Vast energy reserves waiting to be unlocked in Nigeria

Still Africa’s largest oil producer, with an industry that in past decades has fuelled the growth of what is now its largest economy, Nigeria has the most voluminous reserves remaining on the continent. Yet it faces steep challenges, from policy uncertainty amid looming legislative reform to output disruptions due to unrest in the Niger Delta, the heart of its producing region. These obstacles have only been exacerbated by falling crude prices, which halved in the second half of 2014.

Nigeria’s hydrocarbons industry is also at the forefront of a change that is beginning to take place in other sectors and countries on the continent: the shift in production from foreign multinationals to domestic companies. Local content policies and a push by international oil companies (IOCs) to cede acreage within onshore and shallow-water blocks have spurred the emergence of a new generation of indigenous oil companies. These domestic firms will prove instrumental alongside IOCs’ growing deep-water offshore production if Nigeria is to realise its ambition of raising production to 4m barrels per day (bpd) from the 2m-2.5m bpd it has averaged over the past two decades.

The sector is also seeing growing local involvement in the provision of services, driven by a law enacted four years ago that requires a higher degree of domestic content. Although oil has traditionally dominated Nigeria’s production mix, natural gas looks set to gain more ground in the coming years, thanks largely to the forecast increase in demand from the recently privatised electricity sector and the investments by state-owned Nigerian National Petroleum Corporation (NNPC) in gas aggregation and transport infrastructure, which are strengthening supply links to power plants.

Operating Environment

Due largely to increased production in the US via fracking and weaker consumer demand in Europe, the global price of crude dropped by more than 50% from June 2014 to January 2015, when it was trading under $50 a barrel. This has had a strong impact on Nigeria, whose currency hit a series of record lows against the dollar in the last quarter of 2014, prompting the central bank to burn through 20% of its reserves to prop up the naira.

In response, Nigeria has lowered its benchmark oil price for the 2015 budget three times, from $78 per barrel to $73, then to $65, then to $53 in March 2015. The price drop has knocked Nigeria’s growth forecast for the year, put roughly 6000 projects on the chopping block and prompted a review and possible doubling of the nation’s value-added tax rate. It is also expected to result in delays with a number of projects in the energy sector as companies cut capital expenditures to keep their balance sheets healthy.

Adding to uncertainties from falling oil prices are changes in trade patterns. In July 2014 the US, once the biggest customer for Nigerian crude, imported none, causing demand to swing to the East, according to the US Energy Information Administration (EIA). Asia’s four largest consumers – China, India, Japan and South Korea – bought 42% of Nigerian crude in 2014.

Large but Depleting

Nigeria holds Africa’s second-largest crude reserves after Libya and the world’s 10th largest overall, although figures vary from 37.2bn barrels in BP’s “Statistical Review of World Energy 2014” to 36bn barrels according to the NNPC. The light and low-sulphur quality of this crude, of which Nigeria is the largest producer in OPEC, makes it ideal for European and US refineries, many of which are geared towards processing a mix of sweet and sour crudes.

Striking oil has typically been straightforward in Nigeria given its prolific oil basins both on- and offshore, with another 20bn barrels of oil equivalent (boe) in undiscovered reserves locked in some 900 prospects, according to estimates from the Department of Petroleum Resources (DPR), the upstream regulator within the Federal Ministry of Petroleum Resources (FMPR). Indeed, the country aims to raise proven reserves to 40bn barrels in the medium term, even if investment in new exploration has been below planned levels.

Yet for Nigeria, the most significant promise may lie in its reputation as a “gas province with a drop of oil”, with estimates of its proven reserves of natural gas ranging from BP’s 179.4trn standard cu feet (scf) to the NNPC’s 182trn scf, and unproven reserves of up to 600trn scf, according to the FMPR. Though significant, these reserves are not expanding to keep pace with production, with the reserve replacement ratio standing at only 70%, according to the DPR. At current production levels, reserves will last 42 years for oil and 155 years for gas, according to the NNPC. Whereas onshore Niger Delta blocks are moving towards maturity, the scope for new finds is significant in frontier acreage like deep offshore – the same geology where nearby Ghana recently discovered its Jubilee field – and inland basins, according to the DPR. “The relative lack of new exploration activities has caused a drop in reserves,” Francis Olo, strategy manager at the DPR, told OBG. “Insecurity onshore has delayed exploration there, while deepwater drilling is very capital-intensive.”

