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Long Awaited: Nigeria’s OML 13 Reaches First Oil, Looks to Ramp Up to 40KBD

The Indian independent Sterling Exploration has reached first oil in the development of the Oil Mining Lease (OML) 13 onshore eastern Niger Delta.

The company has worked on the project in the context of a Financial and Technical Service Agreement (FTSA), signed with NNPC E&P Ltd (the company formerly known as NPDC), which holds the licence to the acreage.

An NNPC press statement says that production from OML 13, in which the main field is Utapate field, commenced on the 6th of May 2024 with 6,000 barrels of oil per day and is expected to be ramped up to 40,000 barrels per day by May 27th, 2024.

The statement adds that Sterling is working the asset through its subsidiary named Natural Oilfield Services Ltd (NOSL),

The development of OML 13 has been a long, drawn-out project.

When SEEPCO inked the FTSA with the then NPDC in June 2019, close to five years ago, a statement by the NNPC said that the Indian operator, the only non-indigenous independent oil producer operating an asset  in Nigeria, would pump $3.15Billion  to drain the recoverable portion of the 926Million stock tank barrels (MMSTB) and 5.24Trillion cubic feet (Tcf) respectively of oil and gas reserves in place, over a period of 15 years.

First oil of about 7,900BOPD was expected from the project by 1st April, 2020, while production is expected to peak at 94,000BOPD and 542Million standard cubic feet a day (542MMscf/d) within four years, the NNPC statement added.

The terms of the deal was that the $3.15Billion, described as the “ceiling funding”, came with a 10-year capital investment period and five years for cost recovery.

But none of the details of the project, financial or non-financial, have shown up in any of the NNPC annual reports since 2020.

Gas, Is this related?

A week ago, NNPC released a press statement announcing three gas projects expected to be commissioned by President Bola Tinubu. One of those projects  is named AHL Gas Processing Plant 2 (GPP – 2) – which is supposed to deliver 200MMscf/d. “It is an expansion of the Kwale Gas Processing Plant (GPP -1), and will deliver lean gas through the OB3 Gas Pipeline, supporting Nigeria’s industrialization”, NNPC’s statement said. The AHL Processing plant 2 is also expected “to produce 160,000 MTPA of Propane and 100,000 MTPA of Butane, reducing dependency on LPG imports”, the press release added. 

 

 

 


Invictus Signs a Second Gas to Power MoU from Untested Zimbabwean Asset

MoUs are statements of wishes and the company still has to prove economic commerciality of the Mukuyu wells with flow rates…

Australian minnow, Invictus Energy, has signed a second Memorandum of Understanding for sale of gas from its hydrocarbon asset onshore Zimbabwe.

The deal to provide natural gas for a 50MW Gas-to-power project for Eureka Mine, one of Zimbabwe’s largest gold mines, comes three months after an updated MoU with expanded mandate was signed for Mbuyu Energy, a Zimbabwean consortium led by IPP developer Tatanga Energy, a deal which envisages delivery of up to 1,000MW of electricity, if consummated, “with demand for an estimated 1.4Trillion cubic feet of natural gas”, Invictus claims.

Invictus says it finished 2023 by declaring dual discoveries during in its Mukuyu-2 drilling campaign, in what it described as a transformative year for the Company and its shareholders.

But MoUs are more of statements of wishes and Invictus still has to prove economic commerciality of the Mukuyu wells by running Drill Stem Tests (DSTs) which will show flow rates and the deliverability of the reservoirs.

Invictus  has signaled it is awaiting Petroleum Production Share Agreement (PPSA) with the Republic of Zimbabwe,  and has been engaging the responsible cabinet level Ministers, but its recent statements also indicate there’s much more to be done to reach commerciality: “The upcoming working programme includes a well test at Mukuyu-2, preparation for three dimensional (3D) seismic over the Mukuyu gas field and preparing long lead items for a new high impact exploration well, the location of which will be determined following full interpretation of the acquired CB23 infill seismic survey programme”..

 


Edwin Is Back in Full Charge of Dangote Refinery, Alake Will Oversee “The Rest”

Aliko Dangote has reorganized his company’s top executive management, following the completion and commissioning of the mammoth Dangote Refinery, Fertiliser and Petrochemical complex, located on the eastern flank of Lagos, Nigeria’s financial city.

In the event, Devakumar Edwin has assumed responsibility as Vice President for Oil and Gas. including the Refinery, Fertilizer, Petrochemicals and Upstream businesses.

The Nigerian engineer and accountant Olakunle Alake, who as the Dangote Group’s Chief Operating Officer, had a line of sight to the group’s entire operations, has assumed “responsibility as Vice President for all the businesses in the Group “excluding the Oil & Gas business”. Mr. Alake continues to be responsible for the Group Finance and audit function.

Edwin stepped a little back from full charge of the complex when construction was in full steam, as Guiseppe Surace, the former SAIPEM Nigeria CEO, took over as COO of the plant, and led the construction. Surace left in February to run his own firm. .

Dangote’s appointment of Edwin to take full charge of the complex is  a vote of confidence on the man who has “seen it all with him”.

The Group Human Resource, Commercial Businesses and Legal  Departments now report directly to the President/Chief Executive Aliko Dangote himself, “in view of the strategic priority of attracting and managing the leadership team”, a company statement notes. Group IT (Information Technology), meanwhile, reports to Group Strategy.

Mr. Dangote says in the statement that “with the successful commissioning and coming into operation of our refinery, fertiliser and petrochemicals plant, we have successfully created a $30Billion conglomerate The Dangote Group is now positioned to become one of the top 200 global companies and the largest industrial Group in Africa”.

 

 

 

 

 


ReconAfrica to Spud its Second Seismically Defined Well Onshore Namibia

Canadian minnow, ReconAfrica is returning to the rig site in the Kavango Basin in the north of Namibia, 18 months after the furore that greeted its first seismically defined well in the country’s onshore.

