80-100

Chemical Industry

Soaps 200-260

120-260 Medium Synthetic rubber 150-200

Processing heat 120-180

Pre-heating water 60-90

Plastic industry

Preparation 120-140

120-220 Medium

Distillation 140-150

Separation 200-220

Extension 140-160

Drying 180-200

Blending 120-140

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Industrial sector Unit operation Temperature

range (°C) Average temperature range (°C)

Heat Intensiveness

All Industrial Sectors

Pre-heating of boiler feed water 30-100 30-100 Low

Industrial solar cooling 55-180 55-180 Low-medium

Heating of factory buildings 30-80 30-80 Low

The heating requirements of the industrial sector are summarised in Figure 2-6.

Figure 2-6: Industrial heating provided through renewable energy technologies (modified from: EPA, 2017b)

Renewable energy heating technologies can compete on a cost basis with fossil fuel‐based heating, specifically in the commercial and residential buildings sector. To give an indication of the heating cost ranges per technology (fossil fuel and renewable energy), a global summary is provided in Figure 2-7 (IEA, 2014b).

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Figure 2-7: Heat production costs of fossil fuel based and renewable energy technologies (IEA, 2014b)

These renewable energy technologies for heating and cooling are discussed further in section 2.3 of this report. 2.2.3 Kinetic energy services (mechanical power) Kinetic energy can be provided by renewable energy sources by providing a direct force to provide useful work. Wind, hydro and tidal resources provide direct kinetic energy. Energy contained in the movement of mass (kinetic energy) is used for many applications (or mechanical energy services) such as sawing, milling, crushing, grinding, pumping, fanning, sailing, drilling and compressing. The list is extensive and can include any activity which requires movement. Hydropower and wind have been used as direct kinetic energy to perform tasks such as milling of grains and pumping water since 500AD (Ryan, 2009).

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2.3 Renewable energy technology assessment This section of the report provides an overview of the various renewable energy technologies that can be used to provide the energy services discussed above. The mature renewable energy technologies included are solar, biomass, wind, geothermal and micro hydro. The technology assessment provides a valuation of the technologies which considers costs (capital and operational); resource availability; technology availability; supply chain and logistics constraints; technology acceptability; technology maturity and the economies of scale required in order to have a valuable impact.

A summary of the costs of renewable energy technologies compared with the non-renewable energy costs is presented in

Figure 2-8. This shows how the various renewable energy technologies compare with one another on levelised electricity and energy cost bases.

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Figure 2-8: Range of levelised costs of energy for selected commercially available renewable energy technologies compared with non-renewable energy costs, cost development 2010-2015 (REN21, 2017a)

The fossil fuel range indicated in the transport fuels category above, was added above specifically for South Africa. This range was based on the basic fuel price and the pump price in South Africa to indicate the impact of taxes and levies on fuel price. Caution should however be applied when considering the various cost ranges illustrated above, as the ranges can vary further between countries.

2.3.1 Solar Solar energy is one of the most readily accessible renewable energy resources in South Africa (Department of Energy, 2015a) where the global horizontal irradiance (GHI) and direct normal irradiance (DNI) levels are highest over the interior and north western regions of the country (refer to resource maps in section 1.2.3 of this report). Solar thermal energy in particular is expected to play an important part in the country’s path to a low carbon and sustainable energy future (SA-STTRM, 2014). The scope of this report with respect to solar energy focusses on the applications and hybridisation opportunities related to solar heating (and cooling), solar ventilation, solar electricity generation and solar chemistry. The International Energy Agency (IEA) indicates that heat and photoreaction are the two fundamental methods that capture solar energy (IEA, 2011a) for use in various applications such as the provision of electricity and heating. Solar thermal systems capture heat from the sun within a heat transfer fluid (e.g. water, oil or air) which allows the energy to be transported and used for heating or cooling applications. Systems for liquids are more often used when storage is included and are well suited for radiant heating systems, boilers with hot water radiators, and even absorption heat pumps and coolers (Yale, 2017). Both heating and photoreaction systems are characterised by the type of solar collectors they use. The typical range of collectors is illustrated in Figure 2-9. Solar collectors can be either fixed in orientation or can move with the sun to maximise exposure to solar irradiation. In addition to the control of orientation, the reflective surfaces can be flat, curved (parabolic trough) or dish shaped. The trough and dish surfaces concentrate the solar radiation to increase intensity and temperatures at a focal line (trough) or point (dish).

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Figure 2-9: Range of solar collectors (WWF, 2017)

Fixed angle (or fixed tilt) collectors are orientated to optimise for the average elevation of the sun based on the longitude of the location (but may also be based on the slope of the surface they are mounted on such as a roof). Solar collectors may also be mounted so that they can be electronically controlled to track the movement of the sun. Tilting collectors increase irradiance levels by up to 35%. The optimal tilt angle of collectors will depend on the type of irradiance available as well as the particular type of application (IEA, 2011a). Tracking systems generate more electricity than their stationary counterparts’ due to increased direct exposure to solar irradiation. Tracking systems range from single axis to dual axis configurations. Single axis trackers all face the same direction when tracking the sun, and produce about the same amount of energy per hour. This can be done by rotating the solar collector on one axis (single axis) to track the suns pathway from east to west on a daily basis. Dual axis trackers can point directly at the sun which is usually the brightest spot in the sky. Dual axis tracking allows the sun to be tracked both on a daily basis (east - west) and over a seasonal basis (north - south) to compensate for seasonal solar elevation changes. Dual axis tracking is however more complex (and hence expensive) and is subject to more down time and maintenance requirements than single axis configurations. Concentrating solar systems use reflectors (mirrors) to concentrate and focus a large area of sunlight onto a small area, known as the receiver. The concentrator captures solar radiation and directs it to the receiver where the heat energy is absorbed by a heat transfer fluid, typically a special type of oil. The heat transfer fluid has properties of having a high heat capacity, being able to operate and be stable at high temperatures, being non-corrosive, with low viscosity, and a low freezing point. The heated fluid is transported via pipes to a heat exchanger where the heat can be used or stored. Some systems pass the heated fluid to a storage system where the heat can be stored for later use, such as at night or during cloudy days.

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A concentrated system can provide heat at varying temperatures, these temperatures depend on the concentration ratio. The higher the concentration ratio the higher the achievable temperature. The technology can be used for a range of applications, from simple cook stoves to sophisticated, large‐scale collectors for high temperature heat and/or power generation. Concentrating solar technologies at an industrial scale are used for high temperature requirements, such as electricity production using large-scale concentrated solar thermal power plants (WWF, 2017), solar furnaces and the production of Solar fuels (Roos, 2013 and Lovegrove, 2013). Examples of concentrating solar technologies include linear Fresnel, parabolic trough, solar power tower and Stirling dish. The concentrating solar technologies require specific conditions, including clear skies and sufficient DNI in order to generate adequate heat. As such, most appropriate areas for concentrating solar systems are preferably those areas with suitable conditions. Concentrating solar heating systems are usually used for medium scale heat application systems in industry, agriculture and food production. The broad key components and measures related to solar energy production in South Africa are outlined in Table 2-3.

Table 2-3: Typical solar components and measures

Component: Measure: Resource availability

GHI in South Africa, which is applicable to non-concentrating solar systems range from 1,600 kWh/m2/year (along the eastern coast of South Africa) to 2,350 kWh/m2/year in the north-west region (Solargis, 2015a). The country’s DNI, applicable to concentrating solar systems, varies across the country from as low as 1,400 kWh/m2/year in a small part of the country along the eastern coast and ranges up to a high of 3,200 kWh/m2/year in the western and northern parts of the country (Solargis, 2015b). Refer to section 1.2.3 in Chapter 1 of this report for solar maps and further details on resource availability.

Location applicability

The north west of South Africa has excellent conditions for solar energy. In addition, most of the interior of the country is suitable with low cloud cover in the winter seasons when energy demand is the highest. For electricity generation applications accessibility to the electricity grid plays a significant role in the uptake. Location applicability also depends on the hybridisation opportunity. Hybridisation of solar systems with fossil fuel power stations in South Africa (coal or gas) for example will depend on the location of the power station and its available solar resource. A map of the country’s operational or planned power stations are presented in Figure 2-3. Coal power stations are largely located in the Mpumalanga province, with the gas power stations along the coast.

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Component: Measure: Hybrid solar applications within industrial or residential processes will be suitable for those facilities where the GHI or DNI is best. Refer to section 1.2.3, Figure 1-6 and Figure 1-7 of this report for solar maps.

Technology availability

The International Energy Agency - Energy Technology System Analysis Programme (IEA-ETSAP) and the International Renewable Energy Agency (IRENA) report that initially the majority of solar water heating systems were manufactured locally in South Africa by small- and medium-size enterprises (IEA-ETSAP and IRENA, 2015b). South Africa’s solar water heating market expanded from 20 suppliers in 1997 to more than 400 suppliers in 2011 but has since decreased to very low levels. Solar cooling however remains a niche market world-wide, although there is potential for growth (IEA, 2017). Solar PV’s share of local content was reported to be 66% by the end of 2015 (Department of Energy, 2015a). The opportunities of the solar PV industry to support non-utility scale renewable energy solutions are considered to be particularly attractive but depend on a favourable regulatory environment (Department of Energy, 2015a). A favourable regulatory environment may include an appropriate legal and regulatory framework for pricing and tariff structures to support the integration of renewable energy into the energy economy and to attract investors; enabling legislative and regulatory framework to integrate independent power producers into existing electricity systems and others as prescribed by the White Paper on the Renewable Energy Policy of the Republic of South Africa (Department of Minerals and Energy, 2003). Examples of local PV panel producers in South Africa include ARTSolar which has the capacity to produce 250,000 PV modules a year (enough to generate 75MW of electricity) as well as PiAsolar, which specialises in the production of solar PV mounting systems (Department of Energy, 2015a). The cumulative local content levels associated with concentrated solar power in the third bid window was just under 45% (GreenCape, 2017). The World Wildlife Fund (2015) reports that experts anticipate that 70-85% of the capital cost of utility scale concentrated solar power tower plants can be produced domestically over the long-term. The Department of Trade and Industry has commissioned a localisation study for concentrated solar power technologies to define which and how many components can be manufactured or assembled locally.

Technology maturity

Several solar heating technologies are already mature and can compete with fossil fuel technologies. The applications in which they are most competitive include domestic hot water heating and swimming pool heating systems, (IEA, 2014b). The global cumulative capacity of glazed and unglazed collectors in operation increased by nearly 5% during 2016 (to a year-end total of 456 GWth) (REN21, 2017b).

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Component: Measure: Globally solar thermal collectors of all types provided approximately 375 TWh of heat annually by the end of 2016, equivalent to the energy content of 221 million barrels of oil, (approximately 0.23% of global total primary energy supply) (REN21, 2017b). For the first time, new solar PV generation in 2016 accounted for more additional capacity, than any other power generating technology. Solar PV represented about 47% of newly installed renewable power capacity in 2016. Solar power had a global capacity of 303 GW in 2016, which was a small market share (1.5%) of the estimated total renewable energy segment (i.e. including hydro sources) of global electricity production (REN21, 2017a). Concentrated solar power (CSP) had a global capacity of 4.8 GW during 2016, which was the smallest market share (0.4%) of the estimated total renewable energy segment (i.e. including hydro sources) of global electricity production. Even so, CSP remains on a strong growth trajectory, with as much as 900 MW expected to enter operation during the course of 2017 (REN21, 2017a). Furthermore, the International Energy Agency (cited in World Wildlife Fund, 2015) projects that concentrated solar power will account for 11% of global electricity generation by 2050. The World Wildlife Funds (2015) considers CSP technologies to be generally immature. REN21 (2017b) reports that parabolic trough and tower technologies dominate the international CSP market, with parabolic trough systems representing the bulk of capacity that became operational in 2016 as well as most of the capacity expected to come online during 2017.

Supply chain / logistics constraints

There are good to excellent levels of solar radiation across the country. Fossil fuel value chain that are hybridised with solar resources to create heating services should ideally occur close to the source of end-use, to avoid unnecessary energy losses.

Acceptability Large scale solar electricity generation is widely accepted in South Africa, where the technology has been successfully rolled out in five bid windows through the Department of Energy’s renewables procurement programme (procured solar capacities are second to wind capacity). There is untapped potential for the rollout of smaller scale solar in South Africa’s industrial sectors. Research by the WWF (2017) indicates that barriers to uptake include the cost of installing solar technologies and a lack of consumer knowledge (particularly regarding solar thermal opportunities). The regulatory environment is currently in development. For example, Nersa published a consultation paper on the Regulatory Rules applicable to small-scale embedded generation in South Africa. In addition, Nelson Mandela Bay Metropolitan Municipality, eThekwini Metropolitan Municipality and the Cities of Cape Town, Johannesburg and Tshwane) have developed policies on embedded generation in South Africa. The viability of rooftop solar depends ultimately however on the local electricity tariffs in South Africa. Furthermore, there are many tariff structures as each municipality may set their own tariffs.

Economies of scale

Most solar technologies are modular in nature and can be readily scaled to small and large systems, ranging from residential buildings to large industrial and district applications. Financial feasibility will depend on a number of factors

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Component: Measure: including annual solar yields, technology type, electricity demand, tariff structure, time of use and access to funds (Millson, 2014). Utility-scale facilities achieve highest economies of scale (IRENA, 2015b and IRENA, 2016a). Concentrating solar power facilities in particular tend to be large in size. Substantial economies of scale may be achievable at a plant capacity of 130-170 MW, where the key driver is the fixed cost associated with turbine size for CSP electricity generation (Word Wildlife Fund, 2015).

The solar services related to heating, cooling, ventilation, electricity generation and solar chemistry are discussed further in the following sections. 2.3.1.1 Solar heating and cooling The vision of the South African Solar Thermal Technology Road Map (SA-STTRM), which was proposed by the Centre for Renewable and Sustainable Energy Studies at Stellenbosch University, is that by 2030 there should be a ½ square metre of solar thermal collector installed for every member of the population in South Africa. This translates into an estimated 30 million square meters of installed solar thermal collectors. To date there are approximately only 1.5 million square metres installed in South Africa (SA-STTRM, 2015). The number of installed solar thermal system units in South Africa are as follows (SA-STTRM, 2015):

• High pressure residential solar water heating: ±150 000 • Low pressure residential solar water heating: ±400 000 • Industrial/commercial/multi-family residential installations for solar heating &

cooling: ±213 • Unglazed swimming pool solar water heaters: ±4 335

Solar thermal technology is used extensively worldwide for water heating, space heating and cooling, drying of products and to provide heat, or steam for industrial processes. Solar thermal systems typically complement existing systems to generate heat or cooling for processes and their benefits lie in decreasing electricity or fuel costs as well as the associated GHG emissions (WWF, 2017). Different technologies produce a range of temperatures for a number of applications. The solar technology to be used within a process depends on the temperature requirements. A summary of the various solar collector technologies and their applicability to different industry sectors for heating provisions is summarised in Figure 2-10.

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Figure 2-10: Solar collector technologies applicable for various industry sectors (Solar Payback, 2017)

Non-concentrating technologies are typically used for low‐temperature air and water heating or cooling in buildings or industry. Concentrated technologies are better suited to high temperature requirements, such as electricity production and solar chemistry, and are typically larger in scale than non-concentrating solar technologies (WWF, 2017). Hybridising concentrated solar power with coal-fired power stations to generate steam to produce electricity further increases the potential for concentrated solar energy technologies, while reducing emissions associated with coal power generation. Research by the Electric Power Research Institute (EPRI) suggests that central tower systems are better suited to hybridisation (steam augmentation) due to their ability to achieve higher steam temperatures compared with the parabolic trough technology. However, from a project risk perspective, parabolic troughs are associated with less risk because of the number of plants deployed (i.e. they dominate the market). Designs for hybridising coal power stations with solar must consider the steam cycle, required temperature and pressure requirements. The associated levelised cost of electricity from a hybridised coal fired power station with concentrated solar is higher than that from a conventional coal fired power station, but much less than that from a conventional concentrated solar power plant, (Van Rooy et al, 2015). Internationally there are currently five operational hybrid concentrated solar power plants, all using the parabolic trough technology, however none hybridised with coal-power stations. The operational plants are hybridised with geothermal, combined cycle gas turbines, and biomass power plants, (NREL, 2017). There have been a few cases of unsuccessful hybridisation of coal fired power stations with concentrated solar, these are included in Chapter 3 of this report.

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Solar thermal augmentation to preheat feed water into a steam power plant is shown as a schematic in Figure 2-11. In this case solar energy is used to preheat the water going into the boiler reducing the energy required to produce steam. It is also possible to use a larger solar field to produce steam and to add this to the steam coming out of the boiler.

Figure 2-11: Solar thermal augmentation of a steam power plant (Miller, 2013)

Concentrated solar power technologies easily integrate into existing fossil fuel-based power plants that use conventional steam turbines to produce electricity. In these cogeneration facilities, the steam produced by the combustion of fossil fuels is substituted by heat from the concentrated solar power technologies. Considering that South Africa is a water scarce country, water efficient “dry cooling” systems are the preferred option. However, such plants are typically about 10% more expensive than water-cooled facilities (IEA-ETSAP and IRENA, 2013a). Solar thermal augmentation of a steam power combined cycle gas turbine is shown in Figure 2-12. Here the solar field provides heat in addition to the waste heat coming from the gas turbine to enhance and enable a larger steam turbine to be used.

Air-Cooled Condenser

HP IP / LP

Cold Reheat

Steam Turbine

LP FW HeatersHP FW Heaters BFP

Solar Field / Solar Feedwater Heaters

Deaerator

Steam Generator

Final Feedwater

Main Steam

Hot Reheat

CondensatePump

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Figure 2-12: Solar thermal augmentation of combined cycle gas turbine (Miller, 2013)

The IEA (2017) notes that solar thermal district cooling networks could have strong potential for the enhanced use of renewable heat for cooling, as availability of the solar resource usually correlates to the cooling demand in buildings. An example of a solar cooling facility at the MTN data centre and head office in Johannesburg is provided in Figure 2-14. The facility utilises linear Fresnel concentrating collectors.

Figure 2-13: MTN's linear Fresnel concentrated solar cooling plant at head office

As with the MTN facility, in most cases, solar heating technologies are unable to cover the entire heating or cooling requirements of a building, representing fossil fuel hybrid opportunities in the form of back-up systems to support and provide supplementary energy services. When combining a solar thermal system with another heating or cooling source, complexity is added. Solar heat can

HPSH

RH

HPEC

HPEC

IPSH

IPEC

LPSH

LPEC

Steam Turbine

Gas Turbine

Air

Fuel

Heat Recovery Steam Generator

Air-Cooled Condenser

LPEV

IPEV

HPEV

HPEC

HP IP / LP

Main Steam

HP SteamDuctFiring

Solar Field / Solar Power Block

BFP Discharge

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be integrated into a system at various points. One of the most common integrations of solar heat into a system is through preheating. Solar heating can also be used to generate steam or can be fed directly into the production system. Through the preheating process, cold water is preheated in the solar field and fed into a storage tank where it is further heated up by a fossil fuel powered boiler to the temperature required in the production process, Figure 2-14.

Figure 2-14: Solar thermal integration for preheating (Solar Payback, 2017)

Direct process heating is the transfer of heat from the solar field to the industrial process, this is usually to maintain the temperature of a bath or a thermal separation process. In these setups additional heat can be provided to the operation by a fossil fuel boiler. These two circuits operate on a closed loop system, Figure 2-15.

Figure 2-15: Solar system supplying heat directly to an industrial process (Solar Payback, 2017)

The integration of solar thermal systems with fossil fuel processes can also be carried out through direct steam generation which is fed into an industrial process. During this process water is partly evaporated in the concentrating collectors to produce steam. The solar-heated steam is then separated from the remaining water in the steam drum before being supplied to the industrial process or the steam network of the factory, Figure 2-16. Indirect steam generation is a further opportunity where the heated water or thermal oil from the collector field generates steam via a heat exchanger.

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Figure 2-16: Solar heat integration through steam generation (Solar Payback, 2017)

Broad key components and measures related to solar heating and cooling in South Africa are outlined in Table 2-4. Table 2-4: Typical solar heating and cooling costs

Component: Measure: Costs The costs of solar heat for industrial processes strongly depend on process

temperature levels, demand continuity, project size and the level of solar radiation of the site.

Capital Non-concentrating systems (IEA-ETSAP and IRENA, 2015b): For conventional solar water systems, investment costs range between EUR 0.2 million/MW and EUR 0.3 million/MW (R3 million – R4.6 million/MW) 10 in India, Turkey, South Africa and Mexico. Eskom (2011) provides South African specific costs of solar water heaters, indicating that these vary between R7 000 and R35 000 depending on the size, type and source. Concentrating systems (IEA-ETSAP and IRENA, 2015b): • Parabolic Dish Collectors with costs ranging from USD 0.4 million -

1.8 million/MW (R5 million – R24 million/MW)11 • Parabolic Trough Collectors with costs ranging from USD 0.6 million -

2 million/MW (R8 million – R27 million /MW)12 • Linear Fresnel collectors in the range of USD 1.2 million –

1.8 million /MW (R16 million – R24 million /MW)13 Solar heating systems (Solar Payback, 2017): The turnkey capital costs of the solar water heating system at the Cape Brewing Company amounted to R16 million /MW.

10 Based on an exchange rate of ZAR15.249/Euro as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=EUR&To=ZAR 11 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR 12 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR 13 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR

http://www.xe.com/currencyconverter/convert/?Amount=1&From=EUR&To=ZAR

http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR



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2.3.1.2 Solar ventilation Solar induced convection has been used for power generation (Schlaich et al, 2003) and is also used in ventilation in buildings (Gan, 1998, Kaneko et al, 2010 and Ismail, 2012). The implementation of such a system would reduce the energy demand of a building related to its heating and cooling requirements. The principal involved in solar ventilation is convection of air heated by a surface which acts as a heat sink for solar radiation causing the air to rise or fall. This is demonstrated in Figure 2-17. The direction of the flow of air for ventilation is controlled with the use of dampers located within a thermal storage wall (Trombe wall) and the adjacent window. The gap between the wall and the window encourages the flow of air either into or out of the building depending on which dampers are open. The use of solar ventilation reduces the requirement for forced ventilation using electrical fans and thus the related emissions related to electricity systems. Passive solar technologies need to be incorporated into the building envelope during the design of buildings. For a new building the costs related to solar ventilation are included within the costs related to construction. The savings related to a solar ventilation retrofit (Trombe wall) have a payback period of 7-8 months (Sharma and Gupta, 2016).

Figure 2-17: Solar ventilation in buildings (Gan, 1998, Kaneko et al, 2010 and Ismail, 2012)

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2.3.1.3 Solar electricity generation Electricity generated from solar sources is the second most widely procured category of renewable energy (second to wind) in the Department of Energy’s Independent Power Producer Procurement Programme (Independent Power Producer Procurement Programme Office, 2016). Solar PV and concentrated systems are the eligible technologies under the procurement programme, and are discussed further in the following sections with a focus on the potential to hybridise with fossil fuels.

2.3.1.3.1 Solar PV Solar PV utilises energy from the sun’s radiation, where sunlight is captured and converted into direct current electricity using semiconductors that exhibit a photovoltaic effect. PV panels do not require direct sunlight to work, meaning that they can still generate some electricity on cloudy days. Supplementary inverters and storage batteries are required for a continuous supply of electric power from PV technologies. In 2016 solar PV accounted for about 47% of newly installed renewable power more than any other power generating technology (REN21, 2017a). Solar PV’s procured capacity in South Africa is approximately 2.3 GW which falls under the Department of Energy’s large and small scale Independent Power Producer Procurement Programmes (Independent Power Producer Procurement Programme Office, 2016). This amounts to just under half of the capacity for solar PV provided for in ministerial determinations to date (Independent Power Producer Procurement Programme Office, 2017). Solar PV can be used to produce electricity which can be used to run the auxiliary equipment of many facilities in South Africa. This can range from a rooftop solar PV installation to hybridise the electricity requirements of a building, or to provide some or all of the parasitic/auxiliary load required to run power stations. The addition of a solar PV system to a power station assist with increasing the output of the station (as much as 20%). Such a system reduces coal consumption and thus the related GHG emissions per MWh of electricity. (Rycroft, 2013). Solar PV is a particularly cost-competitive source of electricity generation. Modelling undertaken by the Council for Scientific and Industrial Research indicates that when coupled with flexible gas-powered generation, combined wind and PV can provide the cheapest new baseload capacity in South Africa (Bischof-Niemz, 2016). Electricity prices generated from large solar PV facilities have declined sharply since the inception of the Renewable Energy Independent Power Producer Procurement Programme (Figure 2-18), and are becoming increasingly competitive with Eskom’s tariffs (R0.63/kWh Eskom megaflex tariff for standard period and low demand season).

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Where BW = bid window

Figure 2-18: Average prices of solar PV per bid window in the Renewable Energy Independent Power Producer Procurement Programme (Department of Energy, 2015a)

The levelised cost of electricity (LCOE) generated from solar PV in the EPRI report (2015) is determined by various parameters that range from capital and operational costs related to specific technologies, location (irradiance levels) and configuration, amongst others. Summaries of these key costs related to silicon and thin-film PV technologies are outlined in the following tables. Table 2-5: Typical silicon solar PV costs

Silicon Solar PV (EPRI, 2015) Measure: Tracking Measure: Fixed-tilt Rated Capacity (MW) 1-10 Mounting Location (Cape Town-Johannesburg) Single and double axis

Average Capacity Factor (%) 25 19 Average Fuel Cost (ZAR/MWh) - - Plant Cost Estimates: Overnight (ZAR/MW) 34 - 60 million

Fixed O&M, (ZAR/MW-yr) 0.3 million 0.2 million LCOE (ZAR/MWh) 2 289 3 422

Table 2-6: Typical thin-film solar PV costs

Thin-film solar PV (EPRI, 2015) Measure: Tracking Measure: Fixed-tilt Rated Capacity (MW) 1-10 Mounting Location (Cape Town-Johannesburg) Single and double axis

Average Capacity Factor (%) 24 18 Average Fuel Cost (ZAR/MWh) - - Plant Cost Estimates: Overnight (ZAR/MW) 41 - 46 million

Fixed O&M, (ZAR/MW-yr) 0.3 million 0.2 million LCOE (ZAR/MWh) 2 847 3 795

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The levelised costs as per the EPRI study above, uses data prior to 2015 which doesn’t account for technology learning at present. However the levelised costs of electricity that have been seen from the bid windows of the Renewable Energy Independent Power Producers Procurement Programme, which accounts for technology learning are presented below in Figure 2-19. The dates are the bid submission dates of bid window (BW) 1 to 4 (Expedited). Here it is seen that the current levelised cost of electricity from solar PV is down to ZAR620/MWh, this is in comparison to the results from EPRI which ranges between ZAR 2,289 – 3,795/MWh.

Figure 2-19: Reduction in tariff for new wind, solar PV and CSP, as per the Department of Energy’s REIPPPPP (Bischof-Niemz, 2017)

2.3.1.3.2 Concentrated solar power Electricity is generated when the concentrated light from the sun is converted to heat, which drives a heat engine (usually a steam turbine) connected to an electrical power generator. Concentrated solar power (also called concentrating solar power, concentrated solar thermal, and CSP) may be paired with heat storage facilities (such as molten salt tanks) which act as heat batteries. The heat stored in these may be utilised to generate electricity at determined times,

allowing concentrated solar power facilities to generate electricity during peak power demand periods, during cloudy periods or even several hours after sunset.

Figure 2-20: Parabolic troughs. (Source: www.seia.org)

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The ability of thermal energy storage to provide intermediate and base-load electricity is a significant advantage of concentrated solar power technologies, which improves grid integration and economic competitiveness of such power plants. In terms of fossil fuel value chain hybridisation with electricity produced from a CSP plant, the opportunity exists for facilities to install a CSP plant to produce electricity which can be used to power the electrical auxiliaries of the plant. The economics of CSP facilities means that plants of this nature are often large in scale, for example in 2016 many of the globally commissioned facilities were over 100 MW (REN21, 2017a). The capacity factor of concentrated solar power plants range from 25-70% (EPRI, 2015), depending on the technology, whether thermal storage is included and location (which determines the typical levels of solar radiation). Parabolic trough and tower technologies dominate the CSP market (REN21, 2017a). Trough systems are considered to be the most mature of the CSP technologies (REN21, 2017b). Parabolic troughs use thousands of large, U-shaped reflectors (focusing mirrors) that are assembled in lines allowing the troughs to track the sun from east to west during the day. Pipes running along the centre of the parabolic troughs contain a heat transfer fluid that is heated by the concentrated solar radiation up to 390°C. The resulting heat is used to boil water and create steam, which is finally used to run conventional steam turbines and generators (IEA-ETSAP and IRENA, 2013a). Tower systems (also called central receivers or power towers) use many large, flat heliostats (mirrors) on dual-axes to track the sun and focus its rays onto a receiver. Receivers are positioned on top of tall towers in which concentrated solar radiation heats a fluid, typically molten salt, to temperatures up to 565°C. The hot fluid can be used immediately to make steam for electricity generation or stored for later use. Molten salt retains heat efficiently, so it can be stored for days before being converted into electricity (IEA-ETSAP and IRENA, 2013a). South Africa was the fourth largest generator of electricity from CSP world-wide by the end of 2016. South Africa also had the highest level of Annual Investment / Net Capacity Additions / Production in Concentrated solar power in 2016, beating China in this category (REN21, 2017a). Concentrated solar power accounted for 9.4% (600 MW) of South Africa’s actual procured generation capacity under the Renewable Energy Independent Power Producer Procurement Programme (Independent Power Producer Procurement Programme Office, 2016). This amounts to half of the capacity for concentrated solar power provided for in ministerial determinations to date (Independent Power Producer Procurement Programme Office, 2017). Studies undertaken by IEA-ETSAP and IRENA (2013a) indicate that investment costs and levelised costs of electricity associated with concentrated solar power are expected to decline by 30-50% by 2020 due to technology learning and economies of scale following the increasing deployment of the technology.

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The learning curves for concentrated solar power production in South Africa’s Renewable Energy Independent Power Producer Procurement Programme are illustrated in Figure 2-21.

Where BW = bid window

Figure 2-21: Average prices of concentrated solar power per bid window in the Renewable Energy Independent Power Producer Procurement Programme. (Department of Energy, 2015a)

The tariffs for CSP decreased by 49% over the four bid windows in which concentrated solar projects were awarded preferred bidder status (Department of Energy, 2015b). The costs and configurations of concentrated power technology in South Africa vary. Key costs related to the most prolific CSP technologies, parabolic trough and tower systems, are outlined in Table 2-7 (as per EPRI, 2015). Table 2-7: Typical concentrated solar power costs

Component (EPRI, 2015): Parabolic trough Power Tower

Plant Cost Estimates: Overnight (ZAR/MW)

- Thermal only: R59 million

- With storage (3-12 hours): R79 million - R143 million

- Thermal only: R58 million - With storage (3-12 hours): R71 million -

R110 million - Heliostats account for 38% of the

capital cost of tower plants with storage, while receivers account for 10%. Thermal storage accounts for 6%; the power block 14% and the tower 2% (World Wildlife Fund, 2015)

Fixed O&M, (ZAR/MW-yr)

- Thermal only: R0.9 million

- With storage (3-12 hours): R0.9 million – R1 million

- Thermal only: R0.8 million - With storage (3-12 hours): R0.86 million

– R0.9 million

LCOE (ZAR/MWh)

- Thermal only: R4 215 - With storage (3-12 hours):

R4 366 - R4 628

- Thermal only: R3 598 - With storage (3-12 hours): R3 213 -

R2 772

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The learning curve of the concentrated solar technologies is presented in Figure 2-19 and Figure 2-21, with the latest bid window of the REIPPPP coming in at an average price of R 2,020/MWh (Bischof-Niemz, 2017). 2.3.1.4 Solar chemistry Solar chemistry involves using solar radiation as an energy source in the chemical processing of materials and the production of fuels. Solar energy can either completely replace or partly substitute other sources of fossil fuels which are used to provide heat in chemical processes. Examples of technologies where solar energy is applied include water electrolysis (dissociation of water into oxygen and hydrogen, separation of methane (to separate the hydrogen and carbon though a catalyst – the carbon is combined with the oxygen in the air to produce CO2), thermochemical water separation and carbon dioxide reduction. The development of electrolysis and fuel cell technologies has been continuing for a number of decades as a research field (Murray, 1986, Friedland, 2001, and Sartory et al, 2017). Current efforts focus on costs and efficiency improvements (Sartory et al, 2017). These technologies are only competitive in niche markets but at a commercial scale. Generalised solar fuel production is shown in Figure 2-22. In this closed cycle process materials are cycled between energy storage and energy depleted states separated by energy transfer through a heat exchanger or another mechanism to provide useful heat or work. The production of fuel uses an open system where “Energy charged storage” is fuel that is extracted and “Energy depleted storage” is water, CO2 or other compounds at lower energy states. As fuels are produced additional feed materials need to be added to the system.

Figure 2-22: Generalised reversible endothermic chemical reactions driven by solar heat to store energy (Lovegrove, 2013)

Generation of electricity from the ammonia dissociation and ammonia synthesis cycle, with the aid of solar energy, is demonstrated in Figure 2-23.

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Figure 2-23: Ammonia based thermochemical electricity production (www.solar-fuels.org)

Fuels and hydrogen carriers which can be produced from solar energy include (Lovegrove, 2013): • Hydrogen (H2):

Can be produced from electrolysis and thermochemical processes. Combustion of hydrogen with air produces water. The energy density of hydrogen is low in a gas state form and it needs to be cooled and compressed for before being stored or used as a transport fuel (pressures for vehicle fuel tank storage are in the range of 350-700 bar, (Eberle, 2012)).

• Methane (CH4): Can be produced in the water gas reaction and later used in liquefaction, (e.g. PetroSA). The project would be costly but possible. Methane rich gas can also be synthesised from coal (e.g. Sasol).

• Methanol (CH3OH): Methanol is the simplest hydrocarbon liquid but is carcinogenic and has a lower energy density than current oil based fuels.

• Di Methyl Ether (CH3OCH3): Can be used as a transport fuel but needs to be stored at an elevated pressure to maintain in the liquid state

• Ammonia (NH3): Can be used as a hydrogen carrier made with nitrogen from the air. There is however a caustic risk.

Value chains for the production and use of solar fuels are illustrated in Figure 2-24.

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Figure 2-24: Production and use of solar fuels (RSC, 2012)

Solar fuels produced using solar energy provide a means to store and efficiently transport renewable energy due to their higher energy density and fluid form compared with the primary solar energy. Carbon dioxide from fossil fuelled power plants equipped with carbon capture technologies can provide the carbon to be used in the production of these fuels (the carbon capture and utilisation study at SANEDI is currently considering this). The production of hydrogen as a direct fuel, as a component used in chemical processes to produce other fuels or as a feedstock for other materials production is a key focus of research programs such as SolarPACES (Solar Power and Chemical Energy Systems) of the IEA. The EU has also funded solar fuels research such as the Hydrosol projects, the latest of which is a Hydrosol plant to demonstrate the production of hydrogen using CSP (Sattler, 2015). In the US, both Sandia National Laboratory and the US Airforce have active programmes in this area, (Biello, 2010). Within the South African context the following processes have been considered at a research level for the use of solar energy in chemical and fuel processing (Roos, 2013):

• Solar melting of aluminium - CSP • Thermal desalination • Solar fuels – using CO2 to make aviation fuel

• The current method uses: steam methane reforming (PetroSA & Sasol): o CH4 + H2O + combustion heat → CO + 3H2 → fuel by Fischer Tropsch

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• This can be replaced by the Solar method: Solar heat replaces combustion heat o CH4 + H2O + concentrated solar heat → CO + 3H2 → fuel by Fischer Tropsch

• In addition one can replace H2O with CO2 captured from power stations & FT plants o CH4 + CO2 + concentrated solar heat → 2CO + 2H2 → fuel by Fischer Tropsch

• Solar calcination of CaCO3 to CaO for cement industry • Solar water splitting to generate hydrogen • Solar gasification of coal

The price of various energy carriers and the cost to produce energy carriers from solar technologies are compared in a common unit of R/GJ in Table 2-8. The costs provided show that solar heat energy costs solar steam reformation can compete with current conventional fuel on a cost per unit of energy basis. Table 2-8: Comparison of solar fuel costs with conventional fuel prices

Energy Type R/GJ for 2017 Source of data South African coal price (export) 42 globalCoal.com (June 2017 Richards Bay)

Crude oil price 115 International Energy Agency (Brent crude 2017)

Basic Fuel Price Diesel 133 Department of Energy basic fuel price media release July 2017

Basic Fuel Price Petrol 154 Department of Energy basic fuel price media release July 2017

Wholesale electricity 175 Eskom, standard tariff low demand season

Concentrated solar heat (in Heat Transfer Fluid) 121

CSP in Australia analysis, Lovegrove et al (2012) (adjusted for exchange rate and inflation)

CSP electricity 347-778

R327/GJ REIPPPP bid window 4, IPP office (2016) R778/GJ - CSP in Australia analysis, Lovegrove et al (2012) (adjusted for exchange rate and inflation)

Hydrogen by PV electrolysis 743 Estimate from Lovegrove 2013 (adjusted for exchange rate and inflation)

Hydrogen by general electrolysis 600-1000 Correspondence with Hydrogen South

Africa

Hydrogen produced from Natural Gas Reformation 300 Correspondence with Hydrogen South

Africa

Hydrogen by steam reform 149 Estimate from Lovegrove 2013 (adjusted for exchange rate and inflation)

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2.3.2 Biomass Biomass is any organic material, which is available on a renewable basis. Different biomass feedstock will have different characteristics, availability, related logistics and energy content. The IEA divides potential feedstocks into four main categories (cited in IEA-ETSAP and IRENA, 2015a):

• Wastes such as domestic waste and certain types of low quality bio-oil • Processing residues such as saw mill dust • Locally collected feedstock such as wood chips • Internationally traded feedstock such as pellets, upgraded biogas and bio-oil

In South Africa the low rainfall rate, coupled with the low and degrading carbon soil content, limits the availability of existing plant based biomass and the ability to generate large scale agriculturally-based biomass projects. Furthermore sustainable forestry practices are imperative where plant based biomass sources are considered. The uses of ‘waste’ biomass by-products (which range from abattoir wastes, food waste, and agricultural wastes) therefore present greater opportunities for renewable energy generation as these by-products often represent a liability and their disposal methods (for example landfilling or incineration) can result in the release of GHG emissions and other pollutants into the atmosphere. In addition, due to mandatory rehabilitation requirements on industry in South Africa, there may be potential for biomass production where degraded land may be converted into areas that facilitate biomass to energy projects. The provision of clean and sustainable energy is a priority in both South Africa and further abroad. The development of biomass to energy projects therefore has the potential to be one of the measures required to counteract the unsustainable harvesting of firewood which has negatively impacted on ecosystems and rural communities in sub-Saharan Africa (Wessels et al, 2013). South Africa’s Department of Environmental Affairs has accordingly outlined various main mitigation streams associated with biomass use and the related value chain elements, illustrated in Figure 2-25.

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Figure 2-25: Value chain elements of South Africa’s mitigation streams, (Department of Environmental Affairs, n.d.2)

The opportunities for biomass hybridisation with fossil fuels in South Africa range from heating, cooling and electricity generation. Biomass is typically pre-treated to improve feedstock characteristics, energy density and make handling, transport, and conversion processes more efficient and cost effective. The most common forms of biomass pre-treatment include drying; pelletisation and briquetting; torrefaction and pyrolysis. For the production of liquid biofuels, technologies can include hydrothermal treatment (including pyrolysis and torrefaction). For gaseous fuels pre-treatment or production, technologies include anaerobic digestion, pyrolysis, hydrothermal upgrading and thermochemical gasification (IEA-ETSAP and IRENA, 2015a). These enhanced biomass energy forms can be used in hybrid solutions. An example of the pre-treatment of biomass prior to the co-firing in biomass power and heating facilities is presented below. There are various co-firing technology options which include direct co-firing, indirect co-firing and parallel co-firing, illustrated in Figure 2-26.

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Figure 2-26: Co-firing technology options, (IEA-ETSAP and IRENA, 2015a)

Baxter and Koppejaan’s research for the IEA (cited in Rycroft, 2015) finds that co-firing in combined heat and power facilities is currently the most competitive option to exploit the biomass energy potential for both electricity and heat production. Accordingly in 2015, the global contribution of bioenergy to final energy demand for heat in buildings and industry was found to far outweigh the use of biomass for electricity and transport combined, illustrated in Figure 2-27.

Figure 2-27: Global share of biomass in total final energy consumption and in final energy consumption by end-use sector (REN21, 2017b)

Different biomass types are better suited to the various energy services offered. Typical energy densities of biomass, compared with anthracite coal, anthracite coal, are illustrated in Figure 2-28.

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Figure 2-28: Energy density of biomass and coal, (IEA Technology Roadmap cited in IEA-ETSAP and IRENA, 2015a)

The broad key components and measures related to biomass heating, cooling, electricity generation and biomass fuels production in South Africa are outlined in Table 2-9.

Table 2-9: Typical biomass components and measures

Component: Measure Location applicability

Location will depend on the type of biomass source and its application. In addition, biomass resources are dispersed across the South Africa, and thus it is a very location specific resource and not applicable everywhere. Biological sources of waste biomass (such as wastewater and abattoir waste, among others) are found across the country and are typically less sensitive to issues of water scarcity and seasonal variability than woody biomass sources. Accordingly, the Department of Environmental Affairs (n.d.2) reports that there is significant opportunity for anaerobic digesters at a farm scale, as well as in households that currently do not use electricity for cooking and heating. The use of waste streams as an energy resource may however result in lengthy Environmental Impact Assessment and governmental approval processes which can hinder the project implementation (SANEDI, 2014). The eastern coast of South Africa is typically wetter than the interior and western regions, meaning that plant based biomass sources proliferate better in these regions making them ideal locations for biomass powered facilities. Large scale hybridisation with coal-fired power stations would however likely limit the location of such projects to the Mpumalanga province (Department of Science and Technology, 2017), which is also characterised by commercial forests and, to a lesser degree, agricultural activities. The sustainable sourcing of large quantities of the biomass may also pose issues. The challenge that biomass supply may be constrained by competition for the resource as well the variability of seasons which impacts the production of rain-fed agriculture/forests in South Africa is also an issue. Furthermore, unlike the

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Component: Measure European Union, South Africa does not have extensive capacity to utilise biomass resources.


