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TOTAL’s Dalia FPSO Scheduled for TAM in Late February 2023

Angola’s National Agency of Petroleum, Gas and Biofuels (ANPG), the country’s regulatory agency, has announced a scheduled maintenance of the TOTALEnergies’ Floating Production, Storage and Offloading (FPSO) vessel Dalia, located in Block 17.

“The scheduled shutdown that will take place from February 20 to March 26 2023”, the regulator says in a release, noting that it was providing “the necessary clarification, in view of the inaccuracies circulating in some media”.

ANPG says that the operation will involve more than 500 specialized technicians, including TOTALEnergies’ employees and service providers, observing the high standards of safety, hygiene and environment in force in the oil and gas industry”.

It is unusual for a regulator to go to press to announce an operational plan on behalf of an operator, so should a lot more interpretation be read into ANPG’s statement?

The agency does not respond to press inquiries, but it says this much in the announcement:

“Contrary to what is speculated using sources external to the oil sector, this is actually a preventive maintenance (for that very reason programmed) of the equipment, aimed precisely at guaranteeing its operational efficiency and the reduction of production losses, within the scope of a annual work program, approved by ANPG and the Ministry of Mineral Resources, Oil and Gas (MIREMPET).

“As it is a scheduled stoppage, its impact is already safeguarded in the production projections established by the Angolan authorities with investors that are part of the Contractor Group of Block 17, not affecting the commitments of the supply of Angolan oil in the international market”.

ANPG lectures that “the operating philosophy of oil installations includes carrying out work for the preventive maintenance of essential or critical equipment, with complete or partial shutdown of the installations every four, five or six years, for a period of time that varies from 20 to 45 days. Maintenance includes a whole series of interventions such as replacing parts, equipment for engines, turbines, electrical equipment, control instruments, cleaning, painting, among others”.



“All Steel Products for Nigerian Hydrocarbon Output Must be Procured in Country, 100%. That’s What the Law Says”-Wabote

In the first instalment of this interview, SIMBI WABOTE, Executive Secretary (ES) of the Nigerian Content Development Monitoring Board (NCDMB), fielded a wide range of questions for this special edition of Africa Oil+Gas Report’s C-SUITE SERIES focused on the headwinds, the enablers, and the big wins of his six years in office. It appears, from those answers, that Wabote regards the Board as a pivotal instrument for industrializing the continent’s largest economy. The responses in this second and the last part, we argue, will indicate how far he has delivered on that agenda. Excerpts:

AOGR: The proposed Brass Methanol Plant will soak up a lot of natural gas. At about 350MMscf/d (350Million standard cubic feet per day), it will be the largest single domestic offtaker of Nigerian Gas. NCDMB is involved in the project. But sitting where you are, how clear is the sight to Final Investment Decision (FID), to construction? What is the single, major obstacle to moving this project away from the drawing board?

ES, NCDMB: For the methanol project, the investment required for it is quite substantial. You’re talking about two-three billion dollars. First, we faced the headwind of the COVID., Everywhere was shut down when we started that process and they couldn’t complete the FEED to be able to announce a financial close as it were. I think the team is working hard. Standard Chartered is the organization that is helping to syndicate for the debt portion of the Investments. The timelines have shifted because of some of these hurdles, including a mop up of global funds with regards to hydrocarbon. But we keep our fingers crossed and hoping that by end of first quarter 2023, they should be in the position to announce a financial close.

Are you very comfortable with how the process is going?

As a board member, I will only tell you that yes, we’re following the process to get to Financial close, but it’s not an easy task because of some of the factors regarding how funds out there were drying up, and people weren’t sure of what kind of project investments they want to put their money in. It is progressing, but has it progressed at the pace and speed that we would have wanted it? The answer is probably no; the climate change challenge, the lack of clarity out there on what some of the hedge funders would want to put their money behind but I guess this COP-27 would have addressed some of those innuendoes that you see or hear. Before the end of this first quarter we might get to that bridge and probably cross it.

The focus of the local content drive has been oilfield services; subsurface as well as surface. For onshore and shallow water projects, top indigenous subsurface companies like Ciscon and Geoplex are “entitled” to get subsurface service jobs while multinationals like Schlumberger, Baker Hughes can only be invited when the locals can’t do the jobs. But these foreign multinationals complain that they are being elbowed out of even deepwater projects. And often, when they do jobs as partners to locals, they don’t get paid. Does this sort of thing concern you?

That’s new to me. I have not heard that complaint before that they are being edged out. I don’t think they are. The Nigerian content Act is very clear in terms of the opportunities for indigenous players in the swamp and land assets. They have a right of first refusal. Some indigenous players have also grown their capacity to where they can also compete in the offshore arena. If we see indigenous players with that kind of capacity, of course in line with the provision of the Act, they have the right of first refusal. But there are a lot of areas within the offshore arena where the locals don’t have capacity yet, particularly in deepwater. We’re talking two kilometres of water above the seabed and stuff like that. The capacity is not there yet. The multinational service providers have an edge to the indigenous players, but where indigenous players have built capacity to compete, of course, they have the right of first refusal in the offshore arena if they have that capacity, but on the onshore and also in the swamp, we have so much capacity in the oil and gas sector that we practically don’t dominate. These multinationals help us with the equipment because most of the indigenous players buy that equipment off them with which they use for their services and a lot of them are happy playing that role in terms of providing the equipment and giving some bit of assurance with regards to the operations. As to not being paid, I think is a general phenomenon. It’s not just with the multinational companies or indigenous players. I recently had a contractor who came to me lamenting he had provided services for a particular indigenous operator, and was not being paid. It permeates the industry; even the multinationals don’t also pay the indigenous contractors that give them services and they argue that their joint venture partner has not paid so they are not paying them. It’s not just within the local companies it is also with the multinational particularly the Joint Ventures find it difficult. There are a lot of court cases that I also get served summons to come and be a defendant on court cases that I have no clue about because local contractors have not been paid by the multinationals. So they bring in NCDMB as co- defendant of those action.

Has it always been like this?

It has been like that for a while where Joint Ventures owe their service providers. Sometimes for up to one year people are being owed. The agreement says that by 45 days you will be paid but a lot of people are being owed. So as far as I can remember, it has been a recurrent decimal particularly with the Joint Ventures. In the Production Sharing Contracts, you don’t have such challenges because all the money is brought in by the multinational so they pay for services that they require but we see it with the Joint Venture; where companies have Joint Venture with NAPIMS or NNPC. Those are the areas where they don’t pay the contractors and the contractors complain and take us to court and stuff like that. It didn’t start today. Even in my days back in Shell, we’ve seen all those for quite a long time now.

