Legal consequence of Nigeria’s recent amendment of the Deep Offshore Inland Basin (Production Sharing Contract) Act

Nigeria’s President gave his assent to the Deep Offshore Inland Basin (Production Sharing Contract) Act CAP D3 LFN 2004 (Amendment) Bill 2019 recently passed by the National Assembly. The Bill amends the Deep Offshore Inland Basin (Production Sharing Contract) Act (the “Principal Act”) mainly by providing for a different royalty regime. This paper scrutinises the fiscal provisions of the Bill in the deep offshore area and the potential implications of its passage. Before doing so however, I will discuss Production Sharing Contracts (PSCS) in Nigeria and provide a background to what made the Principal Act necessary.

PSCS and the Deep Offshore Inland Basin (Production Sharing Contract) Act

Prior to the promulgation of the Principal Act, Nigeria’s fiscal terms were determined by the Petroleum (Drilling & Production) Regulations (“PDPR”) (Rent & Royalties) and the Petroleum Profits Tax Act (“PPTA”) (Taxes). Under the PDPR the applicable royalty rates were:

The PPTA provides for taxes at 65.75% for the first five years of a company’s production and 85% thereafter.

Nigeria entered its first PSC in 1973 with Ashland Oil. Ashland Oil’s assets were acquired in 1998 by Addax. The PSC became the preferred petroleum development agreement for the Nigerian government in 1993, when Nigeria sought to develop its deep offshore resources and was unwilling to contribute money as it had done under the joint venture arrangement. In recognition of the risks associated with developing these offshore assets, the PSCS were designed to provide enough fiscal incentives to encourage International Oil Companies (IOCS). Under the PSCS signed in 1993 (1993 PSCS), the royalty rates were graduated according to water depth as follows:

The royalty rates were applicable to the contract area. The 1993 PSCS also provided that the applicable petroleum profits tax rate to the contract area would be 50%. These provisions contrasted with the royalty provisions under the PDPR and the tax regime under the PPTA. Whilst the Nigerian National Petroleum Corporation (NNPC) executed the PSC as concessionaire and it was approved by the Minister of Petroleum Resources, the 1993 PSCS did not have the power to override the PDPR or the PPTA. This explains the need to legislate the fiscal elements of the PSC in the Principal Act. The Act replicated the PSC royalty provisions, save for areas up to 200 metres water depth, over which it was silent. It also adopted the provision for a 50% petroleum profits tax rate.

Amongst other provisions, the Principal Act provided for the review of the provisions of the Act and the adjustment of the PSCS in favour of the government, if the price of crude oil exceeds $20 in real terms. Notwithstanding these provisions, the Act was to be subject to review 15 years after the commencement date of the Act and every 5 years thereafter. Until the recent passage of the Bill, the Act has not been reviewed. This has been a source of tension between the government and the IOCS. Over the years, the government has expressed its concerns about the fall in government revenue, arising from the perceived favourable terms under the 1993 PSCS. It has proposed changes to the fiscal regime under various iterations of the Petroleum Industry Bill, which have failed to pass from 2009 till date.

The Bill

The Bill was introduced to the Senate as an executive Bill in October 10, 2019 and passed by it on October 15, 2019 before being passed by the House of Representatives and given assent by the National Assembly on November 4, 2019. It is fair to say that the timelines are unprecedented.

The Bill provides for a new royalty regime for companies operating in the deep offshore area.

Instead of the graduated royalty by water depth provided under the PSC and the Principal Act, the Bill provides for a dual royalty regime. Royalty by volume of production will be at a single rate of 10% and is to be calculated on a field basis as opposed to contract area basis under the Principal Act. It is not clear whether the basis of calculations would have any fiscal implications on producing companies in the deep offshore area. In addition to the royalty by volume, the Bill also introduces royalty by price. This is based on the price of oil at the time of production. The applicable rates are as follows:

The effect of the above is that a company currently producing in an area of 1001 metres water depth, which under the Principal Act pays 0% royalty will now be required to pay 10% royalty in terms of royalty by volume, and an additional 4% in terms of royalty by price (assuming the oil price of 4th of November 2011 of US$ 62.17). This of course will have immediate economic impact on any project in that circumstance.

Stabilisation Clause to the Rescue?

The 1993 PSCS include a stabilisation clause in Clause 19.2, which provides that in the event of any change in law which “materially and adversely” affects the rights and obligations or the economic benefits of the Contractor, the parties shall use their best efforts to modify the PSC in such a way as to compensate for the loss of economic benefits. This means that if a contractor under the PSC can demonstrate that the change in royalty under the Bill has had a material and adverse economic effect on it, NNPC is obliged to discuss and incorporate changes to the PSC terms to minimise the impact of such adverse economic effect. The economic levers available to the parties under the PSC to address this situation are limited as most of the levers will require changes to legislation. An obvious area however, which will not require legislative change is an amendment to the profit sharing terms. The PSC allocates Profit Oil (the available oil after Royalty Oil, Tax Oil and Cost Oil have been deducted) between the NNPC and the Contractor on a graduated basis depending on the volume of production from the contract area. Under the 1993 PSC, the split in favour of NNPC may rise to 60% of the Profit Oil when the cumulative production is between 1,501 to 2,000 million barrels of oil. The parties may of course agree to modify the contract in relation to non-economic levers.

Clause 19.2 requires the parties to make the necessary modifications within 90 days and where this fails, either party may refer the matter to arbitration. The determination of the arbitrator is final, and the PSC will be deemed modified in accordance with the determination of the arbitrator.

My opinion

It is my view that the parties are unlikely to agree a modification to the PSCS within the 90-day deadline prescribed under the contract. Where no agreement is reached, I expect that the matter will be referred to arbitration, most likely by the Contractor. In my opinion, it will be straightforward for the Contractor to establish that:

1. A change in law has happened; and 2. The change in law has had a material and adverse effect on the Contractor’s economic benefits under the PSC.

Where this happens, it will be up to the arbitration panel to determine the most appropriate mechanism for compensating the lost economic benefits. The net effect is that with respect to the 1993 PSCS, the overall government take (i.e. royalty, tax and NNPC profit share) will not increase if the provisions of the stabilisation clause are brought into effect.

Concluding remarks

It is worth noting that the provisions of the Principal Act applied not only to companies with PSCS with NNPC but also to licences obtained under the sole risk awards made in the 1990s. These licences have no protection from the economic consequences of the change in the fiscal terms under the Bill.

Whilst I have highlighted the potential legal consequences that may arise as a result of the passage of the Bill and assent by the President, there are other strategic considerations for both the government and the Contractor, which may influence the outcome. The chief consideration in this regard is the expiry of the 1993 PSCS. These contracts have a 30-year tenure and renewal discussions are ongoing. I expect this to be used as leverage by the government. Another consideration is the pending final investment decisions (FID) on a few 1993 PSC projects. FIDS on such projects will be delayed as the companies consider the impact of the royalty changes in the Bill to the feasibility of those projects and the government will need to reflect on the impact of such delays on its overall objectives.

The speed of the passage of the Bill and its assent is also instructive. On the one hand, it shows that the Executive and the Legislature are working hand in hand and gives hope that the petroleum industry bill will be passed in one form or the other under this government. On the other hand, the private sector will be concerned about the lack of consultation with it and what this means for the wider reforms to the sector.