The single largest structural shift in the last decade’s global energy markets, the emerging output of shale gas and oil in the US, is having its most disruptive effect on African oil producers. The US’s reliance on African exporters, which reached a peak of 20.34% of US oil imports in 2007, has sharply reversed as domestic sources of similar light sweet crude in Texas and North Dakota have come online.
While the impact of these developments on Egypt has been fairly limited, the broader evolution of global energy markets is nonetheless affecting the country’s export dynamics. With Egypt’s exports to the US traditionally fairly small, and with domestic consumption accounting for a growing proportion of local output, the direct result of US shale production on Egypt’s gas and crude is minimal. However, Egypt has long held export contracts with European and Asian consumers, which are now seeing increased supply-side competition as other major producers, such as Nigeria, Angola and Algeria, redouble their efforts to find buyers for their output.
At the millennium’s start, all indications were that the US would become an increasingly large consumer of African oil and gas given its declining reserves of conventional gas. Indeed, major suppliers like Nigeria, one of the top-five until 2009, had a long track record of exporting to the US dating back to 1973.
US policy was driven by a desire to diversify away from its traditional North African and GCC suppliers, with the 2001 Cheney Report on the US’s energy strategy setting an ambitious target of 25% of oil import needs from West Africa alone, as well as growing reliance on liquefied natural gas (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 figures from the EIA. In particular six key African suppliers – Algeria, Angola, Cameroon, Congo-Brazzaville, Gabon and Nigeria – often with US oil majors ExxonMobil to Chevron participating, 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 on supply shut-ins in the restive Niger Delta up until the amnesty of late 2009, the six countries’ combined exports to the US grew 40% from 2001 to 2010, outpacing the 16% rise in total US oil imports.
The US’s 2001 energy plan also provided for the development of unconventional oil sources domestically, in a move that started yielding new output from 2007 onwards. Building on the hydraulic “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. In the US developments have centred on two areas in particular: Eagle Ford, which covers over 24 counties in Texas, with an estimated 1.25bn barrels of oil and 8.4trn cu feet of gas reserves, and the Bakken formation in North Dakota, with estimates varying from 7.4bn to 24bn in potential recoverable reserves. Backed by Marathon Oil, ExxonMobil and Statoil Hydro, all of which bought into the fracking rush since 2009, 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. In parallel, shale gas production at major deposits like Marcellus in Appalachia has 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. The reconfiguration of the US’s LNG import terminals for export, due by end of 2015, could significantly expand US gas exports.
Having surpassed Russia as the world’s largest energy producer in 2013, the US then overtook Saudi Arabia as its largest crude oil producer in 2015, according to BP. Domestic shale oil’s light (low-sulphur) and sweet qualities put American shale oil, 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 an estimated 50% from 19.34% in 2010 to 15.3% in 2011, 11.3% in 2012 and 8.2% in 2013, a year in which a mere 812,000 bpd were imported, 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 of Nigeria, whose US exports dropped from 1.02m bpd in 2010 to 281,000 bpd in 2013 and 102,300 bpd in 2014; Angola, 393,000 bpd to 216,000 bpd; and Algeria, 510,000 bpd to 115,000 bpd. Smaller producers in the Gulf of Guinea like Gabon, Congo, Equatorial Guinea and in North Africa including Egypt and Libya have witnessed corresponding declines in the same span, of at least half the volumes. In total, US shale oil production has cut US-African trade from around $100bn a year in 2008 to an expected $15bn in 2014, according to a May 2014 study on the impact of US oil fracking on Africa by the UK’s 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.
Although affected by falling US demand, North African producers have been able to capitalise on their closer proximity and infrastructure links to European buyers to expand their market share. Key producers of gas like Algeria and Egypt have long supplied much of their gas to the European, Turkish and, in some cases Levantine markets through gas pipeline connections to Spain, Italy and Israel. However, they have not been wholly immune to the change in US production. While the US remained the top buyer of Algerian oil as recently as 2011, purchasing 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 Q1 2014, it relies overwhelmingly on Europe for 75% of its oil sales: Spain rose from third to its largest export market with 15.67% of all Algerian exports between 2012 and 2013.
