The 2009 version of the PIB provides for an incremental sliding scale royalty rates based on daily production and value, designed in such a way as to automatically respond to project economics in what can rightly be referred as a “certain yet flexible system”. PIB 2012 on the other hand is silent on specific royalty rates but confers the powers to determine royalty rates on the Minister – S.197 states thus: “there shall be paid in respect of licences, leases and permits under this Act such royalties, fees and rentals as may be contained in this Act and in any regulations made by the Minister pursuant to this Act”.
Such a discretionary provision is a recipe for gratuitous speculation and arbitrary fondling with royalty rates which could undermine confidence in the fiscal regime. Stability of contract is a key investment consideration and an ideal fiscal system should strive to restrict administrative discretion to changes in fiscal terms. A self-adjusting system of royalty rates as designed in 2009 PIB is generally preferable even though the rates were considered too high by some stakeholders.
Assessing the competitiveness of royalty and tax instruments in the PIB from a global context and in comparison with existing regimes in Nigeria throws up interesting insights. Royalty rates as provided for under Section 5 (1) (a)-(d) and Section 5(2) of the Deep Offshore and Inland Basin Production Sharing Contracts Act, Cap D3 LFN 2004 has a maximum rate of 12% for production in water depth of between 201-500 metres and 0% for production in water depth above 10,000 metres. Applicable royalty rates on Joint Venture (JV) operations in Nigeria range from 20% (onshore), 10% (inland basin), 18.50% for production in water depth up to 100 metres and 16.50% for water depth up to 200 metres.
Royalty schedule in the 2009 version of the PIB may not be as deterrent as it was made to look by some stakeholders. PIB 2009 proposed royalty rate upper ceiling of 25% subject to ruling oil price and given the prevailing average price of crude of just above US$100 a barrel today, maximum rate of about 16% would have applied and could be significantly less depending on the area of operations.
In Venezuela, royalty rate is 30% and could go as high as 33.33%. 16.67% and 15% apply in Lybia and Kuwait respectively. While Onshore and offshore fields in the Gulf of Mexico (GoM) attract up to 30% and 16.667%. Royalty rate on Concession contract in Brazil is between 5%-10%. In Russia, it is RUB64 per barrel or RUB470 per tonne or 1.7% at current crude price plus an upward adjustment using exchange rate and crude price coefficients (note that there are other material upfront charges such as export duty).
On the main fiscal instrument which is tax, the proposed Nigerian Hydrocarbon Tax (NHT) is expected to be assessed at a rate of 50% for onshore and shallow water areas and 25% for bitumen, frontier acreages and deep water areas in addition to Company Income Tax of 30% in both cases which, at the moment, does not apply to upstream petroleum companies. Compared with the existing fiscal arrangement, Petroleum Profit Tax (PPT) of 50% is charged on Deep Offshore and PSCs, 65.75% on new companies and 85% on JV operations.
However, evaluation of fiscal regimes on the basis of absolute tax rates alone is flawed. Better measures capable of reasonably estimating competitiveness can be found in undiscounted government take or discounted company take statistic. These approaches are more holistic as they take into cognisance some or all variables that impact on overall project viability such as state participation, tax allowances and bonuses, price of crude, cost recovery limit, field size, life and decline rate,cost of capital amonsgt others. The latter is even more superior because it incorporates the time value of money.
Existing fiscal arrangements in Nigeria yields, on average, government take of 62% on deep offshore production and 75% for onshore and shallow waters. PIB on the other hand yields government take of about 73.8% and 81.6% on offshore and onshore fields respectively (using worst case scenario Royalty rates in PIB 2009). From a global perspective, world average government take for deepwater projects is 64% (note that this includes less prospective regions).Government take statistic under the PIB clearly shows a significant upward movement compared with the existing regimes but on average still less than government take of up to 90% in Venezuela. In Angola, government take averages 69.5%, less than 60% under the Brazilian Concession Contracts, up to 54% in Ghana (PSC), 72% in Norway, 77% in Cameroon and over 90% in Abu Dhabi.
From the foregoing, the current lobby by some investors for a more favourable PIB terms is somewhat understandable. Therefore, even as the government considers the existing terms as sub-optimal,there is need to strike a sustainable balance between the objective of seeking a fairer share of the oil wealth and attracting the much needed investment in the oil sector in order to optimise revenue. As the saying goes, “the art of taxation consists in so plucking the goose as to obtain the largest amount of feathers with the least possible amount of hissing”. It is equally important not to “frighten away the geese so that they lay no any eggs, golden or otherwise, let alone present themselves for plucking”. But come to think of it, the desire to obtain terms that are favourable is one thing, but no investor wants to negotiate the worst terms in a country, even if they are relatively good terms from an international perspective, says Daniel Johnston, an expert in international petroleum fiscal systems design. In the final analysis, the key consideration in the design of petroleum fiscal system depends largely on the relative geological potential of each country.
Ubohmhe Glenn Olowojaiye
