An undeniable giant in the energy world, Nigeria faces some challenges in terms of performance and progress of its hydrocarbons sector. These include broad issues like politics and insurgency, in addition to the specifics of regulating a large energy sector. Its natural gas is even more abundant than its oil, but Nigeria has so far failed to realise more than a fraction of its gas potential. However, remedies seem to be in hand. If and when they work, the country will be a giant indeed.
STORY SO FAR: While oil prospecting began in Britain’s Nigerian colony as early as 1908, large-scale exploration did not start until 1937, when British company Shell D’Arcy received an exploration licence covering the whole of Nigeria. The company (now known as the Shell Petroleum Development Company of Nigeria) discovered its first commercially viable oil deposit in 1956 at Oloibiri in Bayelsa State, and first exported in 1958. Independence from Britain came two years later, and by the early 1960s, US giants Mobil, Texaco and Gulf had acquired oil concessions. Production peaked at 420,000 barrels per day (bpd) in 1966, prior to the outbreak of a civil war that was fought partly over issues of control of the oil-rich Niger Delta region.
The 1970s saw a global oil boom, further development of the oil industry and infrastructure, and consolidation of federal government control in the sector. The Nigerian National Oil Corporation (NNOC) was founded in 1971, mainly to serve as an obligatory partner to foreign oil companies, and the state’s claims on resources expanded over the decade. In 1979 the NNOC – restructured and given most of the Ministry of Petroleum’s supervisory functions – was renamed the Nigerian National Petroleum Corporation (NNPC), serving as proxy for the federal government that would now hold a minimum 55% share in all petroleum ventures.
CENTRAL PLAYER: Commercialised in 1988, NNPC was and remains something of a behemoth, covering the entire gamut of activities in the oil and gas sector. Its structure includes companies for exploration and production (Nigerian Petroleum Development Company, NPDC), for the domestic gas industry (Nigerian Gas Company, NGC), for each of the country’s three oil refining centres at Warri, Kaduna and Port Harcourt, for transporting oil to and output from those refineries and ensuring supplies to the domestic market (the Products and Pipelines Marketing Company, PPMC), and for natural gas liquefaction (Nigerian Liquefied Natural Gas, NLNG). This last subsidiary is a joint venture (JV) with three foreign companies.
Still a mandatory partner for hydrocarbons producing companies, NNPC is far from being a modern national oil company in the mould of Brazil’s Petrobras or Saudi Aramco. To remedy this – and much else – Nigeria’s decision-makers intend to introduce a modernised legal framework for the sector. Commonly referred to as the Petroleum Industry Bill (PIB), this piece of legislation was at the time of press close to passing through Nigeria’s parliament (see analysis). If approved, it would be a welcome development: four years of delays have effectively put decision-making in the sector on hold.
COSTS & BENEFITS: Nigeria’s oil is considered highquality for its low-sulphur (“sweet”) character that makes it easy to refine. It is also not difficult to access. Onshore reserves are mostly in the country’s south-west and, while not concentrated in convenient giant fields, they are geologically uncomplicated and near the surface. Offshore, there are both shallow and deepwater fields, but even the latter, although challenging, are not exceptionally so by international standards.
However, the sector faces a number of challenges. The Niger Delta’s problems are not only logistical. A deep sense of injustice felt by many of its inhabitants found expression in a local insurgency that disrupted oil production severely until it was ended by an amnesty in 2009 and, as of 2012, it is far from clear that the troubles are definitively over (see analysis). Even without insurgency, grievances, poverty and tricky terrain combine to produce a high rate of sabotage, theft and theft-related damage on the pipelines that take oil out of the Delta, with losses estimated at 150,000 bpd. Moreover, the Delta has over the years suffered significant environmental damage connected with hydrocarbons extraction, with a vigorous dispute on who is to blame. A more proactive approach by the international oil companies (IOCs) may serve to alleviate some of these local challenges, however. “To maintain environmental standards, companies must be proactive with the communities in which they operate. There is also a need for an inter-IOC contingency programme to deal with environmental problems,” Adams Mamudu, the executive director at GCA Energy, told OBG.
