The Nigerian Upstream Petroleum Regulatory Commission (NUPRC) has listed eight (8) refineries as functional in the country.
Their total nameplate capacity in barrels per stream day (BPSD) totals 864,500BPSD, the regulator says in a report.
But their total required feedstock forecast for second half of the year 2024 averages 582,750 barrels (bbls) per day.
NUPRC forecasts that Dangote Refinery’s crude oil demand for September and October 2024, comes to 460,000 barrels for each month. It also expects the plant, which it acknowledges as having 650,000BPSD capacity, will require 500,000 barrels and 550,000 barrels of crude every day in November and December 2024 respectively.
These data are outlined in the agency’s forecast of crude oil feedstock requirements of Nigeria’s local refining plants, which is a key input in NUPRC’s calculations of the volume of crude to allocate to each of Nigeria’s crude oil producing companies as Domestic Crude Oil Supply Obligation. The oversight function is carried out in collaboration with the Nigerian Midstream and Downstream Petroleum Regulatory Agency.
Apart from the Dangote Refinery, which is listed in the report as Dangote Refinery and Petrochemicals FZE (650,000 BPSD), the NUPRC also names OPAC Refineries (10,000 BPSD), Waltersmith Refinery & Petrochemical Company (5,000 BPSD), Duport Midstream Company Limited (2,500 BPSD), Edo Refinery & Petrochemical Company Limited (1,000 BPSD), Aradel Refinery (11,000 BPSD), Port Harcourt Refinery (1) Old (60,000 BPSD), and Warri Refinery and Petrochemical Company (125,000 BPSD) as functioning refineries in the country.
Section 9 (1) of the Production Curtailment and Domestic Crude Oil Supply Obligation Regulations 2023 states “Crude oil produced by a lessee shall be subject to domestic crude oil supply obligations (DCSO) imposed by the Commission, provided that the lessee shall be entitled to export any volume of crude oil more than its domestic crude oil supply obligation”. The regulation further contains guardrails on how the regulator intends to curtail export of crude oil by the lessee: by processing and endorsing lessee’s application for export permit, granting export permit based on allocation production that has factored in DCSO and making sure the export does not contravene lessee’s domestic obligations.
The daily refining feedstock requirement forecast for the eight functional refineries listed by the regulator is about 34% of daily projected output of 1,701,097.06 barrels of crude and condensate, enunciated in the Nigerian 2024 budget . But in the first eight months of the year January to July 2024 (the months for which data have been published by NUPRC), Nigerian crude and condensate output has averaged 1, 517,749 Barrels per day f crude oil and condensate, of which 1,305, 847BOPD was crude oil. Over 200,000BOPD of h the crude have been forward sold by NNPC in lieu of payment for debt.
Analysts have argued that contractual sales obligation of the private operators to oil traders, also serve to shave a significant volume of what could be available for sale to local refineries. But some of the homegrown Nigerian oil producers have been supplying crude to local refineries long before the Domestic Crude Supply Obligation became a mainstream item of national debate. Seplat has, for the last two years, supplied 2,500Barrels of Oil Per Day of Ohaji South crude to Waltersmith’s Ibigwe Refinery, which is a neighboring asset in Imo State. Aradel Holdings currently supplies over 7,000BOPD of its 16,500BOPD output in Ogbele field, to its own 11,000BPSD capacity refinery located on the same property in Rivers State and where Decklar Resources has been trucking over 200BPD to the Edo Refinery from Oza field.
Adeoloye, a Petroleum Geoscientist, contributes to Africa Oil+Gas Report from Calgary, Canada.
Aradel Holdings’ conclusion of a sale and purchase agreement to acquire 100% interest in the Olo and Olo West Marginal Fields has increased the company’s portfolio to four operated, stand-alone hydrocarbon fields, outside of the exploratory tract: Oil Prospecting Lease (OPL) 227.
The fields are: Ogbele, Omerelu, Olo and Olo West fields, all located onshore eastern Niger Delta.
This is a significant shift from the one-field portfolio that the company has run with for most of its 32-year existence.
The Olo and Olo West fields, located in TOTALEnergies operated Oil Mining Lease (OML) 58, north east of the Ogbele field- Aradel’s flagship asset and (so far) sole producing field- were acquired from the NNPC /TOTALEnergies Joint Venture for $16Million, with an additional $3.5Million in deferred and conditional payments.
