With the most energy-intensive economy on the continent, South Africa has undergone a spate of load-shedding in recent years as demand continues to outstrip supply. However, while faltering output and under-maintained infrastructure have had an adverse effect on the country’s economic performance, a range of government initiatives, notably the country’s independent power producer (IPP) bidding programme, should help strengthen long-term output and reduce the risk of volatility.
South Africa is responsible for just under 60% of Africa’s total power-generating capacity. A large supply of generating inputs – most notably including coal, which comprises over three-quarters of total capacity – have helped the country achieve a relative measure of energy autonomy, while reducing price pressures on production.
However, a large growth in consumption over the past two decades has placed strain on the country’s networks. From 1994 to 2008, GDP grew by 70% and 4m new homes were connected to the grid. This has contributed to significant rises in demand, alongside growth in the industrial and commercial sectors that together combined consume 60% of the power supply. On the supply side, however, South Africa’s generation capacity increased by only 14% in the same period. While the country’s nameplate capacity stands at nearly 45,645 MW, over 34% of its capacity is estimated to be either non-operational or offline owing to ongoing maintenance, resulting in between 30,000 MW to 35,000 MW in available capacity.
The electricity sector has experienced significant load-shedding, with the margin between peak demand and available capacity hovering at around 4%. The electricity supply remains vulnerable to any shocks in the system or disruptions in supply, such as the collapse of the coal storage silo at the 4110-MW Majuba plant in late 2014, which disrupted the plant’s supply to the grid for just over three months. “The country needs diversification of its generators and primary energy sources to mitigate the risk of failure of the dominant monopoly to meet demand and the risk from the climate change impacts and price trajectory of coal,” Chris Yelland, CEO of EE Publishers, which produces energy sector magazines focusing on electricity content, told OBG.
As of the end of August 2015, the country had experienced 99 days of load-shedding for the year, leading to significant drops in manufacturing and mining in particular, as the country’s GDP contracted 1.3% in the second quarter of 2015. As detailed in a presentation of the Department of Public Enterprises to Parliament, it was estimated that power cuts had cost the economy between $1.7bn and $6.8bn per month, depending on the load-shedding stage implemented.
The cuts were in part due to a series of unexpected incidents in the country. For example, a technical issue at the Koeberg nuclear power plant in February 2015 resulted in one of its 900-MW units going offline for over 2 months, costing the country’s economy $648m, while the Majuba plant coal silo collapse in November 2014 reduced the 4110-MW plant to 60% of its normal capacity. “The regularity of load-shedding this year has accelerated the need for IPPs to play a bigger role to ensure electricity security for the country,” Bonang Mohale, chairman of Shell South Africa, told OBG.
With almost two-thirds of South Africa’s 87 coal-fired units past the mid-point of their operational lifetimes, maintenance work is currently being undertaken on around 4500 MW of cumulative capacity, in part a result of postponing previous priorities. In the 18 months leading up to the 2010 FIFA World Cup, the country adopted a “keep the lights on” policy while Eskom, the country’s publicly owned state utility company, postponed maintenance so they could avoid any load-shedding. According to Eskom, the maintenance backlog will therefore take at least several years to address, approximately the same amount of time it took to accumulate it in the first place.
Reserve capacity, defined as the margin between forecast peak demand and the available capacity, has fallen to below 2000 MW, or 4% – well below international standards of 10-20%. Once below the 2000-MW threshold, Eskom uses diesel-powered open cycle gas turbines to make up the difference.
Eskom supplies around 95% of produced electricity in South Africa, with the remainder coming from various IPPs that produce more than 6000 MW overall as a result of four bid rounds since 2011. In 2014, 21 IPP renewable energy projects with a combined installed capacity of 1076 MW were brought onto the national grid. Scatec Solar, a Norwegian solar company, was the first of the companies in the Renewable Energy Independent Power Producer Procurement programme to connect to the grid, followed by companies including Cape Town-based Umoya Energy and US-based SunEdison. Even so, coal-fired power plants still account for 85% of South Africa’s total installed electricity capacity, with the rest split between hydroelectric (10%), nuclear (4%) and other renewables (1%).