OUTPUT RECOVERY: More prosaically, Nigeria is not producing as much oil as it might. According to BP’s “Statistical Review of World Energy 2012”, its 2011 output level was around 2.45m bpd of oil and condensate, roughly 2.9% of global production, making it the world’s 12th-largest supplier. That meant that Nigeria had almost, but not quite, regained the extraction level of 2005, and recovered from the significant dip resulting from the insurgency in 2008-09. Production is up in 2012, partly because the 180,000-bpd offshore Usan field has come on-line, and record production of 2.7m bpd was announced in late July. However, the country is still far behind the 4m bpd potential continuously quoted by Nigerian politicians. In 2000, this output level was scheduled for 2010. Now it is slated for 2020.
RESERVE LEVELS UNCHANGED: In July 2012, Osten Olorunshola, director of the Department of Petroleum Reserves (DPR), put reserves at 36.2bn barrels. BP report’s figure, at 37.2bn barrels, is more optimistic, placing it second in Africa after Libya (47.1bn barrels) and 10th globally, accounting for 2.3% of global reserves. Strikingly, reserves have risen not since 2006 ( compared to a growth of 21% in proven reserves worldwide), which is disquieting, since at 2011 rates of extraction, those reserves would not last for 42 years.
But this is not surprising: serious bidding rounds for exploration acreage have not been held since 2007, with the government and multinationals both waiting for the Godot-like PIB. Indeed, much investment remains on hold until the PIB’s final content becomes clear. This holdup has affected numerous facets of the sector. “As a result of the delayed passage of the PIB, demand for infrastructure and equipment has practically dried up; only one IOC is active,” Mohammed Dahiru, the CEO of Damagix Nigeria, a local oil services company, told OBG.
There have been promises of a bidding round later in 2012, with Olorunshola pointing out that 215 of the country’s 388 acreages have yet to be allocated. Nontraditional areas are now being examined. In February 2012 Diezani Alison Madueke, minister of petroleum, announced that the government had earmarked $1bn for seismic surveys, exploration and appraisal drilling in the Chad Basin and six other inland frontier basins. And some put Nigeria’s total oil potential far higher than proven reserves. In June 2012, former presidential oil advisor Emmanuel Egbogah estimated a total of 113bn barrels had “yet to be exposed and fully exploited”.
Expectations, meanwhile, seem more cautious: officials regularly mention a total of 40bn barrels for 2020. With reserves being used up at around 1bn barrels a year, Nigeria must act quickly. Global consultants Wood McKenzie warned that, without the expected investment boost with the passage of a satisfactory PIB, output would likely decline about 20% from 2016 to 2020.
MARKET STRUCTURE: The bulk of Nigeria’s oil production is done by IOCs, or more precisely, the JVs and production-sharing companies (PSCs) that these firms have operated with NNPC in the existing market. The JV model has been applied onshore and in shallow water offshore fields, while PSCs have been utilised in Nigeria’s increasingly important deepwater sector. While NNPC has largely lacked an operational role in either case – its main activity is to claim the money corresponding to its share – the JV/PSC distinction has remained important in certain ways.
In PSCs, the contractor’s production expenses, including investments, are deducted from revenues, and the balance is shared between partners. However, in JVs, partners are jointly responsible for investments, and since the NNPC is usually cash-strapped, it has often not been in a position to contribute its share of vital investments in a timely fashion. This leaves its partners with the hard choice of fronting NNPC’s share or foregoing investments. Along with security considerations, this is one reason why offshore production has developed more quickly than onshore in recent years. Deepwater production accounted for a third of oil output in early 2012, compared to under 10% as of end-2005.