The Company expects to begin drilling Naingopo (Prospect L), in June 2024, “targeting 163Million barrels of unrisked prospective oil resources or 843billion cubic feet of unrisked prospective natural gas resources based on the most recent prospective resources report prepared by Netherland, Sewell & Associates, Inc. (NSAI) dated March 12, 2024”, the company notes in a statement.

ReconAfrica’s primary target is no longer the prospects in the so-called Karoo rift, but now the Damara Fold Belt, the company explains.

Construction of the well pad and access roads have commenced and ReconAfrica has shared its drilling programme and future drilling and subsurface data acquisition plans with its partner, the state hydrocarbon company NAMCOR and the Ministry of Mines and Energy

The Toronto listed explorer, in 2021, drilled two stratigraphic test wells in the Kavango Basin, at the time described by the Canadian geologist Tako Koning, as “an unregarded sedimentary basin”.  The 6-1 and 6-2 wells, the company reported, intersected over 300 metres and 200metres of oil and gas shows respectively. ReconAfrica did not call any of these a discovery. Indeed, it stated clearly that “the two wells were drilled to provide stratigraphic, sedimentological, reservoir and geochemical information”.  Although the data in both probes was very positive, neither 6-1 nor 6-2 was tested since they were designed to be only stratigraphic wells.

Makandina 8-2, drilled in late 2022, was ReconAfrica’s third well in the basin. It was the company’s first seismically defined probe in the campaign. It failed to encounter economic accumulations of hydrocarbons. The company placed the blame on the absence of a trap or a four-way dip closure. A lot of condemnation ensued, with some media reports cynically questioning the company’s claim that it had proven a working hydrocarbon system in the basin.

The next well is expected to drill to a depth of approximately 12,500 feet or 3,800 metres and is projected to encounter four primary reservoir intervals targeting both oil and natural gas.

Following the drilling of the Naingopo well, ReconAfrica is planning to drill a second Damara Fold Belt well, Prospect P, targeting 278Mllion barrels of unrisked prospective oil resources, or 1.5Trillion cubic feet of unrisked prospective natural gas resources, based on the NSAI Report.

Drilling of the second Damara Fold Belt well is expected to commence in the fourth quarter of 2024, subject to the results of the Naingopo well.


Opec To Participate At Iae 2024, Outlining Future Of Africa’s Energy Industry

 PARTNER CONTENT

OPEC Director of Research Dr. Ayed S. Al-Qahtani will deliver a keynote address at the upcoming Invest in African Energy (IAE) 2024 forum in Paris, affirming the importance of African oil supplies in global affairs.

Home to six OPEC member countries, the African continent is playing a growing role in global supply discussions, accounting for a rising percentage of OPEC-led production. Libya and Nigeria represent Africa’s two largest producers – according to OPEC’s latest monthly oil report – both producing approximately 1.2 million barrels per day (bpd). While Angola left the organization at the end of last year, OPEC is said to be in talks with Namibia – which could be Africa’s fourth-largest producer by 2030, on the back of prolific offshore discoveries – and other African nations that represent the next generation of African oil production.

IAE 2024 is an exclusive forum designed to facilitate investment between African energy markets and global investors. Taking place May 14-15, 2024 in Paris, the event offers delegates two days of intensive engagement with industry experts, project developers, investors and policymakers. For more information, please visit www.invest-africa-energy.com. To sponsor or participate as a delegate, please contact sales@energycapitalpower.com.

Consisting of 22 nations, OPEC and its allies have been committed to maintaining oil supply cuts to boost barrel prices amid economic uncertainty. The alliance has implemented cuts of more than five million bpd since the end of 2022 and is extending voluntary cuts of 2.2 million bpd into mid-2024. The IAE forum will feature technical discussions around Africa’s oil outlook, exploring supply, demand and price forecasts based on various energy transition scenarios.

“IAE 2024 welcomes the participation of OPEC in leading critical supply discussions, as African producers seek to incentivize new exploration and develop recent offshore discoveries. The forum will share high-level insights into current and future efforts to ensure market stability, as well as highlight Africa’s growing influence on the global energy stage and the importance of African solidarity,” says Sandra Jeque, Event & Project Director at forum organizers, Energy Capital & Power.


Waltersmith Plans an Oil Terminal to Export Fuel Oil: “Our Expanding Refinery Has Brought So Much Value”

Waltersmith Petroman’s inability to export its crude oil output out of the country in the last 18 months, as a result of the outage of the Trans Niger Pipeline (TNP), has not precluded its access to earning foreign exchange from its Ibigwe field.

 The Nigerian independent pumps its entire 2,500Barrels of Oil Per Day into its 5,000Barrels Per Stream Day (BPSD) refinery, producing diesel, naphtha, heavy fuel oil, and kerosene. Seplat supplies the rest of the crude from its Ohaji South field.

 “50% of the fuel oil produced is exported out of the country”, Abdulrazaq Isa, the company’s Group CEO, told Africa Oil+Gas Report.

Now Waltersmith wants to explore this business opportunity further by installing an oil terminal in Port Harcourt closer to the coast. Currently, it sells the fuel oil at the gate of the refinery in Ibigwe, which is far in the hinterland. With the establishment of the terminal, however, it will truck the product from Ibigwe to the terminal, where offtake vessels from companies like Shell Trading and LITASCO will pick it up for export. “We want to control the delivery from end to end”, Isa told our team.

Excerpts of the second part of the interview, in our C-SUITE series, already published in our February 2024 pdf edition, by AKPELU PAUL KELECHI

Waltersmith started primarily as a crude oil producer but now that you are into refinery as well, has anything changed?

No and as you can see, since I came back, we have restructured the company to get it focused. We have now determined that we want to emerge as an industrial company. Value addition is going to be a key focus area for us. Oil and gas are our raw materials.

Going forward, for every crude that we produce, we want to add value to it and for any gas that we produce and or receive, we want to add value to it as well. We are going to do both simultaneously; we are going to continue to grow our E&P business. Waltersmith Petroman Oil, which is our core company, would continue to focus on oil exploration and production. Once all of this is done, we have Ibigwe now, Assa, and we are also part of ND Western. We will have our operated assets and we also have significant non-operated assets.

