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Last Updated: October 27, 2017
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Overview

South Africa has a large energy-intensive coal mining industry. The country has limited proved reserves of oil and natural gas and uses its large coal deposits to meet most of its energy needs, particularly in the electricity sector. South Africa also has a sophisticated synthetic fuels industry, producing gasoline and diesel fuels from the Secunda coal-to-liquids and Mossel Bay gas-to-liquids plants.

South Africa's energy sector is critical to its economy, as the country relies heavily on its large-scale, energy-intensive coal mining industry. South Africa has limited proved reserves of oil and natural gas and uses its large coal deposits to meet most of its energy needs, particularly in the electricity sector. Most of the oil consumed in the country, used mainly in the transportation sector, is imported from Middle Eastern and West African producers in the Organization of the Petroleum Exporting Countries (OPEC) and is locally refined. South Africa also has a sophisticated synthetic fuels industry, producing gasoline and diesel fuels from the Secunda coal-to-liquids (CTL) plant and the Mossel Bay gas-to-liquids (GTL) plant. The synthetic fuels industry accounts for nearly all of the country's domestically produced petroleum because crude oil production is very small.

South Africa’s economy has grown rapidly since the end of the apartheid era in 1994, and the country is now one of the most developed nations in Africa. South Africa has the second-largest economy in Africa, in terms of gross domestic product (GDP), and it has the highest energy consumption on the continent, accounting for about 28% of total primary energy consumption in Africa, according to BP Statistical Review of World Energy 2017.[1] Despite rapid economic growth over the past few decades, economic problems from the apartheid era remain, particularly poverty and the lack of economic participation among disadvantaged groups. The South African government has committed to ensuring that black-owned companies have access to energy and mining sector activities under its Black Economic Empowerment (BEE) program. In addition, the 2000 Petroleum and Liquid Fuels Chartersets a target to place 25% of the oil industry (across all facets) in the hands of black-controlled energy companies.

According to a 2015 study by the U.S. Energy Information Administration (EIA), South Africa holds the eighth-largest technically recoverable shale gas resources in the world (390 trillion cubic feet) primarily located in the Karoo basin. The South African government hopes that shale gas will provide the country with a reliable alternative fuel to coal. However, regulatory uncertainty and environmental concerns have delayed exploration. Some progress was recently made when the Petroleum Agency South Africa (PASA) announced that it would start processing existing applications for exploration permits in late 2017.[2]

In 2016, 70% of South Africa's total primary energy consumption came from coal, followed by oil (22%), natural gas (4%), nuclear (3%), and renewables (less than 2%), according to BP Statistical Review of World Energy 2017 (Figure 2).[3] South Africa's dependence on coal has led the country to become the leading carbon dioxide emitter, on a volumetric basis, in Africa (accounting for 35% of emissions in Africa) and the 14th-largest emitter in the world, according to the latest BP Statistical Review estimates.[4]

Figure 1. Map of South Africa

Map of South africa

Source: U.S. Department of State

Figure 2. Total primary energy consumption in South Africa, 2016

Energy sector management

PetroSA, a South African state-owned company, operates upstream oil and natural gas producing assets in South Africa, along with the GTL plant in Mossel Bay. Sasol, a privately owned company based in South Africa, operates the Secunda CTL plant, has a majority interest in the Natref oil refinery, partially owns the pipeline transporting natural gas from Mozambique to South Africa, and is involved in coal mining.

Regulatory organizations

South Africa has several government agencies and companies involved in the coal, natural gas, and oil sectors. The Petroleum Agency of South Africa (PASA) regulates oil and natural gas exploration and production and provides public data on those activities. The National Energy Regulator of South Africa (NERSA) regulates the electricity sector, natural gas pipeline industries, and petroleum pipeline industries. NERSA regulates electricity prices and promotes private sector participation by encouraging investment by independent power producers (IPPs) and off-grid technologies to meet rural energy needs. Eskom—the state-owned electricity company—generates about 90% of South Africa's electricity and owns and operates the national electricity grid.[5]

Major companies

South Africa's upstream oil and natural gas sectors are dominated by the state-owned company Petroleum Oil and Gas Corporation of South Africa (PetroSA), while the downstream oil sector is more diversified and includes companies from Europe, North America, and Asia. BP, Shell, Chevron, Total, and Engen are the main players in the downstream oil and petrochemical industry. PetroSA operates all upstream oil- and natural gas-producing assets in South Africa, along with the GTL plant at Mossel Bay. The company also participates in oil and natural gas activities internationally.

