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‘Nigeria’s Regulatory System “Sat on” the Gas Flare Out Programme’

Gbite Adeniji, Managing Partner at ENR Advisory, is a specialist with expertise in policy, regulatory and commercial issues in the energy, natural resources and infrastructure sectors. He was, between 2015 and 2018, the Senior Technical Adviser (Upstream and Gas Policy and Regulation) to the Nigerian Minister of State for Petroleum Resources, in which role he advised and provided direct support to the Minister on policy development, governance, regulation and reform of the petroleum sector. He led the preparation of the National Gas Policy and the National Petroleum Policy among other reform deliverables. In a wide ranging interview with the Africa Oil+Gas Report, he fielded questions on the entire spectrum of the energy industry, the highlights of which include: opportunities in the midstream infrastructure, challenges of low domestic offtake of natural gas; the heavy subsidy of gasoline (PMS) importation, mitigating the poor finances of the Bulk Electricity Trader, conundrum of price fixing in the natural gas market and all through the conversation, he kept repeating the warning: “there are 13 years left for Nigeria to make the most of its fossil fuel resources, achieve domestic industrialization on the back of those resources, ensure power sector growth and start making foreign currency reserve gains…


AOGR: How Challenging, or exciting, do you find the Nigerian energy sector?

ADENIJI: The first point is that Nigeria is expending 1.2Trillion Naira per annum on gasoline (PMS) subsidy. But you have to question whether that is the correct policy choice. We have an economy waiting to accelerate, if you just direct money to proper places. Left to me, I’d take the money from PMS subsidy and move it to the power sector where we are more likely to have wider economic impact. This is where the focus should be, not on PMS. As it is, many of us have more than two cars. We are the people that are being subsidised.

So, We Might as Well Subsidise the Power Sector?

Not quite. Let me explain.

70% of the demand for gas is from the power sector where most of the power plants are owned by government. There’s a bulk electricity trader (NBET) that buys most of the power that is produced. It has no balance sheet of note. Therefore, it is not an effective purchaser of power, which also means it is not an effective purchaser of gas. As you know, gas is an input for power production.

The Bulk Trader takes power that is produced with gas, but is always delaying payment. You certainly cannot run a utility business that way. So, the NBET’s weak balance sheet affects the natural gas sector. If you were a gas asset owner, and you are presented with a power sector offtaker and you know that most of that power is not paid for, what position would your directors take on such a transaction? What do you think your lenders will be saying? You simply cannot sell gas to an impecunious offtaker. It’s just not a bankable project if your offtaker is not bankable.

So why doesn’t the Government put some of this subsidy money behind NBET? As you start producing more power, the economy starts growing. The purchasing power of these poor people that you say you’re helping will gradually start increasing as you produce more power. That’s how you build a market for natural gas.

You mentioned a balance sheet?

Yes, you need to put that money right behind NBET to give it a strong balance sheet. You just cannot attract the right investments into the sector if you still present a bulk purchaser that doesn’t have a meaningful balance sheet. So, I would rather take the money that is going to PMS, and put it at NBET. You must of course understand the argument about putting money in development as opposed to consumption.

But that’s what they’re doing and NBET has been the one that they’ve been giving the money to, over two trillion naira.

It’s not enough. A policy choice was made to put NBET in the centre as a bulk purchaser. When you take that decision, you cannot now not back it up, because it’s central to the bankability of the chain.

That’s true. And it’s in the law, which you helped draft.

I didn’t draft the power sector reform, I just contributed to part of the debate.

My point is, where is all that money?

Let me contextualize it. NBET is the centre as the main purchaser of the power, which it sells to the DISCOs. Again, the decision was taken to privatise the DISCOs. The privatization was badly done clearly, because the DISCOs are not strong enough and the purchasers of the DISCOs also bought with a commitment to roll out meters within eighteen months. It’s been several years now and that hasn’t happened, which is why all this other damage is happening. Many things have happened wrong in the handling of the entire power sector reform. But what I’m just trying to illustrate is that proper funding of NBET is very important for the time being. You can then put more attention around the DISCOs because revenue collection through the metering programme is very, very, important. The more revenue you collect, the more fluid the power sector becomes and it becomes easier to pay those who have made the investment in gas and in power generation. So, the two areas of focus should be distribution and bulk purchase of power. Another area is transmission, which the Government also decided to retain ownership of but doesn’t seem to be able to fund adequately. However, I think that with consistent support from multilateral finance institutions, this issue will be resolved in the long run.

 But what happened to the Gas Flare Commercialization Programme that you championed when you were in Government?

Our regulatory system sat on it after I left.

The President made a very correct call when he went to Glasgow for COP 26 when he said that Nigeria cannot commit to Net Zero by 2050. But he had a low hanging fruit that would have made him look like a like a giant among all the global leaders at the summit, because he had signed the Natural Gas Flare (Prevention of Waste and Pollution) Regulations into law in 2017 to address the enormous waste of approximately 320Billion cubic feet of (Bcf) gas that is flared every year. This was a programme that Nigeria had presented to the world’s largest gas flaring nations at various fora in Paris, Baku, in  Azerbaijan and in Cairo in Egypt, and was acknowledged as the most advanced solution to gas flaring globally. Everyone was looking for Nigeria to lead on gas flare – out and were ready to follow.


Part of NPDC/NDWestern’s 320MMscf/d Utorogu Gas Plant: “The escrow account and aggregate gas price hard wired into the law, are potentially poison pills to investment and need to be removed, so that those who are going to invest in the upstream have more clarity regarding price. The next area is that requires clarity is the question of when the transitional pricing phase would end. As you just cannot have an indeterminable period of fixed pricing”.

In the Niger Delta onshore and shallow water, we identified 197 flare sites because every company was compelled to submit their data. Now let us assume that only 97 of the 197 sites are doable because some sites are so remote and therefore might not have immediate solutions. If there are 97 sites within the Niger Delta where people are investing millions of dollars in communities, you will first of all be able to address some environmental issues, but then also the social and economic activity or value from that that activity may change the Niger Delta story entirely.

But what do you have instead? You hear that we have a shortage of LPG in the country whereas most of that gas that is being flared and wasted contains a lot of valuable Natural Gas Liquids. A lot of that gas would have been captured and put into the domestic market to meet LPG and related gas shortages. Supply meeting demand keeps prices down, not so?

This was a scale thinking behind the gas flare commercialisation programme. It was not only an environmental programme, but it was also a multiple developmental impact programme.

Unfortunately, our regulatory system sat on it. They preferred to go out and licence marginal fields instead. Basically, this country took the wrong policy choice again. How does that make us look?

You have to wonder why Nigeria keeps taking the wrong decisions even when opportunity is staring it in the face?