When you rank in your mind without naming names, what companies are the worst offenders?

What is the One Achievement You’re Most Proud Of? I would choose the construction of the NCDMB headquarters building. it’s the tallest building in the South-South and South East geopolitical Zone. People talk about difficulty in the terrain in the Niger Delta to get things done. That building was to prove that this is doable in the Niger Delta.

Most of them that are the Joint Venture are in the same basket in terms of paying their contractors and this to a large extent affects the indigenous capacity. I have complained in public forums a lot about this. You come around and tell me an Indigenous contractor that I am pushing, is not providing the desired service but when I check, you’re not paying the guy and you know what it is to take a bank loan in this country to provide service. And if you don’t pay this provider on time, by the time you pay him both interests and capital and everything is wiped out and he comes up with nothing. It’s been a recurrent decimal; it is troubling and it affects the indigenous service providers to a very large extent. It does, to be honest. Let me not name names but, like I said, it is a challenge amongst the Joint Venture companies.

And because it is more with the JVs, one can assume that it must be because of cash call issues.

That’s what it is. That’s what they tell you and that’s what they tell the vendors; that their cash calls are not being honoured. But again, some of their Cash Call discussions are also in dispute because their joint venture partner challenges some of the expenditures and don’t honour some of those expenditures and the rest and so it becomes a cat and mouse thing to say you are not paying me. Hey you didn’t get approval for the service that you had and then, you have a lot of arrears being kept there as disputed arrears. It’s a very fuzzy situation as it were.

Multinational service companies say that the enforcement of Local Content legislation has been, sometimes, a “knee on the neck” for them. Do you sense that?

No, that’s not fair. But one thing you must accept with regards to multinationals is that their main objective as a business is to maximize return on investment to their shareholders. If you leave them, they will achieve this without a care about what happens to you as a country; whether your people are employed. They don’t care if service is procured locally. “I’m going into Nigeria, I want to go and provide this service and the return I will bring is X amount and then somebody is now telling me to do it differently and that would probably cost me a lot more”. They will resist it under normal circumstances. Even so let me be fair, the people I see that are very compliant in terms of Local Content are the multinationals because these are companies that operate globally; they have Global Standards with which their operations are measured. They obey the law to a large extent and the way we have implemented the law, at least since I came on board, is pragmatism.

Having been around the industry for a while, we know what is possible and what is not possible. We do not push people to do things that we know are impossible. We have a pragmatic approach to implementation of the law. The International Oil Companies, International Service Providers, do everything they can to comply within the pragmatic approach of implementing the law. A place where we have problems is those indigenous companies that we have fought for to be given opportunities are the ones who don’t want to comply with the provisions of the law. Which is sad and pathetic in my opinion because these are people you have done everything for. Interpreting the law to the multinationals, giving them the opportunities and privileges but today, they have it and they want to circumvent the law. That’s where we find ourselves. But it is natural because if we if we say we didn’t expect it then we are liars. We did expect such cutting of corners, trying to maximize benefits and profit for themselves. We see that but the multinationals cannot complain because ultimately local content is cheaper for them at the long run.

I will give you an example, if you hire an expert and you bring the expert into this country, it costs you a lot. His salary, his security and stuff like that. That same amount of money you pay an expert, you can use to hire 10 or 11 Nigerians. But imagine that you take one Nigerian, how much money you are saving as a local as an international company? The other example I’ll give you again is security of supply. Take for instance when the COVID struck. The predictions by WHO on how people will be dying on the streets, falling everywhere in Africa because of our challenged Healthcare System and the rest of it, a lot of the experts left. They ran to places where they felt that they had better health care system, but who were the people dying? During that period, we never stopped production because of the capacity we have built in country. Nigerian businesses were running the fields; throughout the COVID period where the whole world was shut down, we never stopped production as a country for one day.

You can imagine if we had not pushed Local Content to where it is today, we would have all shut in our wells and be waiting for them to come back. That’s the benefit with regards to security of Supply. Ultimately it is cheaper for them in terms of local content development and they know this.

“Nigerian companies don’t spend enough money on Research, Right or Wrong?” It’s a big concern for me and people who are saying that are very, correct. With all theseclimate change headwind on fossil fuel, there will come a time when most of the countries where you have all these tools being manufactured will tell companies like Baker Hughes and Schlumberger and Halliburton to stop manufacturing such tools for hydrocarbon.

Some companies, choosing not to be quoted, say NCDMB sometimes insists that the job goes to an inexperienced company and the Multinational should help train such a company in order to build capacity. They say that such issue frustrates them.

I don’t feel it and I don’t see them complaining in that regard because the truth is that, how do you build capacity? You don’t build capacity by sleeping and waking up and that capacity suddenly exists. You have to invest and support the process to build it. What the law says is that if you want to undertake a project and the capacity does not exist on that project, you must build that capacity before you start the project. That is contextually what the law says. But how can we wait for you to build capacity before you start the project, and so we say, okay, go ahead with the project so that production will come out and Nigeria will earn her revenue. But meanwhile, while the project is going ahead, can you build the capacity of those people for future opportunity? That’s what we say and that’s where the Human Capacity Development Programme comes in, which we call the HCD: put an investment to train these people. If you go by the law, it says you must train them to execute that job but you and I know that if you say it, it isn’t going to happen. So we say go ahead with the project, set aside a budget with which you would build capacity for future opportunity. The implementation of the law has always been very pragmatic at least from when I came in here.

There’s another example about our pragmatism: If you read the law, it says: all steel products must be procured in country. That’s what the law says 100%. So now if I want to implement the law like a Bible, I’ll probably ask all of them to go and build a steel plant first before you start producing hydrocarbon. But we know that’s not possible. We say, okay, what else can you do for us? You get on with your project but there are other activities you can do that are not as gigantic as building a steel plant. Is there is there any other way to do it?

Are you concerned that Nigerian companies don’t spend enough money on Research to bring out new tools?