Between 2005 and April 2013 South Africa expanded transmission lines nationwide by 4686 km, increased transmission substation capacity by 23,775 mega-volt amperes (MVA) and made capital upgrades of $5.7bn. From April 2013 to March 2014, Eskom, the country’s sole transmission company, commissioned 811 km of transmission power lines and 3790 MVA of transmission substation capacity. Eskom has allocated $82.3m for transmission spending for the 2015/16 financial year, including a significant $25m contract to Abengoa for the building of two 174-km-long, 400-KV transmission lines from the Medupi station in Lephalale to the Borutho substation in Mokopane.
Eskom has planned $12bn of spending on transmission infrastructure from 2015 to 2024, according to the utility’s transmission development plan. Around 89% of this will be allocated to capacity expansion, with the rest divided between refurbishment, capital spares, production equipment, lands and rights, and strategy. A total of 13,396 km of transmission lines will come on-stream in that time, with 5235 km by 2019 and 8161 km from 2020 to 2024. Investment in transmission infrastructure, as well as providing connectivity in areas far away from major load centres, forms part of a strategy to support regional power corridors, connecting generation pools to one another more efficiently.
The electricity distribution sector comprises 170 licensed distributors, almost all of whom are local municipalities. These municipalities serve 52% of customers, with Eskom distribution directly serving the remaining 48%. The manufacturing sector consumes around 40% of the electricity distributed, with mining and domestic usage following thereafter at 18% each. The bulk of the remainder is accounted for by the power requirements of the agricultural and transport sectors.
At present, electricity sales make up over 25% of municipality revenue and can reach up to 34% in the largest urban areas. As available electricity and revenues fall in some areas, the municipalities may lose the ability to re-invest in maintenance of their network infrastructure, leading to losses in distribution. Although the World Bank estimates that South Africa lost up to 8% of its electricity output in 2012 in transmission and distribution, a 2015 OECD report noted that in some parts of the country “a number of municipalities use their distribution tariffs for cross-subsidisation without investing sufficiently in the maintenance of their distribution network”.
This can have an impact on municipalities’ ability to repay Eskom for the electricity they received from the transmission network; for instance, Soweto owes the utility company approximately $280m, with the remaining municipalities owing a combined estimated $300m. The OECD report recommends the country to “ring-fence the electricity distribution businesses of the 12 largest municipalities (which account for 80% of supply), resolve maintenance and refurbishment backlogs and develop a financing plan, alongside investment in human capital”.
Tariffs & Management
Electricity prices in South Africa have increased four-fold since 2007. Eskom’s revenue requirements dictate the tariff, which has been a challenging deficiency at a time of rising costs and decreasing output. The tariff structure sets a revenue target for Eskom, but as costs for production due to the use of diesel for feedstock, refurbishment of aging plants, and maintenance have increased, overall electricity output has fallen. This has caused the per unit price of electricity to rise significantly, impacting both business and consumers.
According to Shaun Nel, director of the Energy Intensive Users Group, an industry organisation, “The issue with revenue-based tariffs is that as demand from energy-intensive industries are decreasing, tariffs will go up because each individual unit of electricity sold will need to be more expensive to meet the revenue target,” said Nel. As a result of this, a move to a cost-reflective, accurate and transparent tariff structure would be more sustainable and generally welcomed by all actors.
The National Energy Regulator of South Africa (NERSA) institutes five-year tariff arrangements, with the latest implemented in 2012 and allotting an 8% increase every year from 2013 to 2018. In August 2015, Eskom asked NERSA for permission to recover over $280m of unplanned costs incurred in its 2014/15 financial year via higher electricity tariffs beginning April 1, 2016. In an earlier request in June 2015, NERSA rejected Eskom’s request to raise tariffs by 25% for the fiscal year. In both requests, Eskom cited additional costs incurred for purchasing power from IPPs and for diesel to fuel generators needed to combat load-shedding.
Eskom was previously granted permission in October 2014 to raise tariffs by an average of 12.7% for the year beginning April 1, 2015 to recover unbudgeted costs of over $580m that it had incurred in the three years leading up to March 2013. However, the raise still fell far short of amortising the total that Eskom had initially claimed in unbudgeted costs. “The approximate $1.1bn shortfall will have to be recovered in local and international bond markets,” Khulu Phasiwe, spokesperson for Eskom, told OBG. For 2015, Eskom is also seeking to raise $4.5bn to fund key projects, he added.