Widely available globally.

Technology maturity

Large-scale biomass combustion plants to produce heat (and by extension, cooling) and power are commercially mature technologies (REN21, 2017a and Parsons Brinckerhoff, 2013), reflected in the South African Mkhuze (16 MW) and the Ngodwana (25 MW) biomass power stations which both comprise boilers and steam turbines (Ngodwana Energy, 2015 and Building Energy, 2014). The IEA (cited in IEA-ETSAP and IRENA, 2015a) indicates that combustion based technologies are currently the most mature in regard to biomass heating and cooling services. Thermal waste to energy is still in its infancy stage in South Africa. Market penetration remains low although there are opportunities for growth (Record, n.d). Small scale gasification (<0.3 MW) plants are available commercially. Demonstration plants in the range of 10-30 MW have been in operation since mid-1990s. The financial viability of biomass gasification on a large scale is not yet established (Boyle, 2004).


The distances related to the transport of biomass will dependant on the type of feedstock required. The lower moisture content and higher bulk density, the easier and less costly the feedstock is to transport and trade on a larger market. Securing sustainable, good quality and quantities of feedstock at affordable prices over a plant’s lifetime is a key issue for biomass projects. Biomass business cases are therefore sensitive to the distances of the biomass sources and the related transport costs.

Acceptability The potential for biomass power in South Africa is well documented and is supported by the ministerial determination that biomass should be a small part of the country’s electricity mix. However, biomass renewable energy projects have not had the market penetration of other renewables (such as solar) in South Africa indicating that there are barriers to entry in this market. For example, some applications, such as waste to energy, often face opposition from the public (Record, n.d). There are concerns that if plant based biomass projects are not implemented sensitively, the direct/indirect land use change that occurs as a result of such projects could increase lifecycle GHG emissions or could cause land degradation and negatively impact biodiversity and water resource availability (IEA-ETSAP and IRENA, 2015a). The issue around sustainably sourcing biomass feedstock is imperative to prevent such issues.

Economies of scale

The size of biomass generating units is generally limited by the availability of biomass fuel and the cost of transporting the fuel to the site. However, there are economies of scale that arise from large scale combustion.

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Component: Measure The IEA (cited in IEA-ETSAP and IRENA, 2015a) indicates that biomass sources from waste, process residues and locally collected feedstock have potential power generating capacities that range between 0.5 – 50 MW. Overall efficiency of biomass heating plants range from 80% – 90%. The efficiency depends on the size of facility, year of installation and energy content of the biomass feedstock. A wood chip installation larger than 20 MW is typically five percentage points more efficient than a 1-5 MW installation (Yale, 2017). Bio-digesters range in size from processing 1m3 for household units, to 10m3 for farm based plants and can be more than 1,000m3 for a large installation (Boyle, 2004).

The specific characteristics, technologies, typical costs and learning curves associated with biomass fuels production, biomass heating, cooling and electricity generation in South Africa are discussed in the following subsections. 2.3.2.1 Fuel production from biomass Solid, liquid and gaseous fuels can be produced from biomass. The transformation of biomass (primary energy) into fuels (secondary energy) creates higher quality energy carriers. Properties such as calorific value, density, consistency and purity are enhanced through transformation. The transformation also allows different components to be separated for different applications such as biochar for heating, biogas for electricity production and biofuels for transport from the original biomass. Four methods are used for converting biomass to other fuels: anaerobic digestion, fermentation (aerobic digestion), thermochemical thermochemical processing (pyrolysis, torrefaction, liquefaction and gasification) and mechanical oil production. These are discussed in the following subsections.

2.3.2.1.1 Anaerobic digestion (microbial digesters) Anaerobic digestion is used in the production of biogas, which is composed of methane and carbon dioxide. It involves a series of biological processes in which microorganisms break down biodegradable material in the absence of oxygen. There are four fundamental steps of anaerobic digestion which include hydrolysis, acidogenesis, acetogenesis, and methanogenesis. Anaerobic digestion technologies can convert a range of feedstocks such as; livestock manure, municipal wastewater solids, food waste, high strength industrial wastewater and residuals, fats, oils and grease, and various other organic waste streams into biogas. The process also produces nutrient rich digested solids which can be applied to cropland as a fertiliser (according to the relevant environmental regulations governing waste discharges) or converted into other products.

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In an anaerobic system gaseous oxygen is prevented from entering the system by containing the biomass feedstock in sealed tanks. The microorganisms (anaerobes) can access oxygen from the organic material itself or alternatively from supplied inorganic oxides from within the input material. In an anaerobic system the majority of chemical energy contained within the biomass is released by methanogenic bacteria as methane rich biogas. The produced biogas can then be combusted to generate electricity and heat, or can be processed into renewable natural gas and transportation fuels. To date the majority of the world’s biogas production occurs in the United States and Europe (REN21, 2017b). In the United States biogas is predominantly sourced from the collection of landfill gas while Europe is focused more on the anaerobic digestion of agricultural wastes. Other regions, including Asia and Africa, were taking up the technologies as of 2016 (REN21, 2017b). While these regions have started from lower levels, the growth rates have been comparatively higher. In Africa, biogas production has continued to expand, largely from municipal and agricultural wastes. In South Africa, renewable energy developer New Horizons teamed with gas firm Afrox to open the first energy-from-waste biogas plant near Cape Town, which was commissioned in 2017, at a cost of USD 29 million (ZAR 400 million) (REN21, 2017b). Usable waste is converted into various products, including organic fertiliser, liquid carbon dioxide, compressed biomethane, recyclables and refuse-derived fuel (Record, n.d). The New Horizons plant is the first of its kind in South Africa which demonstrates the barriers associated with developing such projects considering that the costs associated with the waste feedstock is low or zero. The Bio2Watt Bronkhorstspruit Biogas Plant, using animal waste as feedstock, is another example of an innovative biogas project implemented in South Africa which has overcome the barriers to implementation. The technology to produce biogas typically comprises of large, sealed, airless containers wherein bacteria biodegrade the biomass feedstock. Currently numerous different anaerobic digestion systems are commercially available. The configurations and costs of these plants differ depending on the type and volume of feedstock. It is well recognised (for example in South Africa’s Integrated Resource Plan) that the price of biogas and landfill gas in South Africa can vary considerably and will depend on numerous variables, such as the quality, the quantity, the longevity of the gas supply, the potential of interruption of gas flow, the operations and maintenance arrangement on the gas collection and supply system. On the one hand, many large landfills in South Africa flare the collected gas which is considered a waste stream, implying that the cost of this fuel in a landfill gas to energy project could be zero. However, the technologies to harvest and store such feedstocks have associated costs which need to be considered to establish whether they outweigh the benefits of a ‘zero-cost’ feedstock. Typical costs of a bio-digester plant setup costs between USD 50-75/m3 (ISAT, n.d.) which is the equivalent14 of ZAR 669- 1 004/m3. The bio-digester constitutes between 35-40% of these costs.

14 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR


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2.3.2.1.2 Aerobic digestion (fermentation) Aerobic digestion can be used to create bioethanol, a biofuel. Bioethanol is mainly produced by the sugar fermentation process, and is commonly produced from raw agricultural materials (biomass) containing sugars (Vohra et al., 2014). The main fuels or energy crops which serves as the sugar source for bioethanol include maize, corn and wheat crops, waste straw, willow, sawdust, reed canary grass, cord grasses, Jerusalem artichoke, myscanthus and sorghum plants. South Africa’s Biofuels Industrial Strategy (2007) proposes the use of the country’s sugar cane and sugar beet resources as feedstocks for the production of bioethanol. Agricultural crops are however typically water intensive to grow, which is one of the drivers related to ongoing research and development into the use of algae and municipal solid wastes to produce ethanol fuel. The production of ethanol can be separated in the following steps: fermentation of sugars, distillation, dehydration and denaturing. Before the fermentation process, some crops require saccharification or hydrolysis of carbohydrates such as cellulose and starch into sugars. This process relies on enzymes to convert starch into sugar. The process requires mills to crush the feedstock and then industrial cookers to liquefy the starch or sugars (BFAP, 2005). The fermentation of the feedstock occurs in large sealed vats prior to distillation and processing. Microbial fermentation of the sugars is the process that produces the bioethanol. For the ethanol to be usable as a fuel, the water must be removed. The majority of the process water is removed by distillation. This will typically yield an ethanol purity of 95-96%, (BFAP, 2005). This may be used as fuel alone but further water removal treatment is required for it to be compatible to burn in combination with petrol, in petrol engines. This treatment is known as ‘dehydration’ and can be done through a physical absorption process using a molecular sieve, which permits the passage of molecules below a certain size, thus separating the water from the bioethanol. Brazil and the United States accounted for over 75% of all ethanol production in the world in 2015 (Renewable Fuels Association, 2017). Global production of bioethanol exceeded 97 billion litres in 2015 (Renewable Fuels Association, 2017). The idea of producing bioethanol from food crops is still a contentious moral issue in Africa (‘food versus fuel” debate). For this reason, the South African Biofuels Industrial Strategy (2007) excludes the use of food crops such as maize as well as land areas where food crops are grown. There are six manufacturers of fermentation ethanol in South Africa and Swaziland. These manufactures produce bioethanol from molasses as the feedstock (Department of Energy, n.d.2). The product is used in industrial and commercial applications, for example in the liquor industry, solvent applications and pharmaceuticals, but is not currently used at a large scale as fuel in the region. Although Swaziland made a commitment as part of its Intended Nationally Determined Contribution to the UNFCCC, to introduce the commercial use of a 10% ethanol blend in petrol in the country by 2030. The annual production capacity is summarised in Table 2-10.

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Table 2-10: Summary of the ethanol producers in South Africa and Swaziland (Department of Energy, n.d.2)

Company Name Annual Production Capacity (m3) NCP Alcohols 55 000 Illovo Sugar - Meerbank 48 500 Royal Swazi Sugar Corp 45 000 USA Distillers 32 000 Glendale Distilling Co. 5 000 Greenpoint Alcohols 5 000

There is much anticipation from these producers and aspirant bioethanol producers for the implementation of the South African Biofuels Regulatory Framework (2014) in South Africa which is still in draft form. The subsidies proposed in the framework will present an opportunity for these producers to develop a market for bioethanol as a fuel. South Africa’s Biofuels Industrial Strategy (2007) targeted a 2% penetration of biofuels in the liquid fuels supply. The Department of Energy have conducted research on the manufacturing costs of the bioethanol. It was determined that the cost of bioethanol would be approximately R6.5/litre in 2017 (adjusted by inflation) (Department of Energy, 2010). It was determined that manufacturing bioethanol from sorghum would be the most financially and socially appropriate route. The reference plant for production was 158,000 m3/annum of bioethanol at an estimated capital cost of R 2.13 billion.

2.3.2.1.3 Thermochemical transformation Thermochemical transformation uses the application of heat in a low oxygen environment to convert biomass into solid, liquid and gas hydrocarbon compounds (Clifford, 2017). Examples of thermochemical transformation include pyrolysis, torrefaction, gasification and liquefaction. The difference between these processes is the temperature at which they occur and the addition of other elements or compound (e.g. hydrogen or water). Torrefaction uses temperatures in the range of 200-300°C, pyrolysis uses temperatures >400°C and gasification involves temperatures >700°C, (Tumuluru et al., 2011). Liquefaction uses the products of gasification (primarily hydrogen and carbon monoxide) together with steam to produce liquid fuels. When biomass is heated at such temperatures, the moisture evaporates and various low-calorific components contained in the biomass are driven out. The rate at which the heating occurs also influences the mixture of components produced from the biomass (Hanif, 2016). Higher rates of heating result in more gaseous and liquid hydrocarbon molecules (e.g. water, methane, ethane, propane, butane and longer more complex hydrocarbon chains) whereas lower rates produce more solid materials (solid carbon or biochar) (Hanif, 2016). The process is maintained by the heat from partial combustion of some of the biomass during this process. Heat released during the reaction can be used to raise steam for a steam turbine or used to drive an Organic Rankine Cycle turbine to drive a generator to generate electricity. Balancing the trade-off between the products of the thermochemical processes such as solid, liquid and gas

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fuels, heat and electricity is determined by the value of these products and the operational ranges of the specific technology deployed. Torrefaction of biomass results in a high grade solid biofuel with higher energy density and calorific value than the original feedstock (Chen et al, 2015). The product can be used as a replacement of coal in electricity and heat production and as input for gasification processes in the production of high value bio-based fuels and chemicals. The biochar can be used as charcoal, blended with other solid fuels or ground for non-energy uses. The biochar is mainly organic waste and has very advantageous properties for soil rejuvenation and carbon sequestration. The lower density liquid and gas products produced during the torrefaction and pyrolysis processes may also be used to fuel internal combustion engines or gas turbines to generate electricity (Chiaramonti et al, 2007 and Fan et al, 2011). The lower density liquids are however typically water soluble and corrosive, which may require a conversion process to produce engine friendly fuels. Kirkels and Verbong (cited in UNIDO, 2010) and Parsons and Brinckerhoff (2013) consider biomass gasification to be in development phase as no dominant design has emerged yet. Kirkels and Verbong’s research indicates that gasification technologies are unable to compete with other biomass technologies, and technology standardisation is needed to ensure proper operation. In South Africa however, research related to and commercial applications of gasification technologies are ongoing, with a view to establishing the technical and economic viability of the technology, (GTZ, 2014).

2.3.2.1.4 Biofuels directly from plants Biofuel produced from biomass oils are quite different from the liquid fuels described above (ethanol) (Boyle, 2004). These oils occur naturally in the seeds of many plants and are extracted by crushing. The typical energy content of 37-39 GJ per tonne of oil is only slightly lower than that of diesel (Boyle, 2004). Oil seeds that can be used are rapeseed, canola, soybeans, mustard, sunflower, castor bean and other warm climate feedstocks such as palm oil, Jatropha and Moringa. These oils can be burnt in diesel engines either in a blended or pure mixture (Boyle, 2004). However, there are challenges with incomplete combustion in these oils and this can lead to carbon build up in cylinders. As such the conversion of these oils to a biodiesel is preferred. The conversion process of oils to biodiesel is called transesterification and involves adding methanol or ethanol to the oil from the harvested biomass (Boyle, 2004). No engine modifications are required to use biodiesel produced in this way. In addition, glycerol may be produced. In 2016 global production of biodiesel rose to 30.8 billion litres (REN21, 2017b). Biodiesel production is more geographically diverse than bioethanol production, with production spread among many countries (REN21, 2017b). In 2016, the leading countries for production of biodiesel were the United States (18% of global production), Brazil (12%), and Indonesia, Germany and Argentina (each with 10% of global production). The recent increase in biodiesel production was due mainly to restored production levels in Indonesia and Argentina and to significant increases

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in North America. South Africa has however been slow to take up biodiesel production, as the anticipated policy incentives have still to be approved. The Department of Energy’s Draft Position Paper on the South African Biofuels Regulatory Framework (2014) has not yet advanced to the stage of a bill. South Africa’s Biofuels Industrial Strategy (2007) targeted a 2% penetration of biofuels in the liquid fuels supply. This target will require only about 1.4% of national arable land, which is not a significant percentage given that nearly 14% is currently underutilised. Ongoing research by the University of the North West indicates that the production price of biodiesel is between R6 and R7 per litre15. This range is aligned with past work undertaken by the Department of Energy which estimated that the manufacturing costs of the biodiesel based on 2010 values would be approximately R5.64 per litre (Department of Energy, 2010). The Department of Energy determined that manufacturing biodiesel from soya beans would be the most financially and socially appropriate route. The reference plant for production was 113 000 m3/annum of biodiesel at an estimated capital cost of R 1.14 billion. It is important to note that the use of biodiesel-blends can impact engine warranties, which may constrain uptake. 2.3.2.2 Biomass heating and cooling Biomass feedstocks for heating systems can include wood, agricultural crops or residues, plant and woody energy crops, municipal organic wastes as well as animal manure. These can be used in solid, liquid or gaseous forms to produce heating or cooling. In 2016 bioenergy accounted for almost 90% of global renewable direct heat use, where bioenergy used for heat in buildings and industry outstripped the combined use of biomass for electricity and transport (REN21, 2017b). Biomass heating and cooling technologies include fluidised bed combustion or grate furnaces for two-phase combustion processes (Yale, 2017). Biomass feedstocks for these energy services typically require pre-treatment processes discussed in section 2.3.2.1. The technologies to convert biomass feedstocks into heating or cooling services are similar in nature, where additions such as absorption chillers provide the cooling element. Absorption chillers use heat rather than electricity as their driving energy source. Biomass hybridisation with coal boiler power plants is largely achieved by either co-firing or through the installation of a dedicated biomass boiler to provide steam to the high-pressure feed heaters, preheaters or reheater. A study by Parsons Brinckerhoff (2013) for the Australian Renewable Energy Agency found that biomass hybridisation using an additional biomass boiler appears to be less effective than the co-firing options in the assessment. A biomass mix of up to 12.5% can be achieved through the use of proven technologies for co-firing of biomass and coal and a maximum biomass mix of 8.5% can be achieved through the use of a dedicated biomass boiler (Parsons Brinckerhoff, 2013). 15 Personal correspondence with Professor Marx of the North West University, 24 October 2017.

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Co-firing coal and biomass feedstocks in combined heat and power plants has been shown to increase the total energy efficiency (70%-90%) of purely biomass facilities (IEA-ETSAP and IRENA, 2015a). This says that producing heat and power from a pure biomass facility is not as effective as producing it from a hybrid coal-biomass facility. As such, hybrid systems for heating and cooling services must be specifically designed to match the properties of the feedstock in question, to ensure clean and efficient combustion and to avoid corroding of the equipment. Biomass co-firing in coal power plants does require significant boiler retro-fitting, which may however be less capital intensive than commissioning greenfield biomass power stations (IEA-ETSAP and IRENA, 2015a). Forest residues, grasses, wood chips, sawdust, sawmill residue or pellets are typical co-firing feedstocks. The Parsons and Brinckerhoff (2013) Australian study found that in utility-scale pulverised coal boilers, biomass feedstocks are typically between 1 and 5% of the energy input. On a technical level, bioenergy is well suited for industrial processes that require high temperature end uses such as heating or cooling needs. The low penetration level of biomass technologies in the South African market therefore points towards non-technical barriers. These relate more to the sustainable sourcing of biomass and the regulatory barriers around using organic waste streams and energy sources. The IEA (2014b) indicates that biomass based heating applications in industry and residential sectors are becoming increasingly cost competitive, illustrated in Figure 2-29, demonstrating the learning curves occurring in this sector internationally.

Figure 2-29: Biomass-based heating costs (USD/MWhth), (IEA, 2014b)

Key costs related to biomass-based heat and cooling activities are detailed in Table 2-11.

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Table 2-11: Typical biomass heating and cooling costs

Component: Measure (IEA-ETSAP and IRENA, 2015a): Capital costs - Biomass-based combined heat and power: USD 4 million/MW to

USD 7 million/MW (ZAR 54 million – ZAR 94 million)16 - Retro-fitting coal power plants for biomass co-firing: USD 0.14 million to

USD 0.85 million/MW (ZAR 2 million to ZAR 11 million)17 - The cost of anaerobic digestion power systems ranges from

USD 2.6 – 6.1million/MW (ZAR 34.8 million to ZAR 81.6 million)18. LCOE costs Refer to Figure 2-29 above Feedstock costs

Typical biomass feedstock costs (excluding transport) vary according to the type of waste:

- Waste: negative to no-cost - Processing residues: no-cost to USD 4/GJ - Locally collected feedstock: USD 4 to USD 8/GJ - Internationally traded feedstock: USD 8 to USD 12/GJ

2.3.2.3 Biomass electricity generation Biomass power plants use direct combustion technologies such as burners and boilers which include the likes of water-cooled, vibrating grate boilers (fixed bed) and various fluidised bed technologies including bubbling and circulating fluidised bed combustion boilers (IEA-ETSAP and IRENA, 2015a). The global generation of electricity from biomass sources is reported to have increased by 6% in 2016, with rapid growth in the European Union and in Asia (REN21, 2017b). The potential capacity for biomass-generated electricity in the Southern African Development Community is estimated at 9,500 MW, based on agricultural waste alone (REN21, 2015). Electricity generation from biomass has been identified as an important part of South Africa’s energy mix and has been included in the country’s Integrated Resource Plans as an eligible energy source in the Renewable Energy Independent Power Producer Procurement Programme. The EPRI report (2015), which outlines power generation technology data for South Africa’s latest Integrated Resource Plan, considers the electrical potential of biomass from feedstocks such as forest residues, municipal solid waste, landfill gas and biogas. The EPRI report defines a potential for nearly 1,500 MW of biomass-generated electricity within South Africa. Of this, nearly half is from municipal solid waste. The EPRI figure of 1,500 MW is considerably higher than the ministerial determination of 345 MW provided for the biomass, biogas and landfill gas categories under the Renewable Energy Independent Power Producer Procurement Programme, which points towards the cost barriers associated with the realisation of the full biomass potential in the country.

16 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR 17 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR 18 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR




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The benefits of electricity generation from biomass sources include the advantage that biomass fuels can generally be produced, concentrated, and stored for use when it is economic to do so, meaning that they can provide dispatchable, non-intermittent renewable power. The use of biomass sources for electricity generation may also have other co-benefits, such as reduced air pollution and wastes, reduced surface and groundwater contamination or increased sanitation and hygiene, among others (EPRI, 2015). The use of biomass boilers to produce electricity is a mature and well-proven technology, where stoker grate boilers utilising biomass were developed as early as the 1920s (EPRI, 2015). Recent biomass to electricity generation examples in South Africa include the Mkuze (16 MW from sugar cane waste) and the Ngodwana Biomass Power Station (25 MW from sustainable plantations). These projects have been awarded preferred bidder status in the country’s large scale renewable power procurement programme. The Mkuze and the Ngodwana power plants are the only two biomass projects to be awarded preferred bidder status in the renewable energy procurement programme. Their sources of biomass (sugar cane wastes and sustainable forestry) point to where the potential for biomass to energy lies and also of the barriers that constrain widespread rollout of similar biomass power projects, of a similar size. Biogas projects also present opportunities for electricity generation through hybridisation with fossil fuels. The sources of raw material for biogas include organic waste, sewage, restaurant waste, municipal waste, agricultural residues and landfill. The South African Terrestrial Carbon Sink Assessment estimates that the total GHG mitigation potential of biogas from farm manure is in the region of 3.6 million tCO2e (Department of Environmental Affairs, n.d.2). Biogas from this source is identified as one of the largest climate change mitigation opportunities within the land-use sector in South Africa. Electricity from biogas can be generated through the use of digesters which aid the production of methane which can subsequently be fed directly into a gas-fired combustion turbine, creating electricity. Examples of biogas projects in South Africa include the 4.4 MW Bio2Watt biogas generation project in Bronkhorstspruit which uses methane from cow dung decomposition to fire a boiler and generator. The 4.2 MW biogas project at the State owned PetroSA refinery in Mosselbay is another example, which utilises waste process water which is passed through anaerobic (oxygen-free) digesters. The PetroSA project is also registered with the Clean Development Mechanism, which enables the facility to generate and trade in certified emission reductions that accrue from the activity. The ability of biomass projects to earn certified emission reductions or other carbon credits enhances their economic feasibility and potential for implementation. Biogas production from landfill and municipal wastes is also developing in South Africa with the potential to expand. Bacteria in landfills decompose waste and in the process generate gases which can be used to generate electricity. The general composition is about 45% methane and 40% carbon dioxide, with smaller concentrations of nitrogen, oxygen, ammonia and sulphides (EPRI, 2015). Typically, peak production of landfill gas occurs a year after material has been deposited in

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the landfill, and has a generation lifespan of two decades (Earth Works, n.d). Landfill gas is currently used in South Africa more typically for rural heating application than for electricity generation. There is therefore potential for this resource to expand (EPRI, 2015). Furthermore landfill gas is not wide used for energy purposes in South Africa, as less than 10% of South Africa municipalities generate electricity from waste to energy processes (Record, n.d). The conversion of waste to energy is a form of energy recovery. Most activities of this kind processes produce electricity and/or heat directly through combustion, or produce a combustible fuel commodity, such as methane, methanol, ethanol or synthetic fuels (Record, n.d). The proximity of biomass fuel sources to fossil fuel facilities for hybridisation is again a key consideration, as the transportation of biomass, or the biogas product, over long distances will negatively impact the financial viability of such projects. Power stations that utilise landfill or municipal solid waste are likely to be located near population centres where such waste will be readily accessible. Large-scale hybridisation opportunities with coal-fired power stations will therefore be limited.

In some cases, biomass sources are also commodities which have both material and energy values. Wood waste markets, for example, can include feedstocks for particleboard. As a result, fuel pricing is highly sensitive to the area in which the biomass is located and the competitive pressures of local and regional economies (EPRI, 2015). Biomass to electricity projects in South Africa continue to face financial barriers to implementation that have been largely overcome by other mainstream renewable technologies such as solar and wind. The evidence of these barriers is the low penetration rate of biomass technologies in the South African market and also the low learning rates (biomass electricity prices in the Renewable Energy Independent Power Producer Procurement Programme have reduced by just under 3% from the prices in bid window three where biomass projects were first awarded preferred bidder status). The result is that levelised costs of electricity from biomass sources (R1.45/kWh) are currently the highest compared with the other renewables in the procurement programme (Department of Energy, 2015b). Key costs related to forestry residue, municipal solid waste, landfill gas and biogas power technologies are outlined in Table 2-12 (as per EPRI, 2015). Feedstock costs can comprise between 40%-50% on the total electricity production cost. Operating costs are typically 3%-5% of the capital cost for large capacity, 5%-6.5% for small capacity and 2.5%-3.5% for co-firing power plants (IEA-ETSAP and IRENA, 2015a). Table 2-12: Typical biomass power generation costs

Cost component (EPRI, 2015):

Forest residues (25 MW)

Municipal solid waste (25 MW)

Landfill gas (5 MW)

Biogas (5 MW)

Plant Cost Estimates: Overnight (ZAR/MW)

R68 million R131 million R28 million R71 million

Fixed O&M, (ZAR/MW-yr) R1.5 million R6 million R2 million R1.7 million

LCOE (ZAR/MWh) R2 017 R3 457 R897 R1 597

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2.3.3 Wind Wind has been used for centuries to provide motive power for sailing ships, pumping water and milling of grains. In the modern era wind is also increasingly being used to generate electricity, where wind power accounted for 4% of the total global renewable power sources in 2016 and 34% of new renewable power facilities installed in 2016 (REN21, 2017b). Wind is a variable source of energy and therefore the ability to hybridise wind technologies with more reliable energy sources, for example back-up diesel generators or even other complementary renewable technologies, presents increased power management opportunities (Rycroft, 2013). The broad key components and measures related to wind energy in South Africa are outlined in Table 2-13. Table 2-13: Typical wind components and measures


Refer to Figure1-8 of Chapter 1 for South Africa’s latest wind atlas. Research by the CSIR (2016a) indicates that almost the entire country is suitable for wind generation with potential for high load factors. Dispersed wind generation reduces the variability of wind across the grid as wind in one location will compensate for lack of wind in another location.


Wind hybrid systems are ideally located onsite or in close proximity to end users as transporting the electrical or mechanical power will increase capital and operational loss, and will also result in efficiency losses.


Most large wind turbines are imported. South Africa however has a large scale wind tower manufacturing factory in Atlantis, Western Cape (Department of Energy, 2015a) and there is potential to increase localisation of wind components. The Department of Trade and Industry’s wind localisation study indicates that the localisation of wind energy technologies could support the development of up to five wind tower manufacturing facilities in the country, as well as a blade manufacturing facility and a facility to assemble nacelles and hubs (Department of Trade and Industry, 2015). Under the Department of Energy’s renewable energy power procurement programme, the average local content for wind projects under Bid Window 3 was 46.9%, three quarters of which was derived through localisation of the balance of plant and the rest through the procurement of wind towers from the local tower manufacturer (Department of Trade and Industry, 2015).

Technology maturity

Wind technologies are maturing and are continuing to evolve, driven by mounting global competition (REN21, 2017b).


Due to the remote locations of wind farms, access roads and grid connections often need to be improved.

Acceptability Uptake of large wind power facilities and small scale mechanical wind power technologies in South Africa have been widely supported. Small scale wind power technologies have not been widely taken up.

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Component: Measure: Economies of scale

From a practical point of view, the modular nature of small scale wind turbines lends the technology to installation on commercial or residential sites. Turbines for residential and commercial buildings which are larger in size than micro scale (for example greater than 5kW) may however need to be located further away from the point of use of electrical power due to visual and audio impact. Such installations may therefore require more initial accessories which will increase the capital expenditure required (Whelan and Muchapondwa, 2011). Wind is a fluctuating resource and cannot be scheduled like conventional power plants. However variability of wind decreases with increasing scale of the power supply system as many short-term fluctuations are balanced by a spatial smoothing effect (CSIR, 2016a).

Wind for electricity generation and for mechanical power are discussed further in the following subsections. 2.3.3.1 Wind electricity generation Wind energy technologies use the energy in wind to generate electricity. Wind is a result of the sun’s uneven heating of the atmosphere, the earth’s irregular surfaces and the planet’s revolution around the sun. Most wind energy technologies can be used as stand-alone applications, connected to a utility power grid. For multi-megawatt sources of wind energy, a large number of turbines are usually built close together to form a wind farm that provides grid power. Small wind electric systems or small-scale turbines are also available to produce enough power for a single home, farm or small business (REN21, 2017a). Small-scale turbines can and have been used for a variety of applications such as residential electrification (providing for a range of energy services such as water pumping, battery charging or telecommunications, and are increasingly displacing the need for diesel in remote locations (REN21, 2017a). As such wind power can be used to hybridise fossil fuel powered electricity consuming equipment in South Africa. Small wind turbines can be either off-grid or grid-connected facilities. Off-grid facilities work independently from larger electrical systems and may be combined with energy storage systems such as batteries. Grid-connected installations feed electricity into larger distribution networks. Wind turbines in such systems supply energy to a grid connected inverter, (Record, n.d). During 2016, South Africa installed 418 MW of new wind capacity, with a cumulative total of 1 471 MW (GWEC, 2016). Actual wind capacity procured during the Department of Energy’s large and small scale Independent Power Producer Procurement Programmes amounted to 3.4 GW (Independent Power Producer Procurement Programme Office, 2016). The Eastern Cape has significant resource potential in terms of wind energy, representing 43% of the procured wind power (Department of Energy, 2015a). These developments support the findings that wind has become the least-cost option for new power generating capacity in an increasing number of markets (REN21, 2017a).

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The most common wind turbine configuration is the three-blade, upwind, horizontal axis design with a three stage gearbox, variable-speed generator and power electronics to generate 50/60 Hz power (EPRI, 2015). The primary components of an on-shore wind turbine include the tower and foundation, the rotor, the nacelle and drive train, rotor pitch and yaw systems, power electronics and electrical controls (Rycroft, 2013). There is the potential to hybridise diesel generators with wind turbines. This combination is often used in remote areas where wind is a strong resource but solar power is not so abundant that it could be used as a complementary source of power. The ability of diesel generators to ramp up and down at high rates makes diesel generators an ideal partner to wind turbines. Wind turbines can also be used to hybridise electricity consuming equipment, such as those in buildings, or auxiliary equipment at industrial facilities. The feasibility of wind power projects depends on factors such as economies of scale, wind speed factors and capital costs. Wind power was the most cost-effective option for new grid-based power in South Africa during 2016 (REN21, 2017b). Key costs related to wind power activities are detailed in Table 2-14. Table 2-14: Typical wind power generation costs

Component: Measure:

Plant Cost Estimates: Overnight

The total overnight costs for the large scale wind technologies considered by EPRI (2015) range from R23 million/MW for a 200 MW wind facility to R27 million/MW for a 20 MW plant. The uptake of small scale electric wind turbines is constrained by the relatively high capital costs compared with the prices of grid electricity. The local online trading portal Sustainable.co.za (2017) indicates that costs range from R36 500 for 1 kW turbines to nearly R100 000 for a 3.5 kW turbine.

Fixed O&M, (ZAR/MW-yr)

First year O&M costs for large scale wind turbines range from R0.5 million/MW-yr for a 200 MW plant to R0.6 million/MW-yr for a 20 MW plant (EPRI, 2015). Whelan and Muchapondwa’s study (2011) assumed the annual operation and maintenance cost of small scale turbines to be fixed at 1% of the initial capital investment throughout the turbine’s lifetime.

LCOE (ZAR/MWh)

The EPRI (2015) study considers different case studies that range in size (20 MW – 200 MW), capacity factors (22% - 46%) and wind speeds (5 m/s – 8 m/s). The average levelised costs of electricity for these wind case studies is R1 604/MWh.

The learning curve of the large scale wind power is presented in Figure 2-19, with the latest bid window of the REIPPPP coming in at a price of R 620/MWh (Bischof-Niemz, 2017).

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2.3.3.2 Wind mills/turbines for mechanical power In addition to wind for electricity production, it can also be used for mechanical power. Windmills use wind to drive a shaft which can be used to pump water, to mill grains or for use in drying and ventilation activities. Wind pumps are used today in many rural and remote locations where the costs of electrical installations of electric pumps and infrastructure are more expensive than direct wind driven pumps. These applications, at a small scale, can continue to provide useful energy services at farms and small industries applicably located with respect to wind resources, where grid electricity is conventionally used to power equipment. The variability of wind energy can be overcome when combined with other sources of energy. In the case of wind pumps, the variability of wind can be overcome by storing water in dams. The scale of these technologies is small (pico, <0.02 MW and micro level, 0.02 – 0.1 MW, (Klunne, 2010)) but the scope of application can be broad. Wind mills and wind pumps use the change of momentum of air as it moves through blades attached to a shaft. The rotating shaft from the windmill can be used for mechanical work. For example, the rotating shaft may be used to pump water using a cam mechanism to lift and drop a reciprocating pump (similar to a bicycle pump) to pump water out of a well, situated below the wind pump, into a reservoir. The reservoir is located at a higher elevation to where the water is needed and gravity is used to feed the water when required.

Figure 2-30: Wind pump used to pump water (http://www.ironmanwindmill.com/)

The local wind pump market in South Africa, is well established with over 200 000 installed wind pumps, (Stewarts and Lloyds, 2017). Wind pumps may be utilised in areas with low to mild breezes on a regular basis. Hybrid wind electric technologies can be used to drive the water pumping depending on the availability of wind or if excess wind is available, electricity could be produced in addition to the pumping of water. Due to the nature of the required mechanical power, wind pumps in hybrid systems will need to be located onsite or in direct proximity to the end-user. Typical costs associated with mechanical power from wind are provided in Table 2-15.

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Table 2-15: Typical mechanical wind power costs

Component: Measure: Capital Wind pump costs range between R40 000 and R75 000

depending on the average flow rate and pressure required (Stewarts and Lloyds, 2017).

Economies of scale A windmill water pump can pump between 10 000 and 100 000 l/day (Stewarts and Lloyds, 2017).

2.3.4 Geothermal Geothermal technologies exploit thermal energy in the Earth’s interior, stored either in rock, liquid water or trapped steam. Deep and enhanced geothermal technologies are typically used to generate electricity while ground source heat pumps and direct use geothermal technologies have the potential to provide direct heating and cooling services. In South Africa these services are currently catered for mostly through the use of grid electricity. There are three main types of geothermal resources (IEA, 2014b):

• Hydrothermal systems of naturally occurring water or vapour flows such as hot springs or geysers.

• Deep aquifers which are porous bedrock or fracture zones, which can typically be reached within a depth of 3 km, in which fluids are circulating.

• Conductive systems, which lack a natural flow of liquid. An artificial injection of water via fracking of the bedrock is required to access this energy.

Hydrothermal systems are present in South Africa and are typically used for leisure and recreation activities within spas or tourist resorts. To date, the thick and stable nature of South Africa’s craton has precluded extensive research into utilising energy from deep aquifers or conductive geothermal sources on the basis that geothermal technologies are not able to compete with other energy sources and technologies available in the country. Recent research however indicates that South Africa has some areas that have capacity to yield energy from relatively low temperatures (100–200°C) at depths ranging from 2-3 km (i.e. in deep aquifers) (Dhansay, De Wit and Patt, 2013). Low-enthalpy geothermal energy could therefore be a practical and viable renewable energy alternative in South Africa, under certain conditions such as a USD 25/MWh (ZAR 33519/MWh) renewable energy tax incentive (Dhansay, De Wit and Patt, 2013). South Africa is yet to consider such an incentive rendering geothermal applications economically unfeasible.

19 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR


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Geothermal energy also has the technical potential to be hybridised with fossil fuel applications used in industry and in steam-fired power stations, however at this stage this is not competitive with other renewable energy technologies. Typical geothermal components and measures are included in Table 2-16. Table 2-16: Typical geothermal components and measures


In general, South Africa has the potential to provide medium to high energy geothermal resources which are suitable for electricity generation. The Limpopo Belt has been identified as a possible target site for harnessing geothermal energy using enhanced geothermal systems. Namaqualand, south and west of Upington show geothermal heat flow values that are above the Earth’s average (Tshibalo et al, 2015).


The potential for the direct use of geothermal energy is limited geographically as well as by the proximity to suitable fossil fuel facilities where it can be used for hybridisation. In Chapter 1 of this report, the location applicability in South Africa is shown in Figure 1-11. Research by the IRENA (2015b) indicates that geothermal heat can be used as a source for low temperature process heat applications. The geothermal source and the end user must however be sufficiently close to one another.


The components (such as pumps and piping, heat exchangers) that make up geothermal energy facilities are widely available internationally and in South Africa.

Technology maturity

Mature (REN21, 2017b). Many of the technological components (e.g. well drilling, heat pumps) that make up geothermal systems are proven and widely used for other industrial applications. Less conventional geothermal technologies, such as enhanced geothermal systems, still need to be proven (IEA, 2011b).


Geothermal energy facilities should ideally be situated on the site where the energy will be utilised. Transporting heat or electricity will incur additional capital costs and will also result is efficiency losses.

Acceptability The application of geothermal technologies still needs to be proven in South Africa. Anecdotal evidence indicates that heating of residential swimming pools through the utilisation of geothermal energy is occurring. The IEA (2011b) finds that although geothermal electricity and heat can be technologically and economically viable in particular instances, the levelised costs of energy of developing technologies need to be reduced further in order for those technologies to compete.

Economies of scale

The economies of scale of larger heating facilities or those related to electricity generation are yet to be established, pending further investigations into the economic viability of geothermal energy utilisation in South Africa. Tshibalo et al (2015) have modelled a hypothetical 75MWe geothermal plant in South Africa, which is only financially viable with a feed-in tariff or incentive.

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Given the hypothetical potential for geothermal in South Africa, the technologies for electricity, heating and cooling are discussed below in relation to opportunities for hybridisation with fossil fuels. 2.3.4.1 Geothermal electricity generation

A first estimation by Campbell et al (2016) indicates that there is approximately 3,130 TWh of theoretical power capacity generation within the central and southern parts of the Main Karoo Basin. The study demonstrates the need for further investigations to gain a reliable data set to better understand geothermal potential in the basin and in other South African regions. Enhanced geothermal systems are technologies that exploit latent heat far below the earth’s surface for applications, such as electricity generation, that require high temperatures. Enhanced geothermal systems function by pumping a working fluid (mainly water) into a geothermal reservoir where it is heated up substantially by the surrounding hot rocks.

Figure 2-31: Deep or enhanced geothermal system (EPA, 2016)

The heated fluid is then pumped back to the surface and used in a binary generation system. Binary systems evaporate a low boiling point fluid which drives a turbine to produce electricity, illustrated in Figure 2-32 (Dhansay, De Wit and Patt, 2013).

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Figure 2-32: Binary-cycle geothermal power plant (Tshibalo et al, 2015)

Dry steam generation is another geothermal technology which is best suited for sources that are in the upper temperature range of between 200°C – 320°C. Dry steam is expanded directly in a steam turbine, passed through a condenser and returned back into the injection well (Johnson and Fourie, n.d). The economic viability of generating electricity from geothermal energy sources in South Africa has yet to be proven. Studies suggest that an additional Government incentive or tariff of USD25/MWh (ZAR33520/MWh) is required to make a 75MWe enhanced geothermal electricity production system economically feasible (Dhansay, De Wit and Patt, 2013). A financial model developed by Tshibalo et al (2015) established that the LCOE of a 75 MWe geothermal energy development in the Soutpansberg, Limpopo, would be 14 USDc/kWh (R1.87/kWh21), which included a feed in tariff of USD 25/MWh (ZAR 33522/MWh). The findings of the financial analysis undertaken by Tshibalo et al (2015) is broadly aligned with research by the IEA (2011b), where the LCOE of the enhanced geothermal system in Tshibalo et al’s model is at the lower end of the range provided by the IEA (Figure 2-33).

20 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR 21 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR 22 Based on an exchange rate of ZAR13.38/USD as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=USD&To=ZAR




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Figure 2-33: Production costs of geothermal electricity (USD/MWhe) (IEA, 2011b)

The IEA (2011b) further notes that internationally, the costs of enhanced geothermal systems are yet to be fully investigated, as there are few commercial plants in operation. Further research is required in order to better understand the economics associated with this technology in South Africa and abroad. 2.3.4.2 Geothermal heating and cooling Geothermal heat (excluding geothermal source heat pumps) can be used as a source for low temperature process heat applications. Costs increase and efficiencies decrease, the further the geothermal source and the end user are from one another (IRENA, 2015b). IRENA analyses indicate that low-temperature heat applications offer the largest potential in all industry sectors (excluding the chemical and petrochemical and the iron and steel sectors) that require medium- and high-temperature process heat. The IEA (2011b) finds that geothermal may be a financially viable source of energy for district heating (i.e. the distribution of heated water for space heating) where suitable resources and infrastructure are in place. South Africa does not have district heating systems, making this application unfeasible in the country at this stage. The United States Environmental Protection Agency (US EPA, 2016) considers ground source heat pumps, direct use and deep and enhanced geothermal systems to be the main types of technologies that are able to utilise geothermal heat sources. Ground source heat pumps utilise the difference between the above-ground air temperature and the subsurface soil temperature to move heat, in order to provide user services such as space heating and cooling, as well as water heating. The heat pumps are connected to a series of buried pipes either just below the ground surface or several hundred feet below ground. The heat pump circulates a heat-conveying fluid through the pipes to move heat from point to point (Figure 2-34).

