As Africa’s largest oil producer, Nigeria’s energy sector accounts for 90% of exports and at least 50% of government revenues. The country is second only to Libya on the continent in the size of its reserves, and onshore fields have been productive for decades. Offshore deposits are a frontier that has been massively underexplored, and in recent years international oil companies (IOCs) have started to refocus their efforts there.

That has left an opening on land, which local start-ups have filled. New and smaller indigenous companies are buying up onshore blocks from the global giants, investing in fresh capacity, and increasingly shaping the sector and its future. Under President Muhammadu Buhari the government has also taken an aggressive approach to reforming the current regulatory framework and state oil company, to plug leakages and reduce dysfunction both upstream and downstream.

Moving Forward 

It is widely agreed that these reforms are needed. A pending Petroleum Industry Bill (PIB), which has been on the table since 2007 and that ostensibly will provide a thorough – and updated – overhaul for the sector, has yet to pass the parliament, with the resulting uncertainty reducing foreign investment. For example, the country ranked 40th out of 58 nations surveyed in the most recent edition of the Resource Governance Index, a measure of the quality of oversight for natural resources created by the Natural Resources Governance Institute (NRGI). At the Nigerian National Petroleum Corporation (NNPC), the state-owned corporation in control of energy, there have been 16 different managing directors in 38 years, for example. The agency that shares regulatory powers alongside the NNPC, the Department of Petroleum Resources (DPR), suffers from the same type of leadership turnover, with seven directors in the seven-year period ending in 2015.

The overall impact has been lower-than-optimal levels of production for the country, which have failed to meet peak production targets. In addition, a lack of investment in downstream and midstream facilities has resulted in a continued need to import the majority of finished petroleum products. Currently Nigeria’s domestic petroleum industry produces less than 10% of the petrol consumed in Nigeria. This is partially due to the fact that refineries can be erratic in their output, which is a result of a period of poor maintenance.

Policy uncertainty and a rise in violence from militants in the oil-rich Delta region, have also contributed to output losses. Attacks on infrastructure by militants have reduced production in a range from 100,000 bpd to 300,000 bpd in recent years, but the total has at times climbed as high as 500,000 bpd. Long-term concerns about production are on the rise however, and in April 2016 the energy consultancy Wood Mackenzie said it expected average daily output at 1.5bn bpd over the coming decade.

Refinery Investment 

Despite the challenges, breakthroughs do appear imminent. Nigeria has long aimed to boost the use of crude petroleum products in its domestic market rather than export them raw, and refinery investment is seen as having wide-reaching benefits. “In the long run, investment in refineries would bolster the government’s fiscal standing, as it is expensive for the country to import refined petroleum products,” Felix Amieye-Ofoki, CEO of Energia, told OBG. Several investments are under way that could get the country started down this path, including Dangote Group’s $14bn, 650,000 barrels per day (bpd) refinery, fertiliser and petrochemicals complex that is under construction in the Lekki Free Trade Zone. The Dangote plan also involves a shallow offshore pipeline being developed in partnership with First Exploration & Production (E&P). The pipeline is likely to have spare capacity for other buyers, making Lekki an important emerging industrial zone.

Oil Reserves & Production 

Nigeria had 37.1bn barrels of proven reserves of crude oil at the end of 2015, or 28.5% of the total for Africa, according to BP’s “Statistical Review of World Energy 2016”. This put it second on the continent only to Libya, with 48.4bn barrels, while the only other African countries above 10bn are Algeria at 12.2bn and Angola at 12.7bn. Nigeria’s output in 2014 averaged 2.19m bpd, down from 2.193m bpd in 2013, according to NNPC figures. According to BP, Nigeria was the 12th largest producer worldwide, accounting for 2.2% of global production. The reserves-to-production ratio suggests that at the current pace of extraction, given no additional discoveries, Nigeria would be able to produce for another 43 years, according to the BP “Statistical Review of World Energy 2016”. In December 2015 Emmanuel Ibe Kachikwu, then group managing director of the NNPC and now minister of state for petroleum resources, said production would average 2.1m bpd, rising to 2.4m bpd in 2016.

