With increasing support from the government, local exploration and production (E&P) firms are expanding their share of output and prospects. International oil companies (IOCs) have gradually been retrenching their positions onshore and in shallow waters, selling over $7bn in combined assets over the past three years to both local firms and relatively new entrants from China. “The awarding of marginal fields to indigenous oil companies and the divestment by IOCs from some of their onshore assets has been broadly positive for local players in terms of building their capacity, credibility and expertise,” Ladi Bada, CEO of indigenous E&P firm Shoreline Natural Resources, told OBG.
The government is preparing new allocations of marginal fields, with associated incentives, for domestic players, even as it seeks to build up the Nigerian National Petroleum Corporation’s (NNPC) E&P subsidiary, the Nigerian Petroleum Development Company (NPDC), into a national champion. As local funding needs grow, there will be opportunities for both equity and debt investors on the domestic and international stage.
MARGINAL FIELDS: Successive governments have long sought to encourage local equity participation in the hydrocarbons sector. Fields left undeveloped by IOCs for 10 years see their licences automatically revoked, in a “use it or lose it” policy, before being farmed out to local firms. These “marginal fields” were typically allocated on a discretionary basis, although IOCs could also sell their stakes to Nigerian firms directly, circumventing the Department of Petroleum Resources (DPR).
In 2003 the administration of then-president Olusegun Obasanjo held the first and so far only competitive marginal field bidding round, awarding 24 fields to 31 local firms through a normal bidding process. The awarding of marginal fields came with fiscal incentives: royalty rates starting at 2.5% for onshore production of below 5000 barrels per day (bpd) and up to 18.5% for more than 15,000 bpd, compared to 20% normally, and a lower petroleum profit tax (PPT) rate of 65.75% for five years rather than 85% for conventional investors.
Alongside fiscal incentives, winning bidders were only expected to pay a $150,000 signature bonus, far lower than bonuses on conventional block tenders in 2005 and 2007 of above $100m. Six of these fields (five in Delta State) have yielded oil production, and the other one produces gas. Pillar Oil’s finds on oil mining lease (OML) 56 were amongst the most substantial increases, boosting proven reserves to 30m barrels of oil and 500bn standard cu ft (scf) of gas, prompting plans to raise output to 4000 bpd by mid-2014.
DISCRETIONARY: In addition to the marginal fields bidding round, a number of discretionary allocations continued, such as NNPC/ExxonMobil’s farming out to Oriental Energy in 2006 and 2007. The operator was awarded the Okwok and Ebok fields – both located in the Mobil-NNPC joint venture (JV) OML 67 around 50 km offshore – in 2006 and 2007, respectively.
While the Ebok and Okwok fields were initially considered to hold proven reserves of a mere 10m and 5m barrels, respectively, and were thus of limited commercial appeal, a work programme has since expanded proven reserves to 100m-150m barrels for Ebok and 225m for Okwok. In 2012, the two fields were producing roughly 35,000 bpd and 15,000 bpd, respectively. The consortium of operators Oriental, Afren and Addax conducted 3D seismic appraisal of Okwok in 2011 and 2012, with an active drilling programme due in early 2014, indicative of the improved capabilities of local operators. “A number of indigenous oil companies have significantly expanded their financial and technical capacities and are operators on land, swamp and shallow offshore fields. Nevertheless, we are still some years away from seeing an indigenous operator of a deepwater offshore field,” Martin Trachsel, CEO of South Atlantic Petroleum (SAPETRO), told OBG.
Financing will be a key determinant of success for local players, according to Tein George, the chairman of Aveon Offshore. “The most successful of the newer indigenous entrants to the oil and gas industry will be those able to access overseas financing. These firms generally have strong backing from private equity or a foreign technical partner,” George told OBG.
DIVESTMENTS: Delays in enacting legislative reform since 2008, coupled with the slow pace of licence renewals and growing insecurity in the onshore Delta region, have prompted IOCs to review their Nigerian portfolios and move towards divesting from a number of stakes, expanding the space for local operators. The first move was made by Shell Petroleum Development Company of Nigeria (SPDC), an onshore JV of NNPC (55%), Shell (30%), Total (10%) and Agip (5%). Between January 2010 and November 2012, SPDC raised $1.8bn by selling stakes in eight of its more than 30 onshore interests directly to local players. However, these blocks, all in the western Delta, were not grouped as marginal fields and incurred conventional tax rates. The successful bidders raised funding from a mix of international and local banks, at an average interest rate of Libor +7.5%.
