With an abundant supply of natural resources, Nigeria’s oil and gas sector plays a key role in global energy. Its oil deposits have been a major source of crude for decades, while its less developed natural gas fields offer resources that have yet to be fully tapped. In addition to being a traditional heavyweight in terms of output, the energy sector is also notable for its early success in building local content in upstream activity. Policy moves over the past two decades have enabled young firms to acquire and develop oil and gas blocks, build pipelines and distribution networks, and, based on the current project pipeline, refineries as well.
There is still room for improvement, however. Nigeria’s midstream infrastructure is lacking, and while this holds back overall development, it affects natural gas resources in particular. Consumer fuel subsidies have continued to prove problematic, yet efforts to remove them are often met with public outcry. This has left the country simultaneously resource-rich, yet facing chronic shortages of finished products.
Change in the Air
However, a potential change could be coming soon. Dangote Industries, a Nigerian-based business conglomerate, is constructing one of the world’s largest refineries in the Lekki Free Zone near Lagos. Meanwhile, the Nigerian National Petroleum Corporation (NNPC), the state-owned oil company, is working on several fronts to boost domestic refining capacity, including refurbishing the country’s four underperforming refineries and exploring incentive programmes to induce private investors to build new downstream capacity.
Nigeria is the only member of the Organisation of the Petroleum Exporting Countries (OPEC) that imports petrol. The NNPC calculates capacity at the state’s four major oil refineries at 445,000 bpd of crude, which is more than enough to meet domestic demand; however, estimates vary. Neglect and a lack of investment have seen production decline over the years, leading BP to estimate capacity closer to 345,000 bpd. NNPC data shows that throughput has surpassed 100,000 bpd just twice in the past ten years. While a refining revolution would revitalise downstream activities, the sector is also waiting for a legal overhaul to do the same upstream. Forward momentum on this regulatory change, known as the Petroleum Industry Bill (PIB), has stalled as President Muhammadu Buhari’s refusal to ratify it has left potential investors without regulatory guidelines. Additional legislation also proposed disassembling the NNPC into a number of new agencies and parastatals to improve regulatory oversight.
Size & Scope
With an estimated 37.5bn barrels of crude oil deposits at end-2017, representing 2.2% of the global total, Nigeria has the second-largest proven reserves on the continent, behind only Libya with 48.4bn barrels, according to the “BP Statistical Review of World Energy 2018”. Production averaged 1.99m barrels per day (bpd) in 2017, up 4.5% from 1.9bn in 2016, but marking the second consecutive year below 2m bpd, with both figures lower than the previous ten-year low of 2.17m recorded in 2008. Production peaked in 2010 at 2.53m bpd, but decreased for the six consecutive years to 2016. Angola was Africa’s second-biggest producer in 2017 with 1.67m bpd, followed by Algeria with 1.54 bpd.
Proven natural gas reserves, meanwhile, stood at 5.2trn cu metres, representing 2.7% of the global total and the largest reserves in Africa. Natural gas output grew by 11% in 2017 to 47.2bn cu metres and close to the most recent 10-year high of 47.6bn cu metres in 2015. Recent production trends have been less pronounced for gas than for oil, with output totals bouncing between 34.4bn cu metres and 47.6bn cubic metres for the past decade, falling below that threshold just once in 2009.
Oil and gas exploration is ongoing, with major new finds expected in the future, so figures are likely to change; however, if current levels of production and reserves remain constant, the country is forecast to run out of oil in 51.6 years and natural gas in 110.2 years, according to BP data.
The most influential government body in the energy industry is the NNPC, which functions as an operator in the upstream, midstream and downstream sectors; a joint-venture partner to private sector exploration and production companies; and a regulator. The Nigerian Petroleum Development Company (NPDC), a subsidiary of the NNPC, acts as the national oil company. The NPDC currently has interests in 28 blocks, five of which it owns outright and nine of which it has a 55% stake in through joint ventures with private operators. Most regulatory powers originally assigned to NNPC’s Petroleum Inspectorate in the original NNPC Act of 1977 are now exercised by the Department of Petroleum Resources (DPR), which is a part of the Ministry of Petroleum Resources. However, the NNPC still holds considerable authority, including the ability to review and approve the work plans of upstream companies.