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Figure 2-34: Heating mode of ground source heat pumps (EPA, 2016)

South Africa has relatively few heating degree-days compared with countries located in the northern hemisphere, which explains in part why this energy resource has not been pursued in the country. It is possible that increasing temperatures in South Africa will increase interest in the cooling potential that ground source heat pumps may provide. Ground source heat pumps require relatively small amounts of electricity to drive the heating/cooling process (US EPA, 2016). The hybridisation of ground source heat pumps with traditional electric technologies such as electric geysers or air conditioners has the potential to reduce carbon emissions by reducing dependence on grid electricity. Another cooling method entails the movement of heat from the ambient air in a building into the ground, cooling the building (US EPA, 2016), which may be explored further as the demand for cooling services increases. The natural low thermal variability in farm dams in the Western Cape, provided opportunities for precooling in the summer harvest season. Precooling reduced the demand for electricity from the grid by the wine industry. Direct use geothermal systems use groundwater that is heated (93°C or higher) by natural geological processes below the earth’s surface. For such applications to be feasible, the hot water needs to be accessible at relatively shallow depths, (Figure 2-35). This source of renewable energy may be hybridised with fossil fuels in many applications including large-scale pool heating; space heating, cooling, and on-demand hot water for buildings; district heating (i.e. heat for multiple buildings in a city) and some industrial and agricultural processes (US EPA, 2016). Anecdotal evidence indicates that heat pumps that utilise geothermal energy are being used in South Africa to heat residential swimming pools.

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Figure 2-35: Geothermal direct use (EPA, 2016)

Deep and enhanced geothermal systems are described above in section 2.3.4.1 and Figure 2-31. A comparison of typical geothermal heat production costs compared with electricity and natural gas-based heating is provided in Figure 2-36. Few costs and trends regarding geothermal components and measures in South Africa are available, however the US EPA (2016) notes that capital costs – especially drilling test wells and production wells – can be financially challenging.

Figure 2-36: Geothermal heat production costs compared with electricity and natural gas-based heating (IEA, 2014b)

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2.3.5 Small and micro scale hydro In Southern Africa the total installed capacity of small hydropower (plants up to 10 MW capacity) reported internationally amounts to 62.5 MW as of May 2016 (Klunne, 2016). According to these reports South Africa has a total installed capacity of 50 MW of small hydropower, and a proven potential of 247 MW (Klunne, 2016). South Africa’s energy regulator does not report on the number of small scale hydro power facilities installed in the country. However according to an online database of hydropower in South Africa it indicates that the country has a total installed capacity of 110 MW of small scale and micro hydro power plants that are operational in the country (Hydro4Africa, 2017). The discrepancies in the operational capacity figures indicates that there is a lack of consensus on the installed capacity of small scale and micro hydro that is currently in operation in the country. The Integrated Resource Plan for South Africa, through the Renewable Energy Independent Power Producers Procurement Programme aims to install an additional 75 MW of small hydropower in the country by 2030 (Klunne, 2016). Three small hydropower plants have already been installed through the renewables programme, with a total capacity of 19 MW feeding electricity into the national grid. In addition to that which has been installed through the renewables programme, a number of privately owned small hydropower plants have been installed for private electricity consumption. Large-scale grid connected renewable energy projects have been prioritised in South Africa in accordance with the country’s energy policy. However the energy regulator in South Africa is in the process of preparing guidelines and policies for small scale plants (Klunne, 2016), as such the development of small hydropower will be facilitated, both through the renewables programme and through private implementation. Along with the use of small hydropower plants for electricity generation, these plants can also be used to provide mechanical power to drive equipment. Energy from the flow of water has been used to pump water for irrigation, power grain and saw mills and provided shaft power from water wheels for the textiles industry during the industrial revolution. Typical configuration options for hydropower projects include run of river, installations on dam walls, or installed within existing water infrastructure (Hutchinson, 2011). For the most part micro-hydropower plants are run of river installations. These installations operate under low head and require no water storage. They simply divert some water from the river along the side of a valley to be ‘dropped’ into the turbine via the penstock (Hutchinson, 2011). There are also a limited number of micro-hydropower installations at dam walls. Small hydropower projects tend not to make the financial returns of larger facilities. The financial constraints associated with building relatively small hydro projects into a dam wall therefore make them rare (Hutchinson, 2011). There may be potential for the hybridisation of electrical or mechanical equipment with hydro on farms in South Africa, where there are rivers or where dam infrastructure exists on site.

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The Lesotho Highlands Water Scheme has provided a permanent volume of water which is suitable for a number of hydropower facilities along the Ash River in the Free State province. There is an opportunity to harness energy from existing water infrastructure such as the water supply and distribution system. Example of this include hydropower facilities within irrigation canals and between reservoirs (Hutchinson, 2011). This could be applicable in the bulk water services infrastructure within cities in South Africa. South Africa’s Water Research Commission and the University of Pretoria has been doing extensive work into assessing the potential for hydropower form city water infrastructure. It was determined that the city of Tshwane has the potential to generate approximately 10 GWh of electricity per annum from its reservoirs (Loots et al., 2014).These configurations can be utilised to generate either electrical or mechanical energy. The broad key components and measures related to small and micro scale hydro power in South Africa are outlined in the following table.

Table 2-17: Typical small and micro scale hydro components and measures


A Baseline Study on Hydropower in South Africa conducted in 2002 by the Department of Minerals and Energy highlights specific areas in the country that show potential for the development of all categories of hydropower, in the short and medium term. The Eastern Cape and KwaZulu-Natal in particular contain the best potential for the development of small and micro (less than 10 MW) hydropower plants.


The advantages of small and micro hydro plants include their ability to be either standalone projects or hybridised with other renewable energy sources. Commercial farms may have hydro energy potential where there are dams or rivers on site. Similarly the bulk water infrastructure in South African cities may provide an opportunity for hydropower generation. However the use of hydropower installations for mechanical power requires that the process requiring mechanical input must be situated adjacent to a flowing river, which is not often the case in South Africa.


Small and micro scale hydropower technologies are well established and are produced by a number of large manufactures such as Toshiba and Siemens. There are a number of South African based companies providing these micro scale hydropower solutions, who import their plants from a range of countries, including Vietnam (ZM Pumps and Electrical Solutions, 2017).

Technology maturity

The technologies for small scale hydropower are mature.

Acceptability Some of the barriers to small hydropower development in the Southern African region include unclear legislative frameworks, unfamiliarity with the technology, an absence of suitable business models and in a few cases conflicts over access to water and land (Klunne, 2016). There has however been a shift in preference away from large scale hydro operations due to the potential for upstream flooding which can destroy agricultural areas, animal habitats and displace communities in the affected areas (Hutchinson, 2011). Micro-scale hydropower installations therefore present a less invasive option to generate power from water resources.

Economies of scale

The scale of installation can vary from as little as a few kilowatts to hundreds of megawatts. With capacity of 0.01 MW to 10 MW the technology can provide electricity in remote areas with a lifespan of 30 years or more (Hutchinson, 2011).

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2.3.5.1 Small and micro hydro for mechanical power The flow of water in a river can be used to drive various types of turbines such as water wheels, Francis turbines, Pelton wheels, and Kaplan turbines which can be used to rotate a shaft. The rotating shaft can be used to drive machines or an electric generator. Water turbines use the change of momentum of water flowing from a higher elevation to rotate a shaft. The kinetic energy in the water is transferred to the turbine shaft as a result of the change of direction of the water flow. The type of turbine used is dependant of the characteristics of the flow i.e. the flow rate and pressure. The applicability of mechanical power from hydropower installations also requires that the process requiring mechanical input must be situated adjacent to a flowing river. This is rarely the case in South Africa as few of the country’s cities are characterised by flowing waterways. 2.3.5.2 Small and micro hydro for electricity generation With modern turbine technology, up to 95% of the energy available from water can be converted into electrical energy (Hutchinson, 2011). This power output for a hydropower plant is related proportionally to the water flow rate and head, (Hutchinson, 2011). According to South Africa’s hydropower data base there are currently 84 small scale and micro hydropower plants operational within the country (Hydro4Africa, 2017). Hydropower installations make use of one of two types of turbine technologies depending on the head height. The first type are impulse turbines which convert the kinetic energy of moving water into electricity by making use of a high‐speed jet of water striking the buckets. The second type of turbine is the reaction turbines which converts the pressure energy into mechanical or electrical energy (Hutchinson, 2011). Reaction turbines work by fully immersing the turbine blades in water and must be built to withstand the operating pressure. The different energy outputs and scales of hydropower generation make standardised cost estimations challenging. Furthermore, in practice the development of these projects can experience significant cost over runs. An example of this in South Africa is the micro-scale Bethlehem Hydropower project which had two run-of-river installations of 3 MW and 4 MW each. The final costing for the combined 7 MW came to approximately R100 million (Klunne, 2010). Another example of a micro hydropower plant installed in South Africa, the ZMSA PowerSprout system, costs approximately R26 000 and has a generation capacity of between 1 and 2.6 kW (ZM Pumps and Electrical Solutions, 2017). The International Renewable Energy Agency published a report in 2012 on the cost of hydro power. The cost figures for small scale hydropower (which includes run-of-river installations) are summarised in Table 2-18. Table 2-18: Typical small and micro scale hydropower costs

Component: Measure: Capital Costs R10.6 million/MW – R65.6 million/MW (IRENA, 2012) Operational Costs

Operating costs of a small scale hydro plant amounts to between 1% and 4% of the capital costs (IRENA, 2012).

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2.4 Hybridisation potential in South Africa According to the energy use required, renewables can support the provision of energy services in the fossil fuel value chain. The energy services considered include thermal (heating and cooling), electrical, mechanical and mobility. A matrix is presented below that demonstrates the opportunities for hybridisation in South Africa, by linking the fossil fuel value chains identified in Chapter 1 to the renewable energy technologies identified in this Chapter 2. The matrix aims to inform the possible options for hybridisation per energy service, using the below key.

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2.5 Summary of cost analyses Chapter 2 considers the options and costs related to renewable energy technologies that have the potential to hybridise fossil fuel value chains in South Africa. The assessment entailed investigations into a series of potential technical options for integration, the economic consequences (where known) and the applicability of the hybrid opportunities in South Africa. The assessments consider issues such as the maturity of the technologies, the availability of the technologies, the availability of energy resources and supply chain and logistic constraints on fuel supply. The culmination of the assessments in this Chapter 2 is a matrix that demonstrates the opportunities for introducing renewable energy services (such as the provision of heat or electricity) within South Africa’s fossil fuel energy demand sectors and technologies which were identified in subsection 1.4 and 1.5 of Chapter 1. For example, the matrix demonstrates that a coal boiler used for electricity generation can plausibly be hybridised with a concentrated solar thermal application to provide steam; or geysers used in the residential sector may be hybridised by introducing solar water heaters or solar preheaters. The results of the hybrid matrix demonstrate the technical plausibility of hybridising traditional fossil fuel value chains with various renewable energy options. The opportunities vary per energy demand sector and will vary further according to the contexts and requirements of the different project implementers (for example different companies or individual households). The costs associated with implementing new technology measures or retrofitting existing systems or processes are well recognised as key considerations for project implementers. The technical feasibility of implementing new or retrofitted renewable energy applications will therefore need to be supported by the economic practicalities of installing and operating the respective technologies or systems. The typical capital and operations and maintenance costs associated with renewable sources of energy are presented in the relevant subsections of this chapter. The costs are summarised and presented in the following figures, which also seek to draw comparisons (using a single MW as the unit of measurement) across specified energy services and the respective renewable energy sources (hydro, wind, solar and biomass-based). The analysis focusses on the energy services and sources of renewable energy that have been identified, during the course of the analyses in Chapter 2, to be most viable in terms of hybrid opportunities in South Africa.

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Figure 2-37: Typical heating and cooling costs: bioenergy and solar

The range of costs associated with retrofitting coal power plants for biomass co-firing indicates that this form of hybridisation may be economical compared with solar hybrid applications. Such applications can entail integration risks that would likely be mitigated by building new facilities. While the application is technically and financially attractive (based on comparisons with the other technologies per MW installed), there are not many hybrid applications of this nature in South Africa, pointing to a different set of barriers to implementation. It is therefore likely that the critical barriers constraining the retrofitting of coal power plants for biomass co-firing are related to feedstock risks presented in this chapter. Feedstock supply risks include, for example, water scarcity issues and the seasonal variability that affects agricultural applications. Priority biomass feedstock risks also include the environmental and social risks (notably decreased food security) that have been conclusively linked to the production of bioenergy products, even in the cases where such products are well managed or sustainably farmed. Residential solar water heaters are identified as the most economical technology option for solar thermal hybrid options. Concentrating solar thermal applications tend to be the most expensive. Solar technologies also have drawback or risks however, such as the intermittent nature of the resource (typically limiting operation to daylight hours). Each technology and respective measure must therefore be considered within the specific context of the application and the needs of the implementer. The typical costs associated with power generation are presented in the following figure.

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Figure 2-38: Typical power generation costs: hydro, wind, solar and bioenergy

Small and micro hydro facilities have been identified as economic technology options for renewable power generation in South Africa. It must be noted however that the information available in the public domain regarding costs is scarce, and the instances of operational facilities in the country is low (84 plants), compared with the market penetration of the other technologies in the analysis. Small and micro scale wind technologies were found to be fairly costs effective compared with the other technologies, and yet the market penetration of these systems is low in comparison to solar power technologies. The barriers to implementation may be a factor of location, where relatively fewer regions in South Africa have good wind resources compared with the regions that are characterised by good solar resources. It is clear however that the micro scale turbines, less than 3.5kW, are considerably more expensive (per MW installed) than the larger wind turbines. Solar PV technologies were found to be typically more cost effective when compared with concentrated solar power (CSP) technologies. It has been found that CSP technologies are more applicable to larger scale installations. CSP applications that include a storage component were found to be significantly more expensive than the solar PV technologies. The range of capital costs of bioenergy technologies or systems was found to roughly correlate with the range of solar technology costs. The operating and maintenance costs associated with

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creating energy from municipal solid waste were found to be particularly high (compared with the other technologies), which is likely to be a factor of the non-homogenous nature of the feedstock in question, which is likely to increase maintenance requirements. One of the advantages of bioenergy applications is that biomass can typically be stored and used to generate power at a time that is convenient for the end user. However, the figure above does not speak to the feedstock costs that bioenergy technology measures are likely to be subject to, compared with the other technologies which have no related feedstock costs. Furthermore, the risks related to bio-power feedstocks are the same as the risks discussed above, which relate to issues of supply and other potential environmental and social risks. As discussed above, each hybrid opportunity must be considered within the specific context in which the application is to be located. Detailed feasibility assessments may clarify technical and economic uncertainties, thereby improving the rate at which renewable energy is integrated into the South African sectors, thereby facilitating the transition to a lower carbon economy.

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3 Prioritising hybridisation opportunities in South Africa

3.1 Introduction Chapter 3 aims to build on and analyse the research carried out in Chapters 1 and 2 to determine the feasibility of integrating fossil fuel and renewable energy technologies to create hybrid technologies. It highlights the global trends seen within hybridisation to showcase similar applications that are, or may be, feasible in the South African context. An analysis of unsuccessful hybridisation projects tested globally is discussed, to identify challenges and key lessons learnt. This chapter also outlines the policy context of hybridisation in South Africa.

3.2 Feasibility assessment of hybridisation options in South Africa

The feasibility assessment of hybrid technology options identified in earlier chapters is carried out through a multi criteria decision analysis (MCDA). The MCDA is partially informed by the outcomes of a workshop held with stakeholders, from various sectors, on 31 August 2017. This analysis is used to select and prioritise hybridisation options for further techno-economic assessment in the following chapters. Recommendations are made as to which technology options are most suitable or practical at facility level where facilities may have access to local renewable energy resources and at a national level where optimal resource use is considered. 3.2.1 Methodology for selection and prioritisation of hybrid opportunities A range of options for hybridisation of the fossil fuel value chains were presented in Chapters 1 and 2 of this report. These options were grouped per sector and identified according to the energy service (thermal, electrical, mechanical or mobility) that they could provide. Some of the proposed technologies are in early stages of development, thus may not be economically viable, or may have limited opportunities for roll-out in South African context. As such it is necessary to select and prioritise these hybridisation options from the perspective of individual facilities and at a country level as a whole. The selection and prioritisation of the technology options is carried out following a Multi Criteria Decision Analysis. Under this methodology, the success factors evaluated in Chapter 2 are used to rate the hybridisation options. During a stakeholder workshop held on 31 August 2017 the ratings were commented on and were inputs provided which were used to inform the weighting of the success factors to produce an overall weighted rating.

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3.2.1.1 Multi-criteria Decision Analysis methodology The Multi Criteria Decision Analysis (MCDA) is a decision support tool useful for selecting from a range of available, and sometimes competing, alternatives. During the assessment, value judgements are included to address the selection. The methodological steps to carry out the MCDA for the prioritisation of the hybridisation options identified are presented in Figure 3-1.

The assessment begins with identification of hybridisation technology options (1). These were identified in Chapter 2 as suitable for hybridisation with the country’s fossil fuel value chains. The energy value chains which had the potential for hybridisation were categorised into similar technologies, these include: aviation, furnaces, heating, ventilation and air conditioning (HVAC), direct fired kilns, lighting, power motor driven systems, heating ovens, rail, domestic shipping, steam systems, vehicles, water heating and other. The category “other” includes fossil fuel technologies such as open cycle gas turbines (OCGT) power plants, applications at oil refineries and liquefaction plants, electrolysis cells, fuel processing and stoves for commercial and residential use. The goal (2) of this MCDA is to identify feasible technology options suitable for hybridisation and to prioritise them in order to select those to be considered for further techno economic analysis in Chapter 4. Hybridisation options across four broad energy service categories were identified and discussed in Chapters 1 and 2. The energy service categories included thermal energy services (related to heating and cooling), electrical energy services (related to the consumption of grid electricity to provide an energy service), mechanical energy services (related to the use of a direct force to provide an energy service such as pumping), and mobility (related to transport of passengers/goods).

In order to select and prioritise the hybridisation options, assessment criteria (3) are identified. The criteria used relate to the success factors that are relevant when implementing an effective hybridisation project. In the previous Chapter a description of technical options for integration were provided, as well as the cost consequences and the applicability of the hybrid opportunities in South Africa. The MCDA is used to assess the hybridisation options on the following success factors:

• Maturity: maturity of standalone fossil fuel and renewable energy technologies, as well as the maturity of interfacing technologies to retrofit these systems to allow for hybridisation.

1) Identify Technology options

2) Define the goal

3) Identify criteria (Success factors)

4) Rate the alternatives

5) Weight the criteria

6) Score Σ (rating*weight)

7) Identify promising alternatives

8) Sensibility assessment

9) Selection of alternatives for

companies

10) Determine potential impact on

national GHG

11) Selection of alternatives for

the country

Figure 3-1: Steps of the Multi-Criteria Decision Analysis methodology

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The maturity of an option is also dependent on the uptake of technologies for hybridisation in the regional context.

• Availability (existing markets): a. The availability of the renewable energy resource b. The availability of the renewable energy technology c. The availability of the fossil fuel technology

• Costs: the cost implications of retrofitting a fossil fuel system to allow for hybridisation with a renewable energy technology, and the cost to ensure the functioning of such a system.

Availability and cost criteria may vary on a company level depending on the location within the country. Some areas may be better endowed with certain resources than others and distances to transport materials will impact on costs. For this reason, the average availability of a resource within South Africa is not used to eliminate an option as it may be viable at a specific company level activities. The maturity criteria indicates the position of a considered technology within the technology lifecycle. The maturity of renewable energy technologies is presented in the figure below:

Figure 3-2: Example of maturity of renewable energy technologies (IEA, 2016b) Following identification of assessment criteria, the hybridisation alternatives are rated (4) against these criteria. This rating is done using a scale from 1 to 5, and is interpreted for each criterion as follows:

• Maturity: 5 = Technology in commercial consolidated stage of lifecycle; 1 = Technology in development stage of lifecycle;

• Availability: 5 = Widely available; 1 = Very scarce;

• Costs: 5 = Low cost to retrofit; 1 = Very expensive to retrofit.

Inception Take-off Commercial

Biomass

Geothermal

Solar PV

Solar CSP

Hydro

Wind (on Shore)

Wind (off - shore)

Wave and tida l

Solar water heating

Geothermal

Tradi tional biomass

Modern biomass

Bioethanol from sugar and s tarch

Biodiesel fom oi l crops

New tech. for transport fuels Tran

spor

t fu

els

Heat

ing

and

cool

ing

Pow

er g

ener

atio

n

TechnologyCommercialisation

Demonstration2 3 4 51

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The maturity criteria have been adjusted to account for the maturity within South Africa. As an example; biogas technologies that are highly mature in Europe are not as mature in South Africa and have thus been rated slightly lower than the maturity would be rated in Europe. The cost criteria is not limited merely to the cost of implementation, but it also takes into consideration sustainability cost, which includes the operation and maintenance costs. Each of the assessment criteria (maturity, availability and costs) are then weighted (5) for their importance relative to each other, when deciding which hybridisation project to implement. The weighting given to each criteria was informed by inputs provided by stakeholders present at the workshop held on 31 August 2017. During this workshop, representatives from industry, research institutions, public institutions and NGOs provided their individual opinion on the weightings of the discussed criteria. These results were internally computed and the following conclusion achieved:

• Availability = weighted at 36.3%; • Costs = weighted at 35.6%; and • Maturity = weighted at 28.1%.

In this study these weightings have been applied across all sectors considered (industry, mining, agriculture, commercial and residential) as it is a high-level assessment. However, each company may weigh these criteria differently according to their business criteria and the risk that each company is willing to take. For example, in a data centre the risk of going offline is not an option and therefore a company in this field may be willing to implement expensive technologies that reduce its risk, and therefore the cost criteria will have a lower weighting. In areas where renewable energy resources, such as biomass, are not available the related technologies would not be viable. These weights were applied within the MCDA, to obtain a preliminary score per hybridisation option which is sorted from highest to lowest to identify the most promising alternatives. The final score (6) of an alternative is calculated as the weighted sum of the rated alternatives for that specific criteria using the following formula: �𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝐴𝐴𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚 𝑚𝑚𝑚𝑚𝑚𝑚𝑟𝑟𝑟𝑟� ∗ �𝑤𝑤𝐴𝐴𝐴𝐴𝑤𝑤ℎ𝐴𝐴𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚� + �𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝐴𝐴𝑚𝑚𝑎𝑎𝑚𝑚𝑚𝑚𝑎𝑎𝑚𝑚𝑎𝑎𝑚𝑚𝑎𝑎𝑚𝑚𝑚𝑚𝑚𝑚 𝑚𝑚𝑚𝑚𝑚𝑚𝑟𝑟𝑟𝑟� ∗ �𝑤𝑤𝐴𝐴𝐴𝐴𝑤𝑤ℎ𝐴𝐴𝑚𝑚𝑎𝑎𝑚𝑚𝑚𝑚𝑎𝑎𝑚𝑚𝑎𝑎𝑚𝑚𝑎𝑎𝑚𝑚𝑚𝑚𝑚𝑚�

+ (𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝐴𝐴𝑐𝑐𝑐𝑐𝑐𝑐𝑚𝑚 𝑚𝑚𝑚𝑚𝑚𝑚𝑟𝑟𝑟𝑟) ∗ (𝑤𝑤𝐴𝐴𝐴𝐴𝑤𝑤ℎ𝐴𝐴𝑐𝑐𝑐𝑐𝑐𝑐𝑚𝑚) Following the scoring of the technology options for hybridisation, these options are prioritised, to identify promising options (7). Prioritisation of selected technologies take into consideration the following:

• Capacity factors of the renewable energy technology; • Load factor of the fossil fuel value chain; • Maximum % of fossil fuel that can be replaced by renewable energy.

By including the capacity factor of the renewable energy technology, reference is made to the availability profile of the resource. Load factor accounts for the hours during a year for which the fossil fuel value chain is operational divided by the total number of hours in a year.

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A sensibility check (8) is done against the obtained results to ensure coherence and relevance of the prioritised options. The outputs from an exercise carried out at the workshop, where stakeholders were asked to choose which two hybridisation options they would implement if they had the money, were also used to verify the results from the MCDA prioritisation process. The final outcome from the MCDA are heat maps which display the ranking of options for hybridisation in the energy services assessed. Here, the options are ranked from the most promising to the least promising ones. The ranking doesn’t determine the size of the impact that the hybridisation technology may have, but it representing the most promising to the least promising technologies according to the evaluation criteria set. Heat maps are produced at facility and country level. Additional heat maps are produced for locations were bioenergy resources are not available and therefore hybridisation with bioenergy is not an option. The prioritised hybridisation options on a facility level (9) consider the specific conditions available to each company. At country level, one additional step is introduced to determine the impact of the hybridisation technology on the national greenhouse gas (GHG) emissions inventory (10). The prioritised hybridisation options on a country scale to impact the largest GHG emissions sectors of the country are then plotted on a heat map (11). The national GHG emissions of the country have been allocated per technology as follows: Table 3-1: Breakdown of country GHG emissions per technology category (Analysis carried out using data from South Africa’s 2010 GHG inventory, Department of Environmental Affairs, 2014a)

Emissions in the country per technology category Calculated % of emissions of the country within each category (*)

Vehicles 28% Other

• Open cycle gas turbines • Oil refineries • Liquefaction plants

17%

Steam systems 12% Furnaces 12% Heating, ventilation and air conditioning (HVAC) 11% Power motor driven systems 7% Water heating 5% Direct fired kilns 4% Lighting 2% Aviation 2% Ovens 2% Rail 0.3%

Domestic shipping Not included in South Africa’s 2010 GHG inventory

(*) As hybridisation of the national grid, through the renewable energy independent power producer

procurement programme (REIPPPP), does not form part of the scope of this study, country emissions are used to prioritise on a country level, but these emissions exclude emissions from utility scale electricity generation. If electricity generation is included in the emissions profile, the hybridisation opportunities are completely skewed towards those for electricity generation, as these

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emissions account for 55% of the country’s emissions. However, hybridisation options for boosting of utility scale coal fired boilers are intrinsically considered within the steam systems technology category. The other opportunity for hybridisation of utility scale coal fired boilers are to boost the output of the plant, by running the auxiliary equipment on site using a renewable energy. These are usually powered by the electricity generated by the coal fired power plant itself, reducing electricity being sent to the grid. The hybridisation of these auxiliaries is covered within the power motor driven systems category.

Outcomes of the multi-criteria decision analysis are presented using heat maps for the four energy services, thermal, electrical, mechanical and mobility, in the following sections.

3.3 Hybridisation of thermal energy services Thermal energy services include the provision of heating or cooling. Temperature requirements vary according to application, and influence the suitability of the hybridisation options. 3.3.1 Facility level thermal hybridisation For the provision of thermal energy services at facility level, bioenergy and solar powered technologies could offer renewable energy potential for hybridisation of the country’s fossil fuel value chains. Thermal energy services involve direct provision of heating or cooling where the energy is not converted into an intermediate product such as electricity. Electrical energy services are covered as a separate energy service in the next section. 3.3.1.1 Solar thermal hybridisation South Africa has large expanses of flat terrain with high irradiation and low rainfall levels, making ideal conditions for solar energy. As such solar related technologies for the provision of thermal energy services can play an important role in the hybridisation of fossil fuel technologies. The type of solar technology required depends on the application’s temperature. Lower temperatures (<100ºC), required for heating of water may be supplied directly with direct solar heating. Higher temperatures required for steam generation, ovens or furnaces can only be provided by concentrated solar thermal. Within an industrial facility or urban context, flat terrain for project development may not be available or it may be expensive to provide. Rooftop solar is an option that can be used where land availability is limited, however this is limited to the footprint of the facility. Maximum capacity of ratings of commercially available photovoltaic (PV) panels are 150W/m2. Concentrated solar power has a maximum capacity per unit of mirror area of 70W/m2.

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3.3.1.2 Bioenergy hybridisation Bioenergy is a unique source of renewable energy which can be provided in various forms as a solid (biomass), liquid (biofuel) or gas (biogas). Due to the fact that it is suitable for high temperature heat for industry purposes, such as co-firing in power plants and furnaces, it plays an important role for hybridisation of thermal applications. Moreover, biofuel offers the advantage of being a source of stored energy which allows it to cater for demand-driven generation. In this study three types of co-firing opportunities are considered: direct co-firing, indirect co-firing and parallel co-firing. These are defined as follows:

• Direct co-firing: this is the direct firing of a system with the biomass, biogas or biofuel. Typically there are no major retrofits required to directly fire a system with the fossil fuel and bioenergy resource at the same time.

• Indirect co-firing: this is the conversion of a bioenergy resource into an intermediary fuel (for example the conversion of solid biomass to a gaseous fuel), with the intermediary fuel fired into the fossil fuel energy system. In such a system a biofuel technology, such as a separate biofuel gasifier or a biofuel digestion plant is required.

• Parallel co-firing: this is the separate combustion of biofuel in a biofuel technology to deliver the final required energy services. This augments the production of the energy service delivered from the overall fossil fuel installation.

Bioenergy related solutions are only suitable in regions where there is cost efficient resource availability, this can limit the roll out of such systems in South Africa. Both storage and transport of bioenergy can add a prohibitive cost to a potential project. Bioenergy can include plant based biomass which is harvested or organic waste biomass (which range from abattoir wastes, food waste, and agricultural waste) which can be used for energy generation. As per the South African Bioenergy Atlas, plant based biomass resources are predominantly available in the KwaZulu-Natal province and Mpumalanga, represented in Chapter 1, Figure 1-11. Typical locations with potential are those close to agriculture activities such as farming and plantations which have an accumulation of organic waste. However, when talking about bioenergy, the resources available are not limited to biomass from wood or crops. Biomass includes any type of organic matter, including animal waste, oils, sewage, municipal waste, etc. The availability of this type of bioenergy has not been quantified throughout South Africa. This type of bioenergy will become relevant on a facility level where a facility has access organic waste streams. The sustainable provision of heat (and power) from crops’ biofuel needs careful consideration. The large-scale implementation of bioenergy may create competition for other uses of biomass such as food, animal feed, forest products or land. The use of unsustainable biofuel resources results in net generation of emissions, opposed to the aim of reducing emissions when using a renewable energy resource. As such, the International Energy Agency (IEA) notes that the use of biomass resources needs to be sustainably controlled (IEA, 2012). Land degradation is increasingly acknowledged as a key barrier to community development. The soil carbon content is an indicator of land degradation. Unsustainable harvesting or collection of biofuels will affect soil carbon negatively.

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3.3.1.3 Facility level thermal options Suitable hybridisation options at a facility level for thermal applications are presented as a heat map in Figure 3-3 and Figure 3-4. Where Figure 3-3 is relevant where bioenergy is available in the region and Figure 3-4 is relevant where no bioenergy are available. The hybridisation options are categorised per energy consuming technology (e.g. furnaces, heat, cooling and drying equipment, kilns, etc.). The graph displays the hybridisation options from the most promising option (top - dark green) to the least promising (bottom - dark red) option. In areas where bioenergy is available, it is the most promising renewable energy resource for provision of thermal energy services. This is mainly due to the bioenergy resource being able to supply energy for 24 hours a day, compared with solar which can provide energy for only about 30% of the day. The provision of thermal energy is also possible from solar resources, including direct solar for heating, solar PV and concentrated solar. Virtually the whole of South Africa has suitable solar resources throughout the year. The hybridisation choice of a company will depend on the individual requirements of the facility doing the assessment.

Figure 3-3: Hybridisation options for the provision of thermal energy, per technology category, for locations with bioenergy availability

An example could be a company which needs to supply heating, cooling or drying (HC&D). If the company wanted to hybridise, the best option would be to consider direct solar heating which for the case of cooling would need to be coupled with an absorption chiller. The following two options relate to parallel and indirect co-firing of the system with biofuels. If such a technology is not suitable to the company or if the biomass resource is not available to the company due to its location, the company would choose from the list presented in Figure 3-4 for a suitable hybridisation solution for its technology. For the case of HC&D in a location without availability of bioenergy, the best option is to use solar resources, starting with solar heating for preheating of input material such as water, then PV installations and finally concentrated solar energy to make hot water for heating or which can be passed through an absorption chiller to provide cooling as well.

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Figure 3-4: Hybridisation options for the provision of thermal energy, per technology category, for locations where there is no biofuel availability

3.3.2 Country level thermal hybridisation Suitable hybridisation options at a country level are presented in Figure 3-5 and Figure 3-6. These are differentiated for areas with bioenergy availability and prioritised by their potential to contribute towards the reduction of emissions. Figure 3-5 is relevant for regions where bioenergy is available and Figure 3-6 is relevant in areas without access to bioenergy. Applications within the largest emitting sectors are evident. At a national level and in the case of thermal applications, the use of direct solar water heating for pre-heating the boiler feed water is the hybridisation option with the greatest potential for impacting one of the large emissions sectors of the national GHG inventory. Hybridisation for steam production in general is one of the most promising areas for national intervention, this can be done through solar heating (preheating the boiler feed water), co-firing of the boiler with biofuel or through the use of concentrated solar to augment steam production.

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Figure 3-5: Thermal hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations with biofuel availability

Figure 3-6: Thermal hybridisation options at country level based on their contribution to the large emission sectors of the national GHG inventory, for locations where there is no biofuel availability

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Industrial furnaces are existing technologies with potential for implementation of hybrid applications. Typical direct fired furnaces use coal, oil or gas as fuel. Given the resource availability, co-firing with biofuel is a suitable option for hybridisation of furnaces. Concentrated solar is also to be considered for firing of fossil fuel based furnaces, while solar heating is suitable to preheating the raw material going into the furnaces. Hybridisation of “other” industrial applications may have a positive impact on the reduction of the emissions for the country. The most notable of these is the use of biofuel for distillation in refineries and industrial applications. Other fossil fuel driven technologies suitable for hybridisation with renewable energies for provision of thermal energy services include heating, cooling and drying (HC&D), water heating, kilns (only biofuels applicable) and ovens. HC&D includes cooling and refrigeration of products, space heating or cooling, and heating, drying or cooling of equipment or products. Good potential is found in the industrial and agricultural applications with the use of indirect and parallel biofuel co-fired systems for thermal energy services. Solar heating is a suitable option not only for the industry and agriculture sector but for commercial and residential applications as well.

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3.4 Hybridisation of electrical energy services Electrical services include the provision of energy in electrical form to deliver services, for example lighting or heating. Electrical systems are the easiest to hybridise in any facility as they don’t require modifications to the electricity consuming equipment. The hybridisation options result in augmentation of the fossil fuel energy system. A summary of suitable hybridisation options of renewables for the provision of electrical services at facility and country level are provided in this section. 3.4.1 Facility level electrical hybridisation Hybridisation options for electrical applications at facility level are presented using heat maps in Figure 3-7 and Figure 3-8. Where bioenergy is available in the region Figure 3-7 provides relevant options whereas Figure 3-8 provides viable options when no bioenergy is available. Value chains making use of fossil fuels to provide electricity can be hybridised with renewable electricity. These technologies include furnaces, HVAC systems, lighting, motors, electric steam systems, water heating. For electrical energy, the “other” category includes reactors in oil refineries and electrolysis cells in industrial applications. Electricity sourced from PV plants and from parallel co-firing with bioenergy are the preferred options for hybridisation at facility level. PV generated electricity is suitable for many electrical requirements; however, biofuels and biogas are more suitable for applications that require high power output at a constant supply such as furnaces, and reactors.

Figure 3-7: Hybridisation options for the provision of electrical energy, per technology category, for locations with bioenergy availability

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Figure 3-8: Hybridisation options for the provision of electrical energy, per technology category, for locations where there is no bioenergy availability

Wind energy is another important option for hybridisation, especially for facilities that are in a high wind resource zone, and at sites that are appropriate for the installation of wind generators, where there is space available. Smaller wind turbines have also been considered in this study for installation at commercial or residential buildings for electrical applications. For the case of small-hydro electricity generation, this option is only suitable for small and medium industry, mining and the agriculture sector with operations taking place in close proximity to a perennial water stream,. Concentrated solar power is an important source of electricity. Concentrated solar power is a more suitable option for large scale electricity generation, oil refineries, liquefaction plants, and electric furnaces.

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3.4.2 Country level electrical hybridisation Hybridisation options of electrical services on a country level are presented in Figure 3-9, for regions where bioenergy is available, and Figure 3-10, for regions where bioenergy is not available. This summary is prioritised based on the potential contribution of the hybridisation option to impact the national emissions. Reactors, electrolysis cells, electric steam systems, distillation units at oil refineries and electric furnaces are the most suitable areas for hybridisation and could positively impact national GHG emissions.

Figure 3-9: Electrical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations with bioenergy availability

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Figure 3-10: Electrical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no bioenergy availability

PV systems can contribute to the provision of electricity for steam production for the distillation units at refineries or for electrical steam systems in industry. Electric furnaces can make use of electricity generated from bioenergy or from solar resources according to the resource availability. Given the emissions of the country related to the provision of energy for industrial and refining applications, the potential for emissions reductions in these sectors are substantial. Solar energy is suitable to power HVAC applications not only for industry and agriculture but also for the commercial and residential sector. Solar and bioenergy hybrid systems are also promising for the delivery of electricity to hybridise motor driven systems, commercial and residential water heating and lighting.

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3.5 Hybridisation of mechanical energy services Mechanical energy can be used to deliver a direct force to provide useful work. Motors and engines are used to provide a mechanical force. In many cases in South Africa these motors are run using electrical energy. However it can be more efficient to use mechanical energy directly instead of first generating and then converting the electrical energy into mechanical energy (FOA, 1986). In this section, hybridisation options to augment the provision of mechanical work in motors or engines are discussed. A summary of suitable hybridisation options with renewables for mechanical energy at facility and country level are provided below. 3.5.1 Facility level mechanical hybridisation Since early recorded history, people have used the energy from the wind and water flows as a direct source of mechanical energy. With the development of electric power most application migrated to electrical motors to provide mechanical energy as it was more reliable, practical, not affected by the location and it brought significant increases in productivity. There is however great lessons that shouldn’t be lost in how this renewable energies were used in the past. Despite efficiencies there is great potential in use of mechanical power from wind and water and may be a more suitable option on a facility level where grid electricity is not available. Motors, engines and auxiliary equipment such as pumps, compressors and HVAC systems are found in many applications and are used widely in industry in South Africa. Most of the mechanical energy services in South Africa are powered by grid electricity, such as in electricity generation facilities, oil refineries, liquefaction plants, industrial applications, mining sites and agricultural sites. Exceptions are the sugar industry in KwaZulu Natal, utilizing bagasse to generate steam which is used for stirring and mechanical energy. Sasol also uses steams to power air separation plants and boiler feed water pumps. Engines are in some cases used offsite where there is no access to electricity and equipment such as compressors, compactors, vibrators and drills need to be powered. The energy provided by a fossil fuel to move the motor shaft can be complemented with renewable energy. This renewable energy can be provided directly as mechanical energy, for example through the flow of water or wind. Mechanical energy can also be provided by steam which operates at a high pressure and can provide a direct force to perform useful work. In this case steam generation can occur through the combustion of bioenergy or through the use of concentrated solar. The choice of renewable options for hybridisation of the supply of mechanical energy is dependent on the resource availability at the facility. Suitable hybridisation options for facility level mechanical applications are presented in Figure 3-11 and Figure 3-12. Where Figure 3-11 is relevant where bioenergy is available in the region and Figure 3-12 is relevant where no bioenergy is available.

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Figure 3-11: Hybridisation options for the provision of mechanical energy, for locations with bioenergy availability

Figure 3-12: Hybridisation options for the provision of mechanical energy, for locations where there is no bioenergy availability

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In select areas where bioenergy resource is available, steam generation from bioenergy parallel and direct co-firing are the most promising options for hybridisation of engines for the use of mechanical energy. Small scale hydro systems also present promising hybridisation opportunities for mechanical power. This system is only applicable where a facility has access to a perennial flowing stream. Following bioenergy and small-scale hydro, the next most promising hybridisation opportunity is with wind (available in most areas of South Africa, especially along the coastal areas), where the mechanical energy from a wind turbine could power pumps. Steam from concentrated solar systems can be used to provide mechanical power to motor driven systems. This is particularly suitable for facilities which are generating steam and may have excess steam during some periods. 3.5.2 Country level mechanical hybridisation Hybridisation options for the provision of mechanical services at country level are presented in Figure 3-13 and Figure 3-14. The graphs display different solutions for areas where bioenergy is available and for areas where it isn’t. These opportunities are prioritised based on their potential to contribute to reducing the large emission sectors of the country’s national GHG inventory. Given the resource, bioenergy for steam production is the most promising option and steam production from concentrated solar being the least promising.

Figure 3-13: Mechanical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations with bioenergy availability

At locations where bioenergy can’t be obtained, companies in proximity to water streams or with suitable locations, may consider small hydro or wind energy to augment the energy for mechanical applications. The use of concentrated solar for steam generation to provide mechanical power can be considered depending on the application.

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Figure 3-14: Mechanical hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no bioenergy availability

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3.6 Hybridisation of mobility based energy services

There are hybridisation opportunities for vehicles related to the transportation of goods and people in particular the use of biofuels for combustion in engines. In addition solar PV can be used for the operation of auxiliary equipment within vehicles, such as air conditioning. Solar PV can also be used to augment the electricity provision for the operation of electric railways. 3.6.1 Facility level hybridisation of mobility energy services Hybridisation options for mobility and freight services are presented in Figure 3-15 and Figure 3-16. Where Figure 3-15 is relevant where biofuels are available in the region and Figure 3-16 is relevant where no biofuels are available. These are categorised for the hybridisation most applicable per type of vehicle. Transportation sectors assessed include aviation, rail, shipping and vehicles. The hybridisation options for mobility and freight include the use of biofuels for biofuel blending with petroleum. In addition, the provision of energy for auxiliary services in vehicles such as air conditioners, radios, power steering or cooling in refrigeration trucks can also present an opportunity for hybridisation of the transportation industry. Due to the stationary nature of rail infrastructure and the extent of railways across the country, the availability of various renewable energy resources throughout South Africa, present more opportunities for hybridisation of the country’s rail systems. Six percent of work trips are made by rail in South Africa. In Gauteng and the Western Cape 17% and 37% of the work trips are by rail respectively (NATMAP, 2017).

