The single largest structural shift in the last decade in global energy markets – emerging output of shale gas and oil in the US – is having a clear effect on African oil producers. A growing reliance on African exporters in the early part of the millennium, reaching a peak of 20.34% of US oil imports in 2007, has sharply reversed as newly accessible domestic sources of similar light, sweet crude in Texas and North Dakota have come online. And while a growing number of African markets are joining the ranks of Nigeria, Angola and Egypt as key liquefied natural gas (LNG) exporters, the reconfiguration of new US LNG terminals for export will support the convergence of the world’s three reference gas prices (North America, Europe and Asia). While Asian and European buyers are filling the gap in demand for African oil and gas in the short term, new sources of unconventional supplies have the potential to fundamentally alter trade dynamics in the long term.
Key African producers such as Nigeria, Angola, Libya, Algeria; newcomers like Ghana and Côte d’Ivoire; and prospectors like Uganda and Kenya are all having to adapt to the reality that global energy demand is increasingly driven by Asian customers. While rebalancing trade eastward will prove beneficial for African producers’ medium-term prospects, new sources of unconventional oil in the US and Africa, combined with new refining capacity for heavier, sour grades of crude, could have a permanent effect on pricing structures for Africa’s easier-to-refine light, sweet blends.
By the first few years of the 2000s, the US had become an increasingly large consumer of African oil and gas given its declining reserves of conventional gas. Major suppliers such as Nigeria had a long track record of exporting to the US dating back to 1973, but saw exports increase during that period, holding fast as one of the five largest suppliers to the US. The rise in African supply was in part a result of a US policy shift that sought to diversify away from traditional Middle Eastern suppliers, guided in part by a 2001 energy security report released by then US Vice-President Richard Cheney that set an ambitious target of sourcing 25% of oil imports from West Africa, as well as growing reliance on LNG imports through a series of new import terminals.
Rising from 15% of imports in 2004 to a peak of 22% by 2006, African oil exports to the US remained around the 19% mark until 2010, according to the US Energy Information Administration (EIA). In particular six key African suppliers – Algeria, Angola, Cameroon, Congo-Brazzaville, Gabon and Nigeria – ramped up their combined trans-Atlantic exports from 1.79m barrels per day (bpd) in 2003 to a peak of 2.47m bpd in 2007. While this fell slightly to roughly 2.1m bpd by 2010, largely due to supply shut-ins in the restive Niger Delta until the amnesty of late 2009, the combined exports those six countries to the US grew 40% from 2001 to 2010, outpacing the 16% rise in total US oil imports.
Developing New Strategies
The US’s 2001 energy plan also provided for the development of domestic unconventional oil sources, in a move that started yielding new output from 2007 onwards. Building on hydraulic fracturing, or fracking, and horizontal drilling techniques developed in the late 1980s, oil firms used an in-situ leaching method involving water pressure to create fractures in the rock, allowing high-quality sandstone and shale oil and gas to seep out.
The technology led to heavy commercial exploration centred on two areas in particular: Eagle Ford over 24 counties in Texas, with an estimated 1.25bn barrels of oil and 8.4trn standard cu feet (scf) of gas reserves, and the Bakken formation in North Dakota, with estimates varying from 7.4bn to 24bn barrels of potential recoverable reserves of oil.
With operators including Marathon Oil, ExxonMobil and Statoil Hydro, and a host of smaller junior independents like Pioneer Natural Resources, output of tight oil has skyrocketed from 600,000 bpd in 2008 to 3.5m bpd in 2014. Shale gas production at other major deposits, such as the Marcellus field in the Appalachians, has also surged by 50% annually since 2007, with its share of US gas output rising from 5% to 39% in seven years, according to EIA figures.
Having surpassed Russia as the world’s largest oil producer in 2013, the US is expected to overtake Saudi Arabia as its largest crude oil producer in 2015, according to the EIA. Domestic shale oil’s light (low-sulphur) and sweet qualities put American shale oil, also known as light tight oil, in direct competition with major African producers of similarly high-grade petroleum. Refineries in the Gulf of Mexico, which account for roughly half of US capacity, have easily shifted existing light sweet refining capacity to handle domestic tight oil. Imports of African oil, from all 12 suppliers on the continent, declined swiftly by roughly half from 19.34% in 2010 to 15.3% in 2011, 11.3% in 2012 and 8.2% in 2013, a mere 812,000 bpd, the lowest level in four decades.