Sasol is another major player in South Africa's energy industry and operates Secunda, one of the world's largest coal-based synthetic fuels plant. The company holds majority interest in the 88,000 barrels per day (b/d) Natref refinery. Sasol is also involved in coal mining and marketing of natural gas and oil products. According to Sasol, the company mines 40 million metric tons (MMt) of marketable coal per year (mostly used at the Secunda CTL plant) and exports about 2.8 MMt per year. Sasol distributes and markets natural gas produced in Mozambique that is exported to South Africa via a pipeline partially owned by Sasol.[6]

Sasol has operations around the world, ranging from supplying petrochemicals to using its proprietary Fischer-Tropsch conversion technology to pursue opportunities to open GTL plants. Sasol has a 49% stake in Qatar’s Oryx GTL plant (Qatar Petroleum owns 51%) that came online in 2007. Sasol also has GTL projects in Nigeria and Uzbekistan. Sasol is also considering developing a GTL plant at Lake Charles, Louisiana, in the United States and a GTL plant in Alberta, Canada, although both projects are now on hold as a result of recent low oil prices.[7]

Major companies that participate is South Africa’s coal sector include Anglo American, BHP Billton, and Xstrata Coal. The South African-based, majority black-owned coal company Exxaro also ranks among the top producers. Coal mining in South Africa is mainly undertaken by privately owned companies, and the shareholders of Richards Bay, the country’s main coal port, are all private companies as well. The state-owned company Transnet controls the railways used to transport coal from the mines to the ports.

Coal

South Africa has the world's tenth-largest amount of recoverable coal reserves and holds 75% of Africa's total coal reserves. Coal consumption in South Africa is expected to continue to increase as new coal-fired power stations are scheduled to come online to meet rising demand for electricity.

South African proved coal reserves were estimated at 11 billion short tons at the end of 2016, the 10th-largest in the world, according to the BP Statistical Review of World Energy 2017. South Africa’s coal reserves accounted for 75% of those in Africa and 1% of total world reserves.[8]

South Africa's economy is heavily dependent on coal, as it accounts for about 70% of the country’s total primary energy consumption (Figure 2). The electricity sector accounts for more than half of the coal consumed in South Africa, followed by Sasol’s petrochemical industries, metallurgical industries, and domestic heating and cooking, according to Eskom.[9]

South Africa’s coal production and consumption levels have remained relatively stable over the past decade. In 2016, the country produced an estimated 277 million short tons (MMst) and consumed 191 MMst of coal (Figure 3).[10] Most of the coal produced comes from the Witbank, Highveld, and Ermelo coal fields, which are located in the eastern part of the country near Swaziland. South Africa has the potential to increase coal production, particularly from the resource-rich Waterberg basin in the northeastern area of the country. One of the main bottlenecks to increasing coal exports is the lack of railway infrastructure used to transport coal from the inland mines to the ports. Transnet, South Africa’s railway operator, is investing billions of dollars to expand railway infrastructure over the next few years. Several railway projects are slated to be commissioned by 2021, which should facilitate transporting coal to export facilities and demand centers within South Africa.[11] However, weaker global coal demand, lower international coal prices over the past few years, and some regulatory uncertainties have delayed investments in these mine projects.[12]

Some of South Africa’s mining projects are allocated to domestic electricity generation versus coal exports. South Africa’s electricity consumption is increasing, and coal production will be needed to fuel new power plants that are currently under construction. Coal use—especially by Eskom and Sasol—is expected to rise over the next few years.[13] Eskom is expanding its coal-fired electricity capacity to meet growing demand by bringing online coal-fired power plants—Medupi (4,764 megawatts (MW) and Kusile (4,800 MW)—in stages by 2022. Two units of the Medupi power plant and the first unit of the Kusile plant (collectively 2,388 MW of capacity) were operational by September 2017.[14] However, coal consumption in the power sector is expected to face competition from natural gas and renewable energy in the next few years.

Figure 3. Total primary coal production and consumption in South Africa

Coal-to-liquids (CTL)

South Africa produces synthetic fuels from low-grade coal and a small amount from natural gas. At the Sasol synfuels plant in Secunda, more than 37 MMst of coal each year are converted into liquid fuels and a range of chemical feedstock. The plant houses two factories with a total capacity of 160,000 b/d of oil equivalent.[15} Sasol proposed an expansion of Secunda's capacity and construction of another CTL facility, although these projects have been postponed until it has a provision for carbon capture at these facilities.[16]

Exports

South Africa exports about 30% of its coal production and is the fifth-largest global coal exporter. Most of South Africa’s coal exports are sent to Asia, with India being the largest recipient.