It’s a big concern for me and people who are saying that are very, correct. That’s why we as NCDMB decided to develop a 10 year Research and Development strategy because like I said, with all these climate change headwind on fossil fuel, there will come a time when most of the countries where you have all these tools being manufactured will tell companies like Baker Hughes and Schlumberger and Halliburton to stop manufacturing such tools for hydrocarbon and focus on renewable energy in order to get Research Grants. And then what happens? A typical example is your coal. We discovered a lot of coal deposit in Nigeria, and then the world said coal was the dirtiest fuel you can ever imagine and they stopped production of tools that would help us to mine coal, we stopped producing coal. But countries that were able to research-produce those tools are still producing coal till today and using coal for their power generation. Almost 60% of China’s power generation is coal fired. In Australia, almost 50% of Australia’s power generation is coal fired because they have the capacity to manufacture the tools that will help them extract coal and use it for their energy. The same will probably happen to us regarding extraction of oil and gas. We’re making all this noise about opposing the demonization of fossil fuel. If those guys wake up one day and tell all these companies to stop producing tools for hydrocarbon, my brother we are toast as a nation. That’s why we must encourage research and development to produce those tools with which we will exploit our hydrocarbon. NCDMB created the funding mechanism for research and development, set aside $50Million for research and development. That in itself is a paltry sum from the context of research and of movement, but this is just a very small agency that could do this. Today, if you Google how much GDP is spent on research and development; on that list, the only African country you will see is South Africa, which sets aside 0.02% of its GDP for research and development. Every other African country is not there. When you look at it, you look at China, United States, almost about two point something percent of their GDP is set aside for R&D and even Israel. And you ask yourself why are those country developed?

You just came back from the Ghana Petroleum Commission’s Local Content Conference and you’ve seen what Senegal does; you actually once hosted all of Africa at the NCDMB headquarters. Do you see African leaders walking the talk in terms of industrializing the continent or do you see people just flying here and there and staying in fancy hotels and then talking about “Africa will be great” without real progress in terms of domestic integration of hydrocarbon into the local economies?

I see a lot of talk shops. I see a lot of people come to seminars only to promote what is not there. I see it a lot. I said it at the Ghana event that discussions around local content is not about whose car is the best. It is more about who built the car! What I see when I go around is that some African countries go on to the podium and tell you so many things that are being done in their country and then you come out and then you see nothing. Then you begin to ask yourself what is going on? I really get worried because I don’t know if that is the way it’s been set up for them to just market themselves when there is nothing actually to Market. I get worried that people are not really walking in the talk. It’s more about talking as opposed to doing.

What is the one thing that you’ve done in these last years that you’re so proud of that you will list as key achievement of your tenure? Finishing the mammoth headquarters’ building? Any of the NOGAPS? Funding Ibigwe?

I would choose the headquarters building, the reason being that it’s the tallest building in the Nigerian South-South and South East geopolitical zone; it is the tallest completed building. There’s a prevailing narrative about difficulty in construction in the Niger Delta terrain. That building was to prove that this is doable in the Niger Delta. I tell people that my background is engineering and one of the first philosophies you learn in engineering is that there is no problem or challenge without an engineering solution., I’m not talking about philosophical problems. I’m talking about challenging nature and wanting to do things as an engineering solution to it. For me, it was a remarkable achievement that that building was completed on time and also the building does exist in Bayelsa where I come from. Today it is the icon of Bayelsa of a completed project and to crown it all, I was able to build a gas fired power plant to power the building in itself. It’s a remarkable achievement. When they talk about grid collapse and the rest of it, I know nothing about grid collapse, when we’re in Yenagua within the headquarters building because we have our own gas fired power plant supplying us power, we are not dependent on diesel in order to survive. In most establishments in this country, “NEPA” is the standby while diesel is the regular source of supply. But today for us in Bayelsa, generators are standby while we have constant electricity 24/7. It’s my greatest happiness, it is what I can turn around and look back on amongst every other things that you have actually listed here.

What is the strategy deployed in ensuring the actualization of the R&D Project that the NCDMB has earmarked $50Million for and is this related to the Africa Energy Fund (AEF)?

No that is different; the R&D Fund is different from the AEF and it is tied to our R&D development roadmap. The AEF is more of us trying to create our own energy fund as Africa given all these headwinds of funders taking money off the table to fond hydrocarbon projects. That will soon happen. There are two separate things. This one is localized, it’s what we use to support our research and development strategy.

The strategy is that we have a Research and Development Council which is made up of most of the institutes in the country that are responsible for research and development. Also OPTS (Oil Producers Trade Section of the Lagos Chamber of Commerce & Industry) and PCTS (Petroleum Contractors Trade Section) are members of the Development Council. We also have a research and development technical committee that interface with external partners on particular research because like, you know research is not something you do in isolation. You have to do it in conjunction with others. It’s a well-structured set up to encourage research for commercialization.

Most of the institutions we have, the kind of research they do is research for promotion and most of their researches in the country are on the shelf. But what we encourage is research that will produce something that we can commercialize for the industry and beyond; that’s what we support.

What kind of research; is it the type in which a Nigerian University is requested to work on understanding flow assurance in a fluid system or one that says: We need some type of valve for field optimisation? One is knowledge, the other is physical equipment.?.

It’s all in the basket and like you mentioned, some of those names we work with. We have a partnership with Schlumberger where we collaborate on Research support for institution and individual researchers. We also have with Halliburton. Recently with SPE, we signed an MoU where we support research around this gamut of things you have mentioned. You have it in various phases in terms of what we do in research and development. It’s research for commercialization and also some bit of thematic research requirements that people come out with solutions to some of these problems that are encountered by the industry. But we also go beyond the industry because in Nigeria, you need a lot of research in various things as it were but the industry in itself acts as a catalyst to most of these things. We’re very much in that space. It’s a paltry sum that we have to support it. We wish that all the agencies associated with supporting research would pull resources together to build it formidable research and development structure in the country. That is my dream and desire.

Thank you very much. ES, thank you.

Thank you.


South African Hydrocarbon:  So Much Possible, But So Much Stalling

By Toyin Akinosho

Barbara Creecy, South Africa’s Minister of Environment, Forestry and Fisheries, has had far greater impact on investment in hydrocarbon development in the country, than the Minister of Mines and Energy, in the last two years.

Ms. Creecy passionately does her job, which has meant hounding out several companies intent on monetizing hydrocarbon resources, in the country.

Conversely, Mr.Gwede Mantashe, the Minister of Mineral Resources and Energy and a far more senior member of the ruling party, is laid back, very laid back.

If it wasn’t for the fact that fossil fuels are derided today as harbingers of extreme weather conditions, I would have invoked the last two lines of the first stanza of W.B Yeats’ poem, The Second Coming, to contrast Ms. Creecy’s and Mr. Mantashe’s attitudes to their work.

The best lack all conviction, while the worst   

Are full of passionate intensity.

It is the wrong text to cite, I admit. But a large segment of the oil industry would nod to the sentiments expressed in those lines when they consider their proposed/ongoing work programmes in the continent’s most industrialised economy.

One of the most recent of the unrelenting assaults on hydrocarbon investments in South Africa was the denial of the appeal by Turkish owned Karpowership, to obtain environmental authorization to install a 1,200Megawatt gas to power facility off the South African coast, despite its winning a bid run by the Ministry of Energy. The decision came a full year after environmental authorisation for the project was initially denied in June 2021.