All African producers have been equally affected, with the order of suppliers left intact if sharply reduced, dominated by the big three: Nigeria, for which US exports dropped from 1.02m bpd in 2010 to 281,000 bpd in 2013; Angola, which saw exports decrease from 393,000 bpd to 216,000 bpd over the same period; and Algeria, with a decline from 510,000 bpd to 115,000 bpd. Smaller producers in the Gulf of Guinea, including Gabon, Congo and Equatorial Guinea, and in North Africa, like Egypt and Libya, have witnessed corresponding declines in the same span. Fledgling producers like Ghana and Côte d’Ivoire retain marginal market share, although research by Citigroup indicates there is a chance the US and Canada will stop importing West African crude entirely by 2015.
In total, US shale oil production has cut trade between the US and its partners in sub-Saharan Africa from around $100bn a year in 2008 to an expected $15bn in 2014, according to a May 2014 study on the impact of US shale oil on Africa by the UK think tank Overseas Development Institute. The report estimates that African exporters have lost earnings of $1.5bn in gas and $32bn in oil from the US’s development of its shale oil infrastructure over the past decade – $14bn in Nigeria, $6bn in Angola and $5bn in Algeria alone.
Looking To Refining
The US also moved into the global downstream market, further reversing the trend of the past decade by increasing its share of refined exports to Africa even as its share of crude imports slows. With the US barred from exporting crude to any country but Canada by 40-year-old rules, Gulf of Mexico refiners have drawn on this cheaper feedstock to produce refined petrol and diesel, which is in turn sold domestically and exported to markets, including in Africa. Thus, the US share of Nigerian refined fuel imports rose from under 20% in 2010 to roughly 50% by 2013, according to market research firm IHS.
This could increase further, and in a potential sign of loosening export restrictions, the US Commerce Department has licensed two shale oil producers, Pioneer Natural Resources and Enterprise Product Partners, to export ultralight oil and condensates. In a July 2014 note on the sector, Ecobank estimates potential exports of up to 1m bpd from 2015 due to a glut in crude in the Gulf of Mexico.
This spectre has caused unease for both Middle Eastern and African producers. “We risk a situation where, in the first place, we lose our oil market in America,” Omar Farouk, general manger of the media relations at the Nigerian National Petroleum Corporation (NNPC), told an Abuja conference in July 2013. “But beyond that we also risk a situation where America, having satisfied itself with what it has, will also want to find a market outside. And that market may be a market that Nigeria is selling to.”
West Africa Shifts East
Amidst such a radical reshaping of trans-Atlantic oil flows, African producers have looked to other buyers to pick up the slack but have had to offer discounts to expedite sales. European refineries, already geared towards light, sweet crude, expanded their imports of cheaper crude, although Asian buyers, China and India in particular, were crucial to bridging the gap in demand for West African crude. The structural rebalancing of demand towards the East has indeed accelerated with surging US shale oil output: by December 2012 net US oil imports fell to 5.98m bpd, while Chinese net imports reached 6.12m bpd, according to figures from the EIA. Growth in demand has also accelerated due to the dramatic expansion in Chinese domestic refining capacity, which jumped fourfold from 781m barrels per year in 1990 to 2.9bn by 2010.
Different producers have adapted to varying degrees to the drop-off in US demand. Nigeria, for example, has relied on strong Indian demand growth for its exports. While US oil imports from Nigeria slumped from 10% of the total in 2009 to 2% by year-end 2013 and nil by September 2014, India became Nigeria’s largest export market in 2013, accounting for 18.09% of oil sales. Oil sales between the two countries grew 37% year-on-year (y-o-y) to 367,000 bpd in the first half of 2014, according to figures from Platts. Chinese imports have grown at a high pace, rising 105% y-o-y to 41,000 bpd in the first half of 2014, while oil sales to Japan and South Korea remained marginal at 4208 bpd and 1724 bpd, respectively, in the first half of 2014.
While low, the strong growth in Chinese imports should continue given the increasingly prominent role of Chinese state-owned oil producers in Nigeria. The China National Offshore Oil Corporation (CNOOC) is already a major investor in Total’s offshore floating production, storage and offloading (FPSO) facility and expanded its involvement in Nigeria’s offshore through its $15.1bn acquisition of Canada’s Nexen in 2013. China’s Sinopec has also vastly expanded its presence since acquiring Switzerland-based Addax Petroleum, with operations in Nigeria, Cameroon and Gabon, in August 2009. Sinopec also acquired Total’s 20% operating stake in its offshore 287,000-bpd Usan FPSO for $2.5bn in November 2012.
