We have identified five main themes that will be critical for the African Oil & Gas sector throughout 2013, as they will determine the performance of the continent during the rest of the decade:
We see increasing interest in West African subsalt exploration by major international oil companies (IOCs) as it becomes more evident that the large unexplored offshore acreages contain significant potential.
We continue to see increasing gas potential on the continent. On one hand, many developments concerning liquefied natural gas (LNG) facilities are taking shape over 2013, with Angola marking a milestone with its first shipment in June 2013 to Brazil; on the other, we are increasingly bullish on east African gas frontier, where we forecast annual gas production reaching 9.7bn cubic metres (bcm) in Tanzania and 19.5bcm in Mozambique by 2022.
Unconventional exploration and production (E&P) is gathering momentum with 'hotspots' South Africa, Libya and Algeria raising the scope for much upside in gas and oil production from shale. Africa is also a region rich in frontier opportunities with exploration activities accelerating in Senegal, Namibia and Madagascar for example.
We maintain our view that productivity in the African downstream sector will remain insufficient to match the growing refined products demand on the continent, with Kenya potentially becoming a major refining hub in east Africa. We observe that growing gas-to-liquids (GTL) opportunities on the continent could help monetising gas riches not currently marketed.
2012 has been marked by extensive activity by IOCs and national oil companies (NOCs) and expectations the largely unexplored acreages off African coasts will eventually yield substantial resources.
On the west coast, exploration and production (E&P) activity has continued to soar following reinforced beliefs that resources matching the Brazilian subsalt plays could be found on the corresponding side of the Atlantic margin. The most striking result remains Cobalt Energy's large subsalt discovery in the Cameia field on Block 21 offshore Angola in February 2012. The 2011 deepwater subsalt licensing round in Angola's Kwanza basin was also quite successful, as 11 blocks were allocated to IOCs such as Eni, Statoil, ConocoPhillips, Total and Petrobras. Further south, w hile no reserves have yet been proved, Namibia's offshore prospects and subsalt potential pose large upsides for its hydrocarbon s sector, with independent Chariot Oil and Gas planning an extensive drilling campaign for 2014 ( see 'Chariot's See-Saw Rolls Explorer Sentiment,' June 20 ).
In August, a consortium formed of Total, Cobalt and Marathon announced another subsalt discovery offshore Gabon, encountering some 50-55m of net hydrocarbon pay. The sub salt potential of the Diaba licensee is untested, but Harvest Natural Resources reported a sub-salt discovery at its' Dussafu Tortue Marin-1 (DTM-1) wildcat well at the beginning of the year that generated significant excitement regarding Gabon's deepwater potential (see, 'First Subsalt Hit In Decade Marks Step Forward', January 7).
According to consortium partner Cobalt, source rocks offshore Gabon are geologically similar to Angola, whose subsalt potential is more proven and where the IOC has an active portfolio of interests. While oil was not encountered, a hydrocarbons strike does help to de-risk further drilling and with a number of prospects already identified including the Diaman South prospect, the trio are unlikely to be short on opportunities to improve their success.
These discovery are not currently included in our forecasts as no final investment decision has been made and activity remains in initial exploration and appraisal stages (E&A). Therefore, we see African oil production peaking in 2020 at around 11.72mn barrels per day (b/d). Nonetheless, we see that subsalt prospects pose a very large upside risk to our forecasts.
| Waiting For A Subsalt Revolution |
|Africa Oil Production, Consumption (LHS) & Net Exports (RHS), 2010-2022|
The North American shale boom is forcing changes in the African oil market . Increased o il production in the US and cheap crude prices are cutting demand for crude imports, with African producers hit particularly hard by the slump in demand from what was once a key customer. We forecast that oil production in the US will continue to grow throughout the rest of the decade. Therefore, we expect African export s to the US to continue following the downtrend that has been in place since 2009.
| Substitution Effect |
|US Imports of Crude Oil From Africa, 000s b/d|
The critical point of this observation is that African exporters will need to redirect their supplies to alternative market if they are to avoid suffering from a detrimental trade balance effect. If supplies were redirected to Europe, where we forecast demand to be stagnant, we could see downward pressure on Brent, reducing the profitability of exports. Instead, we believe that Africa is likely to play an increasing role in fuelling Asia's soaring crude oil demand. We see Asia's net oil imports growing from 20.8mn b/d in 2012 to 27.mn b/d in 2022.