“BP’s faltering vision, its downward share price and its low valuation—some $100Billion–makes the company a vulnerable takeover prey”

The E&P company will continue to grow by itself and where we can take the oil and gas they produce as raw material, we will take it but then they also look for export opportunities; they will continue to produce and export oil but our ultimate game would be to change the proportion of what goes out to what stays in country for value addition purposes.

We are going to take into refining, petrochemicals, and everything else that can happen there including hydrogen and all that stuff down the line. Right here (in our Industrial Park)  is where we intend to begin to demonstrate all that.

Crude oil generates foreign exchange immediately but all these other products don’t. Or do they? As a company that used to be a primary producer of crude oil, how do you manage the fact that there will be crunches in your foreign exchange earnings now?

I can tell you now that in the last two years or so, I mean, since the TNP shutdown, we haven’t been able to earn any foreign currency from crude export. Yes, there’s none. But we earn FX today from the export of some of the refined products that we have and we really don’t export directly but indirectly. What that has proven to us is that, really, you can take crude and refine it and still generate foreign currency from it. Since we’ve proven this concept, we are now trying to scale up the infrastructure of the facility to export.

You produce diesel, naphtha, HPFO and kerosene; which one of these is the key for export?

Fuel Oil; it’s a good product for the export market. A lot of companies, a lot of countries use it in their mining activities. Some use it for bunkering vessels, power plants use it and cement companies use it as well. So we have established a good export market for these products and we just want to organize it properly; as we are building our refining capacity, we must build the export capability and infrastructure that we need.

I’ve travelled to one or two countries and we have ongoing commercial negotiations with those countries, in those markets, to take our products there. They will be opening letters of credit in our favour for us to deliver our products.

Value addition is the way to go, not just to sell the crude and we see the impact in one of our bottom lines. What I also see is that once the Nigerian refining capacity, controlled by the private sector, significantly covers the domestic demand, the Nigerian market becomes wet in terms of refined products and therefore, export then becomes a major possibility for us as refiners. Even the current restrictions on diesel exports will naturally go away because there is sufficient supply in the markets. We would have excess products so instead of me just focusing on exporting fuel oil alone, I will have the opportunity to export diesel and any other products to the continent as well.

But would we get to the point where a huge fraction of our refined products could be going to the export market because we have sufficient supply back home? If that happens, all of us would be on the continent looking for markets to put our products.

How different are your host community plans for upstream Oil&Gas production from that of your refining plant? Where do they coalesce? What are the key objectives of your host community relationships?

There really is no difference because they are co-located in the same area. Our view of this big issue of community  engagement, quite frankly is like the issue of Nigeria and its crude oil sales and the sales proceeds. What we have been used to is producing oil, exporting crude oil, the international communities receive the crude from you and they give you money and say go and use the money to develop your environment.

That is why we are here today; this whole concept of 3% of your OPEX, dedicate it in a pool then you and the community should sit down and decide if you should build a market or healthcare or this or that. Believe me, in another 10 years, come back and we will still be where we are talking about this same thing. But this right here, (points his fingers at the plan of the industrial park on his table), is the solution to the development of the Niger Delta: building industrial clusters because when you add value to these things, you begin to create development. You will see it reflected in modern infrastructure in the communities. As a necessity, there will be need for a modern hospital to support our industrial park. I won’t go and locate a hospital in Owerri to serve this place. We have to build the model hospital here to support this, it will be hospital that would also serve the Communities.

We are producing electricity and here, there will be modern schools to support this, not village schools. There’ll be modern schools because here in the industrial park, you would have enlightened and educated people living here in the industrial park. There will be residential real estates in these communities that will be built to support this. Then you begin to have modern infrastructure, employment for people in the communities, economic empowerment for them and that’s how the development is going to happen. Not by crude oil extraction and exporting and dedicating 3% of your OPEX and putting it in a pool to go and build market and town halls for people.

Value addition infrastructure must be built within the area where we’re producing this oil. The consequence of all that would then translate into economic development for the Communities, economic empowerment for the Communities and people can see the difference in what you are doing.

When I go to Ibigwe, it’s a totally different world and you see it. From the bad roads we drive through in the communities to entering this park to having internet to seeing modern infrastructure there. The difference is like night and day. What human being would not aspire to live like that? It is when we begin to build industrial infrastructures that allow the whole community to integrate that you begin to see the impact when you see the transformation it has on the people. We should do things that will add value to our oil and gas.

“I believe I’m going to be the last person who will be a CEO of a company leading an IPPG. It needs to become an institution by itself that can truly represent the industry and make a case for the industry.”

 From where you sit as the chairman of the Indigenous Petroleum Producers Group ( IPPG), do you think domestic consumption of Compressed Natural Gas (CNG) would be cheaper than Premium Motor Spirit (PMS) in the long run?

Naturally because gas is cheap. But of course, again it comes down to building infrastructure to carry out the conversion process and making the requisite investment and that is how this transition can happen. Fortunately we are now beginning to have refineries instead taking the crude out and importing PMS to distribute locally. As long as we are producing the gas locally. and making the investment in the Industrial infrastructure that would then produce the CNG and then we can also invest in the CNG facilities and in these vehicles s o t h a t t h e transition can happen. Naturally it is going to be cheaper.

But do you think the international price of gas would affect our CNG market?

We are producing gas in Nigeria. The aspiration has been that we want to move gas pricing away from a regulated environment to a free market environment; willing-buyer, willing-seller concept in order to incentivize investment into gas production. But I don’t see how we would price gas domestically to the point where it will become more expensive than imported gas. It means we are doing something wrong. God has given it to us as a natural resource and if we are producing it at the cost that is more expensive than it is being imported, then we are not doing something right. If you want to create an incentive for gas producers, government can do it because we’ve always said that gas is supposed to be an enabler; it’s also a transition fuel. Through an incentive system, government can decide it wants to let gas reach out to every nook and cranny of this country to influence a lot of the things that we do. We can do that to incentivize gas production and make sure that it is cheap enough to make it available to so many people.

