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. 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.
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). 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.
Figure 1. Map of South Africa
Source: U.S. Department of State
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.
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.
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.
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.
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.
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.
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). 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. 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.
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. 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. However, coal consumption in the power sector is expected to face competition from natural gas and renewable energy in the next few years.
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.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). 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. 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. 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. 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.Table 1. Richards Bay coal terminal shipping statisticsmillion metric tonsYearCoal shipped201172.2201275.3201377.4201478.6201583.1201680.0Source: Richards Bay Coal Terminal, Reuters
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. The company plans to tap into nearby prospective areas, such as the E-BK Project, to continue natural gas flows to the GTL plant. 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. Sunbird received the environmental authorization for the Ibhubesi natural gas project in August 2017.
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.
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.
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. 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. 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.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.
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. 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.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). 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. 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. 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. 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.
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).
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. 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.
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). 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.
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. 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.
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. 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
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.
Eskom supplies approximately 90% of South Africa’s electricity, and the remainder comes from independent power producers (IPPs) and imports. 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.
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). 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. South Africa intends to provide electricity access to all households by 2030.
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.
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.
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. 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.
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.
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.Table 3. South Africa's power stations and installed capacity  (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) 5,027Total installed capacity (existing)53,028Eskom planned capacity additions (Medupi and Kusile)7,176 The table provides installed capacity, which is higher than the country's actual total net maximum capacity. 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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The U.S. Energy Information Administration (EIA) estimates that during May 2019, Saudi Arabia’s crude oil production approached a four-year low, averaging an estimated 9.9 million barrels per day (b/d). Production declined more than 1 million b/d since its estimated all-time high production levels in October and November 2018 (Figure 1). Although the country’s total crude oil exports are also lower than recent highs, its crude oil exports to some Asia Pacific countries actually increased during the period of declining production. China in particular has increased its crude oil imports from Saudi Arabia, which is partially a result of new Chinese refining capacity. In contrast, U.S. crude oil imports from Saudi Arabia reached a 31-year low in February, with weekly estimates for April, May, and June suggesting even further declines.
Four Asia Pacific countries that publish crude oil imports by country of origin—China, Japan, South Korea, and Taiwan—collectively imported an average of 3.5 million b/d of crude oil from Saudi Arabia in 2018 (Figure 2). Chinese and Japanese 2019 year-to-date crude oil imports from Saudi Arabia are higher than their 2018 annual averages, whereas Taiwan’s are flat and South Korea’s have declined slightly. China’s crude oil imports from Saudi Arabia, in particular, have increased by 0.4 million b/d year-to-date through April compared with the 2018 annual average, significantly higher than Japan’s increase of less than 0.1 million b/d.
In contrast, U.S. crude oil imports from Saudi Arabia have declined year-to-date through March 2019 compared with the 2018 average by more than 0.2 million b/d, averaging 0.6 million b/d for the first quarter of 2019. Weekly estimates through June 14 of this year show continued declines, indicating that imports from Saudi Arabia averaged less than 0.5 million b/d in May and the first half of June. As a result of these shifts in crude oil flows, the U.S. share of total Saudi Arabian crude oil exports fell to 9% in March, and China’s share increased to 24% (Figure 3). Collectively, the United States, China, Japan, Taiwan, and South Korea historically accounted for about 60%–65% of total Saudi Arabian crude oil exports.
These recent changes in crude oil trade patterns are partially because of long-term structural trends within China and the United States, but they are also a result of recent oil market dynamics. From 2010 through 2018, EIA estimates total Chinese petroleum consumption has increased from 9.3 million b/d to 13.9 million b/d, whereas Chinese domestic production has increased from 4.6 million b/d to 4.8 million b/d. As a result, China’s need to meet incremental oil consumption has come primarily from imports. China’s crude oil imports from Saudi Arabia have gradually increased in recent years, and in March 2019 reached the highest level for any month since at least 2004, at 1.7 million b/d. Other countries, including Russia and Brazil, have had larger increases in crude oil export growth to China, however, with Russia overtaking Saudi Arabia as the largest source of crude oil on an annual average basis in 2016.
U.S. crude oil imports, on the other hand, have steadily decreased during this period as domestic crude oil production has increased. In addition, U.S. crude oil imports from members of the Organization of the Petroleum Exporting Countries (OPEC) have declined, in particular, following increases from other countries such as Canada. Canadian crude oil can substitute for certain OPEC grades and have lower transportation costs when shipped by available pipeline capacity.
Saudi Arabian crude oil exports to China increased recently at least in part as a result of the startup of a new 0.4 million b/d refinery in Dalian, Liaoning Province, which has a supply agreement with Saudi Aramco, Saudi Arabia’s national oil company. Saudi Aramco also has a supply agreement with another 0.4 million b/d refining and petrochemical complex in Zhejiang Province, which started trial operations this year.
Other near-term developments, however, could reduce the volume of Saudi Arabian crude oil headed to China for May, June, and through the summer. Saudi Arabia typically increases domestic crude oil consumption in the summer months because the country directly burns the fuel for power generation. Although Saudi Arabia has gradually been increasing the use of fuel oil and natural gas instead of crude oil for power generation, the seasonal increase is dependent on the weather and can still amount to several hundred thousand barrels per day in additional domestic consumption during summer months. The five-year (2014–18) average crude oil burn for electric power generation peaks in July at 0.7 million b/d, an increase of 0.3 million b/d from the April average. In addition, Chinese crude oil refinery demand could be lower in the second quarter of 2019 than in the first quarter of 2019. Bloomberg data suggest that Chinese refinery outages in May and June month-to-date were 2.1 million b/d and 1.7 million b/d, respectively, 0.5 million b/d and 0.6 million b/d higher than their respective five-year averages for those months.