The story? Three subsidiaries of the Karpowership Group:  Karpowership SA Coega, Karpowership SA Richards Bay, Karpowership SA Saldanha, won the bid for an emergency power supply aimed at procuring 2,000MW of power to bridge a looming electricity supply gap. They were to generate 1,220MW of power from imported Liquefied Natural Gas (LNG), in what was to be the first formal introduction of natural gas into the country’s electricity grid, through Eskom, the state utility.

In denying the project approval twice, Ms. Creecy said she had “the constitutional and legal obligation not to allow a preventable situation in an environment that may potentially harm the health or well-being, in a wide sense, of another person or persons. The need and desirability of a proposed project should also be considered in this context”.

These are valid arguments. But what does the Minister of Energy do?

He wrings his hands.

There have been several such disruptions by scores of environmental rights groups, fanned out across  the more than 3, 000 kilometre length of the South African coastline, from the desert border with Namibia on the Atlantic coast, to southwards around the tip of the continent and then back north to the border with Mozambique on the Indian Ocean. They are all screaming: “Not in My Backyard (NIBY)!” Their protests have forced a halt to a seismic data acquisition campaign by Shell on the Wild Coast (in the Eastern Cape); held up drilling by ENI in Kwazulu Natal and compelled Searcher Seismic, the Australian geophysics company, to give up on its proposed 10,000 multiclient 3D seismic survey, meant to cover the Outeniqua Basin and its sub-basins, including Bredasdorp, Infanta, Pletmos, Gamtoos and Algoa Basins.

The one case that many of us are closely watching is the progress of development of the Brulpadda and Liuperd fields, two giant gas and condensate tanks that TOTALEnergies recently discovered in deepwater Outeniqua basin. The company had submitted, in early September 2022, an application for production licences for a development plan that includes supply of the gas to the state owned, 200Million standard cubic feet per day (200MMsf/d), Gas to Liquids Plant (Refinery) in Mossel Bay on the Cape Town coast, as well as some 700MMscf/d of piped gas to other customers, located as far as Port Elizabeth in the Eastern Cape. This will represent some substantial flow of natural gas into the South African economy. But, as Ayanda Noah, chief executive of the state-owned Central Energy Fund (CEF) had long predicted, the approval process has come to be heavily subjected to virulent legal opposition from climate justice groups and nongovernmental organisations opposed to the development of the gas reserves.

Like Mr. Mantashe, Ms. Noah, a trained engineer whose office also oversees the functions of PetroSA, the state hydrocarbon company, comes across as helpless. “There is litigation just from all angles”, she told FN24, the country’s top online financial newspaper. And she said more: “PASA (the oil and gas upstream regulatory agency) has been trying to work actively to start engaging the public and just to simplify and help the public to understand better what we do”. Translation: “The Barbarians are going to invade! I really don’t know how we can hold our own!!”

What intrigues me is that even before the recent eruptions of NIBY protests against offshore exploration and production, the South African government, over the past 20 years, had sucked its thumb about the place of oil and gas in development. I’d stood and watched as several iterations of the Upstream Petroleum Resources Development Bill (Upstream Bill) had passed through parliament, observing endless debates without any traction; I have listened to several rounds of speeches by officials expressing concern about the looming shut down of the Mossel Bay refinery, as a result of depletion of gas reserves, and doing  nothing until it actually wound down; I’ve read statements after affirming statements about the Gas Utilisation Master Plan (GUMP) which never saw the light of day.

Then in 2016, the government came up with this idea of imported LNG for power generation. And I thought, well, may be. You know the outcome now.

Around the same time, I sensed I’d discovered what the problem had been. South Africans simply abhorred the idea of utilizing large volumes of imported natural gas. If there were discoveries of indigenous molecules, there would be less reticence, more vigour and robust activity around energizing the economy with this transition fuel.

But I am certain to be proven wrong again.

Algerian Court Finds Saipem Guilty of Fraudulent Practices

The Court of Algiers has imposed a fine of 34,000 Euros on Saipem SPA, the Italian engineering service provider.

The company says it welcomes “the absolutory content of the decision”, but it will “appeal the condemnatory content of the ruling, resulting in the suspension of its criminal and civil effects”.

The penalty is a result of the Court finding Saipem S.p.A. liable for the crime of “inflating the price on contracts awarded by a public company engaged in industrial and commercial activities, taking advantage of the authority or influence of representatives, to obtain advantageous prices compared to those normally charged, or to modify, to their advantage, the quality of the materials or services or the delivery or supply times”..

The ruling pertains to proceedings related to a 2008 bid for studies of competitive feed for the Rhourde Nouss Field.

“With reference to the claims brought by the Algerian state hydrocarbon company Sonatrach and Trésor Public (the national administration of the Treasury in France) as civil plaintiffs, the Court of Algiers, noted the absence of compensatory claims by Sonatrach against Saipem and upheld in minimal part the claims brought by Trésor Public, recognizing in favour of the latter a compensation for an overall amount of about 680.000 Euros, of which the quota directly pertaining to Saipem S.p.A. is equal to approximately 170,000 Euros”, Saipem says in a statement.


How Will You Ride the Slide in 2023? The Case of the Global Service Companies!

By Gerard Kreeft

A service company by its very definition is dependent on the fickleness and whims of the marketplace, but more specifically the oil and gas producers.

For starters, OPEC’s predicted oil production has varying scenarios. The cartel’s long-term forecast is now predicting a global production of 110Million barrels per day up to 2045(see below).

This optimistic prediction is at odds with Wood Mackenzie’s AET-2(Accelerated Energy Transition)

scenario which states that oil and gas demand in 2050 will be 70% lower than today. From

2023 onward oil demand drops with year-on-year fall of around 2Million barrels per day(BPD). Total

oil demand by 2050 is down to 35MillionBPD.

The current blip on the radar screen could well be caused by the reprieve that oil companies and hence their service companies are getting from higher oil prices that started with the Ukraine conflict. Deepwater is the fastest growing upstream oil and gas resource, according to Woodmac’s interpretation. Production in that terrain is expected to hit 10.4MillionBOEPD in 2022 and will reach 17MillionBOEPD by the end of the decade. Even if oil production is on a long term decline the deepwater exploration and development will continue to be the heartbeat driving the industry.

Yet in spite of higher needs for oil, the share price of the three major service companies, has lagged behind the Dow Industrial index.


The company has rebranded itself in two pillars: the traditional oilfield services and equipment (OFSE) and Industry and Energy Technology (IET), offering new energy services for the energy transition. BH’s investment programme is focused on revenue growth, margin enhancement, and improving ROIC ((return on invested capital). In 2022 total revenue of $20.5Billion are anticipated.

