The recent announcement of the second licensing round for 31 marginal oil fields by the Petroleum Minister has come 12 years after the previous round in 2001, but it is a welcome development and represents an opportunity to increase indigenous participation in petroleum upstream activities. It is also anticipated that the additional production from these stranded / satellite fields will boost the nation’s daily crude production output and government revenue.
The term ‘marginality of a field’ is subjective, but whether it is untapped, abandoned or partially depleted reserves the most important factor is always the degree of profitable production. Dr Egbogah defines a marginal field as, “any oil discovery whose production would, for whatever reasons, fail to match the desired or established rates-of-return of the leaseholder”. The Nigerian Association of Petroleum Explorationist (NAPE) defines marginal fields as, “non-producing fields whose economics is not considered robust enough using conventional development methods under the prevailing fiscal regime”. However, from an economic stand-point, a marginal field is one that can be developed with marginal profits regardless of the actual size of the oil field, and so require special field development planning and reservoir management strategies in order to yield acceptable returns on investment (ROI).
Giving details of the current licensing round, the Petroleum Minister (Mrs. Alison-Madueke) stated that a total of 31 fields are on offer with sixteen (16) of them located onshore, while the remaining fifteen (15) are located in the continental shelf. It is vital that potential investors understand the relationship between recoverable oil (in million standard barrels, mmstb) and the terrain of the oil field. Marginal oil fields in Nigeria can be categorized into five based on surface terrain and the typical range of minimal recoverable reserves required for profitable production as follows: onshore land (2-5 mmstb); onshore swamp (7-20 mmstb); coastal offshore (12-25 mmstb); continental shelf offshore (20-45 mmstb); and deep offshore (>40 mmstb). This indicates that the deeper into water the higher the minimal recoverable reserves.
The Ministerial update on the last marginal fields bid round which held in 2001, reveals that of the 24 fields that were allocated to 31 indigenous oil companies in that exercise, 8 were already producing while the others are at various stages of development. Mrs Diezani Alison-Madueke noted that the marginal field operators (who currently account for about 1% of the nation’s production) have also recorded huge discoveries in excess of 100 million barrels to the nation’s reserve base, adding that of the eight assets that have so far been divested by the International Oil Companies (IOCs), at least four are held by active marginal field operators, who have continued to demonstrate remarkable technical ability in operating significantly larger assets.
The government in awarding these marginal fields to indigenous operators hoped to increase oil production by about 1 billion barrels. Some progress has been made in marginal fields’ development as 8 out of the 24 operators have taken their fields to first oil. However, more still needs to be done, and six factors have constrained the activities of marginal field operators. The main factors relate to the lack of funding and the marginality of the fields. Other factors are: inadequate technical expertise, government policies on royalties and petroleum taxes, board / partnership wrangling in some cases, and in other cases the presence of significant anti-entrepreneurial mentality among the operators.
Funding constraints is the main reason cited by the growing number of Nigerian E & P companies for inability to progress on projects, as well as the necessity to invite foreign technical partners. The need to invite foreign partners has become inevitable given that most local banks have not co-operated with marginal field operators in putting these fields into production. However, such invitations run contrary to the core moral concept and principles of the marginal fields’ licensing exercise. The original principle behind this exercise whereby the government took undeveloped discoveries, which has proven oil, from the oil majors and awarded these to local companies, was to encourage indigenous capacity building in the upstream petroleum sector. The indigenous marginal field operators were expected to employ Nigerian geologists and petroleum engineers, acquire workstations for their use, utilize other local skills in field development (in the office and on operational site), put local talent on site to supervise well drilling and produce the oil, and in the event, increase the pool of technically capable oilfield personnel who can replicate the same exercise elsewhere in Nigeria and abroad. Therefore, to invite technical partners would mean that the country still has not ‘indigenized’ the development of these marginal oil assets.
The Role of Local Banks
Skye Bank has funded a number of marginal field projects as follows: Platform Petroleum’s Gas Processing Plant, and Walter Smith’s Production Boost Project. Recently, Skye Bank approved a loan facility of $18m for Pillar Oil to enable the company drill a well, at an interest rate of 17% per annum. Intercontinental Bank approved $6m for Niger Delta Petroleum for the ‘work-over’ of Ogbelle 1 at an interest rate of 18% per annum, a project that led to their crucial first oil.
Brittania-U received their initial funding of $23m from Union Bank in 2007 for its project on the Ajapa field. By the time Brittania-U reached first oil, this loan had been increased to $50m. Brittania-U also received an additional $30m loan facility from Union Bank, which the company used to buy-out its ‘troublesome’ foreign technical partners. Currently, the company is producing about 2,300 barrels per day (bpd). However, focusing on the fortunes of Brittania-U might give the erroneous impression that the local banks are in a lending frenzy to marginal field operators. The fact is that of the six companies producing from marginal fields as at 2011, only Brittania-U commenced operations with a bank loan. Platform Petroleum, the first to reach production, was able to do so with funds provided by its partners (New Cross), a cash-loaded Nigerian company. Pillar Oil struggled for cash and was forced to rally funds through shareholder’s contributions, in order to commence production without a bank loan. Pillar is drilling a new well being funded by Skye Bank, to enable the company increase production. Walter Smith Oil Ltd could not raise funds from a bank until it had established production. Energia Oil Ltd funded its field development with cash flow from its shareholders.