Building New Capacity
The country’s new build programme aims to add 17.1 GW of generating capacity by 2018/19. This will entail the construction of two coal-fired power plants, Medupi and Kusile, with nominal capacities of 4764 MW and 4800 MW, respectively, as well the Ingula hydroelectric plant, which has a nameplate capacity of 1322 MW during periods of peak demand.
However, inadequate planning, skills shortages, labour disruptions and technical issues have hindered the arrival of both coal plants, causing significant delays. The Medupi station, set to become the fourth-largest coal power station and the largest dry-cooled power station in the world, was initially set to have its first unit on stream in 2011 and be completed in 2013. However, its first 800-MW unit was inaugurated and commissioned by President Jacob Zuma in August 2015 and its last unit is meant to come online in 2019. Meanwhile, the completion of Kusile’s first 800-MW unit has been pushed back from 2012 to the first half of 2017. The plants will be completed by 2019 and 2021, respectively, according to Phasiwe. Ultimately, between mid-2015 and September 2017, Eskom plans to bring on-stream 3700 MW in new power generation capacity, including the first two 333-MW generating units of the Ingula pumped hydropower station, set to come on-line in the first half of 2016. The remaining two units will be ready by the end of 2016, according to Phasiwe. “With these new additions, we expect there to be enough supply to bring stability to the grid by 2017, with possibly no load shedding,” Phasiwe added.
South Africa also plans to build 9600 MW of new nuclear capacity by 2029, aiming to have the first unit come on-line by 2023. Eskom currently operates Africa’s only nuclear power plant, the Koeberg facility near Cape Town, which has two reactors and supplies about 5% of the country’s electricity. Agreements have already been signed with several vendor countries that have expressed interest in the new nuclear programme, including the US, China, France, Russia and South Korea. The government’s interest in nuclear energy is strong but with cost estimates projected to be as much as R1trn ($86.4bn), financial and political barriers remain.
The implementation of the Integrated Resource Plan (IRP) has been a critical component of the country’s push to improve supply, opening up space for private sector-led renewable energy (see analysis). The plan calls for coal-fired electricity to account for less than 15% of all new generation capacity added through to 2030, and for the commodity to provide under 50% of the total grid capacity. Renewables are set to take up 42% of all new generation capacity, which would see the construction of 9.6 GW of nuclear energy and 11.4 GW of renewables, including solar and wind by 2030.
Natural gas will also play a larger role, through both imports by pipeline and proposed liquefied natural gas terminals, as well as from domestically produced sources such as the country’s touted shale gas and coal-bed methane reserves. The deputy director-general of the Department of Energy, Ompi Aphane, indicated in August 2015 that it seemed likely they would not extend the lives of Eskom’s ageing coal power stations through retro-fitting pollution control mechanisms. This will require additional new generation capacity to come on-stream, as these stations are to be mothballed from 2018 until 2050.
The IRP marks a clear departure from the country’s traditional reliance on coal-fired power. The majority of South Africa’s power comes from coal plants, and given the sizable deposits underground, it is not difficult to see why. South Africa boasts the world’s ninth-largest recoverable coal reserves, with 3.4% of the global total as of the end of 2014 according to the BP Statistical Energy Review 2014. Current coal production comes largely from the mature Witbank, Highveld and Ermelo fields in the Central Basin near the eastern border with Swaziland. Coal production increased last year, up from 145.3m tonnes of oil equivalent (MTOE) in 2013 to 147.7 MTOE in 2014 after having experienced a brief 0.8% contraction from 2012 to 2013.
The electricity sector is the recipient of over half of the coal consumed in South Africa, according to Eskom. Coal’s share of total energy consumption declined slightly from 71.7% in 2013 to 70.5% in 2014. While coal has historically proved to be an accessible input for South Africa’s power sector, this may not be the case for much longer. Lynne Brown, the minister for public enterprises, warned in May 2015 of a possible 17m-tonne coal shortfall at Eskom’s Matla, Tutuka and Hendrina power stations in 2015 and at the Kriel and Arnot power stations in 2016. In June 2015, former Eskom adviser Ted Blom predicted that the state-run utility company could start running out of coal in 2015. Indeed, by 2020 it could see a deficit of between 60m and 100m tonnes per year.