The acquisition has come at a time when Aradel has successfully proven the producibility of oil and gas columns in another asset: the Omerelu field. As part of its exploration and appraisal drilling campaign for 2024, Aradel re-entered Well 2ST in Omerelu field, and produced oil to the surface. Now the field is undergoing an extended well test (EWT). The company will use the EWT to evaluate the productivity and characteristics of the reservoirs; estimate reservoir volume and confirm reserves for field development as well as long-term reservoir deliverability and pilot future facility designs during field development. “We have to fully understand the reservoirs and find a solution for the gas. It is with that full understanding that we will design a Field Development Plan and an Early Production Facility (EPF)”, Aradel disclosed at a recent technical session of the Nigerian Association of Petroleum Explorationists (NAPE).
With the newly acquired fields and another field in the course of development, Aradel is the process of, as it says, “derisking the idea of a single field”.
But single field or not, Ogbele has delivered. On the back of this asset alone, Aradel has grown into the most integrated player among Nigerian indigenous E&P firms: running a 100Million standard cubic feet gas processing plant whose products it supplies to the Nigeria Liquefied Natural Gas (NLNG) Ltd and other domestic customers, and an 11,000Barrels Per Stream Day refinery which delivers Automotive Gas Oil, Dual Purpose Kerosene, Marine Diesel Oil, High-Pour Fuel Oil and Naphtha to local and international markets.
The company has expressed the view that Omerelu, if it works, will be developed as a cluster with Olo and Olo West fields.
The Nigerian independent Aradel Holdings, has reported that sales of Automotive Gas Oil (AGO), Dual Purpose Kerosene (DPK), Marine Diesel Oil (MDO), Heavy Fuel Oil (HFO) and Naphtha, all products of its crude oil refinery, amounted to $157Million in 2023.
The amount was only $13Million less than the company’s receipts from crude oil exports, which generated $170Million in the same year.
Aradel also earned $15Million from its natural gas business, which it described as “burgeoning”.
These three business units were responsible for the company’s close to 100% surge in profit after tax, from $35.47Million (2022) to $69.12Million (2023).
But it is important not to take the closeness in those earnings from refined product sales and crude oil export receipts too literally.
Aradel’s CEO, Gbite Falade, has been careful to explain in interviews the wide disparity in profit margins between refined product sales and crude oil exports. “In the upstream, you need fewer human beings to bring the crude to the surface”, he told Africa Oil+Gas Report in 2023. “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”.
Still the company had gone ahead to commit over a third of its 9,300Barrels of Oil Per Day output in 2023 to process in its three-train 11,000Barrels per day capacity refining facility.
“Our refined product delivery volumes surged by 75.3% to 267.77Million litres in 2023”, Aradel says in its report.
“The utilisation rate of our refinery capacity experienced a significant enhancement, increasing to 42% from 24% recorded in the prior year, demonstrating our successful efforts in optimising operations and increasing productivity, “ Aradel explained.
“We achieved volume output of 3.55Million barrels of oil and 9.69Billion cubic feet of gas, alongside a significant boost in crude oil exports to 2.12 Million barrels. The deployment of the Alternative Crude Evacuation Route, along with the reduction in crude oil losses to 4% from circa 30% in 2022, underscore our pledge to efficiency”.
Waltersmith Petroman’s inability to export its crude oil output out of the country in the last 18 months, as a result of the outage of the Trans Niger Pipeline (TNP), has not precluded its access to earning foreign exchange from its Ibigwe field.
The Nigerian independent pumps its entire 2,500Barrels of Oil Per Day into its 5,000Barrels Per Stream Day (BPSD) refinery, producing diesel, naphtha, heavy fuel oil, and kerosene. Seplat supplies the rest of the crude from its Ohaji South field.
“50% of the fuel oil produced is exported out of the country”, Abdulrazaq Isa, the company’s Group CEO, told Africa Oil+Gas Report.
Now Waltersmith wants to explore this business opportunity further by installing an oil terminal in Port Harcourt closer to the coast. Currently, it sells the fuel oil at the gate of the refinery in Ibigwe, which is far in the hinterland. With the establishment of the terminal, however, it will truck the product from Ibigwe to the terminal, where offtake vessels from companies like Shell Trading and LITASCO will pick it up for export. “We want to control the delivery from end to end”, Isa told our team.