New Prospects

Over the next decade the DPR aims to boost discovery of reserves through field optimisation, as well as by encouraging more investment in bitumen prospecting, in development of more marginal fields and in deepwater offshore. The last block bidding round was completed in 2007, although, in the context of controversial oil-for-infrastructure, semi-barter agreements, the majority of awarded acreage was revoked following the subsequent elections. A second bidding round for marginal fields kicked off in 2013 but was later put on hold, with the DPR expected to stage a full tender once legal reform is enacted.

In the meantime, Nigeria continues to hit significant new finds. The third-largest discovery in the world in 2013 was located offshore from Lagos, in the Dahomey Basin it shares with neighbouring Benin and Togo – a find that could turn the commercial capital into Nigeria’s 11th oil-producing state. London-listed Afren struck oil in the Ogo field, of nearly 774m boe in proven reserves, under a farm-out agreement with Lekoil on oil prospecting licence 310, according to filings with the London Stock Exchange. The FMPR is also keen to encourage exploration of neglected inland basins, which run from the Middle Belt up to the Chad Basin in the north. In January 2014 local press reported the signing of a memorandum of understanding with unnamed Chinese firms for up to $10bn in investment in Niger State’s Bida Basin; details have yet to emerge.

Output Variance

Currently the 12th-largest oil producer in the world and seventh-largest in OPEC, Nigeria saw its total output rise steadily from 1.5m bpd in the mid-1980s to an peak of 2.6m in 2005, according to the EIA. Despite a series of plans to boost this to 4m bpd – the latest target date is 2020 – total production has never passed the 2005 figure, even though the 2014 budget assumes an output of 2.39m bpd.

Estimates of average production vary widely. Due to bunkering, under-maintained infrastructure and an inadequate chain of custody tracking, figures for Nigeria’s 2013 output range from the EIA’s 2.37m bpd to the NNPC’s 2.2m and OPEC’s 1.95m. This figure then fell to 1.9m bpd in the second quarter of 2014, according to the NNPC, while the declaration of force majeure – a legal step that protects producers from liability when outside factors prevent them from meeting contractual obligations – on the 400,000-bpd Forcados terminal in April 2014 reduced export capacity further to 1.6m bpd. Despite this, the National Bureau of Statistics reported figures of 2.15m bpd by the end of 2014, a drop from 2.26m bpd at the start of the year but above mid-year figures cited elsewhere.

Legal Structures

In onshore and shallow waters, oil companies form joint ventures (JVs) with the NNPC, which holds majority stakes on behalf of the government in a 55:45 split for JVs with Shell and 60:40 for all others. While private firms are typically the operators on the blocks, the NNPC serves as a capital contributor, although its share of the costs is sometimes fronted by other operators due to funding issues.

Since the 1990s, a second legal structure has emerged for marginal fields under the Indigenous Concession Programme, where production contracts are awarded to oil firms that are at least 60% locally owned. The definition for marginal fields can vary, but generally includes active or dormant blocks discovered by IOCs or through JVs that remain undeveloped. Of the 31 marginal fields originally awarded, 10 are currently operating, according to the DPR. A third type of arrangement is the production sharing contract (PSC), which has governed deepwater offshore blocks since 1993. Under a PSC, private oil firms receive block concessions in which they are solely responsible for funding exploration and production (E&P), recuperating the costs from production and then sharing profits with the NNPC.

The effective government take varies by the type of arrangement, but all firms must pay the 85% petroleum profits tax (PPT), a 5% value-added tax, a 3% levy to fund the Niger Delta Development Commission, and a 2% education and resources rent tax. Firms with PSCs receive a 50% rebate on the PPT, while local operators of marginal fields pay a 30% corporate income tax instead of the PPT in the first five years of operation.