South Africa exported about 30% of its coal production (85 MMst in 2016), making it the world’s fifth-largest global coal exporter. Asia received nearly two-thirds of South Africa’s coal shipments, with the largest destination being India, which accounted for nearly half of South Africa’s coal exports (Figure 4).[17] Europe is the second-largest regional importer of South Africa’s coal, followed by the rest of Africa, the Middle East, and the Americas. South African exports have shifted to India and South Asia and away from Europe and China over the past several years.

About 95% of South Africa’s coal is exported via the Richards Bay Coal Terminal (RBCT), and the remainder is exported via the Maputo and Durban terminals.[18] RBCT is located on the eastern coast of South Africa and is one of the world's largest coal export terminals. It began operation with a design capacity of 13 MMst per year in 1976, and it has since gone through several capacity expansions, increasing the export terminal's design capacity to its current level of 100 MMst per year.[19] There are proposals to expand RBCT’s capacity to 121 MMst per year. These plans have been delayed because the terminal still operates below its capacity as a result of inadequate rail capacity needed to transport coal produced at inland coal fields to the RBCT.[20] However, progress has been made over the past few years to increase the terminal’s throughput volumes. In 2015, the RBCT exported more than 83 MMst of coal for the first time before declining to 80 MMst in 2016 (Table 1). Even though exports to Asia and Africa rose in 2016, coal shipments to Europe were weak in 2016, driving down overall exports from RBCT.[21]

Table 1. Richards Bay coal terminal shipping statisticsmillion metric tonsYearCoal shipped201172.2201275.3201377.4201478.6201583.1201680.0Source: Richards Bay Coal Terminal, Reuters

Figure 4. South Africa's coal exports, by destination, 2016

Natural gas

South Africa imports natural gas from Mozambique via pipeline to supply Sasol's Secunda synfuel plant and to fuel natural gas-fired power plants. South Africa produces a small volume of natural gas offshore, which is mainly used to supply the Mossel Bay GTL plant.

In 2016, South Africa produced about 40 billion cubic feet (Bcf) of dry natural gas and consumed nearly 180 Bcf; the difference of 140 Bcf was imported from Mozambique via pipeline (Figure 5). South Africa has very limited proved natural gas reserves but potentially large shale gas resources. Most of South Africa’s natural gas is produced from the maturing offshore F-A field and South Coast Complex fields and sent to the GTL facility in Mossel Bay via an offshore pipeline.

PetroSA intended to develop the F-O field, also known as Project Ikhwezi, to sustain natural gas supplies to the GTL facility, although field reserves and production potential have been severely overestimated by the state company.[22] The company plans to tap into nearby prospective areas, such as the E-BK Project, to continue natural gas flows to the GTL plant.[23] One of the most viable opportunities for offshore field development is the Ibhubesi natural gas field, owned by a joint venture of the South African firms Sunbird (the field operator) and PetroSA. The Ibhubesi field holds at least 540 Bcf of recoverable reserves. The field developers aim to finalize a natural gas supply agreement with South Africa’s state-owned electricity firm, Eskom, in 2017 and to begin production by 2020 to replace some of the country’s diesel-fired power.[24] Sunbird received the environmental authorization for the Ibhubesi natural gas project in August 2017.[25]

The government aims for new natural gas production from offshore conventional fields, onshore shale gas developments, regional imports from Mozambique, and potential liquefied natural gas (LNG) imports to reduce the country's reliance on coal in the electricity and industrial sector in the long term. Currently, infrastructure constraints limit the role of natural gas in the country's electricity sector.

South Africa created a new natural gas plan that includes constructing several natural gas-fired power plants and at least two LNG regasification terminals by 2025. South Africa’s Department of Energy has proposed building nearly 290 Bcf/y of capacity from two floating LNG import terminals on the eastern side at Richards Bay and the southeastern coast at Port Coega. South Africa reported that it plans to move forward with the bidding process for the facilities in late 2017 and to begin importing LNG by 2020. PetroSA has also considered building a floating regasification facility to supply the Mossel Bay GTL plant in the future.[26]

Figure 5. South Africa's natural gas production and consumption

Shale gas resources

EIA estimates that South Africa holds 390 trillion cubic feet of technically recoverable shale gas resources. Environmental concerns led the government to place a moratorium on shale gas exploration from April 2011 to September 2012. Recently, South Africa’s government has started to process pending applications for shale exploration permits.

According to a June 2013 report released by EIA, South Africa has 390 trillion cubic feet (Tcf) of technically recoverable shale gas resources, making the country the eighth-largest holder of technically recoverable shale gas resources in the world. Technically recoverable resources represent the volumes of oil and natural gas that could be produced with current technology, regardless of oil and natural gas prices and production costs.[27]

South Africa’s shale gas resources are located in the Karoo basin in the Whitehill (211 Tcf), Prince Albert (96 Tcf), and Collingham (82 Tcf) formations. EIA lowered its estimate from 485 Tcf to 390 Tcf in the most recent report because the prospective area for the three shale formations in the Karoo basin was reduced by 15%. The Whitehill Shale’s recovery rate and resource estimates were also reduced because of the geologic complexity, according to the report.