Waltersmith started primarily as a crude oil producer but now that you are into refinery as well, has anything changed?
No and as you can see, since I came back, we have restructured the company to get it focused. We have now determined that we want to emerge as an industrial company. Value addition is going to be a key focus area for us. Oil and gas are our raw materials.
Going forward, for every crude that we produce, we want to add value to it and for any gas that we produce and or receive, we want to add value to it as well. We are going to do both simultaneously; we are going to continue to grow our E&P business. Waltersmith Petroman Oil, which is our core company, would continue to focus on oil exploration and production. Once all of this is done, we have Ibigwe now, Assa, and we are also part of ND Western. We will have our operated assets and we also have significant non-operated assets.
“BP’s faltering vision, its downward share price and its low valuation—some $100Billion–makes the company a vulnerable takeover prey”
The E&P company will continue to grow by itself and where we can take the oil and gas they produce as raw material, we will take it but then they also look for export opportunities; they will continue to produce and export oil but our ultimate game would be to change the proportion of what goes out to what stays in country for value addition purposes.
We are going to take into refining, petrochemicals, and everything else that can happen there including hydrogen and all that stuff down the line. Right here (in our Industrial Park) is where we intend to begin to demonstrate all that.
Crude oil generates foreign exchange immediately but all these other products don’t. Or do they? As a company that used to be a primary producer of crude oil, how do you manage the fact that there will be crunches in your foreign exchange earnings now?
I can tell you now that in the last two years or so, I mean, since the TNP shutdown, we haven’t been able to earn any foreign currency from crude export. Yes, there’s none. But we earn FX today from the export of some of the refined products that we have and we really don’t export directly but indirectly. What that has proven to us is that, really, you can take crude and refine it and still generate foreign currency from it. Since we’ve proven this concept, we are now trying to scale up the infrastructure of the facility to export.
You produce diesel, naphtha, HPFO and kerosene; which one of these is the key for export?
Fuel Oil; it’s a good product for the export market. A lot of companies, a lot of countries use it in their mining activities. Some use it for bunkering vessels, power plants use it and cement companies use it as well. So we have established a good export market for these products and we just want to organize it properly; as we are building our refining capacity, we must build the export capability and infrastructure that we need.
I’ve travelled to one or two countries and we have ongoing commercial negotiations with those countries, in those markets, to take our products there. They will be opening letters of credit in our favour for us to deliver our products.
Value addition is the way to go, not just to sell the crude and we see the impact in one of our bottom lines. What I also see is that once the Nigerian refining capacity, controlled by the private sector, significantly covers the domestic demand, the Nigerian market becomes wet in terms of refined products and therefore, export then becomes a major possibility for us as refiners. Even the current restrictions on diesel exports will naturally go away because there is sufficient supply in the markets. We would have excess products so instead of me just focusing on exporting fuel oil alone, I will have the opportunity to export diesel and any other products to the continent as well.
But would we get to the point where a huge fraction of our refined products could be going to the export market because we have sufficient supply back home? If that happens, all of us would be on the continent looking for markets to put our products.
How different are your host community plans for upstream Oil&Gas production from that of your refining plant? Where do they coalesce? What are the key objectives of your host community relationships?
There really is no difference because they are co-located in the same area. Our view of this big issue of community engagement, quite frankly is like the issue of Nigeria and its crude oil sales and the sales proceeds. What we have been used to is producing oil, exporting crude oil, the international communities receive the crude from you and they give you money and say go and use the money to develop your environment.
That is why we are here today; this whole concept of 3% of your OPEX, dedicate it in a pool then you and the community should sit down and decide if you should build a market or healthcare or this or that. Believe me, in another 10 years, come back and we will still be where we are talking about this same thing. But this right here, (points his fingers at the plan of the industrial park on his table), is the solution to the development of the Niger Delta: building industrial clusters because when you add value to these things, you begin to create development. You will see it reflected in modern infrastructure in the communities. As a necessity, there will be need for a modern hospital to support our industrial park. I won’t go and locate a hospital in Owerri to serve this place. We have to build the model hospital here to support this, it will be hospital that would also serve the Communities.
