As Africa’s largest oil producer, Nigeria is a key member of the Organisation of the Petroleum Exporting Countries (OPEC) and the world’s fourth-largest exporter of liquefied natural gas (LNG). In addition to being a traditional heavyweight in terms of output, Nigeria’s 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 Nigerian companies to acquire and develop oil and gas blocks, build pipelines and distribution networks, and soon, based on the current project pipeline, refineries and power plants as well. There is still ample room for improvement, however. Renewed militant activity in the Niger Delta region – where much of the upstream activity is concentrated – continues to disrupt production, while the country’s regulatory framework is ageing, with a long-awaited overhaul yet to materialise.
Progress on these problems could make 2017 a pivotal year. The government has boosted efforts to resolve the dispute with militants, with some success. Forward momentum on the legislative overhaul, known as the Petroleum Industry Governance Bill (PIGB), has also improved investor confidence. Additional legislation proposes disassembling the Nigerian National Petroleum Corporation (NNPC), the state’s energy company, into a number of new agencies and parastatals to reduce inefficiency and improve regulatory oversight.
The pace of reform of the system has increased since President Muhammadu Buhari took office in May 2015. President Buhari directly assigns portfolios to Cabinet members, and appointed Emmanuel Kachikwu, minister of petroleum resources, to work on restructuring the NNPC with a series of temporary improvements. Some of the government’s proposals have been included in the PIGB, such as the reallocation of roles and responsibilities of the NNPC and the Department of Petroleum Resources (DPR) to a series of successor organisations. The National Assembly’s upper house, the Senate, passed the legislation in May 2017, with the House of Representatives expected to pass a version of the bill, leading to a reconciliation process before it is sent to President Buhari for his signature. A second revenue-sharing bill, addressing profit splits between government and industry, is expected to be passed after the PIGB.
The sector has long been in need of reform. The NNPC has traditionally dominated the up-, mid- and downstream sectors, although its work has been complicated by the fact that in addition to serving as an operator, it also has some regulatory functions. It shares some of these responsibilities with the formal regulator, the DPR. The structure of the NNPC, and a lack of transparency over revenues, has led to major investigations into corruption. The Nigeria Extractive Industries Transparency Initiative alleges that the NNPC owes the federal Treasury at least $21.78bn. Between 2011 and 2015 some $15.9bn in crude oil went missing or is unaccounted for, it said.
A 2015 partial audit by PwC found discrepancies and conflicting numbers in the NNPC’s accounts, arousing suspicions that fuel-import systems were used to funnel cash out of the system and into private hands. The Economic and Financial Crimes Commission also set up a whistle-blower hotline that led to the discovery of $43.4m in an empty apartment in Ikoyi, near the Lagos central business district, and $9.8m being recovered from the former managing director of NNPC. Its own investigations have led to further recoveries of cash.
The sector comprised 10% of GDP in 2015, but revenue from oil and gas generally accounts for about 60% of the annual total. In 2015 it provided 94% of export revenue, and therefore foreign exchange. The shortage of foreign currency has damaged the value of the naira and reverberated through the economy. Oil revenue was worth N8.85trn ($31.3bn) in 2011, and fell to N3.75trn ($13.3bn) in 2015.
Reserves & Production
Proven reserves in both 2015 and 2016 stood at 37.1bn barrels, according to BP’s “Statistical Review of World Energy 2017”. The reserves-to-production ratio was 49.3 years, an improvement on the 43 years cited in BP’s 2016 report, and a reflection of the impact of the security disruptions to the oilfields and pipelines. Proven resources of natural gas were measured at 5.3trn cu metres at the end of 2016, or 2.8% of the global total. The reserves-to-production ratio was 117.7 years.
Crude production peaked in Nigeria in 2005, and has declined since then because of the lingering talks over legal reforms and the attacks on sector infrastructure from Delta militants. Total average daily production – which includes condensates and other natural gas liquids – fell from 2.329m barrels per day (bpd) in 2015 to 2.053m bpd in 2016, according to BP’s data, a 12% drop, despite an exemption from OPEC’s production caps.
There are no major new fields expected to add significantly to production in 2017: a handful will collectively provide another 100,000 bpd, according to market research from Ecobank, a regional bank based in Togo. Overall production of crude is expected to rise from 1.8m bpd in 2016 to 2.2m bpd in 2017, with the government setting a target of achieving 2.5m bpd by 2020. The next major field to begin operation is Total’s offshore Egina, which is expected to produce 200,000 bpd starting in 2018. Gas production was at 44.9bn cu metres in 2016, down 10.6% from 2015.
