Nigeria has a well-established track record as the world’s 12th-largest producer of oil and the leading producer in Africa, according to the BP “Statistical Review of World Energy 2013”. Yet as the country’s proven reserves of both oil and gas start to decline, the imperative is to clarify the industry’s long-term legal and fiscal outlooks to encourage more investment in exploration and production (E&P). Despite legislative delays, Nigeria is making progress in expanding local firms’ share of production and oil services while also catalysing significant investment in gas-to-power projects. By channelling its untapped gas reserves towards domestic power and industry, Nigeria can leverage these undeveloped resources to support its industrialisation goals.

Although output remained at 2.2m barrels per day (bpd) on average in 2012, according to the Department of Petroleum Resources (DPR), a number of significant deepwater offshore projects of over 200 metres in depth will add production capacity. The energy sector’s positive outlook is contingent on progress in the key areas of energy production, as well as the expansion of investment in more sophisticated offshore projects. Alongside implementation of the Gas Master Plan, enacting the long-awaited Petroleum Industry Bill (PIB) before the 2015 elections would prove a significant help.

RESERVES: In 2011 Nigeria sat atop roughly 2.2% of the world’s oil reserves (the 10th largest globally), at around 37.2bn barrels, alongside 182trn standard cu ft (scf) of associated natural gas (the ninth largest globally), according to BP’s “Statistical Review” (see analysis). While oil reserves rose from 21bn barrels in 1992 to 34.3bn barrels in 2002, driven by significant deepwater offshore discoveries from the 1990s onwards – which added over 7bn barrels to proven reserves, according to Access Bank – the rate of exploration has slowed since the middle of the last decade.

As oil majors delayed significant exploration investment in the face of uncertainty over oil industry reforms and prioritised large offshore developments from the early 2000s, the rate of oil recovery dropped and reserves peaked in 2010. In 2012 Osten Olorunsola, then-director of the DPR, reported that oil reserves had dropped to 36.5bn barrels, down from 37.2bn barrels in 2011. The sweet, (low sulphur content) light (high American Petroleum Industry [API] density) crude produced has traditionally been in high demand from US and European oil refineries calibrated to handle it.

GREAT POTENTIAL: Exploration has a long history in Nigeria, dating from the first licence awarded to Shell D’Arcy (now Royal Dutch Shell) in 1938. With significant exploration potential in a geologically low-risk basin, the country now has over 1000 fields identified, mainly as a result of 2D seismic studies carried out in the 1970s through 1990s, although the majority of these are not yet producing, according to the DPR.

Most of the 650 or so undeveloped discovered reservoirs, according to brokerage firm CSL Stockbrokers, are onshore and are part of the Akata formation. This reflects the rich portfolio of potential projects from which oil producers can choose, with oil recovery rates amongst the highest internationally, according to oil independent Eland Oil & Gas. Oil operators in Nigeria estimate their drilling success rate in the 75-80% range, high by global standards, thanks to the advent of 3D seismic imaging in the last 15 years, a technology that has improved average success rates.

In 2005 French oil major Total published estimates for Nigeria’s future discoverable resources highlighting the great potential onshore. Total projects that there are 10bn barrels of undiscovered oil and 6bn barrels of oil equivalent (boe) onshore; 2bn barrel of oil and 3bn boe in shallow waters; and 6bn barrels of oil and 3bn boe in deepwater offshore. In a subsequent study in June 2013 the DPR estimated some 20bn boe in yet-to-be-discovered oil and gas through roughly 900 projects and leads. The Nigerian National Petroleum Corporation (NNPC) puts Nigeria’s oil sands reserves at some 43bn boe, although this has yet to be confirmed.

PRODUCTION: While Nigeria has been producing oil since the late 1950s from Shell D’Arcy’s Oloibiri well in Bayelsa State, oil production capacity has remained at roughly 2.5m bpd since the start of the millennium (albeit with short-term fluctuations), despite successive government plans to boost production to 4m bpd. Nonetheless, Nigeria remains Africa’s largest producer, although rising output in Angola could see Nigeria overtaken by the southern African nation as early as 2014. Installed production capacity in Nigeria in March 2013 stood at around 1.5m bpd onshore and in shallow waters and roughly 900,800 bpd in deepwater offshore, areas that are more technically challenging yet further from the unrest in the Delta.