Up to 2030 IET is seen as the real growth engine, doubling revenues from $8.5Billion to $17Billion. Key drivers are LNG, CCUS (Carbon Capture, Utilization, and Storage) and H2 services and technology.


The company is involved in every stage of the oilfield life cycle: exploration, well construction, completions, production and abandonment. Key strategic priorities are profitable international growth, maximizing value in North America and automation of the value chain.

Halliburton is also dedicated to helping customers decarbonize legacy production bases. The company is pledged to reducing Scope 1 & 2 emissions by 40 percent from its baseline of 2018.

Revenue in 2021 was $15Billion.

The company’s energy transition solutions include CCS, CO2 storage and geothermal services.


Schlumberger is of the view that the current oil industry revival is driven by the underinvestment of the past. E&P capital is poised to accelerate E&P capital across all geographic and operating boundaries to drive new production capacity increases.  Digital and decarbonization are gaining momentum.

FID (Final Investment Decision) for the period 2022-2025, in Schlumberger’ estimation, will be $397Billion as opposed to $267Billion in the period 2016-2019. This is an increase of 49%, which is large by any measure.  Offshore represents five times the revenue potential of onshore.

The company indicates that it is reducing emissions and environmental impact with practical, quantifiably proven solutions through partnership across the industry. CCS is one of these measures.

Financial Overview & Summary

Dow Jones Industrial Index in the period January 2018- December 2022 rose 31%: increasing from 25,295 to 33,147. Yet in that same time frame the three major service companies have seen their share price tumble, in spite of a revival in the oil and gas market.

BH has seen its share price fall the least: $29 December 2022, and $34 January 2018, a drop of 13%.

Halliburton’s share price January 2018 was $52 and $39 December 2022, a drop of 25%.

Schlumberger’s share price January 2018 was $74, and December 2022 was $53, a drop of 28%.

By all indications the major service companies have fallen out of favour with major investors. Increased oil and gas activity is no longer a guarantee that this will increase the value of a company’s share price.

Yes, all three service companies are pledged to further decarbonizing their asset base as well as further digitalization. Yet in the final analysis the service sector is dependent on the oil majors who determine the pace and strategy of the sector. As long as the oil majors continue to see their dominant operations within the scope of the E&P world the service sector’s future has been determined.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe.  Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and is a guest contributor to IEEFA (Institute for Energy Economics and Financial Analysis). His book ‘The 10 Commandments of the Energy Transition ‘is on sale at


Local Content Should Not Reduce Competitiveness or Foster Cost Increases

By Paulino Jerónimo

LUANDA, ANGOLA-October 20 is a date of particular relevance for the ANPG, as it was on this day that, in 2020, the Angolan National Concessionaire, through the publication of Presidential Decree 271/20 , was given specific responsibilities for the operationalization of local content in the Oil& Gas Industry.

Top on the assignment was the development and publication of annual lists of goods and services under exclusivity and preference regimes, the registration and certification of Angolan suppliers, the monitoring and inspection of the contracting processes in the sector, the consolidation of the of National Local Content and monitoring the implementation of the Human Resources Development Plan together with MIREMPET.

Here, what results do we have to present in this matter?

The ANPG started by meeting with the government institutions involved in the process – the Ministry of Mineral Resources, Oil and Gas (MIREMPET) and the Ministry of Economy and Planning (MEP) – and with the associations representing suppliers in Angola, namely with the Association of Contracted Companies of the Oil Industry of Angola (AECIPA), the Association of Indigenous Companies for the Oil Industry of Angola (ASSEA), the Association of Exploration and Production Companies of Angola (ACEPA) and the Competition Regulatory Authority (ARC).


The work carried out together resulted, on October 18, 2021, in the publication of the lists of goods and services in the exclusivity and preference regimes on the ANPG website and in Jornal de Angola.

On the same day, the registration and certification process for suppliers came into force through the launch of the platform for this purpose on the ANPG website.

One year after its entry into force, we have 786 companies registered on the ANPG platform and around 322 companies certified in various sectors of the national economy. It’s already working!

We have also set up and operated the ANPG’s Local Content Centre with the aim of guaranteeing the continuity of the operationalization activities of the new local content regime and of coordinating all activities for the creation and implementation of the future Local Content Office. of the National Concessionaire.

The new local content framework must be competitive and must develop the necessary quality among companies. Local content should not reduce competitiveness or increase costs in the industry. This would send the wrong message to investors and could impact the overall objective of ensuring sustainable production.
Our approach was to create three contracting regimes: exclusivity, preference and free competition. The least complex work to be done in the industry was reserved for exclusivity because that work can be carried out by local companies, and they are already doing it.
For the preferential regime, if the service or goods are provided in the country, preference shall be given to the local provider if the cost is within a certain range. If local companies are much more expensive than international ones, it is possible to acquire the goods or services from international companies. The idea here is to generate joint ventures in which international companies bring knowledge and investment to local partners. Our expectation is to update these goods and services lists annually if we need to.
Our expectation also is that this process generates real local companies that can do more complex work, and then we can migrate goods and services to the exclusivity regime.
Sometimes there is a misinterpretation of our procedures. Local companies need to first register on the ANPG website, then present the required documentation. The ANPG and representatives of operators will then visit these companies’ installations to check whether they are up to the standards we require before providing the approval and certification to enable them work in the industry.

In the meantime, with the express support of the Ministry of Mineral Resources, Oil and Gas, we held two workshops in Angola on local content, in which the most relevant national representatives of the oil industry were present and we presented our strategy for operationalizing the theme.

In other words, in these two years we followed up on the functions assigned to us and worked to present results. Above all, to create conditions that allow national companies and entrepreneurs to be one of the most active voices in the development of the Angolan oil sector.

And it is in this way that we promise to continue, supporting, stimulating, contributing so that we all work together more and better for the economic and social development of our country!

Count on us. We count on the commitment of all of you!

Paulino Jerónimo

Chairman of the Board of Directors of the National Agency for Petroleum, Gas and Biofuels

Century Begins Upgrade of FPSO For Dangote’s Kaelekule Field

By Prospect Mojido, in Lagos

“The real work is to repair relations between NNPC, WAEP AND First E&P”

Century Energy Group has moved the Front Puffin FPSO (Floating, Production Storage and Offloading) vessel from the Aje condensate and gas field offshore Nigeria, to the SHIMCI FZE quayside in the Port of Lagos, for upgrade.

It is the third project to be carried out in the SHIMCI FZE yard, widely known to as Samsung -Ladol yard, since the fabrication and integration of the Egina FPSO, which sailed away to the deep offshore field in August 2018.

