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Industrial Park Will Provide Gas & Power: A Solar Manufacturing Plant Is in the Pipeline

CHIKEZIE NWOSU will retire as Managing Director/Chief Executive Officer, Waltersmith Petroman in the next three months. Which makes this second part of  Africa Oil+Gas Report’s  interview with him a valedictory feature. He talks about the company’s upstream business; its asset in Equatorial Guinea, as well as host community, human capacity development and “the future” issues, including the planned investment in renewables.

Waltersmith is an influential player in the African Exploration & Production sector. EXCERPTS by Akpelu Paul Kelechi….

Waltersmith dropped its acquisition in Uganda and later took up assets in Equatorial Guinea. What’s the update on the award?

In 2019 we bid with many other international companies for the EG-Ronda 2019. We put in the most competitive bid for Block EG 23, which is an offshore block roughly about 70 metres of water depth and with significant oil and gas reserves. There are discoveries there, they just have never been developed to be put in production, but they’ve been tested so these are not exploration type blocks. We negotiated a production sharing contract (PSC) with the Government, and we have signed off on our own-in February 2020- and they told us it was going to go through their legal process. Unfortunately, both COVID and some internal processes within Equatorial Guinea meant that they have not yet signed. Now at the launching of the NNPC Limited, the (then) Minister for Mines and Hydrocarbons honorable Gabriel Obiang Lima was there and we again reminded him of the fact that we were still anxiously waiting. And they actually sent us a letter indicating that we are still on track and that once they go to the processes, they would sign the PSC and return it to us. We intend to set up an office, which would be our first International office, in Equatorial Guinea.

So, you see, these things take time. We earlier talked about negotiation with the Nigerian government for  Assa and OML 20 taking about four and a half years. Now we are talking about Equatorial Guinea having taken three years or there about, and we’re still there.

Did you participate in this just completed 2020 marginal field bid round?

Yes we did.

Did you get any field?

No we didn’t.

You want to tell us your story behind it?

There is no story behind it. We put in what we think was one of the best technical bids as we usually do and we couldn’t have won block EG 23 in Equatorial Guinea against other international companies if we didn’t know what we’re doing, yeah? We put in the best Technical and Commercial bid that we thought there was and we’re not going to pay anybody any ridiculous signature bonuses because for us, the value from royalties and taxes to the Nigerian government for early development, if you don’t hamper people’s development through paying huge signature bonuses, is much more than any upfront signature bonus. I can almost tell you that in a field where you have about let’s say 20Million barrels of Reserves, even if you do a conservative $50 per barrel, if you do your calculations well, that’s a significant revenue. And then from there, you pay a significant amount up front of the revenue if you manage to sell it for royalty. Then you take away your costs; we are a very cost-efficient company and then you pay taxes which are significant as well. Those monies cumulated together are much more than any signature bonus. But if you hamper those assets with a huge signature bonus, then those companies will pay a signature bonus but will be unable to develop the field very quickly. Which means that the federal government will lose early revenue from the field. The logical thing to do is bring down the signature bonuses and go to people who are technically and commercially proficient and have the funding to quickly develop and deliver these Fields. That’s what we thought we were. That’s what they thought we weren’t.

Waltersmith now has three arms, your upstream arm, midstream arm and your downstream arm. Is there any point where all these arms coalesce in your host Community relationships?  Or are they separate?

We have to deal with the different companies at arm’s length because they have different boards. But all the energy components report in to me and we keep our transactions at arm’s length. The refinery pays the commercial rate for the oil coming from the upstream part of the business. The gas-to-power pays for gas at the commercial rate and then delivers the power at a commercial rate to the refinery and flow station at this moment and we will continue to do that. How do we deal with the communities?