We are producing electricity and here, there will be modern schools to support this, not village schools. There’ll be modern schools because here in the industrial park, you would have enlightened and educated people living here in the industrial park. There will be residential real estates in these communities that will be built to support this. Then you begin to have modern infrastructure, employment for people in the communities, economic empowerment for them and that’s how the development is going to happen. Not by crude oil extraction and exporting and dedicating 3% of your OPEX and putting it in a pool to go and build market and town halls for people.
Value addition infrastructure must be built within the area where we’re producing this oil. The consequence of all that would then translate into economic development for the Communities, economic empowerment for the Communities and people can see the difference in what you are doing.
When I go to Ibigwe, it’s a totally different world and you see it. From the bad roads we drive through in the communities to entering this park to having internet to seeing modern infrastructure there. The difference is like night and day. What human being would not aspire to live like that? It is when we begin to build industrial infrastructures that allow the whole community to integrate that you begin to see the impact when you see the transformation it has on the people. We should do things that will add value to our oil and gas.
“I believe I’m going to be the last person who will be a CEO of a company leading an IPPG. It needs to become an institution by itself that can truly represent the industry and make a case for the industry.”
From where you sit as the chairman of the Indigenous Petroleum Producers Group ( IPPG), do you think domestic consumption of Compressed Natural Gas (CNG) would be cheaper than Premium Motor Spirit (PMS) in the long run?
Naturally because gas is cheap. But of course, again it comes down to building infrastructure to carry out the conversion process and making the requisite investment and that is how this transition can happen. Fortunately we are now beginning to have refineries instead taking the crude out and importing PMS to distribute locally. As long as we are producing the gas locally. and making the investment in the Industrial infrastructure that would then produce the CNG and then we can also invest in the CNG facilities and in these vehicles s o t h a t t h e transition can happen. Naturally it is going to be cheaper.
But do you think the international price of gas would affect our CNG market?
We are producing gas in Nigeria. The aspiration has been that we want to move gas pricing away from a regulated environment to a free market environment; willing-buyer, willing-seller concept in order to incentivize investment into gas production. But I don’t see how we would price gas domestically to the point where it will become more expensive than imported gas. It means we are doing something wrong. God has given it to us as a natural resource and if we are producing it at the cost that is more expensive than it is being imported, then we are not doing something right. If you want to create an incentive for gas producers, government can do it because we’ve always said that gas is supposed to be an enabler; it’s also a transition fuel. Through an incentive system, government can decide it wants to let gas reach out to every nook and cranny of this country to influence a lot of the things that we do. We can do that to incentivize gas production and make sure that it is cheap enough to make it available to so many people.
When Waltersmith was going to invest and take a stake in ND Western, it took 8%. Did it become an incorporated JV or did you stand alone?
That’s what we did. You know, all of us contributed our equities and it became ND Western so it is an incorporated JV. So that JV is standing alone as an incorporated entity. And each of us is still running our own businesses and that is the consortium that we formed. In the new consortium, named Renaissance Africa Energy Company, ND Western is on its own, different. All of us are in that consortium and we contributed differently to this consortium and that is why we say there are five of us: ND Western as an entity, First E&P, Waltersimth, Aradel are the Nigerian entities and Petrolin as the international entity.
What is the frame of your gas business partnership, which will deliver the Mini LNG in the Industrial Park?
We have a JV with an American company for this gas business, because they have some proprietary mini LNG technology and that is why we are working with them. We have a
company called Waltersmith-Chester LNG. Chester is an Pittsburgh, America, based company. It is in the mini LNG space. We own 51% and they own 49%. We are developing the solutions together.
For your succession plan, you have three CEOs as well as the COO, in the Waltersmith Petroman Group. One of them will take over from you as Group CEO in two to three years’ time. But you’re still going to appoint a CEO for your gas business. Will he/she also be part of the scrutiny for who succeeds you?
As we mature the gas business, we have to have a CEO for the company but we are not there yet. We are developing it as part of our strategic growth plan. I’m going to be group CEO for the next three years. And we are setting some basic parameters for ourselves; specific business goals that we have determined that we want to achieve, some indicative revenue forecast for the period which is based on a long-term strategy. And so, I’m starting the journey and we are making good progress in that regard and we see that improving from year to year.