Figure 3-15: Hybridisation options for the provision of mobility services, per transportation mode, for locations with biofuel availability

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Biofuels can be co-fired in combustion engines that use fossil fuels, such as the engines in aeroplanes, light and heavy duty vehicles, trucks, tractors, ships and diesel trains. The realistic amount of biofuel that can be blended with petroleum products is however limited by factors such as vehicle engine specifications, fuel specifications, the available commercial deployment of the biofuels, challenges during pipeline transportation or national policy for blending percentages. It is important to note that the use of biodiesel-blends can impact engine warranties, which may constrain uptake. Another opportunity in conjunction with direct co-firing is the opportunity to implement dual fuelling in vehicles. This may be more suitable to light duty vehicles. The vehicles engine may need modification to burn two different types of fuels, such as ignition timing and fuel supply components. The engine however only uses one fuel at a time. Dual fuelling requires the vehicle to have an additional storage tank for the second fuel, as well as a control switch to vacillate between the fuel types. This hybrid option is limited by the resource availability for biofuels and the fuelling infrastructure in South Africa.

Figure 3-16: Hybridisation options for the provision of mobility services, per transportation mode, for locations where there is no biofuel availability

Solar energy can also support electrical needs in the transportation sector for example to operate auxiliary services such as the air conditioner in mining and agriculture trucks, support cooling in refrigerated transport of products, or electricity driven services for ships. The amount of electricity which can be provided by a solar energy system is however limited by the area on the transport vehicle exposed to solar irradiation. For the case of railways, the extension of the rail lines creates the possibility of the installations of larger scale solar systems within the train tracks for electricity generation which can augment the train’s electricity supply, in the zone next to or between the rail lines, using the existing electricity infrastructure. The area on a truck available to be fitted with PV panels is a lot smaller and thus the amount of electricity that can be generated from such a system is limited, and will only be able to provide a portion of the power to run the auxiliaries of the truck.

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The electricity grid used to supply railways with electricity can be supplemented by electricity from renewable energy. Renewable electricity for railways can be provided by a wind power station, by a solar PV power plant or a concentrated solar power station. 3.6.2 Country level hybridisation of mobility energy services By nature, any change made at facility level for the transport and mobility sector becomes a country level intervention. The complete set of hybridisation options for mobility services are presented in Figure 3-17 and Figure 3-18. Fuels derived from organic matter could assist in potentially reducing the GHG emissions in South Africa’s transport sector. However, due to the sustainability concerns around biofuels, the uptake of these requires a strong policy framework ensuring that food security and biodiversity are not compromised. A 2% penetration of biofuels is targeted in the national fuel supply, according to the Biofuels Industrial Strategy of South Africa. This is a national average but implementation may result in higher blending in some regions and lower blending in others. Blending of up to 5% for biodiesel and up to 10% for fuel ethanol is suggested in accordance with SANS standards. Other suitable options at national level include the use of solar powered systems for the provision of auxiliary services to vehicle fleets. Auxiliary equipment has been shown to increase consumption between 8% and 30% (Santiangeli et al, 2014). The amount of emissions reduction that can be achieved through the powering of auxiliaries with renewable energy is less than what can be achieved through the reduction of fuel combustion in vehicles, however the opportunity exists. Solar PV for electricity production can also be used to augment the electricity supply to railways. Other renewable energy sources for electricity provision to the railway are also an opportunity. These are plausible options, but not necessarily economically feasible. These can include a wind power station, or concentrated solar power station for electricity production, at a railway station used to power the railway. This electricity generated does not need to be wheeled onto the national grid but can be used directly for ancillary services at the stations, or to augment the supply of electricity for the railways.

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Figure 3-17: Mobility based hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no biofuel availability

Figure 3-18: Mobility based hybridisation options at country level based on its contribution to the large emission sectors of the national GHG inventory, for locations where there is no biofuel availability

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3.7 The policy context of hybridisation This section provides an overview of the regulatory environment applicable to energy system hybridisation in South Africa. A focus is placed on the policy development for renewable energy and established standalone renewable energy technologies since hybridisation is a transitional arrangement. Hybridisation of fossil fuel systems could however play an important role in driving and developing policies to enable greater uptake of alternative energy sources. An enabling policy environment is key to the implementation and development of a diversified energy mix and to enable the implementation of hybridisation of fossil fuel value chains with renewable energies in South Africa. Such an enabling environment does not only imply sound policy design, it should also consider the underlying factors impacting on and informing policy development which might hinder or support successful implementation. In this regard, policy should be suited to the level of market development, provide an appropriate degree of stability for investment and be robust enough to evolve as the market changes and grows (IEA, 2015). Policy plays a key role for renewable electricity because policies establish the level of confidence in the market, the market rules that govern the way electricity is sold, and the associated risk perception. This influences the pace of deployment and costs of generation. The policy and regulatory framework also determines the extent to which non-economic barriers – such as lack of market access, difficulties in gaining the necessary permits, and skills shortages – inhibit or push up the cost of deployment. The regulatory framework also determines how easily renewables can be integrated into grid operations, given technical as well as institutional considerations. (IEA, 2015). In addition to electricity, the roll-out of renewable energy provides for other energy services such as heating and cooling. Therefore an enabling policy environment to maximise all renewable energy alternatives is critical. This could facilitate and support the integration of hybridisation in order to maximise the suite of renewable energy services. 3.7.1 Global hybridisation policy context International policy trends indicate that currently the focus remains on renewable energy as a blanket concept. The important role of renewable energy in the energy sector as well as a growing commitment towards sustainable implementation, will pave the way for hybridisation as a mechanism to support renewable energy roll-out. Research from REN21 (2017b) indicates that, globally, government policy at all levels remains important for renewable energy development. It is evident from this research that renewable energy and fossil fuel hybridisation has not been a focus in terms of energy policy development. However, policy makers implemented a range of renewable energy support policies. These included feed-in tariffs (FITs), tendering, net-metering and fiscal incentives; all of which provide support aimed at economy-wide economic development, environmental protection and national security (REN21, 2017b). These policy developments were driven by two key pressures: to stimulate the renewable energy sector market and to effectively integrate renewable energy

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advances within existing energy structures. There are a number of factors that give rise to these pressures including falling costs and rising penetration of renewables across markets, renewable energy market share, the increase or decrease in the use of energy and technology advances and maturity (REN21, 2017b). According to the Renewables 2017 - Global status report (REN21, 2017b) there are a number of key tendencies within global renewable energy policy development. These are summarised below:

• The power sector is the primary focus of renewable energy policy support Internationally, feed in tariffs (FITs) are the most widely utilised form of regulatory support to the renewable power sector. A number of countries, including Poland, Greece and Slovenia adopted hybrid policy schemes that support small-scale projects through FITs and large projects through tenders. REN21 (2017a) notes in the Renewables Global Future Report that there is a high degree of support for the 100% renewable energy supply goal in the Australian and Oceania regions, and similarly in China, Europe and by international organisations. Policy constraints are however considered to be barriers to going 100% renewable in each of these regions (and also in the view of international organisations).

• Renewable heating and cooling technologies are supported through mandates and

incentives REN21 (2017b) finds that overall, government policies supporting the implementation of renewable heating and cooling technologies tend to be overshadowed by the policies aimed at stimulating renewable energy markets. Nevertheless policies to support renewable heating and cooling technologies are increasing. Europe is reported to be the largest producer of renewable heat worldwide, reflected by the extensive and successful use of policies to increase the uptake of the relevant technologies (REN21, 2017b). REN21 (2017b) reports that in 2016 most government support for the renewable heating and cooling sector was provided through financial incentives in the form of grants, loans or tax incentives.

• Biofuels for road transport are being focussed on by policy makers globally

Support in the roll out of renewable energy in the transport sector through biofuel blending, has been provided through blending mandates and financial incentives. REN21 (2017b) reports that activity in this regard was evident in the United States in 2016, where 2017 blending mandates were released under the Renewable Fuel Standard. Policy support for renewable energy in the transport sector however lags behind the power sector.

• City and local government renewable energy policies

More and more cities around the world are committing to increase the portion of renewables in their energy mixes. REN21 (2017b) reports that in 2016 there was an increase in the number of city governments that implemented specific renewable heating and cooling mandates. An increasing number of cities are also committing to goals to operate on 100% renewable energy.

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The IRENA (2017a) study found that government policies will remain crucial to accelerate the pace of deployment, to create an enabling environment for renewable energy, and make hybridisation market development possible (IRENA, 2017a). The types of policies required differ according to national or local contexts, project scale, technology type and envisioned market penetration objectives. In addition, to grow a sustainable renewable energy market it is important to deploy a number of policy mechanisms that can cater for a broad spectrum of development. These mechanisms are illustrated in Figure 3-19 below covering examples within national policy, regulatory instruments, fiscal incentives, grid access, accessing finance and socio-economic benefits.

Figure 3-19: Global trends in policy instruments to support renewable energy implementation (IRENA, 2017a)

Globally, policy makers recognise the importance of technologies that enable a high share of variable renewable power in in existing energy systems. In this regard policy should support and ensure adequacy of supply and flexibility in terms of systems operation (IRENA, 2017b). 3.7.2 Regional hybridisation policy context The majority of African countries face a number of socio-economic development challenges requiring specific policy interventions. In developing economies, such as the Southern African Development Community (SADC), affordable energy services are critical to economic development, both from a national as well as a regional perspective. The SADC is the geographical region defined by a treaty between the member states concerning socio-economic development, defence, politics, security and regional integration. During 1995 the member governments of SADC signed an Inter-Governmental Memorandum of Understanding for the formation of a power pool in the region. The Southern African Power Pool (SAPP) was set up as a means for national electricity utilities to trade electricity amongst each other. Nine member states of SADC have connected their electricity grids into the Southern African Power Pool, reducing costs and creating a competitive common

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market for electricity in the region. Similarly, SADC has established the Regional Electricity Regulatory Association, which has helped in harmonising the region’s regulatory policies on energy and its subsectors. Hybridisation options could increase the uptake of renewables within the context of the SAPP. This relates to grid hybridisation, which is not covered within this study, but does show great potential for the energy system as a whole. Augmenting existing energy infrastructure with hybridised renewable energy options could allow for:

a) an increase of energy options in the SAPP; b) opportunities for different utilities to participate; c) the subsequent development of diversified business models.

Linked to the above, the Atlas of Africa Energy Resources (UNEP, 2017) emphasises the strategic role governments play in the energy market. Specifically in how the business models of utilities are structured. As such, reaching higher shares of renewables in existing energy systems will not necessarily follow on from the economic breakthroughs of renewable energy technologies, but through the development of robust business models which are expected to drive regional market development. Facilitating higher shares of renewables in existing energy systems such as the SAPP will require infrastructural and institutional changes, which could pose challenges (REN21, 2017a). The challenges could be related to, among others, access to finance and disruptions to the supply of power. For developing countries, with aging and, in many instances, constrained energy infrastructure combined with outdated policy, such changes are difficult to manage (REN21, 2017a). Energy experts identified inconsistent and uncoordinated energy policies as a serious barrier to project development and the uptake of renewable energy (UNEP, 2017). Another challenge relates to lack of knowledge and information, resulting in unsuitable policies which fail to support renewable energy and energy efficiency. Yet, this challenging context provides for opportunities to leapfrog and maximise on the evolution of the renewable energy sector policy. It forces the development of innovative solutions to improve sustainable energy supply. In this regard, hybridisation has been identified as a means to overcome infrastructural challenges, albeit on a very limited scale. This is achieved through performance boosting of existing plants through hybridisation on site without a need to increase distribution capacity to site and in some cases may reduce the demand on the existing infrastructure. Three African countries have identified hybrid options as part of mitigation efforts under their Nationally Determined Contributions (UNEP, 2017). These options are presented in the following table.

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Table 3-2: Hybridisation Options included in African Nationally Determined Contributions

Country Hybridisation options Mauritius Adopt sustainable transportation, including promotion of energy

efficient mass transportation systems based on hybrid technologies and cleaner energy sources.

Senegal Implementation of a rural electrification programme. 392 villages to be electrified with mini-grid using solar or hybrid (diesel/solar) energy sources.

Togo Develop minigrid hybrid networks for rural electrification

Hybridisation could play a role in bridging technological and cost challenges in the transition from traditional energy systems to increased renewable energy options. In addition, hybridisation could offer practical options to overcome challenges in rural electrification. Considering the socio-economic challenges faced in Africa, including an urgent need for basic energy provision, hybridisation could enable short-term solutions to transitioning from fossil-fuel based energy systems to integrated renewable energy options. However, significant transmission constraints and limited interconnector capacity reduces optimal possibilities with cross-border electricity trade. In 2016/2017 cross border trade was limited to 1 TWh (<0.5% of South Africa’s demand) due to transmission constraints. 3.7.3 South African policy context: links to hybridisation South Africa’s policy development experience echoes that of international energy initiatives: a combination of policy tools are most effective to unlock market potential and achieve national clean energy objectives (Department of Energy, 2015a). The first official document to acknowledge the need to secure energy supply through diversifying energy sources was the White Paper on Energy Policy of the Republic of South Africa (1998). This document acknowledged that the ‘rapid development of renewable energy technologies was imminent, and that they would become cost competitive and cost effective’. The White Paper had a strong focus on the introduction of independent players in the market and in doing so, optimising an estimated 6 000 MW of non-utility generation potential. This process of energy market reform did not come to fruition as the Electricity Distribution Industry restructuring came to an end in December 2010. Following on from the Energy Policy White Paper, the Renewable Energy White Paper in 2003 set out objectives and commitments required to increase the share of renewable energy in the South African energy mix. This Paper suggested specific policies to create a conducive environment for renewable energy market growth. Key aspects to ensure market growth related to development of regulations and implementation of localised support including research and manufacturing. In 2007 Eskom launched the Pilot National Cogeneration Programme, with the view to investigating opportunities to increase national generation capacity. The aim of the pilot programme was to procure 900 MW of commercial cogeneration supply during 2007. Three types

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of cogeneration were considered: projects using waste-energy from industrial processes; primary fuel-based generation projects which produced other energy (in addition to electricity) as part of their core design; and renewable fuel-based projects. The programme was not however successful as no Power Purchase Agreements were finalised between Eskom and the relevant Independent Power Producers (IPPs). The Centre for Competition, Regulation and Economic Development (2014) cites the key issues related to the failure of the programme as a lack of market readiness on behalf of both Eskom and the IPPs, a complex bidding process and difficulties in accessing finance on account of uncertainties regarding the feasibility of the programme, and the perceived risk levels associated with the fuel availability. During 2009 the government began looking at feed-in tariffs as a means to accelerate and support private sector investment in renewable energy. In building up the renewable energy programme, NERSA developed and launched the South African Renewable Energy Feed-In Tariff (REFIT) programme. Initially the programme’s focus was on wind, concentrated solar power, land-fill gas, and small hydro plants (Belsinka, B, 2009). However the Department of Energy and National Treasury were concerned that the feed-in tariffs were too high. As a result they commissioned a legal opinion that concluded that feed-in tariffs amounted to non-competitive procurement and were therefore prohibited by the government’s public finance and procurement regulations. This policy was subsequently halted in favour of a competitive bidding process (REIPPPP). In developing an alternative to REFIT the fundamental goal of achieving large-scale renewable energy projects with private developers and financiers remained the same. However, the structure of the transactions, including the feed-in tariffs, was to change significantly (Eberhard, A; Kolker, J and Leigland, J., 2014). Once renewable energy was included in the national integrated electricity plan in 2010 coupled with the government-led procurement programme, the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP) formally commencing in August 2011, South African market conditions enabled large scale renewable energy development. In 2015 the carbon offset regulations under the proposed carbon tax excluded all carbon credits from the REIPPPP. There have since been negotiations to revise the regulations, with the proposal that projects in round 1 and 2 of the REIPPPP be excluded but that subsequent projects, if implemented, could be eligible to provide carbon offset credits into the carbon tax scheme. In such an event, it is anticipated that the carbon offsets could sell at around R100/tCO2e (which is slightly less than the carbon tax rate of R120/tCO2e), adding an additional revenue to the renewable energy generation companies.

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3.7.3.1 REIPPPP as an example There are valuable lessons that can be learnt from the roll out of the REIPPPP, which can be applied in the context of enabling regulations for hybridisation. Some of the key success factors from REIPPPP are highlighted in Table 3-3 below. Table 3-3: REIPPPP key success factors and lessons for hybridisation (Adapted from Eberhard, A; Kolker, J and Leigland, J., 2014)

REIPPPP Key Success factors Political support REIPPPP benefited tremendously from high-level political support, in the

form of a relatively long history of policy statements on renewable energy, but more importantly, South African President Zuma’s commitment to green energy during the COP15 meeting in Copenhagen and South Africa’s subsequent hosting of COP17 in Durban, where the government’s Green Accord with business and other stakeholders was signed.

Institutional setting The largely ad hoc institutional status of the Department of Energy’s (DOE) Independent Power Producer unit, acting at arm’s length from the DOE as a dedicated project office, allowed and, to some extent, encouraged an operating approach that emphasized problem solving to make the program successful, rather than automatically following government operational policies and procedures that emphasized enforcement of rules.

Accelerated roll-out of new generating capacity

Despite the higher initial cost of renewable energy, REIPPPP provided a relatively fast way to roll out new power generating capacity and an opportunity for South Africa to address its renewable energy targets.

Program size The program immediately caught the attention of the global energy development industry, particularly because the European renewable energy markets had been in decline. The program’s size meant that there would be multiple bid winners and future prospects.

Exemption from Public Private Partnership (PPP) regulations

Exempting Independent Power Producers (IPPs) from national PPP regulations by defining the national government-owned power utility – in its role as the off-taker and contractor – as something other than a government agency, employs a definitional distinction that would not always be possible in other countries. Subjecting IPPs to South Africa’s complex and time-consuming PPP rules would have dramatically slowed and, perhaps subverted, this successful program.

REIPPPP showed that instituting key regulatory aspects to unlock project potential, created an enabling environment for renewable energy development. In addition, this allowed for private sector buy-in. The above-mentioned REIPPPP success factors illustrate how the policy environment can be used to strengthen investor confidence and support market development. Hybridisation offers a number of opportunities in terms of growing and diversifying the local renewable energy market. In this regard strategic policy support could maximise the uptake of hybrid technologies for various energy services. Therefore, the lessons from the REIPPPP process are prudent to developing a local policy environment which will invite and develop various hybrid technology options.

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3.7.3.2 Key legislation relevant to hybridisation The following provides an overview of policies and regulations which are relevant to the development context of renewable and fossil fuel energy system hybridisation.

• Free Basic Electricity Policy (2003) and Free Basic Alternative Energy Policy (2007) The Free Basic Electricity Policy provided for 50kWh of free electricity to be provided to low income households through the Local Municipal Equitable Share Grant. However, Government realised the need to extend electricity provision to energy provision. This led to the development of the Free Basic Alternative Energy Policy. The objective of this policy was to support low income households with the equivalent of R56.29 per month of alternative fuels or technology deemed appropriate by the local government. In this regard municipalities are provided with financial resources to procure alternative energy sources. The objectives of this policy include: o The facilitation for the provision of basic energy needs to low income South African

households that do not have access to electricity; o Where possible to address a whole suite of socio-economic issues that arise from

inadequate provision of energy to households such as job creation, etc.; o Minimise health risk by promoting safe use of these energy carriers to ensure that energy

carriers chosen are sustainable, safe and easily accessible to the low income households. Unsustainable biomass harvesting for cooking has been contributing to land degradation in the region; and

o Maximize efficient use of energy carriers for the benefit of all citizens. However, to date this policy has not yet met all the objectives listed above due to significant challenges with regards to the logistical requirements of the roll-out of the policy. Extending existing electricity infrastructure in South Africa into rural areas is cost intensive and difficult in terms of geographic factors. Hybridisation offers opportunities to extend energy services into these areas. The Free Basic Alternative Energy Policy, as well as its predecessor, the Free Basic Electricity Policy, create platforms for municipalities to deliver basic energy services to low income communities. Localised renewable energy projects could assist in overcoming the logistical challenges with regards to the roll-out of these two policies. Micro-grids in rural un-electrified villages is another form of local hybridisation. Hybridised micro-grids may be used to electrify households and reduce transmission and distribution losses while using available renewable energy resources, thereby mitigating GHG emissions.

• Draft Regulations Regarding the Mandatory Blending of Biofuels with Petrol and Diesel, 2012

In 2012, the Department of Energy published draft legislation on the mandatory blending of biofuels in petrol and diesel. Once this regulation is promulgated it will require all licensed petroleum manufacturers to purchase a blend of biofuels from licensed biofuels manufacturers with a minimum of 5% volume per volume (v/v) of biodiesel (a blend with diesel), and between 2 and 10% v/v of bioethanol to petrol. Biogas ‘blending’ into compressed natural gas as a transport fuel is currently not included in this legislation. Once this regulation is promulgated it may facilitate hybridisation of the transport sector in South Africa. Of note however is the concern that the use

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of biodiesel-blends can impact engine warranties, which may constrain uptake in the renewable fuel market.

• Regulatory Framework of Waste Management in South Africa Waste management and related legislation, are not confined to the environmental realm only. There are numerous government departments (such as the Department of Environmental Affairs, Department of Energy, Department of Public Enterprise, Department of Water Affairs, Department of Agriculture, Forests and Fisheries and more) that need to understand, manage and facilitate the use of waste and by-products due to the nature of their mandates. The waste sector in South Africa has been guided by the White Paper on Integrated Pollution and Waste Management published in 2000, the National Environmental Management: Waste Act, 2008 (NEM:WA, Act 59 of 2008) and the National Waste Management Strategy (NWMS) amongst other legal requirements for the private sector triggered depending on the waste project being developed (GreenCape, 2014). Waste legislation is fragmented, with a number of regulations and Acts defining waste from different perspectives and stipulating different regulatory requirements. The current legislative context also does not consider technological advancements and the economically viable applications of different waste streams (AltGen Consulting, 2016). Government recognises the various constraints in the waste sector and is considering policies and measures to accelerate the waste recycling economy and growing the waste-to-energy economy. The recent public sector Chemicals and Waste Phakisa project is an example of development in this sector, which plans to divert 19.7 million tonnes of waste from landfill, of which 13.6 million tonnes will be recycled (Parliamentary Monitoring Group, 2017). In addition to the key pieces of legislation discussed above, project developers must be cognisant of the Municipal Structures Act (Act 117 of 1998), Municipal Systems Act (Act 32 of 2000) and Municipal Finance Management Act (Act 56 of 2003) which govern the municipal procurement processes in South Africa. These regulations are triggered for projects undertaken with the municipality as a stakeholder. The regulatory framework for waste in South Africa is specifically relevant to the biomass and bio-energy contexts. There are numerous bioenergy resources in South Africa including a number of defined waste streams. The spread of these resources coupled with the small and modular nature of the relevant technology applications offers a number of bioenergy hybridisation opportunities. However, the current policy landscape in terms of waste regulations has been found to have an ambiguous effect on the biogas industry: both inhibiting from complex, unclear requirements, and enabling of an undefined playing field (AltGen Consulting, 2016). Waste legislation is seen as fragmented, with a number of departments defining waste from different perspectives and driving different innovation initiatives. In this regard, clear and streamlined policy guidelines with regard to waste and the use of waste to provide energy services are lacking or conflicting but are essential for the use of the renewable resources. Such guidelines could contribute to an improved understanding of the bioenergy

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market, its development opportunities and also provide direction with regards to regulatory approvals.

• Local municipal guidelines on embedded generation in 2016 Across South Africa, local and national government have been involved in efforts to develop small-scale embedded generation (SSEG) rules and regulations to support the growth of the embedded generation market. The purpose of the rules and regulations is to give each stakeholder relevant guidance on the connection of SSEG installations connected to the municipal electrical grid and intended for own use or self-consumption by the end user (GreenCape, 2017b). The uptake of these rules and regulations have increased over the past 18 months (GreenCape, 2017b). Currently there are close to 25 municipalities with SSEG rules in place, enabling the potential for hybridisation. The municipalities with SSEG rules in place account for approximately 10% of South African municipalities, a trend commensurate with the significant increase in solar PV installations across the country (GreenCape, 2017b). The uptake of these rules and regulations presents significant opportunities for the energy services market. Four factors have contributed to the growing improvement of the business case for solar PV. These are (GreenCape, 2017b):

• Regulatory improvements that guide the uptake of embedded generation options; • Municipalities exploring the option to procure from independent power producers; • Significantly lower technology costs; • Funding and insurance of solar PV as a fixed asset by major banks and insurers,

respectively.

These solar PV market drivers are creating opportunities for equipment suppliers, project developers, technical advisors and financial investors in renewable energy generation. In 2015, the South African PV Industry Association estimated that there was market potential for up to 500 MWp annual installed capacity, given the right environment (GreenCape, 2017b). 3.7.4 Concluding notes on the South African policy context in relation to

hybridisation The local renewable energy sector’s growth was not only due to the changing policy environment. Periods of constrained energy provision and rapidly escalating electricity prices forced all manner of electricity users to consider cost-effective and stable alternatives. However, these alternatives are subject to a range of regulations and legal frameworks, which have been discussed above. The fragmented nature of the South African renewable energy policy context remains difficult, and costly, to navigate. Although the renewable energy sector in South Africa has shown growth, a policy environment with clear regulatory guidance and support for localised implementation will enhance renewable energy uptake. Hybridisation could play a catalytic role in this regard. Hybridisation could offer

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opportunities to bridge regulatory gaps in moving from existing stand-alone fossil fuel energy infrastructure to hybridised systems with renewable energy. In addition, hybridisation can be effectively scaled to provide opportunities for research and localised implementation. Opportunities for municipal project implementation are of specific relevance in this regard. Hybridisation could offer opportunities to augment existing energy infrastructure whilst phasing in increased renewable energy within municipal infrastructure systems. The proposed carbon tax, set to be implemented in 2018, could further act as a driver for companies to reduce their emissions inventory through the implementation of renewable energy hybrid systems to augment, boost or replace their existing fossil fuel facilities. In some instances hybridising a fossil fuel facility may be more economical than replacing the fossil fuel value chain entirely with one or more renewable energy technologies. This will result in a reduction of emissions and thus implementing companies will benefit from a reduced penalty from carbon tax. Similarly, the carbon tax could drive a need for renewable energy projects as part of the offset provision allowed for under this tax. Hybridisation could offer a number of energy services opportunities which could qualify as carbon offsets. 3.7.5 Policy barriers to renewable energy project development Grid and non-grid connected renewable energy projects in South Africa have to make their way through a set of obstacles and barriers. These barriers can be of a technical nature, political, information availability, or market related. The main barriers are related to the fact that renewables are relatively new in the market, and project developers require large capital investment at a high risk, operating in an uncertain policy environment. In South Africa, obtaining approvals and licences is considered to be one of the most time consuming project activities required by renewable energy project developers. These time-delays usually imply an increase in capital costs, as labour and material prices rise with time (SACN, 2013). The Municipal Systems Act (2000) empowers municipalities to pass bylaws for energy efficiency and renewable energy, however, the preferred approach by municipalities has been to develop policies, plans and strategies. It should be noted that policies, plans and strategies do not impose the same legal obligation as those created by bylaws. Municipalities with detailed energy efficiency and renewable energy strategies, and a clear motivation for initiating energy efficiency and renewable energy initiatives, have however been more successful in implementing these than municipalities approaching this area of work on an ad hoc basis. Projects carried out at municipal level have to comply with the Municipal Finance Management Act (2003). This is a factor that needs to be taken into consideration by municipalities wanting to implement renewable energy projects. The main challenges in order to comply with the Act are related to the approval of budgets, the role of national treasury in setting the local budgets, pricing and tariffs that should follow national stipulations, contracting arrangements, time frames for expense execution and special permits for long terms financial commitments. The National Energy

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Regulator of South Africa’s (NERSA) lack of enforcement of the distribution licence conditions, which empower the regulator to enforce stricter energy efficiency and renewable energy conditions on municipalities that have specified minimum requirements, is seen as being a barrier, or opportunity missed, in the implementation of energy efficiency and renewable energy initiatives (SALGA, 2013). The summary below provides an overview to some of typical barriers that renewable energy project developers face from a local/municipal perspective: Table 3-4: Barrier faced by project developers to localised or municipal renewable energy project development in South Africa

Institutional Barriers

• Approval to be provided by multiple institutions • Long processing times • The potential need for a public sector finance partner due

to capital costs • Approval of tariffs

Legal Barriers • National and municipal legislation • Securing Black Economic Empowerment partners

Expertise barriers • Experience of local companies and workers - Skills • Suitable research and development facilities

Technological barriers

• May require imported technology • Limited local manufacture capacity • Availability of parts and materials

It is important to note that each renewable energy technology is different and requires different types of development input. Therefore project developers and implementers will experience different barriers or combinations thereof relating to their specific project.

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3.8 The role of hybridisation in driving and supporting policy development

The South African market for renewable energy has shown growth over the last few years. This has happened mainly as a result of the REIPPPP (Renewable Energy Independent Power Producers Procurement Programme) as well as policy development and resultant uptake in the embedded generation sector. The REIPPPP and embedded generation both contributed to the development of policies and supporting regulations within the South African renewable energy sector and showcased market functionality and growth potential. The rapid rate of adoption of pure renewable energy technologies in South Africa over the last five years moved the country from the “research and development” phase in the technology maturity S-curve (see Figure 3-20) into the early stages of the “Growth” phase. The implication for potential renewable energy project developers is that the technology and market risk in the development of these projects are significantly reduced.

Figure 3-20: South African renewable energy technology maturity S-Curve Policy plays an important role in the uptake and subsequent implementation of renewable energy technologies in energy systems. Policies and the regulatory environment can support renewable energy development and resultant technology adoption or integration. This is as a result of policy driving new market opportunities, providing certainty in these investment markets, and incorporating the external benefits of renewable energy technologies into cost-benefit calculations. This is illustrated in the following Figure 3-21.

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Figure 3-21: The role of policy linked to the South African renewable energy technology maturity S-curve

However, an enabling policy environment alone cannot stimulate the uptake of renewable energy. Creating an enabling policy environment for technology adoption must include mechanisms for both stimulation and regulation, as illustrated in Figure 3-21. Policy mechanisms should be varied and include both incentives as well as regulations for compliance to manage the uptake of renewable energy. Both of these components can develop or hinder renewable energy integration and hybridisation with existing energy systems. In the case of South Africa, energy and renewable energy policy indicate the need and the opportunities related to a diversified energy mix, summarised in Figure 3-22. This was practically translated as part of the Integrated Energy Plan as well as the REIPPPP, both of which unlocked the renewable energy market in South Africa and contributed to technology adoption in this regard. However, the REIPPPP was focussed on national scale project development, to hybridise the grid, and occurred within a specific set of regulatory guidelines in this regard. The REIPPPP left provincial and local governments lagging behind in developing the necessary regulations to enable similar renewable energy uptake at a provincial or municipal scale. In addition fragmented policy, in terms of guidance and compliance requirements for renewable energy, contributes to market uncertainty and the constrained development of low carbon measures. Figure 3-22 indicates that whereas solar and wind power have moved into the “Growth” phase in terms of technology adoption, hybridisation has not been provided for in terms of policy. This is despite the fact that hybridisation could assist, in terms of stability and security, in the transitioning from traditional fossil-fuel based energy systems to a diversified energy mix. Hybridisation could

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• Strategy identifies opportunities.

• Strategies allow and encourage research and development.

• Pilot studies inform research and development.

• Policy supports market development.

• Policy enables implementation.

• Policy continues to regulate market maturation.

The role of Policy

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facilitate the phasing in of renewable energy by optimising existing energy infrastructure with renewable energy options. This could allow for policy to catch-up and evolve with the development in renewable energy technology application.

Figure 3-22: South African renewable energy policy development linked to technology adoption rate

In addition, the objective in terms of South Africa’s envisioned energy mix and low carbon development trajectory, would be to ensure that solar and wind energy move into the “maturity” phase. One could view this move in terms of Figure 3-22 in two ways. Firstly, hybridisation could act as a push factor, increasing the uptake of renewables in the current energy context. This would “push” technologies such as solar and wind into the “maturity” phase. Or, the improved utilisation of renewables in the current energy mix will increase hybridisation options. Thus the “pull” of hybridisation will move solar and wind technologies further into the technology maturation curve. Increasing the uptake and use of renewable energy within the South African energy context will require a balanced approach to ensure sustainable integration. Moving from one technology option to another is a process of transition, rather than exclusion. The replacement of existing energy infrastructure with alternative energy options will be costly and time consuming. In addition, from a social perspective hybridisation has the potential to keep electricity costs low but balanced against increasing environmental pressures. Integrating hybridisation as a means to extend the value of existing infrastructure whilst phasing in renewable energy, offers a cost effective, feasible and sustainable option. This is illustrated in Figure 3-23 below.

The South African case

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Key enabling policies: • Constitution (1996)• White Paper on Energy

Policy (1998)• Renewable Energy

White Paper (2003) • National Climate Change

Response White Paper (2011)

• Renewable Energy included in Integrated Energy Plan.

• REFIT.• REIPPPPP implemented.• Small scale embedded

generation.

State case for Renewable Energy

Practical initiative to move from policy to implementation

Development of local market – on national scale

Localised uptake lags behind

• Localised policies for roll-out still in infancy.• Fragmented policies – difficult to guide

development.

• Renewable energy market growth has not kept up with initial momentum.

• Stagnant and challenging sector growth in terms of project development and implementation.

• Limited policies to actively drive low-carbon development trajectory in terms of technology options, small-scale support and large scale grid access

Hybridisation Solar and wind

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Figure 3-23: Potential of hybridisation to drive increased uptake of renewable energy

Hybridisation is a practical bridge between fossil fuel based energy options and a diversified energy mix that includes renewables. Hybridisation also allows for technology share rather than technology exclusion in order to contribute to a sustainable transition away from a fossil-fuel based dominant energy sector. As a result hybridisation could play a critical role in increasing the share of renewable energy in existing energy systems.

3.9 Hybridisation trends globally The growth of renewable energy in the last decade is well documented (REN21, 2017b). Generally the growth of fossil fuel hybridisation with renewable energies forms part of this trend. Various trends are starting to emerge as countries increasingly incorporate renewable energy into their economies. The drivers shifting market preferences from fossil fuels to renewables are largely related to long term goals that take into account the negative impacts of high GHG emissions intensities and local pollution associated with the combustion of fossil fuels. The transition to cleaner economies is however a complex process that must balance future needs of the planet and current needs of society, particularly those related to energy security and sustainable employment opportunities in the fossil fuel sectors. Existing fossil fuel capacity has a replacement cost which cannot be disregarded. The ability to hybridise fossil fuel technologies with renewable sources of energy has advantages. These include the ability to generate and supply energy as and when it is needed (which many pure renewable energy applications are unable to provide), reusing or extending the life of existing infrastructure, lower capital costs, reduced GHG emissions and local air pollutants. Some of these will be considered in Chapter 4. Increasing the market penetration of hybrid applications therefore has the potential to facilitate the transition to cleaner, sustainable and inclusive economies around the world.

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Current scenario

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The sections that follow summarise the global trends in hybridising fossil fuel technologies with renewable energy, with reference to similar applications that are, or may be, feasible in South Africa’s context. The focus on South African specific hybrid opportunities was drawn from the analyses of renewable energy technologies discussed in Chapter 2 of this report. As a result, the analysis of global trends in this section focusses on hybridisation in the solar, bioenergy, wind and small scale hydro market segments. The global trends analysis culminates with a number of case studies of hybrid applications that have been terminated or are unsuccessful. The lessons learnt from these case studies may assist South Africa in avoiding or mitigating similar risks in developing hybrid applications, with a view to increasing the penetration of renewable energy in the country and transitioning to a cleaner and more sustainable economy. 3.9.1 Solar energy The assessment of solar energy technologies undertaken previously (in Chapter 2) included discussions on solar technologies that may be utilised in South Africa. The technologies discussed ranged from those related to solar heating and cooling; solar ventilation; solar electricity (PV and CSP) and solar chemistry (which involves the use of solar radiation as an energy source in the chemical processing of materials and the production of fuels). The technology assessment revealed that while solar ventilation and solar chemistry present opportunities for hybridisation with fossil fuels, the associated technologies are either still in development or not yet widely accepted in South Africa. The sections that follow therefore focus on identifying global trends related to proven solar technologies that are accepted in South Africa, namely PV, CSP and solar thermal heating and cooling, all of which are reported to have had year on year increases by the end of 2016 (REN21, 2017b). 3.9.1.1 Solar heating and cooling The total global solar thermal capacity in operation by end of 2016 is reported to be 456 GWth, which is the equivalent of 652 million square meters of collectors. The global installed capacity of wind power technologies is 487 GWe. This accounts for the highest global renewable electricity capacity, and significantly ahead of PV (303 GWe) and CSP (5 GWe) (Weiss, et al., 2017). China leads the market in terms of total installed solar thermal energy capacity (309.5 GWth), followed by Europe (49.2 GWth). Together, China and Europe currently account for 82% of the total global installed capacity (Weiss et al., 2017). Water heating Recent growth rates, per region, of solar water heaters are presented in Figure 3-24.

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Figure 3-24: Market growth of new installed capacity (unglazed and glazed water collectors) by region (Weiss et al., 2017)

The table above indicates that solar water heating markets were largely stagnant or depressed in the 2014/2015 year, aside from markets in the Asian (excluding China) and Sub-Sahara Africa. Rising electricity prices (for example in Argentina) and solar building regulations (for example in Kenya and Dubai) are reported to have been the major drivers in demand in new markets. However solar PV and heat pump technologies, supported by various energy-efficient building regulations in Germany and France, are creating intense competition in the global water heating market. Heat pumps in particular are considered cheaper and easier to install than solar water heaters, and are reported to have been the main driver of the 58% decline in the annual solar water heater market in 2015 (Weiss et al., 2017). Evacuated tube collector technologies dominate the global solar water heater market (71.5%), followed by flat plate collectors (22%), unglazed water collectors (6.2%) and glazed and unglazed air collectors (0.3%) (Weiss et al., 2017). Solar thermal energy applications for water heating (which dominate the market) are generally hybrid in nature, as they are usually combined with other energy sources and technologies, typically fossil fuel based, to provide water heating services on a consistent basis (i.e. even when the sun does not shine). The solar thermal water heating market is concentrated in single-family houses, where the residential segment accounts for 63% of the total installed collector capacity at the end of 2015 (REN21, 2017b). To date there are approximately 1.5 million square metres of solar collectors in South Africa which have been installed largely in the residential sectors for the purpose of heating water (SA-STTRM, 2015). There is potential to increase this market, which is supported by the vision in the South African Solar Thermal Technology Road Map which was proposed by the Centre for Renewable and Sustainable Energy Studies at Stellenbosch University. The global market for commercial or large-scale solar water heating systems used in multi-family buildings as well as in the tourism and public sectors has grown in recent years. The share of applications, such as solar district heating and solar process heat are increasing the share steadily, even if it is still only 3% of the global market (Weiss et al., 2017). In 2015 new installed collector

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capacity in the commercial solar water heating segment grew by 54%, accounting for 29% of the total global solar water heating collector capacity in operation (REN21, 2017b). The most widely used collectors in the large scale or commercial solar heating segment are non-concentrating technologies (88%), with the remainder (about 12%) comprised of concentrating collectors. Of the latter, parabolic trough collectors dominate (79%) (Weiss et al., 2017). The augmentation of fossil fuel power stations with concentrated solar is of particular relevance to countries like South Africa that rely on coal based electricity generation. In these instances, concentrated solar is typically used to pre-heat water or generate steam which is fed into coal boilers to augment conventional steam production. Hybridising fossil fuel boilers with steam from concentrated solar in this manner has various advantages including reduced capital costs (compared with a standalone concentrated solar power facility); the ability to convert solar energy to electric energy at higher efficiencies; reduced thermal inefficiencies associated with the daily start-up and shut down of pure CSP facilities as well as a significant reduction in carbon emissions associated with standalone fossil fuel power plants (Black and Veatch, 2013). The Martin Next Generation Solar Energy Centre in Florida in the United States is an example of successful concentrated solar hybridisation with fossil fuels on a large scale. The Martin Next Generation Solar Energy Centre is reported to be the first hybrid facility in the world to connect a solar facility to an existing combined-cycle power plant (that utilises natural gas). This concentrated solar facility provides 75 MWth that directly displaces fossil fuel usage (NREL, 2013). This application could be replicated in South Africa gas turbines used for electricity generation. The world’s largest solar thermal plant (110 MWth) is located in Denmark and used for district heating purposes. The success of the facility in Denmark has motivated project development activities in other European countries and as of the end of 2016, there were 290 large-scale systems with a total of 1.1 GWth operating in Europe, making up around 3% of the region’s total operating solar thermal capacity (Weiss et al., 2017). Due to South Africa’s climate, the country as a whole does not have a driving need for district heating infrastructure, rendering this solar hybrid application unfeasible. Solar heat for industrial processes Solar thermal energy is also used to provide process heat, which accounts for around two thirds of final energy consumption in the industry sector (Weiss et al., 2017). Global energy consumption of heat in the industrial sector outweighs global electricity consumption, and is expected to grow by 1.7% year on year until 2030. As of 2016, there was approximately 400,000 m² of collector and mirror area (equating to 280 MWth) used to produce solar heat for industrial processes (Solar Payback, 2017). Both the International Energy Agency - Energy Technology System Analysis Programme (IEA-ETSAP) and the International Renewable Energy Agency (IRENA) categorise solar heat for industrial processes as applications that heat water (discussed above) or air, or solar applications that provide cooling or refrigeration (IEA-ETSAP and IRENA, 2015b).