Whatever China has as a competitive advantage, Nigeria can provide it as well. We started working with some parties to see whether we can start solar PV manufacturing in the industrial park

At the moment, we have Global Memorandum of Understanding (GMoUs) tailored towards Waltersmith as a group not as individual companies. When we invested in the refinery, we adjusted the value of our GMoU along the principles we agreed with communities that for any new projects of XX size, we’re going to increase the GMoU funding by a certain amount of money and that’s what we keep doing. With the refinery we increased it, with the gas business that will also happen. In terms of what we do in the communities and what we’re also trying to change. Human Capital Development HCD is one of the most critical ones for me because it’s not about just building hospitals or building schools because everybody does that. The quality has to be right and then putting utilities in place, like water, electricity is still a challenge and we’re trying to address it together with the other companies in the same operational area and providing good roads. We want to provide good paying jobs and so we started a technical skills acquisition programme. Now using our HCD part of our project, we identified 200 graduates from the community who had graduated but were not industry ready. We have to prepare them for the industry. From the first batch, there were 50 applicants but only 47 attended. And out of that 47 we have hired 12 formally as staff of Waltersmith into our operations, both the refinery and the flow station and three more are there on a contract basis. So, 15 altogether. We expect that as our project grows, for example our trailer park, we want to hire a few more people from that programme into the trailer park and we also have certified them in such a way that other companies there can also look to hiring them for some of their operations. We’re trying to encourage all our other counterpart companies there to look at these communities and hire from them because the disadvantage these communities have is the fact that, if you open up the competition for those kind of positions to everybody in the country or even in the state, the communities will probably lose out. Okay, so we have a different programme that is for all Nigerians and that is our Graduate Intensive Programme and then we have a specific programme for the communities which is our technical skills, acquisition programme.

It is not about these artisanal skills, like welding and all those things. It’s about operations, maintenance and those kind of skill sets that we are hiring graduates into our operations for. And that to a large extent has brought a lot of better relationship between ourselves and the youth in the community.  And as we expand into Assa field, we will continue with the same thing. We’re going to run the programme in 2023 as well with another batch of about 50.

And we’re going to deploy some of these people who we are training but who we cannot hire directly, into being the supervisors of the project we deliver. Because sometimes we are delivering projects in the communities and the supervision is poor, but if they have their own graduates who have come through our training programme and understand projects, civil engineering work projects and things like that, they can supervise Market store buildings, Hospital buildings and the like and hopefully going forward, as we build more hospitals and schools, we can then start training teachers, and medical personnel who would man some of these facilities as well. So human capital development is an integral part and a critical part of our delivering projects to the community.

Now things are going to change a little bit with the host community regulations. And Waltersmith is one of the first to try and get its entire documents ready and submitted to the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) for that purpose. We’ve already started identifying some of the people that will from the Committees from the community itself so that will transit from the GMoUs into this, host Community bill.

In terms of spend, are you necessarily spending more or less? You know, you can have this very robust programme but in terms of spend, it can be much lower than what the Host Community Fund in the Petroleum Industry Act mandates you to spend.

I think you said you know me by reputation.

Oh, yes I do.

Then you know that my business ethics are right at the top. So let me explain coming from Shell. Sometimes at Shell, 2% of the CAPEX, before the Nigerian Content started, 2% of the CAPEX of projects was supposed to be allocated to community projects. Any capital project that I was involved in, 2% was spent. Or more. Because sometimes the communities’ needs did not amount to the value of the 2%, I have to go and make the case that our rules internally are 2% and so let us go and ask them for more projects. The same thing here; I have had conversations internally where it has been pointed out to me that you can go and negotiate something lower to be spent. I don’t even know how that is done and I tell them, please do not do that. It’s not while I’m here. While I’m here, for our capital projects, we submit them to (National Content Development Monitoring Board(NCDMB), they calculate what the 3% is and that is what we use for human capital development. So it can be that or more not less.


Oh later on it will become NUPRC. But at this point, for our human capital development, I don’t know how it’s going to transit under the PIA, the human capital development is 3% of the CAPEX of the projects; it is different from the Host Community Fund. The Host Community Fund is under the PIA at this time and it is 3% of your operating expenditure of the previous year.

You did say you trained 50 people?

Chike Nwosu: We brought in 50 but 47 showed up for the training.

AOGR: Was it last year?

Chike Nwosu: It was last year, yes.

AOGR: Okay, you did mention 200.