When Waltersmith was going to invest and take a stake in ND Western, it took 8%. Did it become an incorporated JV or did you stand alone?

That’s what we did. You know, all of us contributed our equities and it became ND Western so it is an incorporated JV. So that JV is standing alone as an incorporated entity. And each of us is still running our own businesses and that is the consortium that we formed. In the new consortium, named Renaissance Africa Energy Company, ND Western is on its own, different. All of us are in that consortium and we contributed differently to this consortium and that is why we say there are five of us: ND Western as an entity, First E&P, Waltersimth, Aradel are the Nigerian entities and Petrolin as the international entity.

What is the frame of your gas business partnership, which will deliver the Mini LNG in the Industrial Park?

We have a JV with an American company for this gas business, because they have some proprietary mini LNG technology and that is why we are working with them. We have a

company called Waltersmith-Chester LNG. Chester is an Pittsburgh, America, based company. It is in the mini LNG space. We own 51% and they own 49%. We are developing the solutions together.

For your succession plan, you have three CEOs as well as the COO, in the Waltersmith Petroman Group. One of them will take over from you as Group CEO in two to three years’ time. But you’re still going to appoint a CEO for your gas business. Will he/she also be part of the scrutiny for who succeeds you?

As we mature the gas business, we have to have a CEO for the company but we are not there yet. We are developing it as part of our strategic growth plan. I’m going to be group CEO for the next three years. And we are setting some basic parameters for ourselves; specific business goals that we have determined that we want to achieve, some indicative revenue forecast for the period which is based on a long-term strategy. And so, I’m starting the journey and we are making good progress in that regard and we see that improving from year to year.

By the time I leave, which will be by February 2027, we should have achieved at the minimum: our upstream business should be providing 50% of our feedstock in our 10,000 barrels per day refining capacity. We should be well on our way with the construction of the condensate refinery because ultimately, we want to be at about 40,000 barrels refining capacity between our crude line and the condensate refinery. That’s our game plan.

So once those things are accomplished, we are laying the critical foundation for the future; for the new Group CEO to take over and he then starts his own journey from there and the goal for him will be to consolidate on building our industrial capacity because that’s really the future for us. Building that industrial and manufacturing capacity within our complex. Whoever is going to lead our refining business would then have to start thinking what aspect of petrochemicals should we go into. Energy transition can also happen from there; hydrogen.

That’s the future that I see for us as a company; by that time, I can ease out and I would rather be playing a non-executive role than an executive role because on the 7th of this month, (February 2024) which is three days from today, I’ll be 63 so if I give myself another two years, I will be 65. I think I would have done my bit then. We have created a structure now where we have these three CEOs today: the E&P guy, the Refinery guy and the Energy Infrastructure guy and the Gas person who would ultimately join us later. We also have our COO. We all meet every Wednesday physically to engage and have very robust discussions on the business across board. We call it GEC, Group Executive Committee so all of us sitting there understand the business.

We also have the Group Investment Committee where everybody comes to compete for Capital. So everybody sits there and talks within the context of their business; how much money the business is generating and this is how much this business needs. Everything is on the table.

 Let me just ask you this last question: as the chairman of the IPPG, how would you describe the achievement that you’re most proud of?

IPPG itself as a brand! You know, when we started IPPG in April 2015, Demola (Adeyemi Bero) and a few of us sat down and said we needed to have a voice for indigenous producing companies and four of us became the board of trustees and that was how we started to reach out to people. Demola was our first chairman subsequently, I have now taken over from him.

 So it’s a four year term?

Yes; two years per term and I am in my last phase now. I think the primary accomplishment is that you are talking about IPPG. Nobody knew about IPPG before. We have created the visibility and we have now become a known advocacy platform for the voice of the indigenous players. At least now, people know that the indigenous players actually exist. In the past, NNPC as the determinant player did not even think that we existed but now, they know that we exist. That’s just the first phase.

I believe that even me, I’m out living my usefulness in the IPPG as the IPPG chairman and I say that with every sense of responsibility. I think I’m getting to the point where I’m not supposed to be the voice of the IPPG. IPPG requires an independent leadership. IPPG does not require any CEO of any of its companies being the face of IPPG. It requires a more focused leadership because right now, I’m dividing my time between IPPG and Waltersmith;

IPPG needs more focus than that because, when this divestment p r o c e s s i s completed, there will be nobody else but IPPG. OPTS will be no more and it is IPPG that will be

the platform that will speak for the industry. I believe I’m going to be the last person who will be a CEO of a company leading an IPPG. It needs to become an institution by itself that can truly represent the industry and make a case for the industry.

Is there an active search for that person?

No, it is just me saying it now and I’m going to share that with my colleagues to say that’s the direction we have to go, given the enormity of the responsibility that is going to befall the IPPG going forward. That becomes really critical for us to take that decision and I am going to take it upon myself to engage the council and our members so that the process will start. We need to institutionalize the IPPG like some of these other organizations have done; we need to do that. I guess like the LCCI. We need to have a leader that is strong, knowledgeable, research oriented and that has the facts in his hands that can make a strong case. We are apolitical but we are a business based organization and we need a leader that will lead it as such.

Do you play golf?

Not anymore since I hurt my back. But I like to travel.

 

 

 

 


Reviewing the majors: Your guide to the 2024 AGMs(Annual General Meeting)

By Gerard Kreeft

Energy investors and shareholders have a diversity of visions which the oil majors— BP, Shell, ENI,TOTALEnergies, Chevron, ExxonMobil and Equinor—will present them at the various AGMs. Below is an overview of what to anticipate. Perhaps not earth-shattering but enough food for thought to give you the reader a better understanding of the energy transition, regardless of your point of view.

The New York Stock Exchange (NYSE) is an excellent barometer to determine the current status of the oil majors (July 2019-March 2024). It is not a pretty picture.