OUTPUT NEEDS: The average age of Nigeria’s roughly 500 active platforms is 35 years, operated by some 130 flow stations and plants, and the old age of many installations reflects the industry’s investment requirements. The DPR estimated in June 2013 that around 70% of reservoirs in the mature onshore Niger Delta are in secondary or tertiary production stages. It forecasts that some 9bn barrels of oil could be recovered through enhanced techniques, adding about 10% to total production. While the latest deadline for reaching the 4m-bpd production target has been set for 2020, significant investment by oil majors as well as independents and local operators will be necessary to achieve that – far more than is currently planned. According to Nigeria’s Access Bank, new wells are being drilled in markets like Angola at roughly twice the rate as in Nigeria, despite the larger size of Nigeria’s reserves, due mainly to uncertainties regarding passing of the PIB and its subsequent effects on the industry.

PRODUCTION RATES: Domestic production first reached 2m bpd in 1971, the year after Nigeria joined the Organisation of the Petroleum Exporting Countries (OPEC). Today, Nigeria contributes 11% of OPEC output (with an OPEC quota of 2.5m bpd) and around 2% of global production, according to the US Energy Information Administration (EIA). BP put the latter figure at 2.8% in 2012, illustrating that published figures can vary significantly between sources. US-based non-governmental organisation Revenue Watch found significant discrepancies between production reporting data from OPEC, NNPC, BP’s “Statistical Review” and the EIA. According to Revenue Watch, in the period between 1997 and 2011, in part due to leakages in the supply chain, OPEC’s production figures were 11% higher than those reported by NNPC, and EIA and BP figures were 4% and 3% higher, respectively, than NNPC’s.

Nigeria’s reserves-to-production (R/P) ratio stands at 41 years for oil and 128 years for gas, according to figures cited by Diezani Alison Madueke, the minister of petroleum resources, at a summit in May 2013. By this measure its oil production is actually quite conservative: if it maintained the same R/P ratio as Russia, it would produce 5m bpd, according to CSL Stockbrokers. Nevertheless, the industry has an oversized share in the economy, accounting for 14% of GDP and 95% of foreign-exchange earnings in 2012, according to the National Bureau of Statistics (NBS). Roughly 80% of production is located in the southern Niger Delta.

Actual output has regularly fallen short of installed capacity, however, given disturbances linked to sabotage and theft, with output averaging 2.2m bpd in 2012 and slowing to 1.81m bpd in March 2013 and 1.94m bpd in April 2013, according to investment firm Financial Derivatives Company (FDC). Oil production dropped from 2.35m bpd in the first half 2012 to 2.29m bpd a year later, according to NBS, lower than the 2.56m bpd estimated in the 2013 budget and the 2.37m bpd in the 2012 budget. In June 2013 the Federal Ministry of Finance estimated that Nigeria lost some N155bn ($976.5m) per month to oil theft in the first half of 2013, largely due to four cases of force majeure.

PLAYERS: A total of 388 E&P blocks – in both oil prospecting licences (OPL) and oil mining licences (OML) – are currently zoned, according to the DPR, of which 173 have been awarded and 215 are open. A total of 85 firms are operating, with 34 producing oil, covering 218 producing fields and 97 non-producing fields.

Foreign players, dominated by larger international oil companies (IOCs), accounted for 89% of oil production in 2012, according to DPR data. The six largest foreign producers were Shell Petroleum Development Corporation (SPDC) with 605,539 bpd of oil (and a total of 949,000 bpd of boe including gas), ExxonMobil’s Mobil Producing Nigeria (MPN) with 528,000 bpd, Chevron Nigeria Limited (CNL) with 489,999 bpd, Total E&P Nigeria (TEPN) with 400,134 bpd, ENI’s Nigerian Agip Oil Company with 98,284 bpd and Addax Petroleum with 90,489 bpd. Oil majors are planning between $29bn and $39bn in new investment in onshore, shallow-water and deepwater projects by 2018, according to the Oil Producers’ Trade Section (OPTS) of the Lagos Chamber of Commerce, the industry umbrella association. While Asian energy firms have historically struggled to acquire acreage in block auctions (as in 2005 and 2007, for instance), China Petrochemical Corporation (Sinopec) bought into the Nigerian market by purchasing Addax’s worldwide E&P assets in August 2009 for $7.3bn.

Local operators, which produced on average 276,000 bpd in 2012, were led by NNPC’s production subsidiary, Nigerian Petroleum Development Company (NPDC), with 125,828 bpd, Seplat Petroleum with 40,033 bpd, Pan Ocean with 7387 bpd, as well as independent operators with a combined 102,797 bpd.