Chike Nwosu: We identified 200 and we are going through the entire 200. This is the first batch and we are doing it phase by phase. Because if you train 200 people, then you have to bring in a significant portion of that 200 and we have to tie it in with the progress of our projects. So the next batch will be targeted at the refinery expansion. Yeah, and the next batch will be targeted at the condensate expansion while the next batch will be targeted at the industrial park.

Because we also want to provide for the people that will come into the industrial park, the technical, operational, whatever competency, even supports competencies, administrative competence, that are required for them to run their factory, will be from the people in the community first.

Let’s examine this large elephant in the room. Waltersmith has not exported a drop of crude, out of the country since March 2022. The Trans Niger Pipeline, its evacuation route, a has been down for that long. There are people who believe that much of the stolen crude is actually being exported.

I believe that absolutely.

You don’t think that those artisanal refineries-there’s quite a large number of them-are largely responsible…

I’m looking at the logic going backwards because I’ve run a refinery. If for a 5,000 barrels per day refinery, 130,000 litre truck is less than 200 barrels, about 188 barrels. And it you take the dead stock away you would have let’s say 180 barrels. A 45,000 litre truck is less than 280 barrels so you can imagine that for a 5,000 barrel refinery, I need about 30 trucks. Now the crude that is supposedly stolen for illegal refining on the TNP is in excess of 150,000 barrels by the time crude oil theft got to 90%. That is 30 times the number of trucks that I need which is about 750 trucks. I don’t think you could have 750 trucks a day plying that axis without anybody seeing them. It is near impossible to imagine that scale of trucking and logistics happening and that was why I said illegal refineries do not go beyond 40-50,000 barrels per day. The rest of it is a major cartel; I borrow the words of one of my colleagues, I think it is the MD of ExxonMobil, who said that it is an international criminal cartel that are hugely moving away our crude in big tanks not the artisanal or what they call illegal refineries.

The question then is, is it that, once you have a significant volume of theft, you just basically stop producing, so that when the entire production in the country turns out to be just 1.2 million, it is not so much that 1.3Million has been stolen? Or that companies just scale back because you know, so much is being stolen?

There’s been a massive reduction from highs of over$ 20Billion investment per annum to as low as $6 Billion investment in the oil and gas industry. That has the most significant impact on our overall production

Let me tell you about to perspectives about OPEC’s quota and how low it has come. I think Austin Avuru and Osten Olorunshola have shown some work that has been done to indicate that even without crude thefts, because of the lack of investment, you know, these assets will decline. And the decline on the average is 10 to 15% per annum. And the only way you can actually increase production is through new investments, new developments, new production optimization, enhanced oil recovery and things like that. Now Austin, the two Austins, have shown that over the period of the last seven to ten years, I think more likely seven years, there’s been a massive reduction from highs of over 20Billion dollars investment per annum to as low as six Billion dollars investment in the oil and gas industry. That has the most significant impact on our overall production and you know, our OPEC production. So let nobody go away with the thought that it is because of crude thefts that we have gone from two point something Million barrels to 1.2Million. No; investments have not been there to sustain that level of production and to grow it because decline will happen. What you can do is go to 2Million barrels seven years ago and do a decline at 10 to 15 percent and you’ll see the impact of that. Okay? And they even showed the direct correlation between the trending down of Investments and the trending down of production.

Now, however, it doesn’t mean that crude theft is not a problem. It is a significant problem on the onshore assets and he talked about the figures and these are NUPRC’s/DPR figures.

The Waltermith Industrial Park will provide energy products to companies around Ibigwe. That’s the plan. These products are essentially gas and power. Before I ask you where you see Waltersmith in the next five years, there was a point you mentioned at the Nigerian International Energy Summit (NIES) about solar assembly. That was a data point that just leapt at me. I mean, solar, what’s that all about?

There’s something else in our blueprint beyond solar. I’ve got an intern here working on Blue Hydrogen. We recognize that there’s going to be a transition and that the transition will happen through gas as the transition fuel. Our gas business will start dominating the Upstream and we’re looking at the portfolio where that happens and Equatorial Guinea EG 23 is an example of where there’s a lot more in terms of gas reserves in BOE terms and then there’s oil. OML 20 has a lot of gas reserves as well and so we’ve continued to look at those assets. OML 21 as well, where you have the ANOH gas plant. If we start getting gas from there, the total quantum of energy that we are using for consumption will go more towards gas. However, we have to look at the fact that even gas has significant greenhouse gas emissions. We have to start replacing some of the gas to power and fossil fuels to power through refinery into more renewable sources.