Recent global oil supply issues could keep Saudi Arabian crude oil exports to China, Japan, South Korea, and Taiwan relatively high in the coming months, however, in spite of the previously mentioned seasonal factors. These four countries were all initially granted Iranian sanctions waivers through May 2019. However, because waivers were not renewed, each country will likely need an alternative to Iranian crude oil. This development could keep their crude oil imports from Saudi Arabia near first-quarter 2019 levels for the coming months as a partial substitute for Iranian barrels. Saudi Arabia’s support of maintaining current OPEC production cuts or increasing output levels in the upcoming late-June or early-July OPEC meeting will be a critical determinant for future export flows.
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell more than 6 cents from the previous week to $2.67 per gallon on June 17, 21 cents lower than the same time last year. The Midwest price fell nearly 8 cents to $2.54 per gallon, the West Coast price fell nearly 7 cents to $3.45 per gallon, the East Coast price fell more than 6 cents to $2.56 per gallon, the Rocky Mountain price fell nearly 4 cents to $2.91 per gallon, and the Gulf Coast price fell nearly 3 cents to $2.34 per gallon.
The U.S. average diesel fuel price fell nearly 4 cents to $3.07 per gallon on June 17, more than 17 cents lower than a year ago. The West Coast and Midwest prices each fell nearly 5 cents to $3.67 per gallon and $2.96 per gallon, respectively, the Rocky Mountain price fell more than 4 cents to $3.07 per gallon, the East Coast price fell nearly 3 cents to $3.10 per gallon, and the Gulf Coast price fell more than 2 cents to $2.82 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 3.3 million barrels last week to 74.5 million barrels as of June 14, 2019, 10.7 million barrels (16.8%) greater than the five-year (2014-2018) average inventory levels for this same time of year. East Coast, Midwest, and Gulf Coast inventories each increased by 1.1 million barrels. Rocky Mountain/West Coast inventories fell slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 6.6% of total propane/propylene inventories.
It has been 21 years since Japanese upstream firm Inpex signed on to explore the Masela block in Indonesia in 1998 and 19 years since the discovery of the giant Abadi natural gas field in 2000. In that time, Inpex’s Ichthys field in Australia was discovered, exploited and started LNG production last year, delivering its first commercial cargo just a few months ago. Meanwhile, the abundant gas in the Abadi field close to the Australia-Indonesia border has remained under the waves. Until recently, that is, when Inpex had finally reached a new deal with the Indonesian government to revive the stalled project and move ahead with a development plan.
This could have come much earlier. Much, much earlier. Inpex had submitted its first development plan for Abadi in 2010, encompassing a Floating LNG project with an initial capacity of 2.5 million tons per annum. As the size of recoverable reserves at Abadi increased, the development plan was revised upwards – tripling the planned capacity of the FLNG project to be located in the Arafura Sea to 7.5 million tons per annum. But at that point, Indonesia had just undergone a crucial election and moods had changed. In April 2016, the Indonesian government essentially told Inpex to go back to the drawing board to develop Abadi, directing them to shift from a floating processing solution to an onshore one, which would provide more employment opportunities. The onshore option had been rejected initially by Inpex in 2010, given that the nearest Indonesian land is almost 100km north of the field. But with Indonesia keen to boost activity in its upstream sector, the onshore mandate arrived firmly. And now, after 3 years of extended evaluation, Inpex has delivered its new development plan.
The new plan encompasses an onshore LNG plant with a total production capacity of 9.5 million tons per annum. With an estimated cost of US$18-20 billion, it will be the single largest investment in Indonesia and one of the largest LNG plants operated by a Japanese firm. FID is expected within 3 years, with a tentative target operational timeline of the late 2020s. LNG output will be targeted at Japan’s massive market, but also growing demand centres such as China. But Abadi will be entering into a far more crowded field that it would have if initial plans had gone ahead in 2010; with US Gulf Coast LNG producers furiously constructing at the moment and mega-LNG projects in Australia, Canada and Russia beating Abadi’s current timeline, Abadi will have a tougher fight for market share when it starts operations. The demand will be there, but the huge rise in the level of supplies will dilute potential profits.
It is a risk worth taking, at least according to Inpex and its partner Shell, which owns the remaining 35% of the Abadi gas field. But development of Abadi will be more important to Indonesia. Faced with a challenging natural gas environment – output from the Bontang, Tangguh and Badak LNG plants will soon begin their decline phase, while the huge potential of the East Natuna gas field is complicated by its composition of sour gas – Indonesia sees Abadi as a way of getting its gas ship back on track. Abadi is one of Indonesia’s few remaining large natural gas discoveries with a high potential commercialisation opportunities. The new agreement with Inpex extends the firm’s licence to operate the Masela field by 27 years to 2055 with the 150 mscf pipeline and the onshore plant expected to be completed by 2027. It might be too late by then to reverse Indonesia’s chronic natural gas and LNG production decline, but to Indonesia, at least some progress is better than none.
The Abadi LNG Project:
Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b
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