That Conclusion Should Take Us to Discussion on Energy Transition and Industrialisation

Now, there is roughly 13 years left for the country to make the most of its fossil fuel resources, if we go by the energy transition plans of most industrialised nations which will impact demand, especially for crude oil. In those 13 years the country has to have achieved domestic industrialization on the back of those resources, ensured power sector growth and started making foreign currency reserve gains with gas-based products. The hard truth is that a lot of Nigeria’s future rests in the hands of the CEOs of the petroleum sector regulatory agencies. Basically, they have to understand how these things fit together and rise up to the challenge and drive everybody to achieve the most profitable outcome for the country. They don’t have to wait for any minister to steer the industry towards these economic imperatives. As regulators, they are already empowered by the law. The Petroleum Industry Act is powerful. I have dissected the law from several angles. The regulatory powers are clear and enforcement powers tighter than they have ever been.  These guys literally have to assume the toga of war, unlike previous regulators.

What’s your take on Nigeria’s pricing scheme for gas to power and gas to other products”

It’s interesting that you raised it. If you look at the PIA, it says there will be a transitional phase and a fully competitive market-led pricing phase. During the transitional phase, prices will be fixed. In fact, the exact wording is price control. So, the price for power will be derived from what we call a Base Price. So what’s the base price? No one actually knows because the law requires the regulator to go through a consultative process with stakeholders for that price to emerge. Whenever that price emerges it will be a fixed price. Then you add a topping on it every year to take account of inflation.

We’re not there yet at a particular price?

The legacy price will have to continue the consultative and determination process is completed. Now, when that price emerges, the gas aggregation process will kick in. So how that works is that every year the Nigerian Midstream and Downstream Petroleum Regulatory Authority will ascertain what the domestic gas demand requirement is from three strategic sectors: the power sector, the commercial sector, and the gas-based industries. It will then advise the Nigerian Upstream regulatory Commission to impose a domestic gas delivery obligation on all Lessees (holders of Oil Mining Licences) in respect of that ascertained demand.

The Commission will then take that demand requirement and spread the obligation around everybody. What the obligation really means is that you will deliver the gas to a location that the gas aggregator will determine. The concept that everyone should contribute towards gas supply into domestic economy is very good and important.

But where it breaks down is around the pricing. The price is fixed in the contract but you actually do not get that price. The law creates what we call an Escrow account which will be held with the aggregator where all payments due to a supplier will be paid by the purchaser of the gas. All the payments due for gas supplied under this scheme from the three strategic sectors go into these extra accounts and are blended to arrive at an aggregate price, so you’ll actually get paid an aggregate price. So, imagine that you are in the boardroom and your managing director requires the board to make an investment decision to produce gas to supply to let’s say the power sector. If the economics based on the base price show, say a price $2.50 per MillionBtu (roughly $2.5 per thousand standard cubic feet), but the directors become aware that the price in reality will be a different yet unascertained price, the board will likely not approve the project because they’ve got shareholders that they must account to. So they need to know the basis upon which they are making decisions and they also need to know what they are going to earn from the investment. In case the board falls asleep and says yes, you’re still going to end up with your lenders who are likely to be more alert and likely going to say sorry, they cannot lend you money based on an unknown or unquantifiable outcome.

So, gas supply based on the aggregate price concept is not bankable. Again, please put your mind to that 13 years that I mentioned earlier because the time is very short. Anything that gets in the way of a quick turnaround or a quick investment in the power sector growth, quick investment in domestic gas industrialization and quick development of the gas market opportunities, should go out of the law. In fairness to the law, it says that if you find someone who is ready to buy the gas on a willing buyer- willing seller basis, go ahead. So maybe some would take that window. If you find someone who can take the exact volume then you can be exempted from the domestic gas delivery obligation and you’ll be deemed to have complied basically. But if you don’t, then you will have to go through that process. So basically, they need to just clean that bit out of the law quickly.

You’ve been talking about power, the energy deficiency and the fact that people aren’t empowered to build an economy that will demand for power at the end of the day. A large complaint has been that the power tariffs haven’t been robust enough for investment. If you’re sitting across the table from power producers and talking with them, what would be your take? 

Remember the big error, just before the 2015 elections, when the tariffs were due for review and the government intervened with NERC and they could not proceed with the tariff review. That was an awful decision, because it sent a warning signal to the investment community. And it took a while for us to come to the point where tariffs were now reviewed. So, tariffs have been reviewed now to a point where recently, they are headed in the right direction and NERC is becoming more alive to its statutory obligations. Because the law is very clear. The law says when there is a major macroeconomic event, let’s say inflation goes beyond minimal level or there’s an FX devaluation, you must review the tariffs, because you must give those who have invested, the cost reflexivity. You can’t invest one way and then they just find that what they’ve been getting has been eroded by these macroeconomic events. So you’re supposed to adjust the tariffs to make them whole. That’s the law. So, what’s going to happen is that the tariffs have now been adjusted in continuance with these macroeconomic events. We’re not quite there yet but it’s going in that direction. And these are the things that will basically help bring more investment into the sector. It’s also important to ensure that there’s pressure put on DISCOs to roll out meters because you have to be able to collect the money. You’re actually collecting on behalf of the entire chain anyway, which is all the way to the gas sector really. So revenue collection is central to this equation. And that’s where the regulations on the petroleum side must have a good handshake with NERC because it’s an energy chain so they need to be able to work well together.

The Renewable Energy market has taken off from a low base and it is growing, though no in grid scale, in Nigeria. Are you concerned that it will eclipse the gas to power part of the electricity supply industry?

Well, the truth of the matter is that you need a mix.

So you’re not worried about possibly diminishing  investments in gas to power? When everybody in Ikoyi, V.I, and some of the most economically viable places in Kaduna, Kano, Awka and Onitsha, is looking to install renewables?

Firstly, the country has many energy-fuel sources, so we’ve got huge solar intensity in Northern Nigeria, which we need to tap, because it’s going to take a long time to get a gas pipeline carrying base load volumes into Northern Nigeria. And you may see that even when that happens, solar would still be cheaper than gas going through the pipeline to the north. Again, back to fuel-to-fuel competition. We also have two great rivers, Benue and Niger, of which there is a dam in one, Kanji, producing power, cheaper than even the gas for thermal plants.

So there’s a good mix?

There’re many rivers in the country and many dams we could have, producing power discreetly to certain areas that are stranded. Again, there’s the opportunity, with the virtual pipelines, the CNGs and the mini-LNGs to get gas into stranded areas and help respond to and further build up demand in those areas until when there could be a hard pipeline going there. So there are many possibilities here. So, different parts of the country are positioned for different types of energy solutions, so gas should not necessarily trump all. However, what’s great about gas is that it’s useful for industrial projects and also large power plants, particularly in the south. But there’s no reason why you shouldn’t have many solar projects up in northern Nigeria, large ones for that matter because of the solar intensity up there.