Environmental concerns regarding water usage and hydraulic fracturing, one of the processes used to facilitate the extraction of shale gas, led the government to enact a moratorium in April 2011 on issuing exploration licenses for shale gas exploration. The moratorium was lifted in September 2012 after a government-funded study recommended that it was safe to continue shale gas exploration. In June 2015, South Africa’s Minister of Mineral Resources enacted technical regulations to govern petroleum exploration, particularly standards for shale gas exploration and hydraulic fracturing. These regulations balance the economic opportunity of shale gas development to improve the country’s energy security against environmental concerns.[28] South Africa approved shale gas development in the Karoo basin in early 2017. However, the government’s regulations were contested and declared invalid by the Eastern Cape’s High Court.[30] Petroleum Agency South Africa (PASA) had announced it would start processing existing applications for exploration permits in late 2017, although drilling for shale gas could face delays.[31]

Gas-to-liquids (GTL)

The GTL plant at Mossel Bay was commissioned in 1992 and is one of the largest in the world. PetroSA operates the plant, in addition to the offshore gas fields that provide the fuel. The plant has the capacity to process 45,000 b/d of liquid fuels through a Fischer-Tropsch Process, where natural gas is converted to synthetic liquid fuels. The plant produces several synthetic liquid fuels, of which more than half is unleaded petrol (motor gasoline) and the remainder includes: paraffin (kerosene), diesel, propane, liquid oxygen and nitrogen, distillates, eco-fuels, process oils, and alcohols.[32]

The Mossel Bay GTL refinery has operated well below its nameplate capacity for several years and produced less than 22,000 b/d in 2016 because of insufficient natural gas supplies.[33] As a medium-term solution to keeping the GTL plant operating, PetroSA installed a condensate splitter in 2016 and can process about 18,000 b/d of heavy liquid condensates in addition to natural gas.[34]

Natural gas pipelines

Natural gas from Mozambique is imported through a 535-mile pipeline and transported to Sasol's Secunda synfuels plant. Sasol, the South African government, and the government of Mozambique own the pipeline through a joint venture, ROMPCO (the Republic of Mozambique Pipeline Investments Company).[35] The pipeline has a peak capacity of 550 million cubic feet per day of natural gas and was part of a $1.2 billion natural gas project started in 2004.[36] The pipeline has expanded its capacity in recent years to accommodate growing natural gas markets in both Mozambique and South Africa.

Two proposals are pending for a natural gas pipeline that would run from Mozambique’s Rovuma basin in its northeastern province Cabo Delgado to demand centers in South Africa. SacOil Holdings, a South Africa-based oil and natural gas company; the Mozambican national oil company; a consortium of Mozambican private sector companies; and China National Petroleum Corporation’s (CNPC’s) subsidiary, China Petroleum Pipeline Bureau (CPP), signed a cooperation agreement in March 2016 and are studying the possibility of constructing the $6 billion, 1,615-mile African Renaissance Pipeline. CPP would provide 70% of the funding from Chinese financial firms. The second project is the Gasnosu Pipeline, proposed by the Mozambican state oil company and South African firm, Gigajoule, and supported by South African utility Eskom.[37] Several significant gas discoveries have been made in Mozambique’s northeastern Rovuma Basin over the past few years. South Africa is a viable market for Mozambique’s future production given South Africa’s limited proved gas reserves and its need to sustain production at its GTL plant. However, both proposed pipelines involve long distances and high capital costs, current LNG regasification proposals are likely to be more economically competitive in the near term.

Petroleum and other liquids

South Africa has small amounts of proved crude oil reserves, and the country’s crude oil production is very small. Synthetic fuels, derived from coal and natural gas, account for about 86% of the country's domestic petroleum liquids production.

According to the Oil & Gas Journal, South Africa has proved crude oil reserves of 15 million barrels.[38] All of the proved reserves are located offshore in southern South Africa in the Bredasdorp Basin and off the west coast of the country near the maritime border with Namibia. South Africa's petroleum and other liquids (total oil) production was about 134,000 barrels per day (b/d) in 2016 (Figure 6). Synthetic fuels, derived from coal and natural gas, accounted for about 86% of the country’s domestic petroleum supply. Less than 5,000 b/d of crude oil and lease condensate is produced at the Oribi and Oryz fields operated by PetroSA. The country's crude oil and lease condensate production continues to decline as oil fields mature and as no commercially viable discoveries have been made. Refining gains accounted for about 10% of domestic petroleum liquids supplies.

