Upstream operator explains the Nigerian gas sector’s potential

Could you give us an overview of the key projects and operations you have been developing in 2017?
In 2017, we initiated the execution of the Njaba field development in onshore OML 124, which had taken FID. The first FID was taken in 2014, but then the oil price came down. We spudded the first well in November 2017, and since then we have drilled four wells and there are two more wells to drill in 2018. That was the main execution that happened in 2017 and early 2018.
We have also been working on the Ofrima and Udele projects, where we will develop roughly 90 million barrels of oil with an upside of about 100 million barrels. Our original concept was a platform-based central processing facility connected to an FSO. However, when we saw the costs, we changed our strategy. We are currently working with NNPC to use their existing facilities at the Agbara Production Facility, which is about 16 kilometres away from the nexus of our development. It is currently producing from the Agip-operated Agbara field.
The facility has capacity of around 50,000 bopd and is currently producing around 5,000. Our project will have a peak of production of about 45,000-50,000, so that is a good place to take it and that simplifies the project. Instead of thinking about the platform-based central processing facility and an FSO, we only need a pipeline to the Agbara facility and some processing upgrades to handle gas. We are currently reviewing the integrity of the asset because it is about 28 years old and we want to make sure that it lasts for another 15 years. We should be able to take the final investment decision on this project in early 2019, and we will do the technical assessment in 2018.

What projects are being executed in shallow-water OML 123?
We have a number of different projects there. We have submitted a field development plan for Adanga East to the federal government for approval. We are also working on the Antan oilfield. We actually started fabrication and construction of the Antan facilities at the Snake Island yard before the operations went down. We are resuscitating it now to see how we can renew negotiations on the contracts and bring the costs down for us to complete Antan. Antan will deliver peak production of about 15,000 bopd and 15 million barrels of ultimate recovery whereas the Adanga East will deliver peak production of about 9,000 bopd and 11 million barrels of ultimate recovery.
We have a couple of other projects coming up besides these two mature ones. Kita Marine Phase 2 might be three or four years down the line. We also, of course, have Adanga North Horst, the bigger hub development. All in all, what we are working on in 2018 is to put together a development strategy for all of the assets in OML 123 so we know how we are going to mature them. We have managed to negotiate a lot of FPSO contracts, drilling contracts and facilities project contracts substantially lower. Their costs have come down significantly, 40-60%. Between that achievement and the oil price stabilising, the projects might work.

How has Addax Petroleum managed with the low oil prices of the past years?
With some contractors, specifically FPSO contractors, we ask them what their base cost is. We negotiate with them above that rate so we can share a bit of the profit, which depends on the production levels and the oil price. Those are some of the things we have done to try and substantially bring down costs. Across the board, we are delivering quite substantial cost reduction. The benchmark cost for onshore wells given by NAPIMS is currently USD 18 million per well. We are drilling the Njaba well at under USD 11 million because of these negotiated contracts and bonus incentives for the drilling contractors to finish things on time.

What is the industry outlook for the next few years?
We do not want the bad habits created when the oil price is high to be replicated when the price comes back up. We have to find a way to make sure that doesn’t happen. Since oil prices have gone to USD 60-70 per barrel, things are slowly starting to change again. It looks as if lessons have not been learned. The cost-effective mentality has to be sustained even if oil prices are high. That requires a change of mentality, and the laws and incentives should also embody this change of mentality.
What is the incentive to be efficient if you are allowed to reduce your effective tax rate by just spending and not actually starting to produce? The government is rightly trying to remove the current tax allowances and replace them with production allowances so when you make a production promise and meet it, then you can get the boost. That will drive cost-efficiency. Once you know that you have to deliver a certain unit cost or be penalised, you have to deliver a certain level of production, commensurate to this cost limit. With these changes, if they are finally implemented, operations in the country will become more sustainable.

What is Addax Petroleum’s growth strategy?
One area that Addax has not played in yet is gas. However, we have abundant gas resources, and there are many ways to unlock them. In OML 137, we have about 2.5 tcf [70.8 tcm] of gas, which is a very substantial amount. We are trying to put together strategic notes this year for that gas development so we can take a final investment decision in 2019 or 2020. We can unlock these resources, which are where our future growth will come from, in a number of ways.
The planned East-West Gas Offshore Gathering System being developed by Dangote is a gas pipeline system that will run about 20-25 kilometres away from the nexus of our development, so we will be able to tie into it. We can also decide to go for an FLNG. We will narrow our concepts down to what is most commercially viable for us. That is where real growth is going to come from. FID should happen in late 2019 or early 2020.

How can Nigeria’s gas production be stimulated?
Nigeria has 180-190 tcf [5.1 tcm-5.38 tcm] of gas resources and possibly another 600 tcf [17 tcm] of prospective resources. A major challenge has been infrastructure. Also, the most important part of this infrastructural challenge has been implementing the right fiscal terms to allow investments to come into the upstream and midstream for gas.
The government wants a lot of this gas to go to the domestic market. Domestic gas pricing is a challenge because it is not a willing buyer-willing seller situation. We have to find a way to resolve the problem of what kind of gas markets we are looking for. We might start with a regulated market, as a transitional arrangement, where you subsidise some end users that cannot afford to pay in full for the gas utilised, but you have to let it go into a market-driven pricing mechanism, at some stage.
How that is going to happen needs to be unlocked.
In order to stimulate gas production, however, we need to make sure that we incentivise the production of Nigeria’s resources of dry gas, acknowledging that not all gas across the country is the same type of gas. Condensate-rich areas produce gas from which liquids can be derived, and these products are currently treated with the same fiscal terms as gas, which are more relaxed than oil. This makes producers’ operations in condensate-rich areas much more profitable.
The policy has to make it work for dry gas. If you do not make it work for dry gas, that is a substantial volume of gas that will never be delivered to the market. The focus so far has been on finding terms that work for gas as one single entity, without understanding the difference in composition of gas and how that would trigger very different economic conditions. The upstream gas sector needs to be unlocked, and this is a key measure.

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