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Around 52% of the heat demand globally is in the low- and medium-temperature range and thus suitable for solar thermal technologies. The potential for solar thermal is evident in the commercial and industrial sectors. The food, beverages, paper and textiles sectors present notable opportunities for the solar heat segment, as these industries require more than 50% of their total process heat at temperature up to 250°C, for applications that range from drying, cooking, cleaning and extraction (IEA-ETSAP and IRENA, 2015b). The food and beverages sector is reported to contain 40% of the solar heating plants installed worldwide, followed by use to power or augment machinery (12%) and lastly within the textiles sector (10%) (Solar Payback, 2017). These sectors represent opportunities for hybridisation in the South African market. IEA-ETSAP and IRENA (2015b) reports however that the global deployment levels of solar heat for industrial purposes remain quite low, despite the technical potential. Solar Payback (2017) reports that only 0.001% of final heat consumption in the global industrial sector is met by solar thermal means. To achieve higher market penetration, IEA-ETSAP and IRENA (2015b) recommend that policy interventions be implemented that will increase awareness regarding the benefits of solar process heating within industrial applications, and that financing mechanisms or incentives be provided to cover upfront costs. The wider-reaching benefits of local manufacturing are also emphasised, where the market in India is used as a case study. India is reported to be one of the global leaders of installed solar heating applications in industrial settings, where 61% of its solar thermal capacity was used for industrial processes in 2013. The country contained 78 commercial applications of solar concentrators, all of which were parabolic dish collectors, largely for solar cooking purposes (88%). Growth in India’s industrial solar heating market is reported to be driven by capital subsidies (up to 60%), provided by the government and various donors such as the UNDP-GEF (United Nations Development Programme – Global Environmental Finance) project (IEA-ETSAP and IRENA, 2015b). The world’s largest solar process heating plant is a flat plate installation (32 MWth) located on the state-owned Codelco copper mine in Chile that supplies around 85% of the heat demand required to refine copper. Large plants have also been successfully commissioned in China (9 MWth) and the United States (5.5 MWth). IRENA estimated in 2015 that there is potential for growth in this segment, where the total potential for solar thermal is 4.2 billion MWh out of 44 billion MWh total process energy demand in 2030 (IEA-ETSAP and IRENA, 2015b). Air heating Solar air heating systems are used to generate heat in commercial and agricultural applications, often used for drying purposes. Solar air heating systems are typically designed to accommodate between 20% and 30% of the annual space heating demand of a building that is typically electricity driven, meaning that they lend themselves to hybridisation with fossil fuel electricity systems. Hot air is typically taken off the top of the collectors and then ducted into the building via the ventilation system (Weiss et al., 2017). By end of 2016, global installed capacity of glazed and unglazed air collectors was at 1,229 MWth. The main markets are located in Australia, Canada, Japan and the United States. The other markets are negligible (Weiss et al., 2017). Space heating requirements are low in South Africa compared

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with the main markets mentioned above, due to the mild climate. The development of solar air collectors depends on the costs of the technology, which in South Africa's context are fairly high considering that the country has relatively few heating days, compared with, for example, countries in the northern hemisphere (South African Weather Service, 2017). Cooling and refrigeration There is a growing global market for cooling and refrigeration by solar thermal means. Weiss et al. (2017) reports that by the end of 2015, an estimated 1,350 solar cooling systems were installed worldwide, largely in Europe (70%), and notably in Spain, Germany and Italy. The benefits of using solar include reduced energy consumption levels and the avoidance of conventional refrigerants which are associated with high global warming potentials (Weiss et al., 2017). Research by IEA-ETSAP and IRENA (2015b) finds that most product cooling through solar thermal in the food and tobacco sectors is currently done by electric chillers, implying that there are opportunities in these markets (locally and internationally) to switch to solar thermal hybrid systems. In Europe, solar cooling is also supported by various regulations such as the F-gas regulation (517/2014) which has banned various F-gases with a high global warming potentials and is also progressively capping the sale of hydrofluorocarbons on the European Union market (European Environment Agency, 2014). Implementation of such systems remain low, largely on account of the relatively high capital costs and the complexity of the associated systems. Absorption and adsorption chillers are reported to be the dominant technologies used to deliver global solar cooling services, accounting for about 71% of the solar cooling capacity in operation (Weiss et al., 2017). 3.9.1.2 Solar electricity Generation of electricity from solar sources is growing worldwide (REN21, 2017b). The potential to hybridise fossil fuel technologies with solar resources presents various opportunities to reduce the emissions associated with electricity generation while improving the security of supply from solar sources (which are not always able to meet consumer demands). The largest solar PV markets are illustrated in Figure 3-25. The Asian markets (particularly China) continue to dominate in terms of PV installations, accounting for about two-thirds of global additions. The top five markets – China, Japan, Germany, United States and Italy – accounted for about 85% of additions in 2016 (REN21, 2017b).

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Figure 3-25: Solar PV capacity and additions, top 10 countries, 2016 (REN21, 2017b)

The figure above provides insights into the growth of the overall solar PV market. Due to the structure of the available research reports detailing the growth of renewable energies, it is however difficult to disaggregate data relating to solar hybrid systems from the extensive information available on pure solar electric growth rates and future projections. This research therefore focusses on global trends of non-utility or decentralised solar installations, typically servicing the residential, commercial or industrial markets, which are grid-connected. For the purposes of this research, decentralised, grid-connected PV systems are considered to be hybridised systems based on the assumption that the respective grids are largely based on electricity generated by fossil fuels. Decentralised or distributed PV systems are defined by the International Energy Agency (2016) as installations that provide power to grid-connected customers or directly to electricity networks. Distributed systems may be on, or integrated into, the customer’s premises. This market is also referred to as the embedded generation or ‘prosumers’ segment, because it is characterised by electricity producers who are also consumers (i.e. self-consumption). These markets are supported by mechanisms such as net-metering, which allows generators to offset production against consumption, however these same producers need to be net consumers i.e. electricity is not sold to the grid but the grid is used as a bank of sorts where credits are earned. Research by the IEA (2016) indicates that the global grid connected decentralised PV market has been stable over the last three years at about 15-17 GW (since 2013), illustrated in Figure 3-26.

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Figure 3-26: Segmentations of PV installations 2011-2015 (IEA, 2016)

REN21 (2017b) notes that decentralised (residential, commercial and industrial rooftop systems) grid-connected applications have maintained a roughly stable global market (in terms of capacity added annually) since 2011. The reasons given for the lack of growth are reported as the uncertainty of the continuation of feed-in tariffs (which previously supported the rollout of decentralised systems) in various PV markets (for example in California), as well as uncertainties regarding net metering to self-consumption. An example of market uncertainty relating to net-metering is reflected in the United States, where net-metering continued to be at the centre of regulatory disputes during 2016. These regulatory disputes were reportedly instigated by large utilities that view net-metering as an anti-competitive mechanism that is putting their markets at risk. Despite these disruptions, the distributed PV market in the United States in 2016 continued to grow (albeit slowly), where large corporate customers accounted for a record 10% of large-scale additions. The non-residential (commercial and industrial) market increased 49% in 2016 as did the residential sector (up 19%) (REN21, 2017b). Distributed PV markets continued to grow strongly in other regions in 2016, where for example the distributed PV market in China tripled relative to levels in 2015. Growth was also recorded in the Japanese segment (the residential sector accounted for 11.8% of new installations) and in India’s rooftop solar market that accounted for about 10% of the country's total solar PV installed capacity (REN21, 2017b). The IEA (2016) reports that in 2015 Japan was the leader in annual capacity of decentralised grid-connect PV installation, with 6 400 MW. The United States was ranked second place with 3 145 MW, followed in third place by China with 1 390 MW.

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Overall, research by REN21 (2017b) indicates that growth in these markets has been driven largely by government incentives or regulations. South Africa’s distributed PV market is developing along these lines, considering that there is already an existing approved process to allow generator connections to Eskom’s medium- and higher-voltage networks, on the condition that these connections comply with Eskom’s technical standards for interconnection, the requirements of the SA Grid Code, the Distribution Code, and the Renewable Code. The national regulations for small-scale generators (typically rooftop PV) to the low-voltage network is in the process of being developed (Eskom, n.d and Nersa, 2015). In anticipation of the finalisation of the national framework for connecting small-scale generators to the network, close to 25 municipalities in South Africa have published their own small scale embedded generation rules or policies. These developments in local government are to allow for embedded generation for own use and net metering. The viability of rooftop solar is particularly sensitive to the local electricity tariffs which embedded generators will need to compete with to be viable. This may explain why embedded generation levels remain low. The IEA (2016) reports that net-metering is increasing in various regions, and has been announced or implemented in Dubai, Lebanon, Chile, some Indian states and more. The IEA further finds that net-metering presents opportunities for emerging PV markets because it is relatively easy to implement (compared with other incentives such as feed-in tariffs or taxes) and does not require investment in complex market access or regulation for the excess PV electricity. Other examples of solar electric hybridisation with fossil fuels are evident in the development of hybrid mini-grids. REN21 (2017b) reports that 30 hybrid mini-grids are planned for development in Tanzania. These solar-diesel-power systems are expected to provide power to 2 000 customers. It is further noted that electronic or mobile phone payment models are increasingly being used to escalate the penetration of pico-solar products and other solar home systems, which may present opportunities for hybridisation. As of 2016, more than 32 companies operating in over 30 countries in Africa and South Asia were selling solar products for an upfront fee and regular payments through mobile money services (REN21, 2017b). 3.9.2 Bioenergy The residential sector accounts for the greatest use of bioenergy globally, typically for heating purposes (Figure 3-27). While most of this bioenergy is still associated with unsustainable, traditional biomass use, the use of biomass for power and commercial/industrial heating applications has continued to grow in recent years (IEA & FAO, 2017). REN21 (2017b) reports that from 2000 to 2015 the number of bio-power co-generation plants quadrupled to a total global generation capacity of 106,400 MW (equal to around 140 coal power plants with an average capacity of 750 MW). It is important to note that plant based biomass sources of energy need to be sustainably managed in order to avoid the risks associated with increased, instead of decreased, GHG emissions. Furthermore the environmental impacts associated with the agricultural practices and transport of

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biomass feedstocks also need to be carefully considered to ensure that the practices do not increase negative environmental impacts. The global bioenergy consumption for heat, transport and electricity is presented in Figure 3-27

Figure 3-27: Global bioenergy consumption for heat, transport and electricity in 2004 and 2014 (IEA & FAO, 2017).

Biomass and solar thermal energy are reported to account for the vast majority of modern renewable heat in the building sector (7% - 10%) (REN21, 2017b). Bioenergy further dominates renewable heat production in the industrial sector, accounting for around 10% of total demand (REN21, 2017b). Research undertaken by REN21 (2017b) indicates that the global heating market will go through a major transition towards renewable energy over the next 30 years. The United Nations (2014) further forecasts that nearly 66% of the global population will live in cities by 2050, implying that the demand for energy will increase dramatically in urban areas. Biomass is therefore increasingly recognised for its potential for hybridisation and decarbonising electricity systems by providing a stable source of low-carbon baseload electricity (IEA & FAO, 2017). Research undertaken by IRENA-IEA indicates that biomass co-firing can be considered as a transition option towards a lower or carbon power sector (IRENA-IEA-ETSAP, 2013b). Growth in biomass for heating purposes has reportedly lagged behind power production on account of economic and policy challenges such as low oil prices and limited policy support. Policy challenges mostly revolve around setting appropriate sustainability criteria which aim to prevent increased pressure on land and water resources; greater emissions of lifecycle GHGs and particulate matter, as well as biodiversity losses (IEA & FAO, 2017). Increasing pressures to reduce global GHG emissions are motivating the increased use of sustainable biomass in energy systems. McKinsey and Company assert that Europe’s climate goals provide opportunities to materially revive and grow the bioenergy industry (Albani, Bühner-Blaschke, Denis and Granskog, 2014). Many European countries and the Unites States further support bioenergy through policy incentives (e.g. feed-in tariffs) or mandatory regulations to increase renewables’ share in their electricity sectors (Dong, 2012). Co-firing of biomass in utility

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and industrial applications to produce heat or power is particularly well supported by these national policy interventions, and as a result, most biomass co-firing projects take place in these countries (IRENA-IEA-ETSAP, 2013b). South Africa does not currently have feed-in tariffs or mandatory regulations that support the use and development of bioenergy in the country. The Clean Development Mechanism (CDM) however recognises biomass co-firing as a way to reduce GHG emissions in developing countries, and registered projects are eligible to generate and trade in carbon credits. The CDM also recognises that co-firing and other bioenergy generation methods need to be undertaken in ways that do not negatively impact the environment. A number of CDM biomass projects have been registered in South Africa, however the low price of carbon and the market barriers inherent in the European Union’s Emissions Trading System have constrained the registration of biomass projects in South Africa. Of the biomass technologies and designs currently available, direct biomass co-firing in combined heat and power plants is considered the simplest, cheapest and most common technology option (IRENA-IEA-ETSAP, 2013b). For example in the South African environment, bagasse is routinely burnt in boilers to provide low pressure steam for process energy for sugar mills. Improving the efficiency of many of the existing boilers is required, which could reduce the amount of sugarcane bagasse needed to generate the process energy. Additional lignocellulosic material could subsequently be used for conversion to chemicals and excess electricity (for export sales from the sugar mill). In addition, the use of bagasse and harvest residues from the sugar industry is beneficial because these are a non-food feedstocks, meaning that there is no competition with land that could be used to produce food (Gorgens, J., Mandeagari, M., Farzad, S., Dafal, A. and Haigh, K., 2016). Combined heat and power facilities are often used in industrial applications. The overall efficiency of these plants is higher than dedicated biomass facilities, thereby enhancing the attractiveness and economic feasibility of biomass co-firing (IRENA-IEA-ETSAP, 2013b). Biomass levels in most co-firing facilities are below 5%, rarely exceeding 10% on a continuous basis (IEA Clean Coal Centre cited in IRENA-IEA-ETSAP, 2013b). The co-firing mix depends on various factors including logistical and economic constraints relating to feedstock and technology types (IRENA-IEA-ETSAP, 2013b), as well as the adjustments required where retrofitting takes place. Most of the co-firing facilities in Europe and the United States are combined heat and power plants, ranging in capacity from 50-700 MWe. By 2012 there were more than 169 co-firing facilities in Europe. Finland comprised the largest number of coal-fired power plants that co-fire biomass, followed by Germany, the UK, Sweden, Denmark, Italy and the Netherlands. Fluidised bed combustion installations (ranging from 20–310 MW) are typically employed in Finland, where different biomass wastes from the wood industry are directly co-fired with different types of fuels (Dong, 2012). By 2012 there were over 47 co-firing facilities in North America where woody biomass provided 0.9% of total electric power generation. 73% of the total biomass electric power was generated in industrial combined heat and power applications (Dong, 2012). The pulp and paper industry in the United States has co-fired wood (primarily bark and chips) with coal for decades. Biomass

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fuels are reported to provide more than 50% of the total fuel input in the pulp and paper industry (US Department of Energy, n.d). As of 2012, there were about eight biomass and coal co-firing power stations in Australia and a small number in Asia. China in particular has a large market potential for co-firing biomass in coal-fired power plants however this practice is constrained due to lack of supporting financial incentives (Dong, 2012). The risks of bioenergy markets include the development of unsustainable value chains, deforestation and soil degradation. This is illustrated in the move from the combustion of coal to charcoal to produce steel in Brazil. Charcoal either replaces the use of coal or is co-fired with coal to provide heating services. This practice can reduce CO2 emissions when the charcoal is sourced from sustainable forests and high quality charcoal production activities. Many of these activities were registered as mitigation projects under the CDM. Criticisms relating to the practice have been raised however, as the growth in the market for charcoal has led to the harvesting, and in some instances the destruction, of native forests in Brazil which has increased deforestation rates by 200 thousand hectares per year (Nogueira, Coelho, and Uhlig, n.d). The demand for charcoal, particularly from the steel sector, has therefore prompted growing concern about the future supply availability of biomass sources for charcoal production in the country. Furthermore recent studies suggest that unsustainable and often illegal methods employed to make the charcoal have increased, not decreased, CO2 emissions (Nogueira, Coelho, and Uhlig, n.d). Insufficient policy measures and enforcement of regulations are cited as some of the main reasons behind this phenomenon (Phys.org, 2015). The example of the Brazil charcoal sector illustrates the critical requirement that bioenergy activities must be based on sustainably managed sources. Overall, electricity generated from biomass has grown steadily since the year 2000, largely in the United States and Europe, and in 2014 represented about 8% of renewable generation and nearly 2% of global electricity generation. Biomass power is also growing in China and Brazil, largely due to support programmes for biomass electricity generation, in particular related to the use of agricultural residues. Projections indicate that biomass electricity production will reach 590 TWh by 2020, with a 5.5% compound annual growth rate over 2014-20 (IEA & FAO, 2017). Countries and regions characterised by large sugarcane yields (such as Mauritius, La Réunion, Guatemala, Guadeloupe, India and the Dominican Republic) typically use bagasse as an alternative fuel, along with coal. Similarly, countries, such as Malaysia and Thailand use rice husks for energy purposes. Brazil on the other hand is reported to have significant bagasse co-generation capacity (7.3 GW in 2011) but does not combine biomass with fossil fuels (IRENA-IEA-ETSAP, 2013b). South Africa has limited agricultural resources that could represent opportunities for the hybridisation of biomass with fossil fuels. Some of the major constraints include the economics involved, particularly considering the costs and energy consumed in the transportation of feedstock supplies, this will be covered in Chapter 4. The global production of biofuels (particularly bioethanol and biodiesel) grew strongly from 2000 to 2010, largely as a result of increased policy support (such as blending mandates); favourable feedstock costs and relatively high petroleum-based transport fuel prices. While growth rates have

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subsequently decreased, forecasts predict increases in annual production in the near future (IEA & FAO, 2017). The increased adoption of blending targets or mandates in over 50 countries, including several non-Organisation for Economic Co-operation and Development (OECD) countries, is likely to drive growth in the biofuel markets (IEA, 2011c). Bioethanol produced from sugarcane is currently the most cost-effective commercial biofuel and has the highest energy balance of all commercial bioethanol (IRENA, 2016b). Research by IRENA found that there is substantial scope for cooperation between Brazil and Africa, with regards to the transfer of skills, technology and capacity-building relating to sugar based bioethanol production and the development of the related markets (IRENA, 2016b). Conventional biofuels provided around 4% (134 billion litres production) of world road transport fuel in 2015 and are expected to reach almost 4.5% in 2020. The United States and Brazil are the largest biofuels producers (principally bioethanol). Other significant producers include the European Union, Argentina and Indonesia (principally biodiesel) (IEA & FAO, 2017). Growth in the global sector withstanding, the results of numerous studies highlight the environmental and social challenges that have been conclusively arising from the development of biofuel markets, particularly where these involve the use of a traditional food crop. For example, two extensive studies by the High Level Panel of Experts (HLPE) on Food Security and Nutrition (the science–policy interface of the UN Committee on World Food Security) have found that relationships between biofuels and the environments from which they are sourced are especially challenging (HLPE, 2013). Issues concerning food security and land use were highlighted, where the practices and policies related to biofuels production can have negative impacts. The latest HLPE study found that the use of biofuel crops directly impacts the availability of food. The result is an increase in basic food prices, which in some instances encourages consumers to switch food supplies. This in turn was found to be one of the reasons that price increases spread to other crops. Palm oil is another contentious biofuel that is reported to account for the entire growth (34%) in EU biodiesel between 2010 and 2015 (Transport and Environment, 2016). A recent study undertaken by the European Commission (2015) reveals that palm oil feedstocks are associated with very high land use change emissions (231 grams of CO2e per mega joule of biofuel consumed, this is high in comparison to sunflower production for biofuel at 63gCo2e/MJ and can be compared with 96.6 gCO2e/MJ of coal combusted). The drainage of peatlands in Malaysia and Indonesia was found to be particularly damaging, contributing 69% of gross land use change emissions associated with palm oil. Deforestation is another concern, contributing to mounting pressure to ban the use of unsustainable palm oil use in biofuels across the European Union (The Guardian, 2017). While OECD countries are expected to drive the demand for biofuels in the short term, it is anticipated that non-OECD countries will account for 60% of global biofuel demand by 2030 and roughly 70% by 2050. China, India and Latin America are expected to have the highest demand for biofuels. Conventional biofuels (which are less costly and complex than advanced biofuels) are expected to lead in these markets, whereas advanced biofuels markets are expected to increase in the United States and Europe, as well as Brazil and China to lesser degrees (IEA, 2011c).

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South Africa has made some progress in developing a biofuels market, and has published in August 2012 draft regulations on the mandatory blending of bio-ethanol or biodiesel with petroleum petrol and petroleum diesel respectively. These draft regulations fall within the Petroleum Products Act of 1977. These regulations have however seen an ongoing delay in promulgation and have thus hindered the biofuels sectors in the county. 3.9.3 Wind energy As an individual technology wind energy has been growing rapidly. Almost 55 GW of wind power capacity was added during 2016, increasing the global total by about 12% to nearly 487 GW (REN21, 2017a). During 2016, South Africa installed 418 MW of new wind capacity, with a cumulative total of 1 471 MW (GWEC, 2016). Actual wind capacity procured during the Department of Energy’s large and small scale Renewable Energy Independent Power Producer Procurement Programmes amounted to 3.4 GW (Independent Power Producer Procurement Programme Office, 2016). The Eastern Cape has significant resource potential in terms of wind energy and are representing 43% of the procured wind power (Department of Energy, 2015a). These developments support the findings that wind has become the least-cost option for new power generating capacity in an increasing number of markets (REN21, 2017a). Wind energy has the potential for a number of hybridisation applications, however to date some hybrid applications have gained more momentum than others. The hybridisation of wind electricity generation with storage through compressed air, batteries and hydrogen are all still in early stages of development. There are currently only two compressed air storage plants in existence and these are not linked to wind power plants (Energy Storage Association, 2017). The potential for compressed air storage to balance energy supplies from wind energy has been hailed as a strong prospect for the future (Energy Storage Association, 2017). This is a good solution for day to day storage, similar to pumped hydro storage, and is slightly more expensive that pumped storage, but cheaper than lithium batteries (World Energy Council, 2016). Compressed air energy storage costs EUR 180 - 280/MWh and pumped hydro at EUR 80 - 200/MWh, (World Energy Council, 2016). The renewable energy developer ACCIONA has developed the first hybrid wind and battery storage power plant in Spain in 2017 (ACCIONA, 2017). There is also ongoing research into storing energy harnessed from wind as hydrogen as a fuel. However, the costs of this technology have prohibited development beyond experimental stages (Douak & Settou, 2015). Similarly, there are few examples of wind energy being used to augment or boost fossil fuel power plants. A wind, natural gas and solar hybrid plant was proposed to be developed by General Electric in Turkey in 2011, however there is no record of whether this plant has ever been developed (MIT Technology Review, 2011). In contrast policies internationally have positively influenced the market for small-scale turbines, which are used for a variety of hybrid applications, including, rural electrification, water pumping, battery charging, telecommunications, and increasingly to displace diesel generators (REN21, 2017b). Small-scale wind systems are generally considered to include turbines that produce enough power for a single home, farm or small business. The International Electrotechnical Commission sets a limit at approximately 50 kW, and the World Wind Energy Association (WWEA) and the

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American Wind Energy Association define“small-scale”as up to 100 kW, which is the range also used in the REN21 Global Renewable Energy Status Report. In 2015, the global small-scale turbine market grew by 5-7% with the total installed capacity increasing by 12-15% (REN21, 2017b). More than 995 000 small-scale turbines (over 935 MW) were operating worldwide at the end of 2015, (REN21, 2017b). China currently has the largest installed capacity of small scale turbines, 415 MW, with other world leaders including the USA, United Kingdom, Italy and Germany (REN21, 2017b). Italy and Japan have been two of the faster growing markets of small scale wind turbines with other countries experiencing lower growth with competitive solar PV prices. In South Africa, Nelson Mandela Bay Municipality also launched a Small Scale Embedded Energy Generation (SSEG) initiative in 2013, which allows industry and residences to generate power using wind or solar energy technologies (DTI, 2015). Other municipalities such as, eThekwini Metropolitan Municipality, the City of Cape Town, the City of Johannesburg and Tshwane also have policies on embedded generation in place. In addition to wind for electricity production, it has long been established that it can also be used for mechanical power. Windmills use wind energy to drive a shaft that can be used to pump water, to mill grains or for use in drying and ventilation activities. Wind pumps are used today in many rural and remote locations where the costs of electrical installations of electric pumps and infrastructure are more expensive than direct wind driven pumps. These applications, at a small scale, can continue to provide useful energy services at farms and small industries applicably located in areas with wind resources, where grid electricity is conventionally used to power equipment. The local wind pump market in South Africa, is well established with over 200 000 installed wind pumps, the majority of which are used to pump borehole water (Stewarts and Lloyds, 2017). 3.9.4 Small and micro scale hydro energy Small hydropower is a proven, mature technology with a long track record of industrial implementation around the world. As early as 1892 small turbines (6 kW) were used to power gold mines in South Africa (Klunne, 2011). Many African countries have a rich history of small scale hydropower, but over time large numbers of these stations have fallen in disrepair due to facility connection to the national grid, lack of maintenance or even just neglect (Klunne, 2011). According to international reports South Africa currently has a total installed capacity of 50MW of small hydropower, and a proven potential of 247 MW, (Klunne, 2016). Recently a number of countries in Africa have put initiatives in place to revive the small hydropower sector, either through international development agencies or through private sector led initiatives. The Integrated Resource Plan (IRP) for South Africa, through the REIPPPP aims to install an additional 75MW of small hydropower in the country by 2030 (Klunne, 2016). Through REIPPPP three small hydropower plants have already been installed with a total capacity of 19.1MW feeding electricity into the national grid. In addition to that which has been installed through REIPPPP, a number of privately owned small hydropower plants have been installed for private electricity consumption.

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Globally small scale hydropower had an installed capacity of over 110 GW in 2015 and the industry expects an annual growth of above 2.5% up to 2024 (Global Market Insights, 2016). Higher growth rates are expected for Central and South America based on the large hydropower potential in those regions. The global small scale hydropower market share is competitive and mainly influenced by government regulations & energy targets. Key industry participants include Voith, Andritz Hydro and GE, Siemens. Other prominent companies include Agder Energi, 24H - Hydro Power, Lanco, Derwent, StatKraft, RusHydro, and Fortum Oyj (Global Market Insights, 2016). Most of the challenges facing small hydropower exploitation are not specific to hydropower but generic for all types of renewable energy and rural electrification projects. One of the barriers for small scale hydropower projects is the absence of clear policies and regulations to guide development (Klunne, 2012). A second barrier is financing challenges for small scale hydropower that experiences greater difficulty than other renewable energy projects due to high up-front costs (CAPEX) and low operational and maintenance costs (OPEX), something most available financing models do not favour (Klunne, 2012). A lack of capacity to plan, build and operate hydropower plants presents a knowledge barrier for small scale projects (Klunne, 2012). Similarly, data on hydropower resources can also be limited and present an additional knowledge barrier for small scale hydropower developments (Klunne, 2012). This may present difficulties for the future growth of small scale hydropower in Africa. 3.9.5 Lessons learnt from unsuccessful hybridisation projects Following on from the global trends in hybridisation, there are various lessons that can be learnt from unsuccessful hybridisation projects spanning both global and local examples. Examples of unsuccessful hybridisation projects are presented in Table 3-5. For each example the type of hybridisation and the technology is specified as well as how the renewable technology has been integrated into the existing fossil fuel system. The challenges and key lessons learnt are identified and will be used as considerations for the potential of hybridisation in the South African context. Some of the examples presented are not project specific but rather make reference to the challenges faced within a specific industry, which also have various associated key lessons.

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Table 3-5: Challenges and key lessons learnt from unsuccessful hybridisation projects

Project details Location Type of hybridisation

Technology utilised How integrated Challenges Key lessons learnt

1 CS Energy is owned by Queensland government and is a major provider of electricity to the National Electricity Market. CS Energy started developing a solar booster project at their Kogan Creek coal fired power station (750 MW) in 2011 (Parkinson, 2016). The solar booster project aimed to add 44MW of solar thermal to the Kogan Creek power station during peak solar conditions.

Queensland, Australia

Solar CSP and coal-fired boiler for steam production

Solar thermal system, utilising Compact Linear Fresnel Reflector (CLFR) technology (Aurecon, n.d.; Parkinson, 2016).

The solar thermal system aimed to provide steam to augment the coal-fired steam and result in an increase in steam flow through the turbine and an increase in exported electricity to the grid (Aurecon, n.d.).

Technical and contractual difficulties were encountered during construction, negatively impacting on the project’s commercial prospects (Parkinson, 2016). Technical issues related to the addition of boiler tubes to account for the extra heat provision from the solar thermal. Contractual issues included the exit of the service provider AREVA Solar from the project. In 2014 AREVA withdrew all of its operations from Australia so that the company could focus its efforts on its third generation nuclear projects in Finland and France (Parkinson, 2016). Ultimately the solar thermal addition could not be commercially deployed without substantial financial investment. There was doubt that the project would ever make a positive return on

Project feasibility can be an issue if the contract with the renewable energy technology provider is unstable. Significant financial investment is required when implementing solar thermal technology such as the Compact Linear Fresnel Reflector technology in this example.

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investment and thus the project was terminated as there was no business case (Parkinson, 2016).

2 Liddell Power Station is a coal fired thermal power station with four 500 MW steam driven turbo alternators with a combined electrical capacity of 2000 MW (AGL, n.d.). The plant was to be hybridised with a 9MWth concentrated solar plant.

Lake Liddell, New South Wales, Australia

Concentrated solar thermal installation for solar/coal-fired power augmentation, feeding steam into the existing coal fired power station and reducing the coal required to operate the facility.

Compact Linear Fresnel Reflector (CLFR) technology

The solar steam supply temperature can be up to 400°C. This heat increases the temperature of the heat-transfer fluid, water, to produce steam. The system aimed to replace the boiler extraction steam used for feed water heating with solar generated steam. In this way all the steam generated from the coal fired boiler can be used for electricity production, increasing output

The incentive to implement a solar booster project was reduced due to the removal of the carbon price and the excess coal supply in Australia (Parkinson, 2016).

Abundance of fossil fuels and low fuel prices can reduce the viability of renewable energy hybrid projects. A lack of policy incentives for low carbon or renewable energy projects can negatively impact the project business case.

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from the plant without increasing emissions. (AREVA Solar, n.d.; Parkinson, 2016).

3 The US congress created the Renewable Fuel Standard (RFS) program to reduce GHG emissions and expand the nation’s renewable fuels sector, with the aim of reducing reliance on imported oil (EPA, 2017c).

USA Blending gasoline with biofuels, typically corn-based ethanol.

Corn-grain ethanol in the United States is produced in both wet and dry mills (Naik, Goud, Rout, & Dalai, 2010).

Corn-grain ethanol in the U.S. is blended with gasoline, primarily as E10 (up to 10% ethanol blended with 90% unleaded gasoline). A key benefit of E10 is that it is compatible with existing vehicles and infrastructure, including fuel tanks and retail pumps (Schnepf & Yacobucci, 2013).

Feedstocks used for first generation bioethanol are directly or indirectly used for food production, thus sparking the “food vs fuel” debate, (Ajanovic, 2011; Babcock, 2012; Srinivasan, 2009). In addition, the fuel blend limit for bioethanol blending is set at a maximum of 10%, related to the compatibility with existing vehicles and infrastructure, (Schnepf & Yacobucci, 2013). However during 2010, the ethanol production volumes in the US surpassed the capacity that could be blended with conventional motor gasoline. This capped the demand and reduced price of bioethanol, causing some of the bio-

Using food crops for bioethanol is controversial. There are strong links between bioenergy and the agricultural and forestry sectors. Therefore attention should be given to food security and environmental protection (IEA & FAO, 2017). Blending limits of bioethanol as well as impact on engine warranties can compromise the growth of the industry.

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refineries financial feasibility issues.

4 Canada has investigated remote wind-diesel hybrid systems for several years. Canada has over 200,000 citizens in approximately 300 remote communities that are not connected to either territorial or provincial electric grids (Ah-You and Leng, 1999). These remote communities rely on diesel powered electric generators. However diesel fuel costs, fuel spills, emissions and long term sustainability were issues raised by the communities (Weis et al. 2008). Wind-diesel hybrid systems were therefore investigated as an alternative by utilities and governments.

Remote Canadian communities

Wind-diesel for electricity generation.

Wind turbines and diesel generators.

Wind turbines and diesel generators are jointly used to provide electrical power.

Capital and operating costs were significant barriers to wind-diesel systems, along with the technical maturity of wind-diesel systems. Access to appropriate equipment and skilled labour in remote communities was also a reason for failure (Weis et al. 2008).

Capital and operating costs, lack of technical maturity and remote locations can inhibit the implementation of wind-diesel hybrid systems.

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5 The Beema Bamboo project consists of a 320 ha bamboo plantation in Ilembe, KwaZulu-Natal, a tissue culture laboratory for the propagation of the bamboo shoots and a power plant that will use the bamboo as a feedstock to generate electricity using gasification technology. The project aimed to supply biomass to the Pulp and Paper Industry in South Africa.

KwaZulu-Natal, South Africa

Biomass-coal boiler for electricity generation

Gasifier/ pyroliser

Biomass and coal feedstock for the generation of electricity.

Although the Beema Bamboo plantations have successfully been implemented, the project has yet to supply biomass to the Pulp and Paper Industry for electricity generation. The project experienced a number of challenges one of the major delays was the acquisition of a water use license. The drought in South Africa over recent years also caused delays as large amounts of water was required. In addition, the project encountered challenges with respect to the local community in terms of land availability and utilisation.

Hybridisation projects making use of biomass need to consider the implications of water use and land availability. The sustainable management of these plantations is highly important to ensure no increase in overall emissions of such a project.

6 In 2008, the South African Department of Energy launched a national Solar Water Heating Programme with the aim of supplying 1 million homes with solar water heaters over a period of five years. To date the programme has rolled out 424 790 solar geysers.

South Africa Solar water heater hybridising conventional grid connected geysers.

The installed solar water heater technologies included evacuated tube and flat plate collector systems.

Conventional geyser connected to both the solar water heater and the grid.

A major challenge faced by private residences and commercial building owners is the initial capital outlay for a solar water heater, even with offset subsidies (Rycroft, 2016). Eskom withdrew from the programme in January 2015, to focus on energy provision. As

Capital costs of solar water heaters can hinder private sector implementation. Government support and backing is critical to ensure successful implementation.

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The original programme was managed by Eskom and was targeted at private and commercial buildings that already had geysers and electricity, with the aim of reducing the demand by electric geysers on the grid (load reduction programme). Eskom provided a financial incentive (in the form of a rebate or subsidy) on the purchase price of installed solar water heaters based on the reduction in peak demand and energy achieved.

such Eskom handed over the reins of the project to the Department of Energy (Moodley, 2015). In March 2015, the Department of Energy officially halted the project due to poor quality installations and unreliable data on the number and location of the installations (Moodley, 2015). The project focused on increasing local manufacturing capacity within South Africa. One of the requirements for participation in the programme was 70% local content. However this led to the collapse of the local industry as these requirements could not be met (Rycroft, 2016).

Local manufacturing of the technology, to meet local content requirements, may require additional government support and capacity building.

7 Collinsville Power Station in Queensland is a 180 MW coal fired power station. A project was undertaken which aimed to assess the viability of converting the existing coal fired power station to a 30 MW hybrid solar thermal/gas power

Queensland, Australia

Hybrid solar thermal/gas power station

Linear Fresnel Solar Thermal Technology

The hybrid power station comprises a 30 MW solar steam generator and a gas‐fired boiler capable of operating independently or

The project was not implemented due to economic feasibility issues. The studies found the old power station could not be transitioned as the new technology and costs were going to be significantly higher than initial estimates. Initial estimates for the

Lacking government policy frameworks and funding can result in project failure.

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station utilising existing equipment from the coal power plant (RAC, 2013).

with the solar field to maintain full steam supply to a conventional turbo‐generator (RAC, 2013). The use of a dual-fuelled boiler aimed to enhance grid reliability from the project.

project’s costs were expected to increase by as much as 84% (Maddison, 2014). At the time government policy framework did not support investments in technologies such as solar thermal. The private sector was unable to fund the project without government support (Maddison, 2014).

8 In 2009 the European Union directive set a mandatory blending target of 10% renewable energy for transport (Mekhilef et al. 2011; Skogstad; 2017). The EU encouraged the use of first generation or conventional biofuels, such as biodiesel from palm oil. Indonesia is the largest palm oil producer in the world. The palm oil industry contributes positively to the Indonesian economy (Sheil et al. 2009) and the wellbeing of farmers (Rist et al. 2010).

Europe Indonesia

Blending biodiesel with 100% mineral diesel.

Biodiesel is produced through transesterification.

A biofuels target within the transport sector was set at 10% in 2009 (European Parliamentary Research Service, 2015).

Palm oil production in Southeast Asia converts rainforests into plantations. Indirect land use change effects reduce the GHG savings from biofuels (Skogstad; 2017; Hidayat et al. 2017). In addition the deforestation results in biodiversity losses (Hidayat et al. 2017). Large scale palm oil plantations can damage soil (leading to soil erosion) and lead to water quality and quantity problems (Mukherjee and Sovacool, 2014). The EU’s biofuel policy was criticised for not considering emissions associated with indirect land

Hybridisation projects linked to biofuels need to consider water use impacts and land use change effects. Importantly, emissions related to the use of biodiesel versus emissions related to land use change must be carefully considered to ensure project relevance and sustainable impact. Land use change, specifically deforestation, should consider broader environmental impacts

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use change (European Parliamentary Research Service, 2015). As a result by mid-2014, the EU decision makers agreed to cap the contribution of biofuels to the transport fuel target and did not signal support for biofuels beyond 2020 (Skogstad; 2017). More recently, Indonesia has developed a sustainability standard and certification scheme for palm oil – Indonesian Standard Sustainable Palm oil (ISPO) (Hidayat et al. 2017).

such as biodiversity loss. In addition, management methods with regards to soil restoration should form part of these projects, e.g. integrating erosion control measures as part of the project to limit soil damage. The option of biofuels should however not be discounted, as various palm oil plantations are implementing sustainable practices. These include no deforestation, no peat development, and no exploitation policies (Shah, 2017). Further sustainable practices include determining high conservation value (HCV). HCV assessments identify areas of high ecological, social, and cultural value that must be managed to ensure those values are

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maintained over the long term (Thomas et al, 2015). In addition, social considerations are critical to sustainable practices. Effective stakeholder engagement and the recognition of communities’ right to freely give or withhold their free, prior, informed consent are critical to preventing and/or mitigating conflict with communities over land tenure and usage rights (Thomas et al, 2015).

9 The village of Lucingweni in the Eastern Cape consists of 220 homes and is located 4 km inland from the Hluleka nature reserve. Lucingweni was chosen to demonstrate the suitability of hybrid mini-grid energy systems for areas without access to electricity or to areas with limited supply of

Eastern Cape, South Africa

Solar-wind mini grid supplying community’s energy demand

Solar PV panels, wind generators and associated control, accumulation and distribution equipment (Department of Minerals and Energy, 2008;

The wind (36kW) and solar (56kW) hybrid system was combined with a storage battery bank with an effective capacity of 10,140 amp hours. (Department of

The Lucingweni mini grid faced multiple challenges including insufficient risk analyses and inadequate evaluation of available natural resources (Department of Minerals and Energy, 2008). The project’s sustainability was threatened due to a lack in community participation and transfer of skills. The energy

The value of conducting feasibility studies should not be underestimated. Comprehensive risk analyses, technical commercial and financial evaluations are critical to the success and sustainability of hybrid mini-grid systems. The importance of resource

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electricity (Szewczuk, 2009). The demonstration was managed by Shell Solar South Africa. The mini-grid consists of solar PV panels (560 panels, each 100 W) and wind generators (6 generators, each 6 kW). Solar supplied the solar PV panels and the wind generators were imported from the U.K. The electricity generation capacity for the mini-grid is 86 kW.

Szewczuk, 2009).

Minerals and Energy, 2008). The two renewable energy resources were to supply electricity to the community of Lucingweni, with the electricity generation capacity of 86kW.

profiling of the community’s energy needs was not appropriately considered. The lack of community consultation resulted in community expectations not being met and subsequent vandalism of the equipment soon after installation (DEA, 2016). In addition, the evaluation of technical, commercial and financial viability was lacking.

availability is very clear in order to provide a solution to a community. Sufficient skills transfer needs to be carried out to ensure sustainability as well as ensuring stakeholder consultation to ensure the project form part of the community’s needs and wants. Without by in from the community such projects won’t be sustainable.

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From the case studies considered, examples of unsuccessful hybridisation activities are apparent at project level as well as at broader policy and sector levels. At project level, hybrid activities were typically unsuccessful at two stages: failure to progress from the feasibility stage due to technical, funding or capacity issues and failure after the implementation stage due to other reasons, for example changing market needs. Overall, the lack of a supporting policy environment was one of the most common reasons behind the failure of the hybrid projects considered. International trends conclude that supporting and maintaining a supportive policy is essential for the development of renewable energy and hybrid applications. Research by REN21, (2017b) points to strong policy support for renewable power generation in 2016 (and some preceding years) in various countries that has stimulated the development and growth of renewable energy. South African policies on renewable energy, emission reductions and carbon offsets therefore have the opportunity to replicate lessons learnt from other countries and regions which have been successful in this regard. Another barrier to the success of the considered hybrid projects (at both feasibility and implementation stages) was the capital intensive nature of the projects, particularly those that were developed over five years ago. The transportation costs associated with technology provision can also prove prohibitive, especially where hybrid activities are located in rural areas. Technology prices for renewables, particularly wind and solar, are steadily declining (REN21, 2017b), which should reduce the capital cost barrier to implementation of hybrid activities. The localisation of renewable energy technologies has many developmental benefits and could assist in reducing capital costs, particularly those associated with transportation costs. Localisation programmes will however likely require additional Government support and capacity building. A supporting South African policy environment, that includes funding or tax incentives for example, could mitigate some of the risks of developing new local industries. Decreased investor risk is likely to encourage the growth of the renewables sector and the associated technology providers. At the policy and sector levels, the European Union’s mandatory blending target and the United States’ Renewable Fuel Standard provide various examples of both successful and unsuccessful hybrid projects within the transport sector. Both the European Union and the United States experienced similar challenges linked to the unforeseen impacts in the value chain of biofuels. The EU has historically focused on biodiesel blending using palm oil. The demand for biodiesel from the EU drove the development of the palm oil industry in countries like Indonesia. In some cases the palm oil plantations were managed unsustainably (Mukherjee and Sovacool, 2014) and contributed to soil erosion, biodiversity losses and water pollution. And additional impact from unsustainable palm oil practices include the conversion of peat land resulting in major carbon releases (Mukherjee and Sovacool, 2014). Furthermore unsustainable land management practices are known to increase carbon dioxide emissions. The EU has subsequently withdrawn the mandatory blending target. This decision has negative implications for the livelihoods of communities which have relied on the palm oil industry to provide employment. During 2017, Indonesia introduced a sustainability standard and certification scheme for palm oil production in an effort to address the environmental concerns regarding the palm oil sector and encourage

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sustainable growth. This initiative might have been implemented too late to maintain the export levels of sustainable palm oil. The United States’ Renewable Fuel Standard focused on corn based bioethanol blending. The standard was widely supported initially and resulted in a sharp increase of bioethanol producers across the United States. The standard set an initial blending rate of 10%, which was compatible with the majority of existing vehicles in the United States. The rapid production of the bioethanol sector however resulted in supply outstripping demand, which brought prices down and negatively affected the bioethanol market. The standard’s blending rate was subsequently increased to 15% in 2010 to account for the large supply of bioethanol in the country, which assisted with market rebound. Furthermore, bioethanol blending in the United States has become controversial as the feedstock for bioethanol is either directly or indirectly used for food production, prompting concerns related to food-security (Ajanovic, 2011; Babcock, 2012; Srinivasan, 2009). The South African case studies illustrate specific lessons learnt which could be summarised as follows:

• Comprehensive risk analyses, technical commercial and financial evaluations are critical to the success and sustainability of projects. These provide a platform from which to gain buy-in and access financing. Due to the context of renewable energy development in South Africa, specifically hybridisation, is still developing, the planning of projects are critical to show commercial viability.