The de-bottlenecking upgrade is meant to get the Front Puffin ready for its next assignment on the Kaelekule oil field in in Oil Mining Lease (OML 72), held by the NNPC/West Africa E&P (WAEP) Joint Venture.

This event “draws closer the date for first oil on the field and may possibly make everyone involved more committed to early monetization of this resource”, multiple sources tell Africa Oil+Gas Report.

Owned and managed by the Century Group, the Front Puffin, has produced from the Aje field since May 2016. It is a single-sided FPSO with a hydrocarbon production facility designed to receive well fluids, separate and stabilize produced crude, store and stabilize crude in the FPSO’s cargo tanks, treat and discharge the produced water and compress the produced gas for gas lift with the balance of the gas being flared.

The upgrade is focused on changing the current submerged turret production (STP) and mooring configuration to a spread-moored design and inclusion of riser porch so as to accommodate the shallow water and draft requirement of the FPSO.

The location of the de-bottlenecking project in Nigeria provides a significant discount. It reduces the cost that would have been incurred if the job was to be performed in Singapore or Korea. Industry data evaluated by Africa Oil+Gas Report indicate a steep reduction in overall cost of the upgrade from over $250Million to less than $100Million.

Although Samsung sources say that the upgrade would be completed by late February 2023, at which time the vessel would be ready to receive hydrocarbon fluids, there is no certainty that all the upstream partners are in agreement over the proceedings of the work programme, let alone the date of first oil.

Which is odd, as Nigeria has struggled with declining crude oil revenues in the last one year as it battles a huge shortfall in its OPEC production quota. The country is in urgent need of topping up its crude oil output now.

The Kaelekule oil field redevelopment project has dragged, although the scope has increased from “early, marginal output “, of about 2-3,000Barrels of Oil Per Day, to a sizeable 15,000BOPD

The initial plan was to commence some production from the OML 72 by 2019, four years after WAEP, a subsidiary of the Dangote Industries Conglomerate, purchased 45% of the shallow water OMLs 71 and 72 from Shell, TOTAL and ENI for $300Million. WAEP has had, as a technical partner, First E&P, a Nigerian independent oil producer. Kalaekule field, the only field in the two acreages with a history of production, had been scheduled for a revamp; the field had produced crude oil between 1985 and 2002, peaking in 1999 at 22,000BOPD, but much of the facility has rotted.

In 2019 WAEP carried out safe access works, as well as repairs, on the field’s two wellhead platforms, KCPP-A & KCPP-B platforms. The company also did some work on some of the wells on both platforms, including well testing work on the platform B wells. Asset Integrity work, which will end in certification when all complete, is ongoing.

But much of the delay has been due to pushbacks from the National Petroleum Investment Management Services (NAPIMS), the arm of the state hydrocarbon company NNPC Ltd which oversees NNPC Joint Venture activity.  NNPC, through NAPIMS, holds 55% of the asset, and thus contributes that proportion to the wok programme.

NAPIMS eventually agreed to honour work done and the costs incurred in the field optimization work of 2017-2019, but NAPIMS did not honour the 2021 work and has provided no budget for the 2022 work.

“What is important is to repair relations between the partners”, one insider tells Africa Oi+Gas Report.

When the upgrade is completed, “the FPSO will receive co- mingled well fluids from KCPP-A platform through 10″ HP flowline, to enable topside production facility to be isolated from flowline/Production Platform”, says Mochamad Yudistira Nugraha,  SHIMCI FZE yard’s Senior Manager Business Development, .

NUPRC Calls for Inputs for the Next Phase of Regulations Development


The Nigerian Upstream Petroleum Regulatory Commission(NUPRC) has given notice of stakeholder consultation regarding the third phase of regulations development in line with section 216 of the Petroleum Industry Act (PIA) 2021.

The commission invites inputs from Lessees, Licensees, Permit holders, Host Communities, and other stakeholders of the Nigerian Upstream Petroleum sector, between now and January 9, 2023.

1. The matters to which this stakeholders inputs and consultations relate are as follows:

i. Upstream Petroleum Measurement Regulations

ii. Advance Cargo Declaration Regulations

iii. Significant Discovery Regulations

iv. Gas Flare Penalty (Amendment) Regulations

v. Domestic Crude Oil Supply Obligation Regulations

vi. Nigerian Upstream Measurement Regulations

2. Stakeholders are kindly enjoined to follow the link below to download and

review the proposed regulations; https://www.n u p r ng/regulation- development-pio-2021/.

3. Accordingly, submissions of inputs to the regulations are hereby requested as part of the process of stakeholder consultation prior to finalization of the regulations, to give meaning to the intent of the PIA 2021

4. All submissions must be made using the format accessible through this link /uploads/2022/NUPRCRequlation-Comments-Sheet- xlsl.

They must be received at the email address below NO LATER THAN 21 DAYS FROM DECEMBER 19 2022, which means January 9, 2023 (as his publication was put on NUPRC website on December 19 2022).

5. Kindly forward your submissions to the Head Compliance and Enforcement Unit of NUPRC, Kingston Ezeugo Chikwendu on, GSM 08077724442 for further necessary action.


Engr. Gbenga Komolafe FNSE Commission Chief Executive

Will 2023 see a Revival of the Deepwater Market?

By Gerard Kreeft

Is the deepwater market on the cusp of a revival in 2023? Preliminary signs are promising. Yet to participate in this marketplace requires very deep pockets and stamina. While the drilling fraternity has undertaken the necessary rationalization—witness Saipem selling its land rigs to KCADeutag and the merger of Noble Drilling and Maersk Drilling—the oil majors have indicated that it will be business as usual. How will the deepwater marketplace develop in an ongoing turbulent energy future? Is there room at the poker table for the deepwater players who are being constantly overshadowed by energy scenarios which are predicting the early death of the oil and gas industry and hence the deepwater sub-market? Have deepwater exploration and development been given a premature death sentence?

Two opposing scenarios are currently in play: the re-emergence of the offshore marketplace, in particular the deepwater plays; and the International Energy Agency (IEA) ’s recent prediction that in the period 2022-2027 there will be a sharp growth by 2,400 gigawatts (GW) in installations of renewable power. That renewables are becoming a bedrock of the energy transition is not in doubt. Less sure is whether the deepwater players will have a continuing staying power. How will the oil majors divide their capital budgets between oil and gas projects and renewables? Below an overview of what to anticipate in 2023.

The Current Market Situation

A telling sign for 2023 are the recent robust contracts signed by Transocean and the drillship purchased by Saipem. Tranocean’s Deepwater Corcovado drillship was awarded a four-year contract having an estimated worth of $583Million; the company’s Deepwater Orion drillship signed a three-year contract worth an estimated $456Million.