New Policy

Faced with challenges in meeting the NNPC’s funding requirements and in a bid to increase the state’s effective take, the government began a reform process in the early 2000s, with a first draft forwarded to the National Assembly in 2008 and the latest version under debate since 2012, the Petroleum Industry Bill (PIB). Modelled on other successful corporatisation models, such as that of Petroliam Nasional in Malaysia, the PIB would overhaul the 16 pieces of existing legislation, splitting up the NNPC into commercially viable successor companies and delegating its regulatory roles to different agencies. The NNPC’s operator functions would lie with a National Oil Company and a National Gas Company, while its (and the DPR’s) regulatory functions would be divided between a Petroleum Technical Bureau, a National Petroleum Directorate and a Downstream Petroleum Regulatory Agency. Its upstream oil assets would be transferred to a new National Petroleum Asset Management Corporation, which would then manage all JV assets not transferred to the new oil company. The reform would also convert licences for oil exploration, prospecting and mining (OMLs) into similar licences for petroleum exploration (PELs), prospecting (PPLs) and mining (PMLs). PELs would be capped at three years, PPLs at five years and PMLs at 20 years, down from 25 currently.

While the proposals to restructure the NNPC have met with broad industry approval, pockets of resistance to the PIB have focused on its proposed new fiscal terms and the wider discretionary powers it would grant to the minister of petroleum resources. Under the PIB, producers would pay a new hydrocarbons tax of 50% on profits from onshore and shallow-water fields and 25% for deepwater, frontier and bitumen areas, on top of a 30% corporate income tax and a 10% after-tax levy on profits to support the Petroleum Host Community Fund. If the PIB is passed, the FMPR estimates that the effective government take would rise from 61% to around 75%. However, the Oil Producers Trade Section (OPTS) of the Lagos Chamber of Commerce and Industry, the main IOC association, puts the figure much higher, at 96%. Indeed, if the PIB is passed in its current form, the OPTS reckons production could slump by 25% and some $185bn in new investments over the next decade could be cancelled. Others worry about the impact of new fiscal terms for non-associated gas exploration. “Given that gas is a relatively new segment of the upstream industry in Nigeria, the fiscal terms should not be the same as for oil, which is a much more mature sector here,” Mlandzeni Boyce, business manager at Sasol’s E&P division in Nigeria, told OBG. Both houses of parliament held public hearings on the bill in 2013, but its passage has been delayed, with a revisit expected in mid to late 2015.

Onshore Reserves, Offshore Output

While IOCs still dominate crude production, with 89% of output in 2013, down from 95% a decade ago, new sources have increasingly come from deepwater PSCs rather than from onshore and shallow-water JVs. The six onshore JVs still hold the bulk of reserves, yet their share of total production declined from 61% in 2010 to 50% by year-end 2013, compared to 42% coming from the 34 deepwater PSCs, according to the DPR. Despite the higher costs of deepwater operations – about $100m per well, compared to $15m for onshore ones, plus appraisal costs of $500m over a 10-year project cycle, estimates the OPTS – moving production gradually offshore is meant to insulate infrastructure from attacks and vandalism, though even several offshore rigs have become targets over the past five years.

Deepwater projects have an average full-cycle breakeven price of $44 a barrel, according to the EIA, making most large offshore finds profitable. Despite uncertainties surrounding the PIB, oil majors are pursuing plans for new production offshore, though they are holding off on significant greenfield exploration. “Although the original PIB draft was set to be applied retroactively, more recent versions allow for projects to be grandfathered in,” Dele Kuti, head of oil and gas, power and infrastructure at Stanbic IBTC, told OBG. “This is why some deepwater projects are going ahead, even if deepwater exploration has slowed markedly.” In all, six of the IOCs’ deepwater floating production, storage and offloading (FPSO) outfits account for a third of output, according to the NNPC. “As IOCs continue to move offshore and divest onshore assets, it will spur more FPSO activities,” Austin Zurike, general manager of BW Offshore’s Nigeria arm, told OBG. “The divestments create a host of opportunities for indigenous operators who will take over the divested assets, as well as for operation and maintenance service contractors. But even more, it is important to remember that Nigeria is primarily a gas country and thus provides opportunities for the evolving floating liquefied natural gas vessels that are coming on-stream.”

