Nigeria sets out on oil reform to curb corruption
The country's new president promises reform in oil policy and a war against the corrupt practises in the African nation
Muhammadu Buhari, who will take office as Nigeria’s president at the end of May, has a vision for the country’s troubled oil industry. With an end to terrorism in the Niger Delta and a culture-change war against corruption, investment will flow in and oil production will rise. Local oil-service companies will grow, environmental problems will be addressed — and rising tax receipts will make up for the fall in oil prices.
Buhari has form as a decisive leader. As oil minister in the late-1970s he foresaw the competition Nigeria would face from North Sea oil, and introduced sharper marketing arrangements to challenge it. Less creditably, when head of a military government in the mid-1980s he was heavy-handed in his campaign against corruption and indiscipline.
The problems he faces are immense. Much of Nigeria’s corruption is entrenched in support of tribal and political factions, to the extent that many do not recognise diverting state money to local interests as corrupt. Theft of crude on a massive scale in the Niger Delta — Shell has described it as “a parallel industry” — hardly ever leads to prosecutions, because senior figures in the administration and military are said to be involved.
But Buhari’s background could make him the best hope for bringing change. As a Muslim from the north of the country and a former general, he will have two important factions on his side — and a revitalised military will be more effective in dealing with Islamist terrorism in the north. His big challenge will be winning-over the dissenters in the oil-producing states of the delta, where the previous president had his heartland.
The indications are that the state’s Nigerian National Petroleum Corporation (NNPC) — widely regarded as the source of much of the country’s corruption and political patronage — will be an immediate target for Buhari’s reforms. The company holds interests of 55% or 60% in the joint ventures which produce about 1.5m barrels a day (b/d) out of Nigeria’s total output, including condensates, of approximately 2.3m b/d (see Table 1).
NNPC is supposed to pass on the proceeds from the sale of its shares of crude to the government, being funded itself by a treasury hand-out, but there are often allegations that not all of the cash is being remitted. Most recently, in early 2014 the governor of the Central Bank of Nigeria, Mallam Lamido Sanusi, claimed that at least $10.8bn, and perhaps as much as $49.8bn, had not been passed on over an 18-month period — but was dismissed for saying so. Buhari has promised an investigation into the allegation.
NNPC’s import arrangements for refined products are also likely to see early attention. The company operates opaque swap deals with traders under which it supplies consignments of crude in exchange for refined products, sourced on world markets. The scheme is attractive to traders because it is cashless, and crude volumes can be generous — but the arrangements are inefficient and, according to the Nigeria Extractive Industries Transparency Initiative last year, could be costing the country $8bn a year.
NNPC, with a staff of about 10,000, is a powerful force of patronage and is certain to resist moves to reform it. It is likely to be given a new senior management team, and then split into four new entities covering upstream, gas distribution, refining and pipelines, and inspectorate activities. The new companies will be expected to be commercially-driven and will be able to raise funding internationally.
Buhari’s party — the All Progressives Congress, an alliance of opposition parties — has promised to “speedily” pass the Petroleum Industry Bill (PIB), the long delayed re-writing of the country’s oil laws. Also on the agenda are moves to develop the oil-service sector, with the aims of lifting employment and allowing local-content targets to be raised.
Existing plans to end the flaring of gas will be enforced and companies will be required to sell at least half of their gas output in Nigeria, with local utilisation encouraged. Liquefied natural gas (LNG) export schemes will be encouraged, as will the construction of refineries, and there are plans to promote exploration in the country’s northern areas.
However, since the election, party sources have been indicating that pushing through the PIB might not be an immediate priority, given its contentious nature and the pressure of other legislation. It is suggested that it could be broken up into a series of bills, with the more contentious measures left to last. But that would prolong the uncertainty for the oil companies, which has led to a collapse in exploration and a long list of stalled development projects.
Some unacceptable aspects of the PIB have now been removed — in particular, the requirement in an early draft for the creation of incorporated joint ventures, in which the producing companies would have held minority interests under NNPC’s majority. But there are still substantial concerns over fiscal and governance aspects.
The PIB’s revised fiscal arrangements would raise the tax take on joint-venture operations from 86% at present to 91%, according to an industry estimate, while the take from production-sharing contracts — introduced in 1993 when deep-water blocks were offered for the first time — would rise from 30% to 77%. The tax on gas production under joint ventures would rise from zero to 60%.
