Angolan President João Lourenço, declared the term of office of the Board of Directors of the National Oil, Gas and Biofuels Agency (ANPG) to be over.
The Presidential Decree signed on February 19, 2024 affected Paulino Fernando de Carvalho Jerónimo, president of the Board of Directors; César Paxi Pedro, administrator; Nataxa Alexandre Tavares Ferreira Monteiro Massano, administrator; Gerson Henda Baptista Afonso dos Santos, administrator.
In the same Decree, President Lourenço appointed: Paulino Fernando de Carvalho Jerónimo, president of the Board of Directors; Artur Manuel Custódio, administrator; Ana Rosa da Costa Nhanga Miala, administrator; Nicola Isabel dos Santos Lemos de Mvuayi, administrator and Alcides Fernandes Mendes de Andrade, administrator.
ANPG was set up on February 6, 2019, as National Concessionaire, separate from Sonangol, the state hydrocarbon firm, which had, in the four decades prior, played both commercial and regulatory roles in the country’s hydrocarbon industry.
On its fifth anniversary, ANPG touted its credentials as having boosted investment in the oil sector in Angola considerably between 2022 and 2023. “ANPG data points to growth of 96%”, the regulator claimed, arguing that it also “actively contributed to mitigating the decline in oil production in the country and to the relaunch of new production”.
ANPG claimed that its efforts bolstered Local Content as it implemented policies and actions aimed at developing human capital and social responsibility. The regulator boasted that it pushed bidding for new concessions and encouraged investment in exploration activity through the 2020-2025 exploration strategy. It also, by its own telling, led “development of joint efforts to decarbonize oil operations and boost renewable energy with a focus on biofuels;; creating conditions for maintaining investors who were already present in Angola and for the entry of new ones; establishing closer relationships with all partners, particularly investors”.
In the second of a three-part series, GBITE FALADE, Chief Executive Officer of Aradel Holdings, the Nigerian integrated energy provider, fields a wide range of questions, including, very specifically, the company’s view of listing on a stock exchange, a taboo subject for most Nigerian independents.
Excerots of the conversation, by Akpelu Paul Kelechi
Aradel has had several Annual General Meetings before this year’s…The reports always came. But now, you regularly publish half a year’s report. And you have comprehensive summaries out in the open before the AGM. For investors who are keen and who like to do some analysis and some market intelligence, that’s okay, but Nigerian companies, especially E&P types don’t do that, as a rule….
We don’t want to wait until we become listed before we start disclosure and reporting, which are a fundamental obligation. We desire to become a company that operates to global standards, not just at the operational level but corporately as well. We actually think that our adherence to such stringent practices only sells the case for us when we become listed. And it gives the investing public an opportunity to have a clear perspective as to where we are and how we are threading along in our journey.
Aradel has led the Africa Oil+Gas Report’s Talented Tenth Ranking for two consecutive years. Your company is profitable, pays dividends regularly but has promised itself over the last 12 years that it will be listed on the stock exchange. What is holding you back?
Aradel will be listed in 2024. We are already on that journey to becoming a listed company. We already have a programme that we are working with and even the event of our rebranding is part of that effort. The issue of standardising on the reporting and the disclosures is also part of that effort. So, we are on the home stretch towards becoming a listed company.
Where will Aradel be listed?
We will be listed first on the Nigerian Stock Exchange with the possibility of a second listing subsequently. For now, our efforts are on being listed on the Nigerian Stock Exchange.
Unveiling a new name and logo signals a new beginning for the company with you at the helm. What keeps you up at night when you think of the past 31 years of the company especially how it relates to your responsibilities to steer it into the future?
The company has very faithful shareholders. There are a lot of shareholders that have been shareholders from the very first day that this company started. They are well informed industry people and they’ve remained faithful. They’ve not divested. Now, though practically every one of them in that category are no longer young I think what will be worth their while, for those who are still alive, is to let them see the fulfilment of their dreams. That keeps me awake at night.