By the time I leave, which will be by February 2027, we should have achieved at the minimum: our upstream business should be providing 50% of our feedstock in our 10,000 barrels per day refining capacity. We should be well on our way with the construction of the condensate refinery because ultimately, we want to be at about 40,000 barrels refining capacity between our crude line and the condensate refinery. That’s our game plan.
So once those things are accomplished, we are laying the critical foundation for the future; for the new Group CEO to take over and he then starts his own journey from there and the goal for him will be to consolidate on building our industrial capacity because that’s really the future for us. Building that industrial and manufacturing capacity within our complex. Whoever is going to lead our refining business would then have to start thinking what aspect of petrochemicals should we go into. Energy transition can also happen from there; hydrogen.
That’s the future that I see for us as a company; by that time, I can ease out and I would rather be playing a non-executive role than an executive role because on the 7th of this month, (February 2024) which is three days from today, I’ll be 63 so if I give myself another two years, I will be 65. I think I would have done my bit then. We have created a structure now where we have these three CEOs today: the E&P guy, the Refinery guy and the Energy Infrastructure guy and the Gas person who would ultimately join us later. We also have our COO. We all meet every Wednesday physically to engage and have very robust discussions on the business across board. We call it GEC, Group Executive Committee so all of us sitting there understand the business.
We also have the Group Investment Committee where everybody comes to compete for Capital. So everybody sits there and talks within the context of their business; how much money the business is generating and this is how much this business needs. Everything is on the table.
Let me just ask you this last question: as the chairman of the IPPG, how would you describe the achievement that you’re most proud of?
IPPG itself as a brand! You know, when we started IPPG in April 2015, Demola (Adeyemi Bero) and a few of us sat down and said we needed to have a voice for indigenous producing companies and four of us became the board of trustees and that was how we started to reach out to people. Demola was our first chairman subsequently, I have now taken over from him.
So it’s a four year term?
Yes; two years per term and I am in my last phase now. I think the primary accomplishment is that you are talking about IPPG. Nobody knew about IPPG before. We have created the visibility and we have now become a known advocacy platform for the voice of the indigenous players. At least now, people know that the indigenous players actually exist. In the past, NNPC as the determinant player did not even think that we existed but now, they know that we exist. That’s just the first phase.
I believe that even me, I’m out living my usefulness in the IPPG as the IPPG chairman and I say that with every sense of responsibility. I think I’m getting to the point where I’m not supposed to be the voice of the IPPG. IPPG requires an independent leadership. IPPG does not require any CEO of any of its companies being the face of IPPG. It requires a more focused leadership because right now, I’m dividing my time between IPPG and Waltersmith;
IPPG needs more focus than that because, when this divestment p r o c e s s i s completed, there will be nobody else but IPPG. OPTS will be no more and it is IPPG that will be
the platform that will speak for the industry. I believe I’m going to be the last person who will be a CEO of a company leading an IPPG. It needs to become an institution by itself that can truly represent the industry and make a case for the industry.
Is there an active search for that person?
No, it is just me saying it now and I’m going to share that with my colleagues to say that’s the direction we have to go, given the enormity of the responsibility that is going to befall the IPPG going forward. That becomes really critical for us to take that decision and I am going to take it upon myself to engage the council and our members so that the process will start. We need to institutionalize the IPPG like some of these other organizations have done; we need to do that. I guess like the LCCI. We need to have a leader that is strong, knowledgeable, research oriented and that has the facts in his hands that can make a strong case. We are apolitical but we are a business based organization and we need a leader that will lead it as such.
Do you play golf?
Not anymore since I hurt my back. But I like to travel.
CORAN is looking to employ an Executive Director who will be responsible for overseeing, planning, organizing, directing, coordinating, and implementing CORAN policies, programmes, directives, and strategic plans as determined from time to time by the CORAN National Executive Committee, NEC, Chairman, and Secretary
Job Description: Executive Director (CORAN)
The Executive Director of the Crude Oil Refinery Owners Association of Nigeria (CORAN), under the supervision of the Secretary and the leadership of the association’s Chairman, will be responsible for overseeing, planning, organizing, directing, coordinating, and implementing CORAN policies, programmes, directives, and strategic plans as determined from time to time by the CORAN National Executive Committee, NEC, Chairman, and Secretary.