GLOBAL FIRMS: Of the IOCs, those most in evidence in oil production are Royal Dutch Shell (Shell), France’s Total, and US-based Chevron and ExxonMobil. Companies involving these major players accounted for, between them, 84.8% of crude output in 2011, according to NNPC data, which puts “terminal oil” output at just over 2.37m bpd. Fields operated by Shell yielded 612,000 bpd (25.8%), those of Exxon almost 593,000 (24.9%), those of Chevron over 517,000 (21.8%) and Total’s was upwards of 291,000 bpd (12.3%). Fields run by a JV involving Italy’s Agip and America’s ConocoPhillips accounted for almost 95,000 bpd, although the latter has indicated its intentions to withdraw from Nigeria.
The new offshore Usan field – operated by Total – will substantially increase the French firm’s record in 2012, while Shell, once the biggest oil producer in Nigeria, will continue its policy of reducing its onshore footprint. The company has been motivated in part by a government keen to promote indigenous participation, but Shell has also been reacting to security risks and disruptions in the Niger Delta (see analysis). Along with its junior partners in the onshore JV SPDC – Total holds 10% of the company, while Agip owns 5% – Shell sold interests in seven Delta blocks between 2009 and June 2011. And in July 2012, the sale was announced for a reported $850m of a 45% share in the eight-field, 45,000-bpd Block 30 to an alliance of local Shoreline Energy and UK-based Heritage Oil.
While now well-established in Nigeria’s offshore sector – notably in the 200,000-bpd deepwater Bonga field – Shell has by no means given up the Delta region, talking recently of investments of $4bn in onshore oil and gas. Renewal of onshore licences have also been eagerly sought over the last couple of years by Chevron, Exxon and Agip, as well as Shell.
Addax Petroleum Nigeria, a subsidiary of Chinese conglomerate Sinopec Group, increased production from 9000 bpd in 1998 to over 90,000 bpd today. Operating two offshore rigs, the firm is looking to add two more by the end of 2012. Given China's high demand for oil, Addax has plans to boost production by acquiring new shallow water assets OML 123 and 126, alongside increased offshore activity.
HOME GROWN: Local firms that have become increasingly important operate alongside the IOCs (see analysis). These smaller firms may have been strengthened by the requirement that they compete with the major players. “The presence of IOCs brings innovation to the marketplace, which challenges local firms, but creates a higher standard,” Dickson Okotie, the general manager of Eunisell, an oil and gas services firm, told OBG.
The government has supported development of indigenous capacity through its “marginal fields” initiative. Started in 2004, the programme is meant to transfer small, unexploited fields from IOCs to putatively nimbler local companies. According to Eke Eke, the group managing director for West Africa at Schlumberger, the programme is beneficial for the sector. “Fears that Nigeria is leaning towards economic nationalism by reclaiming unused or inactive acreage are unwarranted; this happens in many places around the world and is needed to keep the industry dynamic and competitive,” he told OBG.
However, overall output of these marginal fields has not been spectacular. In a speech made in June 2012, former presidential advisor Emmanuel Egbogah said that their combined output was around 22,000 bpd – less than 1% of total Nigerian oil production – although he estimated that they could raise this to between 40,000 and 50,000 bpd by 2014-15 with operators’ existing programmes. A second round of marginal field allocations has been talked about, but it has not yet happened.
LOCAL CONTENT: Shell has been selling off some of its onshore assets, with local firms well-positioned to buy these fields thanks to the Nigerian Oil and Gas Indigenous Content Development Act, known as the Local Content Act, passed in April 2010. While this legislation has helped domestic firms, some industry participants feel more could be done. “The biggest issue with the Local Content Act is the capacity to monitor compliance data of foreign players. Too often we find that stated facts and figures are incorrect, which leaves smaller, indigenous players out of the game,” Uchenna Duaka, the managing director of Hull Inspection & Research Services, told OBG.