Beyond the operational growth, it is about how we unlock values. How do we create the right price determination for shareholders, such that from the dividend that they get as a result of the operational performance and from share price appreciation and capital gain they can truly be happy? That keeps me awake at night.
Our industry is going through some reconfiguration, new players are coming in, old players are enduring. The boldness and the scale of the future that you dream about and how you pursue it will create a clear distinction about your position in the market. So, how “does one sustain the Legacy of leadership in this industry?” How do you play in such a way that in decades to come, you still continue to be a force to be reckoned with in the Industry?
It is not just in terms of scale but also in terms of what else are you pioneering, because pioneering is in the DNA of our company. How are you expanding the frontier of your accomplishments? How are you redefining how this business should work? How are you working to make sure you remain the best performing energy investment? How are you making sure that on multiple indices, you continue to remain right there at the top? It’s not how far we have come over the last 31 years but what we are reinventing to make sure that we continue to stay ahead of the pack. That is what keeps me awake at night.
In the last two years that we have engaged in conversations with you on the promise of Aradel, you have been a little shy of talking about what used to be the company’s pan African ambitions: Its venture in South Sudan; its aspirations in Mozambique.
In the two years leading to 2023, our industry in Nigeria had been comatose and the first instinct is survival. I came in at a time when crude theft was at a record high, when your barrels were not making it to terminals and at that point in time, survival was the natural extent and it became very difficult to then be going conquering across the continent where your house is burning. So, the last two years have been devoted more to arresting the situation and creating some sort of buffer for ourselves within the mad chaos that was going on in our industry and that’s what we have really focused on. But we have been very active in South Sudan, nonetheless. Our aspiration in going to South Sudan was to replicate our success in Nigeria which is the success in the upstream and we went into a joint venture partnership with NilePet, which is their state-owned national company and our subsidiary is called NileDelta. Our number one aspiration is first and foremost to achieve commercialisation of the significant volume of gas that is being flared.
The second one is also to enter into upstream asset ownership and get some volume. But South Sudan has also had its own fair share of challenges that has then meant that, there is a lot of bureaucracy and things don’t get executed in time at the same pace we have in Nigeria. So, it takes an awful lot of time to sell a case and get the necessary approvals. So, while we are working activity within the structure of the NileDelta JV to achieve these two aspirations, which are still not yet achieved, we have seen progress. What we’ve done is to continue to offer ourselves as the go-to person for oilfield services. Today we are active players in the Electrical Submersible Pumps (ESPs) and the Progressing Cavity Pumps (PCPs), which we offer to help lift the heavy crude that they have and that has been the basis of existence in South Sudan as we speak today, so we’ve got a NIleDelta today that employees over 50 people and as much as 99% of them are South Sudanese that we’ve trained.
We provide PCPs and ESPs to many upstream operators and help them with their with the recovery from their wells, from the heavy oil that they produce whilst working carefully a tripod agenda of gas commercialisation, upstream asset ownership and a potential modular refinery.
We’re not in Mozambique today but we were in Mozambique before. Our board decided for us to scale back from pursuing and progressing the Mozambique opportunity based on some regional factors that we thought was not playing to our strength, but we have since then been actively looking at some other jurisdictions on the African continent.
In that sense, you are a service provider in some cases?
Yes, we are.
Let’s go back to upstream. You did intimate the public of your plan to acquire an upstream asset but during the unveiling, you kept mute about that asset. Is it time to talk about it?
No, it’s not yet time for the purpose of confidentiality and respect for our counter parties.
So, it hasn’t been signed yet?
I can assure you that in no long a time from now, an announcement will be made and we think it’s only fair that it is made in consultation with the seller.
We’ll be able to speak to the asset itself. We think it’s a very fitting asset that strategically fits into what we currently have and it gives us options to develop that asset along with others that we have in well synergised arrangements that give us a chance to make an economic success out of the development and give us the base for enough scale to justify certain facility investments that make it worth the while. We always want to make sure that we are matching the scale of our surface facilities investment to the reserve potentials we have in order to ensure that it is economically viable.