The PIB also sets up a fund for local communities in the oil-producing areas and demands that producing companies pay 10% of their monthly net profits into it — a controversial measure even within Nigeria’s administration because the existing revenue-sharing formula already provides for the oil-producing states to share an additional 13% of income. The PIB gives considerably increased powers to the minister of petroleum resources, which could facilitate further tax and cost increases for the companies and could open another potential route for corruption.
Relations with local communities in the Niger Delta will be an early test for the new government. Since 2009, the level of violence and damage to oil installations in the delta has been reduced through an amnesty programme, under which militants are paid and offered job training. Many have been given contracts to secure oil installations, although they might also be involved in oil theft. The programme is costly and the new administration will want to replace it, running the risk of a resurgence in violence.
Years of uncertainty over the PIB, together with sabotage in the delta, have led to cuts in exploration and development spending, with the result that Nigeria’s production capacity has declined. Output peaked in 2005 at 2.4m b/d (excluding condensates), according to the International Energy Agency, but then fell steadily until 2010 when the amnesty scheme is credited with allowing an increase. In recent years production has declined again, to only 1.9m b/d in 2014 (see Figure 1).
In view of the conflicts and logistical difficulties associated with the delta, the deep-water offshore has been seen as Nigeria’s best area for future oil operations. But, 22 years after the first licences were offered, only five large fields have been brought on stream — the most recent in 2012 — and there is only one stand-alone development project in progress. Perhaps five ready-to-go developments are effectively stalled, awaiting clarification of the fiscal terms which will apply when the PIB is passed.
All five producing fields use large floating production, storage and offloading (FPSO) vessels, together with subsea wells. The first to start flowing, Shell’s Bonga, in 1,000 metres of water, came on stream in 2005 and has now been joined by Bonga Northwest, the first area step-out.
Bonga Northwest is a subsea tie-back to the Bonga FPSO, coming on stream in August last year. It is due to produce a peak of 40,000 b/d of oil-equivalent, keeping the flow through the FPSO at close to its capacity of 200,000 b/d of oil and 4.25m cubic metres a day (cm/d) of gas. At the end of last year Shell said it would drill an additional eight wells at the main Bonga field, in its third-phase development.
ExxonMobil’s Erha field and its Erha North satellite both came on stream in 2006, flowing through an FPSO with a capacity — recently increased — of 200,000 b/d. Production has been running at 140,000 b/d. The company’s Erha North Phase 2 project — a subsea tie-back to the FPSO — is due to come on stream in fourth-quarter 2017 and will flow 60,000 b/d, taking up the spare capacity on the FPSO.
Chevron’s Agbami field came on stream in 2008 through an FPSO with a capacity of 250,000 b/d. The company is implementing a Phase 2 development, under which 10 wells are being drilled to maintain peak production, and it is planning a Phase 3 which will see another five wells drilled.
Total’s Akpo condensate and gas field started producing in 2009, through an FPSO with a capacity of 175,000 b/d of liquids and 9.1 million cm/d of gas. Total also has the Usan field, brought on stream in 2012 using an FPSO with a capacity of 180,000 b/d. The company is trying for the second time to sell its interest in Usan, after an agreed sale to Sinopec in 2012 fell through. It is understood that ExxonMobil will take over as operator if a sale is made.
The only new-field deep-water development project under construction is Total’s Egina, launched in 2013 and targeted for first oil at the end of 2017. Egina lies in the same licence as Akpo and about 20 km southwest of it, at a water-depth of 1,600 metres. A total of 44 wells will be needed, to flow a plateau of 200,000 b/d through an FPSO with 2.3m barrels of storage.
There were hopes that another new-field development — the Shell-operated Bonga Southwest-Aparo — would have been launched by now, but the investment decision has been put back to 2016. The stand-alone project covers a structure extending from Shell’s OML 118 into Chevron’s OMLs 132 and 140, with a pre-unitisation agreement giving interests to those companies together with ExxonMobil, Total, Eni, Sasol, NNPC and Oil & Gas Nigeria.
The development plan for Bonga Southwest-Aparo — lying at a water-depth of over 1,300 metres — envisages 44 wells, flowing to an FPSO with a capacity to process 225,000 b/d. Shell is said to have had a budget of $12bn for the project, but earlier this year there were reports that bids were pointing to a total of $16bn. Contractors have been asked to make savings.
