Nigeria: Marginal Fields And The Petroleum Industry Act 2021: The Good And The Improvable Provisions

According to the 2020 Guidelines for the Award and Operations of Marginal Fields in Nigeria published by the defunct Department of Petroleum Resources (DPR), a marginal field is any field that has been discovered and has been left unattended for a period of not less than ten (10) years, from the date of first discovery or such field as the President may, from time to time, identify as a marginal field. Subsequent to the designation of oil fields as marginal fields, there is usually a bidding process through which the marginal fields would be "farmed-out" to third parties under farm out agreements (FOAs) with the original lease holders.

The government's main objectives for promoting this arrangement were to promote indigenous participation in Nigeria's oil and gas industry, increase the oil and gas reserves base and provide employment opportunities for the teeming population.

However, one of the major characteristics of marginal fields is that these fields may not have been considered for development by the lease holder because of assumed uneconomic returns under prevailing fiscal and market terms. In essence, the economics of a marginal field may not be considered as commercially viable using conventional development methods under the prevailing fiscal regime.

Hence, the government incentivized investments in such projects. For instance, marginal fields had lower royalty rates and some of the indigenous operators were able to enjoy tax holidays through the Pioneer Status Incentive scheme.

However, the Petroleum Industry Act (PIA), 2021 which was signed into law on 16 August 2021 introduced a new fiscal and regulatory framework for marginal field operations. In this article, we have reviewed the PIA to identify the "good" and the "improvable" provisions impacting marginal fields. The "good" provisions are those that will positively impact the marginal fields, while the "improvable" provisions are provisions that seem to be unfair or ambiguous and could adversely impact marginal fields.

The "Good" Provisions

1. Reduced Headline Tax Rate

The PIA reduces the headline tax rates of marginal field operators from 85% to 45%. Specifically, marginal fields will now be liable to Hydrocarbon Tax (HCT) and Companies Income Tax at 15% and 30% respectively. This steep reduction in the headline tax rate could be seen as an incentive to be enjoyed by the operators. However, it should be noted that the effective tax rate (ETR) may exceed 45% as the PIA provides for the non-deductibility of certain expenses such as finance costs and bank charges, for the purpose of computing HCT. More so, the costprice ratio ceiling of 65% of revenue for deductible costs may also increase the ETR of the affected companies.

2. Inapplicability of Farm-out Agreements for New Marginal Fields

Prior to the enactment of the PIA, the original lease holders maintained overriding rights over the petroleum operations to be carried out by the farmee. For instance, depending on the terms of the FOA, the farmor could be entitled to earn overriding royalties from production in the field. The terms for deep drilling were also embedded in the FOA, which implied that the farmor could lay claim to petroleum discoveries below the depth agreed in the FOA. Also, there was no clarity on whether marginal fields could continue to operate after the expiration of the license of the farmor.

However, under the PIA, marginal field operators will now be awarded Petroleum Mining Leases (PMLs) and Petroleum Prospecting Licenses (PPLs). Going forward, it is expected that the marginal field operators would have the exclusive right to conduct petroleum operations within the field. They will also have a direct relationship with the government instead of the initial lease holders.

Furthermore, the PIA provides that no new marginal field will be declared under the PIA, thereby confirming the government's intention of phasing out the current marginal field arrangements.

However, it should be noted that the PIA does not provide a clear framework for transition of existing marginal fields to the PIA regime and this appears to be an "improvable" provision as further explained below.

The "Improvable" Provisions

1. Lack of Clarity on Transition to PIA Regime

Section 94(1) of the PIA states that "a producing marginal field shall be allowed to continue to operate under the original Marginal field royalty rates and farm out agreements, but shall convert to a petroleum mining lease under this Act...". Based on this provision, the expectation is that producing marginal fields will become PMLs upon conversion to the PIA regime. However, the section also provides that a producing marginal field shall be allowed to continue to operate under the original Marginal field royalty rates and FOAs. Thus, it is not clear whether the conversion to PML invalidates the original Marginal field royalty rates and FOAs.