India is the largest single market for Nigeria, although European refiners have expanded imports, particularly given discounts offered by West African producers. Configured to produce petrol and middle distillates like jet fuel, kerosene and diesel, refineries in Europe, similar to those in the US, have long been buyers of West African light, sweet oil. Exports from Nigeria and its West African neighbours like Ghana and Côte d’Ivoire to Europe have almost doubled from 870,000 bpd in 2010 to 1.42m bpd in 2013, according to a 2014 report by ship-broking agent Gibson. Europe remained the largest regional destination for Nigerian oil exports in 2013 at 52.64% of the total, with the Netherlands and France ranking second and third, respectively, as single markets.
Angola has seen a greater emphasis on Chinese trade and investment as well. China’s share of Angolan imports had already trended upwards from 27.36% in 2002 to 39.53% in 2009, and the Asian country was quickly able to fill the vacuum left by Angola’s traditionally main market for oil, the US. Exports to the US contracted from 47.69% to 25.35% of output between 2002 and 2009, dropping to 213,000 bpd in 2013 and 116,000 bpd in the first half of 2014, according to figures from the EIA. While the drop has been sharp, imports have continued as Angolan crude is typically heavier than, albeit just as sweet as, Nigerian grades, export of which to the US stopped by October 2014. China accounted for 46% of Angolan oil exports in 2013, but that share is expected to grow further given recent Chinese state-owned investment upstream. Angola already accounts for 16% of China’s oil imports, as its second-largest supplier after Saudi Arabia in 2013, but with most of Angola’s oil reserves located in the deepwater offshore of its small northern enclave of Cabinda, Chinese investment will be key.
Sinopec has formed a joint venture with Sonangol to hold stakes in key deep-water offshore FPSOs developed by Marathon Oil (alongside CNOOC), Total, ExxonMobil and BP, which will be instrumental to boosting the country’s output from the 1.62m bpd in the first half of 2014 to over 2m bpd in 2016. India has become the country’s second-largest trade partner, with imports of Angolan oil rising from 48,000 bpd in 2004 to 150,000 bpd by 2013, before falling back 18% y-o-y to 120,000 bpd in the first half of 2014. Europe remains a much smaller market than for Nigeria, accounting for only around 11% of Angola’s oil exports.
Sharing The Burden
Smaller producers along the Gulf of Guinea have also shared the pain of declining trade with the US, with Gabon’s exports to the US halving from 47,000 bpd in 2010 to 25,000 bpd in 2013, Equatorial Guinea’s dropped from 58,000 bpd to 17,000 bpd and Congo-Brazzaville’s fell from 72,000 bpd to 20,000 bpd in the same period. At much smaller volumes, fledgling new producers like Ghana and Côte d’Ivoire have also seen their US exports affected, falling from 10,000 bpd to 3000 bpd and from 4000 bpd to nil, respectively, between 2011 and 2013.
This remains a small share of Ghana’s oil output, which has risen sharply from 54,900 bpd in 2012 to 84,700 bpd in 2013 and is forecast to reach 102,000 bpd in 2014, according to the Ghana National Petroleum Corporation. However, delays in construction of the Atuabu gas processing plant at the Jubilee field could postpone the country’s plans to reach output of at least 200,000 bpd by late 2016, when oil will overtake gold as Ghana’s largest export. While Côte d’Ivoire’s output is smaller, at 30,000 bpd in 2014, it hopes to boost output to 200,000 bpd by 2019.
Looking To Europe’s Backyard
Equally affected by falling US demand, North African producers have capitalised on their closer proximity and infrastructure links to European buyers in order to expand their market share. Key producers of gas like Algeria have long supplied all of their gas to the European market through the pipeline connection to Spain. But while the US remained the top buyer of Algerian oil as recently as 2011 with 29% of its output, its imports fell by two-thirds from $15.2bn in 2011 to $5.3bn in 2013. Although Algeria’s oil exports have been falling, by 15% y-o-y in 2013 and 9% y-o-y in the first quarter of 2014, it relies on Europe for 75% of its oil sales.