We highlight that the relationship between Africa and Asia is mutually beneficial, with high stake interests being played out. In particular, state owned Chinese companies have been at the forefront of investment in both the upstream and regional downstream markets:
More investment has been seen in Africa's upstream than in the downstream segment, as crude oil and gas in the region complement Asia's large downstream, power and manufacturing industries. As East Africa continues to produce new discoveries of gas in massive quantities, Asia's growing gas demand is set to see its companies, particularly state-owned ones, continue to lend financial firepower to develop the region's raw gas potential with a view to exports. Not only would it ensure supply security, it could also allow these firms - who are often also importers of oil and gas - access to cheaper resources.
Downstream investment is more commonly restricted to Asian NOCs, which are more interested in diversifying their market exposure and operations beyond their home market, than private companies, which find little appeal in Africa's still-limited domestic market for refined oil products.
There are, however, instances which highlight the risks associated with the rise of Asia. In particular: the willingness of Asian NOCs to spend vast sums of money for a share of upstream assets has led to cost inflation that has priced out IOCs; A presence in areas IOCs that have been more reluctant to enter has exposed Asia's oil and gas companies to greater risks; and the rising presence of China in Africa has provoked a backlash in some markets, (see 'Asian Money Complements Hydrocarbon Riches' August 7).
East African Gas Boom
On the east African coast, IOCs have repeatedly discovered additional gas reserves in countries such as Tanzania and Mozambique. Eni confirmed the discovery of new reserves offshore Mozambique , pushing the total estimate of the country's recoverable resources from 2.6 6 tcm to 3. 68 tcm ( s ee ' Eni's Newest Strike Reaffirms Regional Potential ', March 3 ) .
Eni's latest discovery at the Agulha well in Area 4 in September 2013 has opened up a new play and more importantly produced wet gas from the well. Eni calculates preliminary estimates of the discovery to be 140-196bn cubic metres (bcm) of gas in place. Drilling success offshore Tanzania continues as well, with both BG Group and Ophir Energy reporting the Pweza-2 appraisal well intersected some 20 meters (m) of net gas pay on Block 4 at the end of August. The drillship will now move to spud the Pweza-2 well in a further test of the Pweza field, where gross recoverable resource estimates are now some 47.6bn cubic meters (bcm).
Mozambique's large reserves will make it the dominant player in the region, with our forecasts suggesting that Mozamb ique's total gas production by 2022 will reach 19.5bcm, with significant upside risk associated to this. Tanzania will be about half the size, with annual production reaching 9.7bcm by 2022.
| Heavyweights Rise |
|Tanzania And Mozambique Natural Gas Production Forecasts|
Rising interest in east African gas creates momentum for the development of a number of liquefied natural gas (LNG) project s . Several companies have suggested such developments in Mozambique, including Eni and Anadarko Petroleum . Both firms are targeting first gas from their proposed LNG terminals from 2018. However, an absence of infrastructure and a dearth of skilled labour or a supporting service industry could slow the advance of LNG projects as they work their way through Mozambique's nascent regulatory framework (see 'Infrastructure Required To Service East Africa Gas Potential' , August 2 2012 ) . Demand for East African LNG exports could be easily met as Asia - in particular China and Japan - become s increasingly dependent on gas imports.
We have factored in LNG export capacity in both countries, with Mozambique forecasted to begin exporting 6.9bcm in 2020 and this to rise to 13.8bcm in 2021. Tanzania's LNG capacity is forecast to come online in 2022, with 6.6bcm capacity annually.
In West Africa Angola exported its first cargo of liquefied natural gas (LNG) in mid-June. The inauguration of the Angola LNG terminal will support a significant reduction in the gas flaring, which is as high as 7bcm per annum. With the first cargo heading toward Brazil, we could see growing ties in gas trade between Angola and the Latin American giants, (similar to the ties East African countries are looking to establish with Asia) as the latter is reportedly seeking to increase regasification capacity in an effort to diversify away from hydropower.
However, Chevron's recent exit from the OKLNG project in Nigeria is threatening President Jonathan Goodluck's gas strategy as the project is now at risk of never be ing completed. The Brass LNG terminal is more likely to be move forward but we remain cautious given that numerous above ground risks are likely to create concerns for foreign investors as feedstock for the terminal could be disrupted.