What kind of volume are you looking at in terms of output?
It’s difficult to put it number to it primarily because there are unexplored prospects within that field. Until we carry out the exploration and appraisal before we are in a better position to say what it is; but we see the opportunity for both oil and gas development. So, it will serve to deepen gas production that is available in the economics both for domestic and otherwise. It will also help in bringing additional barrels of crude and condensates.
The highly anticipated multi-billion-dollar Africa Energy Bank, spearheaded by the African Petroleum Producers’ Organization (APPO) with support from the African Export-Import Bank (Afreximbank), is slated to be operational before June 2024, with the announcement of its host country headquarters expected in March of the same year.
Omar Ibrahim, the Secretary-General of APPO disclosed this during the just concluded Sub Saharan Africa International Petroleum Exhibition and Conference (SAIPEC) held in Lagos, Nigeria.
“I want to inform this meeting that at the last ministerial, conference of the APPO Ministerial Council approval was given to us by Afreximbank. To ensure that by the end of March, we take a decision on which country is going to host the headquarters of the Africa Energy Bank. We have also been given a mandate to ensure that the Africa Energy Bank becomes operational before the end of the first half of this year,” Ibrahim announced.
The establishment of the Africa Energy Bank is expected to mark a pivotal moment in Africa’s energy landscape. The bank aims to address the growing financing challenges capable of imperilling the development of the continent’s vast energy resources in the context of the energy transition.
As the developed world amplifies its calls for phasing out fossil fuels to combat climate change, Africa confronts the persistent challenge of energy poverty. With more than 600Million people lacking access to electricity and 900Million lacking clean cooking solutions, urgent action is needed to address this crisis Africa’s energy technocrats and experts say.
In response, stakeholders are advocating for the swift expansion of Africa’s oil and gas sector, acknowledging the potential of these resources to alleviate energy poverty. However, despite the pressing need and opportunities presented, global investors are displaying hesitancy towards investing in hydrocarbons. This reluctance leaves the continent without the critical investment required to unlock the full potential of its natural resources.
Acknowledging the progress made by certain countries like Nigeria and Algeria in advancing their energy sectors, Ibrahim emphasized the need for Pan-African cooperation. He underscored that no single country can tackle the challenges alone, advocating for a unified approach towards infrastructure development and knowledge sharing.
“We do not believe that Nigeria or Kenya or Mozambique or any of these individual countries S has what it takes to be able to say that it has mastered the technology of the oil and gas industry. I must admit that some countries have gone very far. Nigeria is one. Algeria is another. But, this notwithstanding, Nigeria cannot do it alone. And that is why we are coming together as a continent to establish or develop these various institutions so that it may be established in Nigeria, Algeria or Angola,” he noted.
Central to the discussion was the development of pipeline systems such as the Central Africa Pipeline System (CAPS), which aims to connect 11 African countries, facilitating the transportation of oil and gas across the continent. Ibrahim emphasized the importance of regional connectivity, highlighting the economic opportunities it presents for all African nations.
“We commend Nigeria for its leadership with the Trans Sahara Gas Pipeline, the West African Gas Pipeline. We are focusing today on developing the Central Africa Pipeline System, CAPS. It’s going to bring the 11 African countries together to be led by pipelines for oil, for gas, Don’t say that, we are in West Africa. It is going to benefit you. Because once that network has been done, you are in a position to take the West Africa gas pipeline or, um, Trans Saharan gas pipeline. Take from there to Chad, which is in Central Africa. And if you don’t get a market in Europe or Asia, you have a market in Central Africa,” he argued.
Ibrahim addressed the misconception surrounding energy access, insisting that it plays a crucial role in driving economic productivity. He stressed the need to empower African communities with access to energy, not only for lighting but also for enhancing their economic activities. The vision of APPO, as outlined by Ibrahim, is to transform Africa’s energy landscape, ultimately leading to sustainable economic growth and development.
French oil supermajor TOTALEnergies has announced the commencement of production from the Akpo West Field.