Key Players

The top three producers by share of oil output in 2012 were ExxonMobil (14%), Chevron (12%), Shell (11%), Total (6%) and Eni (4%), according to Ecobank. International firms also run distinct subsidiaries for JVs and PSCs: Shell, Total and Eni participate in the NNPC’s JV, the Shell Petroleum Development Company (SPDC), while ExxonMobil operates through the Mobil Producing Nigeria JV and Eni through the Nigerian Agip Oil Company. The longest-running venture, with 30 onshore and shallow-water blocks, SPDC has the most acreage of all JVs and operates about 6000 km of pipelines, eight gas processing plants, and two export terminals at Forcados and Bonny.

Top Three

Shell also runs the wholly owned Shell Nigeria Exploration and Production Company (SNEPCo) for its PSCs, operating the country’s first FPSO at Bonga since 2005. While its output declined from 365,000 bpd in 2012 to 265,000 bpd in 2013 due to shut-ins and sales to local producers, it still derives about 10% of its global supply from Nigeria. SNEPCo has planned $33bn in developments adjacent to the Bonga FPSO in the long term, including Bonga South-West, East and NorthEast, though a final investment decision on Bonga South-West is expected only in 2016 at the earliest.

For ExxonMobil, the lion’s share of production comes from shallow-water JV blocks and deepwater PSCs it runs through its subsidiary Esso E&P Nigeria. It also handles the 400,000-bpd Qua Iboe export terminal in south-eastern Akwa Ibom State and produces gas liquids from its Oso and East Area gas liquids projects. Other deepwater FPSOs in which it holds stakes include Total-operated Usan (30%) and 190,000-bpd Erha (56.25%). The latter came on-line in March 2006 and is nearing a final investment decision on the Erha North phase 2 project in 2015, which would add 60,000 bpd.

Chevron’s JV with the NNPC controls 13 blocks, mostly in shallow waters, and two export terminals at Escravos and Pennington. The US firm’s main focus is on the deepwater front, though it is also the largest stakeholder (36.7%) in the West Africa Gas Pipeline (WAGP), and commercialised its 33,000-bpd Escravos gas-to-liquids plant in June 2014. Having opened the 250,000-bpd Agbami FPSO in 2008, in which it holds a 67.3% stake alongside Norway’s Statoil Hydro (20.21%) and Brazil’s state-owned Petrobras (12.49%), Chevron has been drilling another 10 wells under phase 2 to maintain production. A final investment decision on phase 3, involving five more wells, is expected in 2015.

Other IOCS

France’s Total has emerged as the largest deepwater producer in Nigeria thanks to its FPSO hub strategy, centred on its first such facility, in the Akpo field on OML 130 and in operation since 2009. The development, in which Total holds a 24% stake alongside China National Offshore Oil Corporation (CNOOC) with 45%, the NNPC holding 10%, Petrobras’s 16% (which it sold to leading Brazilian bank BTG Pactual in 2013) and Sapetro’s 5%, puts out 180,000 bpd of oil and 500m scf per day of associated gas. Its second FPSO at Usan, on OML 138, came on-line in April 2012 and reached peak output of 180,000 bpd by year-end 2013. In a strategic move linked to its offshore developments in Angola, Total sold its 20% stake in Usan to Sinopec for $2.5bn in November 2012, roughly twice the average selling price over the past five years, according to research firm AllianceBernstein, and passed operatorship to ExxonMobil, which holds 30% alongside Chevron’s 30%. Nexen, the Canadian firm acquired by CNOOC for $15.1bn in 2013, holds the other 20%.

Since 2013 Total has proceeded with its third FPSO, Egina, on the same block as Akpo, entailing 44 wells linked to a 200,000-bpd FPSO. Production is planned for 2017, but the project is likely to be delayed given disputes between Samsung Heavy Industries and the Lagos Deep Offshore Logistics Base, known as LADOL, to which Total awarded the $3.8bn design and assembly contract (see analysis). It is also forging ahead with a $6.63bn second phase of the maturing offshore Ofon field on OML 102, where it expects to start pumping 40,000 bpd and 106m scf of gas per day by late 2015. Though its presence onshore is limited to OML 58, it supplies natural gas from the Obite gas project and its offshore Amenam field to Nigeria’s liquefied natural gas (LNG) terminal and its own independent power plant.