That is why we started studying solar energy and these solar panels and we discovered that most of the manufacturing of photovoltaic cells, solar PV cells, were done in China. And we believe that whatever China has as a competitive advantage in Nigeria can provide it as well. We started working with some parties in the United States to see whether we can start solar PV manufacturing in the industrial park.

So part of the industrial park will have solar PV manufacturing so that slowly we can transit our gas business into a balance of gas and solar. Now we’ve also started doing some study communities solar assessments, so the power we want to deliver to the community could be a mix of solar and gas. But we’ve done the enumeration for solar first of all and we’ll take a look later on to see what it possibly means for gas.

But even in our facilities, with street light and things like that, we’ve started going away from using diesel power generators to using solar panels for electrification. So if you go to a facility, all the street lights are solar. So we’re testing this concepts as we move along because we know the transition will happen soon.


Who is in charge of Regulating Nigeria’s Crude Export Terminals?

By Macson Obojemuinmoin

Crude oil producing companies operating in Nigeria used to report to the Department of Petroleum Resources (DPR) to obtain export permit for the commodity.

Until the Petroleum Industry Act (PIA).

The overarching law of the Nigeran hydrocarbon sector, enacted in September 2021, created two regulatory agencies out of the DPR: the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) and the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA).

The legislation inadvertently authorised both agencies to be in charge of regulating crude oil export terminals.

Section 7EE of the PIA empowers the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) to:

  • Issue certificates of quality and quantity to exporters of crude oil, natural gas or petroleum products from integrated operations and crude oil export terminals established prior to the effective date and the commission shall have the power to monitor and regulate the operations of crude oil export terminals and the responsibility of weights and measures at the crude oil export terminals shall cease to exist from the effective date.

And Section 32ii of the PIA empowers the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA) to:

  • Issue certificates of quality and quantity to exporters of crude oil, LNG and Petroleum products.

These two clauses have created a conundrum. Which agency is the rightful authority to issue export permit?

“This issue was one among several that the PIA implementation team saw and pointed to both agencies in our interactions with them and they promised to resolve implementation via the presidential steering committee”, a ranking manager at an International Oil Company told Africa Oil+Gas Report.

The two agencies fought out the issue of export permit during the third quarter (Q3) 2022 permitting round as they both insisted on issuing the permits and actually did. “This points to serious implementation hiccups in the law than ever envisaged”, the manager said.

Operators had to apply to both agencies but after much haggling, paid the fees only to the downstream agency as operators refused to pay twice for same permit.

Some analysts have wondered how storage and export of crude which is produced through upstream operations be a midstream to downstream activity.

But the PIA also explicitly defined upstream operations as terminating at the crude oil production Platform, such that there is validity in the argument that the NMDPRA should be the agency to grant export permit to terminals.

Prior to the enactment of the PIA, permits were issued by the midstream and downstream divisions of the DPR, which constitute a significant part of the NMDPRA, but those permits were dependent on clearance by the upstream divisions of the DPR, where the technical allowable and proof of royalty payment were checked.

Even so, there are terminals and there are terminals. In the deepwater terrain, where about half of Nigeria’s crude oil output is delivered, the FPSO is both the production facility and the terminal. In several shallow water fields, the FSO or a Production Platform, is effectively the terminal. From most onshore (and swamp) fields however, the commodity is transported to terminals at the edge of the Atlantic.

Based on this geography of supply, the Minister of Petroleum and the deep divisions, the Minister of Petroleum has directed that the NUPRC will issue permits for export from deepwater as well as those shallow water assets for which their FSO or Production Platform sere as their terminals.

But some still kick against the Minister’s directive, in private, arguing that “dual regulatory powers” are not the intent of the PIA.

“Segregation clauses are meant to resolve the matter but segregation is not immediate”, a Nigerian owned operating company staff explained to Africa Oil+Gas Report. “From late 2021 to end of the 2nd Quarter 2022, operators were taking export permit from NUPRC but this was probably because NMDPRA was still finding its feet then as NUPRC was able to take off more effectively because it took over most of the structure and activities of DPR”.