Revealing Untapped Potential
The US Energy Information Agency's most recent global report on unconventional resources underscored the scale of the world's untapped resource potential. Among the country's to see a big upward revision in estimates of technically recoverable shale gas resources was Algeria, which saw a jump from an estimates 6,400bcm in 2011, to 19,800bcm in the report released June 2013. Libya's technically recoverable shale oil resources are the fifth largest globally at 26bn barrels.
Unconventional resources pose significant upside to countries in Africa and would allow producers to tap new volumes that could shore up exports and help meet rapidly rising domestic demand. For countries with limited hydrocarbons potential (such as Tunisia or Morocco), unconventional resources could unlock new sources of production to ease import burdens and - if large enough - could do so, by utilising existing export infrastructure. We highlight the opportunities presented by unconventional resources and their scope to be de- risked given the existing export links in North Africa, and South Africa's proven capacity to produce synthetic fuels; but we also underscore that infrastructure and fiscal and environmental challenges will impact efforts to tap Africa's shale gas.
Additional opportunities in Africa could also come from numerous underexplored frontier plays. The East African islands are one example. Earlier in 2013, Austria's leading oil and gas player OMV announced plans to purchase a 40% stake in the Grand Prix block offshore Madagascar from Niko Resources (35%) and EnerMad Corp (25%). This farm-in to a deepwater block in Madagascar makes it likely that prospective Morondava basin will see drilling by early 2015 given the technical and financial resources of the Austrian player.
Similarly, the West African frontier begins to hot up as Cairn Energy outlines its latest drilling programme to target the offshore of Morocco and Senegal. In its half year report announcement, the company shared its plans for its latest 12 month frontier exploration drive with a focus on West Africa. This move is well founded considering the high prospects for the West African coast. Initial investigations suggest Moroccan geology resembles that of the Scotian margin in North East Canada, which has seen successful gas finds in the Sable and Deep Panuke fields.
We expect the Moroccan wells to have a high probability of successfully finding hydrocarbons, and believe this is why they will be the first targeted in Cairn's drilling programme. Strong upside it therefore anticipated for Morocco's oil and gas sector, however potential discoveries will unlikely be of considerable size (estimated at between 50-200mn barrels of oil equivalent).
Senegal appears to hold more exploration risk as the conjugal margin of the country, east coast Florida and Georgia, also remains an unproven hydrocarbon province. The country also found oil in the 1960s. The Dome Flore field on the border with Guinea-Bissau is thought to hold as much as 1bn barrels of oil equivalent providing evidence of petroleum systems in the country. However, the oil discovered is very heavy, 10° API, making it challenging and costly to extract. Cairn is targeting 1.1bn barrels of unrisked oil from the two planned exploration wells.
Fuelling Development: The Downstream Race
Africa's refined product consumption is set to soar for the rest of the decade as population and GDP growth accelerate. We forecast that refining capacity on the continent will fail to match this increase, forcing countries to re-import their crude production once refined.
The failure of Africa's downstream capacity to keep pace with rapidly rising demand is reflects the failure of governments to attract necessary investment into a market with huge potential but uncertain prospects for profitability. The disincentive comes from the combination of widely used fuel subsidies and an uncertain political environment. For instance, Nigeria - the continent's top oil producer and fifth largest refiner - has repeatedly failed to pass on subsidy payments to downstream players who charge consumers at the agreed discounted price. Such events result in much uncertainty for foreign investors and force countries to rely on downstream state-owned companies, thus worsening the business environment. Another example is Egypt, which is seeking to cut fuel subsidies, thereby contracting demand and concentrating downstream activities in the hands of national companies.
| Africa's Total Oil Refinery Capacity & Oil Consumption |
With worsening fiscal conditions, t he principal source of funding for new downstream developments ov er the next decade is likely to be development loans - most likely Chinese. This could push regional refining capacity slightly higher , but the expansion is likely to lag fuel consumption growth markedly. Refined product import dependence is therefore set to grow , putting further pressure on fiscal accounts. This may force more governments to follow Nigeria and Egypt's lead in reforming fuel subsidies.