Trailing behind Spain are 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 4.03% according to figures from Algeria’s Centre National de l’ Informatique et des Statistiques. Yet these could grow, given Algeria’s central importance to regional trade with China – it accounted for 40% (around $9bn) of China’s trade with the Maghreb in 2013.
The largest non-OPEC oil producer in Africa with roughly 189,000 bpd exports in 2013 is Egypt. The country’s trade is mainly with European refiners and Asian buyers, although its position atop the Suez Canal and Suez-Mediterranean pipeline give it a strategic interest in the burgeoning energy trade between Asia and Africa.
Despite a spike of 31,000 bpd in 2012, US imports from Egypt are marginal at 4000 bpd, or 2% of exports, in 2011 and 2013. The lion’s share of oil, 56% in 2013, is sold to Europe, with India and China also 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 seen as gas-producing. In 2013 Sinopec bought a 33% stake in Apache’s Egypt upstream oil exploration and production business for $3.1bn. This was followed by massive new gas discoveries by BP and Eni, which should give the country a significantly larger chunk of global gas production over the long term.
“While there is definite potential in unconventional oil and gas – [the Egyptian] government hopes to replicate the success of the US in the space – there is still a lot of conventional to be developed,” Thomas Maher, general manager of Apache Egypt, told OBG. “That said,we hope to unlock the potential in the large Apollonia chalk tight reservoir in the Western Desert.”
Natural gas has provided stability to gas producers’ income, as a growing number of North and sub-Saharan African LNG producers have expanded exports, while Algeria has fed the European pipeline system through its connection to Spain. Algeria and Libya have been exporting LNG as early as 1964 and 1971, respectively, with Egypt’s first LNG facility coming online in 2004.
Nigeria ranks as Africa’s largest LNG exporter, with 27.2bn cu metres in 2012, outpacing Algeria’s 15.3bn cu metres (alongside its exports of 19.5bn cu metres via a pipeline to Italy and Spain), Equatorial Guinea’s 4.89bn (through Equatorial Guinea LNG [EGLNG]) and Egypt’s 4.34bn – although this has shrunk in recent years on the back of increasing domestic consumption (see analysis).New exporters in the continent’s south are adding significant new capacity – Angola’s terminal at Soyo started shipping in 2013, while Mozambique and Tanzania will join the ranks of gas exporters by 2018.
While North Africa’s pipelines have traditionally tied them to the Middle Eastern and European markets, new LNG exporters have sold overwhelmingly to Asian buyers. While Asian oil firms have shown an appetite for equity stakes in these projects, most LNG terminals in Africa remain the preserve of Western oil majors. Asia already accounts 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 accounting for the balance.
Gas producers have been eager to sell to an Asian market where natural gas prices 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, suppliers have been locked into long-term off-take agreements, yet 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 unit in 2012, compared to $11 in Germany and $3 in the US, according to Platts. While Japan’s emergence as the world’s largest LNG importer following the post-Fukushima nuclear shut-in from 2011 has driven Asian prices, the outlook is less certain. Analysts broadly concur that the tripartite market for natural gas is tending towards convergence, driven by significant new LNG exports from Australia and shale gas from the US and Canada.
With such extensive structural changes in global energy markets underway, African producers are faced with a difficult balancing act. Under fiscal pressure, governments will need to expand output if prices for light sweet crude or for gas come under sustained pressure.
The prospect of shale may prove enticing to several states named in a 2013 EIA report on global shale resources that found large gas reserves in South Africa with 390trn cu feet (scfd) of recoverable gas and Algeria with 707trn scfd, while Morocco and Egypt are also hoping to jumpstart exploration. But while many producers 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 or to further explore their territories. Countries will have to work to develop these resources in the coming years.
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