On a global level, Nigeria has been a member of OPEC since 1971, and the organisation’s current secretary-general, Mohammad Sanusi Barkindo, is a former top executive at the NNPC.
Another important state body is the Nigerian Content Development and Monitoring Board (NCDMB). Formed through the Nigerian Oil and Gas Industry Content Development Act of 2010, the NCDMB sets minimum thresholds for using local workers and firms for procurement. Operators are required to submit plans to the NCDMB for approval and pay 1% of contract sums to the Nigerian Content Development Fund, which is overseen by the NCDMB.
President Buhari is the minister of petroleum resources but has designated some of the job’s responsibilities to Emmanuel Ibe Kachikwu, the minister of state for energy. Kachikwu also served as an interim group managing director for NNPC until Maikanti Baru was appointed in July 2016.
Both Buhari and Kachikwu put anti-corruption platforms at the centre of their policies. Several reform efforts beginning in 2015 saw increases in transparency through monthly statistical releases and by the reorganising of the NNPC into five autonomous business units: upstream, downstream, refineries, gas and power, and ventures. However, a number of such reforms have been altered or abandoned altogether, such as the monthly reports, which stopped in May 2016.
Illegal back-door activities continue to negatively impact the government by depriving it of revenues from oil and gas, and by tying up promising untapped fields in court procedures. The offshore oil prospecting lease (OPL) 245 field, for example, has been tied up in legal battles since then oil minister Dan Etete sold rights to the block to Royal Dutch Shell and Italian oil company Eni in 2011 for $1.1bn. With an estimated 9bn barrels of reserves, it is one of the largest untouched deposits on the continent, holding as much as a quarter of Nigeria’s total reserves.
Efforts to tackle corruption, however, have made headway, such as the June 2017 decision to end the monopoly of Integrated Logistics Services Nigeria, the service provider at the ports. The decision is expected to give energy companies more control over shipping, increase competition and guarantee a more level playing field for terminal operators.
The government has been considering deeper reforms of the NNPC, the DPR and the broader petroleum sector in general since 2008. After years of deliberations, however, the legislation was partitioned into several bills, each with a narrower scope, in an effort to facilitate its passage after President Buhari was elected in 2015. Legislative changes included in the PIB would see a number of widespread reforms including: first, breaking up the NNPC and establishing a more pronounced division between sector regulators and state-owned operators; second, adding rules regarding petroleum revenue management; and lastly, redefining the terms of engagement and profit-sharing arrangements with commercial energy companies.
The PIB was passed by the National Assembly in 2017; however, in August 2018 President Buhari announced that he would not sign the bill into law, citing that the method for revenue sharing between the regulator and the three levels of government would leave the latter with an unfairly small share. Failing to solidify the legal and regulatory environment is expected to have negative effects on private sector investment decisions, which had been postponed in anticipation of new legal reforms.
Crude output is expected to increase in 2019 as Total’s Egina offshore field begins production in December 2018. The field is notable for its size – production will peak at 200,000 bpd – but also its local content. As an offshore field, it requires a floating production storage and offloading (FPSO) unit, which was built locally at the Lagos Deep Offshore Logistics Base (LADOL) Free Zone, an island shipyard offering logistics and support services for oil and gas exploration. Total initially hired South Korea’s Samsung Heavy Industries and LADOL to build the FPSO unit together. The cooperation between firms was expected to provide an example of how local content could play a major role in the energy sector; however, the contentious relationship between the two companies, as well as allegations of an unsafe workplace, have led to multiple delays since, with ongoing legal actions that could delay first oil.
Crude production peaked in 2005, but has declined since then due to lingering talks over legal reforms and the attacks on sector infrastructure from Delta militants, who damage pipelines or tap them to steal oil and resell it. Opposition to oil extraction from local groups is based on dissatisfaction over environmental degradation and the share of revenue spent on impacted communities.
A programme in place since 2009 has helped by offering militants the chance to surrender their weapons in return for amnesty, job training and cash. However, in 2015 the Buhari administration cut the amnesty payments and sent in the military. This led to an increase in attacks in 2016 and the rise of a new militant group called the Niger Delta Avengers. The actions of such groups pushed oil output from a peak of 2.2m bpd at end-2015 to a 30-year low of 1.4m bpd just nine months later. The government has since decided to reinvest in the amnesty programme, and the 2018 budget included a 30% increase in funding.