By mid-2024, the company said, “Akpo West will add 14,000 barrels of condensate production per day”.
That volume is about 1% of the country’s crude oil and condensate output.
A big announcement about the commissioning of a such a low production is a sobering commentary on the struggle to bring out any reasonable amount of crude oil volume in Nigeria.
TOTAL added, for effect, that the field will follow up with 141Million standard cubic feet per day (141MMscf/d) of gas by 2028, that is, four years away.
Akpo West is tied back to the existing Akpo Floating Production Storage and Offloading (FPSO) facility, which started-up in 2009.
TOTAL said in the announcement that it produced 124,000 barrels of oil equivalent per day in 2023.
The reality is that, out of the 124,000BOEPD claimed for the field by the European giant, around 70,000BPD is liquid (condensate). The remaining 54,000BOEPD is gas, which translates to 324Million standard cubic feet of gas a day, which is supplied to the Nigeria Liquefied Natural Gas (NLNG) plant in Bonny, in the eastern Niger Delta basin.
TOTAL, in the short announcement, also noted that Akpo West field is on the Petroleum Mining Licence (PML) 2 license in Nigeria. It is the first time a field is announced by a major company in the context of the new nomenclature of mining licences in the country. Previously, Akpo field, like Egina, was in Oil Mining Lease (OML) 130.
The company adds that “Akpo West development leverages the existing Akpo facilities to keep costs low and minimize greenhouse gas emissions. The project’s carbon intensity is expected to be below 5 kg CO2e/boe and will contribute to reduce the average carbon intensity of TOTALEnergies’ portfolio”.
TOTALEnergies is the operator of PML2 with a 24% interest, in partnership with CNOOC (45%), Sapetro (15%), Prime 130 (16%) and the Nigerian National Petroleum Company Ltd as the concessionaire of the PSC.
In 1994, South Africa’s first year of fully democratic elections, the Africa Oil Week (AOW) began in Cape Town, the country’s widely acclaimed ‘mother city’.
Christened ‘Africa Upstream’, at the time, the Conference was inaugurated in Camps Bay, “a beautiful locale over the towering Cape peaks, facing the ever cold Atlantic”, reports Duncan Clarke, the AOW’s founder, in his memoir Three Decades in the Long Grass: The story of Global Pacific & Partners. “No facility existed and we used a huge marquee to accommodate the 300 delegates”, the Zimbabwe born Clarke notes in the book. Clarke enlisted Alec Erwin, “an old friend and minister in Mandela’s cabinet, who had gone to school in Umtali (Mutare), in [then] Rhodesia to give the opening address”.
The second edition of the conference was held in Johannesburg, “unwisely persuaded that this, the heart of sub-Saharan Africa’s economy, would prove a more fertile ground. It didn’t, and the location of the conference in Midrand was a near disaster of logistics and on-site management. Never again, we vowed, so we moved back to the Cape to find the IMAX BMW Centre as our next venue-and for the next 17 years to follow-initially taking a smaller room than the main theatre for the conference meeting”.
By 2013, the conference had been renamed Africa Oil Week (AOW).
I’d pause here to scan across the continent to focus on the emergence of NJ Ayuk, a gutsy, charismatic, Cameroonian born, US trained lawyer.
I met NJ Ayuk in 2015, in the company of Thabo Kgogo, then CEO of the JSE listed, South African independent SacOil, at the Cubana bar and restaurant, an upmarket lounge in Cape Town, which was a sundowner favourite hangout of the AOW crowd. At the time, I had watched Ayuk from a distance with a large dose of respect mixed with curiosity and a lot of questions. His Centurion Law firm seemed so unutterably successful for a company headquartered in Equatorial Guinea. It wasn’t lost on me that, even while located in such a back water part of the continent, it was loudly touting Pan African credentials.
How did the Africa Energy Week, created by Ayuk’s Energy Capital & Power and African Energy Chamber, manage to wrestle down the wrestle down the “gigantic” AOW, which no longer has Duncan Clarke at the helm, but being managed by the Hyve Group?