Refining is also fuelling the debate around monetising the oil reserves of Uganda. Tullow Oil 's discoveries in Kenya in July 2012 have already prompted doubts about the relevance of building a large capacity refinery in Hoima , Uganda . Although the impasse between IOCs and Ugandan officials over construction of a refinery now seems to have progressed to the point at which first oil is now insight, the conflict highlights the risks to downstream projects in Africa which we have noted ( see, 'Refinery Compromise : A Small Victor For Upstream Development,' April 16 ).
Kenya seems to have favourable geographical location to progressively become e ast Africa's refining hub due to its easy access to the se a . Providing the LAPSSET project between South Sudan and Kenya is completed , with an associated 120,000b/d refinery, Kenya is already in a strong position to attract crude from the region (see 'LAPSSET Moves A Step Closer To Reality' , February 5 2013 ). Further discoveries in the country would only confirm that view , yet at present, there seems more downside risk than upside to Kenya's refining capacity with the threat that the East Africa's only refinery could close under the pressure of cheaper imports as the plant's competitiveness further deteriorates ( see 'Region's Only Refinery May Close As Shortfall Worsens,' June 14 ).
Small upside could also come from development in the Gas-To-Liquid (GTL) sector . Africa is favourable to such technological experiments since a large proportion of its gas resources are being vented or flared. According to a report by local newspaper, The Guardian Nigeria, the long awaited Escravos GTL project will come on-s tream before the end of 2013 . The project, 75% owned by Chevron Nigeria Limited (CNL), 15% by Nigerian National Petroleum Corporation and 10% by Sasol , was originally due to be operational in 2010 at a cost of US$3bn. However, c osts for the project have also escalated considerably to the latest revised amount of $9.5bn.
Technip and Sasol have also forged an alliance with regards to the front-end engineering of potential future GTL projects. The partnership, which builds on prior cooperation, will allow Technip to participate in the execution stages of the projects. The move underlines the growing interest in GTL technology and the increasing likelihood of the application of the technology in new regions.
Continued disruptions to Libya's oil supply underscore the extent of above ground risks that continue to stymie the sector's recovery. Despite an impressive recovery to near post-war output levels in the wake of the 2011 civil war, production has struggled in recent month in the face of protest and security concerns in a country where the government in Tripoli still struggling to enforce its mandate across the country.
While Libya had planned to increase output to around 1.7mn b/d in Q313, that target now seems out of reach. Indeed a recent statement from state owned National Oil Corporation confirmed that as a result of disruptions, output had fallen below the 1mn b/d mark with operations hit at export facilities and Eni 's 130,000b/d El Feel field. While clashes between armed groups have been a consistent threat to operations, regular protests have disrupted fields, midstream infrastructure and export terminals.
We expect protests by oil field workers and other disaffected groups will continue to target the oil sector given the growing realisation that such as will garner attention given its importance to the Libyan economy. Moreover, with security forces still not yet up to the job of protecting vital infrastructure, such facilities are set to remain vulnerable for the time being. Militias that have been contracted to guard oil facilities are armed and increasingly making more vocal demands for jobs and benefits.
Officials from the NOC are increasingly spending time and resources engaged in dispute resolution with disgruntled militias, oil field workers, and local leaders pressing for jobs and investment. To date, supply disruptions in Libya and elsewhere have failed to significantly impact Brent prices, with markets well supplied and more concerned about demand. However the impact has been felt locally, with oil minister Abdulbari Ali al-Arousi telling the Financial Times at the end of April that around US$1bn had been lost over the past five months.
Given the above - ground risks that show little sign of dissipating, we have a conservative forecast for growth in Libyan oil output. Without an improvement in security, the oil sector is set to face continued disruptions in a blow the country's economy.
In an announcement that underscores our continued caution, Sudan again threatened to halt the export of South Sudanese oil. On June 8th, Khartoum threatened to close its pipeline's to South Sudan's oil unless Juba ended its alleged support for rebel groups. Oil production only restarted in March after a 16 month halt following long-standing tensions between Sudan and newly independent South Sudan. The row now seems defused, with both countries pledging to work together in the future and a shut-down averted, but In short, these events support our cautious outlook to the sector.
While we see limited potential for an impact on Brent prices from another halt to supplies, the impact of another production shut-in the oil-dependent economies of Sudan and South Sudan would be dramatic. We expect the above ground risks in the region to remain high, with tensions fuelled by decades of civil war and unsettled political questions.