The first sale in January 2010, of a 45% stake in OMLs 4, 38 and 41, was awarded to Seplat, a JV 45% held by French oil independent Maurel & Prom and 55% by a special-purpose vehicle formed by two local firms, Shebah E&P and Platform Petroleum. With a current production capacity of 23,000 bpd, the consortium expects to expand output to 50,000 bpd in 2013.
London-listed Afren Energy was the next successful bidder via its Nigerian subsidiary, First Hydrocarbons Nigeria (FHN), established in 2009 and 45% held by Afren until the parent company raised its interest to 54.8% in March 2013. FHN was awarded a 45% interest in OML 26 in October 2010 for $98m, which covered the two producing fields of Ogini and Isoko, with combined proven reserves of 184m barrels and production of roughly 6000 bpd, as well as 144m barrels of contingent resources at the prospective Aboh, Ovo and Ozoro fields. A third award came in April 2011 when a 45% stake in OML 42 was sold for $390m to Neconde, a consortium of local firms Nestoil (holding 30% of the JV) and Aries E&P (part of the Yinka Folawiyo group, holding 25%); VP Global representing the interests of local communities (5%); and two Polish firms, Kulczyk Investments and Kulczyk Oil Ventures (each holding 20% of the JV). Producing 20,000 bpd, the field is estimated to hold some 232m barrels of recoverable reserves.
BIG FISH: SPDC ramped up asset divestments in 2012 with the largest transfers to date. In August 2012 ND Western, a consortium of Niger Delta Petroleum, Swiss-based Petrolin and Waltersmith Petroman (a Nigerian vehicle part-owned by Canada’s Petroman), acquired 45% of OML 34 for around $400m. Production stands at 15,000 bpd of oil and 300m scf/day of gas.
Also in August 2012, the Elcrest consortium of local firms Eland Oil & Gas (45%) and Starcrest Energy (55%) acquired a 45% stake in OML 40 for $212m. Eland staged an initial public offering on London’s Alternative Investment Market (AIM) in September 2012, in which it raised roughly $184.08m to fund its share of the acquisition. With proven reserves of 30.6m barrels, the field is expected to start producing oil in 2013 and the partners aim to reach output of 50,000 bpd.
The largest sale occurred in November 2012 when SPDC’s 45% stake in OML 30, comprising eight fields, was sold to local player Shoreline Natural Resources, a JV of Shoreline Power (55%) and UK-listed Heritage Oil (45%), for a landmark $850m. With reserves of 1.1bn barrels of oil and 2.5trn scf of gas, this stands as the largest upstream transaction in sub-Saharan Africa in terms of proven reserves. The partners expect to boost output from 35,700 bpd in 2012 to 100,000 bpd in coming years (and 300,000 bpd eventually) through enhanced recovery techniques and further drilling, alongside up to 30m scf/day of gas. In a separate transaction, Shell has put up for sale another four onshore oil blocks: OMLs 18, 24, 25 and 29. Given the combined work programmes on the SPDC-divested blocks, local oil firms’ share of total production is expected to rise to above 300,000 bpd by 2015. “Indigenous operators’ share of total production is set to increase dramatically from the 10% recorded in 2012,” Bada told OBG.
NATIONAL CHAMPION: Established in 1988 and headquartered in Benin City, NPDC announced plans in 2010 to boost its production from 65,000 bpd to 250,000 bpd by 2015. While the operator has the right of first refusal for the operatorship of all onshore NNPC JVs, it only started to exercise this right during the SPDC divestments, when it took over operation of seven of the eight blocks. While NPDC functions primarily as an operator on these blocks, it also retains stakes in all of them, despite the takeover by local operators of SPDC’s stake. This is because NNPC, through NPDC, still has a stake of around 55% in each of the ventures as they are categorised as JVs. By early 2013 NPDC was the fifth-largest producer with 130,000 bpd, of which 70,000 bpd came from OML 119 alone.
