LEGAL PARTICIPATION IN THE NIGERIAN OIL INDUSTRY
Dec 07th 2013
On local and national levels, corruption makes it difficult to see where profits end up
Nigeria has been the largest oil-producing nation in Africa for decades and with the price of oil steadily rising over the last decade reaching all-time highs, the Nigerian oil industry has become wildly lucrative. An important series of questions arises for those of us interested in the stability of the oil-rich Niger Delta: Where exactly does that money go? Are international oil companies (IOCs), like Shell and Chevron, the big winners? What about domestic oil companies? The Nigerian government? This article provides a basic explanation of the legal framework for the Nigerian oil industry, which helps guide the distribution of profits between actors.
An important caveat: this article focuses on the nominal system, which does not necessarily correspond with reality. The Nigerian oil industry is rife with institutionalized corruption and oil theft, on both local and industrial levels. Thus, it is nearly impossible to track actual revenue derived from Nigerian oil. However, we need a baseline understanding of how the industry is supposed to work, in order to see how illicit activity distorts profits and contributes to instability in the region.
In Nigeria, the federal government retains exclusive ownership rights to all crude oil resources, under the Petroleum Act of 1969. However, the government can grant acquired rights of participation in the industry to other actors through licenses:
- Oil Exploration License (OEL): grants exclusive rights to surface exploration.
- Oil Prospecting License (OPL): grants exclusive rights to surface and subsurface exploration for the production of petroleum within limited areas.
- Oil Mining Lease (OML): grants exclusive rights to produce petroleum with a limited area. OPLs can be converted to OMLs only after an area has confirmed potential for petroleum production.
These licenses are awarded through a competitive bidding process to private companies incorporated in Nigeria. They can be structured through several different types of contracts, all of which lay out the participation rights of industry actors:
1. Joint Operating Agreements establish joint ventures (JVs) between oil companies and the Nigerian government, represented by the Nigerian National Petroleum Company (NNPC). The joint operating agreement provides a broad framework for the joint venture relationship, while an accompanying Memorandum of Understanding (MoU) lays out specific fiscal terms. In general, each participant is committed to pay costs and then will share the benefits, in the proportion of its participating interest.
JVs historically have dominated the Nigerian oil industry, and they still account for over 90% of total oil and gas production. Six JVs currently operate in Nigeria:
|Shell Petroleum Development Company of Nigeria Ltd.||NNPC (55%), Shell (30%), Elf (10%), Agip (5%)||
|Chevron Nigeria Ltd.||NNPC (60%), Chevron (40%)||
|Mobil Producing Nigeria Unlimited||NNPC (60%), Mobil (40%)||
|Nigerian Agip Oil Company Ltd.||NNPC (60%), Agip (20%),Phillips Petroleum (20%)||
|Elf Petroleum Nigeria Ltd.||NNPC (60%), Elf (40%)||
|Texaco Overseas Petroleum Company of Nigeria Unlimited||NNPC (60%), Texaco (20%), Chevron (20%)||
* Agip is a subsidiary of Italian oil company Eni.
Imbalances in the financial ability of JV partners led to significant funding challenges. The NNPC consistently failed to meet its financial obligations to the ventures, leading to cuts and delays in production and other company payments.
2. Production Sharing Contracts (PSCs) were introduced in the early 1970s, in part to avoid the financing problems of JVs in new, expensive offshore operations. All new government contracts with IOCs since then have been PSCs. Therefore, as a result of the way the industry evolved, most onshore operations today are JVs, and most deep water offshore operations are PSCs.
PSCs shift the burden of exploration and development risk to the oil companies and compensate them with higher profit margins. Under PSCs, the company acts as a contractor to the NNPC. Companies bear the entire cost of exploration, recouping their costs only in the event of a commercial discovery. The government retains ownership of all equipment and installations. In determining profits, production is divided into several categories, in order of priority:
- Royalty oil is allocated to pay royalties to the Nigerian government, as the legal owner of the natural resources. Royalty rates are determined on a sliding scale based on location, which decreases as operations move further offshore.
- Cost oil is sold to recoup the company’s pre-production and operating costs.