Italian major ENI maintains the smallest presence, operating four onshore blocks (aside from its stakes through SPDC) clustered around the Brass River in the western Delta, where it operates an export terminal and supplies the LNG plant with gas from the Tuomo, GbaranUbie and Idu gas fields. Highly affected by vandalism and oil theft onshore, Eni developed its first deepwater field in Nigeria in 2003, built the 45,000-bpd Abo FPSO on a PSC and holds an 85% stake alongside Nigeria’s Oando, as well as stakes in other deepwater PSCs.

Indigenuous Production

In light of oil majors’ recent and ongoing divestments from onshore and shallow-water blocks, their share of Nigeria’s output is set to shrink from around 90% to 60% within five years, according to Ecobank. The biggest deal of 2014 was concluded in July, when ConocoPhillips divested $1.65bn to Oando, raising the latter’s production to 50,000 bpd. A deal of similar size came in March 2015, when Shell divested its stakes 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. Earlier that month, it had completed the sale of its 30% stake in OML 18, also in the eastern Niger Delta, for $737m. With the exception of three blocks sold to Seplat, the NNPC’s E&P arm, the Nigerian Petroleum Development Company (NPDC), exercised the operation rights inherent in its 55% stakes in the other five blocks sold (see analysis). As a result, the NPDC expanded its output from 60,000 bpd in 2007 to 140,000 bpd and 450m scf per day of gas in 2013, with the aim of reaching 250,000 bpd and 670m scf per day by 2015. Yet the NPDC’s growing role is causing problems similar to the NNPC’s inability to fund its share of onshore JVs, traditionally done through cash calls from IOCs. “The challenges in attracting significant numbers of investors to upstream divestments in Nigeria could be attributed to the NPDC’s exercising its operatorship rights, since this can constrain the ability to fund expansions in production,” Kuti told OBG. The NPDC has thus resorted to strategic alliance agreements (SAAs) whereby private third-party operators – Atlantic Energy for OMLs 26, 30, 34 and 42 and Seplat for OMLs 4, 38 and 41 – front the funding and technical operations before being paid back in cost oil. As the NPDC is expected to exercise its operatorship rights in the next divestments, its technical and funding constraints may prompt it to conclude more such deals. “It makes good business sense for the NPDC to sustain SAAs to increase output in line with their targets,” Uzoma Akalabu, Nigerian content development manager at Septa Energy, told OBG.

Alongside the sale of 13 more onshore and shallow-water blocks to local firms in 2014, the DPR is preparing a second marginal field bidding round, the first being in 2003. An initial 31 marginal fields have been selected – 15 onshore and 16 in shallow waters, representing 3bn boe of reserves – and the legal transfer of ownership secured from IOCs. Though the round was expected soon after the 2011 election and the FMPR conducted a roadshow to raise interest, as of March 2015 it had not been held. If it does occur, the terms will differ from previous sales. “The terms of bidding for the upcoming marginal field round are different from past rounds since the bids are evaluated according to their work programmes, rather than only pricing,” Ladi Bada, managing director and CEO of Shoreline Natural Resources, told OBG. The signature bonuses are expected to be significantly lower than previous rounds, at $150,000 per field, and local players will be encouraged to submit joint bids. “The government will require joint bids from four companies at a time, while we will analyse both the technical and commercial terms of each offer,” Olo told OBG. As of early 2015 it was unclear what impact the fall in oil prices and change in government would have on this round.

Monetising Gas

While output is still dominated by crude, attention has shifted to monetising Nigeria’s vast natural gas resources and channelling supplies to domestic off-takers in both the power sector and value-added industries. With proven gas reserves between 179trn scf and 182trn scf, depending on the source, there is considerable scope for expanding Nigeria’s current production of 8.2bn scf per day.