International oil companies (IOCs) hold the majority of offshore oil producing fields. Notable fields include Shell’s 60-sq-km Bonga Field in oil mining licence (OML) 118, Total’s Akpo fields in OML 130, and Exxon’s Erha and Usan fields in OML 133 and OPL 222, respectively. State-owned oil companies are also present, such as Norway’s Statoil and China National Offshore Oil Corporation.
In the majority of cases, onshore production comes from joint ventures between the NNPC and private entities, whereas offshore production is governed by production-sharing contracts (PSCs). As of 2016 about 44.6% of crude oil was produced by joint ventures and 47.8% through PSCs. Onshore production costs are $8-15 per barrel, and in terms of offshore production, shallow water costs range from $14 to $18, while deepwater costs can be $30-35.
The trend upstream has been for the IOCs to move from onshore joint ventures to offshore PSCs, as Shell, Exxon and others are doing, or to exit Nigeria, as ConocoPhillips did in 2014. It sold its entire inventory – 46,700 bpd in productive blocks in which it had minority stakes – to Nigeria’s Oando for $1.5bn. The joint venture system mandates monetary contributions from all partners, with the NNPC’s National Petroleum Investment Management Services (NAPIMS) serving as joint venture partner to IOCs.
However, recent years have seen NAPIMS struggle to meet the funding needs of private companies, with total arrears reaching peak levels of $6.8bn in 2016 before being renegotiated and reduced to $5.1bn. The issue is one that the government was hoping to address with reforms, in part because the joint venture approach is also a complication on the operational level, as NAPIMS reviews and approves work plans for joint venture hectarage, and companies often wait for months or more for these plans to be approved. By June 2018 NAPIMS had made full payment on all joint-venture arrears – a move which is expected to increase investor appetite.
The remaining 7.6% of oil production is handled exclusively by a class of domestic start-ups that have ownership of productive or prospective assets. These smaller fields are either bought from IOCs, developed by local entities or transferred by IOCs to locals through the Marginal Fields Programme. In this system, fields explored by IOCs but deemed uneconomic can be transferred to smaller, local companies with lower cost structures, which allows them to make profits from these fields. Those that manage to take this acreage from fallow to productive typically sign a farm-out agreement with the original holders and pay royalties to them.
As of August 2018 there were 14 indigenous oil and gas companies operating Nigeria’s marginal fields – including Seplat Petroleum Development Company and Seven Energy – that have developed pipelines and gas-processing plants and signed long-term gas-supply agreements with power producers. These investments are generally considered as positive for the economy, though they do come with their challenges. Seven Energy, for example, faced a drop in production in mid-2017 due to disruptions at the Forcados Pipeline System, which is the second-largest network in the Niger Delta transporting between 200,000 and 240,000 bpd. In addition, the firm was not being paid by the government for the gas feedstock it was providing to state-owned power plants. The company, which had been struggling to meet its debt obligations, is in the process of being acquired by Savannah Petroleum of the UK.
Anyala & Madu
While most foreign investors have been awaiting clarity on the legal regime before making final investment decisions, one major project moving forward is an offshore joint venture between NNPC and FIRST Exploration and Petroleum Development Company (First E&P), an indigenous firm. The two fields, Anyala and Madu, are expected to produce 50,000 bpd and 120m standard cu feet per day (scfd) of gas once production reaches its peak. The two signed an agreement with global oil services firm Schlumberger in July 2018, in which the latter will finance $724.1m of the total $1.1bn project cost.
The most recent bidding round for marginal fields was held in 2003. The NNPC has been planning a new round for 2019, although blocks with new owners will likely be limited to those making acquisitions. As of July 2018 Shell was reportedly in talks to sell OML 11 and OML 17 for $2bn to Heirs Holdings, a conglomerate headed by Tony Elumelu, Nigerian businessman and former CEO of United Bank for Africa, one of the country’s largest lenders.