In the July 2019-March 2024 period the Dow Jones Industrial Index rose 50%: increasing from 26,599 to 39,807. Yet the European oil majors have in this same period (with the exception of Equinor and TOTALEnergies), seen their share prices underperforming badly:

BP -10%

Shell -3%

Eni -3%

TOTALEnergies+23%

Equinor + 35%.

In the same period US oil giants Chevron and ExxonMobil have seen their share prices flourish: Chevron up 27% and ExxonMobil 51%.

 Table 1: Stock market prices of  majors July 2019-March 2024 (NYSE – New York Stock Exchange)

 

YearBPShellEniTotal

Energies

ChevronExxonMobilEquinor
2019$42$65$33$56$124$77$20
2024$38$67$32$69$158$116$27

 

Why is it that the share prices of Chevron and ExxonMobil have performed so well and their European counterparts have done so poorly? And why have TOTALEnergies and Equinor been able to maintain investor confidence? Below a company analysis and a series of conclusions which will help explain the seeming paradoxes.

BP: A Takeover prey?

 BP’s faltering share price has in the period July 2019-March 2024 remained on a downward trajectory: from $42 to $38. The company’s history is rather checkered:

BP’s Deepwater Horizon oil spill of 2010 in the Gulf of Mexico has to 2018 cost the company $65Billion;

The company’s withdrawal from Russia in February 2022, because of the Ukraine conflict, meant the loss of 50% of its global reserves; and

In September 2023 the abrupt resignation of CEO Bernard Looney after he admitted that he had not been “fully transparent” about historical relationships with colleagues.

BP meanwhile is promising to spend up to $65Billion on renewables between 2023-2030 and amounting to half of its investments by 2030. Yet the company has written off $540Million of its offshore wind assets in New York.

Will BP be able to meet its renewable energy goal given the long-term slump of renewables and BP’s lingering share price?

What BP was promising originally?

  • An underlying EBIDA (earnings before interest, depreciation, and amortization) of between 5–6% per year through to 2025, with returns in the range of 12–14% in 2025.
  • From 2025 onwards, when its low-carbon projects start to kick in, an expected growth of between 12–14% to be maintained.
  • Its $25Billion divestment would provide the basis for up-scaling its low-carbon business. A pipeline of twenty-five oil and gas projects and an additional eighteen projects in the pipeline were also key factors.
  • Spending $5Billion per year to green itself and by 2030 will have 50 GW of net generating capacity. To date the company has a planned pipeline of 20 GW of green generating capacity.

More recently BP has announced that it is lowering its oil and gas production to be around 2Millionbarrels per day of oil equivalent (2MMBOEPD) by 25% by 2030,  lower than the 40% originally announced. How this will affect BP’s green vision is difficult to predict.

Yet BP’s faltering vision, its downward share price and its low valuation—some $100Billion–makes the company a vulnerable takeover prey.

Shell’s three illusions

The chief obsession of Wael Sewan, Shell CEO since January 2023,  is to drive up the company share price. Yet the share price has barely moved—it was $65 at the start of April 2019 vs $67 March 2024. In his view Shell must mimic Chevron and ExxonMobil. While the Shell share price has remained virtually unchanged, Chevron has seen its share price in the same period  increase 27% and ExxonMobil 51%.

Shell’s total capex for the period 2023-2025 is between $22Billion-$25Billion per year, of which some 80% is earmarked for hydrocarbons. Not unlike Chevron and ExxonMobil.

Sewan is attempting to change Shell’s narrative: that Shell is in the business of producing hydrocarbons, instead of also selling the illusion that its new energy policy matters. Europe’s oil majors, Including Shell, have seen their share prices flounder. Why? Because of their messaging—wanting to appear to be both an oil company and a green energy company.

Illusion 1:The Common Good

In Shell World the company represented ‘the Common Good’.  Year—in-and-Year–Out Shell’s will was seen as law, at least in the Netherlands. For example, the Director-General of the State Mining Authority in the Netherlands, the highest regulatory body for the oil and gas industry, was always a high-ranking Shell manager who took early retirement from Shell and parachuted into his new regulatory role.

Then there is the matter of Shell’s pending appeal regarding its CO2 emissions. In 2021 the court ordered Shell to cut its absolute carbon emissions by 45% by 2030 compared to 2019 levels. Very quickly Shell stated that its emissions issue was a private Shell matter and not a matter of ’the Common Good’.

Illusion 2: Upstream will provide green funding

Prior to Sewan’s leadership Shell had argued that its Upstream pillar ..”delivers the cash and returns needed to fund our shareholder distributions and the transformation of our company, by providing vital supplies of oil and natural gas.”

Yet Sewan is  frank enough to acknowledge that this vision was an illusion. Depending on its upstream portfolio to lead the company to a bright new green future is perhaps central to Shell’s dilemma. Using funding from its upstream division to fund its green energy is in Sewan’s view a non-starter.

Illusion 3: Shell’s LNG global forecasting—back to the drawing board

Shell’s LNG Outlook 2024 forecasts that China will grow its LNG requirements more than 50% by 2040: rising to 23Trillion Cubic Feet (Tcf) in 2040 from 14Tcf in 2023. Yet Shell’s optimism may be premature.

The Institute for Energy Economic and Financial Analysis IEEFA’s Global LNG Outlook 2023-2027 casts a more somber analysis for  future  LNG developments, in particular for China: rising domestic gas production, pipeline gas imports, and renewable power capacity could limit the potential for rapid LNG demand growth over the medium term.

“Lackluster demand growth and a massive wave of new export capacity are poised to send global liquefied natural gas (LNG) markets into oversupply within two years. These two trends are developing even faster than anticipated.”

“Declining Russian gas supplies to Europe, driven by Russia’s full-scale invasion of Ukraine, caused a spike in European LNG imports that sent global prices to record highs. But despite modest new LNG export capacity additions in the last two years, prices have retreated from 2022 levels, largely due to falling demand from developed economies.