Other challenges exist for local firms, such as unwillingness on the part of IOCs to partner with domestic players. “The debate is a hurdle when we consider that IOCs typically feel more confident working with an international brand, and often demand the vast experience of expatriate personnel with internationally recognised qualifications,” Andrew Hunter, managing director of SGS Industrial Services, told OBG. Sam Jaja, managing director at Piprox Group, stresses that, “Local content is more than simply ‘everything must be Nigerian.’ The policy must facilitate and enforce the development of adequate skill sets for the local population.”
The issue of ensuring adequate skill sets is a challenging one, and one that the government is trying to address through agencies such as the Petroleum Technology Development Fund (PTDF), which focuses on technical training for fields such as engineering and geology. According to Muttaqha Rabe Darma, the executive secretary of the PTDF, the Local Content Act was an essential piece of legislation for the industry. “Since 2010, the level of technical development with regard to Nigerian engineering and management skills has increased dramatically,” he told OGB.
CHANGING PLACES: Nigeria’s oil sector is oriented largely towards the export of crude, with the country’s refineries hardly in a position to sell abroad. According to NNPC data, exports averaged 2.25m bpd in 2011, around 5% down from 2010 but higher than every other year since 2005. The country’s oil exports’ geographical spread is quite wide: of the 2011 total, 33% went to North America, 30% to Europe, 16.5% to Asia, and 9.7% and 8.6% respectively to South America ( especially Brazil) and to African states (largely South Africa). And the geographical structure has been fairly dynamic: the volume exported to North America in 2011 was 37% lower than in 2007 – when it had accounted for well over half of foreign sales – while exports to Europe more than doubled in the same period. Asia is also increasingly important, with an NNPC official announcing in mid-2012 that the US was about to be overtaken as an oil export destination by China.
AN AIR OF REFINEMENT: At present Nigeria is home to just four refineries, all owned and operated by NNPC. An attempt at privatisation in 2007 was later abandoned in the face of public disapproval. All four refineries are relatively old facilities, with vintages ranging from 1965 to 1980. Two of these refineries are in the Niger Delta centre of Port Harcourt, with a combined capacity of 210,000 bpd, and one each are in Warri (125,000 bpd) and Kaduna (110,000 bpd). Aggregate capacity is thus around 445,000 bpd, but operation has regularly been below rated capacity: in the relatively good year of 2011, for instance, Warri operated at 41.7% capacity, Kaduna at 22.2% and the Port Harcourt refineries at 15.3%. The reasons vary. Capacity is not only old, but also poorly maintained, while the pipelines connecting the refineries to the oilfields that supply them are subject to both sabotage and theft.
Whether or not there are solutions to these problems is unknown, and a special task force reportedly set up to assess the refineries’ problems is still being awaited. “The government has controlled the refineries for too long. The PIB needs to include public-private partnership promotion for the development of local refineries in Nigeria,” Prince Atte Timothy, managing director of Bonny Transocean, told OBG.
Authorities have been negotiating for turn-around maintenance by the companies that built the refineries. Officials say this could restore capacity utilisation to 90% within two years, although there have been calls for privatisation, an option that would be allowed under the PIB. “The government has taken a clear direction towards withdrawal from the management of our country’s refineries,” Obiamarije Stanley, managing director and CEO of Shorelink Oil and Gas Services, told OBG. “To increase private sector participation, the deregulation agenda needs to be pushed forward.”
NEW REFINERIES: As for additional refinery capacity, it has long been planned, but none has yet materialised. In 2002 the government issued 18 licences to private companies for refinery construction, but progress has been slow on these facilities. Challenges have included high local financing costs, an absence of government guarantees to attract external financing and a lack of confidence that subsidies would be forthcoming for the fuel produced.
