‘We’ve Bolstered Our Credentials in Nigerian Crude Oil Refining’ - Africa’s premier report on the oil, gas and energy landscape.

‘We’ve Bolstered Our Credentials in Nigerian Crude Oil Refining’

In the first of a three-part series, GBITE FALADE, CEO of the Nigerian integrated energy provider Aradel Holdings, fields questions around the sustenance, daily obstacles and the opportunities in the Nigeria’s burgeoning private sector crude oil refining business

He spoke to Akpelu Paul Kelechi

There is a very poor understanding of the profitability of the crude oil refining market in Africa, and indeed Nigeria. But to go by Aradel’s report, things look pretty good. You were unable to export crude oil for a significant part of 2022 and 2023 and so you recoursed to growing your refining portfolio.You earned 13Billion Naira from sale of refined products in the first quarter of 2023, which was more than quadruple your earnings from crude oil. And you’ve  grown that segment  even more since then.   Is the refined product market probably more profitable than the crude export? Your company has been very profitable when there was not even a drop of crude supply. That’s contrary to widely held perception.

Gbite Falade, Aradel CEO

The profit margin in the upstream is superior to the one you have in refining. When you also consider that that same upstream crude becomes the basic feedstock for your refining, the entire investment on refining infrastructure in your inside battery limit which includes your plants, the outside battery limit which includes storage and many other things, plus the ecosystem of all that you need for off-take, loading, and the sheer number of workers to run a midstream-downstream refinery, you need to ensure that the margin that you have beyond your feedstock input price, is significant enough to cover the general and overhead expenses and then amortise for the CAPEX you have invested in that refining space. By the time you do the accounting, it would be clear that you don’t have that much wiggle room that you have in the upstream.

In the upstream, you need fewer human beings to bring the crude to the surface.  Personnel that you need in the refining midstream and downstream is much more. The sort of quality standards that each product must confirm to and the Q&A processes, lab testing to make sure it works well, your process safety setup and so on, by the time you take a view of all of that, the headroom that you have between the difference in your feedstock price and your realized price at which you sell the processed product does not give you the same quantum of margin as in upstream.

Aradel Holdings produces its own crude, so you probably would not be facing the same challenges that other refiners are facing when it comes to allocation of crude to refineries. But, do you agree that crude should be sold in (the local currency) Naira to modular refinery operators since they are producing for the local economy?

The PIA has actually leap frogged to making that a construct that allows domestic refiners to access crude and pay for it in naira.

You spoke of your company’s likely delivery of Premium Motor Spirit (PMS) in 2024 and, by implication, increased crude intake capacity. How much crude oil increase do you need for you to get to PMS?

We are on a journey to commissioning our PMS station in 2024. We’ve started the process and there are activities within that process that are significantly time driven, some are also significantly driven by the global supply chain. Today, we have a PMS station that is mechanically completed so what we’re getting into now is the commissioning in 2024.

The PMS train has a capacity of about 3,000 barrels per day so it’s capable of churning out about almost 500,000 litres of PMS on a daily basis when fully loaded. It’s a good start and it’s something that we will build on. We are [also] increasing the capacity utilisation of our entire refinery, which today stands at 11,000 barrels per day. Of the five products that it will produce, we designed the refinery in such a way that naphtha, which is the reformate feedstock for PMS, that is produced from that comes to about 3,000 bpd.

Also, we are increasing our capacity utilisation. In 2021 we ended up with a capacity utilisation of about 12½%. We doubled that in 2022 and we have set a target to practically almost double that in 2023. So, whether the PMS comes in or not, we will increase capacity utilisation and there’s a target we have set for ourselves for 2024.

The PMS train does not necessarily increase our capacity utilisation because we’ve been selling the naphtha that should have gone into the PMS train. So, when the PMS train comes, we would redirect the destination of the naphtha to become input into the PMS train. In the medium term, we are working to get to 90% and above capacity utilisation for our refinery. In the event that we have other modular refineries that are producing naphtha that they do not have a destination for, we could take it from them and add it to our own, even while we have not reached 90% capacity utilisation. We can have enough naphtha feedstock to fully max out the capacity of PMS.

Without necessarily adding crude itself?


You figured out a way around regulatory, export and logistics to ensure that you export naphtha for some foreign exchange. Now you want to use the product to earn local currency?

There is a balance between what we devote to export and what we commit for local reticulation. It’s an economic decision but we also think it’s a social responsibility decision for us. We make sure that we are returning value to our shareholders but we are also satisfying some wider community of stakeholders including our local economy.

Besides, even on the international markets, you’re having challenges. We’ve just come through a very difficult one where even though we had aspiration for exports, the evacuation infrastructure was not available. If we had not taken time to develop an alternative destination for the crude, we would have been lame ducks. Our pride will always be that we not only maximised return to shareholders, but we also are active contributors to the economic development of our nation [and] easing the burden on the Naira.

How helpful has the NUPRC been to you on domestic crude obligation? They put out a release somewhere that says NUPRC has enabled Aradel and others to about 4Million barrels of crude as feedstock for your refineries. This is in the context of the domestic crude obligation that was enabled by the PIA. is this correct? Do you plan to use the Domestic Obligation anytime in future for increased refining work?