OWNERSHIP STRUCTURE: Production structure is split between joint ventures (JV) with NNPC onshore and in shallow water, and production-sharing contracts (PSC) in deepwater offshore. NNPC’s subsidiary National Petroleum Investment Management Services (NAPIMS) manages NNPC’s stakes in both JVs, where NNPC owns between 55% (for JVs with Shell) and 60% (for all others) of the venture, and PSCs. Current fiscal terms for JVs include tax rates of 65.75% for the first five years of production and 85% thereafter, with private JV partners traditionally the blocks’ operators. Under PSCs, NNPC is the oil licence holder, but engages oil firms as contractors that bear all risk and recover costs through a share of production at a tax rate of 50%.

The cost recovery element of PSCs has led NNPC to accuse IOCs of inflating claimed costs via transfer pricing, and such disputes are ongoing. A third category of ownership structure, marginal fields, was introduced in the early 2000s to encourage local participation in developing fields farmed out by oil majors, and are taxed at a concessional 65.75%. JVs are due to be phased out over the medium term under the planned PIB, while fiscal terms for PSCs will be significantly raised.

NNPC remains the dominant force in the industry, acting as de facto regulator as well as production partner, refiner and downstream distributor. The firm will be broken up and commercialised under the planned reform, in part to solve capital crunches where NNPC is unable to fund its share of JVs (see analysis). To overcome the funding shortages, IOCs have traditionally covered NNPC’s share of work programmes through “cash calls”, recuperating fronted costs through subsequent oil production, but this has also resulted in NNPC’s growing indebtedness. These cash calls have averaged 3% of GDP since 2007, according to the World Bank, and are expected to remain at this level until 2015 at least.

ONSHORE & SHALLOW WATER: The largest onshore and shallow-water producer has historically been SPDC, a JV between NNPC (55%), Shell (30%), TEPN (10%) and NAOC (5%). With roughly 60 producing fields, 1000 producing wells spread over 33 blocks (28 onshore and five in shallow water), 87 flow stations, 6000 km of flow lines and pipelines, eight gas plants and two major export terminals at Bonny and Forcados, SPDC holds mining licences for an area of around 31,000 sq km and has production capacity of 1m bpd. Shell and its IOC partners, however, have divested from their stakes in eight onshore blocks since 2010 – a major move that helped spark the expansion of local operators – and Shell announced in October 2013 that it was putting up for sale four additional onshore Niger Delta oil blocks – OMLs 18, 24, 25 and 29 – that have a combined production of 70,000 bpd. Nevertheless, SPDC remains a key player onshore.

MOVING UP: ExxonMobil, active in Nigeria since 1955 through its MPN 40:60 JV with NNPC, is the second-largest producer and is expected to overtake Shell by 2020, according to oil consultancy Rystad Energy. It currently operates 90 offshore platforms covering around 300 producing wells, as well as the Qua Iboe export terminal in eastern Akwa Ibom State, with capacity of 550,000 bpd of crude, condensates and natural gas. Exxon’s production is expected to rise to 1m bpd by 2020, following renewal of its shallow-water licences and investment in offshore PSCs. Chevron’s 40:60 JV with NNPC, CNL, operates 13 shallow-water blocks covering 8900 sq km, producing 238,000 bpd in 2012. Though it planned to divest its stakes in five shallow-water blocks – OMLs 52, 53, 55, 83 and 85 – as of mid-2013, CNL is continuing shallow-water exploration.

Despite being the fourth-largest oil producer in aggregate, France’s Total remains a marginal player. Alongside its equity in SPDC, Total only has a 40% stake in an onshore block, OML 58, a gas-producing field with 76,000 boe of gas capacity, as well as an adjacent independent power plant. In shallow waters the main production expansion project is Total’s development of the second phase of its Ofon project on OML 102, in which it holds 40% in JV with NNPC. Aiming to triple production to 90,000 bpd, Total is installing four new platforms to boost output from its proven reserves of roughly 350m barrels, due for completion in 2014. The additional gas will feed Nigeria Liquefied Natural Gas’s (NLNG) train 6, as will the second phase of the Amenam-Kpono field, which will gather associated gas from the project’s current output of 125,000 bpd of oil.

Aside from its stake in SPDC, Italian ENI’s Agip operates four onshore blocks in which it holds a 20% stake, making up two-thirds of its Nigerian production – roughly 66,000 bpd in 2012. It also has stakes in four shallow-water blocks, operating three in which it has a 20% stake, and with a 12.5% stake in the fourth. Addax, whose global operations were bought by China’s Sinopec in August 2009, has only one onshore producing block (that it owns outright) and two shallow-water blocks.

