Nigeria’s Terrible Oil Decision
Nigeria has adopted the Finance Act 2020. A step which unacquainted with the phenomenon might seem completely innocent yet poses great risks to the future of Africa’s largest oil producer. A trend which has been for a several years in the making – ever since a couple of Nigerian states initiated a lawsuit against their own government for allegedly not collecting the maximum possible revenue under the 1999 Production Sharing Contracts Act, compelling the Buhari government to embrace the issue. The idea that the government should have increased its deepwater intake as prices edged higher is certainly a tempting one but hard to force through in a retroactive fashion. The Buhari government eventually settled the lawsuit with the federal states, committed to take on the oil majors present in Nigeria.
First of all, the timing of the endeavor seems remarkably ill-timed: the IMO 2020 era is putting a premium on sweet crudes which make up the overwhelming majority of Nigerian production. When the Buhari administration launched its drive to review deepwater terms Nigeria, still relying on oil and gas for almost 60 percent of government revenues, had just weathered several years of attacks on oil infrastructure in the Niger Delta, hence it would seem politic keep things rolling when some semblance of stability was achieved. Up until 2019 the Nigerian authorities have maintained a shroud of strategic ambiguity over the oft-mooted deepwater reform – never a confirmation that tax hikes might be applied retrospectively nor an assertion that they should be universally applied without exceptions.
The first step was taken in November 2019 when Buhari signed the abrupt increase on deepwater royalties into law. If previously all deepwater projects on the Nigerian shelf (i.e. in water depths of 500 meters and more) were subject to an 8% royalty rate regardless of external conditions, the new amendment now forces companies to pay a unified 10% rate and also a price-based additional component to be added onto the production-based one. If the price of oil moves in the 0-20 USD per barrel interval the price-based royalty is null, however within the 20-60 USD per barrel range it leads to an additional 2.5% added to the overall royalty rate, 60-100 USD per barrel result in a 4% rate. Although stopping short of going for retroactive action, this in itself has raised many eyebrows.
Second step – the Nigerian government adopting the Finance Act 2020 which has amended several oil-relevant laws, with the same purpose of maximizing government revenue. The list is quite conclusive: from increasing the VAT rate from 5% to 7% and including all intangible products and assets into the category of taxable, levying the corporate income tax on all services provided by foreign companies to Nigerian entities all the way to curbing the exemption of profit dividends from the petroleum profit tax (PPT). The value added tax regime changes are of special significance as all license transfers would from now on entail a VAT payment towards the government. Now why would President Buhari adopt such a rigid stance under circumstances which dictate above all flexibility and prudence?
The answer lies in Nigeria’s 2020 budget and Buhari’s internal political standing. First and foremost, it is the largest on record at $34.6 billion, adopted with the assumption that the budget deficit would amount to 1.52% of the nation’s GDP. Second, Nigerian authorities intend to return to the international debt market to finance the deficit (an issuance of $3.3 billion worth of Eurobonds is assumed to take place in H1 2020), having stayed out of it throughout most of 2019. Third, the 2020 budget assumes a 57 per barrel price – thus, should oil prices stay depressed as they are now Nigeria would teeter on the edge of being breakeven. At the same time, Buhari has been under increasing pressure to act as his 2019 Presidential elections win was somewhat marred that he lost in almost every southern state and the capital, too.
In brief, President Buhari is forced to spend big – his plan to splash $30 billion on infrastructure should be approved in the upcoming months – and for this reason he wants to maximize government revenue. Yet Nigeria seems to have chosen the worst path to attain the purported goal of weaning the country off crude income, instead of tightening the federal and regional authorities’ tax collection capacity (a 2018 UN report found that the shortfall between its potential and actual VAT collections amounts to almost 70%) it opted for the abovementioned deepwater tax hikes. One of the worst performers in Africa, Nigerian tax revenues equal to only 6% of its GDP (roughly one-third of the OECD average) yet oil producers are the ones to bear the brunt of future expenses.
In the short term, this might not be reflected in any sharp reductions in crude production or export volumes, moreover, the 10-12% per year decline in hostage-taking and infrastructure-targeted attacks that has been taking place since 2017 has contributed to an uptick in crude exports (massively boosted by the Egina startup in early 2019), with 2019 average levels being on the verge of rising above the 2mbpd threshold, at 1.99mbpd. Yet if one is to look beyond the current day, they would inevitably discover a gaping discrepancy between commercially viable oil discoveries in Nigeria’s offshore and the dearth of final investment decisions on them. In fact, the last major FID was on Egina, back in 2013.
Recent moves from international majors indicate that unless the Nigerian government softens the blow from the deepwater tax regime reassessment, it risks shooting itself in the leg in terms of ensuring future production. First, some majors will simply leave. For instance, Total has already announced its intention to sell its 12.5% stake in the Bonga deepwater project. Second, even the most cost-efficient projects will get delayed. The viability of the Shell-operated $9.7 billion Bonga Southwest/Aparo project (peak output at 145kbpd) was directly linked to Nigeria not deteriorating commercial terms for drillers. Even the Total-operated Preowei project (70kbpd at peak) seems to have its FID delayed into 2021, despite being a tie-in to the Egina FPSO. Exxon’s $8.2 billion Owowo West (140kbpd at peak) was postponed indefinitely. And that’s only the peak of the iceberg.
Source: oilprice.com
