Related Articles
Forward article link
Share PDF with colleagues

Nigeria has a major problem

Opec production cuts matter far less than international companies deciding to scale back production and capex

Uncertainty often surrounds how Nigeria plans to implement crude production cuts after it has agreed them with Opec. But, this time, IOCs are trimming output anyway due to plunging prices, depressed demand and limited storage—and analysts expect foreign firms to further reduce their presence in Africa’s largest oil producer.

NOC Nigerian National Petroleum Corporation (NNPC) has ambitions to raise the country’s oil production to 3mn bl/d by 2023. But such targets are increasingly implausible, and output will decline in the next few years “unless there are marked improvements in the business and investment environment and security”, warns Gail Anderson, research director at consultancy Wood Mackenzie.

Oil production in April was 1.78mn bl/d, according to Opec’s May report. As part of the group’s cuts announced in mid-April, Nigeria agreed to reduce crude production to 1.41mn bl/d from 1 May until the end of June. Production will then increase to 1.5mn bl/d until the end of 2020 before rising to 1.58mn/d for the 16 months starting 1 January. Nigeria’s 460,000bl/d of condensate production is exempt.

“In past cuts, there was never any great expectation that African countries would comply fully with them,” says Anderson. “The regulator has been busy drawing up instructions for operators to comply, but the key point is that following the price crash in mid-March we have seen very deep cuts in capex by all major operators in Nigeria.

“Those cuts will have a big impact on investment and will flow through to production as well. Cuts to production are coming anyway because of the market conditions.”

“IOCs probably would sell more of their Nigerian assets if they could. The big question is whether they can actually exit” Anderson, Wood Mackenzie

More than 100 companies operate in Nigeria’s upstream sector, according to a 2019 report by local investment bank Afrinvest. NNPC holds majority, non-operating stakes in 11 joint ventures with several IOCs including Shell, ExxonMobil, Chevron and Total. IOCs produce 80pc of Nigeria’s crude output, with Shell alone accounting for 40pc and operating the deepwater Bonga field with a 55pc interest. Shell also holds a 44pc interest in another deepwater field, Erha, the report states.

ExxonMobil has a 30pc operating interest in the deepwater Usan field. Total’s affiliates produce oil and gas through multiple shallow water and onshore concessions and also operate the deepwater Akpo field. Chevron is Nigeria’s second-biggest producer, pumping around 400,000bl/d as of January 2019 and operating and holding a 40pc stake in the Agbami field.

The licensing structure of production-sharing contracts (PSCs) may make it difficult for the government to force IOCs to comply with cuts, says Joseph Gatdula, head of oil and gas analysis at intelligence provider Fitch Solutions.

“It is not part of the [PSC] agreement so it is uncertain how these legally could be foisted upon the IOCs,” says Gatdula. “How exactly Nigeria goes about counting crude versus condensate remains to be seen… there may be some significant shifting from crude to condensate.”

To cope with the price plunge, oil companies have filled storage to capacity, aggressively cut costs and trimmed production. The next stop will be to shut in wells.

“Shutting in a well is easy. The challenge is that if it remains shut for too long, transport infrastructure such as pipelines gets clogged—and unclogging that can be very expensive,” says Ekpen Omonbude, a petroleum and mining economist and group managing director of oil and gas services provider Eraskorp. “That is a painful choice to make. [But] IOCs will start announcing shut-ins in the near term, should the macro picture not improve.”

Engineering, construction and procurement contractors are bearing the brunt of cost cuts. “They are already getting letters telling them existing contracts and/or future contracts need to be slashed by at least 40pc,” says Omonbude. “That means the scope of work is being changed, and margins are almost if not completely eroded. In some cases, they are looking at outright contract cancellations.”

Decisions on developing new deepwater fields, which have a breakeven price of around $60/bl will be postponed. Similarly, short-term projects that provide quick returns and are based on discretionary spending are also on hold.