A more substantial promise came in 2010, when NNPC and the China State Construction Engineering Corporation (CSCEC) signed a memorandum of understanding (MoU) for a $28.5bn project to construct three new refineries, as well as a petrochemicals plant. The refineries, which were to be situated in the Lagos Lekki Free Trade Zone, Bayelsa and Kogi States, were expected to come on-line in 2017 and have a capacity of 250,000 bpd each. However, plans were subsequently scaled back, reducing the total to 400,000 bpd (200,000 for Lagos and 100,000 each for the other two). The Industrial and Commercial Bank of China was to provide 80% of the $11.3bn equity finance, with NNPC supplying the remainder. Construction was initially set to begin in May 2011, but was the date was moved to July 2012, according to a late 2011 MoU. However, as of August 2012, the project had still not launched, for reasons that have not been made public. While there is no hint that the project has been abandoned, a startup date of 2017 now seems unlikely.
SMALLER PROJECTS: Even if the CSCEC refineries come later than expected, a quicker fix is in the works, according to a July 2012 MoU signed between the government and the two investors, US-based Vulcan Petroleum Resources and the Nigerian company Petroleum Refining and Strategic Reserve (PFRS). The agreement envisages six new refineries with a total capacity of 180,000 bpd and an investment of $4.5bn. Although locations are not yet clear, all six are to be on-line within 30 months, two in a single year. Modular methods will help speed things up and circumvent the difficulties of local construction: the units will be built in the US, dismantled and reassembled on site. All funding is to be secured from outside Nigeria, according to PFRS. Details are not clear, but this likely means that there will be no financial participation by the government.
July also saw a MoU between the federal government and local player Epic Refinery and Petrochemical Industries for a project at Oporoma in Bayelsa State, to be carried out as a JV between Epic and its partner Sino Asia Energy Group. Aside from a 180-outlet filling-station chain, petrochemicals facility and 500 MW of electricity capacity, this project will involve a 100,000-bpd oil refinery and investments of $7.5bn.
Despite some uncertainty regarding these projects, some industry players are sanguine about the prospects for Nigeria’s refineries. “With proper investments and legislative reforms, Nigeria has the ability to export refined petroleum products and create lasting multiplier effects in the industry,” Samuel Adegboyega, the managing director of Sowsco Well Services, told OBG.
SUBSIDY WOES: A complication to private sector involvement in the refining sector has been the heavy government subsidy on petroleum products, ostensibly for social reasons. At end-2011, petrol was sold for N65 ($0.42) a litre, less than half of the otherwise market rate of N140 ($0.90). This was a major drain on the federal government’s overstrained budget. Indeed, in July 2012, minister of finance Ngozi Okonjo-Iweala reported that the state had spent N2.19trn ($14bn) on fuel subsidies in 2011, around N1.7trn ($10.9bn) of which comprised of arrears from earlier years.
The subsidy issue has made headlines in 2012. At the beginning of the year the government announced it had eliminated subsidies altogether, raising petrol prices to N140 ($0.90) per litre. But public outcry and widespread strikes forced the government to reduce the pump price to N97 ($0.62). The PIB, as tabled in July 2012, has provisions that would eliminate subsidies, but it is unclear how soon this policy will be carried out.
DISPUTED TERMS: Meanwhile, the authorities and oil marketing and trading firms to which fuel subsidies are paid have been at loggerheads. Despite disbursement of around N500bn ($3.2bn) by late June 2012, continued arrears slowed petrol imports, with firms concentrating on diesel imports, whose profitability was not dependent on subsidies. Marketers went as far as to stage a brief strike in late July, which did accelerate government payments somewhat.
INCENTIVES TO CHEAT: On the other side, parliamentary and presidential committees have looked at the issue of subsidy fraud and concluded that it has been a major problem and obstacle. One government estimate was that N422bn ($2.7bn) out of a total of N1.7trn ($10.9bn) paid to subsidise fuel imports in 2011 had been claimed fraudulently. The Presidential Committee on Verification and Reconciliation of Subsidy Payments classified 25 oil-marketing and trading firm companies as “likely fraudulent cases for criminal investigations” and another 50 as “recommended for further investigation”. Alleged scams include claims for fuel that was not in fact imported, the re-export of subsidised fuel to countries with no subsidies and some cases of multiple claims for imported and re-exported fuels.