International oil companies (IOCs) hold the major fields in production in Nigeria, such as Shell’s Bonga, Total’s Akpo and Exxon’s Erha and Usan. State-owned oil companies are also present, such as Norway’s Statoil and China National Offshore Oil Corporation. However, in most but not all 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 2015 about 34% of oil and gas was produced by joint ventures; 42% through PSCs; and 23% through sole-risk arrangements. Onshore production costs are between $8 and $15 a barrel, and in terms of offshore production, shallow water costs range from $14 to $18, while deepwater costs can be between $30 to $35, according to the Ministry of Petroleum Resources.
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 Oando, a Nigerian company, for $1.5bn. “In spite of all the challenges, IOCs will continue investing in Nigeria in order to maintain their operations and keep a foothold in the market,” Barry Ademola, managing director of CNS Marine, a local marine services and engineering firm, told OBG.
The joint venture system mandates contributions to expenses from all equity partners, with the NNPC’s National Petroleum Investment Management Services (NAPIMS) serving as joint venture partner to private companies. However, NAPIMS has struggled to meet the funding needs of the private companies. The total arrears in the joint-venture system had reached $6.8bn in 2016, although by the end of the year a negotiated settlement reduced the amount to $5.1bn. Repayment is now expected to come in the form of crude instead of cash, in a reform meant to remedy the situation.
The issue is one that the government is hoping to address with the pending reforms, in part because the joint venture approach is also a complication on the operational level. NAPIMS reviews and approves work plans for joint venture hectarage, and companies often wait for months or more for these plans to be approved.
Nigeria has seen the emergence of a class of domestic start-ups that have ownership of productive or prospective assets, moving the country closer to the long-held goal of meaningful local content in its chief revenue-earner. Nigerian firms have long been involved in downstream activities like fuel importing and sales, but the rise of domestic primary field operators over the past 15 years marks a new shift, and is unique among the many African economies – including Ghana and Kenya – that have also sought to expand local participation in extractive sectors. “Local content in the oil industry has improved significantly but there is still much scope for growth, especially in energy-related maritime services,” Firas Abboud, managing director of CBU Optimal Services, told OBG.
The local-ownership movement gained significant traction in 2003, when a bidding round was held for marginal fields. Held by IOCs, these fields were either lacking sufficient reserves to prioritise their development, or had gone fallow after a productive period. In 2003 control over 24 of these fields passed to local companies, which are defined as those with at least 51% Nigerian ownership. This allowed new firms to avoid the capital deployments required for new fields and, with lower overheads, turn a profit from lower volumes. One example is the Uquo field, on the eastern edge of the Niger Delta region. It was discovered in 1958, but never developed by its licence-holder, Shell. Lagos-based Frontier Oil won the rights in the 2003 bidding round, and later brought in a peer, Seven Energy, to provide capital. According to a 2014 Seven Energy bond prospectus, the company generated about $4.4m in revenue from Uquo’s gas in the first half of 2014, with a significant revenue stream of $8.8m (for Shell, however, it would have been just 0.002% of the $421bn in global revenue it reported in the period). According to press reports, another marginal-field bidding round is expected in the coming year, although no date or details had been released as of summer 2017.
Domestic companies have also won the rights to upstream hectarage outside the marginal fields programme, for example, through block sales during the previous administration. This helped the IOCs rebalance their Nigeria portfolios to emphasise offshore developments – which are newer and more secure – or to exit the market entirely, like ConocoPhillips. Block sales in the past decade include Shell’s divestment of multiple blocks to Seplat, First E&P and Aiteo Group. The process for block sales is not a rigid one, and deals can be developed privately between IOCs and indigenous companies. Block transactions are, for now, subject to approval from the Ministry of Petroleum Resources, and this has been a cause of controversy in Nigeria as well as a concern for foreign investors, given that the system is open to outside influence.
In these marginal field agreements, an indigenous producer typically has five years to produce oil or gas, or sign a farm-out agreement with the original rights holder. Royalties from production are due to that original holder. The five-year period can be extended, and was for all 24 fields in the original bidding round. In early 2017 DPR announced that seven new development plans for marginal fields had been approved, which could collectively add 155,600 bpd to overall production. So far, 30 marginal fields have been secured by local companies, and 12 are productive. As of June 2017 indigenous companies accounted for about 20% of production, according to Uwadiae Osadiaye, an oil and gas analyst for FBNQ uest, the research arm of First Bank of Nigeria, the country’s largest lender.