South Africa's deepwater offshore Orange Basin near Namibia is believed to hold substantial oil and natural gas resources, although limited exploration activity has occurred in the area. In 2009, Shell acquired exploration rights over a large block in the basin. Shell obtained an environmental authorization for exploration drilling in 2015. However, the company is years away from potentially producing any commercial reserves.[39]

Figure 6. Petroleum and other liquids production and consumption in South Africa

Downstream

South Africa consumes the second-largest amount of petroleum in Africa, behind Egypt. The petroleum consumed in South Africa comes mostly from its domestic refineries that import crude oil and its CTL and GTL plants. South Africa imports crude oil mostly from OPEC countries in the Middle East and West Africa.

EIA estimates that South Africa’s petroleum consumption was 691,000 b/d in 2016. The petroleum products consumed in South Africa come mostly from its domestic refineries that import crude oil and its CTL and GTL plants. The country also imports an increasing amount of petroleum products because overall oil consumption continues to rise. In 2016, South Africa imported an estimated 155,000 b/d of petroleum products, mostly from Asia and the Middle East, according to Global Trade Tracker (GTT).[40]

The South African government is considering a policy to encourage greater use of liquefied petroleum gas (LPG) in the residential, commercial, and industrial sectors to diversify fuel sources and provide low-income households with more affordable and cleaner-burning fuels.[41] A few LPG processing and storage facilities are set to come online in Saldanha Bay and Richards Bay during the next few years to meet the country’s rising demand for this product.[42]

Refining

South Africa has the second-largest crude oil distillation capacity in Africa at 493,000 b/d, surpassed only by Egypt, according to the OGJ January 2017 estimates (Table 2).[43] The government has proposed plans to implement new, tighter fuel standards that would require upgrades at all refineries. However, because of low returns on investment, refinery operators have yet to upgrade their facilities. The new fuel standards will raise refiners' operational costs. The government’s initial deadline to upgrade the refineries was July 2017, but this target has been delayed indefinitely.

South Africa imports oil products to make up for the country’s widening supply shortfall. South Africa’s Department of Energy and the South African Petroleum Industry Association (SAPIA) have been discussing a cost-recovery program for the refineries since 2015.[44]

PetroSA and Chinese national oil company, Sinopec, considered building a new refinery in 2012, but they canceled the project based on high capital cost. In March 2017, Sinopec announced that it plannned to purchase a 75% share in Chevron’s refinery in Cape Town. The Chinese national oil company was in discussions with the South African government, whose main concern is to continue operations and upgrade the refinery to meet the new fuel standards.[45] However, the minority stakeholder of Chevron’s downstream assets in South Africa prevented the acquisition deal from moving forward. Swiss—based oil trading company, Glencore, then decided to acquire these assets in October 2017, although the bid is under review.[46]

Crude oil imports

In 2016, South Africa imported 416,000 b/d of crude oil, according to GTT data. South Africa imports crude oil mostly from OPEC countries, namely Saudi Arabia (38%), Nigeria (29%), and Angola (19%) (Figure 7).

South Africa’s top oil supplier has shifted from Iran to Saudi Arabia in recent years. In 2011, Iran was South Africa’s largest crude oil supplier, accounting for about 27% of South Africa’s total crude oil imports.[47] But in 2012, South Africa's crude oil imports from Iran dropped because of U.S. and European Union (EU) sanctions against Iran. U.S. sanctions, directed toward foreign financial institutions that facilitate oil-related transactions with the Central Bank of Iran, entered into full force in July 2012. To avoid the sanctions, Iranian crude oil importers had to show or pledge significant reductions in their Iranian crude oil purchases to receive a 180-day renewable exemption. South Africa halted Iranian crude oil imports before the July 2012 deadline and was granted exemptions. South Africa has not resumed imports from Iran despite the sanctions on Iran being lifted in 2016. The country continues to substitute Iranian imports with supplies from Saudi Arabia, Nigeria, Angola, and other countries.

Table 2. South African crude oil refinery capacityRefineryCompanyLocationCapacity (b/d)SaprefShell and BP PLC PetroleumDurban170,000EnrefEngen PetroleumDurban135,000ChevrefSinopec (formerly owned by Chevron)Cape Town100,000NatrefNational Petroleum Refiners of South AfricaSasolburg88,000Total 493,000Source: Oil & Gas Journal, January 2017

Figure 7. South Africa's crude oil and condensate imports, by country of origin, 2016

Electricity

After experiencing chronic power shortages for several years, in 2016, South Africa had a power capacity surplus as a result of new capacity commissioned by both public and private sectors and of weaker electricity demand. South Africa intends to diversify its electricity generation portfolio to include cleaner-burning fuels such as natural gas and renewable energy.