Did they mention Aradel?


The feedstock that we have had in our refinery has been self-help. We have not succeeded in attracting feedstock barrels outside of the envelope of what we produce. For us, it comes at a price, especially when you consider the fact that the CAPEX required for building out our infrastructure and drilling the wells and doing everything else is dollar denominated.  Each barrel that we earn in naira rubs us of the opportunity to get the forex to be able to defray expenses and loan obligations that are dollar denominated.

It should have been a totally different case if we were receiving third party crude enabled by whether it’s NUPRC or somebody else that then allows us to still export our crude and earn the dollars to pay down our debt while at the same time maximising the fact that we have invested in this refinery and making the product available.

You do have an obligation of a certain percentage no matter how much crude you are producing, to refine in the local economy and the enablement of the NUPRC is say okay, we approve that you take say 3,000 of your 11,000BPD or something. Is that not the way it works?

Domestic delivery obligation is enshrined in the PIA and the PIA came in 2021. We’ve been refining since 2010-2011, so we were not under compulsion or obligation from anyone such that it would be deemed that our action is consequent to a directive or a regulation or an enshrined tenant within the PIA. We give them credit for that but that’s not the case.

But do you plan to use this domestic obligation anytime soon to increase the refining scope?

Yes, we do and without it, we will not be able to fully maximise the capacity of our refinery because no matter how patriotic we are, we still must maintain a baseline of export to generate the forex not only to meet our loan facilities that are dollar denominated, but even the economy is also helped [by inflows].

Without recourse to this delivery obligation coming from others, we would just have an investment that would be seriously underutilised and that will not be in our interest or the nation’s.

So, how do you propose to do it? Can you explain it in terms of, at what point will you be comfortable to go to Abuja and say, we’ve done this much and we need you to do this for both our and the nation’s sakes?

That conversation has started as we speak. We have written formally to the NUPRC, we’ve written formally to NMPPRA. We have asked for their intervention to come and help us with the sourcing and allocation of third-party crude supplies under the domestic crude delivery obligation that would then allow us to be able to maximise.  We have started that process and we are hoping that it’s something we can wrap up as sooner than later.

Instead of Year-To-Date figures, what was your current output in August 2023 and what is the month to date in September 2023 for crude and the refinery?

In August, we did on the average, north of 11,000 bpd coming from the upstream and that’s even a curtailed production. We had to deliberately shut-in on our gas supply to the NNLG because we just could not continue on very inferior pricing. So, the condensate, the liquid leg associated with our NAG volumes which is north of 2,000,Barrels of Oil Per Day was not produced. So that was our experience in August and that’s our reality in September.

So, when you say you’re producing 6,000BOPD  for example, you have at least a thousand barrels of condensate per day (1,000BPD) spiked that makes that 6,000 right?


It is important that you understand where we are. We are exporting now, but why have we not lifted force majeure on our supply to the NLNG? All these things I just shared with you are part of the reasons. We also need to strengthen our leverage at the table.

You did talk about gradational increase to refinery, from 12.5%, to 25% and to 50%. What percentage are you at right now?

It is 50% that we are targeting right now and in the last one month, I’ve been doing more than 50%. We did about 6,600 consistently and we have maintained that. But you see, the challenge with the Refinery is that, you get to moments where external factors force you at times to scale back. Like when the road network is impassable because of the impact of rain on the condition of the road. So even though you are able to refine, evacuation trucks are not able to come in as often or in the same sync with how you are refining and so, you have to tank top.  In order to manage it, you might need to shut down one of the trains for ullage management. But on a steady state, we can do 6,500 to 7,500 consistently if we don’t have a choke in the evacuation and logistics area. We have lost some ground in the first half of the year. But we have ramped up in the second half of the year that we might be able to establish that 5,500 as a steady state rate but it will not reflect the full year’s average.

If we’re going to go beyond that, that’s why we need third party crude supply to then help fill the ullage that is in my refining capacity while I’m also allowed to breathe and make some export dollars.

One of your competitors in the refining business thinks it is rather expensive to install the reformer unit, especially by a modular refinery operator, to process crude oil to the point of PMS. Are you into any kind of partnerships or are you getting government funding for that?

We are not into any partnerships and we have not received any government funding for that. And the comment made by whoever made it that it is very expensive, is correct. In installing our trains 2 & 3, which is 10,000 barrels, the cost of the reformer unit itself, was as much, if not more, than what it cost us to install trains 2 & 3 combined. So, it’s really expensive and it is the reason why most modular refineries would not contemplate doing it but for us, we have a long-term vision. Ultimately, we would like to scale up to capacities that are much higher, for which the 11,000 BOPD that we are grappling with right now will look like a proof of concept.

Do you want to put a figure to that?

No. We see ourselves scaling up in steps. It’s not going to be a single jump from where we are to an Eldorado number. We would rather take it in a series of steps to match the feedstock supply potentials that we’re able to secure. And also match that with the infrastructure for evacuating that.



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