Saipem, in turn, has announced that it has purchased the Santorini, an ultra-deepwater drillship, from South Korea’s Samsung Heavy Industries to strengthen its offshore drilling fleet amid the growing demand in the market. Saipem disclosed that its purchase option of $230Million will be financed entirely from available cash.

Can the deepwater drillers expect better times in 2023?  The terrain, according to WoodMackenzie, is the fastest growing upstream oil and gas venue: production is expected to hit 10.4Million Barrels of oil equivalent per day (BOEPD) in 2022 and will reach 17MillionBOEPD by the end of the decade.

“Brazil remains the leading deepwater producer, it accounts for around 30% of current global capacity and will continue to grow. Guyana, the most significant new entrant, will be producing 1MillionBOEPD within the next five years. In total 14 other countries will contribute to the deepwater supply mix in the coming years.”

Indexed oil & gas production growth by resource theme, 2022-2030

Source: ‘Global deepwater production to increase 60%’, WoodMackenzie, November24, 2022

According to WoodMackenzie the sector remains under the control of a small number of key players: “Petrobras and the seven majors dominate deepwater production, operating 22 of the top 25 deepwater assets. Petrobras’ deepwater portfolio is around twice as big as its nearest peer, Shell, which stands out among the majors for leading production and cash flow. ExxonMobil and TOTALEnergies show the highest rates of growth this decade.”

According to a recent Valaris investor presentation 2023 and beyond will provide the drillers market conditions not seen for many years:

At present the deepwater drillship fleet has been rationalized to 158 units from a peak of 281 in late 2014; the jackup supply has declined to 493 units from a high of 542 in 2015. Yet one-third of the jackups are more than 30 years old and have a limited use for the future.

Majority of the deepwater rigs are very modern, only 16% of current supply is older than 20 years;

Because of improved market conditions, rationalization of the offshore fleet utilization for both drillships and jackups is above 90%.

Average dayrates for drillships signed in the third quarter of 2022 have more than doubled to $402,000 from $193,000 in the fourth quarter 2020. Average dayrates for jackups signed in the third quarter of 2022 is $97,000 compared to $71,000 in the fourth quarter of 2020.

The Oil Majors


A key component of BP’s strategy is building an investment structure, which requires only a few skilled accountants. The company has either sacked employees or will be delegating BP’s headcount to its joint ventures. The goal is to become lean and mean, reducing costs and, hopefully, increasing margins. In short becoming an investment vehicle.

A key strategy is to decrease its oil production by 40% by 2030. In Angola  BP has merged its upstream activities with ENI to form Azule Energy, which could become a model for other African countries.

To date the company has initiated a series of joint ventures to speed up its transition.

  • BP and Ørsted have partnered to develop zero-carbon ‘green hydrogen’ at BP’s Lingen Refinery in north-‎west Germany, BP’s first full-scale project in a sector that is expected to grow rapidly. The 50 MW electrolyser project is expected to produce 1 ton of ‎hydrogen per hour – almost 9,000 tonnes a year – starting in 2024. The project could be expanded to up to 500 MW at a later stage to replace all of Lingen’s fossil fuel-based hydrogen.
  • BP and Equinor revealed that BP will become a 50% partner of the non-operated assets Empire Wind (offshore New York State) and Beacon Wind (offshore Massachusetts). BP and Equinor will jointly develop four assets in two existing offshore wind leases located offshore of New York and Massachusetts that together have the potential to generate power for more than 2Million homes.
  • BP joined Statkraft and Aker Offshore Wind in a consortium bidding to develop offshore wind energy in Norway. The partnership—in which BP, Statkraft, and Aker Offshore Wind will each hold a 33.3% share—will pursue a bid to develop offshore wind power in the Sørlige Nordsjø II (SN2) licence area.


Two-thirds of Chevron’s production in 2025 will come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States will each yield 1MillionBOEPD.

In 2021, Chevron established a New Energies division devoted to lower-carbon technologies, pledging to spend $10Billion through 2028—about $2Billion per year, or 12.5-14% of Chevron’s projected capital.

The company has indicated that over the next 3 years it will spend some $10.5-$12.5Billion yearly in the USA, mostly in the Permian Basin and Gulf of Mexico. This means that at least 75% of Chevron’s total capital budget over that period is pledged for the U.S. market.

Outside the USA, Chevron will spend $3.5Billion, or 70% of its international budget, to develop its Tengiz asset in Kazakhstan, with the remaining $1.5Billion spent elsewhere. This is not promising for Africa, where Chevron has major operations stretched across the continent, including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt that have received limited funding in order to bankroll Tengiz.


ENI states that 90% of exploration capex is spent on near fields and proven basins. Some $11Billion in the last 10 years has been spent on its dual exploration model—near fields and proven basins. The company states that it only requires three years—from first discovery of oil to market—twice as fast as the industry average. The company produces 1.7MMBOEPD, has a balance sheet which has an economic leverage of 20%, and has, according to its website,  an Internal Rate of Return(IRR) of 34%, the highest of all its peers  for the period 2012-2021. Also, its RRR(Reserve Replacement Ratio) of 110% for the period 2012-2021 is the highest compared to its industry peers.

A key ENI strategy  is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets and at the same pursuing new strategies as part of its energy transition plan.  A key example is Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’ upstream assets, LNG and solar business. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2Billion barrels equivalent of net resources and growing to about 250,000BOEPD of equity oil and gas production over the next 5 years. It holds stakes in 16 licences (of which 6 are exploration blocks) and a participation in Angola LNG JV. The company also participates in the New Gas Consortium (NGC), the first non-associated gas project in the country.


Equinor’s has two pillars: natural gas and its growing offshore wind portfolio. Does the company have the financial depth and ability to achieve maximum leverage for both pillars?

Equinor’s offshore wind portfolio is pledged to grow to 12–16 GW of installed capacity by 2030. Renewables will receive more than 50% of capital investments by 2030.

Equinor has chosen a series of joint ventures to develop its offshore wind portfolio. The first, Dogger Bank, heralded to become the world’s largest offshore wind farm, is being developed together with SSE Renewables based in the UK. Located in the North Sea, the project will produce some 3.6 GW of energy, enough to power 6Million households. More recently, Eni has purchased a 20% stake in the Dogger Bank A & B Project.

The second is Equinor’s Empire Wind and Beacon Wind assets off the USA’s east coast. In September 2020 it was announced that BP was buying a 50% non-operating share, a basis for furthering a strategic relationship. The two projects will generate 4.4 GW of energy.

By 2030 the company will be spending more than one-half of its capital spending on low carbon energy to become a leader in offshore wind technology.