South Africa’s electricity generation has declined overall from 2007 to 2016 by more than 4% as a result of economic weakness, downward pressures on commodity markets, inadequate fuel supply and capacity to meet demand, and rising electricity costs. Gross electricity generation was around 250 Terawatthours (TWh) in 2015 and 2016.[48]

Eskom supplies approximately 90% of South Africa’s electricity, and the remainder comes from independent power producers (IPPs) and imports.[49] South Africa is a member of the Southern African Power Pool (SAPP), which began in 1996 as the first formal international power pool in Africa, with a mission to provide reliable and economical electricity supply to consumers in SAPP-member countries. Eskom exports electricity to Lesotho, Namibia, Botswana, Zimbabwe, Mozambique, Swaziland, and Zambia, and it imports electricity from Lesotho, Mozambique, Zambia, and Zimbabwe.[50]

South Africa’s installed electricity capacity was about 53 gigawatts (GW) in September 2017, although total net maximum capacity (installed capacity minus the amount the power station uses to operate) is lower. Of this capacity, 76% of South Africa’s installed electricity capacity is coal-fired, 7% petroleum liquids- or natural gas-fired at open-cycle plants, 7% hydroelectric, 4% nuclear, and 6% from nonhydro renewable energy (Table 3).[51] South Africa plans to diversify its electricity generation mix to ensure greater energy security and reduce its environmental emissions.

South Africa has struggled with a constrained electricity system over the past decade because the margin between peak demand and available electricity supply was extremely narrow. Reserve margins were low because of aging coal-fired power plants, insufficient investment in power infrastructure, and mismanagement of the sector. Load shedding (scheduled power cuts) during peak demand periods occurred frequently between 2013 and 2015, and the lack of electricity security has negatively affected the country’s industries and economic growth. However, at close to 90%, South Africa still had one of the highest electrification rates in Africa as of 2016.[52] South Africa intends to provide electricity access to all households by 2030.[53]

In response to chronic power shortages and the need to ensure a more diverse fuel supply, South Africa began a procurement program in 2011 to purchase power from renewable sources and lower-emitting energy plants funded by IPPs. This program has added 5 GW of generation capacity to the grid, mostly from facilities fueled by wind, solar, and natural gas. South Africa’s capacity target from IPP procurement is 29 GW by 2025.[54]

In 2015, South Africa’s Department of Energy released a natural gas plan to develop the country’s natural gas infrastructure and to meet increasing demand with future LNG imports and indigenous production. Underlying the plan is the construction of 3.7 GW of new natural gas-fired capacity through the IPP program by 2025. Most of the capacity is expected to be sourced from LNG. The government expects to issue a request for proposal for companies to bid on development of LNG and associated natural gas-fired power plants by 2018.[55]

South Africa’s renewable energy industry is small, but the country has expanded its renewable electricity capacity through the IPP Procurement Program. IPPs added 3.3 GW of renewable capacity to the grid between 2011 and early 2017. Eskom also completed its new Ingula hydroelectric facility with 1.3 GW of capacity in 2017.[56] As part of its Integrated Energy Plan, South Africa aims to commission 17.8 GW of renewable energy capacity by 2030, in line with its overall goal to lower carbon emissions and to diversify the fuels portfolio for power generation.[57]

Eskom is also increasing its own production capacity by building more efficient coal-fired units and converting some diesel-fired power stations to more efficient natural gas-fired combined-cycle units. Eskom is developing the country’s first massive supercritical coal-fired power plants—Medupi and Kusile—with a combined installed capacity of nearly 10 GW from 12 units. The plants are coming online in stages. The Medupi plant has brought two units online, and the Kusile facility has brought one unit online (combined 2.4 GW of installed capacity) since 2015. The other units of these two plants are slated to be online by 2022. Although the government has discussed decommissioning several of its old coal-fired units as new plants come online, Eskom plans to study each facility to determine the best course of action.[58]

Recent plant additions have resulted in a surplus power capacity in South Africa. Overall plant availability was back up to 77% from lows of about 70% in 2015. The government aims to improve plant maintenance and raise the electricity availability factor to 80% by 2020.[59]