Spain also rose from Algeria’s third to largest export market with 15.67% of all Algerian exports between 2012 and 2013, followed by Italy, the UK and France with 13.66%, 10.91% and 10.23%, respectively. China’s share of exports remains much smaller at 3.31% in 2013, behind Brazil and Turkey, both at around 4%, according to Algeria’s National Centre for Information and Statistics. Yet these figures could grow further due to Algeria’s central importance to regional trade with China: it accounted for 40% (around $9bn) of China’s trade with the Maghreb in 2013.
Although Libya’s oil output has surged since 2011, rising from 485,500 bpd to 1.45m bpd in 2012, recent unrest has curbed production sharply, to just over 990,000 bpd in 2013, according to OPEC, and a low of 70,000 bpd in mid-2014. The reopening of Libya’s eastern ports in 2014 has allowed for an increase in trade with global markets, although output remained below 340,000 bpd in September 2014. Libya has traditionally exported most of its oil to European refiners, which accounted for roughly 70% of exports post-war, although Italy and France have taken over market share from Northern European markets in the past year, driven by key investments by Italy’s ENI. American imports have proven resilient to volatility, however, rebounding from a low of 15,000 bpd in 2011 to 59,000 bpd by 2013, according to EIA figures.
The largest non-OPEC oil producer in Africa with roughly 189,000 bpd exports in 2013, according to the EIA, Egypt’s trade is mainly with European refiners and Asian buyers, although its position atop the Suez Canal and Suez-Mediterranean pipeline gives it a strategic interest in the burgeoning energy trade between Asia and Africa. Despite a spike to 31,000 bpd in 2012, US imports from Egypt were marginal at 4000 bpd in both 2011 and 2013. The lion’s share of oil, 56% in 2013, is sold to Europe, with India and China also being significant buyers with 28% and 13%, respectively. In Egypt, too, Asian oil majors are seeing potential for expanded oil output, even if the region is traditionally known for gas: in 2013 Sinopec bought a 33% stake in the US-based Apache Corporation’s Egypt upstream oil exploration and production business for $3.1bn.
Terms Of Oil Trade
As sub-Saharan African producers have looked for new markets in Asia, however, they have had to offer significant discounts to sell inventory. While traders still play a key role for some exporters, like in Nigeria where NNPC awarded the lion’s share of crude-lifting contracts to local brokers in 2014, other large state-owned producers are expanding their presence in Asia directly. For instance, Sonangol opened its fourth trading office in China in late 2013, while the National Petroleum Company of the Congo opened a Singapore trading office in 2014. With reduced US imports swinging sharply into surplus, driven by a glut in global demand for light, sweet crude, North African producers have relied on traditional buyers in Europe, but Asian demand from China and India in particular has only just filled the gap in US imports. The emergence of a contango effect in ICE Brent futures in 2014 has reflected this over-supply.
The redirection of trade eastward has not been a smooth process. By August 2014 unsold Nigerian and Angola crude cargoes had built up an overhang of 25 ships in north-west Europe and the Mediterranean, according to Reuters. Producers have had to offer significant discounts to clear the backlog. While light, sweet Nigerian blends like Bonny Light and Qua Iboe typically trade at a significant premium to Brent, the differential fell to $0.7 per barrel in August 2014, a five-year low. Meanwhile, the equally premium, albeit heavier, Angolan Nemba crude was trading at a $1.5 per barrel discount on dated Brent. While this helped reduce inventory to 10 ships by mid-September 2014, the resumption of Libyan exports to Europe in late 2014 could undercut West African producers on transport costs. Demand from European refiners itself is also shrinking and already met by existing sources. They have also faced shrinking demand from traditional markets like the US, whose imports of refined fuel from Europe fell from 390,000 bpd in 2008 to 280,000 bpd in 2013.
The key variable for African exporters is thus Asian demand. While bargain hunters have snapped up easy-to-refine African crude in the short term, the medium-term outlook is far less certain. New refineries in India and China are geared towards the high-sulphur (sour), heavy crude of the Middle East, where refining margins are higher. Amidst rising competition between Asian refiners, competition on margins will be key, with the refining margins on Dubai’s medium-sour blend far outperforming those on Brent or West Texas Intermediate. Meanwhile, in Japan a new law passed in March 2014 requires a higher share of refining to take place locally, which should also favour imports of heavy, sour blends. Over the long term, rising US oil production – and the prospect of crude exports – poses important challenges to OPEC’s traditional dominance of oil markets and has already started to curb the premiums over Brent traditionally commanded by easier-to-refine African blends.