After a string of acquisitions of smaller rivals over the last four years, TGS finally moved on one of the big ones: PGS
As the company’s chewing of PGS graduates into a swallow, the question comes up: who is TGS’ next acquisition target?
The TGS-PGS tie up is a massive challenge to CGG’s dominance in both digital library and the fleet (of acquisition vessels). This ongoing merger hands to TGS a larger data library than CGS’ but relatively equal match in terms of fleet of vessels.
“The transaction helps mitigate supply chain risks and will add further to economies of scale and efficiency, enhancing the value offered to clients”, TGS explains, adding: “preliminary estimate of more than $50Million annually in cost synergies”, TGS has said in a statement. “In Multi-Client, the combined company will offer customers a global seismic library with data from all active basins in both the western and eastern hemispheres. In data acquisition, the combined company will be a substantial player globally with a strong operational track record. For streamer acquisition, it will hold an operational fleet of seven three dimensional (3D) data acquisition vessels, and for Ocean Bottom Node (OBN) acquisition, the combined company will benefit from around 30,000 mid and deepwater nodes. Within imaging, the combined company will offer a strong service to in-house and external customers integrating on-premises and cloud based high-performing computing services. In addition, the combined company sees significant growth opportunities in new energy with complementary technology offerings for Carbon Capture and Storage (CCS) and offshore wind”.
TGS has not always been gung-ho about vessel ownership, even though its specialty was in Multi-Client data acquisition, which involve days of vessel usage.
When TGS acquired Spectrum Geophysical in 2019, the word in the industry was that the Multiclient data acquisition specialist was only out to grow its data library. TGS, it was said, wasn’t in the business of owning its own vessels.
The same sentiments prevailed when the company moved on to grab ION Geophysical. It so happened that the purchase of ION’s bankrupt business included substantially all of ION’s global offshore multi-client data library, data processing and imaging capabilities, intellectual property, and Gemini Extended Frequency Source technology and equipment”, TGS said in a statement. ION’s data library consists of over 637,000 kilometres of 2D and over 317,000 square kilometres of 3D multi-client seismic data in major offshore petroleum provinces globally, generating revenues in excess of $86Million in 2021. TGS’ takeover of ION was concluded as part of the latter’s bankruptcy process in the United States Bankruptcy Court for the Southern District of Texas. At the time, Kristian Johansen, CEO at TGS, said the company was “excited about taking over another quality data library, particularly in the South Atlantic”.
TGS then moved on to grab Fairfield Nodal company, which was one of the world’s leading specialists in acquisition of 3D time Lapse seismic data.
Kayode Adegbulugbe, Chief Operating Officer of Green Energy International Ltd (GEIL) is upbeat. He is out to make a statement and believes that he has nearly clinched it: delivering Nigeria’s first indigenous Onshore Terminal at Otakikpo, in Oil Mining Lease (OML) 11, Rivers State. Achieving that would be a major milestone for the country’s E&P independents.
GEIL is the operator of the Otakikpo field, classified as a marginal oil and gas accumulation, in the eastern Niger Delta, currently delivering in excess of 11,000Barrels of Oil Per Day (BOPD).
Adegbulugbe’s ebullience is not only fuelled by this impending delivery of 750,000Barrels of crude oil export terminal expandable to Three Million Barrels. He is also excited by the timing of the construction: the project is far ahead of schedule. He declared this to a gathering of industry professionals at the recent Society of Petroleum Engineers symposium in Lagos. As keynote speaker, he gave insight into the backstory and challenges of executing the project.
Is Green Energy on-track to deliver its onshore terminal?
Adegbulugbe: [In collaboration with our strategic partner, we are] delivering Nigeria’s first indigenous onshore terminal six months ahead of schedule. First, to show the rest of the world that a Nigerian indigenous operator could deliver such a complex E&P (Exploration & Production) project in record time utilising local resources. Second, to [dispel] the notion that such complex projects in Nigeria are notorious for taking a longer time to complete, lasting up to 5 years or even 10 years in some cases.