In essence, the PIA does not provide any framework for the transition of the FOAs to the PIA regime. This can lead to the assumption that marginal fields will be governed by both the FOAs and the PIA. However, the expectation is that the PMLs should ordinarily enable the marginal field producers to operate within the lease area on an exclusive basis. Therefore, there is a potential conflict in respect of the overlapping provisions of the PIA and the FOAs.

Meanwhile, based on Section 94(2) of the PIA, the non-producing marginal fields declared as marginal fields prior to 1 January 2021 would be converted to PPLs. For instance, PPLs were awarded to the winners of the recently concluded marginal field bid round. However, it is not clear how the original lease holders would be compensated for the costs they already incurred, especially considering that the draft Conversion Regulations published by the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) do not provide for FOAs. This could potentially result in legal disputes between the new PPL holders and the original license holders.

2. Compulsory Conversion to the PIA

One of the downsides of the provisions of the PIA is the requirement for marginal fields to mandatorily convert to the PIA regime within 18 months of the enactment of the Act i.e. by 15 February 2023. This compulsory conversion requirement does not apply to Oil Mining Lease (OML) and Oil Prospecting License (OPL) holders, as they were given the choice of either converting by 15 February 2023 or waiting till the mandatory timeline i.e. renewal of the licenses. However, marginal fields were not given this option and there could be economic or other reasons for marginal field operators to ordinarily choose to remain under the existing fiscal framework.

3. Royalty Regime

As earlier stated, the PIA provides that producing marginal fields shall be allowed to continue to operate under the original Marginal field royalty rates. This suggests that the royalty payable by marginal fields upon conversion to the PIA will be based on the Marginal Fields Operations (Fiscal Regime) Regulations 2005 (the Regulations). The Regulations provide for a concessionary royalty rate for marginal fields.

However, the Seventh Schedule of the PIA specifies the basis for the computation of royalties for marginal fields. Therefore, this results in a conflict that needs to be addressed through an amendment of the PIA.

We have highlighted in the table below, the royalty rates under the PIA and the Regulations based on the barrels of oil produced per day (bopd):

Based on the above table, crude oil production below 5,000 bopd were subjected to royalties at only 2.5% under the Regulations. In contrast, the same production volume could be liable to royalties at 5% under the PIA. This represents a 100% increase in the royalty rates for production below 5,000 bopd.

More so, the PIA also introduces a price based royalty which will be payable when oil prices exceed the specified benchmark prices in the Act. This will be an additional burden for marginal field operators.

4. Price Fiscalisation

Prior to the enactment of the PIA, the Federal Inland Revenue Service relied on Section 23 of the Petroleum Profits Tax Act (PPTA) in assessing upstream entities to additional taxes, based on the additional deemed revenue. The additional deemed revenue was computed based on variance between the posted or fiscal prices communicated by the defunct DPR and the actual realisable price for the sale of the crude oil. However, some of the affected players argued that the fiscal prices communicated by the DPR were for royalty purposes and should not be adopted as posted prices for the purpose of Section 23 of the PPTA, given that the PPTA required the taxpayer to agree the posted price with the government.

Interestingly, marginal field operators were mostly affected by the above situation because they are unable to command the kind of bargaining power that the International Oil Companies have with respect to pricing of crude sale, due to the low production volume associated with marginal fields. This implied that the realisable price could in certain instances, be lower than the international market prices and the fiscal prices communicated by the DPR.

However, Section 268 of the PIA stipulates that the NUPRC will now be responsible for determining the fiscal prices to be adopted in computing tax on additional deemed revenue. This implies that marginal field operators may be liable to additional tax where the fiscal prices determined by the NUPRC exceed the realisable price of such operators for the particular period. This appears to be an unfair provision, given that the affected companies will be subjected to tax on income that was not earned or received.

Conclusion

While the PIA introduced several "good" provisions, it appears that the "improvable" provisions could have a detrimental impact on marginal field operators.

Given that marginal fields are generally unattractive to develop from an economic perspective, fiscal sweeteners are required to encourage investors. Therefore, the government should consider reviewing the "improvable" provisions and providing additional incentives to encourage marginal field development. This will ensure the achievement of the government's objective of increasing indigenous participation in the Nigerian oil and gas industry.

The affected operators are also urged to engage the government for a possible amendment with "improvable" provisions as soon as possible.

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