Nigerian Banks Can Finance Marginal Fields and Divested Shell Assets, Segun Ashiru, CEO Dupiaza Energy
Arbiterz spoke to Mr. Segun Ashiru, CEO of Dupiaza Energy, an oil and gas services firm, on financing oil and gas production and the acquisition of the assets international oil companies are divesting from. Mr. Ashiru is a graduate of Geology from the University of Ibadan. He worked as a Production Engineer with Express Petroleum/Conoco Energy JV and as an Energy Consultant before joining the banking industry where he spent over 20 years on Energy Desks. He worked with Stanbic IBTC Bank for 12 years, 7 out of which he was Head, Oil & Gas Business Banking. He is a Director at Dupont Energy Services Limited and also the Founder/Managing Director & Chief Executive of DuPiaza Energy Services Limited. Mr. Ashiru is a Member of the Society of Petroleum Engineers, the American Association of Petroleum Geologists and the Society of Exploration Geophysicists.
“Nigerian banks have demonstrated financial capacity and garnered hands-on experience in funding upstream transactions…”
To Start with, what are marginal fields? How would you describe them to the Guy on the Street in Lagos or Kaduna?
Marginal fields are oil fields that have been discovered with the reserves booked-this means the Department of Petroleum Resources (DPR) has recorded the wells as having a certain quantity of oil-but have been “abandoned” by the major (international) oil companies for ten years or more. The Petroleum Act 1969 and the Petroleum (Amendment) Decree No. 23 of 1996 permit the Federal Government via DPR to ask the international oil companies to relinquish such unproduced fields.
Why do the international oil companies leave the fields undeveloped?
The fields are usually left undeveloped because their reserves are low when compared to the overhead costs of the OICs. Instead of leaving the fields fallow, they are awarded to indigenous oil companies thus allowing them to build capacity and adding to Nigerian oil production. This also creates jobs. Nigerian operators tend to have lower overhead costs.
Have the objectives of the marginal fields policy been fulfilled? Please, score the policy on a scale of 1-10.
I would score the marginal field initiative 6 out of 10. The initiative has been successful so far as it has built capacity and increased indigenous participation in the upstream subsector of the Nigeria Oil & Gas Industry. My assessment is based on the fact that 14 out of the 24 marginal fields awarded in 2003 are currently producing.
What are the key technical considerations for financing marginal fields?
Investors and financiers first need to have access to relevant data to make an informed decision on field development which will help them discover key information such as the recoverable reserves of the asset. They will also consider the available infrastructure around the field to evacuate production such as pipelines and flow stations and proximity to export terminals.
They will also examine the integrity of existing wells to see if they can be reentered i.e., if oil could be produced from the wells or if they have to drill new wells. The security situation of the location is important; it’s good for operations and for profits if the host communities are cooperative and the incidence of violence is very low or nil.
How much is required to produce first oil?
It all depends on the field. So many things would determine the cost. These include the terrain of the marginal field- is it swamp or dry land? The cost of drilling wells in swamps is higher.
Data technology is also an important factor. If older technology was used to get data when the field was discovered, there will be a need to acquire new data with more recent technology. The political and security situation around the field is also important; volatile environments require more investment in security. The cost of technical inputs tends to be higher during periods when the oil price is high and a lot more companies are investing in producing oil.
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So bidders for marginal fields don’t have a lot of data on the technical characteristics of the fields when they are bidding?
It is relative. The DPR ensures that the minimum required information is available for any asset on offer for bidding. But what you see in the data room might be different from what you get in the field because the data might not give you all the information about the true state of existing wells.
Are there situations where people bid for something that doesn’t look attractive only to go in and find that it has a lot of easily recovered oil?
Yes. Data gives an idea of what’s in a field but it’s only when you go in that you can confirm the true state of the field.
Let’s be frank, the reality is that people without relevant track record or financial capacity get awarded marginal fields. How do they transform the licenses from paper to oil? What are their options?
One of the options they have is to execute a strategic alliance agreement with a contractor that could provide technical and financial services to stream the field in exchange for crude oil produced in the field. Another option, if approved by DPR, is for them to farm out part of their participating interest in the field to an investor that could carry them in the course of developing the field and recover cost from crude oil production.