• Policy support, as well as government buy-in, are critical to ensure projects are able to move towards implementation.

• Crop based biomass projects, although viable in specific locations throughout South Africa, must consider water use, land availability and the ensuring of sustainably managed plantations. These projects are to ensure a net reduction in emissions and not the contrary which may be the case where the project is not well managed. In the South African context land availability must be weighted in terms of socio-economic development objectives as well as in terms of tribal/communal land availability. Under increasing drier conditions biomass projects must consider water re-use and recycling as part of project development. In addition, the broader catchment impact of these projects must be considered.

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3.10 Summary of hybridisation prioritisation Chapter 3 resulted in the prioritisation of hybridisation technology options within the four energy services assessed: including thermal, electrical, mechanical and mobility based energy services. The prioritisation followed a multi-criteria decision analysis for which the methodology was provided in section 3.2 of this report. Throughout this prioritisation it is seen that bioenergy and solar based technologies dominate the most promising hybridisation technology option. In many cases the opportunity to hybridise with bioenergy is more promising than hybridising with solar. This is due specifically to the higher capacity factor of biomass at about 100% compared with solar at only 30%. However hybridisation with bioenergy sources is very location specific and not applicable throughout the country due to resource availability. Hybridising with solar on the other hand, is applicable in most areas in South Africa and is thus a more suitable option. Within the thermal energy services hybridisation technology options, the most promising hybridisation technologies included: 1) the use of direct solar heating to pre-heat boiler feed water, 2) direct co-firing of furnaces and steam systems with bioenergy for heat production, 3) the parallel co-firing of furnaces and steam systems with bioenergy and 4) concentrated solar thermal use for steam generation in steam systems such as boilers. Within the electrical energy services, the provision of electricity from solar PV systems hybridised with systems consuming electricity from the grid is seen as the most promising. This is followed by electricity generation from bioenergy sources, small scale hydro power, wind power and lastly by concentrated solar power. The provision of mechanical energy services from hybridised technology options shows that bioenergy based energy for mechanical services is the most promising. This is followed by small scale hydro, then wind mills and finally concentrated solar for mechanical power through steam generation. The hybridisation of mobility based energy services is most promising through the use of biofuels blending. Solar PV for powering of auxiliary equipment on vehicles, is also promising. Solar PV can also be used for electric rail services. Following an analysis of the policy context it is seen that there are certain barriers impeding the roll out of hybridisation in the country. One of these relate to the constrained size for small scale embedded generation at 1MW. There are also no incentives supporting implementation. With regards to the use of waste streams as an energy source for hybridisation, these have faced barriers due to the complicated waste legislation in the country. The waste legislation is seen as fragmented, with a number of departments defining waste from different perspectives and driving different innovation initiatives. Clear and streamlined policy guidelines with regard to waste and the use of waste to provide energy services are essential for the use of the renewable resources. The Municipal Finance Management Act, which governs the municipal procurement processes in South Africa, is a limiting factor for municipalities wanting to implement hybridisation projects.

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Enablers for the roll out of hybridisation in South Africa, include the continued downward trend of capital costs of renewable energy technologies. The increase in electricity prices will see more people sourcing alternative solutions instead of purchasing energy at increased costs. A key enabler for hybridisation would be the implementation of the pending carbon tax and offset scheme. With these mechanisms companies will feel the impact of a price on carbon, and will move towards lower carbon solutions to mitigate these risks. There is however a need for government to incentivise the implementation of hybridisation through areas such as net metering or the provision of a tax incentive in order to drive the transition to a lower carbon economy.

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4 Techno economic review

4.1 Introduction Following the prioritisation of the plausible hybridisation options, this chapter aims to assess the techno economic feasibility of these hybridisation opportunities. Quantifying economic and technical feasibility of displacing fossil fuels with renewable energies is carried out. This analysis also considers the risks associated with such interventions. Risks considered include technological risks, process integration risks, fuel supply risks and fuel pricing risks. A range of case studies of successful hybridisation projects in South Africa and internationally are included. The case studies provide lessons learnt and key challenges experienced in getting such projects up and running.

4.2 Methodology for the techno economic review A discounted cash flow methodology is used to evaluate the feasibility of the hybridisation options identified and prioritised in Chapter 3 of this report. This method quantifies the difference between the net present value (NPV) of the hybridised case and the base case (fossil fuel) technology option as well as determining the simple payback period. A larger NPV for the hybridised case compared with the base case indicates a greater return on investment for the hybridisation. The difference between the NPV of the two cases is levelised by dividing the amount of energy delivered or service rendered by the hybridisation. The levelised cost provides an indicator for evaluating and prioritising different projects. The simple payback period is the period of time over which the value of the energy savings of a project equal the cost of implementation. Only embedded hybridisation options are evaluated in this study. Therefore net metering and wheeling or trading on the grid is not included. However where the sites have excess resource availability and the capacity to generate more energy than required, possible trading could result in further roll out of hybridisation projects in the country.

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4.2.1 General assumptions General assumptions made during the techno economic review include discount rates, inflation, electricity prices and carbon price. These parameters are provided in Table 4-1 below. Table 4-1: General assumptions used within the techno economic technology review

Parameter Value applied Assumptions and Reference

Discount rate (cost of capital and technology risks)

Low - 15% Medium - 20% High - 25%

The discount rate relates to the risk of the project, where low discount rate is applicable to low risk projects. The medium and high discount rate is applicable to medium to high risk projects.

Inflation 5%

Assumption based on last 3 years Consumer Price Index (CPI) and Production Price Index (PPI) inflation as published by StatsSA (Statistics South Africa, 2017a & 2017b)

Electricity prices

Eskom: R0.85/kWh Low average price: R1.20/kWh Medium average price: R1.50/kWh High average price: R1.80/kWh

Electricity bill analysis that Promethium Carbon completed for municipal clients operating in different municipalities for the Private Sector Energy Efficiency (PSEE) Programme. These municipal tariffs are higher than Eskom based tariffs and are based on commercial/industrial tariffs, which are lower than domestic/residential tariffs.

Carbon price for carbon tax paying entities

R48/tCO2e to 2019 then increasing linearly up to R120/tCO2e by 2030

Proposed South Africa carbon tax price, as per the draft carbon tax regulations.

Carbon credit price R 100/tCO2e

Assuming companies would be willing to pay less than R 120/tCO2e for a carbon credit under the South African carbon tax.

Baseline fuel cost (coal)

General purpose coal - R 950/tonne or R 39/GJ Utility scale coal - R37/GJ

Average Bituminous Coal price local sales (Free on road) – (Department of Energy, 2016e).

Baseline fuel transport costs R 1.29/tonne/km

Calculated based on the following reference for transport via trucks23, (Braun, 2015).

Calorific value of baseline coal 24.3 GJ/tonne

South African General purpose coal, (Department of Environmental Affairs, 2017b)

23 It has been assumed that coal is trucks throughout the country and not shipped for use. In the case that the coal is shipped this will have a different outcome on the feasibility of the projects.

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Emission factor for coal 2.35 tCO2e/tonnes of coal

Sub-bituminous coal emission factor, using NCV of general purpose coal, (Department of Environmental Affairs, 2017b)

The techno economic review has been carried out using three carbon price scenarios:

1. Only the benefits of the fuel saving from hybridisation is considered, a carbon price is not taken into account.

2. In addition to the fuel saving benefit, the additional revenue from carbon credits is included, at R100/tCO2e.

3. In addition to the fuel saving benefit, the reduction of carbon tax liability for a carbon tax paying entity is included. Up to 2020 the carbon tax price is taken as R48/tCO2e (this considers the 60% tax free threshold), and from 2020 the carbon tax price increases linearly to R120/tCO2e by 2030. After 2030 the price remains constant.

The techno economic feasibility assessment is carried out using a high, medium and low discount rate. Where a high discount rate (25%) reflects a high technology risk and a low discount rate (15%) indicates a low technology risk. There were no other risks, considered in the selection of discount rates.

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4.3 Techno economic review

Resulting from the prioritisation of hybridisation projects carried out in Chapter 3, the following hybridisation projects have been selected to undergo a techno economic review assessment:

• Solar o Solar photovoltaic (PV) installation on a commercial building or at an industrial

operation to augment grid electricity supply. o Concentrated solar power (CSP) installation at an industrial operation to augment

grid electricity supply. o Concentrated solar thermal plant to augment steam generation at a coal fired power

station. o Direct solar water heaters to pre-heat boiler feed water.

• Wind o Wind electricity generation installation at an industrial operation to augment grid

electricity supply. o Wind power to deliver mechanical services.

• Biomass o Direct 24 co-firing of an industrial coal fired boiler with biomass for thermal

application. o Indirect 25 co-firing of an industrial coal fired boiler with biomass for thermal

application, requiring the purchasing of a new boiler. o Indirect co-firing of an industrial coal fired boiler with biomass for thermal

application, where a spare capacity boiler can be retrofitted. • Hydro

o Hydro electricity generation installation at an industrial operation to augment grid electricity supply.

24 Direct co-firing is when the renewable energy fuel source is directly fired along with the fossil fuel, as per the existing operation of the plant 25 Indirect co-firing requires an additional piece of equipment in which the renewable fuel source will be combusted, e.g. an additional biofuel boiler.

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4.3.1 Solar techno economic review Four solar technologies are considered for hybridisation with fossil fuels and are assessed for techno economic feasibility. These include the use of solar water heaters to pre-heat boiler feed water, the installation of solar photovoltaic panels in commercial or industrial operations to supplement electricity demand; the use of concentrated solar power to augment electricity supply in an industrial facility, and the use of concentrated solar thermal to produce steam to augment production from coal boilers. 4.3.1.1 Direct solar water heaters to pre-heat boiler feed water Hybridisation of steam production systems in boilers have been identified as one of the most promising areas for hybridisation. This is due to the low complexity in system conversion and low cost. Solar thermal systems can be used for pre-heating boiler feed water through direct heating, to boost the output from the boiler or reduce the amount of fuel required to deliver the same output. As the temperature requirements for pre-heating of boiler feed water are relatively low (ranging between 30 and 100°C) the use of solar flat plate collectors or solar evacuated tubes will be able to achieve these temperatures. The financial assessment of pre-heating boiler feed water with solar thermal technology was evaluated using a traditional coal boiler of 8 tonnes of steam per hour as the baseline technology. Similar results are expected for boilers up to 20 tonnes of steam per hour, however the area required for solar installations would be larger. The assumptions include: a boiler operating 24 hours per day, with a conversion efficiency of 84% (John Thompson, N.d.) and a baseline coal price of R950/tonne (excluding transport) (Department of Energy, 2016e). The capital cost of the solar pre-heating system includes the collector, a storage tank, a recirculating pump, control equipment, hydraulics and thermal insulation. This system has been estimated to cost €1100/m2 (R 16,780/m2)26 (WWF, 2017). The energy requirements to pre-heat the water from 20°C to 65°C was calculated using the specific heat of water. It was found that the pre-heating of water can save about 2% of the baseline energy consumption of a coal boiler. This was used to determine the size of the solar water collectors, which was determined to be 60 m2. This area could be a multi-use area such as rooftops or parking, and doesn’t require a demarcated standalone area. Operation and maintenance cost are 2% of the annual capital cost of the solar collectors (Dantas, 2014) and are related to the cleaning of the collectors. The lifespan of this type of application has been set at 20 years. The financial assessment was carried out and the levelised savings (savings in net present value) estimated per unit of energy, in R/GJ, when installing solar preheaters was determined, and is presented in Table 4-2. A positive R/GJ value indicates cost savings, and a negative value indicates that the capital and maintenance cost of implementing the hybridisation system exceeds the cost of operating the baseline technology. The table includes a simple payback period which indicates

26 Based on an exchange rate of R15.249/Euro as on 11 July 2017 at: http://www.xe.com/currencyconverter/convert/?Amount=1&From=EUR&To=ZAR

http://www.xe.com/currencyconverter/convert/?Amount=1&From=EUR&To=ZAR

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the time it would take for the implementing entity to recover the investment and start seeing savings in their financial statements. The analysis was carried out at the three scenarios, where the first only takes into account the cost saving from fuel savings and the other two scenarios include a carbon price, with the benefit of carbon credits included and the reduced liability for a carbon tax paying entity. Companies which are liable to pay carbon tax, or companies which can trade carbon credits are able to receive additional monetary benefits which in consequence reduces the payback period and increases the levelised savings. Solar thermal technologies are mature and have a low risk, therefore the discount rate for low risk projects is the most appropriate for this type of hybridisation project. However, a company may face unique situations for which the technology risk increases. As such the medium (20%) and high (25%) technological risk scenarios are also provided below for reference. Table 4-2: Levelised savings for direct pre-heating of boiler feed water with solar thermal to substitute coal

Levelised savings for energy provided by hybridisation

Simple payback period

Discount rate

15% 20% 25%

1. No other benefits other than hybridisation to save fuel costs

5.2 years R 7.09/GJ R 2.99/GJ R 0.55/GJ

2. Company that can get the benefit of selling carbon credits

4.2 years R 10.7/GJ R 5.79/GJ R 2.83/GJ

3. Company having to pay carbon tax

4.6 years R 9.8/GJ R 4.93/GJ R 2.03/GJ

The results show that even at a high-risk technology discount rate of 25%, the implementation of solar thermal systems for pre-heating of boiler fed water is feasible, indicated by the positive NPV/GJ. The simple payback period of these types of projects is around 5 years. This payback can be reduced to around 4 years when taking into consideration the opportunity to receive income from carbon credits. The above analysis was carried out using current condition, however in the future, technology learning would further increase the feasibility of implementing such a hybrid project, increasing the existing feasibility. This analysis used national average coal prices, however the coal price increases with the transport costs associated with transporting the coal to the site for consumption from its extraction point. With an average transport cost of R1.29/tonne/km (R0.053/GJ/km) transported (Braun, 2015), the implementation of solar pre-heating of boiler water feed becomes more attractive to companies operating further away from the coal mines. The analysis used coal as the baseline fuel. Coal is one of the cheapest fuels in the South African market. The returns on the investments are expected to be higher for boiler systems that use oil based fuels.

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Payback periods for solar systems are usually the shortest when compared with other renewable solutions, however as the project savings can’t be displayed in the immediate financial year, some companies withhold doing such implementations as it affects their short term financial statements. Solar thermal applications carry a high installation cost due to the cost of the collectors and the need for storage of the heated water. For companies that are not willing to take on the financial risk and only see a payback after 4 years, it may be more suitable for them to sign a service level agreement with a third party who is willing to implement the project and sell the energy service to the facility. 4.3.1.2 Solar PV installation on a commercial building or at an industrial operation to

augment on-site grid electricity supply With the abundance of solar resources in South Africa and the price of solar PV modules rapidly decreasing, PV system are becoming more attractive for electricity generation and for meeting energy service demand. Given the wide range of applications that use electrical energy to deliver services in South Africa, and the fact that no modifications are required to the electricity consuming equipment, solar PV electricity systems become one of the more suitable, and easier to implement options for hybridisation in South Africa. These systems are applicable to the residential, commercial, industrial and agricultural sector. Furthermore, the expected increase of national grid electricity prices across the country, and the large portion of the country’s GHG emissions inventory which is produced from coal based electricity generation, are reasons to stimulate the roll out of solar PV systems at a national level. A financial assessment has been undertaken to compare electricity generated from solar PV to grid electricity generation. As a baseline, the traditional grid electricity is used. The baseline has been set to differentiate for three average electricity prices. A low average price (R1.20/kWh), a medium average price (R1.50/kWh) and a high average price (R1.80/kWh). Electricity prices across South Africa vary depending on the municipality, tariff structure and type of user, amongst other variables. The assessment has been carried out using the case of solar PV installation to supply electricity to a commercial location. Without storage, the proposed system can supply about 20% of the total electricity consumption of the commercial building, as the occupancy times of the facility match the availability of sunlight. The capital cost has been estimated at around R15 000/kW (Edkins et al, 2010), this value was compared and adjusted with actual data from recently installed PV installations in South Africa. The annual operation and maintenance cost of solar powered electricity generation systems is relatively low, about 1.5% of the capital cost. This figure of 1.5% was estimated from different data sets provided by various recently implemented case studies in the country. The lifespan for the equipment is estimated at 20 years. The results from the financial assessment for the three average electricity prices are presented in Table 4-3 (high average price), Table 4-4 (medium average price) and Table 4-5 (low average price). The comparison is done in terms of levelised savings of electricity in Rands per kWh or net present value per kWh considering low (15%), medium (20%) and high (25%) discount rates. In these

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tables a positive saving means that the hybridisation of the technology provides a net financial benefit per unit of energy substituted by the hybridisation. A negative saving indicates a higher cost for the energy substituted by the hybridisation compared with the base case per unit of energy. Solar PV technology is considered to have a low risk for investment and expected returns are in line with a lower discount rate. Medium and high technology risk scenarios are included for specific cases where these risk scenarios may be appropriate to a company. Electricity usage is not taxable under the proposed carbon tax, therefore the option to reduce a company’s carbon tax liability is not possible. In addition, it has been assumed that the average electricity prices will not increase due to carbon tax pass through costs from Eskom in the future, this is a conservative assumption. However, the opportunity to get a benefit from carbon offsets is possible and has been included. The financial analysis shows that solar PV electricity generation in most cases has a positive net present value, meaning that the savings are higher than the expenses during the lifetime of the project. Projects of this type are more attractive in locations with higher prices for electricity. In areas where the average electricity prices fall below R1.20/kWh, government may need to consider subsidies or financing schemes to promote implementation of solar PV systems. However, with the expected increase in electricity prices, and the decreasing prices of PV equipment, subsidies may not be necessary in the near future. The technology learning within solar PV is already evident from the declining tariffs seen in the various bid windows of South Africa’s REIPPPP programme, presented in Chapter 2, Figure 2-19. It is important to remember that the outcomes are influenced by the baseline electricity prices used and the real reduction in electricity purchases. Both variables are specific to facility cases and are dependent on the tariff structure. The price of electricity can be different according to the time of day or the amount consumed, which is important to consider per facility being assessed. In these cases, better financial outputs are expected for facilities where the sun can provide electricity when it is most needed, i.e. at peak time tariff periods. Likewise, if the consumption periods do not match the demand, the outputs will be significantly reduced as the full capacity of the system is not utilized and there will be additional costs relating to the storage of electricity. Table 4-3: Levelised savings for solar PV electricity to substitute grid electricity at a high average electricity price (R1.80/kWh)



Discount rate

15% 20% 25%


4.5 years R0.34/kWh R0.17/kWh R0.07/kWh



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Table 4-4: Levelised savings for solar PV electricity to substitute grid electricity at a medium average electricity price (R1.50/kWh)



Discount rate

15% 20% 25%





Table 4-5: Levelised savings for solar PV electricity to substitute grid electricity at a low average electricity price (R1.20/kWh)



Discount rate

15% 20% 25%


6.7 years R0.09/kWh -R0.01/kWh -R0.07/kWh


6.3 years R0.12/kWh R0.01/kWh -R0.05/kWh

The payback of solar PV projects for electricity generation range between 4.5 to 6.7 years. This payback period can be reduced to between 4.3 and 6.3 years if the project can generate and sell carbon credits. Despite the positive outcome from the financial assessment, the roll-out of solar electricity projects has been slow, perhaps because of the length of the payback periods, or the risk related to the initial capital outlay. The high capital cost of PV technologies presents a barrier for implementation at a large scale, as many companies are attracted to projects that can show benefits in the same financial year. This however, opens an opportunity for a business model where companies pay a levelised cost per kWh consumed to an energy service company who does the installation and takes responsibility of the capital expenses. This case however, removes the opportunity for the company to use the benefit of the project to generate carbon credits. Solar PV prices are on a downward trajectory and historic electricity tariffs show an upward trend (Figure 4-4), therefore, lower investments from business may in future be required for the same benefits. Driven by technological improvements in solar PV modules, manufacturing advances, economies of scale and reductions in balance of system costs, the global weighted-average installed costs of utility-scale PV systems could fall by 57% between 2015 and 2025 (IRENA, 2016c). Figure 4-1 presents the global weighted average cost of PV installations up to 2015 and the expected trend towards 2025.

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Figure 4-1: Global weighted average utility-scale solar PV total installed costs, 2009-2025 (IRENA, 2016c)

4.3.1.3 Concentrated solar power installation at an industrial operation to augment grid

electricity supply Concentrated solar power (CSP) technologies for electricity generation are mainly feasible for large-scale installations, typically more than 20 MW, with most of the commissioned facilities around the world being over 100 MW (REN21, 2017a). In contrary to solar PV systems, CSP facilities do not only require sunlight but direct irradiation, limiting the location applicability in the country and thus the feasibility of implementation. These factors, together with the intricate mechanical and chemical components of CSP plants, limit the implementation of CSP to companies who have large electricity demands, upfront capital and to companies who have space available for implementation. A potential applicable location and facility for CSP installation could be mines, due to their available space. CSP electricity generation offers the opportunity to easily incorporate a thermal storage solution, allowing a facility to generate electricity around the clock and at peak demand times, as and when it is required. The addition of storage does increase the capital costs. During the last bid window of the REIPPPP27, the average price for CSP electricity was R1.7/kWh at base tariff price and R4.58/kWh at peak time (Department of Energy, 2015a). The weighted averaged thus amount to R3.09/kWh (Yelland, 2016). Using this as the levelised cost for CSP electricity, the financial assessment is negative for any facility when compared with the cost of grid electricity, as is seen in Table 4-6. These values are presented in Rands per kWh saved or net present value per kWh.

27 Window 3.5 for CSP

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Table 4-6: Levelised savings for CSP electricity generation at different average electricity prices (including peak tariff)


Low average electricity price (R1.20/kWh)

Medium average electricity price (R1.50/kWh)

High average electricity price (R1.80/kWh)


- R 1.89/kWh - R 1.59/kWh - R 1.29/kWh


- R1.79/kWh - R1.49 /kWh - R 1.19/kWh

Hybridisation for CSP electricity generation is thus restricted to few companies with the specific characteristics described earlier, and for which the risk of unreliable electricity provision surpasses immediate returns on the investment. However as technology learning continues, the price of concentrated will become more competitive. The rate of learning for concentrated solar is not as steep as that which has been seen in solar PV, Figure 2-19 in Chapter 2. The case where the premium for peak electricity is not paid, as the company owns the facility, was also considered (using R1.7/kWh as the cost of electricity), and the financial assessment results are provided in Table 4-7 below. The results are presented in Rands per kWh saved or net present value per kWh. The results indicate financial feasibility in areas with high electricity prices. Project returns are even better if the project is eligible for carbon credits. It is important to remember that the output from the financial analysis for CSP systems varies considerably from company to company depending on the time of the day when the electricity is required, the tariff structure applicable, and the geographical location of the companies. Table 4-7: Levelised savings for CSP electricity generation at different average electricity prices (using only base tariff)


Low average electricity price (R1.20/kWh)

Medium average electricity price (R1.50/kWh)

High average electricity price (R1.80/kWh)


- R 0.5/kWh - R0.2/kWh R 0.1/kWh


- R0.4/kWh - R0.1/kWh R 0.2/kWh

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4.3.1.4 Concentrated solar thermal plant to augment steam generation at a coal fired power station

On-site hybridisation of coal fired power stations with concentrated solar reduces the coal required for steam production and thus the greenhouse gas emissions. Steam generation by concentrated solar for substitution of steam generated by coal was evaluated using concentrated solar plant costs (adjusted for exchange rates and inflation) from IRENA (2012). The capital cost components of the concentrated solar plant excluding the power block (as these form part of the coal power plant being augmented) were used from a parabolic trough concentrated solar plant which was awarded within the REIPPPP and reported by IRENA (2012) (Rm 10.15/MWth). The operating costs of the concentrated solar steam generation were taken in proportion to the capital invested in the steam generation components. Fixed operating costs were not available in the IRENA study and were derived from the IRP2010 Update (Department of Energy, 2013b) i.e. 1.5% of the overnight capital cost as the annual fixed cost (for a concentrated solar plant without storage). The major capital cost components within a concentrated solar plant are presented in Figure 4-2. The thermal storage (11%) and conventional plant components (14%) were deducted from the costs for the hybridisation with a coal fired power plant, as these already exist at a coal fired power station. The costs used therefore represent the additional plant and equipment needed for the hybridisation of the coal plant. Note that no costs for the provision of land were taken into consideration, with the assumption that the implementer owns the land.

Figure 4-2: Capital cost break down for steam production costs for CSP (IRENA, 2012)

Conventional plant components and

plant system 14%

Equipment: Solar field and HTF and

system39%

Labour cost: Site and solar field

17%

Others 19%

Thermal storage system

11%

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The cost per unit of energy substituted by concentrated solar as calculated using the discounted cash flow methodology are included in Table 4-8. Table 4-8: Levelised savings for steam from concentrated solar to substitute coal generated steam



Discount rate

15% 20% 25%


8.50 years - R 0.99/GJ - R 3.78/GJ - R 5.35/GJ


6.75 years R 2.57/GJ - R 1.01/GJ - R 3.10/GJ

3. Company having to pay carbon tax 7.33 years R 1.74/GJ - R 1.79/GJ - R 3.82/GJ

The results show that a low discount rate and a carbon price, are necessary for ensuring the viability of hybridising coal boilers with concentrated solar steam boilers for electricity generation. A price on carbon is necessary to create an incentive for investing in hybridisation of this type for a commercial project, where returns are generally expected to be higher than public investments. Developing such a concentrated solar project may be seen to be too risky for private developers. The costs of concentrating solar plants are declining as with PV system due to technology learning. The rate of decline for the costs is, however, lower than for PV systems due to the large share of conventional components in a CSP plant (i.e. the steam turbines and generators. The economics of concentrated solar will become more feasible over time as the technology matures, however at a lower rate to that of solar PV. 4.3.1.5 Conclusions for solar techno economic review With the abundance of solar resources across South Africa, solar systems represent an important opportunity for hybridisation of electricity and heat provision. Solar installations have generally shorter payback periods compared with other renewable options. These payback periods will be furthered reduced by the notable downward trend experienced in capital cost of small and large-scale solar PV installations.

• The installation of solar water pre-heating systems for boiler feed water is both technically and financially feasible. The energy requirements to pre-heat the water from 20°C to 65°C was calculated using the specific heat of water. It was found that the pre-heating of water can save about 2% of the baseline energy consumption of a coal boiler. A company can expect to recover the capital investment in 5 years. If the company implementing such a project, is an entity liable to pay carbon tax or if the company can claim this project as a carbon credit project, this payback period can be reduced by a year.

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• Solar PV systems for electricity provision can replace about 20% of the electricity expenses of a commercial or industrial facility. The payback periods range between 4 to 6 years depending on the applicable grid-electricity fee structure and the demand profile. For a company with the possibility of trading carbon credits, the payback period can be reduced by about 4 months.

• Concentrated solar power (CSP) for electricity generation (without wheeling through the grid) is limited to companies who are prepared to make large upfront capital investments, who have large electricity requirements, are located in an area with large solar irradiation and that have available space. In comparison with current grid electricity prices, CSP electricity generation does not show financial benefits. However, a company may have different motivations for off-grid generation such as reliability of the service or environmental commitments.

• Concentrated solar systems for thermal applications have more potential than concentrated solar for electricity. Concentrated solar has a great potential to provide steam for existing large-scale electricity generation (though technology risks are still very high) and reduce greenhouse gas emissions from plants that traditionally would have used coal. However a price on carbon is necessary to create an incentive for investing in hybridisation of this type as a commercial project.

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4.3.2 Wind techno economic review Wind energy considered for hybridisation includes small-scale wind turbines to augment electricity supply and the use of wind pumps for agricultural water pumping. Small wind turbines are ideal for households, communities and small businesses for onsite energy generation. In this section of the techno economic assessment, the focus will be on micro-scale wind electricity generation (< 3.5kW), which is a suitable hybridisation option to augment energy supply to the agricultural, commercial and residential sectors. 4.3.2.1 Wind electricity generation installation at an industrial operation to augment grid

electricity supply South Africa has very good potential for wind energy, especially along the coast and inlands close to the escarpments. The Western Cape, Northern Cape, Eastern Cape and KwaZulu-Natal have been identified as the provinces with the best potential in the country (Wind Atlas for South Africa, 2017). Large scale wind energy is suitable for facilities located not only at good wind resource sites, but also with the suitable conditions for the placing of large scale generators. A 2MW wind generator, for example, has a rotor diameter of about 90 meters, and besides the area requirements, other concerns such as noise, flicking and environmental impacts must be considered. Large scale wind generation in South Africa is fast growing with more than 1,471 MW installed. During the bid window No. 4 of the REIPPPP, wind energy reached an average price of R 0.62/kWh. Such a low price makes wind energy very attractive for companies with high electricity requirements and that are able to provide large capital investments. For micro scale electricity generation from wind, a 3.5kW wind turbine has a rotor diameter of 4 meters, the wind turbine is typically 12 meters high, and requires about 0.8 meters of concrete for foundations, as well as requiring a dedicated land use area for installation (Kestrel, N.d). The obstructions from buildings and tress also need to be considered to ensure performance from these plants. For this assessment, three installation sizes have been analysed comprising of 0.6 kW, 1 kW and 3.5 kW generators. The capital costs were sourced from local manufacturers and include the generator, the tower and the controllers. The capital cost ranges between R 30 000/kW to R 50 000/kW (Turbines.co.za, 2016), and the expected operational life of the equipment is 20 years. As a conservative assumption, the annual operation and maintenance cost has been set at 2% of the capital cost (EWEA, 2009). No battery installations have been considered. A financial assessment was done for three different turbine sizes (0.6 kW, 1 kW, and 3.5 kW) in order to compare economies of scale. The assessment was done using different average electricity prices. The results from the financial assessment for the 3.5 kW installation are presented in Table 4-9 (high average electricity price), Table 4-10 (medium average electricity price) and Table 4-11 (low average electricity price). The comparison is done in terms of levelised cost of the energy saved in R/kWh or net present value per kWh, considering low, medium and high discount rates. Electricity production from wind has a low technological risk. For an installation of 3.5 kW, there are positive net present values seen for low, medium and high electricity prices.

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Table 4-9: Levelised savings for wind electricity (3.5 kW) to substitute grid electricity at high average electricity price (R1.80/kWh)



Discount rate

15% 20% 25%




5 years R0.29/kWh R0.13/kWh R0.03/kWh

3. Company having to pay carbon tax 5.2 years R0.28/kWh R0.12/kWh R0.02/kWh

Table 4-10: Levelised savings for wind electricity (3.5 kW) to substitute grid electricity at medium average electricity price (R1.50/kWh)



Discount rate

15% 20% 25%


6.3 years R0.14/kWh R0.01/kWh -R0.06/kWh


6 years R0.17/kWh R0.03/kWh -R0.04/kWh

3. Company having to pay carbon tax 6.1 years R0.16/kWh R0.03/kWh -R0.05/kWh

Table 4-11: Levelised savings for wind electricity (3.5 kW) to substitute grid electricity at low average electricity price (R1.20/kWh)



Discount rate

15% 20% 25%


7.7 R0.01/kWh -R0.08/kWh -R0.14/kWh


7.2 R0.04/kWh -R0.06/kWh -R0.12/kWh

3. Company having to pay carbon tax 7.1 R0.03/kWh -R0.07/kWh -R0.12/kWh

The above net present values were calculated for a 3.5 kW plant. To assess the impact of economies of scale, a comparison of the results for a 3.5 kW, 1 kW and 0.6 kW system is provided below and displayed in Figure 4-3. It is seen that when carrying the net present value assessment out on the smaller scale systems, such as the 1 kW and 0.6 kW plants, the results are very different

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and are not economically feasible. Figure 4-3 shows the comparison of the calculated levelised savings amongst the three turbines for different electricity prices for the case where no other benefits other than hybridisation to save fuel costs are considered. It is seen that at a medium discount rate, the 3.5 kW plant is only feasible with a medium and high average electricity price. In comparison it is seen that there is no feasibility for the 1 kW or 0.6 kW plants.

Figure 4-3: Summary of levelised savings for wind electricity to substitute grid electricity for a 3.5 kW, 1 kW and 0.6 kW installation using the medium discount rate

The high capital costs make small scale wind electricity installations not very attractive to investors. Greater savings are achieved with low discount rates, in areas with high electricity prices and with larger capacity installations. In this assessment, the capacity factor of the system was assumed to be 35%. The average wind capacity factor for South Africa between 2009 and 2013 was above 30%, and in almost 70% of the suitable area in South Africa a factor of 35% or higher can be achieved (Bischof-Niemz, 2016b). However, the real electricity output depends on the wind quality at the location where it is implemented. The demand profile of the consuming facility also influences the economics. These types of systems may be attractive to sites were grid electricity distribution is unreliable or limited. They can also be good alternatives for government investments in order to accelerate the roll out of low carbon technology while increasing service delivery. Wind electricity options may be more attractive when the continuous supply of electricity can be ensured, combined with storage units, or with other generation options such as solar, hydro or diesel generators.

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4.3.2.2 Wind power for mechanical services Wind power can be used to substitute or replace services provided by grid electricity. The competitiveness of small scale wind technologies depend on the service being provided, the location of the service and the quality of the wind. The most common application is the use of wind pumps for pumping water from boreholes in rural locations. The capital costs of wind pumps range between R 40 000 and R 75 000 for capacities between 10 and 100 kilolitres per day (Stewarts and Lloyds, 2017). This provides a capital cost/unit capacity between R2 and R11 per kilolitre of water pumped per year. In comparison electric motor driven pumps cost between R5,128 and R6,900 for capacities between 12 and 26.6 kilolitres per day, giving a capital cost per unit capacity of between R 0.71 and R 1.17 per kilolitre of water pumped per year (Sunflare, 2017). The electric pumps, however have operating costs related to electricity of between R0.17 and R0.31 per kilolitre. The cost of supplying electricity to remote boreholes can be very high, in which case a conventional wind pump would be the preferred option. A solar PV system could also be considered for such applications. Based on the discounted cost calculation and payback methods the cost of pumping water using a wind pump to supplement a base case electric pump are summarised in Table 4-12. Table 4-12: Levelised savings for pumping water with wind pumps



Discount rate

15% 20% 25%

1. No other benefits other than hybridisation to save operating costs for pumping

5.11 years R 0.04/kl R 0.01/kl - R 0.01/kl

Hybridised water pumping using wind can be viable, but at a farm scale would not provide a viable case for carbon credits due to the transaction costs. The use of wind pumps to supplement electrical water pumping provides sufficient returns to be economically viable at commercial discount rates.

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4.3.2.3 Conclusions to wind techno economic review Abundance of wind resources across South Africa, in particular along the coast line, make the implementation of wind systems attractive as a hybridisation option. Wind can provide electricity or mechanical power.

• Electricity generation: small-scale electricity generation is attractive to companies or institutions where access to grid electricity is limited and where the conditions for the placing of a wind turbine are good. With about 5 to 10 years for payback, it was observed that better and faster financial benefits are achieved by systems with larger capacities. However, there are multiple factors that affect the economic output, such as the electricity tariff applicable, terrain and surrounding conditions, and the actual demand profile. Wind options become more attractive with the existence of incentives such as carbon credits, and when combined with solar or hydroelectric systems as the variability for the provision of electricity is reduced.

• Mechanical power: hybridised water pumping using wind to supplement electrical water pumping provides sufficient returns to be economically viable at commercial low discount rates. In addition, as this type of implementation would mostly take place at farm scale, the economic evaluation does not consider additional benefits from carbon tax liability or carbon credits, reducing incentives for implementation. These types of options are suitable for facilities with existing limitations for grid electricity access and where there is access to a perennial water source.

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4.3.3 Biomass techno economic review Within the context of hybridising fossil fuel value chains with biomass, three hybridisation options have been prioritised for a techno-economic review. The three options to be covered include the direct co-firing of an industrial scale coal fired boiler with biofuel as well as the indirect co-firing, where the purchasing of a new boiler is required and the retrofitting of an existing spare capacity boiler. Biofuel blending in the transport sector was not included in the techno-economic review due to the site specific limiting factors which include constraints on water for biofuel crops, concerns around food security and the logistics constraints for national roll out and distribution without a supporting policy and framework in place in the country. However if these barriers are removed this will be suitable solution to hybridise the country’s transport sector. There are different types of bioenergy sources which can be used. These could include crop based biomass or biofuel from waste streams on site, such as from saw mills as an example. The bioenergy under assessment in this instance is locally cultivated crop based biomass. It is required that the biomass is sustainably sourced, to prevent issues such as land degradation and deforestation. In some cases biomass is produced during the process of land rehabilitation. This is particularly relevant to post mining activities where land cannot be used for agricultural or residential purposes. It is important to note that the use of bioenergy as an energy source is a very site specific resource and is not an applicable resource across the country, as the feedstock is not readily available. This is represented by South Africa’s Bioenergy Atlas in Chapter 1, Figure 1-11. Plant based biomass resources are predominantly available in the KwaZulu-Natal province and Mpumalanga. Areas that may have potential for biomass resources are those located to agriculture activities such as farming and plantations which have an accumulation of organic waste. Due to the legislative constraints of using municipal waste, this study did not look at the possibility of utilising waste from municipal landfills as a feedstock. In the event that waste is used as the feedstock, the associated cost could be negative based gate fees of disposing waste, but it could also come at a positive cost related to the need for a materials recycling facility. If the legislative constraints can be overcome landfill waste is a good source of biofuel. It is constantly available and the use of waste for energy can reduce issues related to the diminishing available landfill areas in the country where waste can be dumped. The co-firing of biomass in coal-fired boilers can be carried out through direct co-firing, or indirect co-firing. Direct co-firing allows for the biofuel feedstock to be fired along with the coal into the boiler. This application has less capital cost requirements, as the existing boiler only requires a retrofit to the feeding system to allow for this hybridisation. Indirect co-firing is the processing of the biofuel in a separate biomass boiler prior to integration with the existing coal fired boiler. As such, the capital cost related to indirect co-firing is larger, due to the requirement to purchase a new biomass fed boiler. Site specific conditions, may allow an existing spare capacity boiler to be used for indirect co-firing. In this case the capital cost is not as large as purchasing a new boiler. Currently there are around 3,000 John Thompson industrial boilers in operation in the country, for which this type of hybridisation could be applicable.

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The feasibility of co-firing hybridising opportunities become attractive when the facility implementing the hybridisation has the following conditions (US Department of Energy, 2004):

• The coal price is high; • The volume of coal required is significant; • The availability of local or facility-cultivated biomass is abundant; • The landfill tipping cost are high, for the disposal of biomass feedstock as a waste stream; • The operational staff are motivated to implement the project successfully.

As indicative conditions, work has been carried out by the US Department of Energy, however it should be noted that biomass analysis is very dependent on local conditions, as large variations could exist in different applications. Some of these indicative conditions by the US Department of Energy show that in general, it has been found that boilers producing less than 15 tonnes per hour of steam are too small to be used in an economically attractive co-firing project (US Department of Energy, 2004). Also the biofuel feedstock should cost at least 20% less, on a thermal basis, than coal for it to be economically viable to implement a co-firing project (US Department of Energy, 2004). The reduced cost will offset the lower energy content of biomass compared with coal, with a difference of around 7 GJ/tonne. The feasibility of hybridising a coal fired boiler with a biomass co-firing solution depends on the price and availability at which the biofuel feedstock can be sourced. In addition, it may be easier for a commercial or industrial sized boiler to be hybridised through biomass co-firing, as the fuel requirements are not as large as the requirements for a utility scale boiler for electricity production. It may be easier to source smaller quantities of fuel, than acquiring steady, year round supplies of large quantities of low-cost biomass for utility-scale power generation projects. In order to implement a hybridisation project of biomass with coal, the implementation may require:

• A replacement to the fuel handling, storage and feed system. This will depend on the existing fossil fuel facilities at the site. In many cases the existing equipment for the coal fired boiler may be usable to handle the biofuel.

• A retrofit to the existing boiler design, this will depend on the type of boiler. The most suitable types of boilers for biomass co-firing include a stoker or fluidized bed boiler. Each type of boiler requires different changes to the setup, and a site-specific assessment will be required to determine if retrofitting is required.

• Improved onsite fuel management and control. In order to carry out a techno economic feasibility assessment on hybridisation of a coal fired boiler with direct or indirect biofuel co-firing, conditions in Table 4-13 were used along with those in Table 4-1:

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Table 4-13: Parameters applied for techno economic assessment of direct and indirect co-firing of a coal fired boiler with biofuel


Direct co-firing: potential to reduce baseline fuel consumption

20% Assuming co-firing of a stoker boiler, (US Department of Energy, 2004)

Indirect co-firing: potential to reduce baseline fuel consumption

50% Assumption: indirect co-firing can replace up to 100% of the baseline fuel.