The Executive Director will perform the following duties:
He/she shall co-ordinate and oversees the day-to-day general administration and management of CORAN National Secretariat.
Manage and administer the Secretariat, human resources, financial and other resources effectively to achieve the objectives of the CORAN.
Coordinate and ensure the effective and efficient implementation of CORAN strategic plan, programmes, policies, decisions and resolutions of National Executive Committee, BOT and the AGM,
Prepare preparations and represent the Association in high level meetings in regulatory agencies, Government agencies and Private sector, and professional bodies to present and articulate the CORAN positions
Develop programmes, initiatives and projects that relate to the regulatory, representative, re-engineering and public interest roles of the CORAN.
Review and recommend approved plans and budgets to the Chairman and Secretary during the annual planning and budgeting cycle.
Prepare and propose an annual plan and budget to the Chairman and Secretary for presentation at the CORAN National Executive Committee.
Manage research and development of policies, working papers, memoranda of understanding, briefs, idea notes, and other materials for CORAN Leadership.
Create business development, sponsorship, and advertising activities to generate revenue for CORAN.
Promote professionalization of the National Secretariat to better serve local private refineries.
Assist CORAN governance structures and platforms, including committees and forums in organizing and implementing their programs, strategies, priorities, and goals.
Facilitate and promote collaboration and partnership with external stakeholders, local and international organizations and Development Partners, donors etc
Manage and ensure smooth transition from one outgoing CORAN. leadership/administration to an in-coming administration.
Ensure continuity and consistency of programmes and policies of successive CORAN administration.
Ensure the timely monitoring and evaluation of programmes, policies, plans and milestones using the necessary monitoring and evaluation mechanisms and tools.
To carry out any other duties and assignments that may be assigned by NEC, chairman and Secretary from time to time
Requirements:
The ideal candidate should have a minimum of 7 years’ experience in administration and management.
Qualification:
First degree – BSc or HND
An advance degree such as M.Sc. in Business Administration will be an added advantage.
Contact:
Qualified candidates should send their CV and cover letter via email to info@coran.ng in PDF format not later than two weeks from the date of this publication.
The Shell operated Bonny Oil & Gas Terminal completed the supply of over 475,000barrels of crude oil to Port Harcourt Refining Company (PHRC) after a prolonged outage of over five years, during which the Refinery underwent rehabilitation and integrity activities on its supply pipeline from BOGT.
“This significant milestone was made possible through intensive preparations, collaboration, and the dedication of both the BOGT and PHRC teams”, Shell told its staff in an internal memorandum.
Key preparatory activities at the Refinery and Terminal to ensure seamless recommencement of crude oil supply included:
Pressure and leak testing to assure pipeline integrity by relevant subsidiaries of te NNPC Ltd.
Integrity and maintenance activities on the BOT Refinery export pumps (which had been shut down for an extended period) and associated instrumentations at the terminal through diligent efforts of the BOT operations and maintenance teams.
Shell said that it identified some issues at planning and execution stages among others which included:
Effective communication: to assure Asset Integrity and the safe supply of crude oil without any environmental impact.
Crude Oil Accounting: critical concern highlighted by BOGT was periodic crude oil accounting for two reasons
Continuous assurance of integrity of pipeline (wide volume discrepancies could be an early indication of compromised pipeline integrity).
Compliance with Regulatory guidelines.
Through the duration of the refinery supply, the team experienced a number of challenges.
These included wide discrepancy of compared supply volumes between the Terminal and Refinery, significant export pressure increases and low flow rates (compared to historical data).
However, at the point of each challenge, the team (BOT and PHRC) paused, took a step back and jointly reviewed the concerns, agreed on remedial actions and a way forward before recommencing supply. This resulted in the successful and safe completion of the refinery supply with no harm to people, environment, or equipment.
“In conclusion, the recommencement of crude oil supply from the Bonny Oil and Gas Terminal to the Port Harcourt Refinery is a significant achievement and a game-changer for the industry and the country. The intensive preparations, collaboration, and dedication of both teams involved were instrumental in overcoming challenges and ensuring a safe and efficient supply operation. This milestone will support the Government’s aspiration of steady supply of petroleum products to the downstream market and other associated benefits to the economy of the nation”, Shell says.
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?
Yes.
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?
Yes.
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?
Yes.
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.