However, contributing to Nigeria’s energy security is our primary goal. The terminal will deliver its first 500,000 barrels of oil capacity by second quarter 2024, less than 10 months after the foundation of the project was laid (in fourth quarter, 2023). No Nigerian Independent has attempted such a complex E&P project before. It was usually left to the IOCs.
How does your terminal compare to the existing ones?
Of Nigeria’s five onshore terminals, none is operated by a local independent. Escravos terminal, built in 1989, is operated by Chevron. Shell operates the Forcados and Bonny terminals while Agip operates the Brass terminal. In terms of capacity, ExxonMobil’s Qua Iboe, completed in 1971, is the largest onshore terminal in Nigeria with a capacity of 8,520,000 Barrels. These terminals, along with their offshore counterparts, provide close to 95% of Nigeria’s foreign exchange earnings and about 80% of its budgetary revenues. The oil sector alone contributed 6.63% to the country’s total real GDP in Q1 2022, according to the National Bureau of Statistics.
What were the challenges in arranging financing for construction of Otakikpo Onshore terminal?
We spent four years going to the international banks and making various presentations yet, we were not getting the deal closed. We then realised that we were competing with the IOCs and the NOCs for the same bucket of funds. We spent four years talking to the banks only to realise that we were not going to get this deal closed. At some point, the banks decided to impose some strict contingencies on our data. We were doing 6,000BOPD from two wells but they insisted on running our models at 10,500BOPD from six additional wells at $50 per barrel.
We thought about it and [realised] that there is a risk factor out there from a subsurface perspective and from a cost perspective. The [added] fact that we are an indigenous company also has some risks attached to it. So, we decided to have a staged approach to the terminal development by reducing the risks associated with the project and developing in-house capacity. We started by drilling two wells in 2022, reducing the sub-surface uncertainties and increasing our cash-flow situation so that we could use that cash-flow as part of our equity contribution towards the project. The banks are mostly concerned about the critical ratios of your debt-to-equity ratio and your coverage ratios. This approach helped us improve ours. But no matter how good your sub-surface department is and how confident you are with all your models; the banks would still impose a lot of contingencies on your data.
The Otakikpo Marginal field is two kilometres away from the shoreline and that provides two challenges: managing funds to maintain your facility and keeping a lid on the very high cost of evacuation, especially if you are doing up to 12,000 BOPD. There are a lot of sub-surface uncertainties because you really don’t know initially if the field is a 5,000BOPD field or a 20,000 BOPD marginal field. We felt initially that Otakipo would be like 5,000BOPD – 10,000BOPD; So, we installed infrastructure to handle that level of production. More drilling however, indicated that this field could deliver about 20,000BOPD.
Aerial view of the on-going construction site of the Otakikpo Onshore export terminal.
Additional wells improved your cashflow. What outflow level was break-even?
The cost of marine operations is very expensive whether you produce or not. At less than 5,000BOPD, you would barely break even. You are always incurring cost of storage tankers, cost of tug boats, and costs of gun boats among others. This means that, the moment your production gets below a certain limit, your costs of production per barrel is unsustainable and that’s probably why you see a lot of stranded marginal fields located less than 10 kilometres to the coastline. This is a challenge and is the reason why we’re installing the first indigenous onshore terminal in Nigeria.
With the road block at the banks, how did you arrange financing?
External inflow for project financing such as this has been drying up steadily since the climate change [movement]. So, we looked inward, fortifying the bond and business relationship with our local service partners like Cakasa (the engineering contracting firm).
Our ability to convince Cakasa and other service partners to provide vendor financing for this project helped us reduce the debt that we would be needing from the lenders and it gave lenders comfort to know that somebody else was willing to take part of the risks. It also fostered a very deep relationship because once we can get this done, the next project will be easier to discuss with companies like Cakasa. Cakasa Projects managed all the onshore portions of the terminal project that includes the Tanks, the LACT Units, the Pumps, the Generators and everything else.