Can you respond to this challenge we hear from people all the time? Nigeria has abundant gas resources, but very few offtake transactions are happening at scale in country. Most of the announcements that Savannah Energy has made are about trickles: 10MMsf/d; 1MMscf/d, 5MMsf/d….  There’s a methanol plant that is penciled down for Bayelsa State. It’s planned gas requirement is about 350Million scf/d, the largest single domestic offtaker. But the FID is not yet in clear sight. What exactly is going on that outside the dysfunctional power sector, there is hardly a >100MMscf/d  offtaker, with the exception of Dangote and Eleme?

You really put your finger on some very concerning issues. The truth of the matter is that gas projects are incredibly difficult to implement. When you put the gas projects together, it’s like you’re putting together a jigsaw puzzle. There is such a mutual dependency of so many things in that chain, and they must work together in sync. If one aspect of these dependencies is off kilter, you don’t have a project. So let me put it this way. Fortunately, we don’t have resource issues in Nigeria as everything starts with the resource being available. But the other end of the equation in gas is the off-take. I illustrated to you that 70 percent of the demand for gas in Nigeria comes from one sector: the power sector, which must be a priority sector for any economy. So if you don’t sort out whatever the problems are in that major off-take sector, then you’ve got a problem and your gas resources may end up being stranded within that 13 year period. So that’s one. I also know that within the 13 year period, funds can gradually start drying up, so time is of the essence. But then also, major industrial plants can take large volumes in gas. So you mentioned the methanol project, yes that’s the second or third largest project being done since the Nigerian LNG project. So it’s a very important for the country.

Another is the Indorama (Eleme) fertilizer project which took off on the back of the initial petrochemical plant at Eleme. So when they went looking for money to do their fertilizer project, it was oversubscribed with 90 percent of the funding for that plant provided by lenders. That’s never been done in Nigeria before but it is because the borrower has a hugely successful petrochemicals business. That shows that sponsor capacity is very important because that’s important to lenders. Alas, most sponsors in Nigeria are weak and that’s why many gas projects just go into the graveyard. I have the experience of many of them. People wanting to do a lot of big interesting projects, but cannot even fund the development of that project. You should be open to bringing in other investors into your project as it makes it more likely to happen.

The brain desk at Egbin Power Station in the north of Lagos: “if you don’t sort out whatever the problems are in that major off-take sector, then you’ve got a problem and your gas resources may end up being stranded within the 13 year period ending 2035. So that’s one. I also know that within the 13 year period, funds can gradually start drying up, so time is of the essence”.

Again, we have a syndrome in Nigeria where investors like to hug everything. An example emerging today are upstream asset owners who want to control the midstream and downstream projects. You don’t necessarily have to do it that way. Someone else can more conveniently build the process plant so the CAPEX spend can be avoided by the upstream. You pay OPEX instead to process your gas and you can still retain the compounds that will come out of the processed gas. But there are hardly any tolling projects in Nigeria today because upstream investors aren’t as focused around capital efficiency in spite of the creation of a distinct midstream sector in the policy reform which allows third parties to invest purely in infrastructure. My point is that upstream people should be happy about putting their money into looking for oil or gas, finding it, producing it, and letting the midstream provide the service.

I have just one last question.


It’s in two parts. The first basically addresses your final line in your magical presentation in late 2021 at the Petroleum Club. You just mentioned midstream, with midstream gas and all that, and that has probably been the centerpiece of your legal career. But then you have a problem with two regulators, and the fact that even though you say now that policy reform in your time in government advocated for a separation in terms of projects, but you still consider it too expensive or cumbersome to have a regulator working in midstream and downstream, and another overseeing upstream. I would like you to respond to that. The second question is; what’s your solution to the gas pricing conundrum?

In the sector policy reforms that was accepted by the government, we advised that a single regulator be established for the petroleum sector because it is a petroleum chain. You produce resources, you either refine crude oil or you process gas, then you store, transport, and then utilise the resource. So, if you’re a regulator, it’s important that you have a full view of your regulatory field so that you don’t have what I call asymmetry of information. If you’re not seeing things fully then you take decisions based on only what you are aware of. Whereas if you are in full view of the chain, then you have what we call structural efficiency in regulation. But when you bifurcate it as they have wrongly done in the PIA, with a regulator with focus on the upstream, and another one focused on the midstream and downstream, then your focus will be limited to areas within your regulatory remit. That is another example of a policy choice taken by the Government notwithstanding its position in published policy.

Now, when you make such a choice, you have to be ready to address the inherent problems in such a structure, especially the regulatory gaps you will have between the upstream and the downstream or the potential clash of power in terms of environmental regulation, competition regulation and even in terms of agencies cooperating together. So you have to have a way of moderating the relationship between the two agencies. If the leaders of the agencies appreciate this problem well and they take up the challenge to work together, they would have served Nigeria well. This is because, the onset of any regulatory system is an inherently risky phase because the system is needs to settle. So typically, investors would ratehr wait and see how things work before they make big investments. So, the early signaling, because of the structural design issues which requires co-operation by the leadership of these two agencies is very important. They have to find a way of working together very quickly, and also calming their respective teams down so that they present a very unified image to existing stakeholders and even prospective ones.

As for the pricing of gas, it’s very important for the PIA to be amended. There are many areas of the PIA that need amendment due to the quality of the drafting and the resulting interpretation problems. But , to the substantive issue of pricing, it would really help the country given its need to take advantage of the direction of global energy policy. This escrow account and aggregate price hard wired into the law, are potentially  poison pills to investment and need to be removed, so that those who are going to invest in the upstream have more clarity regarding price. The next area is that requires clarity is the question of when the transitional pricing phase would end. As you just cannot have an indeterminable period of fixed pricing. You can’t stimulate investment and demand that way. We’ve seen that the market has been calling for competitive pricing, and a lot of people are ready to do willing buyer- willing seller gas supply. So you basically need to steer people in that direction with clarity around the sunset of the fixed pricing framework. We had that clarity in the National Gas Policy but the PIA has detracted from that position to something rather fuzzy.

NNPC seems to, even though it’s no longer the be-all and end-all of the Nigerian petroleum system, have a huge monopoly of the infrastructure. What do you have to say about that?

It still is.

Can people actually use the law to pry away from NNPC this power?

Savannah Energy’s Accugas infrastructure: “In fairness to the law, it says that if you find someone who is ready to buy the gas on a willing buyer- willing seller basis, go ahead. So maybe some would take that window. If you find someone who can take the exact volume then you can be exempted from the domestic gas delivery obligation and you’ll be deemed to have complied basically”.