Efficiency of baseline technology (coal fired boiler)

85% Assumption for efficiency of coal fired boiler. 89.6% Upper reference for utility scale based on higher heating value (EPRI, 2006)

Capital cost of a boiler R1,200/kW

Correspondence with Martin Reck General Manager for Package Boilers at John Thompson a division of ACTOM (Pty) Ltd, on 27/09/2017.

Capital cost to retrofit an existing boiler

R300/kW

It has been assumed that the cost to retrofit the boiler, includes a retrofit to the fuel handling and feeding system. This is assumed to be 25% of the capital cost of a new boiler.

Feedstock cost of biomass R61/GJ28

Biomass feedstock price calculated by Promethium carbon as part of the British High Commission Community based Renewable Energy Projects on Mine Impacted Land study. The cost includes a transport cost of biomass of up to 20 km to the site. (Promethium Carbon, 2016)

Ash disposal cost R500/tonne Assumption based on transport cost and gate fees.

Ash from coal 10% Ash from coal can range up to 30% (Eskom, 2016b), here an efficient plant has been assumed with 10% ash production.

Ash from biomass 1% In wood, ash represents less than 2%, (James, et al. 2012)

Calorific value of baseline coal 24.3 GJ/tonne South African General purpose coal, (Department

of Environmental Affairs, 2017b)

Net calorific value of biomass 15.6 GJ/tonne South Africa’s technical guidelines (Department

of Environmental Affairs, 2017b) The baseline technology consumes coal which is a low cost commodity in South Africa. The replacement fuel is biomass which in most cases is more expensive than coal, and can be more than double the price of coal. As such, in order to make a hybridised coal and biomass system feasible the transport of both the coal and the biomass to the site needs to be considered. This

28 Variable cost dependent per facility and feedstock.

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techno economic feasibility of hybridising has therefore been carried out at various transport distances of the coal, from the coal mine to the site of use. The transport of coal is considered via trucks and not via shipping. If the coal is shipped it will have a different outcome on the feasibility of the projects. The cost of the biomass includes a transport cost of up to 20 km to the site. As such where biomass feedstock needs to be transported from further than 20 km the economics would differ and may not be feasible to implement, but this is site dependent. The price at which the bioenergy is purchased plays an important role in the viability of bioenergy based projects. In this example the full price of bioenergy is more than double the price per GJ of energy as compared with the baseline fuel of coal. However there may be cases where a site can access the bioenergy at a much lower price. An example of this could be where the bioenergy resource is a waste stream from the facility’s process and is produced at no additional cost. Due to the various arrangements that may be available to a site, the option of receiving the bioenergy at low cost has been built into the assessment, ranging from 20% of the bioenergy being paid for to all (100%) the bioenergy being paid for. The low costs would include the cost for storage and transport of the bioenergy despite the fuel itself being supplied at no additional cost. This low cost scenario is represented by the 20% biomass paid for scenario. The benefit of reduced ash production when combusting biomass as compared with coal has also been taken into account. Here the cost saving of the disposal of the ash increases as more biomass is co-fired for combustion in the boiler, due to the reduction in ash production. The results from the techno economic feasibility assessment of direct and indirect co-firing of biomass in a coal fired boiler are presented below. 4.3.3.1 Direct co-firing of an industrial coal fired boiler with biomass for thermal

application As mentioned, the feasibility assessment of co-firing a coal fired boiler with biomass, has taken into account the cost of transporting the baseline fuel (coal) to the site, the possibility of receiving a portion of the biofuel at low cost and the cost saving of ash disposal. The scenario analysis of how the simple payback periods change when taking these factors into account are presented below in Table 4-14, Table 4-16 and Table 4-17. The biomass co-firing accounts for 20% of the coal displacement, with a system retrofit cost of R300/kW as is presented in Table 4-13. Table 4-14 provides the simple payback in years, of hybridising a coal fired boiler through directly co-firing with biofuel, where no other carbon benefits are considered. Table 4-16 provides the simple payback of such hybridisation, taking into account the potential revenues from carbon credits29. Table 4-17 provides the payback periods of this hybridisation, for a company that is a carbon tax paying entity, thus taking into consideration the potential carbon tax reduction that the entity will experience when implementing such a hybridisation projects. With no other carbon credits or carbon tax benefit, in Table 4-14, it is seen that under very site specific conditions such a hybridisation project may be feasible. The availability of biomass in these 29 Biomass offset credits only included the reduction of coal combustion emissions and not the upstream sequestration potential.

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areas may also be limited. Implementing such a hybridisation solution at a site where at most 60% of the biofuel is paid for, the site is situated at least 500 km from a coal mine, and the biomass is sustainably sourced within a 20km radius, will result in a payback of around 2 years. The closer the site for implementation of the hybrid solution to the coal mines where the coal is sourced, the cheaper the coal and thus the less feasible the project. Where the biofuel can be sourced at a low cost, then the implementation of the hybrid project is more feasible. The low cost option, includes the cost of transport and storage and is represented by the 20% biofuel paid for scenario. It is seen that the implementation of such a system is feasible were a maximum of 40% of the biofuel is paid for, no matter what distance the site is from the coal mines. It is seen that at a distance of more than 1,500 km from the coal mines this type of hybridisation project is feasible with immediate payback where up to 80% of the biofuel feedstock is paid for. It is however important to note that these scenarios are not very dominant in South Africa, and thus this solution is not suitable throughout the country. These scenarios are very site specific and depend on the site conditions. Table 4-14: Direct co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit

% of paid biomass

Distance to transport coal (km)

20% 40% 60% 80% 100%

1 1 year 4 years No payback No payback No payback


500 Immediate payback 1 year 2 years 11 years No payback

1000 Immediate payback

Immediate payback 1 year 1 year 3 years


Immediate payback

Immediate payback

Immediate payback 1 year

Companies that consume smaller volumes of coal will pay a higher rate per unit of coal. A feasibility analysis has been carried out for these companies consuming smaller volumes of coal, factoring in a 25% increase in the base coal price. As such the feasibility for these smaller companies to implement a biomass-coal hybrid solution may be more viable due to the reduction in the price difference between the baseline fuel, coal, and the project fuel, biomass. The payback periods to companies consuming smaller volumes of coal are presented below in Table 4-15. Table 4-15: Direct co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit, for companies consuming smaller volumes of coal

% of paid biomass


20% 40% 60% 80% 100%

1 1 year 2 years 13 years No payback No payback

100 1 year 1 year 5 years No payback No payback

500 Immediate payback 1 year 1 year 3 years No payback


Immediate payback

Immediate payback 1 year 1 year


Immediate payback

Immediate payback

Immediate payback

Immediate payback

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It is seen that projects implemented where the site is 1,500 km from the coal mines, have an immediate payback and such hybridisation could be carried out, with the cost of the biofuel having low impact on the payback. Similarly if the biofuel comes at low cost (20% paid for), the hybridisation project should be implemented no matter the distance of the site to the coal mines. This type of scenario is very site specific and not applicable throughout South Africa. There will be few cases in which these conditions hold and where this type of hybridisation can be implemented. However when all the biofuel must be paid for and the site is located close to the coal mines, a hybridisation project does not make economic sense. In Table 4-16 and Table 4-17 the carbon credit benefit and reduction in carbon tax liability is taken into account into the simple payback of hybridising coal fired boiler with biofuel. The payback periods are reduced when taking into account these benefits or reduced liabilities. These benefits however will only come into effect when the carbon tax is implemented in South Africa. It can be seen though that putting a price on carbon could drive the implementation of hybridisation projects due to the increased viability and project paybacks. Table 4-16: Direct co-firing of coal boiler with biomass, simple payback (years) with carbon credit benefit

% of paid biomass


20% 40% 60% 80% 100%


100 1 year 1 year 6 years No payback No payback



Immediate payback

Immediate payback 1 year 2 years


Immediate payback

Immediate payback

Immediate payback

Immediate payback

Table 4-17: Direct co-firing of coal boiler with biomass, simple payback (years) for a carbon tax paying entity

% of paid biomass


20% 40% 60% 80% 100%





Immediate payback

Immediate payback 1 year 2 years


Immediate payback

Immediate payback


If the analysis is carried out for companies consuming smaller volumes of coal, where the coal is purchased at a higher price, then the payback periods would look more favourable. The net present value (NPV) for this type of hybridisation is presented below at a low (15%), and medium (20%) discount rate. We have not considered scenarios for high risk biomass projects, due to the low to medium risk nature of this type of technology. A positive NPV indicates a greater

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energy cost saving from the hybridisation project than the investment required and a negative NPV indicates a greater investment required for the hybridisation project than the value of the energy savings achieved. The analysis is carried out at the following three scenarios:

1. Only the benefits of the fuel saving from hybridisation is considered, a carbon price is not taken into account.

2. In addition to the fuel saving benefit, the additional revenue from carbon credits is included, at R 100/tCO2e.

3. In addition to the fuel saving benefit, the reduction of carbon tax liability for a carbon tax paying entity is included. Up to 2020 the carbon tax price is taken as R 48/tCO2e (this considers the 60% tax free threshold), from 2020 the carbon tax price increases linearly to R 120/tCO2e by 2030. After 2030 the price remains constant.

At a low discount rate this hybridisation project sees a positive net present value (R/GJ) where a maximum of 40% of the biofuel feedstock is paid for and no matter the location of the site to the coal mines from where the baseline fuel is sourced. As the percentage of the biofuel paid for increases, so the viability of the hybridisation project decreases. This is in conjunction with the reduced distance of the site to the source of the coal. If all the biofuel is paid for, the site has to be at least 1,000 km from the coal mines in order to make the project viable. This type of hybridisation is thus not applicable throughout South Africa, but may be applicable when based on site specific conditions linked to the cost at which the biofuel is purchased and the location of the site to the coal mines. Table 4-18: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk

% of paid biomass


20% 40% 60% 80% 100%

1 R10/GJ R 2/GJ - R 6/GJ - R 14/GJ - R 22/GJ 100 R 12/GJ R 5/GJ - R 3/GJ - R 11/GJ - R 19/GJ 500 R 23/GJ R 15/GJ R 7/GJ - R 1/GJ - R 9/GJ 1000 R 36/GJ R 28/GJ R 20/GJ R 12/GJ R 4/GJ 1500 R 49/GJ R 41/GJ R 33/GJ R 25/GJ R 17/GJ

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For the scenario where a company consumes smaller volumes of coal and thus pays a higher price for baseline coal, the hybridisation becomes more economical, as seen by the larger net present values. This is presented in Table 4-19 below. Table 4-19: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for companies consuming small volumes of coal

% of paid biomass


20% 40% 60% 80% 100%

1 R 15/GJ R 7/GJ - R 1/GJ - R 9/GJ - R 17/GJ 100 R 17/GJ R 9/GJ R 1/GJ - R 6/GJ - R 14/GJ 500 R 28/GJ R 20/GJ R 12/GJ R 4/GJ - R 4/GJ 1000 R 41/GJ R 33/GJ R 25/GJ R 17/GJ R 9/GJ 1500 R 54/GJ R 46/GJ R 38/GJ R 30/GJ R 22/GJ

When taking into consideration the additional benefit of receiving revenue from carbon credits in the proposed South African carbon tax system, the viability of such hybridisation increases. Here the hybridisation of a plant paying for 100% of its biofuel and located at least 1,000 km from the coal mines will be feasible. These results are presented in Table 4-20. Table 4-20: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, with carbon credit benefit

% of paid biomass


20% 40% 60% 80% 100%


Similarly for a carbon tax paying entity, the reduction in its carbon emission from the implementation of this hybridisation project impacts positively on the feasibility of such a project. In Table 4-21 it is seen that the net present value, in R/GJ, for a hybridisation project implemented by a carbon tax paying entity will have a positive effect on the feasibility of such a project. Table 4-21: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for a carbon tax paying entity

% of paid biomass


20% 40% 60% 80% 100%

1 R 13/GJ R 5/GJ - R 3/GJ - R 11/GJ - R 19/GJ 100 R 15/GJ R 7/GJ - R 1/GJ - R 9/GJ - R 16/GJ 500 R 26/GJ R 18/GJ R 10/GJ R 2/GJ - R 6/GJ 1000 R 39/GJ R 31/GJ R 23/GJ R 15/GJ R 7/GJ 1500 R 52/GJ R 44/GJ R 36/GJ R 28/GJ R 20/GJ

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There are very specific conditions where hybridising a coal fired boiler with biofuel is feasible. At a low discount rate, where a company pays for 100% of its biofuel feedstock, these conditions are linked to the site being reasonably far from the coal mines, more than 1,000 km. Where a large portion of the biofuel can be sourced at low cost (more than 60%) then the distance of the site from the mines is not relevant. As such this type of hybridisation is not applicable throughout the country. For entities that would implement such a hybridisation project at a medium discounted rate of 20%, presenting medium risk to the company, the net present value of the project is presented below. At a medium discount rate, the levelised net present values are reduced. This is presented in Table 4-22. Table 4-22: Direct co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with medium risk, without any carbon benefits

% of paid biomass


20% 40% 60% 80% 100%

1 R 7/GJ R 1/GJ - R 5/GJ - R 11/GJ - R 17/GJ 100 R 9/GJ R 3/GJ - R 3/GJ - R 9/GJ - R 15/GJ 500 R 16/GJ R 11/GJ R 5/GJ - R 1/GJ - R 7/GJ 1000 R 26/GJ R 20/GJ R 14/GJ R 9/GJ R 3/GJ 1500 R 36/GJ R 30/GJ R 24/GJ R 18/GJ R 12/GJ

We have not considered scenarios for high risk biomass projects, due to the low to medium risk nature of this type of technology.

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4.3.3.2 Indirect co-firing of an industrial coal fired boiler with biomass for thermal application, requiring the purchasing of a new boiler

Depending on the setup of the site and the existing coal fired boiler, it may be more appropriate for the implementation of an indirect co-firing biofuel boiler instead of a direct co-firing setup. The implications of implementing an indirect co-firing system is that there will be increased capital costs as the purchasing of a new boiler will be required. This is assuming that the plant does not have spare capacity on site and will require a new boiler. As such, the techno economic assessment of an indirect co-firing system (with the purchasing of a new boiler) versus a direct co-firing system is not as favourable due to the increased capital cost. The biomass co-firing for an indirect firing setup accounts for 50% of the displacement of coal, with the new boiler costing R1,200/kW (as per Table 4-13). The simple paybacks of the indirect co-firing setup are presented below in Table 4-23, Table 4-25 and Table 4-26 for the three scenarios. Here it is seen that the payback of these systems can range from an immediate payback up to more than 18 years. Where in some cases the project makes no economic sense to implement. Where a company has to pay for 100% of the biofuel, indirect co-firing of such systems will only make economic sense where the site is at least 1,000km away from the coal mines where the baseline fuel is sourced. This type of hybridisation is thus not applicable throughout South Africa, but for site specific conditions. Table 4-23: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit

% of paid biomass


20% 40% 60% 80% 100%

1 2 years 7 years No payback No payback No payback


500 1 year 2 years 3 years 15 No payback

1000 Immediate payback 1 year 1 year 2 years 5 years


Immediate payback 1 year 1 year 1 year

For the case where the company implementing the co-firing hybridisation project is a company consuming small volumes of coal, and thus sourcing the coal at a higher price to companies consuming larger volumes of coal, may make the viability of such a project more promising. The paybacks for a company consuming less coal and therefore having to pay more per unit of coal is presented in Table 4-24.

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Table 4-24: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit, for a company consuming small volumes of coal

% of paid biomass


20% 40% 60% 80% 100%

1 2 years 3 years 18 No payback No payback


500 1 year 1 year 2 years 5 years No payback

1000 Immediate payback 1 year 1 year 1 year 3 years


Immediate payback


The payback periods include the benefit of obtaining carbon credits through the implementation of the project is presented in Table 4-25. The payback periods including the benefit of reducing a company’s carbon tax liability is presented in Table 4-26. These payback are relatively similar. Here it is seen that including a price on carbon does increase the viability of such hybridisation projects. Table 4-25: Indirect co-firing of coal boiler with biomass, simple payback (years) with carbon credit benefit

% of paid biomass


20% 40% 60% 80% 100%




1000 Immediate payback 1 year 1 year 1 year 3 years


Immediate payback


Table 4-26: Indirect co-firing of coal boiler with biomass, simple payback (years) for a carbon tax paying entity

% of paid biomass


20% 40% 60% 80% 100%


100 2 years 3 years 13 years No payback No payback


1000 Immediate payback 1 year 1 year 2 years 3 years


Immediate payback


Where a company can access biofuel at low cost (the 20% paid for scenario), it is viable for a company to implement such an indirect co-firing hybridisation project. The payback period ranges from immediate payback up to 2 year, no matter the distance of the site to the coal mines. This is a site specific hybridisation opportunity and not applicable throughout the country.

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The techno economic assessment results for a low discount rate (15%) are presented below on a levelised net present value (R/GJ) analysis. Where the levelised net present value is positive, the project is feasible to implement, as the cost savings outweigh the investment required. Following this the results for a medium (20%) discount rate is provided. The differences between the levelised costs for the different discount rates are important for companies to see the effect the discount rate has on project feasibility. Smaller companies may only be able to access funding at a higher discount rate, thus taking on more risk during implementation. The implementation of an indirect co-firing system is feasible only for site specific conditions, where the company has to pay for all the biofuel feedstock and where the project is at least 1,000 km from the coal mines. Where the company only pays for up to 40% of the biofuel feedstock, the location of the site to the coal mine doesn’t affect the economic viability of the project. These conditions will all show a positive return on the project investment. This is the result when only taking into the fuel cost saving, as presented in Table 4-27. Table 4-27: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk

% of paid biomass


20% 40% 60% 80% 100%

1 R 8/GJ R 0/GJ - R 7/GJ - R 15/GJ - R 23/GJ 100 R 11/GJ R 3/GJ - R 5/GJ - R 13/GJ - R 21/GJ 500 R 21/GJ R 14/GJ R 6/GJ - R 2/GJ - R 10/GJ 1000 R 34/GJ R 27/GJ R 19/GJ R 11/GJ R 3/GJ 1500 R 48/GJ R 40/GJ R 32/GJ R 24/GJ R 16/GJ

Where a company pays an increased price for its baseline coal feedstock, due to it only purchasing small volumes of coal, the economic viability of implementing this type of hybridisation project is increased. The levelised net present value of this case is presented in Table 4-28. Here is it also seen that where a company pays for up to 80% of the biofuel feedstock, the site where the hybridisation project will be implemented should be up to 500 km away from where the coal is sourced at the coal mines. Thus under site specific conditions this type of hybridisation is feasible. Table 4-28: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for companies consuming small volumes of coal

% of paid biomass


20% 40% 60% 80% 100%

1 R 13/GJ R 5/GJ - R 3/GJ - R 11/GJ - R 18/GJ 100 R 16/GJ R 8/GJ - R 0.04/GJ - R 8/GJ - R 16/GJ 500 R 26/GJ R 18/GJ R 10/GJ R 3/GJ - R 5/GJ 1000 R 39/GJ R 31/GJ R 24/GJ R 16/GJ R 8/GJ 1500 R 52/GJ R 44/GJ R 37/GJ R 29/GJ R 21/GJ

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The inclusion of the carbon credit benefit improves the economic viability assessment, Table 4-29. Table 4-29: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, with carbon credit benefit

Similarly, the results of the techno economic assessment, for the scenario where the company implementing the project will be a carbon tax paying entity under the proposed South African carbon tax, shows similar results, Table 4-30. Table 4-30: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for a carbon tax paying entity

% of paid biomass


20% 40% 60% 80% 100%

1 R 11/GJ R 3/GJ - R 5/GJ - R 13/GJ - R 21/GJ 100 R 14/GJ R 6/GJ - R 2/GJ - R 10/GJ - R 18/GJ 500 R 24/GJ R 16/GJ R 8/GJ R 0.4/GJ - R 7/GJ 1000 R 37/GJ R 29/GJ R 21/GJ R 14/GJ R 6/GJ 1500 R 50/GJ R 42/GJ R 35/GJ R 27/GJ R 19/GJ

It is under very specific conditions where the feasibility of indirect co-firing is viable. Where a company has access to funding at a medium (20%) discount rate or sees the project as a medium rated risk, the results of levelised net present values are presented below in Table 4-31. Table 4-31: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with medium risk

% of paid biomass


20% 40% 60% 80% 100%

1 v5/GJ - R 1/GJ - R 6/GJ - R 12/GJ - R 18/GJ 100 R 7/GJ R 1/GJ - R 4/GJ - R 10/GJ - R 16/GJ 500 R 15/GJ R 9/GJ R 3/GJ - R 2.5/GJ - R 8/GJ 1000 R 25/GJ R 19/GJ R 13/GJ R 7/GJ R 1/GJ 1500 R 34/GJ R 29/GJ R 23/GJ R 17/GJ R 11/GJ

A high risk of 25% wasn’t considered for this type of hybridisation, as biomass type projects are seen as a low to medium type risk projects.

% of paid biomass


20% 40% 60% 80% 100%


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4.3.3.3 Indirect co-firing of an industrial coal fired boiler with biomass for thermal application, where a spare capacity boiler can be retrofitted

The scenario may exist at a company where the company has existing spare boiler capacity. At such facilities the company may be able to implement an indirect co-firing hybridisation project, by retrofitting an existing boiler. As such, the extra capital for purchasing of a new boiler to allow for indirect co-firing won’t be necessary. Such hybridisation is thus possible at a lower capital cost. The payback results of this scenario are the most economic when compared against direct co-firing and indirect co-firing when requiring the purchasing of a new boiler. This is due to the reduced capital cost and the increased blending ratio of 50% of biofuel with coal. However this type of hybridisation is feasible under very site specific conditions and cannot be applied throughout the country. The simple payback periods for fuel saving benefits are presented below in Table 4-32 and Table 4-33. Where Table 4-33 factors in the increased cost of purchasing baseline coal for companies that consume only small volumes of coal. For these scenarios it is seen that in many cases there is an immediate project payback. However were a company pays for 100% of the biofuel feedstock, the site where the project is to be implemented should be at least 1,000 km away from the coal mines in order for the project to be economically viable. Table 4-32: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit

% of paid biomass


20% 40% 60% 80% 100%

1 Immediate payback 2 years No payback No payback No payback

100 Immediate payback 1 year No payback No payback No payback


Immediate payback

Immediate payback 5 years No payback


Immediate payback

Immediate payback



Immediate payback

Immediate payback

Immediate payback

Immediate payback

Table 4-33: Indirect co-firing of coal boiler with biomass, simple payback (years) with no carbon or tax benefit, for a company consuming small volumes of coal

% of paid biomass


20% 40% 60% 80% 100%

1 Immediate payback 1 year 6 years No payback No payback


Immediate payback 2 years No payback No payback


Immediate payback

Immediate payback 1 year No payback


Immediate payback

Immediate payback

Immediate payback

Immediate payback


Immediate payback

Immediate payback

Immediate payback

Immediate payback

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The payback periods when the benefit of carbon credit and the reduced carbon tax liability are taken into account are presented in Table 4-34 and Table 4-35 respectively. Having a price on carbon increases project feasibility. Table 4-34: Indirect co-firing of coal boiler with biomass, simple payback (years) with carbon credit benefit

% of paid biomass


20% 40% 60% 80% 100%



Immediate payback 2 years No payback No payback


Immediate payback

Immediate payback 1 year No payback


Immediate payback

Immediate payback

Immediate payback

Immediate payback


Immediate payback

Immediate payback

Immediate payback

Immediate payback

Table 4-35: Indirect co-firing of coal boiler with biomass, simple payback (years) for a carbon tax paying entity

% of paid biomass


20% 40% 60% 80% 100%


100 Immediate payback 1 year 5 years No payback No payback


Immediate payback

Immediate payback 2 years No payback


Immediate payback

Immediate payback



Immediate payback

Immediate payback

Immediate payback

Immediate payback

The levelised net present value for this scenario is presented below at a low (15%) and medium (20%) discount rate. The levelised net present values (R/GJ) at a low discount rate are presented in Table 4-36 and Table 4-37. Where Table 4-37 includes an increased coal purchase price for those companies consuming small volumes of coal. It is seen that where 40% of the biofuel is paid for, the distance of the site, where the hybridisation project will be implemented, from the coal mines does not affect the viability. For companies consuming small amounts of coal, the distance does not affect viability where up to 60% of the biomass is paid for. But it is seen that it is only under specific site conditions where this type of hybridisation is feasible.

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Table 4-36: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk

% of paid biomass


20% 40% 60% 80% 100%


Table 4-37: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for companies consuming small volumes of coal

% of paid biomass


20% 40% 60% 80% 100%

1 R 16/GJ R 8/GJ R 0.3/GJ - R 8/GJ - R 16/GJ 100 R 19/GJ R 11/GJ R 3/GJ - R 5/GJ - R 13/GJ 500 R 29/GJ R 21/GJ R 13/GJ R 5/GJ - R 2/GJ 1000 R 42/GJ R 34/GJ R 26/GJ R 19/GJ R 11/GJ 1500 R 55/GJ R 47/GJ R 40/GJ R 32/GJ R 24/GJ

The inclusion of a carbon price, by including the benefit of carbon credits and reduction in carbon tax liability are also presented below in Table 4-38 and Table 4-39 respectively. The feasibility of implementing hybridisation projects are increased where the price of carbon is included. Table 4-38: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, with carbon credit benefit

Table 4-39: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with low risk, for a carbon tax paying entity

% of paid biomass


20% 40% 60% 80% 100%


% of paid biomass


20% 40% 60% 80% 100%


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It is evident that where 100% of the biofuel is purchased by a company, the site where the hybridisation project is to be implemented should be at least 1,000 km away from the coal mines. This makes the project viable only in very specific locations in the country. The availability of biomass in these areas may also be limited. The results of the levelised net present value at a medium (20%) discount rate is presented below in Table 4-40. This is relevant to those companies that can obtain funding at these higher discount rates or consider this project a medium risk, which increase the economic risks to the project viability. Table 4-40: Indirect co-firing of coal boiler with biomass, levelised net present value (R/GJ) at discount rate for project with medium risk

% of paid biomass


20% 40% 60% 80% 100%

1 R 8/GJ R 2/GJ - R 4/GJ - R 9/GJ - R 15/GJ 100 R 10/GJ R 4/GJ - R 2/GJ - R 7/GJ - R 13/GJ 500 R 18/GJ R 12/GJ R 6/GJ R 0.3/GJ - R 6/GJ 1000 R 27/GJ R 22/GJ R 16/GJ R 10/GJ R 4/GJ 1500 R 37/GJ R 31/GJ R 25/GJ R 20/GJ R 14/GJ

As mentioned previously, the high risk rate was not considered for biomass, as these projects are considered to have a low to medium risk associated with their implementation.

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4.3.3.4 Conclusions for hybridisation of industrial scale coal fired boilers with biomass co-firing

The low to medium risk of biomass boiler technology, makes hybridisation with coal fired boilers an attractive option. It is however seen that this type of hybridisation is very site specific and feasible within certain conditions, it is not applicable throughout the country. It should be noted that in these site specific areas these sites may not have access to suitable quantities of biofuel feedstock, thus not presenting an opportunity. The conclusions from the techno economic review were that:

• Biomass hybridisation could be feasible under certain conditions, presented in Table 4-13 along with the various distances from the coal mines and the portion of biofuel paid for.

• Changing the conditions could radically alter the outcome of the feasibility. These could include:

o The capital cost assumed that a retrofit is required. This may not be the case where a boiler needs to be reconditioned, where the conversion cost could form part of the reconditioning cost. A new boiler may be built, where the co-firing can be designed into the new boiler.

o Biomass could be available at a negative costs, if a waste fee could be charged for burning of the biomass. Negative costs are not modelled, but would have a more positive impact on the results.

o Small generators who pay more for coal will have faster payback periods. • Where a company purchases all of the biofuel feedstock, the location applicability for an

economically viable project is evident. Applicable sites for implementing hybridisation where all the biofuel is purchased must be at least 1,000 km away from the coal mines. In these locations, the access to biofuel feedstock may not be available.

• Where a company can obtain biofuel at low cost, hybridisation of coal fired boilers with biofuel should be implemented, no matter the location of the site compared with the coal mines.

• Where biomass supply is more than 20 km from the site where it will be used, the economics will be less favourable. The modelling carried out in this techno economic review only assumed that biomass was sourced within a 20km radius. Due to the low density related to biomass feedstocks, the transport costs could be higher than that of coal, and may not make sense to transport it from further distances to be used onsite.

• It is required that the biomass is sustainably sourced in order to prevent degradation of ecosystems and to prevent competition with other forms of land use, as well as to ensure a reduction in GHG emissions through hybridisation.

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4.3.4 Hydro power techno economic review In the section micro hydro power is considered as a substitute for grid electricity. South Africa currently has a total installed capacity of around 50 MW of small hydropower, and a proven potential of 247 MW (Klunne, 2016). However there are discrepancies in the numbers reported by various sources which indicates that there is a lack of consensus on the installed capacity of small scale and micro hydro that is currently in operation in the country and the potential thereof. 4.3.4.1 Hydro electricity generation installation at an industrial operation to augment

grid electricity supply Micro hydro has a levelised cost of electricity between R0.3/kWh and R4.03/kWh based on capital costs in the range of R 10 000/kW and R 65 500/kW (adjusted for exchange rate and inflation) (IPCC, 2011). The range of costs for micro hydro power plants has an overlap with rural electricity tariffs. For example the Eskom Nightsave Rural tariff is R0.54/kWh whereas Madibeng Municipality Rural Energy Tariff is R2.31/kWh. The viability of micro hydro is dependent on the suitability of the site, the permanence of the water source and the tariff charged. In our analysis of hydro power we analyse four combinations of electricity tariff and technology costs: high electricity price and low hydro power costs; low electricity price and low hydro power costs; high electricity price and high hydro power costs; and low electricity price and high hydro power costs. The results are presented in Table 4-41 to Table 4-44. Table 4-41: Levelised savings for micro hydro to substitute grid electricity: high electricity price and low hydro power costs



Discount rate

15% 20% 25%


Payback within the first year

R 0.68/kWh R 0.47/kWh R 0.35/kWh


Payback within the first year

R 0.71/kWh R 0.49/kWh R 0.36/kWh

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Table 4-42: Levelised savings for micro hydro to substitute grid electricity: low electricity price and low hydro power costs



Discount rate

15% 20% 25%


1.75 years R 0.13/kWh R 0.08/kWh R 0.06/kWh


1.92 years R 0.15/kWh R 0.10/kWh R 0.07/kWh

Table 4-43: Levelised savings for micro hydro to substitute grid electricity: high electricity price and high hydro power costs



Discount rate

15% 20% 25%

1. No other benefits other than hybridisation to save fuel costs 7.75 years R 0.04/kWh R -0.03/kWh R -0.07/kWh


7.17 years R 0.05/kWh R -0.02/kWh R -0.05/kWh

Table 4-44: Levelised savings for micro hydro to substitute grid electricity: low electricity price and high hydro power costs



Discount rate

15% 20% 25%


No payback R -0.52/kWh R -0.42/kWh R -0.36/kWh


No payback R -0.50/kWh R -0.41/kWh R -0.35/kWh

A high electricity price (R 2.31/kWh) and a low capital cost (R 10 000/kW) creates an attractive scenario for micro hydro development for all discount rates without carbon pricing. At a low electricity price scenario (R0.54/kWh) and low hydro power costs the substitution of grid electricity with micro hydro power is viable without a carbon tax or credit benefit. Under high electricity prices and a scenario of high micro hydro power costs (R 65 600/kW) there is some potential with lower returns and a payback period of between 7 and 8 years with or without carbon taxes or carbon credits. In the final scenario, the upper range of the hydro costs and the lower range of electricity prices considered, there is not likely to be a viable business case even with a carbon price. In all scenarios the pricing of carbon either through the carbon tax or credits has a

246

benefit of between 3 and 5 cents per kWh. Due to the wide range of tariffs and hydro technology costs the carbon pricing may only be effective in marginal cases. In some cases, hydro resources (streams and rivers) in remote areas are available. This coupled with national grid electricity infrastructure which is too expensive to extend, may provide a viable solution for micro hydro systems. However, modelling was only done with grid connected hybridisation. Micro hydro power supply economics will be more favourable in remote areas.

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4.3.5 Overall conclusions from techno economic review On completion of the techno economic review, various conclusions can be drawn. It has been found that it is feasible to implement solar PV to augment electricity supply from the grid through embedded generation, at all of the average electricity prices considered, due to the decreasing costs of solar PV. The low, medium and high average electricity prices, which are linked to current municipal electricity tariffs in various locations in South Africa cannot compete with solar PV prices, thus making it a viable solution. The assessment included grid connected solar PV systems, which rely on the national grid for power during non-sunlight hours. Similarly off grid solar PV installations for electricity generation would require an energy storage system to ensure continuous devilry of power. It was found that the implementation of wind generated electricity is sensitive to the local electricity tariffs and appears to be most suitable to applications where no grid electricity connections exist, such as rural areas and for services which have inherent storage requirements such as water pumping. When considering concentrated solar, the implementation of concentrated solar power for electricity generation is only feasible for large scale applications, where a site has the necessary land available. The implementation of concentrated solar for steam production to augment steam from a coal fired boiler is feasible at a low discount rate. Funding at lower discount rates would normally only apply to government in the interests of public good. A price on carbon is required in order to provide sufficient returns as a commercially funded project. When assessing the feasibility of biomass co-firing in industrial scale coal fired boilers, it was found to be feasible in all locations where sustainably sourced biofuel is available at low cost. However it is important to note that such conditions are very site specific and do not occur widely across the country. Where a company has to purchase all the biofuel, the hybridisation of such systems only become feasible where the site for implementation is at least 1,000km away from the coal mines. This distance increases the transport cost of the coal to site, making it more competitive to substitute with biofuel. This type of hybridisation will not be applicable throughout South Africa, but only in specific areas where a biomass feedstock is available. The viability of micro hydro power is dependent on the location and access to permanent source of running water and municipal electricity tariffs. The suitable locations for micro hydro power in the country are scarce. The range of municipal tariffs and the costs for micro hydro power vary significantly making implementation sensitive to location. Overall it has been seen that the inclusion of the benefits of carbon pricing increases the viability of projects. From the work carried out, one of the many comments received during stakeholder consultation is that the proposed carbon tax in South Africa will be a significant driver for the implementation of hybridisation projects in the country

248

It is important to note that the techno economic review has used the latest available information based on current conditions. However, in the future the relevance may change and may impact on the outcome of a techno economic review. For example, when looking at the historic trend of electricity prices, Figure 4-4, it can be seen that the electricity prices have increased over the years at varying rates. If this trend continues, the increased electricity price will have a positive impact on the feasibility of many of these hybridisation options, and could stimulate the further rollout thereof. The relationship between electricity prices of the various sectors has also changed over time, for example domestic electricity prices have grown at a slower rate than agricultural and industrial electricity prices. The rate of electricity price increases has been higher than inflation over the last ten years.

Figure 4-4: Eskom’s historic average price trend (c/kWh), (Eskom, 2017)

In addition the learning curves of the various renewable energy technologies and their integration as hybridisation projects with fossil fuel systems could have a positive impact on the feasibility of such projects in the near future. There are other such factors that may have similar or opposite impacts such as the carbon price or pricing of other externalities. These factors may increase the viability of implementing further hybridisation projects in the future.

2003 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17Average standard tariff price

(Excld NPA and Int'l) 16.68c 16.82c 17.69c 18.38c 19.89c 25.65c 33.39c 43.94c 52.50c 61.25c 65.48c 70.10c 78.30c 84.70c

Local-authorities 15.25c 15.19c 16.13c 16.88c 18.21c 23.29c 30.84c 39.53c 48.03c 54.59c 60.67c 65.92c 74.11c 81.38cResidential 36.58c 38.70c 40.08c 41.74c 44.56c 53.43c 63.98c 66.45c 77.50c 87.05c 92.41c 98.06c 108.11c 118.60cCommercial 20.62c 21.88c 22.69c 23.50c 24.85c 31.61c 40.97c 52.63c 63.92c 73.24c 82.67c 89.16c 100.07c 109.09cIndustrial (Excl NPA) 14.73c 14.42c 14.65c 14.76c 16.30c 21.94c 29.24c 37.64c 44.44c 51.09c 58.72c 63.26c 70.52c 76.87cMining 15.07c 15.36c 16.19c 16.90c 17.99c 23.12c 30.25c 39.78c 48.10c 55.74c 64.66c 69.52c 78.01c 84.80cAgriculture 29.14c 30.83c 32.86c 33.69c 35.91c 45.78c 58.96c 72.72c 87.22c 99.75c 108.75c 115.66c 128.19c 141.70cTraction 18.98c 19.37c 20.25c 21.05c 23.31c 29.78c 38.23c 48.55c 56.24c 68.66c 77.34c 83.63c 96.60c 104.95c

0.00c

20.00c

40.00c

60.00c

80.00c

100.00c

120.00c

140.00c

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4.4 Case studies Various case studies have been analysed to provide insight into hybridisation. These case studies are considered to be successful examples of the hybridisation of fossil fuel technologies with renewable energy technologies. The case studies range from project examples to wider sectoral programmes. While the majority demonstrate successful implementation in the domestic environment, key international case studies have been included as well in order to provide a wider context for the trends that may be observed from analysing the key success factors of the respective hybrid projects. The analysis of the case studies seeks to provide insights into the evolving local and international energy sectors, which continue to contend with challenges relating to the World Energy Council’s definition of energy sustainability. That is, the effective management of energy security; energy equity and environmentally sustainable (i.e. renewable or low-carbon). We are grateful for the contributions of various project developers and champions who represent the organisations listed below. We would like to acknowledge the time and effort that they provided in assisting us develop insights into the key success factors and lessons learnt from which future project or programme developers may draw. Participating organisations:

• City of Johannesburg’s grid connected small scale solar PV programme: City Power • Solar PV on Clicks head office: Clicks Group • Power generation from biogas in Windhoek, Namibia: Cape Advanced Engineering • Biogas used for energy services in South African schools: Agama Biogas • Harmony biogas project: Harmony Gold • Heat and power produced by biogas at Riverside Piggery: Trade Plus Aid and Acrona South Africa • Fuel switch in the Brazilian steel sector: ArcelorMittal • Badplaas hydro pilot: Nepsa Energy • Electricity generation from methane at the Beatrix Gold Mine: Sibanye-Stillwater • Co-firing waste coffee grounds with coal for heating services in Escort: CSIR • Contributors who wanted to remain anonymous organisations.

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4.4.1 Solar PV on retail facilities in Gauteng Retail companies within South Africa are increasingly motivated to buffer themselves from increasing electricity tariffs and to ensure a reliable source of own electricity supply for their operations. In addition to the provision of long term sustainability, these companies aim to reduce indirect emissions associated with the fossil fuel based grid electricity. The installation of rooftop solar PV on retail stores to augment electricity supply from the grid presents a solution to these challenges. These factors were some of the main drivers that led a large South African retailer to implement solar PV on three of its standalone stores. The installation of solar PV on the retailer’s standalone stores was fairly easy to implement, as the retailer has direct control over the installation and management of the PV facilities, as opposed to retail outlets in shopping centres which are usually managed by property management companies. The South African retailer has implemented three such systems, all of which have been carried out through negotiating power purchase agreements with a third party. Type of hybridisation: grid and/or diesel generator electricity supply augmented with rooftop solar PV installations. Cost: large retailers often enter into a power purchase agreements with third parties, eliminating capital cost requirements and ensuring cost competitive renewable electricity prices. As such the payback period of this case study is unknown, as it was third party capital that was invested. Maturity: rooftop solar PV panel installations have a high level of maturity and are widely used around the world and in South Africa and have a life span of between 20 to 25 years. Key issues: the solar PV installations were designed and limited to provide between 15 to 25% of the retail stores’ annual electricity requirements. However the size and economic viability of rooftop solar PV installations could be increased through the ability to supply renewable energy to the national grid. This limitation reduced the retailer’s ability to maximise returns on installations. In addition, successful power purchase agreements rely on long term modelling of the South African national grid tariffs. If the tariff differentials between the national grid and renewable energy are not favourable, then the feasibility of rooftop solar PV installations is reduced. Success factors: the power purchase agreements ensure the supply of renewable electricity at competitive rates compared with national grid electricity. This large South African retailer has seen that some of its stores can run solely on renewable electricity for short periods during peak solar radiation periods. Furthermore the renewable electricity costs negotiated through the power purchase agreements has allowed the retailer to drive down electricity related costs in its stores through the lower electricity tariffs. In addition, purchasing the power from a third party allows the retailer to mitigate the risks of financing and maintaining such a system. Apart from energy security and greenhouse gas reductions, private companies also place a value on positive publicity.

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4.4.2 Solar PV on Clicks head office A 400kW solar PV facility was installed on the Clicks Group’s head office in Cape Town in 2015. Clicks purchases power from the owners of the PV facility, at a competitive rate. During the 2016 financial year, Clicks generated approximately 655 MWh of electricity from the installation, which accounted for 21% of the head office’s electricity consumption. As such the Group is 46% towards achieving its target of producing 1.5% of its own renewable energy by 2020. Assuming that the Group maintains a constant electricity consumption profile up to 2020, the renewable energy (from solar PV installations) will account for around 1.5% of the Group’s electricity requirements (around 1,310 MWh/year generated from renewable energy). Clicks is currently investigating rolling out the installation of solar PV facilities on the roofs of the Group’s various distribution centres, specifically Montague Gardens, Centurion and UPD Lea Glen centres. Type of hybridisation: the grid-tied rooftop solar PV installation displaces a portion of grid electricity requirements of the Clicks’ Group Head Office. Cost: the solar PV installation implemented in 2015 cost Clicks approximately R 6.9 million. Maturity: rooftop solar PV panel installations are widely used around the world and in South Africa. Some solar PV manufacturers, suppliers and small scale manufacturers were established before the first round of REIPPPP in 2011 (GreenCape, 2015). Key issues: energy security for the Clicks Group is essential for maintaining productivity in its head office as well as avoiding downtime of its tracking and ordering systems. These systems include the transport of essential medicines and clinic requirements. As a listed entity, the Group aims to ensure the reduction of its carbon footprint over time. Success factors: the PV facility’s renewable energy tariff is more competitive than purchasing power from the grid. Furthermore the rooftop PV facility reduced Clicks’ head office emissions by 21% during FY2016 and continues to support the Group energy and carbon targets.