In Japan, South Korea and Europe—which account for more than half of the world’s LNG demand—combined imports fell in 2023 and will likely continue falling.

In emerging Asian markets, structural LNG demand growth faces a complex web of economic, political, fiscal, financial and logistical challenges. The global LNG crisis of the last several years heightened those challenges, spurring some Asian nations to reduce the role of LNG in their development plans and accelerate the development of alternative energy sources.”

ENI

ENI, the Italian oil and gas giant, is often overlooked in any discussions involving the other oil majors. Yet ENI could be the Joker in the deck providing surprises to an unwitting public and be an upstart which deserves the needed attention. The company operates in the frontier areas seldom mentioned in the daily news media.

For starters ENI produces 1.7MMBOED, has a balance sheet which has an economic leverage of 20%, and has, according to its website,  an Internal Rate of Return(IRR) of 34%, the highest of all its peers  for the 2012-2021. Also, its RRR (Reserve Replacement Ratio) of 110% for the period 2012-2021 is the highest compared to its industry peers.

ENI further states that 90% of exploration capex is spent on near fields and proven basins. Some $11Billion in the last 10 years has been spent on its dual exploration model—near fields and proven basins. The company states that it only requires three years—from first discovery of oil to market—twice as fast as the industry average.

Yet ENI’s stock market price has remained flat in the period July 2019-March 2024: from $33 to $32.

A key ENI strategy  is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets and at the same pursuing new strategies as part of its energy transition plan. Two examples:

 Vår Energi, Norway was formed in 2018, following the merger of ENI Norge AS and Point Resources AS, owned  by Hitec Vision, a private Norwegian investment fund.  The company’s primary focus is oil and gas developments on the Norwegian Continental Shelf. ENI controls 69.6% of the shares, and HitecVision 30.4%. Vår Energi has production in 36 fields and produces 247,000BOEPD.

Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’ upstream assets, LNG and solar business. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2Billion barrels equivalent of net resources and growing to about 250,000BOEPD of equity oil and gas production over the next 5 years. It holds stakes in 16 licences (of which 6 are exploration blocks) and a participation in Angola LNG JV. The company also participates in the New Gas Consortium(NGC), the first non-associated gas project in the country.

 ENI’s North African Gas Hub

ENI’s North African Gas Hub–Algeria, Libya and Egypt–will certainly be a key provider of natural gas to Europe. The three countries together produce 648,000 boepd, approximately a third of Eni’s total global production.

Algeria

In July 2022, Sonatrach and ENI announced that an additional 141Bcf per year will be exported to Italy via the TransMed Pipeline which is a 2,475 km-long natural gas pipeline built to transport natural gas from Algeria to Italy via Tunisia and Sicily. In 2023 ENI’s production from Algeria was scheduled to rise to over 120,000BOEPD.

Libya

The Libyan gas produced by the Wafa and Bahr Essalam fields operated by Mellitah Oil & Gas, an operating company jointly owned by ENI and NOC(Libyan National Oil Company). The gas  is brought to Italy through the Greenstream pipeline. The 520-kilometre natural gas pipeline crosses the Mediterranean Sea connecting the Libyan coast with Gela in Sicily. The natural gas pipeline has a capacity of 283Bcf per year. ENI has a production of 168,000BOEPD in that country.

Egypt

ENI is operator of the large Zohr field which In August 2019, had a  production of more than 2.7Bcf/d. An important agreement was the restart the of Damietta liquefaction plant which will provide up to 106Bcf in 2022 for European customers. ENI produces 360,000BOEPD.

TOTALEnergies: Providing the lead

The company’s twin growth pillars— developing its low carbon hydrocarbon assets and developing its integrated power business—are key for implementing  its energy transition strategy.

TOTAL is replicating its integrated oil and gas business into the electricity value chain to achieve a profitability of at least 12% ROACE(return on average capital employed) for its integrated power segment, based on an equivalent of $60 per barrel.

TOTALEnergies aims to grow its power generating capacity to 100 GW by 2030: investing $4Billion per year so that by 2030 it will achieve positive cash flow.

By 2050 TOTALEnergies’ energy mix will be:

25% low carbon molecules

50% electricity and renewables

18% LNG

7% oil

To understand the French major’s strategy we must go back to 2020. Then TOTALEnergies took the unusual step of writing off $7Billion in impairment charges for two oil sands projects in Alberta, Canada. Both projects were listed as proven reserves. By declaring these proven reserves as null and void, with one swoop of a pen, TotalEnergies cast aside the petroleum classification system, which was the gold standard for measuring oil company reserves.

The company simply decided that these reserves could never be produced at a profit. Instead, TotalEnergies has substituted renewables as reserves that can be produced profitably.

TOTALEnergies’ strategy was based on the two energy scenarios developed by the International Energy Agency (IEA): the Stated Policies Scenario (SPS), which is geared for the short to medium term, and the Sustainable Development Scenario (SDS), which focuses on the medium long term.

Taking the “Well Below 2 Degrees Centigrade” SDS scenario on board, TotalEnergies has, in essence, taken on a new classification system. By embracing this strategy, the company is the only major to have seen a direct benefit from using the Paris climate agreement to enhance its renewable energy base.

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.

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

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.

But TOTALEnergies’ write-offs showed that even proven reserves are no sure thing and that adding reserves doesn’t necessarily mean adding value. The implications are devastating, upending the oil industry’s entire reserve classification system as well as decades of financial analysis.

How did TOTALEnergies reach the conclusion that reserves had no economic value? Simply put, reserves are only reserves if they’re profitable. The prices paid by customers must exceed the cost of production. TOTALEnergies’ financial team decided those resources could never be developed at a profit.

The company had not abandoned its oil and gas investments. However, its renewable investments were seen as additional ballast to the company’s balance sheet, keeping it afloat as it carefully chooses investments, including oil and gas projects, with a high economic return.

Equinor: Will it maintain its course?

Equinor’s past message of spending more than one-half of its capital spending on low carbon energy by 2030 in offshore wind technology had caught the fancy of its investor community.

