Disagreement over offshore fiscal terms deters new IOCs investments

Disagreements regarding the right fiscal term for production in offshore deep water fields is a sticking point in the plans of International Oil Companies (IOCs) to conclude final investment decisions (FID) on oil and gas projects in Nigeria.

 

Major discoveries in offshore fields are yet to proceed to development as IOCs do not see a path to profitability in the proposed framework by the Nigerian government which seeks to raise royalty rates to between 3 and 8% and cut back taxes from 85% to 70% in new production sharing contracts (PSCs).

 

Shell’s plan to expand develop 225,000 barrels per day (bpd) Bonga South West/Aparo, has been unable to reach FID based on disagreement over fiscal terms. The project has been suspended every year since 2016.

 

Other projects that have stalled include 120,000bpd Zabazaba-Etan project; 140,000bpd Bosi project; 110,000bpd Uge project and 100,000bpd Nsiko deepwater project. The 1billion barrel Owowo field development is also waiting on the right fiscal terms among other conditions.

 

In a bid to prop revenues, Nigeria which gifts oil companies zero royalties in deepwater fields, has introduced a 3-percent royalty rate for projects located in depths of over 1,000 meters and another 8-percent royalty rate for fields that produce up to 50,000 bpd on deepwater projects. But the IOCs would not hear it.

 

In other OPEC countries, the IOCs pay royalties either based on crude prices or production volumes.

 

“But in these countries, they do not operate in the same difficult environment as Nigeria,” says Chuks Nwani, an energy lawyer. “In Nigeria, security is a big issue, there is regulatory uncertainty and contracting issues which raises cost of production for them.”

 

Nigeria’s terms have remained constant since 1993 and even when it recommends adjustment based on the rise of oil prices above $20 bpd, the Nigerian government has failed to enforce it leading to multibillion dollar losses.

 

Countries like Saudi Arabia and United Arab Emirates set their terms according to the capacity of the acreages and prevailing economic indicators such as oil price and output.

 

Crafted in 1993 when scant knowledge about deep offshore production existed, Nigeria’s PSCs were based on less than $20 oil price with anticipated drilling depths of 1,000 metres. Two decades later, Nigeria’s biggest production is far below 1,000 meters and oil prices rose above $100 per barrel prior to 2015.

 

The ministry of petroleum resources in March this year, released the draft of the National Petroleum Fiscal Policy (NPFP), which reviews the rate in the 1993 PSC but it is proposing rates that are not competitive industry stakeholders say.

 

Nigerian has introduced a Nigerian Hydrocarbon Tax which would be levied on the chargeable profits of upstream companies at the rate of 40% for onshore areas, 30% for shallow waters and 20% for deep water areas. Upstream companies will also pay Companies Income Tax 30% of chargeable profits.

 

Shifting focus from tax to royalties, the NPFP replaces removal of royalty payment based on water depth for a regime based on oil price and volume. It also mandates that royalties and taxes be paid on a monthly basis. Currently royalties are paid every three months.

 

“Under the policy, if you produce more than 50,000 barrels per day, at a price of over $100 per barrel, you could be liable to a royalty rate of 40%,” Seun Ajayi and Babatunde Akin-Moses, analysts at PwC said in a report.

 

The policy also seek to change the Associated Gas Framework Agreement, a part of the current Petroleum Profit Tax Act which allows gas producing companies take up 85% higher tax deduction against oil income and still pay tax at 30%. The NPFP sees gas as part of petroleum operations and sets a maximum tax of 70%.

 

“While there is nothing wrong with this, it is important to strike a balance between more revenue for government and attracting or retaining investments in the sector,” the PwC analysts counsels.

 

They further said, “While the proposals seek to remove or reducing existing incentives, there must be equally be a deliberate effort to tackle current disincentives in the sector. This balance is paramount to given a shrinking economy and growing need for foreign direct investment.”

 

Nigeria is proposing these rates at a time when competition for new projects is up in Africa, it lacks savings from oil sales and US, who was once a major market has become the competition.

 

Worse still, Nigeria’s key markets of China and India are investing heavily in alternatives including electric cars and the country has a poor refining capacity to meet rising domestic consumption.