Subsidies are also criticised for undesirable distribution effects, as they favour car-owners, not to mention foreign consumers who benefit from illicitly exported subsidised products. They also drain public finances, making it difficult for the government to invest in productive projects. Moreover, subsidies distort incentives: one important reason why liquefied petroleum gas – a promising form of domestic fuel widely utilised in other countries – is underused in Nigeria is that, unlike kerosene, its price is not subsidised (see analysis).
GAS GIANT: While the Nigerian hydrocarbons sector is at present dominated by oil, its future may lie more in natural gas. The potential is enormous. In terms of proven reserves, figures vary. In July 2012 the director of DPR, Osten Olorunshola, cited 183trn cu feet (tcf), although 187 tcf is more commonly mentioned, while the BP report gives 180.5 tcf. Whichever figure is correct, it is an impressive total. The BP figure puts Nigeria ninth in the global pecking order, far behind Russia, Iran, Qatar and Turkmenistan, less dramatically below the US, Saudi Arabia, the UAE and Venezuela, and gives it 2.5% of global proven reserves. But the country’s potential is likely much greater. As nobody has been looking specifically for gas in Nigeria until recently, its proven gas reserves have essentially been the by-product of oil exploration. Potential resources of around 600 tcf – more than three times higher than the level of proven reserves – are regularly mentioned.
Inevitably, there is bad news as well. First, although Nigeria’s gas (like its oil) is generally high-quality, a high proportion of what has been proven and what has been accessed is “associated”, meaning that it occurs in oil deposits and is extracted along with oil. At best, this means extra expenses in separating, treating and piping the gas and, at worst, the waste of flaring it. Around 52% of proven gas reserves are associated, while figures cited by Olorunshola in July 2012 suggest that the associated gas and oil currently being extracted is around 65%, with over a quarter of that amount flared.
Second, proven reserves have been undynamic: while they rose around 47% between 1999 and 2003, according to the BP report, they are now at roughly the 2003 level, having first risen and then fallen back with extraction in the interim. The explanation is the same as for oil: a lack of bidding rounds in recent years and the uncertainty caused by the delay in the passage of the PIB.
PRODUCTION LEVELS: Output, however, has shown some dynamism. The BP report gives figures that exclude flaring and reinjection, which stood at 1.7bn cu feet per day (bcfd) and 950m cu feet per day (mcfd), respectively, in 2011, according to NNPC. According to BP, Nigeria’s gas output in 2011 was 3.9 bcfd, giving it 1.2% of world output and placing Nigeria third in Africa (after Algeria and Egypt) and 16th globally. In growth terms, Nigeria’s performance has been impressive, albeit from a low base. Output rose from 0.4 bcfd in 1991 to 1.4 bcfd in 2001, topping the 3-bcfd mark in 2007. The 2011 total marks an 11% rise on 2010, while figures cited by Olorunshola suggest production in July 2012 was running at as much as 44% higher than the 2011 average.
According to NNPC statistics, companies involving five IOCs accounted for no less than 97.2% of total output, excluding flaring and reinjection. Shell was the clear leader, and the companies it operates produce 56.5% of the total, or nearly 2.22 mcfd. Agip was the runner up with 17% and 335,000 cfd. The others were Chevron (11.2%), Total (9.1%) and ExxonMobil (3.4%), although the shares of the last two were affected by reinjection on a very large scale (278,000 and 602,000 cfd, respectively). Medium-term expansion prospects appear to be good. In July 2012, for instance, Shell announced that it had 17 gas projects worth $6bn under development in Nigeria, and is working hard on the objective of eliminating flaring – which, in 2011, it had already reduced to less than 10% of the total gas it extracted.
