The landscape of onshore exploration and production (E&P) joint ventures has shifted considerably in recent years. Nigeria and Angola, the two most mature oil players in Africa, have witnessed the most mergers and acquisitions (M&A) on the continent of late, according to Standard Chartered. With some 2.2bn barrels of oil equivalent (boe) sold by international oil companies (IOCs) to indigenous players in the four years to 2014, local independents are now taking on an even larger role in production, accounting for 10% of aggregate output. Some forecasts see this figure reaching 25% in the next five years.
As IOCs have managed their portfolios more actively and rebalanced towards deepwater developments, a new generation of smaller Nigerian producers is increasingly investing to optimise production, partly urged by the Nigerian Petroleum Development Company (NPDC), which has sought out technical and financial partnerships with private firms. The new operators have been greeted with eagerness by local and foreign investors, who appear keen to support emerging indigenous firms through both debt and equity. Such moves have been complicated by the fall in oil prices, however, which dropped below $50 a barrel as of early 2015. In February 2015, for example, the Nigerian National Petroleum Corporation (NNPC) reduced its capital expenditure for joint venture oil operations by 40%, from $13.5bn to $8.1bn.
Recent Divestments
Successive governments have long sought to support the growth of domestic oil and gas firms, but it has only been with IOCs’ recent divestments that their share of oil production has expanded. The awarding of some 50 marginal blocks through discretionary allocations in the 1990s, another 24 through the sole marginal fields bidding round in 2003, and 60 more blocks through conventional bidding rounds in 2005 and 2007, have together handed control of over 100 blocks to Nigerian operators. Yet by 2013 only nine of these marginal fields were producing, accounting for around 2% of total oil production out of the 10% produced by local players, according to research by Ecobank.
The bulk of local producers’ output has come from divestments by IOCs, prompted by unrest in the Delta region and a renewed focus on deepwater offshore developments. Shell in particular has been a driving force behind the divestments, with its goal of selling $15bn in assets worldwide by 2016 to fund future E&P plans. “A number of these IOCs are moving into more challenging frontiers in the deep offshore and are leaving the onshore blocks, which they consider less profitable,” said Diezani Alison-Madueke, minister for petroleum resources in the outgoing Jonathan administration, in May 2014. “In addition, some of them have been sitting on the oil blocks and have allowed the acreages to go fallow for years without significant development.”
Onshore Sales
IOCs led by Shell Petroleum Development Company (SPDC), a joint venture between Shell (30%), Total (10%), Eni’s Nigeria Agip Oil Company (5%) and the NNPC (55%), sold eight onshore blocks between 2010 and the end of 2012. While M&A activity included some deepwater stakes in foreign-to-foreign transactions – including Total’s sale of 20% in the Usan floating production, storage and offloading facility on oil mining licence (OML) 138 to Sinopec’s Addax for $2.5bn and Petroleo Brasileiro’s sale of half its Nigerian ventures to Brazilian bank BTG Pactual for $1.5bn, both in 2013 – most activity involved selling onshore blocks to local independents.
This was not the first sale of an under-used marginal field. SPDC sold its gas-rich Uquo field on OML 13 to Frontier Oil in 2009, and finalised its first block sale in January 2010 when the three IOCs sold a combined 45% stake in OMLs 4, 38 and 41, which at the time had total proven reserves of 135m barrels and output of 16,100 barrels per day (bpd), to Seplat for $340m. In November 2011 followed the sale of a 45% stake in OML 26, with reserves of 18.3m barrels and production of 2700 bpd, to First Hydrocarbons Nigeria (now 54.8% owned by London-listed Afren) for $147.5m, as well as a stake in OML 42, with 126m barrels and production of 9000 bpd, to Neconde Energy for $585m. SPDC’s next round of sales came in August 2012, when OML 34, with reserves of 182m barrels and production of 29,250 bpd, was sold to ND Western for $600m, and OML 40, with 30.6m barrels in reserves, was sold to the Elcrest consortium for $154m. The largest of these deals came in November 2012, when a joint venture between Shoreline Power and London-listed Heritage Oil bought a 45% stake in OML 30, with reserves of 456m barrels and production of 15,665 bpd, for $850m.