“The IOCs are pulling back on infill oil-well drilling programmes and simple one-well tie-backs. Those incremental barrels are just not going to get drilled,” says Gatdula.“Any capex related to drilling wells is pretty much on hold, which is increasing the impact of the natural decline rates and bringing overall field production down.”

The coronavirus pandemic has had little effect on oil companies’ operations in Nigeria, with much of the Niger Delta supply chain based locally. International contractors have been unable to fly in engineers from abroad due to travel restrictions, which has impacted projects under development more than ones already onstream.

“We have not had any instances so far of production [being] shut in because of the coronavirus—there is a big effort to ensure there are no infections offshore, because with everyone in close proximity there is a big risk of infection spreading,” says Anderson, noting workers are isolated for 14 days prior to transfer to offshore facilities. “They are also working with a skeleton workforce offshore. The measures so far seem to be working.”

Oil provides about half of Nigeria’s tax base and more than 85pc of its goods exports, ratings agency S&P Global Ratings estimates, so the slump in both crude prices and production has further weakened the country’s already-strained finances.

Nigeria’s fiscal deficit will widen to 7pc this year, predicts consultancy Capital Economics. The country’s current account deficit (exports minus imports) could more than double to 3.3pc of GDP, S&P Global Ratings forecast in March.

Precipitous drop

In response, the government plans to increase value added tax, cut fuel subsidies and raise electricity prices. The naira, which the government devalued by 15pc in March, will probably weaken further, making dollar-denominated oil income worth more in local currency terms, but all these measures would not be enough to mitigate the precipitous drop in crude prices and oil revenue.

In an attempt to boost state income, Nigeria’s president Muhammadu Buhari in January amended the 1993 Deep Offshore and Inland Basin PSC. Before these changes, royalties ranged from zero to 12pc based on the field’s water depth. The zero-rate has been scrapped, with royalties now calculated based on the chargeable volume of the crude and condensates produced per field.

“Nigeria’s deepwater projects are already delayed because of a lot of fiscal uncertainty, and this increase in government share from deepwater production makes it harder for IOCs to sanction new projects,” says Anderson.

“IOCs will start announcing shut-ins in the near term, should the macro picture not improve” Omonbude, Eraskorp

Following the royalty increase, Wood Mackenzie put back its estimates for the start dates for all Nigeria’s new deepwater fields. For example, Preowei is now expected to begin production in 2025, Bonga Southwest in 2027 and Owowo in 2029.

“I still believe Shell wants to go ahead with Bonga Southwest, and Total would like to develop Preowei because it is such a small field that you can tie back to the existing infrastructure. But [for] a bigger project such as Owowo, I doubt ExxonMobil will develop it because the company has better projects in its global portfolio,” says Anderson.

Continued uncertainty surrounds the Petroleum Industry Bill, which was first brought before the National Assembly in 2008 but has yet to become law. The government has changed the bill’s structure several times, and in February stated that it hoped it would be passed by mid-2020. That now seems improbable.

“There are not many people outside the petroleum ministry—perhaps [even] the presidency—who have seen the new bill,” says Omonbude, who worked on four versions of the bill between 2008 and 2012. “I would imagine the industry is likely to push back against it, or at least request consultation.”

That is because the IOCs want to lower the overall effective tax rate on Nigeria’s oil industry, which is 84-86pc including royalties, taxes and PSCs, according to Omonbude’s calculations.

“IOCs probably would sell more of their Nigerian assets if they could,” says Anderson. “The big question is whether they can actually exit.”

The investments are deepwater assets and joint-venture assets onshore and in shallow water. “It is not an easy thing to leave, with potential decommissioning liabilities as well. Nigerian M&A is really a niche market and there are not many companies that want to enter because of the above-ground risks. The outlook is very uncertain.”

Also in this section
Latest licensing rounds
23 September 2020
The industry's most comprehensive list of current and recent rounds for onshore and offshore licences
Kosmos sheds frontier portfolio
22 September 2020
Explorer divests non-core assets to cut costs and focus attention on proven basins
Petrobras pulls back spending
18 September 2020
Spotlight falls on pre-salt production as Latin American NOC dials down capex