Oil producers have typically flared as much as a third of total production, paying penalties of N10 ($0.06) per million scf flared, although this had slumped to 978m scf per day by May 2014, according to the DPR. Roughly two-thirds of gas produced is exported as LNG through the 22m tonne-per-year Nigeria LNG (NLNG) plant on Bonny Island, the fourth-largest source of LNG globally, according to the EIA. First opened in 1999 with its sixth train completed in 2007, the $9.35bn project is the largest private investment in Africa, backed by the NNPC (49%), Shell (25.6%), Total (15%) and Eni (10.4%). The plant draws supplies from the three main operators: SPDC’s three onshore fields of Soku, Bonny and Gbaran-Ubie; SNEPCo’s Bonga and EA fields offshore; Agip’s Obiafu-Obrikom gas plant; and Total’s Obite, Ibewa and Obagi fields onshore and the offshore Akpo and Amemam platforms. In all, the plant had shipped 3000 cargos by the end of 2013, generating some $80bn in revenue, according to NLNG. Shipments of 280 vessels fell short of the 325 targeted in 2013 given a two-month blockade by the Nigerian Maritime Administration and Safety Agency over unpaid cabotage fees. NLNG is purchasing another six LNG vessels by 2017, adding to its current fleet of 24.

New Projects

Three other LNG projects have been tabled over the past decade. The most economical pending project would be a seventh train at NLNG, with a capacity of around 7m tonnes per year and costing an estimated $12bn. Two parallel greenfield projects have also been discussed. The first is the 22m-tonnes-per-year Olokola LNG in the western Delta, proposed in 2006 at an initial cost of $10bn by the Olusegun Obasanjo administration, originally backed by the NNPC (49%), Chevron (19%), Shell (19%) and the UK’s BG Group (13%). However, BG’s withdrawal in 2012 delayed the investment decision indefinitely. The other, a 11mtonnes-per-year Brass LNG project, would cost $15bn, although changes in the composition of project shareholders have delayed any decisions on this.

Use Locally

Progress on new export channels is limited by the priority placed on channelling gas supplies to the domestic market, in particular to recently privatised gas-fired power plants that account for 70% of gas not consumed by NLNG, according to a report by MIG Securities (see analysis). Indeed, supplies to Nigeria’s second gas export channel, the 678-km WAGP to Ghana, remain far below original plans given growing demand in Lagos. Originally conceived of in 1982 and backed by Chevron (36.7%), Shell (18%), the NNPC (25%) and the national gas and power companies of Benin, Togo and Ghana, the $1bn pipeline opened in 2008 with an installed capacity of 474m scf per day, tied into the Escravos-Lagos western pipeline system. While commercial deliveries started in 2011, the pipeline was accidentally damaged by an errant ship in August 2012, and when deliveries resumed a year later, they remained below the 120m scf per day contracted to each of the three countries. The resultant supplies were retained domestically to meet growing consumption from power-generating off-takers in the Lagos area.

The FMPR and NNPC also hope to attract private investment in gas-based, value-added industries, beyond the existing Notore fertiliser plant and Indorama’s petrochemicals plant. Dangote is planning a $9bn refining complex in the Lekki Free Trade Zone, including provisions for a urea and ammonia fertiliser plant. The FMPR has proposed a new 2800-ha, gas-based free trade zone in Delta State near the Escravos River, which would generate demand for up to 2.5bn scf per day of gas as feedstock for new fertiliser and methanol plants. A third gas monetisation channel, the Escravos gas-toliquids plant, began exports in June 2014. The $10bn project, producing 33,000 bpd of Euro V compliant diesel and kerosene from 320m scf per day of gas, is backed by Chevron and the NNPC using slurry phase distillate technology from Sasol (under a 75:15:10 split), but has suffered repeated delays due to concerns over security and community relations.

Downstream

High-grade output from the Escravos plant, dedicated to exports, will not reduce Nigeria’s reliance on imported refined products, which remains high since its four existing refineries run at only 30% of their installed capacity of 445,000 bpd (see analysis). According to the NNPC, domestic output meets only 9% of daily consumption of petrol, 24% of dual-purpose kerosene and 28% of automotive gas oil, with the rest imported from abroad, especially the Netherlands.