LICENCE WOES: Uncertainty remains for oil majors operating onshore and in shallow waters. Some 20 mining licences expired in 2008 and have only been renewed yearly on an ad-hoc basis, restraining new investment. Although ExxonMobil received extensions for three of its blocks in 2011, covering 400,000 bpd of aggregate production, the other IOCs are still waiting. While licence renewal has not been formally linked to onshore divestments to local players, oil majors are encouraged to farm out blocks. More practically, the process of licence renewal has been delayed by the slow passage of the PIB. The Federal Ministry of Petroleum Resources (FMPR), which oversees the sector and under which the DPR regulates the upstream, downstream and midstream markets, supports the expansion of local operators’ share of oil production (see analysis).

MOVING DEEPWATER: E&P in Nigeria’s deepwater offshore – more challenging than onshore drilling but simpler than the world’s most complex deepwater developments in the Gulf of Mexico or offshore Brazil – has grown significantly since it began in 1993. Deepwater production expanded from 10% of total output in 2005, two years after the first floating production, storage and offloading (FPSO) facility, Abo, was opened by Agip, to around 37.5% in 2012, according to the DPR.

Shell first incorporated its offshore E&P subsidiary, Shell Nigeria Exploration & Production Company ( SNEPCo), in 1993 to develop two PSC licences, in partnership with Total and Agip. In the two decades to 2013, roughly $48bn in foreign investment was allocated to deepwater developments, according to figures from SNEPCo. While costs associated with deepwater drilling are significantly higher – roughly $100m per well compared to around $15m onshore, with further appraisal costs of $500m and development cycles of between 10 and 20 years, according to OPTS estimates – IOCs have increasingly shifted the bulk of their investment offshore. NNPC’s consistent shortfalls in funding its share of onshore JVs, uncertainty over onshore and shallow- water licence renewals since 2008, and a deteriorating security situation in the Delta, particularly up to 2009, have largely driven this shift. By 2013 there were five main FPSOs in operation, with at least three major projects in development. All based on discoveries at the turn of the millennium, current deepwater investments are developing capacity and exploring in adjacent areas, rather than greenfield prospecting.

BONGA: While Agip’s Abo development, which came on-stream in 2003, remains marginal to overall deepwater output with a capacity of 45,000 bpd and 900,000 barrels of storage, other IOCs like Total and Shell are developing offshore FPSO hubs, linking a series of FPSOs to a central facility. SNEPCo’s developments centre on the Bonga project, the first major FPSO to come on-line in late 2005. Operated by SNEPCo with ExxonMobil (20%), Agip (12.5%) and Total (12.5%) as minority partners, the Bonga field lies 120 km offshore the western Delta on OML 118 and holds proven reserves of over 500m barrels. Built by Samsung Heavy Industries, the FPSO has production capacity of 250,000 bpd of oil and 150m scf per day of gas (supplied to NLNG in Bonny), from a field over 1 km deep – the first deepwater discovery in 1996. The total project cost $3.6bn.

The FPSO suffered a damaging leak of 40,000 barrels in December 2011, the worst since 1998, landing Shell $5bn in fines from the government; the case was still pending as of mid-2013. Following 4D seismic studies in 2008 and 2010, SNEPCo is forging ahead with adjacent developments. First in line, the Bonga Phase 2 and Bonga North-West developments will involve the drilling of 19 new wells, at a reported cost of $12.35bn (including the new FPSO), to extend peak production rather than expand existing FPSO capacity.

FPSO HUB: Coming on-line in 2008, Total’s Akpo FPSO is the centre of the operator’s deepwater FPSO network linking to the Usan and Egina projects, making it Nigeria’s largest deepwater oil producer. On OML 130 some 200 km offshore Bonny, the Akpo field discovered in 2000 is operated by Total (which holds a 24% stake), with China National Offshore Oil Corporation (CNOOC, with 45% interest), Brazil’s Petrobras (16%), NNPC (10%) and General TY Danjuma’s Sapetro (5%) as partners. With 620m barrels of proven oil reserves and roughly 988bn scf of gas, the development consists of 44 wells (22 producing) and has a production capacity of 180,000 bpd of oil and around 500m scf of gas per day since it came on-stream in 2009.

Total’s second major FPSO development came with the Usan field in OML 138, around 100 km offshore. The field was discovered in 2002 on a PSC granted in 1993, and the FPSO came on-line in April 2012. While it took longer to reach production than expected, this happened in June 2013 when it hit 127,000 bpd, with peak output of 180,000 bpd anticipated in the near future. Total was the FPSO’s operator with a 20% stake – alongside ExxonMobil (30%), Chevron (30%) and Nexen (which acquired 20% in 1998) – although the project’s shareholding structure changed in 2013 when Total sold its 20% stake to China’s Sinopec in November 2012 for $2.5bn. It was not clear as of mid-2013 who would take over Total’s operational role, but it is likely that CNOOC will use its 20% stake to support China’s state-owned Sinopec’s bid to become operator.