Gas Production & Reserves 

Nigeria’s 180.1 trn cu feet (cf) of natural gas, or 5.1trn cubic metres, accounted for 2.7% of global reserves at the end of 2015, according to BP’s figures. This is the 9th-highest total worldwide, and the largest in Africa. Production hit 2.52 trn cf in 2014, according to the NNPC, up from 2.32trn in 2013. Nigeria was the 14th-largest producer, with a 1.1% market share. At current rates of production, proved reserves would last for more than 100 years.

Regulatory Framework 

Perhaps the single most important government body in the energy sector, and the country’s largest state-owned enterprise, is the NNPC. Created in 1977, the NNPC’s powers include oversight of the sector as well as participation in it, through joint ventures (JVs) with the private sector and through its ownership of the national oil company, the Nigerian Petroleum Development Corporation (NPDC). However, the NNPC is not the only body with regulatory powers. The DPR, which is a part of the Federal Ministry of Petroleum Resources (FMPR), issues licenses and ensures compliance with rules and regulations. Also under the ministry is the Department of Gas Resources, which regulates gas. Another important body is the Nigerian Content Monitoring Board, which supervises compliance with local-content requirements in hiring, procurement and other issues.

The sector falls under the purview of the FMPR, which is currently headed by Buhari, a reflection of his government’s prioritisation of sectoral reform. Kachikwu, formerly of ExxonMobil, was appointed as minister of state for petroleum resources and group managing director at the NNPC in 2015. Kachikwu spearheaded an extensive process of restructuring at the NNPC, including laying the groundwork for an eventual break-up of the company into separate entities, before he was named chairman of the board, a move that saw him replaced as managing director in July 2016.


At the exploration phase companies apply to the NNPC for oil prospecting licences, which are then converted into oil mining leases if blocks yield commercially viable reserves. Formally, the consent of the minister of petroleum resources was required to assign either an exploration or production licence. The most recent bidding round for major acreage was completed in 2007, although much of what was awarded was revoked because the round had taken place in the months before an election, and the administration of Umaru Yar’Adua, the former president, decided to pause and review recent deals across the sector and elsewhere in the economy because of corruption concerns. New bidding rounds are not expected before the issue of the PIB is settled.

At the production stage there are two types of arrangements: JVs with the NNPC and production-sharing contracts (PSCs). Though not in every case, JVs generally are used onshore and in shallow-water fields and PSCs are for offshore acreage. JVs with the NNPC have often come with difficulties when there are cash calls – when a company asks existing stakeholders for more money for an investment – as the NNPC has on a number of occasions been unable to meet these requests, in part due to the frequent delays experienced by Nigeria’s budgeting process.

Under both the JV and PSC structures, royalties are due to the government when production starts. Onshore the rate is 20%. The royalty charged offshore varies, falling as water depth increases. For example, in shallow water a royalty of 18.5% is due, and 12% is charged between 201 metres and 500 metres. At 1 km or deeper the rate is 0%. Whether in an onshore JV or with an offshore PSC, companies must pay a petroleum profits tax (PPT) at a rate of 65.75% in the first five years of production, rising to 85% thereafter. However, offshore at a depth of 200 metres or more, the rate falls to 50%, although historically this number has varied according to when the contract was signed. Producers also pay 3% of their annual budgets to the Niger Delta Development Commission, which can be deducted from the PPT. Overall, the government’s effective share of energy-sector profits is currently estimated at approximately 65-75%.

Under the PIB, various interpretations suggest that this share would increase to anywhere from 72%, according to the government, to 96% according to the Oil Producers Trade Section of the Lagos Chamber of Commerce, which estimates production and investment would slump under such terms. While fiscal incentives and crude-oil prices will in part determine investment levels, another important factor is gas infrastructure.

IOCs holding offshore acreage have been delaying making investment decisions on projects that will require pipeline and processing upgrades. The NNPC’s Gas Master Plan has for years been the road map for gas development, which is centred around three major processing facilities and an expanded network of pipelines. For now, within the broader plan, the NNPC has prioritised four pipelines, two processing plants and an industrial park called the Gas Revolution Industrial Park.