Figure 4-5: Clicks' solar PV installation at the Group's Head Office.

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4.4.3 City Power’s grid connected small scale solar PV programme City Power is responding to the energy trilemma of affordable, clean and safe energy, by piloting an innovative hybrid project through the installation of 110 grid connected, micro (3kW) solar PV panels that supplement grid electricity supply in the Lawley and Thembelihle Informal Settlement near Lenasia, Johannesburg. The initiative supplements household and street lighting and launched mid-2017. The outcome of the pilot will establish if the PV programme is more cost effective over time to implement than typical grid connections.

Resource utilised: solar radiation is used to provide electrical energy to households.

Type of hybridisation: the 110 solar PV panels are located across the settlement and installed on a series of pylons (12 panels per pylon) connected to an AC network in a ‘semi-smart’ grid formation, meaning that the electricity demand and load limitations can be managed by City Power. The panels have an expected lifespan of 20 years, if properly maintained. Micro storage facilities (lead acid batteries) are also supplied (one battery set per 12 households) to accommodate demand outside of sunlight hours, and together with the solar PV panels they complement the supply of residential electricity to the settlement. The provision of LPG for cooking purposes was considered but ultimately excluded from the pilot due to budget constraints.

Cost: the cost incurred by City Power was between R41 000 - R50 000 per service connection. A standard grid connection costs R25 000. The additional cost for the panels is expected to be recovered over a five year period through the electricity the panels will contribute to the system. The batteries were required to assist with reducing the maximum demand on the Eskom supply into the area during the morning and evening peaks. The batteries will constitute an ongoing maintenance cost due to their relatively short lifespan.

Maturity: solar PV panels are widely used around the world and in South Africa. The integration of the panels in a ‘semi-smart’ grid is however an innovative feature, particularly in South Africa where individual installations are the norm. The City Power will investigate the technical and economic feasibility of the pilot programme in the years to come.

Key issues: the use of solar as a resource, instead of grid electricity, could impact the City Power’s revenue collections. Furthermore there are concerns that the exclusion of LPG for cooking purposes may compromise the goal of the pilot, which is to reduce both the demand on the inadequate grid supply and effects of illegal connections.

Success factors: the grid connected PV panels are distributed energy facilities that generate renewable energy and reduce the increasingly unsustainable demands on the national grid in this area. City Power’s pilot programme aims to provide electricity to the low-income, underserviced community at a lower cost (driven by falling PV panel costs), using an energy source that is less polluting and carbon intensive than the current grid supply and reduce transmission and distribution losses. Small rooftop PV installations (<1MW) do not need to apply for generating licences from NERSA, but all rooftop PV applications do however need to be registered.

Figure 4-6: Solar panel at Thembelihle Informal Settlement (source: City Power)

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4.4.4 SOLTRAIN solar thermal demonstration systems The Southern African Solar Thermal Training and Demonstration Initiative (SOLTRAIN) is a regional initiative that provides capacity building and demonstrations of solar thermal systems in the Southern African Development Community (SADC). The initiative supports SADC countries to switch from fossil fuel energy supply systems to renewable energy, particularly solar thermal. As much as 40% of the electricity consumption within the SADC region is used to generate hot water within households (Austrian Development Cooperation, 2012). To address this issue, the SOLTRAIN initiative installed 127 solar water heaters across the region, with local projects in Pretoria, Johannesburg and Cape Town, between 2009 and 2016. The systems were installed across a variety of retirement villages, student housing, adult residential facilities, sheltered employment centres, hospitals, guesthouses and private businesses. The systems have a combined yield of 1,650 MWh, equating to annual electricity cost savings of approximately R 3.5million. Type of hybridisation: solar water heaters replace electric geysers, augmenting grid electricity. Cost: solar thermal water systems range in cost from R 4 200 to R 24 100. Maturity: solar water heaters are used extensively internationally and the technology is tried and proven. Key issues: bank loans are not always readily available for individuals wanting to invest in solar thermal systems. There is therefore a need for financing models to ensure co-financing in addition to international funding (Energy Research Centre, 2013). Key issues were also identified with respect to the maintenance of large solar thermal systems. The need for knowledge transfer and capacity building is important to ensure long term sustainability of the systems. During phase I of SOLTRAIN, the majority of the components required for the solar thermal systems were imported because locally produced components were much more expensive. The need for a sustainable local solar manufacturing industry is pertinent (Energy Research Centre, 2013). Furthermore the broad range in costs of the solar thermal systems indicates that the Southern African market is still maturing. Success factors: solar thermal systems have the potential to reduce the electricity demand and expenses of these households, while also reducing greenhouse gas emissions. The systems installed across SADC have reduced electricity consumption by 1,650 MWh/year which is equivalent to more than 500 tCO2e avoided annually. With the exception of Zimbabwe, SOLTRAIN has received strong political support as it aligns with the national energy policies of the host countries in the region.

Figure 4-7: Solar thermal systems installed at the Bergridge Park

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4.4.5 Solar thermal for industrial processes Industrial processes often require energy in the form of heat. Both the Cape Brewing Company (CBC) in Western Cape, South Africa and the Martin Next Generation Solar Energy Centre in Florida, United States are successful examples of solar thermal use in industrial applications.

Approximately 60% of the CBC’s hot water requirements are met by the flat plat solar thermal collectors installed on the company’s premises in Paarl, Western Cape. The 84kW facility, producing around 105.6 MWhth annually, was installed in 2015 and the collector field spans 120 m² (Solar Payback, 2017).

The 75 MW Martin Next Generation Solar Energy Centre directly displaces fossil fuel use by providing solar thermal energy to a combined-cycle natural gas power plant. The concentrated solar facility utilises over 2 million m2 of parabolic troughs with production starting in 2010 (NREL, 2013). Type of hybridisation: Solar radiation at both CBC and Martin Next Generation is captured in the respective collector fields which heats process fluids. At the CBC facility a heat exchanger transfers this heat to the production process in the form of hot water (70-90°C). The solar component accounts for 29.6% of the paraffin demand onsite (Solar Payback, 2017). At the Martin Next Generation the heat is used to generate steam for use in a Rankine system that supplements the electricity production of an adjacent gas plant. Cost: the CBC installation cost USD 110 000, including installation and a EUR 30 000 subsidy from SOLTRAIN (USD 1 730/kW). The Martin Next Generation Solar Energy Centre cost USD 476.3 million (USD 6 351/kW). Maturity: the respective solar thermal technologies are mature. The CBC solar thermal panels were designed and produced in Austria and through this project have now been used for the first time in Southern Africa. The integration of solar thermal at the Martin Next Generation Solar Energy Centre was however particularly innovative as it was the first project to integrate solar thermal with an open cycle gas power plant. Key issues: high upfront investment costs plus low energy prices are typical barriers to the uptake of solar thermal installations in industrial and power production processes. The complexities of integrating new systems with existing, potentially inflexible, processes also pose risks. Success factors: the CBC solar system was integrated within one day, resulting in minimal operational disruptions. The company expects to see a return on investment in around 6 years. Financial savings of approximately 20% were achieved at Martin Next Generation (compared with the cost of a similar stand-alone solar plant) because the facility uses a steam turbine, transmission lines, and other infrastructure from an existing combined cycle unit, (NREL, 2013).

Figure 4-8: CBC solar thermal panels (photo: www.solarthermalworld.org)

Figure 4-9: Martin Next Generation Solar Energy Center (photo: www.cspworld.com)

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4.4.6 Wind-diesel hybrid at a garnet mine in Australia Australian Garnet specialises in the marketing, research and development and distribution of high quality West Australian garnet products. The mine is located in a historic and remote sand mining area which is characterised by particularly windy conditions. The closest national grid connection is roughly 10 km away, making it difficult and expensive for the mine to connect to the grid. In addition, the grid electricity can be unreliable, due to the rapid expansion in the region with limited infrastructure upgrades. In response to these challenges, Australian Garnet is developing an onsite wind-diesel hybrid generation system (Dougherty, 2017b).

The mine aims to incorporate 6 MW of wind turbine generated power, which will account for over 50% of the mine’s energy per year. The project will be Australia’s first wind-diesel hybrid mine once operational. Project construction began in mid-2017 and is expected to be complete by the end of 2018. Electricity consumption is high due to dependence on conveyor belt systems and processing.

Type of hybridisation: 6 MW wind-diesel hybrid generation system. Cost: research suggests that a wind-diesel hybrid power system, with 25% wind penetration, can cost approximately US$ 4.2 million (Rehman et al. 2005). This cost includes six wind turbines with electricity production of 4 000 MWh and three diesel generators with electricity production of 12 000 MWh. Maturity: wind farms of a similar scale are common in the Western Australian region, including Kalbarri and Mumbida, commissioned in 2008 and 2013 respectively (Kevan, 2017). Key issues: integrating electrical control and power management in the hybrid system is a complex task (Dougherty, 2017b). Success factors: Wind speeds of more than 10 m/s could potentially allow the mine to be completely wind powered. This project is expected to save 2.5 million litres of diesel per year, ultimately reducing the greenhouse gas emissions of the mine by 6,550 tCO2e/year (Kevan, 2017). Wind power is particularly beneficial when used for the energy intensive process of mineral sands mining. The costs involved in transporting and processing the sand are significantly reduced when using wind power compared with diesel power for the operating of conveyor belts (Dougherty, 2017b).

Figure 4-10: Australian Garnet's Balline Project Site in Western Australia.

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4.4.7 Power generation from sewage biogas in Windhoek, Namibia The Gammams Water Care Works, situated in Windhoek, demonstrates how biogas may be used to generate electricity at a public utility. The Gammams Water Care Works has been in operation since 1971 and is the only municipal wastewater treatment plant that services the city. The biogas project was motivated by the need to upgrade the wastewater treatment works and reduce onsite electricity consumption. The facility was upgraded and bio-digesters were installed in 2015. The bio-digesters at the plant have been sealed off to capture the biogas from the sewage system, reducing the quantity of methane emitted to the atmosphere. The captured biogas is subsequently combusted in combined heat and power engines to generate 245 kW of electric power and 494 kW of thermal energy. This electricity and heat is used by the water treatment plant, augmenting the use of emissions intensive grid electricity. The power generated by the biogas facility supplies 30%-40% of the operation’s electricity requirements. Resource utilised: the facility receives around 37Ml of domestic wastewater per day which is treated by the plant for direct reuse in Windhoek’s drinking water system. The power plant uses approximately 450 tonnes of anaerobically digested sludge per day to generate just under 3,000 m3 of biogas (equivalent to 1,275 kg of methane gas per day). The project developer is considering increasing the capacity and efficiency of the facility by upgrading the engines in the future. Type of hybridisation: the biogas supplies energy for two new, grid embedded, combined heat and power engines as well as a low pressure boiler. An installed gas storage tank (volume of 100 m3) is capable of accumulating eight hours of gas production. Therefore, the plant can be used as a peak generation plant in addition to being a biogas plant and a combined heat and power plant. Cost: the capital cost to upgrade the existing plant infrastructure and install the biogas power plant was approximately R20 million. Maturity: the biogas to energy project design are conventional in nature and have been tried and tested in both local and international applications. The engines technology is unique and developed and built in South Africa. Key issues: the timeframe to conclude the project was lengthy. It took two years to conclude the contract with the City of Windhoek and a further two years to finalise the financial arrangements, which were required before construction could commence. Success factors: the City of Windhoek the City of Windhoek had few regulatory constraints regarding entering into a partnership with a private company (compared for example to the constraints imposed by the Municipal Finance Management Act on South African municipalities). This enabling business environment contributed to the successful implementation of the project. Windhoek also has advanced water treatment and reclamation facilities and skilled and knowledgeable personnel. In addition, the biogas project was registered with the Clean Development Mechanism, which provides for an additional revenue stream (once the credits are issued) which increases the bankability of the project.

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4.4.8 Bio2Watt organic animal waste to electricity case study

In 2015 Bio2Watt built the first commercially viable waste to energy plant in South Africa. The 4.6MW plant is located on the premises of a large cattle feedlot (Beefcor). The location provides the project with proximity to key feedstock supply, grid access and sufficient water. The feedstock for this plant includes cattle manure, chicken abattoir waste, vegetable and fruit market waste, paper sludge and dairy waste. It relies on approximately 120 000 tonnes of organic waste per year, whilst producing around 20 000t/yr of fertiliser as by-product. The electricity produced is purchased by BMW South Africa via a power purchase agreement, with BMW willing to pay a premium for green power.

Type of hybridisation: the biogas is generated from the organic waste and converted to electricity. BMW has agreed to a 10 year deal to buy as much as 4.4 MW from the biogas plant. This is used to augment BMW’s use of coal-fired electricity from Eskom. The biogas facility, when ramped up to full capacity, will represent 25% to 30% of the electricity consumption at BMW’s factory (Hill, 2016). Cost: the plant cost approximately R165 million and was financed through both private and public funds (Bio2Watt, 2016). This included an R16 million grant from the Department of Trade and Industry and a R98 million loan from the Industrial Development Corporation. Equity investors included Bio2Watt, Norfund, two impact funds and the EPC contractor (Thomas, 2016). Maturity: converting organic waste into methane for electricity production using bio-digesters is a well proven technology. However, this technology has not yet been widely applied in South Africa. This project has been constrained by unknown wheeling costs and application procedures.

Key issues: as a first of its kind project in South Africa there were a number of institutional hurdles to overcome. The difficulty in obtaining some of the required licenses, the non-alignment and diverse licensing application processes and the need for additional permits as the authorisation process matured, led to very high development costs. As such, securing initial finance was difficult and required that the financial model underwent a number of changes (Ndlovu et al, n.d). Local technology support was challenging and delayed construction. Initial bio-methane potential tests had to be outsourced to New Zealand as there were no suitable laboratories in South Africa. However these pioneering efforts have served to strengthen some of the local structures required to build a South African biogas industry. Success factors: strong partnerships between the various stakeholders propelled the project forward. These partnerships refer to cooperation and commitment between the off-taker, the feedstock providers, Eskom, the local municipality and the Department of Energy (Bio2Watt, 2016). Having BMW as a project partner and the signing of the power purchase agreement with BMW facilitated investor confidence (Ndlovu et al, n.d). The new waste management legislation in South Africa, prohibiting the disposal of organic waste in landfills, will ensure the continued success of this project.

Figure 4-11: The Bio2Watt Biogas Plant located on the Beefcor cattle feedlot (Earthworks, 2016)

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4.4.9 Biogas used for energy services in South African schools Khangezile Primary is a no-fee paying school located in Kwa Temba, Johannesburg. The school has a feeding programme that provides learners with meals twice a day. Volunteers cook meals for learners using biogas, generated by a 6 m3 bio-digester installed as part of the Sustainable Energy and Livelihoods project, managed by Earthlife Africa and sponsored by the European Union and Oxfam. There are two biogas digesters tanks located at Khangezile Primary. The bio-digesters can take up to 50 kg of organic feedstock for short period, but the best daily input is 20 kg. The organic feedstock is converted into biogas, which is piped along the school wall to the kitchen where it is used, in addition with other conventional fossil fuels such as liquid petroleum gas (LPG), to prepare meals for school learners. Resource utilised: food and garden waste. Type of hybridisation: biogas displaces the use of LPG used for cooking food. Cost: the cost of implementing a biogas system is approximately R 95 000 (R15,800/m3). Additional training and support services are reported to cost approximately R 20 000 (for a three month training period). Maturity: the technology used is an AGAMA Biogas system, which has been produced in South Africa for over ten years. Globally, micro-biogas systems have been used for more than 20 years. Key issues: the success of similar community based biogas installations hinges on endorsement and support from the community, as well as sufficiently trained personnel to operate the systems and sustainable sources of feedstock supply. Low quantities of food and garden waste can threaten the viability of biogas projects. Furthermore the expectations of the school, working staff and local community need to be managed to avoid miscommunications. Success factors: the technology is uncomplicated and durable. Bio-digesters can be positioned in rural communities, thereby providing cleaner and more affordable sources of energy to traditionally or underserviced areas. Additional success factors were derived from the support provided by the school’s headmaster as well as student and local community involvement, which continue to assists with successful implementation and operation. Furthermore, the provision of training to onsite staff has improved the success of the system, meaning that the school is able to run the system without external contractors and associated costs.

Figure 4-12: Biogas digester tanks installed at Khangezile Primary School in Springs. Photo: eNCA/Bianca Bothma

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4.4.10 Harmony biogas to thermal energy project Harmony Gold Mining Company Limited has implemented the first phase (1.5MW) of a 6MW biogas plant at its Free State operations. The project produces biogas from biomass cultivated on mining impacted land, using water from the tailings storage facility to irrigate the crops. This land cannot be used for food production, due to the contamination of the land with heavy metals from mining. The project forms part of Harmony’s rehabilitation strategy and effectively links mine rehabilitation with alternative energy solutions. The biomass will be cultivated from three types of crops: energy beet, sorghum and giant king grass. The crops will be rotated seasonally to maximise biomass generation. Phase 1 of the project is set to deliver 71 000GJ of energy. The project plans to ramp up to generate 187 000GJ. Through this initiative, Harmony has contributed to the creation of economic, social and ecological benefits for local mining communities. These benefits include job creation, land restoration to combat erosion as well as managing land contamination through phytoremediation. Resource utilised: biomass planted and harvested includes energy beet, sorghum and giant king grass. Type of hybridisation: the cultivated biomass is used to generate biogas in an anaerobic digestion process which is used to displace fuel oil in direct heating applications on the Harmony site. These applications include the company’s elution plants and carbon regeneration circuits. The digestate is used as fertilizer for the biomass crops. Cost: the cost for the implementation of the first phase of the project was R56 million. Maturity: converting organic material into biogas in anaerobic digesters is a well proven technology. However, this technology has not yet been widely applied in South Africa. Key issues: the use of old mining infrastructure refurbished as anaerobic digesters proved challenging and costly. Due to the relatively new application of this technology, ensuring the right balance of biomass in the feedstock to achieve sufficient biogas was learnt in-situ and thus escalated costs. Finally, as biogas is a growing industry in South Africa finding the right skills match and capabilities to take this project through to fruition also proved challenging. Success factors: biogas projects can make viable land use options as part of mining rehabilitation strategies. The availability of land, suited to energy crop production, was a key project success factor. By integrating this project with Harmony’s existing rehabilitation strategy it allowed for financial support through the company’s rehabilitation commitment as well as limiting initial labour costs. The biogas industry needs technologies that can be adapted to conditions in Africa. In this regard the use of locally manufactured materials, or as in the Harmony case, the refurbishment of existing infrastructure, is vital in lowering costs. Finally, using tailored crops can improve the biogas yield.

Figure 4-13: Onsite work on Harmony Biogas Project

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4.4.11 Heat and power produced by biogas at Riverside Piggery

The Riverside Piggery in Pretoria, Gauteng, installed a biogas treatment plant in 2015 that generates heat and power for use in the company’s operations. The process involves the capture and subsequent combustion of methane rich biogas that is produced by the reaction of organic waste material (produced at the piggery) in a covered, anaerobic lagoon. The waste water and digestate that arise from the process are used as fertiliser on the piggery’s premises.

Type of hybridisation: the biogas comprises two micro turbines, each with an installed capacity of 65 kW. The biogas plant supplies the Riverside Piggery with about 85 kW of electricity, which accounts for about two thirds of the piggery’s demand. The biogas volumes are such that the Riverside Piggery is considering commissioning a third micro turbine. The facility currently includes a gas storage unit which facilitates the generation of electricity at peak periods, if required. The exhaust heat from the biogas plant is further used to heat water (to between 80 and 85°C) for use in the operations. The water heating component includes a 25 m3 water storage vessel. Cost: the capital cost was approximately R7 million, with an expected payback period of four years. Maturity: the biogas plant uses high quality, tried and tested equipment. The technology is low maintenance and reliable. Key issues: the onerous, complex and high costs associated with complying with the required environmental regulations were noted as barriers to the implementation of the biogas project at the Riverside Piggery as well as the development of further such projects. Success factors: this distributed energy facility produces both heat and power from the Riverside Piggery biogas plant. Furthermore the plant provides dispatchable power, facilitated by the inclusion of a gas storage facility in the plant design. The use of high quality, tested technology is a notable success factor which, aided by the homogenous and reliable nature of the feedstock, has contributed to the consistent supply of heat and power. Critically, the cost of utilising the renewable biogas to generate heat and power required by the piggery’s operations is less than the cost of the ‘business as usual’ fuels (electricity supplies as well as liquid paraffin). The biogas facility therefore displaces the use of traditional fossil fuels. There is opportunity therefore to register the facility as a carbon credit project which has the potential to supply carbon credits to the upcoming carbon tax scheme in South Africa.

Figure 4-14: Covered anaerobic lagoon at the Riverside Piggery

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4.4.12 IBERT Biogas combined heat and power facility The Iskhus Bio4Gas Express Reactor Technologies (IBERT) project involves the treatment of biological waste at the Cavalier Abattoir through anaerobic digestion to produce methane (biogas) and organic fertilizer. The biogas is then processed in a combined heat and power plant to produce electricity and heat for use on site. The project started supplying the abattoir with electricity in April 2016 despite initial delays with project implementation as a result of site repositioning and change in subcontractors. The anaerobic digestion technology was designed by IBERT (Pty) Ltd. To date more than 3,000 tonnes of abattoir waste has been used as feedstock for the biodigester, producing 4.5 MWh of electricity for the abattoir. Type of hybridisation: grid electricity supply augmented with biogas generated electricity. Cost: the project has a financial asset base of R 14.3 million and the total project cost in April 2016 was R 23.8 million. Maturity: producing methane for electricity generation in bio-digesters is a well proven technology but remains an emerging industry in South Africa. Key issues: the project implementation was delayed due to site repositioning in accordance with the environmental impact assessment and performance issues with sub-contractors. After initial implementation, the project experienced issues with diluted organic material due to excessive water use in the abattoir, which reduced the amount of methane generated. The project experienced cash flow issues due to the withdrawal of an equity partner who had committed a significant amount of funds towards the project. As such the project investigated various other funders. Success factors: through training programmes and on-site transfer of technical skills related to biogas, the project is enhancing the biogas skills base in South Africa, further supporting the development of the industry. The project has played a key role with respect to increasing industry and regulatory awareness around biogas as well as providing regulatory input and sharing technical knowledge. In addition the project contributed towards the establishment of biogas safety valve production in South Africa to support local maintenance.

Figure 4-15: Ibert biogas anaerobic digester and combined heat and power facility

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4.4.13 Co-firing waste coffee grounds with coal for heating services In 1994, a multinational food producer in South Africa installed a direct co-fired biofuel and coal boiler. This custom design fluidised bed boiler was designed by the CSIR, supplied by John Thompson, and installed in Estcourt, KwaZulu Natal. The boiler is still operating successfully today. The system incinerates waste coffee grounds and coal in the same boiler. The waste coffee grounds are generated from the company’s own operations. The steam that results from the process is utilised for heating purposes in the food producer’s facility. Resource utilised: waste coffee grounds and coal Type of hybridisation: the fluidised bed combustion boiler was designed for co-firing and allowed the co-firing of 12 tonnes per hour of coffee grounds waste (at high moisture, containing 85% water) with approximately 2 tonnes per hour of coal. The coal is required to make the fuel “auto-thermal”. The system thus has an 86% renewable energy fuel and a 14% fossil fuel component. The system generates up to 26 tonnes of steam per hour.

Figure 4-16: Typical fluidised bed combustion system (Source: www.photomemorabilia.co.uk) Maturity: John Thompson boilers and fluidised bed combustion systems are mature technologies used in South Africa and around the world. There are currently around 3,000 John Thompson boilers in operation in South Africa. Key issues: the size of the co-firing facility was limited by the amount of biomass available at the facility. The high moisture content of the coffee grounds also reduced system efficiencies. As a result, the use of supplementary coal is required to meet the onsite steam demand. Success factors: extensive calculations and pilot-scale tests were undertaken to prove the practical application of the facility. A fluidised bed combustor was identified as the technology with the lower capital cost. This technology allowed the burning of coffee grounds in their wet state, which mitigated the need to dry the biomass feedstock. In addition, the system converts a waste stream to a valuable heating resource at no feedstock cost, and which also has lower associated emissions compared with the use of fossil fuel to generate heat.

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4.4.14 Co-firing with sustainable charcoal in Brazil’s steel sector Sustainable charcoal production is a renewable source of energy which, and if produced responsibly and sustainably, has the potential to reduce greenhouse gas emissions when supplementing fossil fuels in co-firing applications. Steel production is associated with high energy requirements and associated greenhouse gas emissions. In particular, the partial substitution of charcoal in place of metallurgical coke in small scale blast furnaces in Brazil’s steel production sector has reduced steel manufacturers’ greenhouse gas footprints. This type of hybridisation is most applicable to small scale blast furnaces and only allows for partial substitution of the fossil fuel. Type of hybridisation: co-firing of charcoal with metallurgical coke in small scale blast furnaces in the Brazilian steel sector, to produce pig iron. Maturity: blast furnaces are widely used internationally and are mature in nature. The use of charcoal in small scale blast furnaces may require refurbishment or retrofitting. However the co-firing of charcoal in larger scale blast furnaces, such as those in South Africa, is not as applicable as co-firing in small scale blast furnaces. Key issues: the potential for hybridising small scale blast furnaces through co-firing with charcoal is better than hybridising opportunities in larger scale blast furnaces, such as those available in South Africa. Other key issues relate to the availability of charcoal production applicable for co-firing in blast furnaces, the lack of technical expertise related to the metallurgical requirements when using charcoal, and the requirements for refurbishment or retrofitting. Gaps in policy planning and enforcement can be contributing factors to the growth for unsustainable deforestation practices (Nogueira et al, n.d). It is important that an effort is made for the development of well-managed eucalyptus plantations from which the charcoal is produced. In order to ensure a successful biomass based project it is imperative that the biomass is sourced sustainably from a well-managed plantation. Success factors: where there have been successes in Brazil’s steel sector, these have arisen where the production of charcoal (used for co-firing purposes) has been facilitated through well managed, legitimate and sustainable plantations. These plantations have been directly managed and are under the control of the multinational steel companies themselves. In 2012 the Brazilian Charcoal Sustainability Protocol was implemented, which saw the steel industry develop several activities to fulfil commitments to increase environmental sustainability in the country. One of the most important steel industry goals relates to the commitments to satisfy 100% of the sector’s charcoal demand through sustainably planted and well managed forests (largely Eucalyptus) (Steel Times, 2013).

Figure 4-17: ArcelorMittal BioEnergia Ltda’s eucalyptus plantation in Minas Gerais, Brazil. Photo: Carlos Euler

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4.4.15 Badplaas hydro pilot

Nepsa Energy initiated the Badplaas hydro power refurbishment project in 2009. Completed in 2013, the pilot facility entails the refurbishment of the original Gilkes turbine (153kW), which was installed in 1953 which had fallen into disrepair. All power generated is sold to the Forever Resort in Badplaas, South Africa, based on a long term power purchase agreement. The hydro power supplements the Resort’s electrical demand of 0.6 MW – 1.5MW, the balance of which is

drawn from the Eskom grid. The aim of the pilot was to showcase a working small hydro-electric plant which displaces a portion of the Resort’s grid electricity. Nepsa Energy subsequently sold the hydro-electric facility to MBB, a specialist hydro operational and maintenance company. Type of hybridisation: water from the Seekoei Spruit is used to generate electricity in the Badplaas run-of-river hydro electrical facility. Cost: the refurbishment cost was approximately R1.6 million. Most of the expenses incurred were related to development costs (such as hydrological assessments and legal consultants). Maturity: used in approximately 160 countries, hydropower is a mature technology (IEA-ETSAP and IRENA, 2015c). Key issues: Nepsa Energy’s experience reveals that economies of scale are particularly important in the development of hydro-electric projects. With a view that facilities under 5 MW are not likely to be financially feasible, unless they are refurbishment projects. The costs and complexities of regulatory compliance are other barriers which increase project risk, and therefore inhibit the development of small and micro facilities. The importance of a comprehensive hydrological assessment was noted, as inaccuracies in this regard can affect the technical specifications of the project as well as the financial feasibility. Success factors: the nature of the refurbishment was such that the pilot project did not need to apply for a water use licence. Such an application would likely have made the small scale pilot project economically unfeasible, as the requirements are complex and the related transactional costs would have been high compared with the project returns. In addition, the distributed energy facility was located on private property, which reduced administrative burdens and timeframes that are associated with complying with the Public Finance Management Act (required where state assets are utilised). The ability to sell all of the generated hydro power is another of the project’s success factors, augmented by the ability to sell the power at tariffs that are below the Eskom wholesale electricity price. Furthermore security of supply is enhanced by the presence of a dam upstream in the Seekoei Spruit, which stabilises the water flow compared with rivers that do not have supporting dams.

Figure 4-18: Refurbished Badplaas hydro turbine (photo source: Nepsa Energy)

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4.4.16 Electricity generation from methane at the Beatrix Gold Mine The Beatrix methane project demonstrates how biogenic sources of energy (preferably renewable in nature) can be successfully hybridised with fossil fuels. The Beatrix Gold Mine, owned by Sibanye-Stillwater, is located in Free State, South Africa. The mining activity releases underground methane, located in intersecting geological faults, which needs to be removed or diluted on account of its highly explosive nature. Boreholes were initially used to vent the underground methane to the surface, contributing to mine safety but also to global warming. Sibanye-Stillwater set about exploring opportunities to reduce the impacts in 2003. The methane-flaring component of the privately financed project was initiated in 2011 and electricity generation commenced in 2013. Resource utilised: methane present in geological faults is combusted to generate electricity. The underground gas concentrations tend to vary but methane typically accounts for over 80%.

Type of hybridisation: the underground methane is captured and combusted in two internal combustion engines (2 MWe total capacity). The electricity generated displaces the consumption of emissions-intensive grid electricity and accounts for about 1% of the mine’s electrical demand. Sibanye-Stillwater purchases the electricity from Aggreko (equipment owner). The use of waste energy to power absorption chillers was considered but excluded due to budget constraints.

Cost: the capital cost of the project for Sibanye-Stillwater was R32 million (in 2011). This figure was reduced from an initial capital cost of R76.1 million where Sibanye-Stillwater was considering purchasing the combustion engines for use in the project. The commercial arrangements were restructured and Aggreko owns, operates and maintains the methane power facility.

Maturity: the Beatrix project was the first and only project of this nature in South Africa. The maturity of the combustion engines is however well established and they are widely used.

Key issues: the time taken to develop the project (particularly to establish the methane availability) was extensive (eight years). Even so, the anticipated methane flow rates have not materialised, limiting the amount of electricity that may be generated in the combustion engines. The high capital costs, as well as the costs to register the project with the CDM, have reduced the project profitability, particularly in light of the unanticipated low prices for carbon.

Success factors: the privately financed distributed energy resource project was not subject to requirements of state contracts which can be lengthy and onerous in nature. The benefits for Sibanye-Stillwater extend beyond the mitigation of health and safety risks to the operational advantages associated with diversifying and improving the security of supply of electricity to the mine. In addition, the electricity from the Beatrix methane plant has lower associated emissions compared with the emissions that result from the use of grid electricity. The Beatrix methane project is registered with the CDM and is therefore eligible to trade the certified emission reductions.

Figure 4-19: Methane flaring point at Sibanye-Stillwater’s Beatrix mine (photo: Sibanye-Stillwater)

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4.4.17 Summary of key trends from case studies Globally there is a shift to increased uptake of renewable energy technologies (REN21, 2017b), with the growth of fossil fuel hybridisation with renewable energies forming part of this trend. The trend for hybrid systems point to the demand for decarbonised activities. These activities are increasingly distributed or decentralised (for example, the widespread rollout of small and micro solar PV around the world), (REN21, 2017b). However the uptake of pure renewable energy technologies outweighs that of hybridised systems. The research of hybridisation case studies in South Africa proved challenging. Information on hybridisation was harder to access compared with the literature available on purely renewable energy projects. The lack of information on hybrid installations may indicate a preference for new or pure renewable installations or projects of a lower complexity. However, it could also be due to the maturity level of the facilities which may limit the availability of information in the public domain or hesitation on the part of project implementers to share information, which could in some instances highlight inefficient energy consumption patterns. In addition, from the successful case studies discussed in this chapter and the unsuccessful case studies discussed in Chapter 3 it was found that there are almost as many unsuccessful hybridisation projects as successful ones. This points to both the complexities related to hybridising two technologies and the lack of supporting policy environment. In addition, many of these projects are “first-of-its-kind” type projects in South Africa (such as the Bio2Watt case study), which poses risks to companies, who may be more comfortable to remain with a fossil fuel technology that they know is reliable. The use of renewables to augment fossil fuel pathways in industrial applications is slowly increasing (as illustrated in the case studies relating to the Windhoek biogas project, Brazilian fuel switch in the steel sector and Australian wind-diesel on a remote mining operation). Similar trends are emerging in South Africa, where solar PV and waste to energy (bioenergy-based) applications tend to dominate. The rollout of small scale hydro has not proliferated, due to the comparatively high capital costs associated with the technology as well as the limited suitable locations available for implementation. The application of small scale hybrid wind to electricity facilities has also been similarly limited. While wind powered water pumping is well established in off grid situations. In South Africa, the last decade has been characterised not only by steep cost increases but also by high levels of insecurity regarding the supply of grid electricity. Unreliable supply has had negative impacts on industrial and commercial activities, which have been some of the drivers for companies moving towards hybridised systems to increase energy security. In addition, the technology learning of renewable energy technologies allows them to compete with fossil fuel technologies. This should continue to drive the implementation of hybridisation in the near future to prevent the stranding of fossil fuel assets. Hybridised systems brings with it both opportunities and risks. These risks are evident in the low penetration of hybrid systems in the energy market. Furthermore in some cases the markets are not well educated on the benefits of the particular intervention (for example solar heat in industrial processes).

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One of the key themes that has been identified in the case study analysis is the requirement for an enabling policy and regulatory environment. There are few incentives and subsidies available and the regulatory environment related to some areas (for example small scaled embedded generation and net metering) has been in development for a number of years. In the case of solar power, an enabling regulatory environment could include formalisation of net metering and the wheeling of power to different parties, within and outside of South Africa’s boundaries. This could increase the size and therefore the economic feasibility of business models linked to rooftop solar installations, which would benefit from the economies of scale and the additional revenue streams. However the associated risks related to the integration of distributed generators into the South African energy system (particularly the electricity segment) must be carefully considered, understood and mitigated in order to minimise electricity supply disruptions. Current investment into hybridisation is not only linked to energy security and cost reductions, but also to value of positive publicity for these types of projects. The value of understanding the drivers and best practices behind hybrid applications lies in the potential of these systems to facilitate South Africa’s transition to a lower carbon economy resulting in the reduction of the national greenhouse gas inventory. Fossil fuel value chains need an affordable transitional arrangement to reduce their carbon intensity and prevent stranded assets.

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5 Conclusions This study assesses the country’s fossil fuel value chains to identify and prioritise hybridisation opportunities with renewable energy technologies on a facility scale. Thermal, electrical, mechanical and mobility energy services across the energy transformation and energy demand fossil fuel value chains are assessed. Various renewable energies are assessed for their potential of hybridisation with fossil fuel technologies. The use of solar and bioenergy are the most dominant renewable energy resources for the provision of thermal and electrical energy services. The use of geothermal energy in the hybridisation technologies is found to be unfeasible to the South Africa case. The broad nature of this study requires a suite of hybridisation technologies for implementation depending on the type of interventions or levers available to government. Circumstances at a facility level require site specific solutions whereas national government investments are likely to focus on optimum solutions for public good across the country. Incentivising private investment requires facilitating the most cost-effective solution at the facility level, to ensure a sufficient return. For the provision of thermal energy services, the use of direct solar heating is the most promising solution for hybridising low temperature fossil fuel applications. These include water heating applications, pre-heating of boiler feed water for steam generation systems, heating and cooling processes, as well as drying processes. Through the techno economic review it is found that the installation of solar water pre-heating systems for boiler feed water is technically and financially feasible. A company can expect to reduce its fossil fuel consumption by 2% per year, and recover the capital investment in 5 years. Where there is the requirement for high energy output and a constant supply of thermal energy, hybridising with bioenergy based heating is more promising and suitable. Bioenergy can be used to achieve higher heating requirements (>100°C) as well as lower temperature heating. However, the use of bioenergy is site specific and not applicable throughout South Africa. Bioenergy for thermal applications is only viable under certain conditions. The conditions for viability include availability of the bioenergy resource on site or within a 20 km radius, and available at a low cost. Bioenergy can be in the form of crop based biomass and bioenergy from waste streams. The South African case studies have a predominance for bioenergy from waste streams, which were generated on site. These waste bioenergy resources come at no extra cost and thus can compete with the cheap fossil fuels. Where crop based bioenergy is used, it is required to be sustainably sourced to prevent degradation of ecosystems and prevent competition with other forms of land use. The provision of high temperature thermal energy services (>100°C) from solar resources, such as a concentrated solar thermal plant to augment steam generation in a coal fired boiler is currently not viable on an industrial scale. A price on carbon is necessary to create an incentive for investing in hybridisation of this type as a commercial project. This type of hybridisation is more applicable

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to large scale steam generation systems such as utility-scale coal fired power stations, where a payback of over 8 years can be expected. Electrical systems are the easiest to hybridise, with renewable electricity, as they typically do not require modifications to electrical equipment used to provide services. From the range of case studies considered there was a clear dominance for hybridisation for the provision of electricity compared with thermal applications. Due to the country’s good solar resources, and the technology learning seen in solar PV technologies, solar PV is the most promising technology for hybridising electricity generation in any sector. The levelised cost of electricity from solar PV is competitive with municipal tariffs in South Africa. However, a grid connection is required to compensate for variable electricity supply, when storage is either not available or is costly. Solar PV systems for electricity provision can replace about 20% of the electricity requirements of a commercial or industrial facility from the national grid, with payback periods ranging between 4 to 6 years. Bioenergy hybrid based electricity facilities are second to solar PV facilities. Bioenergy based electricity production for hybrid systems is more suitable for applications that require high power output at a constant supply. Specific conditions exist for this to be feasible, such as availability of onsite bioenergy which comes at no extra cost. Small scale wind energy and small scale hydro power are applicable to remote locations, where there is no connection to the national grid, or the extension and upgrading of the grid is costly. These applications are site specific and not applicable throughout South Africa. Small scale wind and hydro technologies have not proliferated in South Africa. This is due to the limited applicable locations of such renewable energy resources and the high capital costs for these technologies. When assessing mechanical energy services, hybridised water pumping using wind to supplement electrical water pumping is found to be economically viable at commercially low discount rates. This type of hybridisation is suitable for facilities with existing limitations to grid electricity access. The hybridisation of the mobility energy service through blending of biofuels for vehicles, ships, aviation and rail pose good opportunities to reduce transport related emissions. Blended fuels are however limited by factors such as vehicle engine specifications, commercial supply of biofuels, transportation challenges and mandatory blending limits. A strong policy framework is required to ensure food security and biodiversity are not compromised in the development of a sustainable biofuels market. Such a supporting policy and framework is required in order for this type of hybridisation to develop in South Africa. It is seen that information about hybridisation is harder to access compared with the literature available on purely renewable energy projects. The research further showed that there are almost as many unsuccessful hybridisation projects as successful ones. This could also be due to the maturity level of the facilities which may limit the availability of information in the public domain or hesitation on the part of project implementers to share information. Various key lessons and challenges are drawn from the hybrid case studies analysed. The key reasons for implementation of hybrid projects related to security of energy supply, positive publicity, sourcing of lower carbon alternatives, costs savings and the transformation of a waste stream into a resource. The challenges

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limiting the uptake of hybrid projects in the country relate to the high upfront investment cost required, lack of funding opportunities, low prices of fossil fuels, complexities with combining two technologies, lack of local technology support and regulatory barriers. Hybrid systems tend to entail an increased level of technical complexity compared with standalone renewable energy systems. Therefore, hybridised systems typically have a greater need for technical capability and training as these systems require skills and knowledge within multiple disciplines. Overall it is concluded that hybridisation allows for technology integration rather than technology exclusion in order to contribute to a sustainable transition away from a fossil-fuel based energy sector. Hybridisation is a key arrangement to efficiently transition to a lower carbon economy, whilst reducing the risks posed by climate change. Hybridisation of fossil fuel value chains with renewable energies can prevent the risk of stranded assets, once the cost of the renewable energy competes with the fossil fuel technologies. In addition, hybridisation is a mechanism to increase the uptake of renewable energy technologies in the country.

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6 Recommendations Policy support is required to ensure the roll out of energy hybridisation in South Africa and to stimulate implementation of renewable energy technologies. An incentive scheme for hybridisation projects, similar to section 12L and section 12J of the income tax act, is recommended to be further explored as a measure to incentivise hybridisation. It is suggested that government continue to broaden the regulations on Small Scale Embedded Generation, to provide further opportunity to stimulate the implementation of small scale hybrid systems beyond 1MW. Implementation of pending legislation, such as the South African carbon tax and carbon offset scheme will be a large driver in the implementation of facility level hybridisation projects, particularly where these pieces of legislation put a price on the externalities of fossil fuel use. It is recommended that a broader hybridisation research and implementation agenda be set. This may include consultation with stakeholders, defining research themes and identifying sources of funding under the green economy classification. This research programme can include the consideration of renewable energy hybridisation for individual and specific fossil fuel value chains in greater detail. Pilot projects, can form part of this programme and should be carried out in order to generate more detailed and accurate data, for evaluating the business case of specific hybridisation technology applications. Further investigations within such a programme should consider the use of energy storage in combination with a hybridised energy solution. The inclusion of energy storage solutions could further support the viability of hybridisation. Further research should also be carried out to assess hybridisation potential through the use of a portfolio of energies (as opposed to a single energy source as was the focus of this report). A mix of renewable energy sources and technologies that are hybridised to a fossil fuel technology may further improve flexibility, reducing supply risks and facilitate the transition towards a low carbon future.

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