The PIA is not a straight forward document the makers thought it is and so much unforeseen issues have come up and are coming up.

“Some of the segregation clauses were written by those who are not industry practitioners and operators seem to have paid more attention to the fiscal clauses in their advocacy such that there are several confusions in the operations clauses”, several analysts say.

So, what should be the way forward?

Everyone seems to agree that poor drafting is the big issue and this is clearly one area where some amendment will help.

“A literal reading of  the provisions of section 7 of the PIA would suggest  that the NUPRC remains responsible for any existing terminal”, says Adeoye Adefulu, Managing Partner at Odujinrin & Adefulu, a full service commercial law firm, “the NMDPRA would only be allowed to supervise the terminals which are established afterwards”.

In the long run, however “to address the conflict on regulations between the two regulators, the PIA needs to be amended to ensure that the full upstream value chain from acreage management to crude oil export is regulated by the upstream regulator while the midstream regulator is focused on midstream and downstream”, argues an asset manager at one of the International Oil Companies, who has had oversight function on regulatory permits. “In the interim until PIA is amended”, he argues, “the minister of petroleum/ President should issue a policy directive to effect the change”.


TOTAL Starts First Oilfield Development on Angola’s Block 17/06

French major TOTALEnergies has announced the final investment decision for Begonia, the first development on block 17/06, located 150 kilometres off the Angolan coast, in agreement with concession holder Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG) and its partners on Block 17/06.

The Begonia development consists of five wells tied back to the Pazflor FPSO (floating production, storage and offloading unit), already in operation on Block 17. After commissioning, expected in late 2024, it will add 30,000 barrels a day to the FPSO’s production.

After CLOV Phase 3, another satellite project that produces 30,000 barrels a day and was launched on Block 17 in June 2022, Begonia is the second TOTALEnergies-operated project in Angola to use a standardized subsea production system, saving up to 20% on costs and shortening lead times for equipment delivery.

The project represents an investment of $850Million and 1.3Million man-hours of work, 70% of which will be carried out in Angola, the company says in a release.


Angola’s Oil Revenues Rise, Crimp China Debt by 2%

Angola’s revenues rose from $1.4Billion in April 2022 to $2.1Billion in May 2022, the government data says, owing to the doubling of crude prices compared with 2021.

Payments to Chinese creditors began in the first quarter of the year, 18 months ahead of schedule, as the suspension of debt service meant that payments would only resume at the end of the first half of 2023.

Angola’s debt to China fell by $351Million in the first quarter, to $21.4Billion, according to data from REDD Intelligence.

Angola’s debt to China, estimated at 40% of registered external debt, is mostly derived from loans contracted with Chinese banks, especially Exim Bank and BDC, in the view of Africa Monitor Intelligence,

Angola ´s debt to Chinese creditors had threatened to reach $22Billion between 4th Quarter 2019 and 4th Quarter 2021, but the Angolan Government had vowed to start bringing it down and now it is doing so.

Chinese loans, which represent about a third of Beijing’s claims on all African countries, were essentially intended to finance infrastructure projects (construction or reconstruction) and others, of an industrial nature.

Under a mechanism called “Angola Mode”, Angolan oil supplies, carried out under special price conditions, are intended to pay off Chinese investments in these projects.

Standard Bank: Big Lender in Uganda, Small Player in Oilfield Project

Standard Bank is the largest lender in Uganda.

The Bank had been keen to be a part of the funding for the country’s basin wide oil development project

But, under pressure by activist shareholders and environmentalist groups to desist from funding fossil fuel development, the Johannesburg headquartered Bank has thrown its hands in the air, explaining that the project does not depend on its participation.

“While we are the biggest lender in Uganda, we are such a small player in the $10Billion project that if Standard Bank does not participate, the project can still be funded by more well-heeled financial firms”, the company’s management sources say.

