Think of the huge Zohr gas discovery offshore Egypt’s Nile Delta, the huge gas resources found in the deep waters off Mozambique, the significant Ugandan oil reserves still untapped in Africa’s interior and the oil and gas prospects being appraised offshore Mauritania and Senegal. All involved skilled geologists using the latest technology, but essentially represented an astute bet that reserves would be found outside Africa’s traditional producing centers of Algeria, Angola and Nigeria. Some companies in certain countries have found the sweet spots: Eni in offshore Egypt, Eni and Anadarko off Mozambique, UK-based Tullow Oil in Uganda, and U.S. independent Kosmos in Senegal/ Mauritania. For others, offshore Namibia and Liberia for instance, the quest has been elusive. Meanwhile exploration capital expenditure, pruned significantly in 2014-15, is only slowly recovering.
Egypt's Zohr and deepwater Mozambique
The big value transactions of 2016-17 can be seen as paybacks for yesteryear. They include Eni’s 2016 divestments of stakes in its own discoveries: 10 percent and later 30 percent of the supergiant Zohr field offshore Egypt to, respectively, BP (USD 525 million) and Russian giant Rosneft (USD 1.6 billion) plus a 25 percent interest in Mozambique’s offshore Area 4 for USD 2.8 billion to ExxonMobil, announced March 2017 though still to be completed. At Zohr there is additional potential upside for Eni in that BP and Rosneft have options to buy a further 5 percent equity each in the supergiant field—in which case Eni’s equity stake in Zohr will fall to 50 percent. Eni as operator expects Phase 1 of Zohr to begin producing at 1 billion cubic feet (bcf) per day later this year, less than 30 months after its discovery, increasing to 3 bcf/d by late 2019, which will enable Egypt to generate gigawatts of power from local gas. Zohr has 30 trillion cubic feet (tcf), or 850 billion cubic meters (bcm) of gas in place and its full development could cost partners USD 12 billion. While there have been earlier farm-downs offshore Mozambique, the last 18 months has seen only ones by Eni in Area 4, with partners in Anadarko-operated Area 1 sitting tight on their 75 tcf (2.1 tcm) recoverable gas resources. Area 4’s resources are 85 tcf (2.4 tcm), of which Eni will retain a 25 percent interest even after the sale to Exxon is complete. Rosneft and Exxon, meanwhile, remain partners in 3 deepwater licenses acquired in Mozambique’s 2015 licensing round.
Senegal and Mauritania, evolving mining and production
BP agreed to pay USD 916 million in cash and carried expenses in late 2016 to Kosmos in return for roughly 30 percent interests in the latter’s six Senegal/Mauritania offshore blocks and a share in the Tortue deepwater floating LNG venture that is expected to take a Final Investment Decision (FID) in 2018 and export its first LNG in 2021. There is further upside for Kosmos in the BP transaction if oil prices rise. Greater Tortue holds 25 tcf (708 bcm) of gas at 100 percent equity, says Kosmos, with a potential increase to more than 50 tcf (1.41 tcm) of gas. This May, Kosmos announced the Yakaar-1 gas discovery of 15 tcf off Senegal—potentially enough for a second Floating Liquefied Natural Gas (FLNG) project with BP—calling it the largest hydrocarbon find in the year to date. Kosmos had a shortlist of four bidders during its 2016 offer to farm down these interests, from which it eventually chose BP both on price and suitability criteria. The bidding contest shows the strong interest that Senegal/Mauritania has elicited. But there have also been disputes. Australian independent Woodside acquired ConocoPhillips’s 35 stakes in 3 blocks offshore Senegal for USD 350 million in mid-2016. A year later, junior partner Australia’s FAR referred Conoco to international arbitration, alleging Conoco failed to follow correct pre-emption procedures. An arbitration ruling is due mid-2018. Cairn, operator of the 3 blocks, has since made its eleventh consecutive oil discovery—all at or near its first find, the SNE field. So, the region has become a hotspot, with firms like Total and China National Offshore Oil Corp (CNOOC) stepping up their involvement in nearby acreage.
Chinese eyes look towards East Africa
Another substantial farm-in was undertaken by Total in Uganda, but it was later pre-empted by partner CNOOC. Tullow agreed in January 2017 to farm-down 21.57 percent of its 33.33 percent interests in the oil-rich Lake Albert project covering areas 1, 1A, 2 and 3A in Uganda to Total for USD 900 million, which would have given the French company a majority 54.9 percent stake in the acreage. But two months later, in March 2017, CNOOC exercised its pre-emption rights under the joint operating agreements between Tullow, Total and CNOOC to acquire half of the interests being transferred to Total in Uganda on the same terms—thus denying Total its majority stake in the venture. Tullow, which will still net USD 900 million, is expected to transfer its operatorship to Total upon completion later in 2017. Lake Albert oil, is a much-anticipated project. Tullow has discovered some 1.7 billion barrels since 2006 and has already raised USD 2.9 billion in 2010-12 by bringing in Total and CNOOC as partners. FID was expected this year. The pre-emption by CNOOC may slow that slightly, but neither Tullow, Total nor CNOOC want to lose the momentum from Uganda’s April 2016 announcement that it will help develop a USD 3.55 billion, 1,445 km oil export pipeline to the port of Tanga, northern Tanzania. Meanwhile, Malaysian state Petronas is rumored to be eying a sale of the onshore oil field stakes, which it acquired from Conoco in 2012-13 for USD 1.75 billion.. Indonesia’s national oil company Pertamina in late 2016/early 2017 wrapped up the purchase of French independent Maurel & Prom for USD 1.1 billion, a deal that included its Gabonese oil and Tanzanian gas production. Chinese investor China Great United Petroleum conditionally offered in late June 2017 to buy UK-listed San Leon Energy, whose main asset is an onshore Nigerian field stake, for over £0.3 billion.