With their reserves expected to run out in less than a decade, the industry has turned its attention to inland coalfields in the Limpopo Province and around the resource-rich Waterburg Basin. Coal of Africa Limited is planning a $400m project in Makhado, located in Limpopo Province. The 16-year, opencast Makhado mine would produce 2.3m tonnes of hard coking coal and 3.2m tonnes of thermal coal per year once it comes on-stream in 2018. Commercial viability for exploration depends on overcoming water, transportation and infrastructure constraints. The poor financial health of mining companies – due principally to rising power costs, shortfalls in productivity and steep declines in global coal prices down to $50 per metric tonne – could inhibit large-scale capital investments in exploration programmes and greenfield projects.
Despite recent offshore discoveries in neighbouring Mozambique, locally sourcing significant amounts of fossil fuels other than coal seems unlikely in the short term. Even so, there remain plans to increase output from gas and unconventional deposits. South Africa’s proven oil reserves have remained fairly stagnant and stand at 15m barrels, according to the US Energy Information Administration, while PetroSA has estimated prospective offshore oil and gas resources at 21.75bn barrels and 62.4trn cu feet (tcf). South Africa’s west coast accounts for 10.2bn barrels and 27.7 tcf of the total, while the south coast was estimated to hold 9.55bn barrels of oil and 25.5 tcf of gas, respectively. PetroSA is the only operational player, producing less than 5000 barrels per day of crude oil and lease condensate from its Oribi and Oryz fields and 39bn cu feet from its F-A and South Coast Complex fields.
The Ibhubesi gas project off the west coast, which is being developed under a joint venture between PetroSA and Sunbird Energy, would see an initial flow rate of 100m standard cu feet of gas per day by early 2019 via a 400-km pipeline to an onshore gas receiving facility near Ankerlig in the Western Cape.
Overall, plunges in the global oil prices, coupled with regulatory uncertainty surrounding the pending Mineral and Petroleum Resources Development Act (MPRDA), have led to a slowdown in activity. President Zuma rejected the MPRDA and sent it back to Parliament in January 2015 amid concerns regarding the automatic 20% free carry the state had in prospecting and operational projects, as well as the ministerial discretion to declare certain minerals as “strategic”, and whether the black empowerment levels of 9% would increase to 25% as prescribed in the Mining Charter. President Zuma has emphasised the need for supportive legislation, adding that the country’s goal would be the development of 30 offshore exploration wells in the next ten years. “Getting the bill signed would essentially restart offshore exploration, which has been more or less frozen for two years,” Paul Eardley-Taylor, Standard Bank’s head of Oil and Gas Southern Africa, told OBG. A minimum of 14 energy firms currently have offshore exploration rights to 16 different blocks in the Orange Basin, while nearly 60 firms also have onshore exploration rights in the country.
“The majority of the players upstream are either deep into their seismic campaigns, or have finished these and identified drilling sites. From a technical and geological point of view, these explorers still have a sense of excitement, as the early campaigns have been promising,” David van der Spuy, the resource evaluation manager at Petroleum Agency SA (PASA), an agency that works to promote exploration for oil and gas resources, told OBG. Despite regulatory uncertainty, progress has been made in terms of infrastructure for oil and gas. In January 2015, the Transnet National Ports Authority announced R9.65bn ($833m) in infrastructure projects at Saldanha Bay, including a 380-metre-long and 21-metre-deep rig repair quay; an extension of the Mossgas quay from a length of 38 metres to 500 metres to accommodate floating docks for the construction of service vessels; and a one-stop-shop supply base for offshore operations. With around 120 oil rigs passing through the South African coastline per year, the projects would create 6300 new direct jobs and 25,200 new indirect jobs while contributing an estimated R4.74bn ($409.5m) to national GDP once completed in December 2017.
Following the shale boom in the US, unconventional exploration and production has increased around the world and has met with some success in South Africa – although it has not been without its challenges. In 2013 the EIA estimated South Africa’s technically recoverable shale gas reserves to be 390 tcf, the eighth-largest reserves in the world.