Yes and no. The first thing to understand is that the PIA has protected NNPC such that nothing invasive has been done to the national oil company. In fact, the new one created out of the old one shed out its liabilities to create a liability-free entity with huge assets vested onto it. In terms of its power in the upstream, nothing is done there and it has a potential to be a very strong upstream entity because of the size of the assets vested onto it, but its governance is the big issue that must be addressed so that it can deliver on its promise. And that has implications for the 13 years. It’s the issue of how it will use those assets and how to drive crude oil or gas development, keeping an eye on the 2035 period, so that’s one. Then go to its infrastructure. Most of the infrastructure for gas assets in the sector belong to NNPC directly or indirectly. Indirectly because it’s a 60 or 55% interest owner in the JVs. So it has big control there. Also, it has its midstream subsidiary, NGC which controls most of the transmission system. In competition law that is a monopoly. Now, I’m trained in competition law, so I hasten to say that there’s nothing wrong with the monopoly per se; what is important is how you use your monopoly power. So, what the PIA has done is to open the space for other people to come and invest in infrastructure, but then you cannot duplicate infrastructure as that would offend against the waste doctrine. But there are other opportunities, for instance Ibadan is waiting to happen, so is the entire eastern Nigeria.

But Ibadan is under the franchise of NNPC?

The PIA doesn’t recognise franchise. Rather, the PIA vests sole power for determining entry into the midstream along with competition regulatory powers onto the Midstream and Downstream Petroleum Regulatory Authority, and not NNPC. There are eight midstream licenses, including transmission and transportation of gas and network operations. That’s all within the power of the regulator. So, NNPC may not determine who builds and operates gas pipelines to Ibadan, Enugu, or Nnewi. This position is very clear in the law.

What about the former Oando Gaslink, which is Axxela now? Was that not a franchise? What happens to it?

It was. If they want to transport gas, they should go and apply for a license. The law says you must make an economic case and show potential demand if you want a pipeline license. Once you make that case with the regulator, and meet up with the other conditions, you will get the license. So you don’t have to go to NGC to enter the midstream otherwise that would be anti-competitive.






Lazarus (Shell) Resurrected from the Dead?

By Gerard Kreeft

Was Shell’s second quarter results of 2022 a Lazarus moment?

The company announced adjusted earnings of $11.5Billion in the second quarter of 2022 and adjusted EBITDA (earnings before deduction of Interest, Tax and Amortisation) of $23.1Billion. Included in the figures was a post-tax net impairment of $4.3Billion. Translation: $4.3Billion previously identified as stranded assets is now seen as an energy asset that can be developed profitably.

The prestigious Dutch Financieele Dagblad (Financial Times) correctly asked whether Shell’s increased asset value is now positioning the company to do a takeover of a major renewable energy company? Or will it continue to plough more of its investments in fossil fuels? Shell’s last major investment was the takeover of British Gas in 2015 for $70Billion. With $100 per barrel of oil predicted for the short-to-medium term there is sufficient motivation to continue down the current hydrocarbon path and pay scant attention to even think about a dominant renewable energy future.

Yet Shell’s post-tax net impairment strategy has a precedent. In the summer of 2020, French oil and gas giant TOTALEnergies announced a $7Billion impairment charge for two Canadian oil sands projects. This might have seemed like an innocuous move, merely an acknowledgement that the projects hadn’t worked out as planned. However, it opened a Pandora’s box that would change the way the industry thinks about its core business model—and point the way toward a new path to financial success in the energy sector. While it wrote off some weak assets, it also did something else: TOTALEnergies began to sketch a blueprint for how to transition an oil company into an energy company.

The heart of the oil and gas industry is knowing how it measures its value: learning to understand the petroleum classification system, which provides the heartbeat of the industry. In the trade this is called the RRR (reserve replacement ratio), the annual amount of oil and gas reserves that a company must replace on an annual basis to maintain its portfolio.

The Paris Agreement of December 2015 was a sharp warning to the oil and gas industry that it was no longer business as usual.

But it was during the summer of 2020 that the seeds that eventually transformed the oil and gas industry, as we know it, were planted. Patrick Pouyanné, TOTALEnergies’ chairman and CEO, now says that by 2030 the company “will grow by one third, roughly from 3Million BOE/D (Barrels of Oil Equivalent per Day) to 4Million BOE/D, half from LNG, half from electricity, mainly from renewables.” (TOTALEnergies Strategies and Outlook Presentation, 9/30/2020,

This was the first time that any major energy company had translated its renewable energy portfolio into barrels of oil equivalent. So, at the same time that the company had slashed proven oil and gas from its books, it also added renewable power as a new form of reserves.

Each of the oil and gas majors spilled red ink in 2020, and most took significant write-downs, but TOTALEnergies’ oil sands impairments were different. The company wrote off reserves, or oil and gas that the company had previously deemed all but certain to be produced. Proven reserves long stood as the holy of holies for the oil industry’s finances—the key indicator of whether a company was prepared for the future. For decades, investors equated proven reserves with wealth and a harbinger of long-term profits.

Because reserves were so important, the reserve replacement ratio (RRR), the share of a company’s production that it replaced each year with new reserves, became a bellwether for oil company performance. The RRR metric was adopted by both the Society of Petroleum Engineers and the US Securities and Exchange Commission. An annual RRR of 100% became the norm.

Now Shell has concluded that because of high energy prices, its post-tax net impairment strategy—a role reversable—the company can reclaim a portion of its stranded assets. Will other companies follow? Will these claims lead to more investments in the oil and gas sector, or in renewable fuels?

 Explaining the Myths

Oil company vs Energy Company

The oil majors must face a significant paradigm shift: an oil and gas company becoming an energy company. Their previous strategy of high risk = high returns is being replaced by high risk = low/no returns. The real litmus test is the contrast between the performance of the share price of the oil majors and the Dow Jones Industrial Index: between January 2018 and June 2022 the Dow rose 23% (25,295 to 31,097) while the oil majors, with the exception of Equinor and Chevron, have under-performed dramatically. Shell, for example, in the five-year period January 5 2018–July 1 2022 has decreased 25% (from $69 in 2018 to $52 in June 2022).

Table 1: Stock market prices of  majors 2018-2022(NYSE)

Year Repsol       BP       Shell Eni Total


Chevron ExxonMobil Equinor
2018 $18 $43 $69 $35 $58 $128 $87 $23
2022 $13 $29 $53 $28 $49 $157 $88 $34

Note: Values based on  January  5 2018 and  June 30 2022

During this 5-year period the share price of the oil majors is as follows:

  • BP is down 32%
  • Repsol is down 28%
  • Shell is down 25%
  • Eni is down 20%
  • [1]TOTALEnergies is down 16 %
  • ExxonMobil remained flat
  • Chevron’s stock up 23%, and
  • Equinor up 48%.