The third major development is Egina, on Akpo’s OML 130 that also hosts the undeveloped Preowi field, which received a positive investment decision in 2013. Discovered in 2003, the project will entail 44 wells connected to an FPSO with a 200,000-bpd capacity and storage for 2.3m barrels. Construction was awarded to Samsung Heavy Industries in early 2013, and assembly of the FPSO’s hulk will take place at an extension of the Lagos Deep Offshore Logistics Base (LADOL), with first production expected in 2017. Some 75% of all project work-hours will be conducted locally.

MORE FPSO: ExxonMobil, Chevron and Agip are forging ahead with their own deepwater investments. The $3.5bn Erha FPSO, covering 24 wells on OML 133 some 100 km offshore, opened in March 2006 with production of 190,000 bpd of oil, 300m scf per day of gas and storage of 2.2m barrels, operated by Exxon (56.25% stake) with Shell as a partner (43.75%).

In February 2013 Exxon decided to move ahead with the Erha North Phase 2 project despite uncertainty caused by the PIB. Aiming to add another 10 wells to gain an additional 60,000 bpd of production, the new supply will be channelled to the existing FPSO when it is completed in 2016. Chevron, which opened the Agbami FPSO in 2008, reached its peak production of 250,000 bpd in 2012. Some 70 km offshore, the field discovered in 1998 on OMLs 127 and 128 has proven reserves of 900m barrels and is operated by Chevron (67.3%), with Norway’s Statoil Hydro (20.21%) and Petrobras (12.49%). Chevron is investing $1.9bn between 2012 and 2016 to drill another 10 wells under phase two. Meanwhile, Agip is expecting to move towards development of its OPL245, jointly held with Shell (50% each), since it was acquired from Malabu Oil in 2011.

The Zabazaba/Etan development is expected to move into production in 2016, with proven reserves of over 500m barrels, which will include a total of 18 producing wells and a 120,000-bpd capacity FPSO. Overall, the industry expects a significant boost to deepwater production, totalling more than 600,000 bpd in new capacity, if all projects proceed as planned.

NEW ACREAGE: While most operators face slow progress in renewing JV licences that expired in 2008, new block awards have been few and handled with discretion since the last formal block bidding rounds. The 2005 round attracted bids for only 30 of the 77 blocks on offer, with bids coming from Korean and Chinese operators rather than IOCs. A mini-round in 2006 awarded an additional 18 blocks to 11 firms from China, India and Nigeria that pledged significant infrastructure investments. The last round in 2007, held less than a month before the presidential elections, awarded 19 of the 45 blocks on offer, spread over the inland basins, continental shelf, onshore Delta and deepwater offshore blocks. The winners were again Indian and Nigerian.

Although some $226m in signature bonuses was secured, since 2008 five block awards have already been overturned following investigations into the round’s legality. Oil firms have been waiting for new bidding rounds since 2010, although there have been discretionary awards of blocks since the last bidding round in 2007 (see analysis). While the more than 26 blocks left from 2007 are still expected in a new regular round, this has repeatedly been delayed pending passage of the PIB. In 2011 the government announced that it intends to stage a second marginal fields round for local firms, with some 50 fields in reserve. Yet this too has been delayed and is now only expected before the next election in 2015 (see analysis). The latest PIB draft also includes provisions for exploration in the inland Chad basin in the north-east (see analysis).

GOVERNANCE: Foreign investors in Nigeria’s upstream industry have paid particular attention to governance issues over the last decade, prompted principally by stricter enforcement of the US’s 1977 Foreign Corrupt Practices Act (FCPA) and the UK’s 2010 Bribery Act. Several prosecutions overseas and high-value settlements have prompted investors to increase due diligence and risk management processes, both in-house and through outsourcing to due diligence firms. The highest-profile case involved accusations of bribery against a consortium of companies working on the construction of the NLNG project in the late 1990s. In 2009 several oilfield service firms were involved in a long court case, and one US firm settled out of court with the US Securities & Exchange Commission for $579m. Recent examples of prosecution include a $11.76m fine for a US drilling firm in April 2013 for bribing Customs officials.

While the business environment remains opaque, the administration has sought to improve transparency by expanding oversight of contractors through implementation of the 2010 Nigerian Content Act and proper processes for awarding contracts. NNPC’s subsidiary NAPIMS, which manages its stakes in oil developments, is also tasked with reviewing all contracts. Yet more marked improvements in the industry’s transparency still await passage of the PIB, which aims to clearly separate regulatory from operational functions of the state, and NNPC in particular (see analysis).