Gas is also having to adapt to slower demand in the US and rising demand in Europe and Asia, both through LNG production and direct pipelines. Algeria and Libya began exporting LNG as early as 1964 and 1971, respectively, both supplying European, particularly Spanish, buyers. However, significant African exports only followed Nigeria’s LNG plant (NLNG), which expanded to six trains between 1999 and 2007. According to a KPMG report, Nigeria ranks as Africa’s largest LNG exporter, with 27.2bn cu metres in 2012, outpacing Algeria’s 15.3bn cu metres, Equatorial Guinea’s 4.89bn cu metres (through EG LNG) and Egypt’s 4.34bn cu metres. Although civil war suspended Libya’s LNG exports in 2011 (it has exported gas mainly to Spain since 1964 by pipeline), new exporters in sub-Saharan Africa are adding significant new capacity. Angola’s terminal at Soyo started shipping in 2013, while Mozambique and Tanzania are expected to join the ranks of gas exporters by 2018.
While Algeria and Libya’s pipelines have traditionally tied them to the European market, new LNG exporters have sold mostly to Asian buyers. Asian oil firms have shown appetite for equity stakes in these projects, although most LNG terminals in Africa remain the preserve of Western oil majors. Exports from the 22m-tonnes-per-year NLNG to Asia have risen over time, reaching 48% in 2013, including 24% to Japan, although European countries like Spain (19%), France (12%) and Portugal (6%) remain important markets.
Asia already accounted for 82% of Egypt’s LNG exports in 2013, far out-stripping Europe’s 7%, South America’s 6% and the Middle East’s 5%. Japan alone accounted for 77% of Equatorial Guinea’s LNG exports since 2007, with South Korea, Taiwan, Chile and Greece taking the balance. The first clients for Angola’s 5. 2mtonnes-per-year plant, which began producing in mid-2013, were Japan, Brazil and China. Japan’s Mitsubishi Corporation is eager to expand its share of gas traded to Asia and has been aggressive, acquiring a 20% stake in Anadarko’s LNG project in Mozambique and a 8.5% stake in EG LNG alongside fellow Japanese firm Marubeni. The Mozambique LNG plant was farmed out by the China National Petroleum Corporation to ENI in March 2013 and is due to come on-line in 2018.
Gas producers have been eager to sell to an Asian market where natural gas price are roughly six times higher than North America’s and 50% higher than Europe’s. Given that natural gas has traditionally been transported through pipelines, many suppliers have been locked into long-term, off-take agreements, while the price of natural gas has proven far stickier than the highly traded global oil market that emerged post1970s. Asian demand, from Japan in particular, drove many LNG projects planned in the 1990s and the Japan/Korea Marker developed by Platts became the Asian benchmark price. These prices averaged $17 per million British thermal units in 2012, compared to $11 in Germany and $3 in the US. While Japan’s emergence as the world’s largest LNG importer following the post-Fukushima nuclear shutdown from 2011 has driven Asian prices, the outlook is less certain.
Analysts broadly concur that, short of as fluid a global market as that of oil, the tripartite market for natural gas is tending towards convergence, driven by significant new exports from Australia and the US and Canada. The next three years will see four new LNG plants come on-stream in Australia, with some $200bn invested over the past decade. Australia expects to overtake Qatar as the world’s largest LNG exporter with 84m tonnes per year capacity by 2018, with most sold to North Asia. The Asian market is also set to tap North American exports, with 20 new LNG export terminals at various stages of development in the US alone.
With such extensive structural changes in global energy markets under way, African producers are faced with a difficult balancing act. Under fiscal pressure, governments will need to expand output, particularly if prices for light, sweet crude come under sustained pressure. The prospect of shale may prove enticing to several states named in a 2013 EIA report on shale resources, with large potential gas reserves in South Africa of 390trn scf of recoverable gas and Algeria with 707trn scf, while Morocco and Egypt are also hoping to jumpstart exploration. But while many would like to replicate the success of the US, they do not necessarily boast the same underground property rights or developed oil industry to capitalise on these resources. As African producers adapt to the new export landscape in the short term, they will seek to expand long-term supply agreements with Chinese state-owned majors, as Nigeria and Angola have done. With OPEC launching a study into the impact of US shale production on its members in late 2013, African governments are already faced with the spectre of falling oil revenues and the need to diversify their economies.
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