By contrast, new energy companies—ENGIE, Enel, Iberdrola, Ørsted, RWE, and Vattenfall—all are low risk, and their dividends are competitive with the oil majors. Iberdrola had a 5% dividend in 2021, Enel provided a dividend yield of 6.6% in 2020, and ENGIE dividend yield 6.23% in 2021. Their stock prices are steady and positive. Their green strategy has been delivered in place and accepted by the investor community.

For new energy companies there is only good news: With the exception of Enel, the Italian power company has seen its share price remain flat and most of the major power companies have seen their share price increase, some very substantially. Engie, the large French energy giant, has seen its share price increase by 17%. Iberdrola, the Spanish power company has had an increase of 30%. The two big winners are RWE, the German utility giant, which has seen a stock price increase of 111%. Ørsted, the Danish power company which has seen its stock soar by 132%.

 Table 2: Stock market prices of new energy companies 2018-2022

Year Enel Engie Iberdrola Ørsted RWE  
2018 $5 $17 $7 $47 $18
2022 $5 $20 $10 $109 $38

Note: Values based on  January 5 2018 and June 30 2022

 Scope 3 Emissions

Under pressure from its shareholders and public opinion, Shell may be forced to move its zero emissions deadline forward to 2030 instead of 2050. At the AGM (Annual General Meeting)  in May 2022, shareholder climate resolutions did not carry the day but still is a major issue which the company cannot ignore.

Greenhouse gas emissions are categorised into three groups or ‘Scopes’ by the most widely-used international accounting tool, the Greenhouse Gas (GHG) Protocol. Scope 1 covers direct emissions from owned or controlled sources. Scope 2 covers indirect emissions from the generation of purchased electricity, steam, heating and cooling consumed by the reporting company.

Scope 3 includes all other indirect emissions that occur in a company’s value chain. Scope 3 emissions, most of the oil majors claim, are difficult if not impossible to control. Shell has on this basis argued that it can only react to client reactions and not predict or anticipate their reactions. This is why the court decision of May 2021 in the Netherlands ordering Shell to cut its CO2 emissions by 45% by 2030 compared to 2019 levels was a rude awakening to Shell management. Suddenly Scope 3 emissions have been declared a societal duty.

Shell’s Present Situation

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 with the $3Billion earmarked for marketing, $4Billion in integrated gas—its LNG arm, $4-5Billion in chemicals and products as well as $8Billion in upstream investments consisting of upstream exploration and production.

Shell must make some key strategic choices. The time for small incremental steps to meet the goals of the energy transition is over. Currently renewables and energy solutions account for only $2-$3Billion or approximately 10% of the company’s total expenditures

While its competitors—BP and TOTALEnergies—are busy buying and creating gigawatts of new energy, Shell maintains that it wants to focus on the value it generates for shareholders across the entire value chain. While the company is eager to proclaim value generation there is little indication to shareholders what this means. 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(read LNG) and chemical & products will receive 30-35% of  Shell’s capital outlay; and

Upstream will get 30-35%.

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

Will this strategy placate shareholder unrest?

Shell has a target to become a net-zero-emissions energy business by 2050. The company plans to transform its refinery footprint to five core energy and chemical parks, reducing the production of traditional fuels by 55% by 2030.

Does Shell’s goal for its energy and chemical parks fit within the verdict brought down by the Dutch courts that ordered Shell to cut its CO2 emissions by 45% by 2030 compared to 2019 levels? Is Shell still in charge of its energy transition scenarios or is it desperately playing catch-up to ensure that its influence and strategy has  an impact on the swiftly changing energy landscape?

In Shell’s latest energy scenario update, four conclusions are stated:

  • Energy needs will grow.
  • Energy systems will be transformed; speed is the issue.
  • Transformation will have costs and benefits.
  • Action accelerators are necessary to meet climate aspirations.

In its Sky 1.5 Scenario, Shell anticipates a rapid and deep electrification of the global economy, with growth dominated by renewable resources. Global demand for coal and oil will peak in the 2020s and natural gas in the 2030s. In the sectors that are more difficult to electrify, liquid and gaseous fuels will be progressively decarbonized through biofuels and hydrogen.

Shell’s energy prognosis is certainly in line with other sources who are sounding the alarm about global warming and the need for rapid decarbonization. But how will this affect Shell? Is the company nimble and dextrous enough to ensure it will be a force for good in the next phase of the energy transition? The signs are not encouraging.

In 2020 the IEEFA (Institute for Energy Economics and Financial Analysis) evaluated Shell’s green progress. According to Clark Butler, the author of the report, Shell must shift at least $10Billion per annum or 50% of its total capital expenditures from oil and gas and invest it in renewable energy if they are to reduce their carbon intensity in line with their stated goals.

Re-inventing Shell

How will Shell’s rebranding affect the company’s three major divisions—upstream, integrated gas, and downstream? Could Shell’s post-tax net impairment strategy be a smaller part of a major Shell renovation?  Not in the first place any takeover of any renewables company but a serious reallocation of its resources—both financial and technical. A Good Bank vs Bad Bank Scenario: Spinning off its huge Upstream Division to possibly merge with other upstream divisions; thus freeing up funding needed to transform its Integrated Gas and Downstream and Renewables Divisions for the energy transition.

Shell indicated that it would reduce its upstream division to nine core hubs—Permian, the Gulf of Mexico, United Kingdom, Kazakhstan, Nigeria, Oman, Malaysia, Brunei and Brazil– and it will do no frontier exploration after 2025. If the rush to the global exploration exit continues to pick up speed, Shell may well have to reconsider its upstream strategy, perhaps going so far as to spin off the upstream division as a separate entity or do a joint venture with other partners.

Shell’s integrated gas division, translated Shell’s LNG division which is the largest of the oil majors, could prove to be its star asset. For example, Wood Mackenzie’s AET-2 Scenario (Accelerated Energy Transition Scenario) predicts that in the following decades, market power will shift from OPEC to the giant gas producers, such as the USA, Russia, and Qatar.

According to AET-2, the “Era of carbon-neutral gas is born. AET-2 would require $300Billion to support Liquified Natural Gas growth globally and $700Billion to support dry gas development in North America.”  Given that Shell is the global leader of LNG (liquid natural gas)this is certainly a sweet sound for Shell’s LNG business.

