Potential energy

Nigeria

TOGY talks to Ebiaho Emafo, CEO of Eroton Exploration & Production, about being an indigenous operator in Nigeria, the country's gas market and the local industry conditions. Eroton is the operator and joint owner of the OML 18 oil and gasfields, which were acquired from Shell in 2014.

What is the potential of Nigeria’s gas market?
There’s a huge potential for the gas business, especially for gas sales to the power sector, but there are also challenges with the gas distribution infrastructure. Some companies have huge gas reserves, but still are not able to exploit them fully because of the infrastructure issues. The government is promising to work on a gas bill but that has been under discussion for several years. We can only speculate on when the bill would come into place. I think an announcement by the minister should be made within this year or early next year.

Do you think the government has been going in the right direction?
The government always has good intentions, but implementation is sometimes a bit challenging. On a general note, if the right infrastructure was put in place for the communities by the government several years ago, we wouldn’t be having the problems that we are facing today, including, dearth of infrastructure, youth agitation, community insurrection and security. The government said they will improve on security in the Niger Delta, but a lot of companies have to invest in their own security arrangements, working closely with the communities to be able to operate.
The government has also faced problems to meet their financial obligations, because at USD 50 per barrel, their revenue has shrunk by at least half and as such, they find it difficult to meet their cash call obligations. This issue is being discussed extensively with the hope that we would get a landing on it before the end of the year.

What role do indigenous companies play in Nigeria’s upstream market?
Indigenous operators now represent about 25% of production volumes in Nigeria.
The indigenous operators have been given opportunities through the international companies’ assets divestment and the licensing of marginal fields. A lot of locals have been involved in the bidding rounds for Shell and Chevron’s asset divestments. Many of them are also struggling because a lot of people who acquired assets did so on a USD-100-per-barrel projections.
In 2016, we also created a new association, the Indigenous Petroleum Producers Group (IPPG). All indigenous producers are given the opportunity to subscribe and most have. We are trying to work together as indigenous companies to talk to the government about the challenges we face running businesses as indigenous operators. For example, security, community and financing – those sorts of issues which are common to all of us.

How did you increase production at OML 18?
When we took over the asset [OML 18], the former operator was producing 12,000 bopd gross. Today we produce about 65,000 bopd gross. This is due in a large part to our rigless activity campaign – we have just been picking the low-hanging fruit, cleaning up, opening and restoring production to the wells. In 2017, we plan to begin drilling activity. We set aggressive targets as a business, and that’s what has driven us to achieve 65,000 bopd.
I think Shell had really moved away from putting their best effort towards their swamp locations, possibly due to community agitations, and that may be part of the reason why they decided to divest as they appear to have refocused their attention to their deep offshore assets. We have been working closely with the local communities, because their activities used to negatively affect the operations of Shell. Whilst we are working with the locals to improve relations, we have also worked on security as well to improve the security arrangement within OML 18. In addition, we launched a quick-win programme when we took over which focused majorly on field re-entries, wellhead restorations, flowline replacements and general asset integrity activities.
Our success is mainly driven by a combination of production restoration activities and optimisation, improved security arrangements and working closely with the communities to ensure that there are no disturbances in our operations.
We were also able to motivate our staff. A lot of the staff we employed were previously contract staff within Shell, and we offered them better conditions of employment with its attendant benefits. We have weekly/monthly performance reviews in which the teams work together to ensure that the production numbers are achieved and when they are not achieved, we conduct root cause analysis to identify the reasons and share lessons learnt across the board, including through peer review sessions, etc.
We have been exceeding expectations in terms of our production. At this time, it was thought we would be doing about 40,000-45,000 barrels [per day]. We also try to be lean in terms of operations and management costs. We focus on managing costs so we are able to realise value. We aim to be the number one indigenous producer in Nigeria by 2020.

How were you able to acquire such a large asset?
It was an international bidding round. We were able to work with a consortium of banks to raise the funds and bid for the asset, which we eventually acquired for close to USD 1.22 billion.
Right now, we are one of the few Nigerian businesses able to meet loan obligations without any issues or problems because we have been able to ramp up production and manage our costs, whilst ensuring production continues with limited interruption. This has given us an edge in terms of being able to make repayments on our loans.

What do you expect from the 2017 drilling programme?
First, we expect to produce a few more thousand barrels of oil per day before we start the programme. At some point towards the end of 2017, we will be at 80,000-90,000 bopd at least.
We are going to have hydraulic workover units first, then we will hire and start using drilling rigs. Up until now, our production ramp-up activities have been rigless. We intend to drill five sidetrack wells and conduct a series of workovers in the region throughout the year.
We are working on our field development plan. The plan is to have incremental growth on an annual basis. The final numbers have not been agreed with our joint venture partners but initial discussions within our team have yielded plans for incremental growth.

How do you plan to develop the field’s gas potential?
We produce on average, 60 mcf [1.7 mcm] of gas per day. We have an existing contract to provide 50 mcf [1.42 mcm] per day, the balance we keep for our internal use. We have the capacity to produce approximately 200 mcf [5.66 mcm]. We have progressed in discussions to invest in gas development because there is an opportunity to monetise our gas assets.
There are a lot of potential offtakers of gas, but in determining the supply of gas we need to work with our JV partners as well be able to come to an agreement on whom to market our gas to and what investment to make. Many companies have approached us and offered to offtake some of our gas, but we first need to invest in gas development to be able to satisfy the requirement of potential offtakers.
A lot of the equipment that we inherited from Shell is quite old and needs to be revamped. We have one ageing gas plant which we need to improve to ensure its reliability and also improve on the capacity. We intend to undertake a thorough revamp and expansion campaign. Our intention is to improve the reliability of the gas plant in 2017-2018.
Thereafter we are thinking of gas expansion plans to increase gas availability. Gas agreements are typically “take or pay,” so we do not want to get into commitments where we are not able to deliver on the volumes.

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