Local Transfers 

Nigeria’s marginal fields policy means that blocks held by IOCs that either lay fallow or have small production profiles may be redistributed to domestic companies. In 2003, 24 of these fields were moved in a bidding round. In total 31 marginal fields have come under the control of local companies, which are defined as those who are at least 51% locally owned. When marginal fields are reassigned, the new rights holders typically get five years to push them into production or enter into a farm-out agreement with the original IOC holding the rights to that contract. As part of these agreements the new holder of the field pays a royalty to the previous one. The government may allow extensions on the initial five-year period, which it did for all of the holders of the 24 fields awarded in the 2003 bidding round.

Upstream Profile 

Most onshore acreage in production is owned through seven JVs that the NNPC has established with IOCs. They accounted for 58% of total production of oil, gas and condensates in 2014, according to the NNPC’s annual statistical bulletin. The largest single upstream producer is ExxonMobil, with a 22% share of total upstream output. Production-sharing contracts, which mostly govern offshore projects, accounted for 31% of total output. In this category Chevron is the biggest producer, at 7% of the total. Smaller independent producers, who are mostly local companies, produced 6% of all output in 2014, led by the NPDC, at 4%. Producers in marginal fields yielded 4% of output, with Midwestern Oil & Gas providing slightly more than half of the total. The share held by independents and locals is also on the rise, said Dolapo Oni, head of energy research for Ecobank, a regional lender based in Togo. “There’s going to be more blocks for sale, but the process will not always be public,’’ he said. “Some companies could privately invite people to buy.”

The largest single sale to date from an IOC to a local firm was completed by US major ConocoPhillips when, in June 2014, it sold its entire acreage in Nigeria to Lagos-based Oando for $1.5bn. Oando now controls 46,700 bpd in output, and has said it intends to push that total to over 100,000 bpd by developing the existing fields and through making additional acquisitions. Most IOCs have divested stakes in some or all of their onshore blocks, and while not all of them have publicly announced their intentions, more blocs are expected to be on offer. Though it is unclear how many blocks are available for sale or will be in the near future, reports in Lagos as of March 2016 had at least three IOCs each looking to sell off multiple blocks, either by publicly inviting offers or soliciting them privately.

A Good Mix 

The trend of local ownership on land and IOC focus on the deep offshore is seen as a good fit in Nigeria because deep-water exploration and production is more complex and capital intensive, and thus a better match with the profile of the IOCs. From the perspective of IOCs, relinquishing smaller onshore blocks means reducing their engagement through JVs. Smaller onshore blocks are considered a better fit for local players still in the process of building up their capacity and capital, and are seen as a catalyst for investment.

IOCs are generally looking for large-scale opportunities, so the smaller scale production and investment needs of these marginal onshore fields are better suited to local companies. This is also seen as better for maintaining local community relationships, particularly given the history of poor local stakeholder and community relations in the oil sector. One example of investment catalysed through local ownership can be found in the state of Akwa Ibom, where the Uquo field was discovered by Shell in 1958, but never entered into production. It was awarded to Frontier Oil in 2003, which later teamed up with another growing local company, Seven Energy, to extract the gas and find a market for it.

Many of the smaller non-associated gas fields in particular were not developed in previous decades, and the gas that they generated was generally flared off, but natural gas is now seen as the preferred feedstock for conventional power plants in Nigeria. Indeed, Seven Energy’s subsidiary Accugas spent $600m developing the Uquo Gas Processing Facility, which has a capacity of 200m standard cu feet per day (scfd) – enough to create almost 1000 MW in power generation.

This local group also built two pipelines in order to carry out gas-supply agreements with two electricity-generation plants in the region. Supply commenced in January 2014, according to the companies. In Nigeria’s best-case scenario developments such as Uquo could be used to better leverage the gas produced in the country, which is often still flared instead of used. In 2014, 289.6bn cu feet of gas was flared, representing 11.5% of the total gas produced during the year.


Onshore pipelines in Nigeria are owned and operated by the NNPC’s subsidiaries: pipes carrying crude oil and fuels are owned by the Pipelines and Product Marketing Company (PPMC) and gas pipes are owned by the Nigerian Gas Company (NGC), which lists 12 major pipeline systems.