Table 3. South Africa's power stations and installed capacity [1] (unit: megawatts)Coal-fired plants Hydroelectricity   Arnot2,352Conventional hydro stations   Camden1.561   Gariep360   Duvha3,600   Vanderkloof240   Grootvelei1,180Pumped storage schemes   Hendrina1,893   Drakensberg1,000   Kendal4,116   Palmiet400   Komati990  Ingula1,332   Kriel3,000Other hydropower stations   Lethabo3,708   Colley Wobbles42   Majuba4,110   Second Falls11   Matimba3,990   First Falls6   Matla3,600   Ncora2   Tutuka3,654Other renewable energy stations   Medupi (operational)1,588   Sere Wind Facility100   Kusile (operational)800     Gas/liquid turbine stationsNuclearAcacia171  Koeberg1,940Port Rex171  Ankerlig1,338  Gourikwa746  Independent Power Producers (IPPs) [2]5,027Total installed capacity (existing)53,028Eskom planned capacity additions (Medupi and Kusile)7,176[1] The table provides installed capacity, which is higher than the country's actual total net maximum capacity.[2] Capacity among IPP-owned power stations represents total installed capacity owned by independent companies. All other power plants in the table are owned by Eskom, South Africa's state-owned utility company.Source: Eskom Integrated Report, March 2017; Eskom media reports.

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Is The Saudi - Russia Oil Bromance Souring?

There are things brewing within OPEC. At a meeting in Baku, Azerbaijan last week – which was meant to set the stage for a formal meeting in April to review the current supply deal among the 24-country OPEC+ block – the conclusion of the meeting was that the April meeting would be deferred. The review will now take place at OPEC’s regular meeting in Vienna in June, which is mere days before the current supply deal is scheduled to end. That’s cutting it close, but more interesting for market observers is that it points to the Saudi Arabia-Russia bromance souring.

Prior to the meeting, Saudi Arabia had gone on record to state that the Kingdom believed that OPEC’s job in rebalancing the oil market was far from over and that output cuts were necessary to continue into the second half of 2019. Defying US President Donald Trump’s Twitter tantrums – especially with the Kingdom implicated in the assassination of Saudi dissident Jamal Khashoggi – Saudi Arabia is firmly behind continuing restricted supply. In the past, Saudi Arabia would most likely to be able to bully its way into an OPEC consensus. But now, it has to deal with an equally powerful 20-ton gorilla in the same room: Russia.

The success of the OPEC+ club over the past two years has been down to this close relationship between the world’s two largest oil producers. This had allowed crude prices to recover from sub-US$50/b levels. But the latest meeting is also the latest sign that all may not be well in the friendship. First, a joint Saudi-Russia meeting at the World Economic Forum in Davos was called off. Second, February data showed that while Saudi Arabia and its allies were doing far more than necessary to cut their crude production, Russia was shuffling its feet with less than 50% adherence, claiming that it needed more time to implement the cuts. And last week, despite Saudi Arabia lobbying for an extension to the cuts and general backing from members including Iraq, Russian Energy Minister Alexander Novak was in opposition. The official reason was that OPEC+ would need clarity on market situation before planning the next move, given the disruption brought about by ongoing and developing American sanctions on Iran and Venezuela. In the absence of necessity, the two crude powerhouses have drifted back to their default positions: Saudi Arabia’s aggression and Russia’s conservatism.

So while the world waits and watches for OPEC+’s next move, the market is analysing the potential impact of a strained Saudi-Russia relationship. But necessity might bring the two back together again, since they now face a common foe – rising US crude production. OPEC’s secretary general recently met with key executives in the US shale oil industry. This was billed as a ‘friendly conversation on current industry trends’ and interpreted as an attempt to cajole American shale producers in a mutually-beneficial stabilisation of the market. It is ridiculously unlikely for the US to ever join the OPEC+ club, but if the move could convince US shale firms to temper their expansion to prevent global oversupply, it might be worth it. Because OPEC has accompanied the olive branch with a threat – if OPEC does all the work to stabilise markets only to have American shale take advantage of the situation, it could very well reverse its stance and turn the OPEC tap on full to swamp the market once again. It’s a classic example of game theory, and one to watch as the power dynamics of global oil continue to change.

Key upcoming dates for OPEC: 

  • April 2019 – Review of January supply deal cancelled
  • May 2019 – USA to decide on waiver extension for Iranian crude imports
  • June 25, 2019 – OPEC meets in Vienna, supply deal review to be discussed
  • June 30, 2019 – OPEC+ January supply deal expires
March, 26 2019
Your Weekly Update: 18 - 22 March 2019