PIPE DREAMS: As of 2011, Nigeria was exporting most of the natural gas it produced. According to the BP report, exports that year accounted for 67% of the country’s total production excluding flaring and reinjection. The vast majority of exports are in the form of liquefied natural gas (LNG) from what is at present the country’s only LNG plant at Bonny. Having started production in 1999, Bonny now boasts six trains – the most recent commissioned in 2007 – and is operating at close to full capacity. A seventh train is under consideration, while plans for two other large-scale LNG plants – at Brass and Olokola – have been on the table for years. No final investment decisions have been made for any of the three projects, however, as financial considerations, world market conditions and the balancing of domestic and export priorities mean that none are a foregone conclusion (see analysis).
The rest of exports in 2011 were accounted for by Nigeria’s single international gas pipeline, the 687-km West African Gas Pipeline, which was commissioned in 2009 and is sub-Saharan Africa’s first regional gas distribution system. Linked to Nigeria’s most important domestic gas line – the Escravos-Lagos pipeline – it runs offshore and supplies gas from the Niger Delta to the neighbouring countries of Benin, Togo and Ghana. It is owned by a consortium that includes Chevron (36.7%), NNPC (25%), Shell (18%), Ghana’s Takoradi Power Company (16.3%), and the gas companies of Togo (2%) and Benin (2%). Its capacity is 170 mcfd, expected to rise to 460 mcfd. Its operation has generally been successful, although it experienced technical problems in 2010, while in early 2012 supplies were affected by the demands of Nigerian domestic consumers.
More ambitious, if implemented, would be the 4300-km Trans-Saharan Gas Pipeline (TGSP), a project designed to carry up to 1.1 tcf of gas per year from the Niger Delta over the Sahara Desert to the Algerian export terminal of Beni Saf on the Mediterranean, giving it easy access to European markets. This was the subject of an MoU between NNPC and its Algerian counterpart Sonatrach in 2009 and has been a topic of much discussion in the press. TGSP has been seen as a move by the EU to reduce its dependence on supplies from Russian gas behemoth Gazprom. The plot thickened as, also in 2009, Gazprom signed a JV agreement (Nigaz) with NNPC, involving plans to share infrastructural knowhow, invest $2.5bn in gas infrastructure and perhaps – as a countermove – help build TSGP.
However, development of TGSP and Nigaz has been slow since 2009, as formidable technical challenges and costs – estimated between $13bn and $20bn – are compounded by the security problems and local rivalries.
The latest news on TGSP came from senior NNPC official David Ige, who in February 2012 said that the government was “reconsidering” the project given falling global gas prices. As for Gazprom, there has been no activity, and Russian officials explained that Gazprom is frustrated by the uncertainties entailed by PIB delays.
STEPPING ON THE GAS: In practice, the attention of Nigeria’s decision makers to natural gas are focused nearer to home than Beni Saf. Their aspiration is to increase the use of gas locally, with an eye to making the economy stronger and more diversified.
This found its first expression in the Gas Master Plan put out in February 2008 by the late President Umaru Yar’Adua. It defined gas utilisation aims and the transitional mechanisms to kick-start the domestic gas market and guide it through phases of “full commerciality”, “full liquidity” and “full market-driven status”, the last of which was set to begin in January 2014.
Gas pricing policy was to make production for the domestic market progressively more attractive for gas companies until a free market mechanism could take over. Domestic gas supply obligations were to function as a stick, supplementing the pricing carrot for as long as necessary, by forcing producers to dedicate a growing proportion of their output to domestic users. Finally, a “Nigerian gas infrastructure blueprint” was to ensure that the necessary 2100 km of pipelines and three central processing facilities (CPFs) were put in place.
GAS REVOLUTION: Yar’Adua’s successor, President Goodluck Jonathan, has been clear about his commitment to the Gas Master Plan, and in March 2011 fleshed it out under the slogan of “Gas Revolution” by unveiling intended investments projects. These included a petrochemicals plant to be built by the Saudi firm Xenel Industries (see Industry chapter), a fertiliser plant by India’s Nagurjama, and a $3m gas plant for one of the three CPFs, to be built at Obiaruku by a consortium of Italy’s Eni and local player Oando. “The government knows it will have to harness the private sector to fill the power generation gap. To do that it needs to implement a pro-private sector regime,” Phillip Ihenacho, executive chairman of Septa Energy, told OBG.