TOTALEnergies, the project leader, declared in a release after the Final Investment Decision (FID) on the project in early February 2022, that the FID was in line with the company’s “strategy of only approving new projects if they are low-cost and low emissions”. In particular, TOTALEnergirs said, “the design of the facilities incorporates several measures to limit greenhouse gas emissions well below 20 kg CO2eq/boe, including the extraction of Liquefied Petroleum Gas for use in regional markets as a substitute for burning biomass, and the solarization of the EACOP pipeline”.

The French major’s emission numbers stand in stark contradiction to the figures thrown up by groups like Just Share, which says the pipeline would pump enough oil to generate up to 34.3Million tonnes of carbon dioxide – about seven times the emissions of Uganda and Tanzania combined. It’s not clear whose numbers are correct, but TOTALEnergies has not lamented scarcity of funding for the project and it continues to announce first oil in Uganda by 2026.

South African banks like ABSA, Nedbank and Investec have been scared away from oilfield development projects by the loud protestations of such groups.


OML 11 is the Biggest Asset in NPDC’s Portfolio

The Oil Mining Lease OML 11, novated to the Nigerian Petroleum Development Company NPDC by the parent company Nigerian National Petroleum Corporation (NNPC), is considered the largest asset, in value terms, in the portfolio of NPDC, in the opinion of several members of the company’s management.

“It has over 11 flowstations and the Ogoni Bodo field is largely untapped, NPDC managers say.

The export terminal for the crude is at Bonny, although Shell didn’t agree that the terminal is part of the OML 11 asset. At $3.5Billion, the value of investment committed to, in the Finance and Technical Service Agreement (FTSA) is the highest of the three FTSAs….Click here to read full article

TOTAL: First Oil in Uganda in 2025, First Gas in Mozambique in 2026

TOTALEnergies has announced the proposed dates for commissioning of its two ongoing hydrocarbon field development projects in East Africa.

The company’s Tilenga project, which monetises a cluster of onshore fields the company is developing in Uganda, is expected to reach first oil by 2025, according to TOTALEnergies Strategy Outlook 2021. The French major does not say there are any complications in delivering the project which, along with CNOOC’s Kingfisher field development, is a 230,000Barrels of Oil Per Day (BOPD) project, ferried to the Indian Ocean though a 1,400km pipeline.  TOTALEnergies notes, however, that the entirely onshore project is delivered in a sensitive environmental context and with a significant land acquisition programme.

In Mozambique, the French Supermajor has postponed the likely date for the first cargo of Liquefied Natural Gas expected from the Area 1 project from 2024 to 2026. The company does not say anything about insurgent attacks, which, primarily, was the reason for the setback.


Massive Production Drop in Nigeria’s Western Onshore

Crude Oil output crashed to significant lows in five acreages held by Nigerian independents in the western onshore Niger Delta, in August 2021, according to field data seen by Africa Oil+Gas Report.

These acreages, operated as Joint Ventures with state oil firm NPDC, produce the bulk of the hydrocarbons in Nigeria’s western onshore as well as most of the natural gas for the country’s electricity supply.

NPDC/Neconde’s OML 42 output fell to 23,000 Barrels of Oil Per Day (BOPD), from 38,669BOPD averaged in July 2021.

NPDC/NDWestern JV grossed…Read more




NIGERIA: The Big Asset Sale Season

Nigeria is back in a big asset sale season.

This is like mid- 2013 all over again, a half-year after RoyalDutch Shell completed a significant asset sale and was about to conduct another. But this time, the scale is humongous, and the above headline is closer to the narrative than it was when we ran it in 2013.

Our latest edition, just released to our global pool of paying subscribers, covers the asset sale with full disclosure.

Shell is about to sell acreages. ExxonMobil is in the midst of selling and Chevron has almost concluded a sale.

But again, the really big disposer is RoyalDutch Shell.

When the European major concludes the imminent sale of its equity in 18 joint venture assets in Nigeria, it will be left with just one operated acreage and two non-operated assets, all of them in deepwater. Midstream, it will still hold the largest non-state share in the NLNG plant, but it will no longer be in direct control of the feedstock.  The company whose name was, for most of the last 65 years, synonymous with the phrase ‘Nigerian Oil industry’, will have retreated into the background.