- Tax oil is sold to cover tax payments to the Nigerian government. In Nigeria, companies active in the oil industry are subject to a special Petroleum Profit Tax in place of the standard corporate income tax. The current tax rate is 50% for PSCs in deep water and inland basin operations, and 85% for JVs in onshore and shallow waters operations.
- Profit oil is whatever is left after the above allocations. It is given to each party in pre-determined proportions.
3. Service Contracts are the final, and by far least significant, type of contract. Under these contracts, companies are hired to conduct and finance operations. Depending on the terms of the contract, the company is reimbursed for its costs and paid out of the sale of any discovered oil, or they are simply paid fees for their services regardless of result. Agip is the only company with a service contract in Nigeria.
The Petroleum Industry Bill
All this could change if the Nigerian National Assembly passes the Petroleum Industry Bill (PIB), currently before the Senate. The PIB would restructure the petroleum industry, including institutions and regulatory and fiscal frameworks.
Since its introduction in 2008, the PIB has been subject to fierce debate and several revisions. Key fiscal terms of the current bill include:
- Replacing the Petroleum Profits Tax with a Nigerian Hydrocarbons Tax, at the flat rate of 50% for onshore and shallow water operations and 25% for deep water.
- An additional 30% corporate income tax.
- All upstream companies would be required to remit 10% of after-tax profits to a Petroleum Host Community Fund, for the development of the economic and social infrastructure of host communities in the Delta. This is different from the current obligation to remit 3% of total annual budget to the Niger Delta Development Commission Fund, but it can be credited by the companies against other payments to the government.
- No new royalty rates are declared. However, the bill grants the Minister of Petroleum rights to draft new royalty rates after the bill has been enacted.
Proponents argue that the bill will benefit stakeholders by creating a more robust business environment to attract investment and increasing the Nigerian government share of revenue. Certainly, the fiscal terms of the PIB benefit the government, at both federal and local levels. However, most independent analysts agree with IOCs, who claim the bill would further hamper an already-struggling industry.
Mark Ward, Managing Director of ExxonMobil’s Nigeria subsidiary, stated last month that the PIB will stall oil and gas production, resulting in lost revenues of up to $185 billion. According to Ward: “The cumulative effect of this is a combination of higher royalties and taxes with reduced incentives such that: no new deep water investments are economically viable and they will not go forward, 90% of new JV gas production will not happen, 30% of new JV oil production will not materialize.”
The potential for continued corruption is significant. For example, the PIB does not explain how the Petroleum Host Community Fund will be distributed to communities, leaving plenty of room for government interference. The Minister of Petroleum would have the power to raise royalties unilaterally, and the President would be able to grant licenses outside the current competitive bidding process.
The Nigerian government claims the vast majority of oil revenue after costs. For onshore operations, the effective government take can be as high as 95%. Consider the Shell Petroleum Development Company of Nigeria JV, which paid $42 billion to the Nigerian government in taxes and royalties between 2008-2012 alone. Shell’s deep-water operations contributed another $6 billion during that same period. This is a staggering sum.
Offshore operations are generally more profitable for IOCs, even though they require greater investments and have higher operating costs. Not only are offshore projects less vulnerable to security threats*, but they are not subject to the same high taxes and royalties as onshore projects. These reasons are pushing IOCs with more onshore projects (e.g. Shell, Agip, and Chevron) to shift toward deep water exploration. (*However, if the trend supports a greater amount of deep water production, there will be a necessary increase in the logistical supply chain to support it, and the supply support ships would be vulnerable to piracy and sabotage for greater distances than previously experienced, which could drive up ancillary costs.)
As IOCs move offshore, they create space for Nigerian oil companies to take up onshore operations. Historically, local Nigerian companies have been unable to participate significantly in the petroleum industry. They are much smaller than the IOCs and lack the resources and technical expertise for deep offshore projects, while onshore projects were dominated by long-established IOC joint ventures. These companies are buying up onshore oil blocks as the IOCs divest, shifting the dynamics of the industry.
If passed, the PIB will further increase the Nigerian government’s share of oil revenues. This is a cause for serious concern for IOCs, who are already struggling to make a profit in an unstable environment. In particular, the proposed tax regime would curtail the current benefits of offshore v. onshore projects. The bill seems stalled in the legislature, as Nigeria faces its next major elections in 2015.