Downstream could also prove to be a key energy transition asset. Shell’s REFHYNE Project, the Rhineland Refinery in Germany, could well become the precedent that the company needs to ensure it becomes the leading supplier of green hydrogen, where hydrogen production is powered by renewable energy for industrial and transport customers. Could the REFHYNE Project be duplicated many times over to ensure that green technology becomes a key ingredient in the energy transition?

Shell must make some key strategic choices. The time for small incremental steps to meet the goals of the energy transition is over. Currently renewables and energy solutions account for only $2-$3Billion or approximately 10% of the company’s total expenditures. Will Shell use its post-tax net impairment of $4.3Billion as a first step to drastically expanding its renewable energy division or will it be utilized to explore for more oil and gas?

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.  Gerard has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and contributes to IEEFA (Institute for Energy Economics and Financial Analysis). His book The 10 commandments of the Energy Transition is now on sale at  Bookstore

Our Latest Edition/PIPELINE ANNUAL 2022

Twelve 12 years ago, Transnet, the South African state-owned logistics company, was constructing a new, $1.5Billion, 715 kilometre long, multiproduct pipeline (MPP) to transport petrol, diesel and jet fuel from Durban, on the coast of the Indian Ocean, to Gauteng, in the north of the country, to replace the ageing Durban-to-Johannesburg fuel pipeline. The network, expected to have a life cycle spanning more than 70 years, was designed for a capacity of 1,000 cubic metres per hour (m3/h) when brought on stream, and could be scaled up to 3,000 m3/h through the addition of new pumpstations.

In Nigeria, around the same time, Shell, the UK major, was commissioning the Nembe Creek Trunk Line (NCTL), a 97 kilometre, 150,000 barrels of oil per day pipeline to receive and transport crude oil from over 15 oil fields in eastern Nigeria to the Bonny terminal on the Atlantic.

These two transmission lines have suffered significant vandalism, in the short time since their inauguration.

In Nigeria especially, the rule has become not to have a single crude evacuation route, if the primary route is through a pipeline.

But just because the risk of pipeline transport is growing does not mean that opportunity in Africa’s hydrocarbon pipeline space is necessarily diminishing. For every kilometre of line that is tampered with in Durban and Warri, there are three kilometres of new pipes being laid in Kabaale in Uganda and Western Desert in Egypt.

And while the focus is high on grid length lines which move fluids from production centres to demand nodes, there is a lot of opportunity in spur lines, in pigging, in maintenance and in integrity issues.

The pipeline story has been an integral part of our reporting in Africa Oil+Gas Report ‘s 21 years of publishing. It surprises even us that an annual edition had not been dedicated to Pipeline issues. With PIPELINE ANNUAL 2022, we are grabbing the opportunity.

Read your copy here.

The Africa Oil+Gas Report is the primer of the hydrocarbon 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 international corporations, local entrepreneurs, technical enterprises or financing institutions, for useful analyses of Africa’s oil and gas industry. It has been published by the Festac News Press Limited since November 2001, and, since the COVID -19 season, as a monthly digital (pdf) 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  +2347062420127, +2348036525979, +2348023902519.


‘African Officials Who Accepted Glencore’s Bribes Will Likely Walk Free’

There’s a growing call for prosecution of African officials who were part of ‘the elaborate corruption networks’ for which Glencore, the Swiss mining and commodities conglomerate, was fined by the United States Justice Department.

Five African countries were named as having been captured in the web of sleaze spun by Glencore on two continents between 2007 and 2018.

A drawn-out investigation involving law enforcement officials in Brazil, the United Kingdom, and the United States, led to two Glencore subsidiaries pleading guilty May 24, 2022 to “multiple charges of market manipulation and bribery, including corruption related to the company’s oil operations in Africa and South America”. Glencore’s penalties to the U.S. “for violating the U.S. Foreign Corrupt Practices Act (FCPA) and manipulating commodity prices” is approximately $1.2Billion.

In the time frame covered by the investigation, Glencore’s corrupt actions included more than $100Million in bribes to officials in Brazil, Cameroon, Côte d’Ivoire, Equatorial Guinea, Nigeria, South Sudan, and Venezuela, the report says.

“African officials who accepted bribes should be held accountable”, declares the African Energy Chamber (AEC), an influential energy advocacy group. “Glencore’s dealings in African countries should be closely examined on a local level. Investigations should be opened, and Glencore should be forced to come clean about the full extent of its corrupt business dealings”, the AEC argues.

In South Africa, Brian Molefe, former chief executive of Eskom, the electricity utility, has chosen to name names. He accuses the Zondo Commission, a panel of inquiry set up by the government to investigative state capture, of being “very sympathetic” towards Glencore over its relationship with President Cyril Ramaphosa. Although South Africa was not named in the investigation, President Ramaphosa was Glencore’s local empowerment partner at the time it acquired Optimum Coal Holdings in 2012, but divested his interests in Glencore in 2014.

In a report published as far back as July 2021, the Premium Times detailed court proceedings focused on how Anthony Stimler, former United Kingdom-based trader for Glencore Plc, bribed officials in Nigeria in exchange for favourable contracts from the Nigerian National Petroleum Corporation, NNPC. In effect Premium Times narrowed the Nigerian culprits in Glencore’s corrupt practices to officials working for the state hydrocarbon firm.

However, Musikilu Mojeed, the newspaper’s editor-in-chief, regrets that “no particular official was named or properly identified in court papers, so it is difficult identifying the officials involved”.

Nigerian authorities never responded to Premium Times report and they have been silent about the widely circulated 2022 account.

Mum too are the authorities in Cameroon, Côte d’Ivoire, Equatorial Guinea and South Sudan, which are the other African countries whose officials are implicated in the investigation.

African officials who accepted Glencore’s bribes will likely walk away free.

This piece was initially published in the May 2022 edition of Africa Oil+Gas Report

BW MaBoMo Starts Move to Gabon for 2023 First Oil

BW Energy has announced the sail away of the BW MaBoMo (formerly Hibiscus Alphaoffshore production facility.

The production facility is currently onboard a heavy-lift vessel in transit to the Dussafu license offshore Gabon where it will be installed to produce oil from the Hibiscus and Ruche fields.

The BW MaBoMo is expected to arrive on the field at the end of September 2022 for installation and hook-up with first oil planned late in the first quarter of 2023. The Hibiscus / Ruche development is expected to add up to 30,000 barrels per day of gross production once all the initial six horizontal production wells are on stream.

The platform left the Lamprell yard in Dubai on August 8, 2022, following completion of the yard scope with some minor outstanding upgrades, which were executed offshore in preparation for the sail away.  The BW MaBoMo is a former jack-up drilling rig which has been repurposed as an offshore production facility with 12 well slots. It will be connected to the BW Adolo FPSO via a 20 km pipeline.