Total investment involved in the master plan would come to $25bn, said Jonathan, while domestic gas utilisation would soar from 1 mcfd to 10 mcfd in 2020. By 2014, Jonathan declared, Nigeria would have been “firmly positioned as the undisputed regional hub for gas-based industries such as fertilisers, petrochemicals and methanol”. But some industry players are more sceptical. “Nigeria has huge potential for the production of petrochemicals, but pricing, infrastructure and disputes on domestic gas continue to hold back the opportunities,” Vito Testaguzza, the managing director at Saipem Contracting Nigeria, the local subsidiary of the European oil services firm, told OBG.
Developments are clearly under way. Gas output is rising briskly in 2012, and domestic gas availability will grow even more sharply with the Bonny terminal already operating close to capacity. Headway in infrastructure is also being made. During a presentation in Houston, Texas in May 2012, NNPC’s David Ige listed 198 km of pipelines at or near completion strengthening the country’s western pipeline system, as well as a vital 327-km line due for completion in early 2013. The latter would double the capacity of an existing line for transmission to the western system, to 2 bcfd.
POWER PLAY: The immediate focus is on ensuring that Nigeria’s problematic but expanding power sector has sufficient gas. A one-year “gas emergency” was declared in April 2012 to solve existing problems and pre-empt a shortfall of around 400 mcfd. Electricity, specifically the poor payment record of the Power Holding Company of Nigeria (PHCN), is among the most obvious financial problems for sector development, although it may prove soluble given institutional innovations and World Bank risk guarantees (see Utilities chapter).
Ige’s presentation shows that expectations are high: total demand (including exports) in 2017 is projected at about 11 bcfd. Of this, perhaps 5.5 bcfd is accounted for by pipeline exports (still small) and foreign sales of LNG. The latter is expected to amount to roughly 5.3 bcfd as against 3.7 bcfd in 2012, which appears to reflect the expectation that substantial capacity will have come on stream at Brass or Bonny. Gas consumption by the power sector is assumed to have trebled to around 4 bcfd, while gas-based industries and the industrial consumers served by local distribution companies are projected to consume around 1.35 bcfd.
INDUSTRIAL DEMANDS: Development of two industrial complexes with CPFs is envisaged in 2011-16 and 2012-18, respectively, with front-end engineering design to commence in August 2012 and final investment decisions to be taken in January 2013. Additional facilities are planned from 2017 onwards. However, there are both challenges and prospects. Aside from the PHCN payment difficulties, Ige’s presentation sites two long-term issues. First, financing for certain critical gas transmission infrastructure has either been delayed or is not yet available. There are also three crucial large pipeline projects, namely Ob/Ob-Oben (estimated cost $481m), Ajaokuta-Kano ($1.7bn) and QIT-CalabarAjaokuta ($1.4bn ). Given these costs, a rise in the gas transmission tariff from $0.30 to $0.79 per million BTU will be needed if the lines are to be financed by third-party investors. This increase may need to be greater, as costs can be up to 20% higher than original estimates, affecting the prices power companies pay for fuel.
Second, says Ige, the “long gestation period for high-impact supply projects puts major supply additions outside the short to medium term”. This means that, although it has been increasing briskly of late, gas supply cannot be relied upon to go on doing so.
OUTLOOK: As is the case with many elements of the Nigeria energy sector, how the natural gas sector evolves depends on the effectiveness of the impending overhaul of the regulatory framework – above all, implementation of the PIB. There are also questions about whether or not authorities are determined enough to allow prices to reflect costs and to approve the market mechanism. For these issues, time alone will tell.
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