Meanwhile, the long list of deep-water projects still “in development planning” — as they have been for many years — includes Shell’s Bonga North (a large stand-alone development), Bolia and Doro, ExxonMobil’s Bosi and Uge, Chevron’s Nsiko, Eni’s Etan and Zabazaba (likely to be a joint development), and Total’s Owowo. Likely production rates for these fields add up to about 750,000 b/d, potentially lifting the country’s output to 3m b/d.
Onshore and in shallow-water, the majors are exiting licences in favour of local companies who might be seen as less of a target for terrorism. Shell and partners have completed 10 such sales since 2010. Most recently, in March, Shell (30%), Total (10%) and Eni (5%) completed the sale of their interests in OML 18 to Eroton, with NNPC retaining its 55%. In November last year the companies sold the same interests in OML 24 to Newcross.
Earlier sales by Shell and partners have covered OMLs 30, 34 and 40 in 2012, OMLs 26 and 42 in 2011, and OMLs 4, 38 and 41 in 2010. ConocoPhillips and Chevron have also sold licence interests.
PIB uncertainties are also delaying the expansion of the NLNG complex at Bonny — an investment which established a successful new industry for the country, paying the government taxes totalling $1.3bn last year together with substantial dividends on the state interest. NLNG — made up of NNPC with 49%, Shell with 25.6%, Total with 15% and Eni with 10.4% — has a six-train facility and wants to build a seventh train, but will not take a final investment decision until the PIB is passed and the tax treatment of feed gas is made clear.
The NLNG complex has a production capacity of 22m tonnes a year (t/y) of LNG together with 5m t/y of liquefied petroleum gas and condensate, and uses 36bn cm/y of feed gas — almost as much as the entire consumption of the Netherlands, as NLNG points out. Train 7 will lift LNG output to 30m t/y.
NLNG, coming on stream in 1999 with two trains, has performed well but has not been immune to Nigeria’s problems. Production declined in 2013 as a result of damage to pipelines supplying gas to the facility, together with a dispute over levies with the government’s shipping authority, Nigerian Maritime Administration and Safety Agency, which prevented ships leaving Bonny for over two weeks.
There are still hopes for the construction of a second LNG complex, at Brass, under a plan dating back to the early years of the century. After several structural changes, the Brass LNG venture received another setback last year when ConocoPhillips, a participant, withdrew from the country — but remaining partners NNPC (49%), Total (17%) and Eni (17%) have said they will share the spare 17%. They plan to construct a two-train facility with a capacity of 10m t/y.
Brass LNG said it was close to a final investment decision when ConocoPhillips pulled out. The venture is now having re-design work carried out to change the liquefaction process from ConocoPhillips’ Optimised Cascade technology to Air Products’ APCI process.
For the average Nigerian, the main change the PIB will bring is likely to be negative: if fuels marketing is deregulated, prices will rise. Nigeria’s gasoline price is among the world’s lowest at N87 ($0.43) per litre since January, when it was cut from N97 in the run-up to the election.
Since most of Nigeria’s gasoline has to be imported, maintaining a low price is immensely costly for the government. The 2014 budget allocated N971bn ($4.84bn) for the subsidy, although with lower prices the allocation was cut to N459bn ($2.29bn) for 2015. However, attempts to raise the price in the past have led to riots, and have had to be reversed — for most Nigerians, low-cost fuel is the only benefit they see from living in an oil-rich country.
The subsidy also supports large-scale illegal exports of gasoline to neighbouring countries. Consequently, Nigeria’s gasoline imports are vast — they probably exceed 300,000 b/d, although gasoline consumption, partly covered by refinery production, is estimated at 180,000 b/d.
Higher fuel prices will be necessary if Nigeria is to achieve its ambition of constructing private-sector refineries. Various projects in the past have failed, but there are high hopes for a plan launched by Aliko Dangote — said to be the country’s wealthiest businessman — and backed by $3bn of his cash, together with debt. He plans to build a refinery at Lekki, just east of Lagos, and in March raised the envisaged capacity of the facility from 400,000 b/d to 650,000 b/d. The $11bn project, with a 2018 start-up target, will include a large petrochemicals and fertilisers complex.
Meanwhile, the country’s 445,000 b/d of refining capacity operates at woefully low utilisation rates. There are two facilities at Port Harcourt, one at Warri and one at Kaduna, all owned by NNPC and all affected by inadequate maintenance, fires and pipeline damage. Combined output rarely averages more than 25% of capacity.