In our last monthly edition, released in mid-July, 2021, we explored the likely beneficiaries of these sales. We have updated the analysis in this edition.  In that issue, we worried about the impairment to the state coffers and debated whether the overall divestment picture was a good or bad sign, on balance to the fiscus. In this edition, we ask, why is the state company deeply concerned about this sale?

Elsewhere in the magazine, our regulars are of course included: who is getting to first oil; who is drilling what and where? Where in Africa is gas being commercialized and how can our subscribers benefit from such opportunity? Where else is opening up and what are the new technologies?

The Africa Oil+Gas Report  is the primer of the hydrocarbon and the growing new energy industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions, for useful analyses of Africa’s oil and gas industry. Published by the Festac News Press Limited since November 2001, AOGR is a monthly, publication delivered to subscribers around the world. Its website remains and the contact email address is Contact telephone numbers in our West African regional headquarters in Lagos are +2348038882629, +2348036525979, +2347062420127, +2348023902519.



South Africa Sprouts New Shoots

In the last five years, several E&P companies, primarily owned by South Africans, have left the upstream market, such that it is tempting to declare the end of the growth of South African E&Pindependents. 

JSE listed SacOil, badly burned by its dealings in Nigeria with local partners Transcorp and NigDel, has turned into a downstream company and changed its name to Efora. 

Thombo Petroleum, owned by Trevor Ridley, former Petroleum Advisor at BHP Billiton, disappeared into the folds of Canadian owned Africa Energy Corp.

But apart from Sasol Exploration and Production International, which is the most visible and best resourced South African bornE&P company, there are a number of companies to consider:

JSE and ASX listed Renergen describes itself as an integrated alternative and renewable energy business that invests in early-tage alternative energy projects.

But it started its project life six years ago by acquiring an onshore natural gas acreage from Molopo South Africa Exploration and Production. Renergen holds the first, and currently only, onshore petroleum production right in South Africa. 

Several homegrown independent South African companies, including Tshipise Energy (Pty) and Sungu Sungu Petroleum, are exploring for natural gas, in coal beds, in the Karoo and offshore Orange Basin, but their distance to development is, at best, far off. 

Renergen is the only one pumping natural gas from subsurface reservoirs into the local market. It has been supplying compressed natural gas to transportation companies since May 2016.

South African National Petroleum Company (formerly PetroSA), the only other natural gas producer in the country, is a state-owned enterprise.

Renergen is working on ramping up production from its acreage, which holds an estimated 142Billion standard cubic feet of proven and probable reserves, near Virginia, about 300km southwest of Johannesburg. It has moved intoliquefied natural gas (LNG) production, “primarily serving the growing domestic heavy duty truck market across Africa and emerging markets”, it says. Renergen has signed an offtake agreement with South African Breweries (SAB) for the supply of liquefied natural gas to power its delivery trucks. For this project, it initially rolled out compressed natural gas to a small fleet of SAB trucks in Gauteng, the country’s major commercial province.

A POTENTIAL STAR IN THE SOUTH AFRICAN E&PFIRMAMENT is Sunbird, a gas explorer and developer which owns a 76% interest in the Ibhubesi Gas Project, Block 2A, offshore of the west coast of South Africa and is the operator of the block. The company was originally owned by Australians, and was sold to South Africans in 2016. The Ibhubesi Gas Project is the country’s largest, undeveloped gas discovery, in the opinion of Sunbird and the local media. Theindependently certified gas reserves are 540 Bcf (2P) with “best estimate” prospectivity of close to 8 Tcf of gas, according to the company. The immediate focus of the project is provision of gas to the Ankerlig Power Station, an 11 year old, 1,338MW capacity thermal plant, designed to be fired by natural gas, but instead, utilizing expensive diesel fuel.Sunbird’s JV partner PetroSA, holds the remaining 24% in Ibhubesi.

Sunbird, for now, remains no more than a potential.

Five years after the Department of Environmental Affairs (DEA) issued an Environmental Authorisation (EA) for the project, the company is not anywhere close to concluding the gas sales negotiations with Eskom, the South African state power utility which owns the Ankerlig power plant. Nor is Sunbird seen to be progressing any deal to sell gas for industrial uses like Renergen is doing.  

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