Final negotiations for the financing and construction of Uganda’s $4Billion domestic refinery began on January 16, 2024, after Alpha MBM Investments from the United Arab Emirates was chosen by the government of Uganda as preferred bidder.
The breakthrough was announced by Ruth Nankabirwa, Uganda’s Minister of Energy and Mineral Development, at the first of a series of press conferences due to run quarterly giving up-to-date overview of the country’s transformative oil and gas project.
As a strategic investor in the 60,000Barrels Per Stream Day facility, Alpha MBM Investments will replace the Albertine Graben Energy Consortium (AGEC), whose Project Framework Agreement (PFA) was refused extension after it expired in June 2023.
After the AGEC had been shown the door for apparently lacking a sense of urgency, Ugandan President Yoweri Museveni called for renewed search for a new lead investor.
“The Ministry of Energy and Mineral Development engaged stakeholders to develop a strategy for the refinery project and received Expressions of Interest (EOIs) from several potential investors and evaluated,’’ Mrs. Nankabirwa said.
Four investment groups expressed interest in the refinery project but Alpha MBM, which began preliminary talks with the Ugandan government last September, was successful.
“After thorough consultations and evaluations by the government, a Memorandum of Understanding (MoU) was signed on 22nd December 2023 between the Government of Uganda and Alpha MBM Investments LLC from the United Arab Emirates, outlining cooperation and negotiation terms for the Refinery Project”, the minister told reporters.
“I am happy to report negotiations of the key commercial agreements between the Government and Alpha MBM Investments LLC commenced on 16th January 2024 and are expected to be concluded within three months,’’ Nankabirwa explained.
Alpha MBM is a UAE-based investment house led by His Highness Sheikh Mohammed bin Maktoum bin Juma Al Maktoum, a member of the Dubai Royal Family.
Alpha MBM is a pioneering investment company and describes Uganda as “an untapped market with the power to create opportunities where none were perceived’’, the Minister noted.
Final talks began between the two sides on January 16 in Kampala for what will be East Africa’s first major refinery, ending the region’s reliance on refined products imported expensively from overseas.
“Since the landmark discovery of oil in 2006, Uganda has upheld the highest environmental, industrial, legislative, and regulatory standards,’’ she said.
And the construction of the refinery at Hoima in the west of the country will transform Uganda’s energy security profile as it will no longer rely on neighbouring countries for transshipment of critical fuel supplies.
The Dangote Petroleum Refinery, which announced its commencement of production over the last weekend, started by utilizing 350,000Barrels of Oil Per Day from its storage, to output diesel and aviation fuel, for now.
The facility, located in the Lekki Free Zone in the eastern flank of Lagos, Nigeria, has a name plate capacity for 650,000BOPD, but the 350,000BOPD, Africa Oil+Gas Report learns, is a precautionary startup rate, because all the units are not yet ready to start. The company is avoiding production of giveaways, as it calls them: “products we have to sell at low prices”.
Dangote Petroleum Refinery is also using the startup period to test the equipment and plants under actual conditions, crude oil processing and high temperatures.
The company has been upfront about its challenges of procuring feedstock, informing the public step by step as it received million after million of barrels of Nigerian crude until it reached six million barrels in its storage. The announcement of commencement of production happened on January 13, 2024, five days after the six million mark was declared.
For a six-million-barrel storage, the 350,000BOPD input would suggest a 17-day supply, but that’s not how it works. Africa Oil+Gas Report learns that 11Million barrels are being contracted for, and will be delivered to the refinery, starting shortly. The Dangote Petroleum Refinery will stock the storage tanks to ensure maximum freedom to operate at optimal rates as conditions and the market warrant.
Akin Omole, the Chief Executive Officer of the Dangote Petroleum Refinery, in a January 9, 2024 statement, four days before the announcement of the Refinery start up, declared that Liquefied Petroleum Gas (LPG) would be included among the startup products of the facility “before subsequently progressing to the production of Premium Motor Spirit (PMS)”. Although LPG wasn’t included in the final statement announcing the Refinery take off, Africa Oil+Gas Report learns that the facility has, in its sights, early production of Propane and Butane. The latter is cooking gas.
Dangote’s struggle with feedstock procurement was surprising news to some of those who had followed the course of the project from the earliest days of construction.