COMMUNITY RELATIONS: Relations between IOCs and local communities in oil-producing regions continue to be an issue, particularly in the Niger Delta where conflict over sharing oil revenues, environmental damage and job creation have long fuelled unrest (see Country Profile). Yemi Adeoye, CEO of D’AlphaXristi, told OBG, “Ensuring community support can be difficult, given that the benefits of economic development from investment are not always immediately apparent, and broadly speaking, communities often have high expectations and are not easily satisfied.” Dean Gabriel, CEO and managing director of Melchizedek, said that local business leaders can play a role here. “Collaboration with local businesses improves community support for projects by major multinationals. Local businesspeople are well placed to handle community relations in the Delta region, for example,” Gabriel told OBG.

As the IOCs continue to divest certain assets and local firms take on a greater role in the production of hydrocarbons, as well as in the provision of related services, ties between energy companies and local communities are expected to improve (see analysis). This is unlikely to be a cure-all, however, according to Ademola Adeyemi-Bero, managing director of FIRST E&P. “Perpetrators of vandalism and bunkering do not differentiate oil production from an indigenous company and an international one. But local firms often are able to place greater focus on social issues and community relations more fit for their situation, and this is a sound risk management strategy,” Adeyemi-Bero told OBG.

SERVICES: The last five years have seen significant changes in market share between the major oil services companies, with Baker Hughes gaining ground on Schlumberger, traditionally the dominant international services firm. Slower investment overall caused the number of rigs active in Nigeria to decline to 19 in January 2013, although this rebounded to 22 by April of that year, according to Baker Hughes’ rig count figures. While this remains roughly half the 50 rigs active in Angola, the spike in offshore E&P in the broader West African region has had an effect on global supply, according to Remi Okunlola, co-founder and executive director of Seawolf. “The increase in West African offshore activity has stretched the global supply of jack-up rigs. However, day rates for rigs have not escalated to the extent some anticipated. There is still a fair amount of uncertainty regarding the global economy, financial markets, and the Nigerian oil and gas industry.” Meanwhile, new laws passed in 2010 requiring greater local sourcing are prompting international firms to launch local partnerships and local firms to expand their capacity and ownership of equipment like rigs (see analysis).

IN THE ZONE: The dominant oil and gas free trade zone (FTZ) has traditionally been the Onne FTZ in Port Harcourt. The 26-sq-km zone, the world’s largest oil and gas centre providing logistics and fabrication services, had attracted cumulative foreign investment of N930bn ($5.9bn) from 150 investors as of 2013, according to the Federal Ministry of Trade and Investment. ENI subsidiary Saipem operates a 1m-sq-metre fabrication yard in the zone, handling $4.1bn worth of projects signed in the first half of 2013 alone. However, competition is increasing from Jagal Group’s Nigerdock, which runs a fabrication yard in Lagos, and the much smaller LADOL, traditionally a logistics centre that is now investing in fabrication capacity. These two Lagos-based zones are well placed for deepwater projects, as they are located roughly the same distance from them as Onne.

Given the volatile security situation in the Delta region in recent years, a larger share of work has gone to zones in Lagos. Samsung Heavy Industries, which won the contract for supplying the FPSO for Total’s Egina, concluded a $1bn partnership to complete fabrication on the 330-metre-long platform, including integration of the topsides and platforms, at LADOL. Nigerdock, which handled some fabrication on Total’s Usan FPSO, is partnering with contractors like Subsea 7 and operators like ExxonMobil to expand its fabrication capacity, particularly for wellhead platforms.

EXPORTS: Alongside the main FPSOs processing deepwater output, Nigeria hosts six main oil export terminals: Shell’s Bonny (Nigeria’s first, commissioned in 1961) and Forcados terminals, Chevron’s Escravos and Oloibiri facilities, ExxonMobil’s Qua Iboe and Agip’s Brass. These are connected to a network of 7000 km of crude oil pipelines, operated by NNPC’s Products and Pipelines Marketing Company (PPMC). The key crude pipeline is SPDC’s 48-year-old, 150,000-bpd Trans-Niger Pipeline, which has suffered some 25 leaks since July 2011 due to sabotage and theft that cost SPDC 60,000 bpd in losses, according to Shell. In June 2013 SPDC announced a major $1.5bn upgrade of the pipeline, involving burying a more secure pipeline deeper underground to reduce theft and pollution.