Europe still remains at the window
Conoco quit Senegal to pay down debt, and European firms have taken similar actions. Shell’s USD 54 billion acquisition of BG, completed in early 2016, led it to announce plans to divest USD 30 billion of assets, one of which was oil production in Gabon announced for sale in March 2017 to U.S. Carlyle Group’s upstream arm CIEP for USD 854 million, including USD 285 million debt. Key BG assets that Shell has retained for now, though, include its 60 percent interest in Tanzania’s gas-rich blocks 1 & 4. However, there have been unconfirmed reports that Shell might be seeking a buyer for its Tunisian E&P gas assets. In May 2017, Carlyle said its part-owned Neptune Energy business is in detailed talks with France’s Engie to acquire the latter’s 70 percent stake in Engie E&P for USD 3.9 billion, most of whose assets are in Europe or Asia. Engie will retain about half (currently 65 percent) its E&P interest in the Touat gas field development of southwest Algeria, due to start production jn 2018 and plateau at 4.5 bcm/year. The sale of Maersk Oil, announced this August by Danish parent AP Moller-Maersk to Total for USD 7.45 billion in a share and debt deal, is scheduled to be completed in the first quarter of 2018. While most (85 percent) of Maersk’s Oil assets are in Europe, it has stakes in Anadarko-operated oilfields onshore Algeria and also the Chissongo oilfield offshore Angola where Maersk (operator, 65 percent) chose in early 2016 to defer development. Total CEO Patrick Pouyanne hinted his firm may be better placed to proceed with Chissongo, as Total "operates 40 percent of Angolan production" and has "a strong relationship with Sonangol."
Uncertainties remain regarding the Western front
A deal struck in August of 2015 collapsed in 2016: the USD 1.75 billion sale by U.S. independent Cobalt of its 40 percent stake in Angolan oil and gas-rich deepwater blocks 21/09 and 20/11 to state Sonangol. In May 2017, Cobalt referred the case to arbitration and is claiming USD 2 billion damages from Sonangol. BP this July wrote down an Angolan gas find, Katambi, and stakes in the same Cobalt blocks by USD 750 million, as it saw no prospects for any near-term commercial development. Nigeria, like Angola, has seen its oil and gas revenues fall steeply since 2014-15 and has also been afflicted by 2016-early 2017 militant attacks in the Niger Delta region that stalled a much hoped-for influx of private investment into new gas-fired power plants. This happened just as falling LNG export prices were giving producers more incentive to sell gas into the domestic market, where prices were firming.Unlike Angola, Nigeria retains a resilient private sector E&P base, and this has soldiered on during the lean times. This summer, U.S. giant Schlumberger agreed to commit USD 700 million of investment to oilfields operated by Nigeria-owned First E&P. Nigeria’s Seven Energy is now in talks over a possible acquisition of UK-listed Savannah Energy’s exploration assets in neighboring Niger.
The LNG situation and the midstream sector
One interesting industry development was Schlumberger’s July 2016 decision to farm into a joint venture, OneLNG, that seeks to develop low-cost gas reserves into LNG. Golar LNG will retain a majority 51 percent interest in OneLNG, but Schlumberger will provide capital and own 49 percent equity. Golar’s particular appeal is that it has pioneered a floating LNG (FLNG). a new approach to liquefying and thus monetising stranded gas, a process especially useful in Africa where large onshore liquefaction projects and expansions over the past decade have all stalled. In autu million 2017, as a ship provider, it will launch Africa’s first FLNG venture offshore Cameroon, a project operated by UK-French firm Perenco. In late 2016, OneLNG and UK independent Ophir signed a shareholders’ agreement to jointly develop a FLNG project offshore Equatorial Guinea dubbed Fortuna, with OneLNG holding 66.2 percent and Ophir 33.8 percent. No cash transaction was reported, but expenditure on Fortuna FLNG will be roughly USD 2 billion, with OneLNG expected to carry at least its equity share. FID is due later this year for a planned 2020 start-up, and it will be Africa’s second FLNG venture (following Cameroon) and ahead of Eni’s 3.4 million mt/yr Coral FLNG offshore Mozambique that took FID this June but will not start exports until 2022. Africa is also seen as a promising place for floating LNG import schemes based on Floating Storage and Regasification Units (FSRU) and maybe later LNG-to-power projects. Ghana has three such FSRU projects to import LNG, but two are stalled, including one for more than 15 months. Total hopes to launch an FSRU-based venture in Cote d’Ivoire in 2018 with six co-investors including Shell and Azeri state Socar. Egypt has operated FSRUs since 2015, chartered from ship owners Hoegh LNG and BW Gas, but it will probably not retain these engagements post-2020, as it will have more than sufficient indigenous gas once the giant Zohr starts production later in 2017 and ramps up steeply in 2019. At the oft-jilted Kudu gas field offshore Namibia, Singapore-based shipowner BW Offshore is to decide this 4th quarter 2017 whether to earmark one of its floating production vessels (FPSOs) to develop gas that would be piped ashore to generate electricity in Namibia for export to South Africa. BW would earn a 56 percent interest in Kudu, with state Namcor keeping 44 percent of all previous stakeholders having exited Kudu as uncommercial. Namibia is eying LNG imports based on an FSRU if Kudu fails.
Asset deals in the field of refining
Glencore announced October 6 a proposal to buy a 75 percent interest in Chevron’s South African downstream oil joint venture that includes a 100,000 b/d refinery at Cape Town for $973mn; the deal – replacing an earlier planned sale to China’s Sinopec that stalled – would also give Glencore a downstream presence across South Africa and neighbouring Botswana. Total also expanded its filling station network in East Africa earlier in 2017 through a much smaller transaction.