“By repurposing existing oil and gas production assets we extend their economic lifespan, shorten the time to first oil while also significantly reducing the field development investments and CO2 footprint. We are very pleased to have completed the conversion project with excellent HSE results and only minor adjustments to schedule and budget in a highly challenging environment due to COVID-19, supply chain disturbances, geopolitical tension and commodity inflation,” said Carl K. Arnet, the CEO of BW Energy.


Warren Buffet’s Chevron Dilemma

By Gerard Kreeft

Warren Buffet, America’s most foremost and savvy investor, is a major Chevron investor. Berkshire Hathaway, his investment vehicle, owns 8.16% of Chevron, representing $23Billion. His foremost ability is owning stocks that have regular and high dividend returns. The Chevron dividend has for the last 35 years increased incrementally every year. No wonder that Buffet has become the symbol of blue chip stocks.

Is this about to change? Could Chevron give Buffet a black eye? This deserves a short explanation. Buffet has in the past been candid about how his early investments turned out to be duds. Berkshire Hathaway, as Buffet recalls, was originally highly involved in New England’s fading textile industry. Lessons learned from the textile industry have been a strong influence on Buffet’s investment strategy. Could Chevron go the way of the New England textile factories?

Two key factors play a role: Chevron’s lack of diversity of supply and logistically bringing Tengiz oil to the market place.

The Present Situation
Mike Wirth, Chevron’s Chairman and CEO recently revealed that two-thirds of Chevron’s total production of 3Million barrels of oil will, in 2025, come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States will each yield 1Million barrels of oil equivalent per day. Not exactly diversity of supply.

The company’s market cap is now $284Billion. Chevron’s positive image is largely because of its dividend track record: the company has increased dividend payouts for 35 consecutive years.

Chevron management, nonetheless, has suffered important setbacks at the company’s Annual General Meetings in both in 2021 and 2022. Over the objections of management, 61% of shareholders voted in 2021 for a proposal to encourage the US company to reduce its emissions. At the 2022 annual shareholders meeting 39% of shareholders voted for a resolution asking the company to provide quantitative information how a net zero by 2050 will affect key components of Chevron’s financial position, including potential impairments, remaining asset lives and asset retirement obligations.

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 budget. The company’s new energy division is focusing on the following areas:
• Renewable natural gas products;
• Renewable fuel products;
• Hydrogen production;
• Carbon capture and storage.
Will Chevron shareholders see Chevron’s new energy division as a new direction or mere symbolism? Certainly, Europe’s supermajors-BP, Shell, and TOTALEnergies-who have a dash of renewables, have seen their share prices remain stagnant. Is the alternative simply to follow the hydrocarbon route?

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. Putting so many of its eggs in the Tengiz basket could be a strategic vulnerability: if Tengiz output falls short, Chevron’s market performance will suffer, potentially dramatically.

The Caspian Region, particularly Kazakhstan, has been a key frontier for Chevron since the break-up of the Soviet Union. Tengiz, Kashagan and Karachaganak were all major projects taken on at great risk, but they garnished great financial wealth which in turn generated cashflow for the majors to develop projects around the globe, including Africa.

This is about to change. WoodMackenzie is predicting that, by 2030, annual capital spending on upstream oil and gas projects in the Caspian Region will drop 50% from it’s 2018 peak of $20Billion.

According to WoodMac most of the largest pre-FID (Final Investment Decisions), both brownfield and greenfield, do not generate an IRR(Internal Rate of Return) above 20%. Tax issues, cost overruns and project delays are key constraints. Add carbon neutrality to the mix and you have the ingredients for a perfect storm.

When the Soviet Union broke up in the early 90s and Kazakhstan emerged as a new oil province, Chevron was seen as an ambassador of US goodwill. Chevron’s prize was operatorship of Tengiz (50%) and ExxonMobil gained a 25% share. Chevron also has an 18% share in the large Karachaganak Gas Field.
What once was a sign of great wealth—Kazakhstan’s oil riches—could turn sour very quickly. Both Chevron and ExxonMobil, key developers of Kazakhstan’s prosperity, are also the two key oil majors lacking any serious decarbonization and energy transition plans. While this is most relevant for the Caspian, it is also a warning for Africa where both companies have major projects.

Expiry date for the Tengiz concession is 2033. What will happen then? Given the huge costs, highly sulfur-based oil and low chance of carbon neutrality, Tengiz could become a vast stranded asset. To date Shell has abandoned two Kashagan projects in Kazakhstan because of high costs. Tengiz was for most of its duration Chevron’s crown jewel, providing cash to developing assets elsewhere including Africa. Given Chevron’s current strategy it can only hope that Tengiz can continue to squeeze out more oil.

Caspian Pipeline Consortium (CPC)
An equally troubling problem is the Caspian Pipeline Consortium (CPC) which transports Caspian oil from Tengiz field to Novorossiysk-2 Marine Terminal, an export terminal at the Russian Black Sea port of Novorossiysk. The CPC pipeline handles almost all of Kazakhstan’s oil exports. In 2021 the pipeline exported up to 1.3Million barrels per day(BPD). On July 6, 2022 a Russian court ordered a 30-day suspension of the pipeline because of an oil spill. The CPC appealed the ruling and the suspension was lifted on 11 July of the following week, and the CPC was instead fined 200,000 rubles ($3,300). Also there have been unconfirmed reports that western service companies are refusing to provide repairs and spare parts, which could be seen violating sanctions against Russia.

The incident demonstrates the vulnerability of Tengiz and future production. No doubt this is not the last such incident which involves Russian and Kazakhstan goodwill to ensure that Chevron’s Tengiz Project does not falter. Having to depend on Russian-Kazakhstan goodwill to guarantee Tengiz production has put Chevron’s lack of diversity of oil supply in a very bad light.

Permian Basin
A final sour note for Buffet could be Chevron’s Permian Basin assets. What assurances do we have that Chevron’s Permian Basin adventure will fare better than that of past shale operators?

In a 2021 March report IEEFA (Institute for Energy Economics and Financial Analysis) found the 30 producers generated $1.8Billion in free cash flows in 2020 after slashing capital spending by $20Billion from the previous year.

“Last year’s positive free cash flows were only possible because shale companies cut their capital spending to the lowest level in more than a decade,” said Clark Williams-Derry, IEEFA energy finance analyst and co-author of the report. “Restraining capital spending could help the fracking sector generate cash, but low levels of investment also undermine the industry’s prospects for growth.”

Since 2010, the 30 companies examined by IEEFA had reported negative free cash flows totaling $158Billion.

“The positive free cash flows pale in comparison to the industry’s accumulated debt loads.”