Nigeria’s five principal crude blends are considered amongst the world’s highest quality given their low sulphur content, high density and low acid content. These blends typically trade at a premium to benchmark Brent crude, ranging from $1 to $5 per barrel, according to CSL Stockbrokers. In May 2013 Bonny crude averaged $105.7 a barrel (down from $116.7 in January that year), compared to Brent’s $102.5 and an OPEC average of $100.6, according to FDC figures.

Suited for conversion to petrol and middle distillates like kerosene, diesel and jet fuel, Nigerian crude is traditionally processed by refineries along the Atlantic, particularly in North America and Europe. “Given that Asian refineries are typically less suited for Nigerian crude than European or North American ones, Nigeria generally must sell oil at a discount to Asian consumers,” Osam Iyahen, senior vice-president of natural resources at Africa Finance, told OBG. “This is significant given that sales to India have outstripped those to the US of late.”

As the US market becomes increasingly self-sufficient with the developments of the shale gas industry, Nigeria crude exports to the US have halved from 12% of US oil imports in 2011 to 6% in 2012. Exports to US slipped to 194,000 bpd in January 2013, the lowest in 18 years, according to the EIA, while India overtook the US as Nigeria’s largest export market in the same year.

DOWNSTREAM: Despite production far in excess of domestic consumption needs, Nigeria’s refining capacity has remained moribund, with successive rounds of turnaround maintenance on the four existing refineries failing to raise production to more than 30% of the total installed capacity of 445,000 bpd. Emeka Onwujuba, managing director of Neobosit Integrated Services, told OBG, “The government is dragging its heels on privatisation, particularly in the downstream sector.” This looks set to change in the near future, however, according to an interview given by Alison Madueke to Bloomberg in mid-November 2013, when she said that the government plans to begin privatising the four refineries before the end of the first quarter of 2014.

While several greenfield refining projects have been tabled, Nigeria still imports some 85% of its refined needs, particularly for premium motor spirit (PMS) (see analysis). In 2012 Nigeria’s aggregate daily consumption reached 30m litres of PMS, 10m litres of dual-purpose kerosene (DPK), 18m litres of automotive gas oil (diesel fuel) and 780 tonnes (1.4m litres) of liquefied petroleum gas (LPG), or cooking gas, according to the DPR. NNPC’s subsidiary PPMC operates the network of 4400 km of refined products pipelines, 21 fuel depots and eight LPG storage facilities. Local oil marketers have increasingly invested in their own storage facilities, particularly around major consumption centres like Lagos. “In the early 2000s Sahara Energy was the first to offer open tank farms to any trader, which led to a revolution in downstream fuel since marketers could now outsource storage requirements,” Peter Dugdale, managing director of AMG Terminals, told OBG.

According to industry sources interviewed by OBG, the largest open-access private depot operators include Aiteo, NIPCO, Sahara and Global Fleet. While the average size of depots remains relatively small, at around 25m litres, their rapid expansion has kept pace with real fuel demand growth of 7.5% per year on average over the past decade, according to OPEC figures. Nigeria boasts five main fuel station operators: Oando with 505 stations in 2012, Total with 500, MRS/Global Energy Group with 416, Nigerian Independent Oil Company (NIPCO) with 137 and Conoil with over 300. Local traders have increasingly imported directly from European refineries, squeezing international traders, which in turn have focused more on crude oil trading.

“As a growing number of Nigerian traders like Sahara or Oando have been able to imported refined fuel directly from Holland, foreign refined product traders’ share of the market has slumped,” Dugdale told OBG.

SUBSIDIES: With over 150 companies involved in refined fuel imports, as well as NNPC subsidiaries offshore such as Panama-registered Duke Oil, the market has been crowded, spurred by subsidies on refined fuel paid by Nigeria’s government through the Petroleum Products Pricing Regulatory Agency (PPPRA), the downstream regulatory agency, and administered through the Petroleum Stabilisation Fund (PSF).

Subsidy payments ballooned from 1.3% of GDP in 2006 to 4.7% in 2011, according to IMF figures. While the PSF is funded by transfers when market prices are below subsidised domestic prices, the majority of subsidy payments are covered through transfers from the Excess Crude Account when the world price is above the local market price, as has been the case over the past decade. In January 2012 the government cut subsidies in half, raising prices at the pump from N65 ($0.41) per litre to N97 ($0.61) per litre, but lower than the N141 ($0.89) per litre originally envisioned under a fully deregulated regime. This reduced the cost of subsidies to 3.6% of GDP in 2012, according to the IMF.

At the same time, the government sought to rein in excess subsidy claims and fraud, and indicted 99 “briefcase importers” who had been lodging multiple subsidy claims on the same oil imports. Stanley Okafor, the managing director and CEO of Integrated Marine & Petroleum Solutions, told OBG, “In response to the fuel subsidy scandal that broke in 2012, the government has tightened monitoring and inspection of petroleum products and is withholding payment for three to four months to allow clearance and approval.”