More than half of the companies that were awarded marginal fields in 2003 have not produced any oil. What should the government do about this?
That is not true. It is only 40% of the companies that have not yet produced their assets. The government should provide the enabling environment and required support to marginal field operators facing challenges in streaming their assets. After the government’s intervention, if no progress is made by those companies prior to the expiration of the statutory development timeline, such marginal field licenses might be revoked. I am not aware of any license that has been revoked.
What are the main problems in producing from marginal fields?
Access to funding and the credibility and track record of the sponsors. The state of the wells may also be a factor. It’s easier to produce or expand production from wells that you can easily reenter and that have high-demand sweet crudes like the Bonny Light.
What would you think is unique about the companies that started producing immediately when they got marginal fields?
Simply their track record in the industry and their credibility. If a company doesn’t have this it should think of ways to acquire it rather than just forging ahead and hoping to get lucky.
Fields have been awarded to three or four Companies that did not put in joint bids for the marginal fields. Would banks and other financiers be reluctant to fund entities that are practically strangers to each other?
Even in the 2003 bid round, there were instances where two companies were jointly awarded the same field and they were able to secure funding to develop these fields. What’s important is to have the right legal and operational structures. The companies jointly awarded appoint one of them as the operator and this company operates the field on behalf of the others.
They sign a Joint Operating Agreement which allows the operator to borrow on behalf of all the owners of the asset and recover capital and interest from crude oil production. If financiers have the appetite for the asset, they would fund the operator under this structure.
Has the marginal field policy built the capacity of Nigerian banks to finance oil and gas production?
The marginal field Initiative has definitely built capacity for upstream financing by Nigerian banks. In view of their risk appetite, they prefer to support marginal field operators for production optimization after first oil has been produced. Production of first oil coupled with the reserves gives banks comfort to avail funding to marginal field companies.
The banks’ risk appetite in most cases does not permit them to take exploration risk on marginal fields. Nigerian banks have demonstrated financial capacity and garnered hands-on experience in funding upstream transactions in this market as most of the international oil companies’ divestments in the last decade such as Shell’s, Chevron and ConocoPhillips’ were majorly funded by Nigerian banks (with some participation from foreign banks).
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If you were the Managing Director of a bank, which would be more attractive for you to finance between marginal fields and acquisition of the assets that Shell is divesting from?
The Shell divestment would be more interesting because they are assets still producing oil with known daily production figures and recoverable reserves. So the bank would be lending against established cash flow. You know the state of the asset. Divested assets also have existing infrastructure like pipelines, flow stations etc. and staff currently engaged in producing from the fields. In most cases investors who acquire divested assets employ some of the same staff. They then focus on raising the production of the fields. For marginal fields, there is less certainty about reserves or the true state of the wells.
Divested assets are oil blocks consisting of several discovered fields. It is not like marginal fields where you have just a field. In an oil block you have several discovered and/or producing fields with existing infrastructure. The transactions are huge but also have high profit margins; the financing structure is reserve-based lending. I would ensure the crude oil price is hedged to mitigate price volatility which could compromise loan quality.
What is the role of international capital (investment banks, private equity companies etc.) in financing acquisitions of OIC assets and marginal fields?
Foreign Banks participate in syndications for capital-intensive transactions in this market such as international oil Companies divestments to bridge funding gaps in view of regulatory single obligor limits and sectoral limits set for Nigerian banks. Project Finance is about risk sharing and in view of that, foreign banks could be invited to participate in such syndications.
Prior to Nigerian banks developing capacity for upstream transactions, foreign banks such as BNP Paribas led major reserve-based lending financing in Nigeria in 2007 and 2010 because of their technical understanding of the upstream subsector of the oil & gas industry and financial capacity. The foreign banks had energy desks which included geologists and petroleum engineers that provided support for analysing transactions which was lacking in most Nigerian banks at that time. Nigerian banks and firms seeking to develop marginal fields or acquire OIC assets will still be very interested in working with foreign capital.