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Nigeria endangers IOC interest for quick fiscal fix

The government’s revision of PSCs to seek more revenue from oil majors will backfire if it prompts them to reevaluate their portfolio investment priorities

The latest move by Nigeria to raise revenue from the oil industry, a law constituted in record time in November, could add up to $1.5bn to the government’s coffers over the next two years but quickly backfire in subsequent years, say participants in the country’s oil sector. 

Nigeria’s President Muhammadu Buhari gave executive assent to a bill amending the 1993 Deep Offshore and Inland Basin Production Sharing Contract (PSC), with the aim of increasing the governments revenue from oil production. 

Before the amendments, royalties ranged from 0pc to 12pc based on the water depth of the field. The new law eliminates the 0pc rate and royalties are calculated on a basis dependent on the chargeable volume of the crude and condensates produced per field. 

The new rates are 10pc for offshore in water deeper than 200m and 7.5pc for frontier or inland basins. Under the old Act there was a flat 10pc rate. However, the amendment also imposes an additional royalty rate tied to the price of crude when it is in excess of $20/bl, rising in four increments until a 10pc rate is due when the price is above $150. 

“The royalty increase could adversely impact on operating costs to the point of encouraging companies to ‘get clever’ about how their costs are declared” Omonbude, Eraskorp

Other amendments that came with the new Act include a stipulation that all PSCs will be reviewed every eight years. Under the old Act, reviews were supposed to be triggered when oil prices exceeded $20/bl in real (inflation-adjusted) terms but this was never enforced. 

The new Act also introduces a new section that states that any person who does not comply with any of the provisions is committing an offence and is liable, on conviction, to a fine not less than NGN500m ($1.38mn) and/or at least five-year imprisonment. 

The move, according to Senate leader Ahmed Lawan, will add at least $0.5bn to the treasury this year and $1bn the year after. President Buhari says the law will help Nigeria “receive its fair, rightful and equitable share of income from our own natural resources for the first time since 2003”. 

It has proved popular with many people in Nigeria; advocacy groups and union leaders have hailed the law as commendable. It is “historic and developmental” as well as “a smart patriotic economic move which has balanced the age-long corporate greed in the oil and gas sector with urgent national needs in terms of revenue,” in the assessment of Issa Aremu, a member of the executive council of the Nigerian Labour Congress (NLC). 

Unintended consequences 

As the law increases operating costs for oil and gas companies operating under PSC arrangements, analysts, as well as sector advocacy groups, say that local players will struggle to cover the costs as they lack the balance sheet capacity of international players. Oil and gas industry body Oil Producers Trade Section (OPTS) says the new rate increase could decrease future investment in future deepwater projects by at least $15bn and lead to a 20pc decline in deepwater production within three years. 

Nigeria, through its state oil company Nigerian National Petroleum Corporation (NNPC), has PSCs with several international oil companies (IOCs), which combined pump nearly two-thirds of the country’s average daily output of 2mn bl. 

“[The law will help Nigeria] receive its fair, rightful and equitable share of income from our own natural resources” President Buhari

Analysts at PricewaterhouseCoopers (PwC) say while the Nigerian government’s intention in applying price-based as well as field-based royalties is to increase treasury revenue, it will reduce the profitability of investments and therefore force companies to reassess the commercial impact on the cash flows from existing and future investments. 

“The government was well within its rights to make the amendment,” says Ekpen Omonbude, group managing director of Lagos-based service provider Eraskorp to Petroleum Economist. “As required by the 2004 Act, we had reached its 15th anniversary and crude oil prices were higher than $20/bl. The conditions for an amendment had been met. However, royalty increases, while essentially guaranteeing early revenues for the government, it is recovered by the contractor along with other eligible costs.” 

The contractor pays the royalty as a percentage of gross revenues as soon as production starts, notes Omonbude. Then, when calculating costs to deduct for the purpose of calculating petroleum income tax, the royalty is included. So, if the royalty paid upfront was $20, and cost of production was $30, eligible costs to deduct for tax purposes would be $50, according to the law.

Upward revisions of petroleum fiscal instruments of this nature, and in this context specifically, risk incentivising base erosion and profit shifting. “Depending on the size of the operation, the royalty increase could adversely impact on operating costs to the point of encouraging companies to ‘get clever’ about how their costs are declared,” says Omonbude. 

“The existing fiscal system implemented in accordance with this Act—both original and various amendments—is regressive, [in the sense that] the fiscal system is unable to capture an incremental share of project revenues in the event of an increase in profitability. This is why, typically in desperate times, governments are tempted to make upward revisions to royalty rates, cost recovery limits, taxes etc. whenever it is apparent that they could be losing out on the upside. The effective tax rate—i.e. the combined effect of royalties, production sharing splits between the government and contractor and [other] taxes—for many of these contracts is already around the 84pc mark or higher. One wonders how much further up it must go.” 

Risk to revenue 

Nigeria’s reliance on the new law to boost revenue, amid a worsening long-term debt profile, would be unsuccessful if oil prices and/or output decline. It may cut offshore production by nearly 30pc over the next four years, according to analysts at Stratfor, a leading geopolitical intelligence firm based in Austin, Texas. 

The potential commercial impact on oil companies' cash flows from existing and future investments could be severe. Greg Priddy, director, global energy and Middle East, at Stratfor says “recently completed projects such as Shell's Bonga will see a hit to their profitability.” Nigeria, he says, “has been successful in growing output [during] the last couple of years, but if they keep the fiscal regime changes in place, it will render them uncompetitive for future investment in deepwater offshore projects, which is where they have a lot of potential for volume growth. 

$15bn Potential decrease in deepwater investment resulting from fiscal changes

“This is effectively a short-term versus long-term tradeoff. Squeezing the companies now increases state revenues, but undermines the investment needed to maintain production volumes into the future. There are plenty of places where the IOCs can develop offshore resources, and the recent bid round failure in Brazil shows that the market is not favorable for host-country governments right now. I suspect that they will need to relax this in a few years as their production begins to decline—but that could be too late, particularly if demand growth weakens due to climate change policies in consuming countries.” 

Shell Nigeria has criticised the new law. It would create additional challenges for operators that are already “faced with a lot of regulatory challenges in Nigeria, changes in regulations that are impacting the ability of Nigeria to attract investment,” according to Bayo Ojulari, managing director of Shell’s exploration and production subsidiary SnepCo. 

The uncertainty around further reviews of PSCs could also serve as a deterrent to investments in the sector, according to analysts at PwC. “The lack of certainty around the fiscal outcomes of impending PSC reviews may constitute a disincentive for future investments in these assets especially where other investment destinations provide more attractive risk and returns,” it stated in a November 2019 report.

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