Following the probe, the PPPRA restricted import licences to owners of storage depots and transport infrastructure, licensing only 30 fuel importers in the second quarter of 2013. A new PPPRA pricing template in December 2012 reduced operating margins for importers to N1.18 ($0.01) per litre, according to Access Bank, or roughly N50m ($315,000) per fuel cargo.

FUNDING & BALANCING: NNPC funded its fuel imports through a mix of crude oil swaps executed through its New York-based trading account and debt. NNPC raised a syndicated $1bn loan in 2012, with some 30,000 bpd set aside by its operating subsidiary NPDC in order to cover repayment. Given delays in subsidy payments in 2012 amidst parliamentary probes, NNPC became the dominant importer of fuel, accounting for some 70% of total imports, according to PPPRA figures.

Meanwhile, fuel consumption dropped by 17% year-on-year to 38m litres of PMS daily in the first quarter of 2013, according to the Central Bank of Nigeria. As fuel importers are increasingly required to own their infrastructure, they have been prompted to integrate different lines of business. “To grow, you need to be an integrated oil company,” Tunde Akinpelu, executive director of Aiteo Group, told OBG. “We are seeing more fuel marketers and distributors expand vertically upstream into oil services, exploration and production.”

Quality control is another major issue when it comes to imported fuel products, according to Donatus Agbim, chairman of Vegasirius Nigeria. “Given the reliance of Nigeria on imported refined petroleum products, quality control becomes that much more important. Regulatory standards and capacity are currently insufficient to stop low-quality products from coming into the country. The private sector should take it upon themselves to train government regulators through seminars or training placements in their companies,” Agbim told OBG.

LPG: With some 82% of Nigeria’s total energy consumption made up of traditional biomass like wood, waste and kerosene in 2010, according to EIA data, the potential for shifting consumers to cleaner cooking gas, or LPG, is significant. Nevertheless, consumption of LPG declined from around 120,000 tonnes per year in 1992 to 50,000 tonnes per year in 2005.

Most of the LPG supply comes from the Escravos-Lagos pipeline as well as the 150,000 tonnes per year of LNG offloaded by NLNG tankers at Apapa port since 2007. By 2012 LPG consumption reached roughly 80,000 tonnes thanks to greater usage for cooking and heating, according to figures from Aiteo, but still shy of its 1992 peak. Although the market is over-supplied with LPG, efforts to shift demand towards gas have been gaining traction gradually, and storage capacity has indeed expanded markedly, particularly around Lagos, in the last decade. “We believe that availability drives consumption in the Nigerian LPG market,” Akinpelu told OBG. “Though our aggregate consumption remains below the 120,000 tonnes per year seen in 1992, the LPG storage capacity in Lagos alone has since quadrupled to 16,000 tonnes. This should drive consumption over the long term as more people switch their energy consumption away from wood fire and kerosene.”

By introducing 3-kg and 6-kg LPG cylinders in 2012, much more affordable than the previous 12.5-kg and 50-kg options, Oando has sought to accelerate conversion for lower-income households. Yet the main LPG consumers remain larger industrial concerns like Flour Mills of Nigeria and Dangote. NNPC subsidiary the Nigerian Gas Company (NGC) and Shell’s gas subsidiary, Shell Nigeria Gas, which was established in 1998, also supply firms such as GlaxoSmithKline, Unilever and Nestlé, for instance. In addition, Oando is expanding its gas pipeline network beyond Lagos, developing a new 128-km pipeline from Akwa Ibom gas producers to Calabar-based industries in Cross Rivers State, with planned capacity of 100m scf per day. An initial 22m scf per day is being delivered to United Cement in Calabar.

OUTLOOK: Although reform of Nigeria’s hydrocarbons industry appears to be delayed for now, significant changes are already under way. Expansion of NNPC’s producing capacity through NPDC, support for indigenous producers’ growing role in E&P, and increased local sourcing of goods and services are already being implemented despite successive delays in passing the PIB. Meanwhile, key elements of the master plan are gradually being developed to support the government’s power reform agenda. Yet clear visibility on the long-term fiscal framework is sorely needed to boost E&P investment as Nigeria’s proven reserves plateau, and its average production remains just over half of the government’s goal of 4m bpd. With greater competition for upstream investment from other African producers like Angola, the imperative is to enact reform before the 2015 election. Consultation with both traditional IOC investors and the relative newcomers like China’s oil producers will be key to accelerating investment.