The company had declared, as far back as 2017, that the refinery was designed to receive and process crude from many parts of the world. But foreign exchange availability has moderated that vision. The main supplier now is (the state hydrocarbon company) NNPC, which, in the view of the Dangote Petroleum Refinery, can supply in equivalent dollar, payable in Naira, since the products will be for Nigeria initially. The thinking is that the transaction will relieve the foreign exchange pressure on Nigeria very considerably.
But this is a two-way street: as Dangote snaps up a significant portion of NNPC’s share of crude, which is the Federation crude, and pays in Naira, it also increases pressure on availability of foreign exchange in the wider Nigerian economy. This is an interesting debate for economists, as 350,000BOPD is easily around 20% of the country’s total output..
The Dangote Petroleum Refinery can load 2,900 trucks a day at its truck-loading gantries. The products from the Refinery will conform to Euro V specifications. “The refinery design complies with the World Bank, US EPA, European emission norms, and Nigerian Midstream Downstream Petroleum Regulatory Authority (NMDPRA) emission/effluent norms. Employing state-of-the-art technology”, the Refinery notes.
Nigeria’s small scale crude oil refiners have been producing diesel, kerosene, jet fuel, high pour fuel oil, even naphtha, for, in some cases, over the last 12 years.
Now that a chunk of the government’s subsidy on Premium Motor Spirit has been removed, some of the companies are mulling ideas about secondary refining, which takes them to the point of producing Premium Motor Spirit (PMS), also known as gasoline.
But the readiness and/ or capacity to invest in the production of PMS depends on which refiner you are talking to.
“The catalytic reformer helps you to go into second secondary refining”, says Momoh Jimah Oyarekhua, CEO of OPAC Refinery, located in Delta State, but “part of the reason why most modular refineries today don’t have or cannot produce PMS is because they’ve not been able to purchase the units that will make them to go into secondary refining”.
Oyarekhua, who is the chairman of the Crude Oil Refinery-owners Association of Nigeria (CORAN), says that “the catalytic reformer, is a very expensive unit. Only three or four companies, globally, have the license to provide the equipment, so it’s not cheap”. He says that CORAN is advocating for some form of intervention fund from government so that refiners can invest in installing catalytic reforming units in their processing lines.
But Oyarekhua is not speaking for all modular refining companies when he says that government intervention fund is required to install a catalytic reformer.
Indeed, Aradel Holdings, operator of the Ogbele field and owner of a three train 11,000BPSD refinery, is in the process of completing the installation of one such reforming unit. “We are not into any partnerships and we have not received any government funding for that”, Gbite Falade, the company’s CEO, Africa Oil+Gas Report. “But it’s true, it is expensive. The cost of the reformer unit itself, was as much as, if not more than what it cost us to install the refinery trains 2 & 3 combined, which have a collective capacity of 10,000BPSD. 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, Falade explains, “we would like to scale up to capacities that are much higher, for which the 11,000BPSD that we are grappling with right now will look like a proof of concept”. Falade says: “Today, we have a PMS station that is mechanically completed so what we’re getting into now is the commissioning in 2024”.
Now Waltersmith wants to explore this business opportunity further by installing an oil terminal in Port Harcourt closer to the coast. Currently, it sells the fuel oil at the gate of the refinery in Ibigwe, which is far in the hinterland. With the establishment of the terminal, however, it will truck the product from Ibigwe to the terminal, where offtake vessels from companies like Shell Trading and LITASCO will pick it up for export. “We want to control the delivery from end to end”, Isa told our team.
Crude oil generates foreign exchange immediately but all these other products don’t. Or do they? As a company that used to be a primary producer of crude oil, how do you manage the fact that there will be crunches in your foreign exchange earnings now?
That’s the future that I see for us as a company; by that time, I can ease out and I would rather be playing a non-executive role than an executive role because on the 7th of this month, (February 2024) which is three days from today, I’ll be 63 so if I give myself another two years, I will be 65. I think I would have done my bit then. We have created a structure now where we have these three CEOs today: the E&P guy, the Refinery guy and the Energy Infrastructure guy and the Gas person who would ultimately join us later. We also have our COO. We all meet every Wednesday physically to engage and have very robust discussions on the business across board. We call it GEC, Group Executive Committee so all of us sitting there understand the business.