The Whitehill formation, located in the Karoo Basin and thought to be among the most prolific reserves in the country, holds an estimated 36 tcf of recoverable shale gas, or roughly 30 times that of PetroSA’s Mossgas project. In 2009 and 2010 PASA awarded technical cooperation permits to four international energy companies to conduct geological surveys of potential shale reserves in different areas of the Karoo Basin. Following this, the government placed a 19-month ban on fracking as it conducted environmental impact assessments amid concerns over its potential impact on aquifers and ecosystems. The ban was later lifted and the government announced its intention to proceed with the issuing of licenses once the shale regulations are published. The Department of Energy will process existing applications first and will issue new licences in three years.
The drop in oil prices has slowed shale activity worldwide, including in South Africa. Shell, which holds three of the five shale blocks, announced in March 2015 the redeployment of its senior staff to outside of South Africa. The move came as part of a worldwide cut in shale spending of 30%.
The EIA estimated South Africa’s total oil consumption at 655,000 bpd in 2014. Increased demand nationwide for energy resulting from economic growth over the past two decades, alongside a failure to add new domestic production capacity, has turned the country from a net exporter of petroleum products in the early 2000s to a net importer, importing 120,000 bpd of petroleum products in 2014. Indeed, the capacity limits are clear. South Africa’s GDP has grown at an average of 2.4% between 2010 and 2014, and Avhapfani Tshifularo, the executive director of the South African Petroleum Industry Association, told OBG, “Available infrastructure to refine and import products would have been insufficient if the economy was growing at a steady 5%. This kind of growth over just an 18-month period would put enormous pressure on the supply of petroleum products.”
The country’s crude oil refining capacity consists of four conventional refineries with a combined capacity of 503,000 bpd, the second-largest crude oil distillation capacity in Africa. The Sapref refinery, jointly owned by Shell and BP, has a capacity of 170,000 bpd; followed by Enref, Engen Petroleum’s refinery, with a capacity of 135,000 bpd; Chevref, owned by Chevron’s local subsidiary Caltex Oil SA and has a capacity of 110,000 bpd; and the Natref refinery, which is a joint venture between Sasol and Total and has a capacity of 88,000 bpd. South Africa imported 425,000 bpd of crude oil in 2014 for domestic refineries, according to the South African Revenue Service, up from 378,000 bpd in 2012. In 2014 imports originated from Saudi Arabia, with a 38% share; Nigeria, with 31%; and Angola, with 12%. Synthetic fuels account for 40% of consumption in South Africa and are processed at Sasol’s Secunda coal-to-liquids plant, which, with a capacity of 160,000 bpd, is the largest of its kind in the world. Mossel Bay, a PetroSA-operated gas-to-liquids plant with a 45,000-bpd capacity, produces several products including kerosene, diesel, propane, liquid oxygen and nitrogen, but over half of its product is petroleum. With demand for transportation fuels in South Africa forecast to grow to more than 400,000 bpd by 2020, PetroSA estimates that if no new refinery investment is made, the country will have to import more than 200,000 bpd by the end of the decade.
The government is also trying to push tighter fuel standards to bring South Africa up to international levels. Refiners have been in talks with the government since 2009 to obtain guarantees and regulations that would bring more certainty regarding the return on investment in making these upgrades, which are estimated to cost the industry $3bn. The initial compliance deadline of July 2017 has been pushed back to a date to be determined, but according to Tshifularo, the upgrades should eventually come through. “Market dynamics will force these upgrades. The international automotive market, a bulk consumer of these refined fuels, is moving towards these new standards and South Africa must keep up the pace in order to not be left behind,” Tshifularo told OBG.
NERSA approved the construction of South African firm Burgan Cape Terminals’ clean liquid fuels storage facility in Cape Town in December 2014. The facility will allow importers of clean fuels to bring in, store and distribute their product, which Nobuzwe Mbuyisa, the then-chairperson of Chevron, claimed could end up “threatening the viability of the [domestic refining] industry”, adding that the impact could cost $20m per year if the government does not assist in the refinery upgrades of in-country refineries and put certain regulations in place to protect the domestic refining industry from imports. The facility is seen as a threat on the basis that it would allow importers meeting the government’s clean fuel standards to dump product into the market, thus rendering existing in-country refiners that have failed to upgrade to these standards obsolete and unable to compete.
As the country searches to find shortterm solutions to plug the power gaps in the national grid, policy implementation and a renewed focus on bringing the Medupi, Kusile and Ingula plants on-line will help to accelerate IPP programmes, reverse issues with load-shedding and stabilise the power sector.
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