In total the NGC operates 1250 km of pipe, ranging from 4 inches in diameter to 36 inches, with a collective capacity above 2.5m scfd. However, pipes can also be concessioned to private entities, or constructed through JVs with the NNPC on a build-own-operate basis. For example, local firm East Horizon Gas delivers gas on long-term contracts through a section of the NNPC’s pipelines for which it has operating rights. Ownership of East Horizon was passed from Oando to Seven Energy in a 2014 transaction worth $250m.

There is one international pipeline, the West African Gas Pipeline (WAGP), a 678-km route that exports natural gas west along the Gulf of Guinea, with the offtakers being government electricity-generation companies in Benin, Togo and Ghana. The pipe has been filled to only a fraction of its capacity of 474m scfd since it was commissioned in 2011, and a lack of supply has caused complications in consumer countries.

Export Destinations 

The sale of Nigerian hydrocarbons is evolving due to the disruption of traditional trade links, a result of a rise in unconventional oil and gas production in the US. Shale output is similar to Nigerian crude in sulphur content and gravity in that it is light and sweet, which has resulted in a significant drop in exports to the US. Before 2012 the US relied on Nigeria for between 9% and 11% of its crude, but that level dropped to less than 1% two years later.

Nigeria’s emphasis has shifted east. India is the main destination for crude oil, while for liquefied natural gas (LNG) it is Japan, particularly since the Fukushima nuclear incident of 2011. Exports of both crude and condensates to China and European countries have also shown growth overall between 2011 and 2015, as per statistics from the UN Conference on Trade and Development.

Oil Sales 

The NNPC’s share of crude production finds its way to market through two subsidiaries: PPMC and the Crude Oil Marketing Division (COMD). The PPMC is responsible for the allocation of 445,000 bpd intended for domestic refineries. However, because the refiners are unable to process all the crude, other arrangements have developed. One of these is a system by which the PPMC enters into contracts with downstream providers to swap it for finished petroleum products. These systems have been changed under the new administration, in hopes of ending a recurring billing problem, as it was reported that swap companies had been delivering less product than contracted.

The COMD handles term contracts, in which commodities traders lift crude and resell it globally. The NNPC’s allocation of oil output generally amounts to half of production, and in 2014 just 10% of its share was sold to end users, with much of the remainder going to traders. According to a study by the Natural Resource Governance Institute (NRGI), Nigeria is the only major producer with a stable government that sells its crude through traders as opposed to directly to end users. The annual contracts to lift crude are given to companies ranging from major global trading houses such as Switzerland’s Trafigura and Vitol to lesser-known domestic entities. A study the NGRI conducted in conjunction with the Berne Declaration, a Swiss advocacy group, found that from 2011 to 2013 $55bn of a total of $254bn in oil sold went to Swiss trading houses. The NRGI’s and other audits of the NNPC export-sales system have found significant discrepancies in the data. Two contracts with Vitol, for example, entitled the company along with a Bermuda-based entity called Calson that it owns together with NNPC to receive a total of 60,000 bpd in 2012. However data show it bought 145,000. In another example, from 2011 to 2013 a company called Arcadia did not have a term contract but lifted crude 19 times.


Accounting discrepancies such as these eventually led to depressed revenues reaching the national Treasury, and an investigation in 2014 by the Central Bank of Nigeria accused the NNPC of failing to fully remit revenues. Those claims were initially denied, but then the debate later moved to the question of exactly how much has gone missing, with estimates ranging from roughly $10bn to $50bn. The end result was a partial audit of this segment of the NNPC’s process, which was performed by PwC. Discrepancies in that report involved the NPDC, whose revenue figures vary by $820m depending on the accounting used. By examining COMD data, PwC’s audit found that approximately $5.65bn was unaccounted for.

However, PwC’s report also suggests that dysfunction in the energy sector is not entirely the fault of the NNPC, citing the example of kerosene. Subsidies for the fuel were ended via presidential directive in 2009, but this change was never published in the Official Gazette, leaving the legal status of the subsidy unclear. The NNPC continued paying a portion of the cost of this fuel, spending $3.38bn in the period under audit. In addition, Usman Mohammed, managing director of New Energy Services Company, told OBG that “broadly speaking, the laws that govern the energy sector are sound, but the enforcement of the rules and the lack of penalties have created problems for the industry.” Local content policies have also some received praise from Eric-Stephane Georges, group executive director at Jagal Energy, who told OBG that they ”have been successful in providing a platform for investment in Nigerian firms and people”.