Apart from them providing funding, it also reduces the project management interface because now we are dealing with only one contractor that would supervise all the other sub-contractors that work with them.
Any lessons for the industry to learn from your challenges?
When we went back to the drawing board after four years of merry-go-round, we knew right away that we should be able to do what the banks do not have the time to do for us, such as build a model for you to tell you how much equity you need. So, during COVID-19, we engaged the financial industry to identify the trainings that were critical to developing in-house capacity especially as it relates to building financial models. It is from your banking model that you would know if your project is bankable and if it is not, what needs to change to make it work.
The Advanced Financial Modelling course was a very rigorous training that had a success rate of 40% at that time and I am proud to tell you that all the GEIL staff that went for it qualified on our very first attempt. Today, we have a one-stop-shop where we can build everything. So, all we require now is just one day with the banks; so that we can explain the project and give them whatever they want to aid their decision-making process to move to credit.
As outcome, within the last 18 months we have been able to close six deals – vendor financing, off taker financing, various short-term facilities from local banks, worth approximately $750Million to be able to move our project forward incrementally from 3,500BOPD to 11,500BOPD. We believe that before the end of 2024, we should be able to get to 20,000BOPD. This is in addition to delivering Nigeria’s first indigenous onshore terminal by Q2 2024, a clear six months ahead of schedule.
Algeria’s new law has altered the investment environment to attract international oil companies, by reducing taxes significantly, while also removing customs duties and taxes on most imported E&P equipment.
“We are not only looking to offer exploration assets, but going beyond that and offering asset development on mature assets”, according to Fethi Arabi. Vice-President, Business Development & Marketing at Sonatrach, the Algerian state hydrocarbon company. “We have exploration in different areas, in the frontier zone of offshore areas, while also looking to develop some areas in the north of the country and we have over 100 discoveries that remain undeveloped,” he said.
Arabi said at a Pan African energy summit that Algeria’s new reformed law provides VAT exemptions for professional activities in the oil and gas sector.
He explained that Sonatrach was now actively engaged in partnerships and discussions with over 20 oil and gas companies, resulting in significant contracts. The French major TOTAL and the Italian explorer ENI are two large European companies who have put Algerian operations high on their strategy list in the past 10 months. TOTAL’s latest quarterly report the 3rd Quarter 2023 report, lists “partnership with Sonatrach to increase the production of Tin Fouye Tabankort fields”, as a prominent highlight of its muti-energy strategy As high on the list is TOTAL’s plan to “extend to 2024, 2MMTPA of LNG deliveries in France and develop renewable energy projects in Algeria
“These collaborations are set to mobilize nearly $6Billion, enhancing the quality of crude oil, condensate, LPG and natural gas, while also extending the life of existing deposits, leading to an estimated additional production of almost 1Billion barrels of oil equivalent,” Arabi explained.
The Nigerian government’s assumption of an average output of 1.78Million Barrels of Oil and Condensate per day (1.78MMBPD) in its 2024 Budget is exceedingly exaggerated, in the opinion of Africa Oil+Gas Report.
The 2023 average daily output (year to date) for crude oil and condensate as of November 31 was 1.46MMBOPD. This means that the government is expecting a 320,000BPD jump in the coming year to meet the budget expectations.
The facts on the ground, from the oil fields to the export terminal, speak to the contrary.
Nigeria’s crude and condensate production dropped from 1.834MMBPD in 2020 to 1.62MMBPD in 2021 and fell to a historic low of 1.38MMBPD in 2022. The year-to-date average for 2023 of 1.46MMBPD (he NUPRC didn’t release the December 2023 report), suggests an 80,000BPD rise year on year, but it is a poor reason to expect a 320,000BPD increase to 1.78MMBPD in 2024.