Given NNPC’s chronic funding shortfalls for its stakes in existing JVs, there have been doubts about the operator’s capacity to increase production. To bridge this gap NPDC concluded strategic alliance agreements with two private firms, Atlantic Energy for OMLs 26, 30, 34 and 42, and Seplat for OMLs 4, 38 and 41. Under the deal the private firms second technical, managerial and project staff to NPDC and front NPDC’s share of capital expenditure, receiving a share of production above a baseline level. While these three-year agreements elicited strong criticism from civil society and oil companies, which consider them to be unofficial discretionary allocations, they are the quickest way for NPDC to expand its operatorship and oil production. It remains unclear how such agreements would be affected by enactment of the Petroleum Industry Bill (PIB).
MORE ACREAGE: While local firms’ share of production is expected to exceed 10% in the next two years, they are also positioning themselves to acquire fresh acreage from both divestments by IOCs from onshore and shallow-water blocks, as well as a planned second marginal fields round. Divestment by IOCs is not a formal requirement, but financiers see it as highly encouraged. “The government is making divestments from certain onshore blocks a precondition for the IOCs’ licence renewal, which should generate demand for credit from indigenous marginal field operators,” Kehinde Lawanson, executive director of First Bank, told OBG.
In December 2012 leading local oil and gas firm Oando announced its intention to acquire all of ConocoPhillips’ Nigeria stakes for $1.8bn, and in October 2013 the firm received a $815m loan from a mix of foreign and local lenders to help it complete the sale. The US firm’s 20% onshore stakes in OMLs 60, 61, 62 and 63 represent production of a mere 22,000 bpd, which would boost Oando’s output to 32,000 bpd. Yet Oando aims to attain production of 50,000 bpd by 2015 and 100,000 bpd by 2018, alongside a proven reserve targets of 500m barrels of oil. The sale also includes a 95% stake in OML 131 offshore, a 20% stake in the Kwale-Okpai independent power producer and a 17% stake in the planned Brass LNG project. In June 2013 Chevron announced its intention to divest from its 40% stake in OMLs 52, 53, 55, 83 and 85, all in shallow waters offshore Bayelsa State. As of October 2013, the firm was considering bids on three of the five fields, which have total reserves of about 134m barrels of the 250m total. At the same time, according to local industry sources, ExxonMobil was said to be holding talks with local players bilaterally amidst a review of its onshore holdings.
SECOND ROUND: Aside from IOC divestments, the prospect of a second bidding round for marginal fields is key to local players’ growth prospects. Originally expected after the 2011 elections but since delayed, these would qualify for the incentivised fiscal framework. Local firms estimate the coming round will offer up to 50 marginal fields, with over 90% of these onshore. “We think over 3bn barrels of reserves will be distributed to indigenous oil firms in the coming five years, based on ongoing government initiatives and IOC divestments,” Osam Iyahen, senior vice-president for oil, gas and mining at Africa Finance, told OBG.
However, the DPR will have to revamp its bidding rules before the marginal fields round can be held. According to officials from the DPR, it plans to raise the cost-of-debtor, application and processing fees, although the $150,000 signature bonus will likely remain in place. Far less onerous than the roughly $100m signature bonuses in previous bidding rounds in 2005 and 2007, the smaller amounts are meant to encourage local players to bid. Indeed, a bidder on marginal field assets must be more than 51% owned by a Nigerian entity. According to DPR officials, the next marginal fields round will likely be held before the 2015 election.
The private sector also foresees the potential for downstream investments associated with the new bidding round. “We would not be surprised if the rules for the upcoming marginal fields bidding round include the need for infrastructure investment commitments, particularly in power and rail,” Niyi Yusuf, country managing director at global consultancy Accenture, told OBG. “This is reminiscent of the oil-for-infrastructure deals under [former President] Obasanjo.”
SURE FOOT: While the PIB does not specifically address the role of local E&P firms, these seem less affected by the uncertainty of proposed reforms. Indeed, with NPDC acting as operator on a growing number of blocks, it seems unlikely such onshore blocks would be adversely affected. With relations between local players and host communities expected to improve, the government appears eager to expand their role, particularly onshore and in shallow waters. “This will drive significant funding requirements, and alongside a growing role for private equity we also expect an increase in initial public offerings both onshore and on key exchanges offshore, such as London’s AIM,” Iyahen told OBG. With this growing role, investors both foreign and local will be seeking opportunities to fund indigenous players’ growth.
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