These imports are secured through both swap agreements and normal imports (see analysis). While NNPC subsidiary Pipelines and Product Marketing Company operates the 4400 km of refined fuel pipelines, 21 fuel depots and eight propane storage units, a growing number of importers and marketers such as Aiteo, Sahara Energy, Global Fleet and NIPCO are investing in their own storage near major consumption centres, with about 30 each in Lagos and Port Harcourt with average capacities of 25m litres. Four fuel retailers dominate, including Oando with 505 stations, Total with 500, MRS/Global Energy Group (which acquired Texaco’s stations in 2009) with 416 and NIPCO with 137.

The partial lifting of fuel subsidies in January 2012 (see Economy chapter) raised the litre price of petrol from N65 ($0.40) to N97 ($0.59). Coupled with a crackdown on fraud, this has reined in the rapid growth in imports since 2008. Subsidies, which had risen from 1.3% of GDP in 2006 to 4.7% in 2011, fell to 3.6% of GDP in 2012 and 3% in 2013. Indeed, according to the NNPC, petrol consumption fell from a daily average of 44.46m litres in the first quarter of 2012 to 32m litres in 2013, suggesting that fraudulent imports had inflated import figures. Following the rebasing of GDP in April 2014, budgeted fuel subsidies, frozen in real terms at the N971.1bn ($5.9bn) spent in 2013, dropped to 1.2% of GDP. The state has also tightened licensing, reducing the number of fuel import licences from 50 to 30 in the six months to March 2014.

Some industry stakeholders argue for scrapping subsidies altogether. In 2014 Nigeria’s Depot and Petroleum Products Marketers Association, a lobby group, called for deregulation of the country’s oil and gas industry, with its chairman, Dapo Abiodun, saying this could lead to complete removal of petroleum subsidies “with its attendant benefits for the sustenance and growth of that vital sector of the economy”. In early 2015 another industry body, the Major Oil Marketers Association of Nigeria, called for complete deregulation of the downstream sector, saying this could spur private investors to build local refining capacity. “The slogan is clear: no deregulation, no private refineries,” Obafemi Olawore, its executive secretary, told the press in Lagos. “Government cannot continue to set prices of petroleum products and expect private investors to come and stake their money in building refineries.”

Security

Security in Nigeria’s oil-producing region has long been a headline topic. Problems like oil theft and vandalism, though less acute than earlier in the past decade, have seen a slight increase in 2014. Although an amnesty for over 26,000 former militants has curbed kidnappings and general violence since 2009 – with monthly cash payments to former insurgents being paid until the end of 2014 – oil theft began to see an uptick from 2013. According to the IMF, this occurs mainly through either small-scale theft from pipelines to be used for illegal refining, or large-scale bunkering carried out by stealing directly from the wellheads and filling tankers at export terminals.

The scale of oil theft has risen in line with oil prices since the early 2000s, according to the IMF, although the fund shies away from drawing a direct causal connection. Losses vary from 100,000 bpd to 500,000 bpd, depending on the source and time, and oil output has stayed below 2m bpd since October 2013, according to OPEC. The Nigeria Extractive Industries Transparency Initiative reports the country lost $10.9bn between 2009 and 2011, while the Federal Ministry of Finance reported in mid-2013 that losses averaged $1bn a month. To address this, the government has upped security expenditures, increasing the NNPC’s annual spending on security to N15bn ($91.5m) in 2014.

Outlook

Despite the legal uncertainty caused by serial delays in passing the PIB and concerns surrounding the drop in oil prices, Nigeria’s hydrocarbons industry is undergoing a number of positive changes. Local operators are expanding their share of production, while domestic services companies are boosting capacity to meet local content requirements. Investors, both local and foreign, are likely to increase their equity stakes in local upstream firms and Nigerian services companies. Although crude output remains comparatively flat, output of gas looks set to continue growing in coming years, with credible domestic off-takers emerging. The mid-stream refining segment, despite a series of false starts, looks set to receive much-needed private investment. Serious challenges remain, however, from under-investment in greenfield exploration, which could improve reserve replacement, to vandalism and oil theft from onshore infrastructure. If Nigeria is to reach its production goal of 4m bpd by 2020, it will also need to improve its policy predictability and transparency.