Ups & Downs
The overall process of shifting upstream control of smaller fields to local companies has not been without challenges. Seven Energy, for example, faced a drop in production in mid-2017 due to disruptions at the Forcados pipeline and terminal, in addition to not being paid by the government for the gas feedstock it was providing to state-owned power plants. However, the company has been working hard to improve its stability, including negotiating a partial-risk guarantee issued by the World Bank for its gas supply business that should protect it against risks of non-payment for gas it supplies.
Other indigenous companies have also faced challenges. Many relied on debt to make the purchases and are short on investment and buffer capital now. “The local companies need to start deleveraging if they are to stay in the game,’’ Dolapo Oni, oil and gas analyst for Ecobank, told OBG. “The debt-to-equity ratio is probably about 90 to 10.” This has created complications for the banking sector, whose collective exposure to oil, gas and power comprised 26% of loans in the system, Oni said.
In some cases firms have managed to increase output from their fields, although this remains a rarity. Seplat successfully boosted production from fields it took over from Shell. “The local players haven’t yet proved they have technical expertise,” Oni said. “You can’t find many that have increased production.”
At the same time, there have been ancillary benefits to the rise of domestic firms. Part of the rationale for the sale of lower-volume onshore blocks by IOCs is the friction that IOCs have often faced with local communities. Some indigenous companies have managed better relations, Osadiaye said. “Seplat isn’t just giving money to the local chiefs,” he told OBG. “They set up a community board and did a security contract with the locals. Their incentives are now in line with Seplat’s.”
The improved relationship between onshore producers and local communities is crucial, given the impact that supply disruptions can have on production volumes. Successive governments have attempted to reduce insecurity in oil-producing areas. Former President Goodluck Jonathan’s administration, for example, rolled out an amnesty programme for Delta militants, which included demobilisation, job-training components and security contracts to guard oil infrastructure.
The current administration has continued this policy, albeit with some adjustments. Payments previously went directly to recipients, but are now being funnelled through group leaders, and pipeline protection contracts have been cancelled. By early 2016 the number of incidents had risen again, affecting several key infrastructure points, such as the 400,000-bpd Forcados export terminal. Shut-in production had reached 750,000 bpd in May 2016, the highest since January 2009. In response, many firms took steps in 2016 to reduce their reliance on existing infrastructure, moving crude to other terminals on barges, storing it at the refinery complexes in Port Harcourt and Warri, and rerouting it through other pipelines. In May 2017 the government announced extra funding of $111m for the programme, triple the previous budget amount.
The security challenge presents risks beyond attacks on oil sector infrastructure. Oil theft – or bunkering – is also an issue, with the crude oil illegally siphoned from pipelines subsequently being resold into global crude markets or refined domestically in small, illegal refineries. An exact measurement of the scale of theft is impossible given the illicit nature of activity, but estimates are as high as 400,000 bpd.
Nigeria has successfully boosted local content in the oilfield services sector. A number of locally owned providers now operate in the country, providing ancillary support to IOCs and indigenous producers, such as Lagos Deep Offshore Logistics Base (LADOL), a free zone focused on oil and gas services; Nigerian Foundries, a ferrous foundry group; and Oilserve and Elper, both providers of onshore and offshore services in the oil and gas sector. “They’ve been helped by the drop in oil prices,” Amy Jadesimi, managing director of LADOL, told OBG. “When the oil price dropped, the IOCs’ views on local content changed, because all markets in the world where genuine local content has been applied have benefitted from reduced costs.”
During the previous government’s administration the ministry also signed several strategic-alliance agreements with indigenous companies for upstream services, including exploration and production, to help local companies develop expertise. However, some of these were not subject to an open tendering process, which has prompted a proposal in the pending reforms to give an independent regulator the responsibility to approve ownership changes. The offshore market in Nigeria was valued at $12bn from 2010 to 2012, as major IOC projects such as Usan, Bonga and Akpo drove spending. From 2012 to 2014 it was valued at $17bn, but in 2016 a drop in spending was expected, according to the “Nigeria Offshore Market Report 2016-20”. That could change if legal reforms create the conditions needed for new products, with offshore activity jumping in value to potentially surpass $20bn.
The NNPC’s arm for global sales is the Crude Oil Marketing Division, which operates a system in which commodities traders deliver the crude to foreign markets. These contracts go to local companies as well as global giants such as Switzerland’s Trafigura and Vitol. The system is regarded as unique for its use of commodities traders: Nigeria is the only major energy producer that sells to traders rather than to end-users. It also does not maintain a national fleet of crude carriers to ship internationally. The country’s natural gas is exported primarily through Nigeria LNG (NLNG), which is a joint venture between the NNPC, Shell, Total and ENI. It provides 7.2% of LNG in the world market. NLNG operates six trains at its facility in the Niger Delta region.