Yet the reality could prove to be different. In 2023 the company suffered a loss of more than $750Million on its New York offshore wind projects.

In spite of its loss Equinor’s transformation ambitions, combining a focus on renewable energy with continued high production of oil and gas, will result in a renewable share of 7–12% by 2030. The company aims to produce around 2 million barrels of oil and gas per day in 2030, which is at the same level as in 2022.

 Equinor’s twin pillars

 Will  Equinor’s twin pillars of natural gas and its growing offshore wind portfolio provide the company  the financial depth and ability to achieve maximum leverage for both pillars?

 Equinor’s  goal to grow its offshore wind portfolio to 12–16 GW of installed capacity by 2030 faces a number of severe challenges:

In the past the company had pledged that renewables would receive more than 50% of capital investments by 2030. Now there is no mention of trying to achieve this!

There is severe competition from a number of key European new energy players, who have the economies-of-scale that Equinor can only dream about.

  • ENGIE based in France: will have 80 GW of global renewable installed capacity by 2030.
  • Enel based in Italy: The company’s strategic plan outlines that by 2025 it will have 75 GW of installed capacity; and by 2040 its electricity generation derived solely from zero-emission sources.
  • Ørsted based in Denmark: By 2030 the company will have an installed capacity of 50 GW of renewable power.
  • Iberdrola based in Spain: From 2024–2026, the company will be spending more than $40Billion on renewable energy and has a pending target of 100 GW of installed renewable capacity.
  • RWE based in Germany: By 2030 RWE will have 65 GW of installed wind and solar capacity and net zero emissions by 2040.

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

Equinor’s Empire Wind and Beacon Wind assets off the USA’s east coast have resulted in a swap transaction with BP. Equinor will take over full ownership of the Empire Wind Lease and projects and BP will take over full ownership of the Beacon Wind lease and projects.

Chevron: Stay vigilant

Aside from its newly acquired asset in Guyana  two-thirds of Chevron’s total production of 3 million barrels of oil will in  2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States  each yielding 1 million barrels of oil equivalent per day.

Today the company has a net value of  over $300Billion, seen its stock price rise to $158 by March 2024, up from $124 in July 2019. A rise of 27%. It anticipates maintaining a capital budget of between $18.5-19.5Billion per annum, which includes capex for affiliates. The company has indicated that $14Billion is devoted to upstream, two-thirds or $9Billion mostly in the Permian Basin and Gulf of Mexico.

Outside the USA, Chevron will spend $5Billion: $1.5Billion to further develop its Tengiz asset in Kazakhstan, with the remaining $3.5Billion 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.

Caspian Pipeline Consortium (CPC)

A potentially 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 1.3 million bpd(barrels per day). 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).

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 dependent 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 Chevron could be its 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.

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.

ExxonMobil: Don’t count your chickens…

ExxonMobil’s vital signs are the following: between July 2019 and March  2024 the stock price at the NYSE has risen from $77 to $116, 51%. The company has a capex of between $23-$25Billion in 2024 and for the period 2025-2027 it will spend annually $22-27Billion.

Good News & Bad News from Guyana

ExxonMobil continues to publish for the world its good news from its offshore Stabroek Block in Guyana: by 2027 a target of 1.2MMBOPD will be pumped, budgeted at a cost of $45Billion. Total recoverable reserves are estimated at 11Billion barrels.

Not mentioned is the price tag.

At the end of five years(2024), according to IEEFA, Guyana will carry a minimum $20Billion outstanding balance owed to its oil producer partners. This amount must be paid, along with other contractually obligated development costs, before the country can fully enjoy any long-term benefits that might materialize.

This is a discussion which must be had in the coming months.

 LNG—A Mixed Blessing

Rovuma LNG was supposed to become ExxonMobil’s futuristic model LNG project. ExxonMobil has recently issued various tenders to move its Rovuma project ahead. Instead, in a matter of months events have overtaken ExxonMobil’s best laid plans.

IEEFA’s recent warning of a global LNG oversupply in the coming five years is not good news!  Will Rovuma make it to the starting gate?

Then there is the matter of ENI’s Coral Sul Project in Mozambique.

The  inauguration of this project deserves special attention. The first LNG shipment of ENI’s Coral Sul FLNG shipment took place in November 2022.

  While Africa’s two  most highly touted LNG projects—Rovuma and Mozambique LNG– continued to be on security hold,  ENI achieved pole  position with its Coral Sul FLNG project.

A Final Investment Decision (FID) is expected to be made on ENI’s  second Coral Sul Project in Mozambique June 2024.

 Key takeaways

BP’s quest to survive is taking precedent over any discussion whether how green the company should be or whether to indeed be an oil and gas company. No doubt the final chapter has yet to be written.

 Shell continues in vain to search for its soul. Anxious to play catch-up with its US rivals—Chevron and ExxonMobil. Yet in hot pursuit of them is no guarantee that Shell’s future will become brighter.

 ENI operates in a very fluid market place and has shown the ability to be diverse and able to provide contrarian strategies. A characteristic needed in a fast-changing energy world. The Joker has not yet dealt his final card.

TOTALEnergies continues to set new precedents for the energy transition:  replicating its integrated oil and gas business into the electricity value chain to achieve a profitability of at least 12% ROACE(return on average capital employed) for its integrated power segment, based on an equivalent of $60 per barrel. By 2030 it will achieve positive cash flow. This is no mean achievement given that the industry average for the electrical sector is 6%.

 Chevron’s key achievement to date has been its relatively stable share price—rising 27% in the period July 2019-March 2024.  A key concern  for shareholders is that two-thirds of Chevron’s total production of 3 million barrels of oil will in 2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States  each yielding 1 million barrels of oil equivalent per day. Not exactly diversity of supply.

ExxonMobil in the period July 2019- March 2024 seen its share price increase 51%. Much of the gloating is based on its Guyana offshore project, scheduled to produce 1.2 mbpd by 2027. Yet little is being said about the $20Billion debt which the Government of Guyana must pay in 2024 to settle its cost of developing the Stabroek Block.