Market Watch

Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b

  • Global crude oil prices slipped at the start of the week, as OPEC and its OPEC+ allies met in Azerbaijan to discuss the state of the club’s oil output cuts
  • Crude oil prices had risen prior as on speculation that the OPEC+ group would extend its supply deal, but this was dashed when OPEC+ instead decided to defer a decision until June, scrapping a planned OPEC extraordinary meeting in April because it was ‘too soon to make a decision on extending oil-supply cuts’
  • Observed friction between Russia and Saudi Arabia over the cuts could be behind the delay; Saudi Energy Minister Khalid al-Falih is said to be in favour of continue supply reduction through 2019 while his Russian counterpart Alexander Novak said that uncertainty over Venezuela and Iran would ‘make it difficult’ to decide until May or June
  • Other OPEC members have also not expressed any more willingness to extend the cuts, and Saudi Arabia seems to be unusually focused on a united front, rather than strong-arming the rest of the gang to its own aims
  • Some reprieve could be coming for OPEC, as the US Energy Information Administration trimmed its 2019 output forecast by 110,000 b/d to 12.3 mmb/d, seeing a scale-back in smaller shale plays and the US Gulf of Mexico
  • Echoing this, the US active rig count declined for a fourth consecutive week, following up a 9 and 11 rig drop with the net loss of a single oil rig
  • A better prognosis on demand leading into the northern summer and faith that OPEC+ will continue to work towards preventing a major crude surplus from returning should keep crude prices trending higher. We are looking at a range of US$66-68/b for Brent and US$58-60/b for WTI

Headlines of the week

Upstream

  • Eni has announced a major oil discovery in Angola’s Block 15/06, with the Agogo prospect joining the Kalimba and Afoxé discoveries, adding some 450-650 million barrels of light oil in place to the block
  • ExxonMobil has delayed its US$1.9 billion, 75,000 b/d Aspen oil project as Canada’s Alberta province continues to grapple with the pipeline bottleneck that has caused a glut of production trapped in the inland province
  • Lukoil had hit a new milestone with the Vladimir Filanovsky field, which has now reached 10 million tons of crude oil supplied through the Caspian Pipeline Consortium (CPC) system, transporting oil to the Black Sea for transport
  • ExxonMobil is looking to reduce field costs in its Permian Basin assets to about US$15/b, a highly-competitive target usually only seen in the Middle East
  • Eni and Qatar Petroleum have agreed to a farm-out agreement that will allow QP to take a 25.5% interest in Mozambique’s Block A5-A, joining other partners Sasol (25.5%) and Empresa Nacional de Hidrocarbonetos (15%)
  • Successive industrial action strikes have begun in the UK, affecting the Shetland Gas Plant and Total Alwyn, Dunbar and Elgin platforms in the North Sea
  • ADNOC has begun planning for an output drive at its Umm Shaif field, which would increase output at the giant field to 360,000 b/d

Midstream & Downstream

  • Shell is planning to restart the Wilhelmshaven refinery in Germany through a deal with terminal firm HES, which will re-convert the existing tank farm into a 260 kb/d refinery that will focus on producing IMO-mandated low sulfur fuels
  • Petronas is offering first oil products cargos from its 300 kb/d RAPID refinery in April, ahead of planned full commercial production in October 2019
  • Lukoil is now planning to invest some US$60 million in its 320 kb/d ISAB refinery in Augusta, Italy to produce high-quality, low-sulfur fuels to meet IMO standards, instead of selling it as previously considered in 2017
  • The Ugandan government has approved the technical proposal for the country’s first refinery in Kabaale, which will run on crude from the Albertine rift basin
  • Kenya expects to have the Lamu crude export terminal operational by the end of 2019, syncing with the start of Tullow Oil’s Kenyan oilfields

Natural Gas/LNG

  • The UK Onshore Oil and Gas body has published updated figures for UK onshore shale potential based on three test sites in north England, estimating that productivity could be at 5.5 bcf per well leading to annual gas production reaching 1.4 tcf by the early 2030s
  • Eni’s winning streak in Egypt continues, announcing a new gas discovery in the Nour 1 New Field Wildcat, which join its existing assets under evaluation there
  • Conrad Petroleum’s development plan for the Mako gas field in Indonesia has been approved by Indonesian authorities, paving way for development to start on the field with its estimated 276 bcf of recoverable resources
  • Ventures Global LNG is planning to double the capacity of its LNG projects – including the Calcasieu Pass and Plaquemines LNG sites in Louisiana – from 30 mtpa to a new 60 mtpa, having already booked all output from Calcasieu
  • Darwin LNG is set to choose the source of its backfill gas by the end of 2019, with the Barossa field more likely to be taken than the Evans Shoal field
March, 22 2019
Technology may be a game changer for future oil supply

Risk and reward – improving recovery rates versus exploration

A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.

How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.

1. Reserve growth

An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.

2. pre-drill tight oil inventory and conventional pre-FID projects

They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve. 


3. Contingent resource


These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.

4. Yet-to-find

Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.

Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.

But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.

To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).

Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.

Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.

If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects. 


Global oil supply through 2040 


March, 22 2019