Gas Sales 

For natural gas, the export system is simpler: gas is either piped through the WAGP or sold via Nigeria LNG (NLNG), a JV between the NNPC, Shell, Total and ENI that accounts for 7% of global LNG supply, according to Shell. NLNG has six trains, and a seventh has long been proposed but not decided on. In April 2016 Babs Omotowa, managing director of NLNG, told local media of a new plan – rather than build one new train with a capacity of 8.7m tonnes per annum the company would copy the structure of train six, which would mean two new trains at 4.3m tonnes per year each.


Nigeria consumed 305,000 bpd of petroleum products in 2014, but modern energy solutions account for just a small minority of total final energy consumption, pegged at 4500trn British thermal units by the US Department of Energy. The burning of traditional biomass and waste accounted for 80% of the total, including wood, charcoal, manure and crop residues. About 80% of natural gas consumption is for electricity generation, with the balance going to heavy industries such as cement and steel.

Domestic refining capacity is the main factor shaping the downstream energy sector. If the country’s four main refineries could operate at full capacity they would meet domestic demand and end the need for large-scale imports. The combined capacity is 445,000 bpd, not counting a 1000 bpd topping plant owned by the NPDC, but for years actual production has been far below half of that level. For large parts of 2015 there was no output at all, according to Karim Belkaid, managing director of Entrepose DBN, a French-owned engineering, procurement and construction firm. In previous years, the combined utilisation rate has hovered around 22%, according to the US Energy Information Administration. The market for imported petroleum products has contributed to the controversies of recent years, including accusations in 2012 that some fuel importers were overbilling or delivering less than they claimed.

Reviving Refining 

Boosting refining capacity has meant a fresh round of invitations to the private sector to develop capacity, a repeat of licensing rounds in the past, as well as fixing existing facilities. “The government’s first action was to address the refineries,’’ Belkaid said.

The refineries need rehabilitation in large part due to a problem Nigeria has seen before – insufficient public sector spending for the ongoing maintenance of existing assets. The refinery at Warri is considered to be the most problematic: it is in need of maintenance and is still suffering lingering damage from fires in the past, according to Belkaid. It has a capacity of 125,000 bpd. Those at Kaduna (110,000 bpd) and Port Harcourt (210,000 bpd in two facilities located in the same complex) are considered to be easier fixes. Yet ensuring that the refineries can run at full capacity would not solve the whole problem, as continuing attacks on the pipelines that feed them are also an obstacle.

For the long term, privatisation is a solution that has been explored by the government and supported in the private sector. Putting these assets in the hands of investors could mobilise investment. This line of reasoning led to the privatisation of electricity assets in 2012 and 2013, but it remains unclear if that privatisation process, which is still under way, will deliver those results. Moreover, the pool of investors may be limited, due to limited access to finance and profit challenges.

Key Factors 

According to Ainojie Irune, head of corporate communications at Oando, upstream margins are wider, at roughly 18% compared with about 2% downstream. “In the last 15 years margins have dwindled downstream,’’ Irune said. “It’s a lot of work for very little money.” Energy entrepreneurs in Nigeria have already spent $3.2bn in purchasing downstream power assets, with $2.9bn through bank loans. Still more has been spent on acquiring upstream blocks, with banks in those deals also serving as a source of capital. One question as of early 2016 was whether banks are willing to finance more transactions in the energy sector (see Banking chapter), given that loans in the oil, gas and power sectors accounted for roughly 40% of total bank debt as of March 2016. Another factor that will affect the amount of crude in the market is the Dangote Group refinery, which will add 650,000 bpd of capacity and as of mid-2016 was expected to be operational by 2018. It is unclear whether Dangote’s refinery will have a legal obligation to supply products to the domestic market, but it is expected to include an export element.

At The Pump 

Prices for consumer fuels are set in a mixed regime, with diesel and other common products unregulated, but petrol and kerosene tariffs still controlled by the state. Prices consumers pay for the latter are typically set below the cost of import, with the state making up the difference by paying licensed importers set rates.