Equally concerning is the Rovuma LNG project in Mozambique: IEEFA’s recent warning of a global LNG oversupply in the coming five years could prove to be a challenge for the company.

Equinor has managed to achieve an ROACE of 34% and its share price has risen some 35% in the period July 2019-March 2024. The company’s fallback position is that it is a key provider of natural gas to Europe. Yet its offshore wind sector lacks the economies of scale to compete with companies such as Enel, Iberdrola, Ørsted and RWE.

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  Bookstorehttps://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition

 

 

 

 

 


Giuseppe Surace, Ex SAIPEM Executive Who Fast Tracked Dangote Refinery Construction, Leaves to Run His Own Company

Giuseppe Surace, former managing director, Saipem Contracting Nigeria Limited, who was appointed in 2017 to fast track the (then) slow construction of the Dangote Refinery, has moved on to the next phase of his career.

The Italian engineer left the Chief Operations Officer role in Dangote refinery in February 2024 and has been owner of Only Capital in Dubai since.

Surace’s right-hand man Antonino Raffa, also a Saipem alumnus, had earlier left his role as Head of Field Engineering for Dangote refinery in January 2024 and has since been Field Engineering Manager at Azule Energy, ENI-BP Joint Venture in Angola.

Surace had gone to Dangote from Logstor, a company held by Private Equity Triton, where he was running the Oil &Gas business. Logstor is a supplier of pre-insulated solutions for District Energy and Oil and Gas markets”, Surace reported, himself, on his LinkedIn page.

Africa Oil +Gas Report had once reported this much about Surace’s job at Dangote: “On the factory floors, in the executive offices, everywhere on site, the consensus is that one of the best decisions that Aliko Dangote made was Surace’s appointment”, said our sources. “He saved the project”.

Prior to Logstor and Dangote, Surace spent 20 years with Saipem, where he started in 1995 as Piping Design Engineer in Italy. After two years’ assignment in Kuwait he was promoted to Project Specialist Leader, Project Engineering Manager and Proposal Manager before moving to Lagos, Nigeria in 2007 as Managing Director of Saipem Contracting Nigeria. In 2011, he relocated to Brazil and became CEO of Saipem Do Brazil. In 2014, after a short assignment in Saipem HQ Milan, he returned to Nigeria as Senior Vice President, Central Africa. Giuseppe holds a Master Degree in Mechanical Engineering from University of Calabria and a MBA from Bocconi University and MIP School of Management in Milan, Italy.


Azura is a Shiny Outlier, Transcorp is Noisy

…And Hydro plants Perform Better …

Out of Nigeria’s 10 largest electricity producing plants, the exemplary outlier is Azura, which generated 424MW, or 92% of its installed capacity in February 2024.

The closest performers are the hydropower plants: Kainji delivered 438MW or 58% of its installed 760MW; Jebba output 306MW or 54% of its installed 570MW and Shiroro produced 305MW or 51% of its installed 600MW.

In terms of percentage, Agip’s Okpai plant counts among the first five but the 52% of installed capacity, which it produced, was a mere 251MW. These are all February 2024 performances, published by the Nigerian Electricity Regulatory Commission.

The report is evidence that the generation part of the Nigerian Electricity Supply chain is an astonishingly underperformer.

Total actual output, of…

The full report is for paying subscribers only


Namibian Oil: “We’re Not Looking for a Knight in Shining Armour”

By Toyin Akinosho, in Windhoek

The Namibian government is keen on accelerated development of the string of huge oil and gas discoveries made offshore the country in the last two years.

The country acknowledges that the path to crude oil development is in early stages and the institutional framework and the Namibian capacity in the sector are a work in progress, but the authorities have signaled that they are neither desperate nor despondent.

“The investors we seek to attract are those who agree that the investment must result into a mutually rewarding relationship that benefits both the Namibian people and the investor”, Tom Alweendo, Minister of Mines and Energy, told delegates at an annual energy conference in Windhoek, the country’s capital.  “Not only will the investor earn a return on his investment, but the investment, in itself, would have assisted to transform the economy into a more complex and dynamic one – something that will better serve humanity.

“It is the savvy investor we would like to attract to our shores, and not a knight in a shining armour who is coming to rescue us from a situation of hopelessness”.

Alweendo, a graduate of Commerce from the South African University of Witwatersrand and the first Namibian national to be the Governor of his country’s Central Bank (1997-2010), said the government had accepted companies who hold oil and gas licences, “to collaborate with us and in return we expect that you earn your license to operate.

“I ask that you tune out the barrage of noise about how Namibia lacks the necessary expertise, or capital, or infrastructure to build a successful oil and gas industry. We want you to adopt a tenacious persistence to make things happen and use your unique perspectives to develop Namibia-specific strategies that will succeed”.

Since the announcement of the basin opening discovery of the Graff accumulation by Shell in February 2022, there have been reportedly bigger finds in the deepwater Orange Basin by (again) Shell, TOTAL, and (the Portuguese explorer) Galp Energia. These subterranean hydrocarbon tanks are now estimated, by the authorities, as collectively holding in excess of 4Billion Barrels of Oil Equivalent.

The industry and the government are “still assessing the commercial viability of these exciting finds”, Alweendo explained. However, “we are confident that the early projections will prove accurate, and that we need to prepare for a hydrocarbon bounty that will turn Namibia into a major oil & gas producer.”

The minister turned on the pressure.

“To those who have made commercial discoveries, we want you to fast-track field development for all discoveries. Although I consider myself a pragmatist, the fact is that we need the resources out of the ground for the oil & gas industry to flourish”, Alweendo told the 1,000 delegates from around the world, including industry professionals from Angola, Nigeria and South Africa (in Africa); France, Britain and Portugal from Europe; the United States, Canada and Brazil from the Americas.

“We need to develop plans now to speed up production as soon as the discoveries are determined commercially viable”.

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