Most bankers insist that the problem with funding marginal fields’ development is that the only asset available on the table as collaterals is the marginal field itself. Most bankers insist that if a marginal field operator has cash flow from other oilfield operations, or other businesses or has a sizeable deposit with the bank, then the bank can leverage on these to approve loan facilities. Marginal field operators will argue that deposits to the banks can only accrue if they are assisted to produce their fields. So, it’s more like the chicken and egg situation! Bankers further argue that the best way to fund marginal field projects should be through equity contributions. The flaw with this argument is that, quite frankly, bulk of the funds available with individuals in Nigeria were not derived through sheer enterprise (but mainly through cronyism, and other corrupt means), so there is little desire by such high net- worth individuals to commit those ill-gotten funds into relatively risky projects
The case of Brittania-U is more of the exception than the rule, whereby local banks were willing to finance their project on projected reserves-based lending. The reason is that reserves-based lending which is the modus required for financing start-ups like marginal field operations is yet to be embraced by local banks in Nigeria. The traditional banking concept in this country, which emphasizes lending against collaterals and securities, still holds sway, and this is not applicable to marginal field development. The concept of reserves-based lending accepts ‘oil in the ground’ as collaterals and more of the local banks in Nigeria should be willing to embrace this concept for their lending decisions in regard to marginal fields’ development.
The second constraint is the relative marginality of the fields. Of the six companies that have brought their marginal fields to production as at 2011, only Mid-Western Resources (partnering with Mart Resources) are producing sizeable volume of crude oil (about 8,700 bpd). This is followed by Brittania-U (producing about 2,300 bpd) and Energia (producing about 2,000 bpd). Pillar Oil was producing 100 bpd before the well watered-out. Some of these volumes can be quite discouraging for ambitious foreign E & P companies, considering the amount of investment required to bring some of these fields into production. Production from swampy / deep sea fields is usually higher than production from onshore fields. This is a critical issue that investors have to consider too.
The third constraint is availability of local technical expertise. Undoubtedly, there exists abundance of local technical expertise, which has developed over a long period of time. This is so, considering that Nigeria has produced oil in commercial quantities since 1970 to date. However, most of them may not be available to work for marginal operators if they can earn more pay with established E & P companies. It should also be acceptable to highlight the relative differential in quality between local technical expertise and the technical expertise available in Western countries. Consequently, the government is not averse to joint-ventures between marginal field operators and foreign technical partners, provided that the Local Content Act applies to board appointments, local employees, and inclusion of local contractors in the provision of goods / services needed for field development and production.
The fourth major constraint is government policy as regards royalties and taxes. New fiscal regimes have been proposed in the Petroleum Industry Bill (PIB). If the PIB is passed in its current form, operators will observe a significant reduction in applicable royalties and taxes. A reduction of about 30% in applicable royalties and petroleum taxes has been proposed, which makes it commercially attractive for small operators to develop these marginal fields very profitably. The Bill also introduces a modern acreage management system with strict relinquishment guidelines, which provides for oil companies operating in this country to relinquish acreages from existing oil prospecting licenses (OPLs) and oil mining leases (OMLs), except acreages that will be developed in the near future, or those that are currently in production. This policy is meant to discourage operators from sitting on acreages that otherwise will be available to other credible investors.
The future of marginal fields’ development still looks very promising despite these hoops. However, going forward, there are a number of financial, technical initiatives and government policies that will aid the process of marginal fields’ development. The most important of these is the passage of the PIB. On the technical side, operators will have to develop more effective reservoir management systems and synergistic facilities utilization in order to boost mutual profitability. Energy & Petroleum Academic Centres in the country should be strengthened through funding by local industry players. This should enhance human capacity development needed in the industry and reduce the strong dependence on expensive expatriate personnel and skills. Presently, investment in marginal fields comes from JV, Debt and Equity financing, or a combination of these. There should be more effective mutual integration between operators and the local financial sector. Operators can form Special Purpose Vehicles (SPV’s) and tap into the international investment market as well. They can also attract more capital expenditure (CAPEX) investment by aggregating or co-mingling proximal fields’ reserves in order to achieve critical volumes.
The Role of Government
Government has a crucial role to play in enhancing the profitability of these ventures. Government can revise the fiscal terms and make them more investor- friendly; suspend royalty payment for at least three years from commencement of production to eliminate front-loading of royalty payments and thereafter apply the sliding- scale method to royalty payments based on producibility; and provide tax holiday of 3 years by suspending VAT, import fees, education tax, etc. The CBN can support the local banks in reviewing monetary terms for energy projects, and government can also establish Energy Bank, as separate from Bank of Industry, to enable local energy companies gain access to funds at globally competitive rates.
Dr Chijioke Nwaozuzu, petroleum policy expert, wrote from Emerald Energy Institute, University of Port Harcourt. Email: [email protected] Tel: 070 6874 3617 (SMS only)