The 30 shale producers owe almost $90Billion in long-term debt, and the reductions in capital expenditures are unlikely to ensure that the industry grows .

If Buffet is seen visiting Tengiz or the Permian Basin. investors should sit up and take notice. It will be, perhaps, an indication that much like the New England textile mills, all is not well in the land of Chevron.




Two Valve Assembly Plants, and a Pipe Threading Factory, On the Cards, in Nigeria


Bell Oil & Gas says it is looking forward to commissioning a multi-million-dollar, integrated facility, located at the Lekki Free Zone in the eastern flank of Lagos, Nigeria.

The facility is on a site with a total size of over 15,000 square metres, according to Kayode Thomas, the company’s CEO.

The first phase of the project “comprises state-of-the-art valve assembly, maintenance, testing, painting and production”, which will deliver “Made in Nigeria valves for the oil and gas industry”, Thomas explains.

The second phase of the facility is for piping, pipe threading, machining and production of pup joints, crossovers and accessories. Thomas says that commissioning is at hand. “The facility will also accommodate our composite pipe fabrication services as well as serve as a storage and logistics base for our entire operation”

Bell Oil & Gas is a Nigerian owned service company which produces, supplies, installs, commissions and maintains a range of composite pipes. It is involved in some of the country’s ongoing large E&P projects including TOTALEnergies’ Ikike oilfield development, Nigeria Liquefied Natural Gas (NLNG)’s Train 7 construction and the ANOH Gas Processing Company’s ANOH midstream gas processing project. It is looking forward to participate in such future projects as the Shell led Bonga Southwest/Aparo, a deepwater oil field project.

MEANWHILE, IN PORT HARCOURT, THE LARGEST CITY IN THE NIGER DELTA BASIN, Tag Energy says it will commence the construction of a 3,000 square feet factory for the design, production, and repair of valves of all types and sizes by the year 2025.

The company ordinarily does flange management services; providing solutions for bolting requirements, including torquing, tensioning, stress analysis, and joint integrity quality assurance and quality control (QA/QC), with services catering to “high-integrity sealing of flange joints at chemical plants, refineries and offshore installations, as well as general industrial sites”.

Tag also supplies, services and repairs valves, mostly in engineering facilities in the oil industry. As the company builds the manufacturing facility, it has taken charge, as part of its CSR, of training young people in the eastern Niger Delta at its new valve service centre in Port Harcourt. Tag will “offer paid internships to qualifying students to produce a steady stream of skilled resources for the industry, further reducing our dependence on foreigners for ongoing maintenance and support activities”, says Yemi Gbadamosi, the company’s Chief Executive


Senegal’s New Fortune Favours the Locals

Senegal’s Revised Petroleum Code has introduced a provision that goods and services that could be adequately fulfilled by the local private sector must include majority Senegalese ownership of such companies.

The new law calls for a partnership between an international firm and a local entity, maintaining local ownership of at least 5%, in projects in which the local private sector may lack the technical or financial capacity for.

And regarding goods and services which the local private sector is chronically incapable of providing, foreign entities can fulfill these specific industry requirements independently of local partners.

Local Content Development Fund

The Petroleum Code’s Decree 2021-248 of the Revised Petroleum Code formalizes the operations of a Local Content Development Fund under both the Ministry of Finance and Ministry of Petroleum and Energies, funded by levied fines and other budgetary appropriations. The fund’s objectives are to develop more robust local content development guidelines in partnership with private companies and to improve local capacity through technical training and support for SMEs. Chairing this and acting as enforcer for all local content decrees is the National Local Content Monitoring Committee (CNSCL) created by Decree 2020-2047 – a body with the objective of achieving a 50% local content ratio for Senegal by 2030.

The law mandates international oil companies to submit annual content plans outlining their use of local contractors, suppliers and service providers, and justifying any international preferences for the above in terms of lower price or superior standards. It instructs all oil and gas industry service providers and sub-contractors to open a local subsidiary in the country and to submit all tender bids through a centralized government platform.

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



BW Energy Reports High Production Cost in Gabon

The Norwegian junior, BW Energy has reported gross production from the Tortue field offshore Gabon, averaged approximately 10,700 barrels of oil per day in the second quarter of 2022, amounting to a total gross production of approximately 975,000 barrels of oil for the period and in line with expectations.

But a key data in the company’s operational update is that “production cost (excluding royalties) was approximately $35 per barrel”, in the subject quarter.

BW Energy does not go any length to explain the reason for such a high number, but it notes that “the overall production cost includes approximately $1Million related handling of the COVID 19 pandemic in the period.

“Second quarter revenue is expected to reflect approximately 32,500 barrels of quarterly Domestic Market Obligation (DMO) deliveries with an under-lift position of around 247,000 barrels at the end of the period”, the company explains.

There were no BW Energy liftings from the Gabon operations in the quarter.  “BW Energy had a cash balance of $123Million at 30 June 2022, compared to $111Million at 31 March 2022. The increase is due to the previously communicated April payment of $114Million for the Company’s March lifting, offset by continued investments in the Hibiscus / Ruche development project.

At the start of the period, the Company had commodity price hedges for a remaining total volume of 1.04Million barrels for 2022 and 2023, of which 37% is for 2022, BW Energy notes. “These were a combination of swaps and zero-cost collars that will allow for future cash flow stability for ongoing development projects. BW Energy has recognised unrealised crude oil hedge losses in the amount of $4.1Million for the second quarter”.

NNPC Gets a Court Injunction Against ExxonMobil Sale of its Nigerian Assets

A Federal High Court in Abuja has fixed, for July 15, 2022, the hearing of a motion against the sale of shares of ExxonMobil’s Nigerian unit to any third parties.

The court, presided over by Justice S. B. Belgore, had on July 6, 2022, granted an injunction sought by Nigerian National Petroleum Company (NNPC) Limited, restraining Mobil Producing Nigeria Ltd and Mobil Development Nigeria Plc from selling, trading, allocating, transferring, or disposing of their shares in their interests covered by or connected to the Joint Operating Agreement between them and the NNPC.

The order restrains “sale of assets covered in Oil Mining Lease 68, Oil Mining Lease 69, Oil Mining Lease 70 and Oil Prospecting Licence 94, to anybody, person (s), company, consortium or entity howsoever described pending the determination of the claimant/applicant’s motion filed on the 5th of July or when the judicial tribunal is duly constituted and can make interim preservation orders.”

NNPC has stepped up, in public, its determination to take over the subject ExxonMobil assets since Seplat Energy Plc, Nigeria’s largest homegrown, private sector led energy company, announced in February 2022, that it had entered into an agreement to acquire the entire share capital of Mobil Producing Nigeria Unlimited (“MPNU”) from Exxon Mobil Corporation, Delaware.

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