For 2023 the company has stated that its capital investments will range between $23Billion-$25Billion. Over a six year period ExxonMobil will invest some $2.5Billion per year in low carbon solutions: CCS (Carbon Capture and Storage) hydrogen initiatives and biofuels. The company will invest 70% of its capital budget in the Permian Basin (USA), Guyana, Brazil and LNG projects. By 2027 production is anticipated to be 4.2MillionBOEPD.


Annual capital expenditures in the near term, according to Shell, could be in the range of $21-23Billion. The company has stated that its renewables and energy solutions will be $2-3Billion compared to previous targets of $1-2Billion. This pales in comparison to the $3Billion earmarked for marketing, $4Billion in integrated gas, $4-5Billion in chemicals and products as well as $8Billion in upstream investments. For the period 2025-2030, Shell lumps together the capital budgets devoted to three categories:

  • Growth which entails renewables and marketing will receive 30% of Shell’s capital budget;

 Transition which entails Integrated gas and chemical & products will receive 30-35% of Shell’s capital outlay; and

  • Upstream will get 30-35%.

Predicted Internal Rates of Return per category vary between 10-25%.


TOTALEnergie’s capital expenditures for the period 2022-2025 is anticipated to be between $13Billion-$16Billion per year: 50%  ($6.5Billion-$8Billion) on hydrocarbons and only 25% ($3.25Billion-$4Billion) on renewables.

Much of TOTALEnergies’ hydrocarbon budget will be devoted to Africa in which  low-cost, high-value projects are the goal. Squeezing more value out of  various African assets to ensure a prolonged life cycle.

A prime example is TOTALEnergies’ Mozambique LNG project, which is expected to cost $20Billion and produce up to 43Million tons per annum.

In Angola the company produces more than 200,000 boepd(barrels of oil equivalent per day) from its Block 17 and Block 32, and non-operated assets including AngolaLNG.

In Namibia TOTALEnergies has made a significant discovery of light oil with associated gas on the Venus prospect, located in block 2913B in the Orange Basin, offshore southern Namibia.

In South Africa the company is focused on its two South African assets: Brulpadda(drilled to a final depth of more than 3,600 meters) and Luiperd, the second discovery in the Paddavissie Fairway in the southwest of the block.

Key Takeaways

Deepwater production is expected to hit 10.4MillionBOEPD in 2022 and will reach 17Million BOEPD by the end of the decade.

  1. Wood Mackenzie’s AET-2(Accelerated Energy Transition) scenario states that oil and gas demand in 2050 will be 70% lower than today. From 2023 onward oil demand drops with year-on-year fall of around 2Million barrels per day (bpd). Total oil demand by 2050 is down to 35MillionBPD. What affect will such long-term reductions have on future deepwater investments and strategies? Will the deepwater plays continue to be a strategic part of the energy world?
  2. Further long-term investments and rationalization will have to be done if the deepwater sector is to be a strategic energy player. Already the deepwater drillers—Saipem and Nobel Drilling+Maersk Drilling– have rationalized their deepwater fleets. Of the oil majors only BP and Eni have joined forces in Angola to form the JV Azule Energy. Will others follow?
  3. Closer examination of the oil major plans reveals that in 2023 it will be business as usual. Continued higher oil prices have postponed any thought of possible future mergers and rationalization among the oil majors. Be that at a project or at a corporate level.
  4. Finally, the IEA’s recent report which states that “renewables are set to account for over 90% of global electricity expansion over the next five years, overtaking coal to become the largest source of global electricity by early 2025,” should be a sharp warning to all energy players.
  5. In conclusion ‘Fasten Your Seat Belts’, we are headed for turbulent weather.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe.  Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis). His book ‘The 10 Commandments of the Energy Transition ‘is on sale at

Angola’s Hydrocarbon Output Slumps for the Third Consecutive Month

By Angolan National Petroleum and Gas (ANPG) Agency

Translated directly from Portuguese

Angola produced 32,590,947 barrels of crude in October 2022, corresponding to a daily average of 1,051,321 barrels of oil (BOPD) against a forecast of 1,123,215BOPD.

It was 3% less than the 1,091,371BOPD produced in September 2022, which was 7% less than the 1,174410BOPD produced in August 2022, which itself was less than the July 2022 output of 1,177,153BOPD.

Associated gas produced (outside the Cabinda Association) during October 2022 was 69.140Billion cubic feet (bcf), a 10% drop from the 76.6Bcf of gas output in September 2022, which on its own was a 14% slide from the 89.5Bcf produced in August 2022. Naturally the volume of gas made available to the Angola LNG plant in Soyo, dropped 17% to 498MMscf/d from 599MMscf/d in September 2022, which itself was an 18% plunge from 730MMscf/d in August 2022.

1,096MMscf/d was injected, and 300MMscf/d utilized for power generation at oil facilities and the remainder used in oil operations and disposal.

The ALNG Factory produced 2,614,487barrels of oil equivalent (BOE), or 84,338BOEPD in October 2022, with LNG production of 68,188BOEPD, 6 898BOEPD of Propane, 5,311BOEPD of Butane and 3,942BOEPD Condensates.

Associated gas production of the Cabinda Association was 700MMscf/d in October 2022, from which 349,578barrels of LPG (averaging 11,277Barrels Per Day) was extracted and divided into daily production of propane of 6,387barrels and butane of 4,674barrels.

The total production of crude oil, condensate and LPG was 32,940,525BOE, or average of 1,062,598BOEPD; the operational efficiency of the facilities was 89.18% against a forecast of 91.18%.

Angola’s crude oil exports for October 2022 were 33,619,013barrels (or 1,084,484BOPD) against 996,774BOPD predictted. The ANPG lifted around 7,252,023 barrels (22% of total withdrawals), Sonangol P&P lifted 4,859,517barrels (14% of total withdrawals) and the Sonangol EP lifted 1,759,442barrels (5% of total withdrawals).

Rig Activity/Well Count: In October 2022, TEN (10) drilling units were in operation, five (5) of which were drillships, namely West Gemini, Sonangol Libongos, Valaris DS-09, Sonangol Quenguela and Transocean Skyros and one (1) semi-submersible rig Scarabeo 9. There was one ground probe FALCON HP-1000, one (1) Tender SKD Jaya, one (1) Tension Leg Platform TLP-A; one (1) Jack Up Shelf Drilling Tenacious Probe. These 10 units carried out work in twenty (20) wells, including four (4) intervention operations, fiftteen (14) drilling/completion operations and one (1) evaluation, making a total of 8,754 metres of drilling.

Completed in the month: Four (4) development wells (producers), one (1) injector development well, and two (2) interventions in producing wells.

Originally published in the October 2022 edition of the Africa Oil+Gas Report.

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