Roughly 445,000 bpd of the NNPC’s crude allotment is diverted from normal export channels and designated to the four state refineries, at Warri (with a capacity of 125,000 bpd), Kaduna (110,000 bpd) and Port Harcourt (210,000 bpd from two facilities in the same complex). However, the facilities operate at a small fraction of overall capacity; average utilisation was 20% from 2010 to 2015. What the refineries cannot take is handed over to commercial fuel importers in swap deals. They are expected to sell this crude internationally and bring back an equivalent value of end-user fuels. The utilisation rate is low because of poor maintenance, fire damage and transport bottlenecks.
However, the government has made restoring the refineries a priority, partly because Nigeria must import the majority of its processed fuels, and by mid-2017 the utilisation rate had climbed to 30% of capacity. According to Oni, efficiency was also on the rise. From 2010 to 2015 when the average rate was 20%, the typical output was 1.6bn litres of premium motor spirit (PMS).
Most onshore pipelines are held by the NNPC subsidiary Pipelines and Product Marketing Company, but the gas pipelines are operated by another subsidiary, the Nigerian Gas Company. Its network includes 1250 km of gas pipes with a capacity of more than 2.5m standard cu feet per day (scfd). The state can also concede operating rights. Oando developed a midstream gas-distribution company called East Horizon Gas, which delivers gas on long-term contracts to industrial consumers through the NNPC pipelines it had operating rights for. In 2014 Oando sold the business for $250m to Seven Energy, which has continued to develop its midstream gas through a subsidiary called Accugas.
The West African Gas Pipeline is the sole pipeline in the region – other proposals, including the Trans-Saharan Pipeline to Algeria’s export terminals, have been considered – and it is a secondary route in the market, complementing NLNG. It runs 678 km west from Nigeria, providing gas to public electricity generation companies in Benin, Togo and Ghana. Capacity is 474m scfd, but since completion in 2011 the pipe has rarely carried that amount, due to technical and gas supply issues.
Domestic gas sales in Nigeria are complicated by the lack of development of the domestic pipeline network, leaving a limited number of major offtakers available, but also because of a long history of counterparty risks. Power plants remain a primary client, but cash flow throughout the electricity value chain has historically been erratic, causing irregular payments to gas producers and midstream companies.
This has partially been addressed following the implementation of a state-mandated domestic gas supply obligation in 2008, requiring IOCs to provide a portion of their gas for domestic consumption, although compliance has varied, according to the government.
The state in 2014 boosted the regulated price that government power plants can pay to $2.50 per million British thermal units (mBtu), up from the previously regulated price of $1.50 per mBtu. According to a report by Ecobank, a price of $4 per mBtu would precipitate new investment in the midstream sector.
Most demand in the regulated market for gas comes from power plants, and is directed through Nigerian Bulk Electricity Trading, a government entity created to serve as a low-risk offtaker of power. The plan for de-risking the gas-to-power process also includes proposals for a number of public sector guarantees to incentivise private investment in both power plants and gas supply, including indirect ones from the government through the World Bank’s partial risk guarantees, as well as other development institutions. As of June 2017, one of these World Bank guarantees had been finalised.
In the deregulated gas market, captive independent power producers (IPPs) have emerged as a growing client base, with prices set directly with industrial clients served by those plants. For private builders, the gas price is not regulated. The Azura Edo IPP, the first major IPP planned to produce on-grid power, settled on a rate of $3 per mBtu with Seplat. Gas travelling through the NNPC’s pipeline network is also subject to a transport charge of $0.80 per mBtu.
Prices for consumer fuels are set in a mixed regime, with diesel and other common products unregulated, but PMS tariffs still nominally controlled by the state – although the price is now roughly the market rate. Prices consumers pay for the latter have historically been set below the cost of import, with the state making up the difference by paying licensed importers standard rates, but tighter budgets have forced the government to reduce subsidies. Created in 2001, the NNPC’s Petroleum Products Pricing Regulatory Committee generates the monthly formula for pricing petroleum products. The committee is also responsible for maintaining the pipeline network that sends fuel from the domestic refineries to storage depots.
Nigeria’s energy sector is largely awaiting the passage of the PIGB – which has been on the cards for roughly a decade – but given the recent momentum in the National Assembly, the next year may finally see that happen, which would bring in significant sector changes. Regardless of when the new legislation is passed, there are other additions to the country’s output under way. The US Department of Energy counts eight planned deepwater projects, to add 1.1m bpd of new production, while a number of indigenous-owned onshore blocks have the potential to contribute as well.
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