The NNPC’s Petroleum Products Pricing Regulatory Committee (PPPRC) was created in 2001, and in addition to generating the monthly formula for pricing petroleum products, it maintains the pipeline network that sends fuel from the domestic refineries to storage depots across the country.

Fuel subsidies are a contentious topic in Nigeria, as they are in many African markets. The subsidies place a strain on the government’s budget and the IMF has consistently advised the country to cancel them, a view shared by many investors who see the distortions as impacting sustainability and cash flow. “The NNPC should get out of the way and let the market work,” said Cyril Odu, CEO of African Capital Alliance, a pan-African investment firm based in Lagos. Nigeria spent more than N1trn ($3.2bn at time of printing) in 2015 defraying the costs users pay for fuels, equivalent to 31% of retained revenue. However, popular sentiment holds that subsidised fuels must not be taken away. Nigeria made headlines worldwide in January 2012, when an attempt to end the petrol subsidy led to mass street protests. They ended only when the state backed down and partially restored it, resulting in a price of N97 ($0.31) per litre at the pump.

Some industry players hold that the complete abolition of the subsidy would have a positive effect overall. “The full removal of fuel subsidies could free up capital for support programmes in education and agriculture,” Nuhu Yakubu, group CEO of Banner Energy, told OBG.

However, in reality Nigerians are not always able to access petrol at the regulated price, as periodic scarcities send buyers into the black market. Furthermore the system has been prone to abuse, with fuel importers in the past having defrauded the government through overbilling, or according to a government investigation in 2012, by importing fuel at a lower rate and then smuggling it into neighbouring markets to sell. The government pegged daily consumption at 35m litres daily, but imports were billed at a rate of 59m litres per day.

Given the low oil prices in world markets, as of mid-2016 a new regime was announced that featured a price cut. Under the new system retail stations owned by NNPC have been selling petrol at N86 ($0.27). The NNPC has said that the state plans to end the subsidy, and the federal budget, passed in March 2016, did not allow for any spending on consumer fuels. Indeed, the state’s plan as of early 2016 was to phase out the subsidy.

Some officials have also spoken in support of a full deregulation of prices. “The question is what will really help or hurt people,” said Bismarck Rewane, CEO of Financial Derivatives, a Lagosbased investment firm. “Buhari’s advisors are telling him that poor people in the north will suffer more than poor people in the south if fuel prices were completely deregulated. But with the current system and the shortages it creates, they are still paying more on the black market.”

Change & Continuity 

In July 2016, Kachikwu formally stepped down as group managing director of the NNPC, handing over that leadership role to Maikanti Baru. The newly appointed Baru immediately rolled out a revised 12-point programme for the NNPC, which included addressing the cash call arrears owed to IOCs by the NNPC and ensuring that the federal government is relieved of the burden of meeting the cash call obligations. Baru has pledged to continue Kachikwu’s work, focusing on undertaking a holistic reform of the NNPC and the Nigerian petroleum industry as a whole, while also prioritising existing infrastructure deficits across the sector. Kachikwu, meanwhile, has stated that a number of substantial milestones were met during his term, and expressed optimism that the NNPC would continue along its reform path. Some of the notable achievements accomplished in 2015-16 have included the overall restructuring of the NNPC, the deregulation of the downstream segment of the petroleum industry, a revamping of the country’s refineries and a focused push to bring the NNPC into profitability.


Under the current government, a number of substantial moves have been planned – all of which, if executed, could significantly modernise the hydrocarbons industry for one of the world’s largest producers. Among the proposals currently on the table are the NNPC’s future size, role and scope, a vote on the PIB, and the future prospects for the refining segment. Yet while the state still retains a major role, both in regulatory matters and upstream and downstream production capacities, private capital is increasingly pushing the sector forward. Whereas in previous years policy uncertainty and poor governance in the public sector had slowed spending, the rise of indigenous producers and the announcement of major projects like Dangote Group’s $14bn complex have demonstrated that the case for investment is strong even though certain fundamental questions remain outstanding. Going forward, the key priority for the Buhari government remains transforming the NNPC into a cost-effective, profit-driven and transparent institution that works effectively with private players.