Domestic Investments
The local players making ambitious moves have benefitted from international support through both debt and equity, especially from foreign independents and oil traders. Established in 2009, Seplat sold a 45% stake to French independent Maurel & Prom in 2010 and then 6% to Swiss oil trader Mercuria, before staging a dual listing in London and Lagos in April 2014, selling a 25% float for around $500m. Meanwhile, local oil firm Aries E&P, a subsidiary of the Yinka Folawiyo Group, teamed up with local contractor Nestoil and Polish firms Kulczyk Investments and Kulczyk Oil Ventures in the Neconde joint venture. ND Midwestern was a venture between Niger Delta E&P and Swiss upstream investor Petrolin and Waltersmith Petroman, partheld by Canada’s Petroman. The Elcrest venture involved London-listed Eland Oil & Gas and Starcrest Energy, backed by Emeka Offor, while Shoreline Natural Resources involves locally owned Shoreline Power and London-listed Heritage Oil, acquired by Qatar’s Al Mirqab Capital for $1.4bn in April 2014.
Older marginal field operators have also drawn foreign participation. Seven Energy, Frontier Oil’s technical and financial partner on the Uquo field, raised $150m in equity from Singapore’s sovereign wealth fund Temasek in April 2014 and another $105m from the International Finance Corporation. “Nigerian E&P companies are increasingly restructuring their governance to meet global standards as they seek to access offshore investment,” Ladi Bada, managing director and CEO of Shoreline Natural Resources, told OBG.
Local Production
Total local production is forecast to reach 300,000 bpd by 2015, according to the Federal Ministry of Petroleum Resources (FMPR). Some 50,000 bpd will come from marginal field operators like Brittania-U, Energia, Frontier Oil, Movido E&P, Waltersmith Petroman and Excel E&P, which all received licence renewals in 2013. Yet the bulk of new production is expected to come from divested blocks. “Typically divested oilfields that have been acquired by independents tend to invest more to boost production,” Toba Akinmoladun, executive director of the Oil Producers’ Trade Section of the Lagos Chamber of Commerce and Industry, told OBG.
Seplat has seen the sharpest output increases thus far, doubling production to 60,000 bpd on its three blocks by the end of 2013. Shoreline, whose production rose to 40,000 bpd by the end of 2013, aims to reach at least 65,000 bpd by the end of 2014. The NPDC’s increase from 60,000 bpd to 140,000 bpd during the divestment process was achieved by exercising operatorship rights on all divested blocks other than Seplat’s, rather than by boosting production.
More Momentum
In one of the largest deals in sub-Saharan Africa in 2014, ConocoPhillips in July finalised a $1.65bn sale of four blocks, OMLs 60-63, to local integrated oil and gas firm Oando. A deal of similar size was completed in March 2015, when Shell divested its stake in OML 29, the Nembe Creek Trunk Line and other interests in the eastern Niger Delta to Aiteo Eastern E&P Company for $1.7bn. Total, with only one gas-rich onshore block, and ExxonMobil, with no community relations issues in its operations, are unlikely to follow suit, but SPDC is offering OMLs 18, 24, 25 and 29 for sale, as well as the key onshore Nembe Creek Trunk crude pipeline to Bonny as part of OML 29. While initial appraisals put the total value of the four blocks – which together produced 70,000 bpd in 2013, or 10% of SPDC’s output, according to Wood Mackenzie – at roughly $3bn, eager bidding by local independents has pushed the price up.
A consortium of local oil trader Aiteo and Taleveras won OML 29, with 2.2bn boe, for $2.5bn in May 2014. The Erotron consortium, involving local operators Midwestern Oil & Gas, Mart Resources and Suntrust Oil, won the OML 18 block, with 1.5bn boe, for a reported $1.5bn. The two smaller blocks, OML 24 and 25 with reserves of 803m and 157m boe, respectively, were awarded to Pan Ocean and Crestar – with reported but unconfirmed bids of around $500m. The winning bidders beat competition from Dangote, Sahara Energy, Seplat and other previous divestment bidders, but also consortiums involving Swiss trading houses Glencore and Mercuria.
Looking Ahead
Although Chevron had offered its 40% stake in five onshore and shallow-water blocks in 2013, its award of three of these, gas-rich OMLs 52, 53 and 55, was delayed due to legal battles, while sales of OMLs 83 and 85, with a combined 160m boe, were still pending as of early 2015. Although the five blocks are expected to fetch some $1.5bn, according to Ecobank, the legal uncertainty highlights the need to consider not only bid size but also technical capacity and regulatory approval. The court case centres around Brittania-U’s $1bn bid for OMLs 52, 53 and 55, which, though the highest offer, was declined in favour of a lower bid by Seplat. With the case ongoing as of early 2015, further asset sales by Chevron have been put on hold.
While prospects for domestic oil and gas producers are bright, with their share of output set to reach 25% by 2017 according to the FMPR, the new operators’ ability to boost production is not yet clear. The divestment process itself can be fraught, as shown by Chevron’s case. Yet in the long term, new investment by IOCs is likely to move toward deepwater projects, while local players will need to optimise onshore production through advanced recovery techniques.
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