The fundamentals, especially ageing and dilapidated crude oil evacuation infrastructure, have worsened since 2020. The Nembe Creek Trunk Line which ferries more crude to the Bonny Terminal than any other line, had more significant uptime in 2020 than 2021, but it has stopped working since 2022 and is unlikely to work in 2024. It’s true that the operators who produced through NCTL have found alternative routes to export their crudes, but barging crudes out to sea is far more of a logistical challenge than pipeline transfer and the volumes are smaller. The best that AITEO has done in its seven months of barging operations is 32,000BOPD. Newross has never pumped more than 25,000BOPD in its 12 months of barging. It is this difficulty of aggregating volumes that is driving AITEO to consider construction of a pipeline from Nembe to Brass. Between AITEO and Newcross, we don’t expect more than 40,000BOPD increase collectively in 2024 over their 2023 production. And that is a very liberal position.
Deepwater output has plunged by more than 20% between 2020 and 2023, as the seven fields in this terrain “wind” down. With drilling in Bonga and a revamp campaign on Egina, there isn’t likely to be more than 40,000BPD collective contribution from this duo. Usan, Akpo and Agbami will remain, at best, at flat levels
In onshore and shallow water, the fields expected to come on stream in 2024 include Seplat operated ANOH condensate field at 20,000BPD; Sterling Exploration operated Utapate field and other accumulations in OM 13 at 75,000BOPD at the most (and we consider this exaggerated). Okwok and Tubu may add 15,000BPD each, if they make it to commissioning.
The government is also expecting a top up of around 10,000BPD in Anyala Madu in the year.
In a largely mature basin, natural depletion processes work round the clock, mitigating the gains afforded by small increases in output. In November of 2023, Egina and Bonga shed a collective 28,000BPD.
Downtime on pipelines will do its own damage; Elecrest’s output plunged by 8,000BPD in the same month because of down time on the TransForcdos line.
A 320,000BPD addition to Nigerian production, in a year in which the country is not expecting an elephant sized, new field coming on stream, is wildly optimistic.
Waziri Adio, one of the country’s top essayists, had this much to say about the proposed ₦27.5 Trillion 2024 Budget: “Nigeria’s largest, so far in Naira terms, continues the problematic tradition of unrealistic budgeting, anchored on revenue projections that are hardly met and on debts and deficits that always end up bigger than anticipated”.
The prospect of Libya producing less than 900,000 Barrels per day of crude in January 2024, still remains, but the country has had a reprieve with the return of the Al Sharara field to production.
The National Oil Corporation (NOC), Libya’s state hydrocarbon company, says it has lifted force majeure on the large onshore oilfield, located in the Murzuq Basin, around two weeks after it was shut in due to protests.
Al Sharara is one of the largest single accumulations on duty in the country, with a production capacity of more than 300,000 barrels per day of oil. By some accounts, it produces around a third of the country’s output.
The January 7, 2024 shut in was due to eruption of protests demanding the establishment of an oil refinery in the host community, along with improvements to deteriorating roads and increased employment opportunities for locals within oil companies.
The protesters also threatened to shut down the vital Mellitah oil and gas complex, thus heightening the possibility of a return to the kind of instability that has ket Libya away from its promise of reaching 2Million Barrels of Oil Per Day..
Al Sharara oil field consists of oil accumulations in the blocks NC115 and NC 186, situated approximately 700kilometres south of Tripoli in the Sahara Desert. The first oil discovery in the block NC115 was made by Rompetrol in 1984. The blocks NC115 and NC186 are spread over approximately 8,700 square kiloetres.. Repsol acquired Rompetrol’s stake in the block in March 1993.
First oil was commissioned in NC115 in December 1996, while the first discovery in block NC186 was made by Repsol in 2000. Production from block NC186 started in 2003.
Al Sharara output has been, however, severely challenged since a NATO backed militia ousted Libya strongman Moamer Ghaddafi in 2011. The field has experienced multiple production disruptions due to interventions by armed groups.
What could be termed a relatively steady production at the Al Sharara field resumed in January 2017 after a two-year closure caused by a pipeline blockade from November 2014 to December 2016. But the facility keeps being “stopped an started” as a result of protests such s the one that manifested on January 7, 2024.
Current partners with stakes in the asset include NOC, TOTALEnergies, Repsol, OMV and Equinor.