The process for block sales is not a rigid one, but approval is required from the Ministry of Petroleum Resources. “We might not see more purely Nigerian deals, but we could see local companies combining with foreign capital,” Amy Jadesimi, managing director of LADOL, told OBG. “It’s difficult to get deals done in Nigeria with foreign capital because there is so much de-risking necessary.”
While refinery capacity has been the controversial topic in Nigeria, its pipeline network remains an important constraint, but also an area in which private investment is already growing. Pipelines in Nigeria are generally operated by the NNPC through its subsidiaries, the Pipelines and Product Marketing Company and the Nigerian Gas Company. The network features roughly 13,000 km of pipes for oil, natural gas condensates and fuels. Various attacks on pipelines as well as breakages and malfunctions created a total loss of N174.6bn ($564.5m) in the period covering 2005 to 2015.
Pipelines can be built or operated by private interests through management contracts or concessions from NNPC. Examples include pipelines built by Seplat Petroleum and Seven Energy to transport gas to power plants, and private networks of gas pipelines to supply major industrial customers in Lagos’ industrial zones. Roughly 500 km of gas pipelines have been built since 2010, including the 196-km ObenGeregu line, the 110-km Escravos-Warri-Oben line, the expansion of the Escravos-Lagos route and an east-west line referred to as OB3. In March 2017 the government awarded a contract to build the 614-km line to bring gas to the northern cities of Ajaokuta, Kaduna and Kano. This route has in the past been considered as the start of a line that would go north through the Sahara Desert and on to Spain, giving Nigeria access to European markets for its natural gas. The line has been proposed as a joint venture between NNPC and Algeria’s Sonatrach.
In May 2018 Dangote Group revealed a five-year investment plan, which will see the construction of the East-West Offshore Gas Gathering System (EWOGGS) undersea gas pipeline, a project the company has been developing with First E&P. At a cost of $3bn, two 550-km pipelines, each with a capacity of 1.5bn scfd, will transport gas from the Niger Delta to the Lekki Free Trade Zone near Lagos. Aliko Dangote is a minority investor in First E&P, and the pipeline is proposed to land near his refinery, petrochemicals and fertiliser plants in Lekki. The EWOGGS project will help transport gas from First E&P, but will also have room for gas deposits from other companies.
Gas is currently exported as liquefied natural gas (LNG) through Nigerian LNG, the country’s sole LNG plant. A joint venture between the NNPC (49%), Shell (25.6%), Total (15%) and Eni (10.4%), capacity at the six-train facility is 22m tonnes per year as of 2018. Efforts to increase capacity to 30m tonnes per year are under way, with front-end engineering and design contracts awarded in July 2018.
The NNPC is the main importer of fuels to Nigeria. Consumption was 50m litres per day as of March 2018, at a daily cost to the state of N774m ($2.5m). Fuel prices are regulated in Nigeria, with petrol pegged at N145 ($0.47) per litre. However, the landing cost of the fuel varies, based on market prices, and is often higher than the pump price. This often leaves the NNPC unable to fully recover its costs, such as in March 2018 when the landing cost was about N171 ($0.55) per litre. The deregulation of consumer fuels is viewed by the government and IMF as necessary to reduce pressure on public coffers (see analysis). The state has also admitted that it is, in effect, subsidising fuel sales in neighbouring countries – because some of what is brought in is later smuggled across borders – as well as propping up large business who consume a greater share of fuel.
Without a resolution for the PIB, the country remains, to some extent, an uncertain investment. However, continued progress on sector challenges could mark a pivotal turnaround for domestic industry. With Dangote Industries’ refinery under construction and state efforts to boost smaller refineries ongoing, we will likely continue to see major downstream development in the medium term. The state has also boosted efforts to resolve the dispute with Niger Delta militants and address corruption with some success. Still, there is ample room for improvement if the country is to take significant advantage of its natural resources wealth. Indeed, some stakeholders have pointed to the Nigeria’s potential in biofuel production “Since Nigeria has immense agricultural potential, there is significant opportunity for growth in the biofuel market,” Bashir Namadina Jega, CEO and president of local energy firm Capegate Group. “Biofuel production and use could reduce dependence on imports and have a positive environmental impact by lowering emissions.”
More Top Reads From Oilprice.com: