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“Teach Us How,” Namibians Seek Angolan Help in Hydrocarbon Development

Namibia’s petroleum officials have signed a Memorandum of Understanding (MoU) with their Angolan counterparts, essentially about holding their hands in navigating the terrain of regulating the development of the series of oil discoveries Namibia is walking into. The MoU, between Namibia’s Directorate of Petroleum Affairs and Angola’s National Petroleum, Gas and Biofuels Agency (ANPG) aims to promote bilateral cooperation in the Oil and Gas sector between the institutions, based on mutual benefits between the two countries, strengthening and intensifying cooperation in the Oil and Gas Industry.

“We are going to train the Namibians so that they can assume the responsibility of producing in Namibia”, remarks Paulino Jeronimo Chairman of the Board of Directors of ANPG. “The training will not take place in an office, but in a task force because we have accumulated experience with different operators and we want to make use of this aspect to help in the training of Namibians. Remember that the national workforce in Angola is 80% and it is our expectation that Namibia will gradually reach this level”.

The MoU was inked in the course of the Namibia International Energy Conference held in Windhoek, under the motto “Shaping the future of energy for value creation”.

Namibia has hosted a number of huge discoveries of oil and gas in its deepwater acreages since 2021. By some analysis, the large tanks encountered by Shell and TOTAL under the Namibian portion of the South Atlantic could hold up to six billion barrels of hydrocarbons. But the country has never seen any hydrocarbon discover through to development.

Namibia and Angola will now, after this agreement, move on elaboration, approval and execution of the Action Plan, according to a release by the ANPG.

The MoU follows up on an earlier MOU signed between the Ministry of Natural Resources, Oil and Gas of Angola and the Ministry of Energy and Mines of the Republic of Namibia, on the 29th of November last year, during the Angola Oil and Gas Conference.

The Angolan delegation, headed by the Chairman of the ANPG, was made up of the Executive Director, Belarmino Chitangueleca, the Director of Negotiations, Alcides Andrade, the Coordinator of the Biofuels Nucleus, Vita Mateso, Exploration and Negotiation Specialists, Adriano Sebastião and Hermenegildo Buila, respectively, as well as technicians from various areas assigned to the Concessionaire.

Missed Opportunities in Gas to Wire/Our Latest Issue

The gas to power market is large in North Africa.

It is growing fast in Ghana and has shown encouraging uptick in Tanzania.

Nigeria is punching below its weight, running a distant third after Egypt and Algeria, even with much more abundant gas resources than either of them and more than double the population of each of these two countries.

Namibia has had a great opportunity to take the tide at the brim, but it has been shy to grab it.

Mozambique has everything to take off in the sector, but it has very little ambition.

South Africa keeps fiddling with the chance to become a massive gas fired economy, and has shown either cluelessness about, or utter disdain for, developing either imported gas or local discoveries.

Read your copy of our latest monthly issue

We have stories in this edition, of the broken link in the line from the well head to the Power Plant in Nigeria; the energy challenges facing Egypt and the “good problem” North Africa has in choosing between export to nearby Europe or responding to growing appetite at home

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 decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions. Published by the Festac News Press Limited since 2001, AOGR is a paid e-copy publication delivered around the world. Its website remains, and the contact email address is Contact telephone numbers in the West African regional headquarters in Lagos are +2348124374087, +2348130733523, +2347062420127, +2348036525979, +2348023902519.

Decklar Has Contracts to Truck Over 300,000Barrels to Two Nigerian Refineries

Canadian operator Decklar Resources reports that it has trucked a total of 48,500barrels of crude to two modular refineries in Edo State, Nigeria.

The company has contracts to deliver over 300,000 barrels of oil to these two refineries over the next 12 months.

Decklar operates the Oza field on behalf of itself and Millennium Oil & Gas, the holder of the licence to the field, located in Oil Mining Lease (OML) 11 in Rivers State.

As the two partners were unable to evacuate their output through the Trans Niger Pipeline (TNP) to the Bonny Terminal for export, they decided to truck the commodity to local refineries.

Decklar’s latest operational update notes that “trucking of crude oil from the Oza Oil Field to the Edo Refinery & Petrochemical Company (ERPC) has reached a cumulative volume of over 41,000 barrels”. ERPC is a 6,000 barrels per day modular refinery located in Ikpoba-Okha Local Government Area, Edo State.

The update also says that “over 7,500 barrels of crude have been delivered to Duport Midstream Company Limited (DMCL)”, located in Otien Edo State.

In effect, these deliveries have upended the narrative that refineries that are not built by oil producing companies themselves will suffer undue delays getting access to feedstock.

Prior to the supply of Oza crude to Edo Refinery and Duport, the two functional modular refineries in the country were the 11,000BPD ND Refinery at Ogbele, owned by Niger Delta E&P and the 5,000BPD Waltersmith Refinery &Petrochemical at Ibigwe, owned by the Waltersmith Group. Their supplies are assured by the crude oi production from their Ogbele and Ibigwe fields respectively.

Decklar says that the 41,000Barrels it trucked to Edo Refinery includes “10,000 barrels delivered in 2022 under the initial sale and purchase agreement and over 31,000 barrels delivered so far in 2023”. With that, “the deliveries under the 30,000 barrels contract have now been completed and invoiced, and deliveries will continue under the new 200,000 barrels contract”.

The company commenced delivery of crude oil commenced from the Oza Oil Field to DMCL in March and “under the sale and purchase agreement with DMCL, Decklar and Millenium initially delivered 5,000 barrels to the Duport refinery in March and early April, followed by an additional 2,500 barrels in the last half of April”.

Deliveries of an estimated 5,000 barrels per month will continue going forward, Decklar explains “and DMCL has agreed to purchase up to 100,000 barrels over the next 12 months”.

Angola Slips Below 1MMBOPD in Output and Export, Loses Revenue

By Macson Obojemuinmoin

Angola produced 30,059,033 barrels of oil in March 2023, corresponding to a daily average of 969,646 barrels of oil (BOPD).

This was 9% less than the 1,063,589BOPD produced in February 2023, according to data by Angola’s National Oil, Gas and Biofuel’s Agency (ANPG), the country’s hydrocarbon industry regulator.

Export for March 2023, published by the country’s ministry of finance portal, frequently consulted by Africa Oil+Gas Report, amounted to 950,460BOPD, which was a 9.5% drop from 1,050,866BOPD in February 2023.

The country’s revenues have also headed for a fall. “Angola exported 87.92Million barrels of oil for a total of $6.92Billion in the first quarter of 2023, which represents a 30% year on year decline”, the Portuguese news agency Lusa reports, quoting José Alexandre Barroso, Angola’s secretary of state for oil and gas. “In the first quarter of 2022, according to figures from the ministry for mineral resources, oil and gas consulted by Lusa, Angola exported 98.38Million barrels of oil at an average price of $103.83, generating revenues of $10.14Billion”, Lusa reported.

Angolan authorities’ concern about declining output has provided the impetus for a frenzied drive for acreage licencing rounds (there have been three lease sales in the last three years) and improved fiscal terms for oil majors in the country.

In the event, Azule Energy, the incorporated joint venture between ENI and BP, awarded, last February, $7.8Billion worth of contracts for commencement of construction of the second phase of its Agogo Integrated West Hub Development project in Block 15/06. The project, expected to be in operation by mid-2026, involves the installation of an FPSO with a production capacity of 120,000BOPD, gas injection capacity of 230MMscf/d and water injection capacity of 120,000BWPD.

The government has also approved the development plan for TOTALEnergies operated the Cameia-Golfinho development in Blocks 20 and 21, the first hydrocarbon development targeting presalt reservoirs in the deepwater Kwanza Basin. TOTAL plans to take Final Investment Decision on the project by July 2023 and has indicated that it expects first oil from the 70,000Barrels of Oil Per Day project by 2026.

TOTALEnergies: Neither a soul to be blessed nor a body to be damned!

By Gerard Kreeft

TOTALEnergies recently announced that it has accepted an offer of $4.5Billion from Suncor Canada for its oil sands assets. Originally The French giant planned to spin-off its Canadian assets in an Initial Public Offering (IPO). According to the major’s press release the Suncor offer was “more straightforward in its execution than the planned spin-off”. Accordingly, the spin-off was terminated.

TOTALEnergies’ divestment was from two oil sands properties in northern Alberta.  The oil sands were earlier called “tar sands” or “bitumen” due to the oil’s low gravity and dense composition.  Production from these sands took a traditionally difficult, expensive and energy intensive route in the journey to upgrade the heavy oil into light saleable crude oil.   In the past decade, technological advances improved the commerciality of the production but it remains highly carbon intensive.  Indeed, President Barrak Obama and Energy Secretary John Kerry in 2015 declared that oil from the Alberta oil sands was “the dirtiest oil in the world”.  The benefit of this deal to TOTALEnergies is huge. In one fell swoop, the company gained $4.5Billion and also received a significant reduction in its carbon footprint by disposing its two most emissions-intensive assets in its global portfolio.  This disposition allows the company to significantly polish up its green credentials.

In the same press release TOTALEnergies stated that it will distribute to its shareholders at least 40% of the cash-flow in 2023, either through share buybacks or a special dividend distribution.

The timing of this announcement comes on the eve of the company’s AGM (Annual General Meeting) on May 26 in Paris. No doubt shareholders will cheer that more cash will be forthcoming. Yet is this a short-term gain for a long-term pain?

Clarity of Message

In the January 2018-April 2023 period the Dow Jones Industrial Index rose 35%: increasing from 25,295 to 34,098. Yet the European oil majors (with the exception of Equinor), including TOTALEnergies, have seen their share prices underperforming badly: Repsol down 18%, BP down 7%, Shell down 10%, ENI down 14%, TOTALEnergies remained the same. Only Equinor was up 26%. In the same period US oil giants Chevron and ExxonMobil have seen their share prices flourish: Chevron up 32% and ExxonMobil 36%.

Table 1: Stock market prices of majors Jan 2018- April 2023(NYSE – New York Stock Exchange)

Year Repsol BP Shell Eni Total


Chevron ExxonMobil Equinor
2018 $17 $43 $69 $35 $58 $128 $87 $23
2022 $14 $40 $62 $30 $58 $169 $118 $29


Why is it that the share prices of Chevron and ExxonMobil have performed so well and their European counterparts have done so poorly?

The message from the investor community is the clarity of the message. Chevron and ExxonMobil have as their mainstay–the production of hydrocarbons and this is the message that is preached. New energy policies including CCS(Carbon Capture and Storage) and other new energy initiatives make up only  between 15-20% of their capital budgets. In the case of Chevron some $3Billion per year based on a capital budget of $15-$17Billion; ExxonMobil’s new energy comes in at $3Billion per year based on a capex of $23- $25Billion. The message is clear and simple: we are oil companies pure and simple. Done in the good tradition of John D. Rockefeller the spiritual father of both companies.

European oil giants, have seen their dualism—wanting  to maintain their green image and also  profiting from the oil bonanza—fall out of favour by company shareholders. Their clarity of messaging has been found wanting.   The sole exception is Equinor who have stated that the majority of their capex budget will be from renewables by 2030.

Where did it go wrong?

To understand TOTALEnergies’ 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.

Patrick Pouyanné, TOTALEnergies’ chairman and CEO, then stated that by 2030 the company “will grow by one third, roughly from 3Million BOED (Barrels of Oil Equivalent per Day) to 4Million BOED, half from LNG, half from electricity, mainly from renewables.” 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. The Suncor sale is perhaps an indication of selling oil and gas assets at a profit before they are deemed stranded assets.

Reviewing TotalEnergy’s Strategy

Counting the money

TOTALEnergies has recently announced that it will be on track, by 2050, to have 50% of its energy mix in renewables + 25% in “new molecules”(green fuels). The remaining 25% would be comprised of oil and gas including LNG.

The company’s capital expenditures for the period 2022-2025 is anticipated to be between $14Billion-$18Billion per year: “a third will be in low-carbon energies, about 30% will be dedicated to the development of new oil and gas projects, and the remainder devoted to maintenance of the hydrocarbon portfolio.”

In other words the hydrocarbon budget will be approximately $8Billion-$11Billion and the renewable budget will be $5Billion in 2023.

Could shareholders demand that by 2030 the lion’s share of the company’s capital budget is  dedicated to renewables instead of hydrocarbons?

TOTALEnergies could take the Equinor precedent as an example. Equinor’s message of spending more than one-half of its capital spending on low carbon energy by 2030 in offshore wind technology has caught the fancy of its investor community.

LNG—Where did it go wrong?

TOTALEnergies’ 2022-2025 hydrocarbon budget could also be threatened by a floundering LNG market. In particular its Mozambique LNG project.  IEEFA(Institute for Energy Economics and Financial Analysis) in its recent Global LNG Outlook 2023-2027 provides a somewhat sobering picture for new LNG projects: “IEEFA expects that sustained high global LNG prices; weak LNG demand growth and elevated price sensitivity in Asia; declines in gas consumption in Europe; and a multi-year string of global capital investments in cost-competitive energy alternatives will undermine global LNG demand growth over the next several years.”

According to IEEFA the global demand for LNG is slowing:

Europe although maintaining a high degree of importing LNG, is also increasing  energy efficiency measures and wind and solar projects have become commonplace; Japan and Korea, historically dependable LNG importers, are increasingly turning to nuclear, and renewables; China, decreased its LNG imports by 20% in 2022 and is turning to pipeline gas supplied by Russia as well as domestic gas supplies; South Asia, including India, Pakistan, and Bangladesh, slashed purchases by 16% in 2022 and suppliers often defaulted on contracts to obtain higher prices elsewhere.

“After several years of weak supply growth, IEEFA anticipates that the global LNG market will see a tidal wave of new projects come online starting in mid-2025. The wave will likely crest in 2026, with the addition of 64Million metric tons of annual liquefaction capacity—the most in the history of the global LNG industry. The supply additions will boost global liquefaction capacity by roughly 13% in a single year. Liquefaction projects targeting in-service after 2026 may be entering a much smaller demand pool than bullish market forecasts anticipate. As new supply floods the market, today’s tight markets may give way to a supply glut, with lower-than-anticipated prices, smaller netbacks, tighter margins, and lower profits for LNG exporters.”

According to IEEFA’s forecast in 2023 only 5.8Million Tonnes Per Annum (MMTPA) of liquefaction production will be developed, and in 2024 9.1MMTPA. Total LNG production capacity is currently 456MMTPA.

The turning point will be 2025.

“IEEFA anticipates that roughly 17MMTPA of liquefaction projects are likely to come online around the world in 2025—more than in 2023 and 2024 combined. New capacity additions will crest in 2026, with an estimated 64MMTPA of capacity coming online in a single year, and continue into 2027, when 37MMTPA of new capacity is expected to begin operating”.

Much of the new production will come from Qatar, USA and Australia. If 2026 and 2027 will see a sharp upturn in LNG liquefaction production, how will this affect Mozambique’s two LNG projects which could potentially add 38.1MMTPA when fully functioning? Long term delays can only threaten project viability. And not proceeding sooner rather than later increases the chances of these projects being listed as stranded assets.

A more immediate threat is that of ENI’s Coral South project in offshore Mozambique which is already in operation. BP has contracted the entire output of Coral Sul for 20 years, having signed a free on board (FOB) contract with the project partners. In July 2022 it was reported that ENI was considering the possibility of deploying a second floating liquefied natural gas vessel in Mozambique. What does this mean for Rovuma and Mozambique LNG?

TOTALEnergies’ African strategy      

Much of TOTALEnergies’ 25% forecasted hydrocarbon  budget, proposed for up to 2050,  will be focused  on African  low-cost, high-value projects, squeezing more value out of  various African assets to ensure a prolonged life cycle.

In Angola the company produces more than 200,000BOEPD from its Block 17 and Block 32, and non-operated assets including AngolaLNG.

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

In South Africa the company is focused on its two South African assets: Brulpadda and Luiperd, the second discovery in the Paddavissie Fairway in the southwest of the block.

Will TOTALEnergies’ deepwater  division seek other parties to ensure that its various projects can be delivered?

A fly in the ointment could well be TOTALEnergies’ Mozambique LNG project, which is expected to cost $20Billion and produce up to 43Million tons per annum. IEEFA’s stinging critique of the LNG market has given this project a visible setback. Will it ever be developed? Deepwater projects are extremely expensive. Will TOTALEnergies call upon potential partners to help develop these prospects?

Then there is the matter of the East African Crude Oil Pipeline (EACOP). Public dissent is continuing. The large international banks and financial institutions are balking at financing this project. Continued delays only make the completion of this on-going saga more uncertain. Will TOTALEnergies sell its stake to avoid further reputational damage?

Turning the Tanker

TOTALEnergies should turn back the clock to 2020 when it made the bold move to utilize renewables as a strategic part of its reserve count. The duality of servicing two masters: hydrocarbons and renewable energy has only produced a murky outlook.

On the renewables front TOTALEnergies has confirmed it will have a 100GW capacity by 2030.

A key to TOTALEnergies’ success is its ability to step into projects at an early stage, some examples:

  • A 50% share of Adani Green Energy Ltd., India installed solar activities.
  • A 51% stake in the Seagreen Offshore Wind project in the United Kingdom.
  • Major positions in floating wind farm projects in South Korea and France.

Yet the company must take a number of radical steps:

First it must repair the splintered and diffused view of  its subsidiary companies—TOTALEren, Sunpower, and Saft–in which it has invested:

TOTALEren: an IPP(Independent Power Producer) developer involved in all phases of project development and implementation with a generating capacity of 3.7GW and 4GW under construction.  According to Africa Oil + Gas Report, the company could become a candidate for a top-ten list of Africa’s leading  renewable developers.

Sunpower: has 6 GW of photovoltaic power installed globally.

Saft: a leading battery producer, whose lithium-ion batteries can store large amounts of electricity in a small amount of space.

TOTALEnergies should look at becoming part of the Green Alliance. Enel, Engie, Iberdrola, and Ørsted have pole position in determining the direction  and scope of the global renewables market:

Enel: committed to achieving CO2 neutrality by 2040 instead of 2050, achieving 75% of electricity from renewables and 80% digitalization of its customers on the grid  by 2025. and having an installed generating capacity of 75GW by 2050.

Engie: pledged to reduce to CO2 neutrality by 2045- 45% of investments is focused on renewables and by 2030 will have 80GW of installed generating capacity.

Iberdrola: in the period 2023-2025 the company will invest $50Billion and achieve net zero for Scope 1, 2 and 3 before 2040. By 2030 the company will have installed capacity of 100GW, valued at $70Billion.

Note: Essentially, Scope 1 and 2 are those emissions that are owned or controlled by a company, whereas Scope 3 emissions are a consequence of the activities of the company but occur from sources not owned or controlled by it.

Ørsted: the Danish wind energy pioneer, continues to set new records. Ørsted share price in December 2022 was $93; five years earlier in 10 June 2016 it was $37. By 2030 the company’s goal is to have an installed capacity of 50GW. Ørsted is also involved with the building of two energy islands– Bornholm and North Sea– which will deliver 10GW of power.

What has set these companies apart is that they have created a huge competitive advantage which will be hard to challenge for newcomers. Moreover, they have moved well beyond simply dabbling in green energy. These companies have become specialists and now moving on to the next level: creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems. Essentially borrowing a chapter from Uber, which does not own taxis or Booking, which does not own hotels. Creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems.

How will shareholders react to  these companies in 2023?  To date there is good news and bad news for green energy companies.

Table 2: Stock market prices of new energy companies  Jan 2018- April 2023

Year Enel Engie Iberdrola Ørsted
2018 $5 $16 $7 $49
2022 $7 $16 $13 $89

Enel, the Italian power company has seen its share price increase by 40%. Engie, the large French energy giant has seen its share price remain flat . Iberdrola, the Spanish power company has had an increase of 86% and Ørsted, the Danish power company, has seen its stock soar by 82%.


Plan A : Make 2030, instead of 2050, the new deadline when renewables will command the lion’s share of its capital budget;

Plan B: If Plan A is not working then…Split the company up so that the renewables and hydrocarbon divisions (deepwater and LNG) can pursue their own strategies and directions;

Repair the splintered and diffused view of subsidiary companies—TOTALEren, Sunpower, and Saft.

Such radical measures are required if TOTALEnergies is to grow its stock market price and create real shareholder value.

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

Ghana’s Oil Firm’s  Spending Could be Reckless, Unsustainable, PIAC Warns

Ghana National Petroleum Corporation (GNPC) ’s expenditure on various line items, mainly administrative expenditure and its capital projects, witnessed significant increases by more than 200 percent in 2022, the country’s Public Interest and Accountability Committee (PIAC) has reported.

The company is spending largely on projects that are not in its remit and which are better covered by the finances of the central government, PIAC declares in its 2022 annual report.

GNPC’s continued funding of the construction of roads in the Western Corridor Enclave “constitutes quasi-fiscal expenditure, and should be the primary responsibility of central government and not the National Oil Company”, PIAC recommends in the report. “The total expenditure by GNPC on these roads since 2014 is $124.66 Million”, the report states.

“Given that petroleum revenues recorded a historic high in 2022, the PIAC recommends that GNPC should manage its expenditure and build buffers against volatilities in petroleum revenue inflows in the future”.

PIAC reiterates its call on “GNPC to focus on its core mandate and for the government to desist from borrowing or requesting GNPC to make advances and guarantees on behalf of government and its agencies”.

GEOPLEX: ‘We Are Early Movers in the New Marginal Field Development’

As part of our C-Suite Series of interviews with active leaders in Africa’s energy space, Africa Oil+Gas Report engaged WOLE OGUNSANYA, Geoplex’s founder and Chief Executive, in a long conversation. The company has taken substantial interest in a marginal field offshore Nigeria. That’s where the discussion began.

Below, Paul Kelechi Akpelu summarises the chat:

Now that you have acquired equity interest in a marginal oil field, tell us about your journey as an E&P independent; your proposition as an oilfield operator…

We have interest in one marginal oil field, which is the Indibe field. We did not go forward with the second field that we had interest in, because of the result of our evaluation. We were awarded that second field (during the bid round) but the Net Present Value (NPV) and the (development) requirements of that field didn’t look very good. So, we replied back to the Nigerian Upstream Regulatory Commission (NUPRC), to let them understand that it was too much of a burden for a small company like us to take on. But with Indibe, yes, we are part owners of Indibe because we farmed into it and we Have finished drawing up our field development programme. We actually had to take on Baker Hughes to do all these studies for us to make sure that if we invest more in this field, what we think is there, what the prognosis says will make economic sense. So, we’re into that and most likely sometimes in mid to late 2023 we will be drilling the Indibe field.

They ran double completion inside a seven-inch pipe with gas lift… and the whole thing jammed up. The well was finished. But we cut those tubings eleven times and picked them out like spaghetti to salvage that well. This is how passionate we are because this is a Nigerian thing

When should we expect First Oil?

We have been engaging with the NUPRC , reviewing all of the regulations in place that we have to meet. Part of it requires that you have your facility ready and we are offshore. This asset is in OML 67 which is owned by ExxonMobil. With the regulations that we have and the meetings that we have had with the NUPRC, they are going to allow us do what is called Extended Well Testing. It allows you test the well over a number of days and the volume, temperature, and pressure information that you gather will be used to determine or predict the production that you would have over say five to ten years. And of course, when you are doing that, you can keep and monetise the production you had during the extended well test period. That is the way we are intending to get to First Oil hopefully in 2023.

What are the maximum allowable days you could do an extended well test?

The law allows 90 days for extended well test and a one-time renewal of another 90 days.

In the past, some companies have essentially used extended well tests to produce and over the course of say two years, they keep saying they are doing extended well test.

NUPRC is focused to help us, including getting support from the multinational company that owns the OML where these fields are to deliver value. If you put in $20Million to drill a well and complete it; if you are efficient, your ability to flow that well even at a 1,000 BOPD for 90 days helps everybody. It helps you to generate some revenue and it helps you to raise finance because the banks now understand that the oil is there and that the well is completed. If you are lucky to get a renewal, after another 90 days you already have certain level of cash flow and you shut in that well and come back in another six months with the permanent facility, it makes sense. That is what the government wants, for us to get more volumes out of the ground.

There is a lot of gas in Indibe. What are you going to do with that? For a new company like yours, gas could be a bit of a challenge.

We are aware of that and we are working very closely with ExxonMobil on how to handle the gas production. There is also the Ibom Power opportunity in [that sector] and a number of people that will offtake gas in Eked. We are hoping we will offtake with ExxonMobil because it is in their field. If we are able to put the infrastructure in place and get NGL [to offtake], we could consider that for a good price as far monetising is concerned. All that gas monetisation issues we have to [solve] otherwise the project will not be viable.

Geoplex has an interest in the FPSO business and you have equity shareholding with Yinson Holding. Is Yinson Operations & Production West Africa Ltd(YOPWAL)- looking at any opportunities outside Nigeria at the moment?

Yes, we are the partner for Yinson in the country at the moment and there’s a number of FPSOs that we operate. The uptime of our FPSOs, how many days our FPSO was running without any shut down is probably the highest in the world. The FPSO partnership that we’re running with Yinson is strictly in Nigeria. Geoplex is the majority owner of the local company [but] there are other opportunities that they have within sub-Sahara Africa that could be an advantage to Geoplex and we could partake in future.

What we have with YOPWAL is strictly a relationship for Nigeria and of course in Nigeria, we’re looking for further opportunities.

Will YOPWAL  provide the FPSO for Amni’s Tubu Field?

I am not aware of that. What I can tell you without mentioning any names is that we’re looking at another client that has solicited us to provide FPSO for them based on our record that they are aware of. It is important that that end of the spectrum is handled at the highest competency level and that is what we have been able to do with Yinson.

The Nigerian  National Content Development & Monitoring Board (NCDMB) is worried that local companies like yours do not invest in research and development. What’s your take sir?

In Geoplex, we do a number of research, local simulations and we document them. This is deliberate because we have the local know how that helps us in some of our services to deliver better than the multinationals and that’s where we actually are today. There are some services that Geoplex can do better in Nigeria than any multinational company.

If you don’t build capacity, if you don’t invest in equipment, if you don’t train people, if you don’t develop, you cannot do research. There would be nothing for you to research because for you to do research, you must have certain level of know-how and what you’re doing in research is expanding that know-how in a scientific manner. It is important for indigenous companies to build our capacity to that level that we can do a lot of research within the country. In Geoplex, we’re already doing a few things in our own way. We have a test well in Port Harcourt where we simulate operations and have records that help us when we’re going to the well site to deliver those services as good as anybody in the world.

Why did you decide on acquiring a fleet of rigs, and becoming a drilling rig investor?

So that we derive value across the value chain of oil and gas services in Nigeria. It’s not the first time we will expand our portfolio of services, drilling rig is just one of them. We started as a monolithic service company providing electric wireline services, [then] we rolled into many other services: MWD, LWD, coil tubing, cementing, slake line, surface well testing and even completion. So the rigs are just one of the other services  [and] we have capacity to deliver turnkey projects on land.

One of the clients for whom we delivered turnkey projects, made a presentation at the conference of the Nigerian Association of Petroleum Explorationists (NAPE)  and declared that turnkey service is the path that Nigeria’s small field operators should be traveling  because it saves them cost, it is more efficient and it avoids a long supply chain process. This client had raised production to more than two times of what they previously had and the job we did for them, we did  within budget. If an E&P company chooses to set up a supply chain to drill one well [on its own], it supply chain department will award 33 contracts. That’s how many contracts you need to deliver that well. So you can imagine the efficiency or lack of in that system.

We are saying look, we have the rig, we have the services and here’s our international partner. We deliver this core value at double digits lower percentage than you will if you do it yourself.

We delivered in joint venture with one of our multinational partners but Geoplex rigs drilled the wells and Geoplex equipment did some of the services such as coiled tubing,  cementing and so on. We supplied all the long lead items like the pipes, the well head and installed all of that. Our partner, the international company, also carried out some of those services to deliver those wells. So, it was a turnkey JV project that we delivered.

 Who are your international partners?

We work with all the international companies in Nigeria. In the oil and gas service space, there are some technologies, some know-how that some indigenous companies have not attained, including us. The local content Act of 2010, is to ensure that we increase capacity, [but] it will take time to be there, 100 percent.

What’s your general idea of the rate of return on your investment?

The rig business is cyclical. When the price of oil is good, most oil companies in Nigeria would want to drill and get more oil but in other countries, it is really done the other way around; they drill when the price of oil is cheap because the services will be cheap from the service companies. There is nothing wrong when the prices are $80 or $90 and I drill a few more wells to get more oil because even if I’m paying a little bit more for the services, I’m also selling my oil at a reasonable price. The only thing is that because the rigs are more expensive in terms of servicing and maintenance, when the upside is there, you have to take advantage of it. When the downside comes, that depends on how you prepare yourself for that.

In Geoplex, we have learnt to take advantage of the upside and preserve ourselves on the other side. When our rig is working, the business is very profitable. Right now, we have a number of contracts that these rigs are already lined up for, apart from the work that we’re just completing.

When you deploy one of your rigs to Asa field, will it be a multi-well campaign, and how many wells are you looking at drilling and what is the time frame?

On that one, since we’ve not heard anything from the client. [But on another], we are mobilizing our 3,000-horsepower rig to Shell. Preparing a rig can take 2-3 months. The Shell contract is a contract that we have and we have signed off on. The 3,000-horsepower rig can drill a very extended well, meaning we can drill both horizontal wells and extended wells with it. When you have the spec of the rig, 1,500hp, 2,000hp or 3,000hp, it just tells you how much they can pull and the deeper you go the more you need to pull that pipe back. So, With Shell, we got this two years contract plus a possibility of one year extension and they needed that rig because they’re going for deeper wells. There are only two of those rigs in the country and we own one of them.

Baker Hughes is known, for example, for making tools for the industry. Do you envisage several Nigerian companies manufacturing a range of oilfield tools?

That’s happening today. There are actually companies that are already doing that when it comes to mechanical equipment. Even in Geoplex, we design stuff, we design crossovers and we go to machine shops in Nigeria and make them. On other high-level technology, there is not a lot going on in Nigeria yet but it is not impossible. What will make them happen [is] that you have to have a certain know how and that you must developed to a certain level, then with a little bit of research, you can raise the bar. Even Baker or Schlumberger don’t build those tools, they design them.

The beauty of the world supply chain systems is, when you do your designs, there are patents and there are agreements so that whoever you are outsourcing your design components to or the equipment that you are building are bound by that agreement. At Geoplex, we are partnering with a UAE company for some specific downhole tools, to integrate some of our equipment so that instead of having a 40ft length of equipment, we can reduce that to 10ft. In oil and gas industry, the more things you put in the well the more risk you are exposing that well to by introducing lots of junk in it all of that.

Which companies are utilising GEOPLEX’s subsurface service the most?

We’re working for everybody. We work a lot for Seplat, NDEP, (as I speak with you our team are there helping them complete a well that they are drilling right now),  Heirs Holdings. We work for Waltersmith and we are preparing to support them with some remedial work that they have with their well and we also work for Midwestern. For the multinationals, as I am speaking with you, we have more than four crews in Chevron right now, with Shell, we also have people out there working and we are preparing our rigs for them. We recently finished the work we have with ExxonMobil but we are still working for TOTALEnergies. 

If you acquire equipment, it ties down funds when nothing is happening, but you say there is a need to have that equipment yourself

Halliburton, Baker Hughes and Schlumberger have been doing this for 95 years now.  The way they have succeeded is to develop and own equipment. Of course, it is not easy to own equipment and have that equipment not put to use all the time in delivering those services for which they were bought. To compound the issue, you borrowed money to buy them and if they don’t work you don’t make the money and you need to service that debt. But if you plan and structure yourself properly, there is no other way to survive in this industry without owning equipment. The local content law was established for us to build capacity and have capacity within country to produce our oil and gas. If you don’t have equipment, you are not building capacity.

As a service provider, who your worst offenders are in terms of payments and how frustrating is it before you get your money?

People are owing us quite a lot and it is very painful because when you have debts that run into tens of millions of dollars, it doesn’t matter how strong you are because even the multinational partners that we work with, when we are not paying, they too are feeling the pain. We are always in conversation with them on how we can get the end client to pay us. We are hopeful that the PIA will help solve that though.

You had a joint bid with Baker Hughes in Angola recently, how did it go?

They were the ones that bid and asked us to support them. We are in conversation with them right now on how we can mobilise our equipment and personnel from Nigeria to go and support those operations.

How is your interest in bitumen going and what are the challenges with that?

We were invited for the bitumen opportunity, it wasn’t something that we had in our schedule. We are working with one or two state governments to see how we can support them to exploit the bitumen that they have in their states. We are at the bid round stage right now and this exercise is conducted by the Ministry of Mines and Solid Minerals Development.

This country imports about $300Million worth of bitumen every year. To exploit bitumen, you have to drill. Because it is on land and Geoplex owns land rigs, we have a major capacity to exploit bitumen. The other capacities that would be required would likely include a lot of surface processing and we have a foreign partner that can support us. So, it is for purely economic reasons and purely national reasons that we think, if we can invest in bitumen exploitation in Nigeria and make money out of it and at the same time reduce the money, we spend to import that material into the country.

Are you working with the power sector too?

We are working with the Transmission Company of Nigeria (TCN) to support some of the electricity distribution companies to upgrade their distribution capacity. This will involve building sub-stations and we already have the contract to do that and we are involved in working with them right now to see how we can place orders for some of the materials. We think we can leverage our engineering know how, our discipline, and our approach to business to make this a success.

Are you working with TCN as an enabler to them?

No as a contractor. There are three distribution companies that we are going to work with to help upgrade their distribution network.

Is that part of the Presidential Power Initiative, aka Siemens project?

No, this is a completely different arrangement that TCN made. Nigeria’s installed capacity is about 12,000MW but the production capacity is no more than 6-7,000MW because of gas availability issue. Also, within that production capacity, we could barely maintain 4,000MW. Part of the problem is caused by the distribution network because it is not robust enough to [deliver] what we are producing. As the generating companies are ramping up production, they are not able to have it distributed through the national grid and down to the end users through the sub-stations. So TCN designed a programme with the CBN and we are one of the lucky ones to win that contract.

There’s talk that Geoplex plans natural gas supply to some projects in Southwest Nigeria

We are not supplying gas. We have a growing interest in embedded power. The power sector regulations allow you to have embedded power, which means that the distribution companies [discos] can by themselves or in partnership with others, generate power within their disco network and I think the maximum power they can generate as embedded power is 10,000MW. If the national grid is not able to supply you enough power and you have your own embedded power, you would need less from the national grid. It is all about having more because we do not have enough power as a nation. Geoplex is interested in embedded power with one of the discos. We have done a lot of engineering work; feasibility studies and we have even identified the kind of turbines that we will need and the capacity that we are going to build within this disco network. We are in talks right now with the disco and we are going to site it along one of the gas routes that we have across the country.

We are working on an agreement with the Nigerian Gas Company to tap into their gas supply area in the Southwest of the country. The power that some of these big factories are using is enough to power half of Victoria Island, (an upmarket, mix residential and office suburb of Lagos). So, if I have property in VI  and there is a gas pipeline in the vicinity and I buy a piece of land along that route and secure it, go to the water front and put my micro turbine in there and hook it up to the network, VI has constant power.

Your 13 years at Schlumberger is relatively a short time. What was the trigger for you to leave?

When I joined Schlumberger, I think we were 16 in our training school and probably half didn’t make that training school and before I left, we were probably just two left in the company after 12 years. The job was extremely difficult and the attrition rate was high. Some of us had the attitude that we were going to do our job to the best of our abilities and we did. But we also thought, if they are going to ask us to go, then we were prepared to go. And of course, there was also some rule changes when I was 12 years in the company which might affect your pension. If you left at a certain time, you got a lot of money. if you left at a certain window, you didn’t get pension at all until you are 50 or 55 years old.

NNPC had formed a local content policy, the NOGIC Act of 2010. That was visionary for the national interest and the industry interest to have Nigerians carrying out these services. I got aware of it and said well, if they are going to give me the job, I am already doing it here for Schlumberger. I already manage people and I work in different countries and I have trained a lot of people. So, if the Nigerian government decided to give me this job, I was very confident that I would deliver on it. That was actually the catalyst for me to leave.


Where do you see the oil industry in the future?

Foreign subsurface service operators charge that companies like yours are pushing them out of the market.

When we were colonised by the British, they came with their cars but Nigerians did not know how to drive. So, the Britons drove the cars. Now imagine if we still don’t know how to drive today. There is going to be a time when those multinationals will not want to work in this country and that time is not going to be decided in one day; it is going to be transitioned. That is the whole purpose of the Local Content policy, to develop capacity. So, what I see is a value chain plain where we are creating value for ourselves as Nigerians and we are not pushing any multinationals out. There is a niche, there is a value space for these multinational service companies to be part of this industry and we are doing it with our partners and they are partnering more with us because they have seen that working with us also gives them value that is better than they working by themselves.

You don’t think that Schlumberger would be saying:” these guys are trying to take our job”s?

We think we can leverage our engineering know how, our discipline, and our approach to business-in the oil industry to make a success of our foray into electricity distribution sector

We work with Schlumberger and everybody else. In fact, our first partnership in the industry was with Schlumberger in electric wireline. The first contract we had with Shell was with Baker but since then we have always worked with Schlumberger on electric wireline.

In the oil and gas space, because of who we are and because of our integrity, many of them want to work with us. We partnered with Halliburton and they sold us their bulk cement plant in Escravos. Geoplex is the only Nigerian company that can do cement job in Escravos today because of the capacity that we have built. Halliburton is still partnering with us and their senior vice president has come and we have put an agreement in place. They see that there is an interest to work with Geoplex. So, it is not just with Baker, Schlumberger or Halliburton, we are also working with Weatherford in some areas. The whole purpose is that you have to ensure that your partner has a space in the value chain and you have to have the integrity that is required and the due diligence that the multinational companies are very strong about because of the laws in their home countries that cannot be violated.



Despite the Uproar, TOTAL Finally Awards EPC Contract for Uganda-Tanzania Oil Pipeline

It is done. TOTALEnergies has finally awarded the contract for the installation of the long, heated pipeline from Uganda to the Tanzanian coast.

China Petroleum Pipeline Engineering (CPP) had been one of the engineering firms on the bid to construct the 1443-kilometre pipeline from  Uganda’s Hoima district to the Chongoleani peninsula near Tanga in Tanzania’s Indian ocean coast. The company, a subsidiary of China National Petroleum Corporation, received the nod for the project’s engineering, procurement and construction.

The pipeline, named East Africa Community Pipeline (EACOP), has been the most targeted of all the several upstream and midstream projects that make up the Ugandan Lake Albert basinwide oil development, meant to unlock over 1Billion barrels of crude oil, stored in more than 15 fields in Uganda. It will ferry, at peak, up to 216,000 barrels per day of waxy crude from the Tilenga and Kingfisher clusters of fields in Uganda to Tanzania.

The EACOP has been singled out for several court cases by a wide range of activists; it has been cited as wrong by the European parliament and blacklisted by prominent banks who have declared they won’t finance it.

But TOTALEnergies has insisted it is one of the lowest carbon emitting projects in its portfolio. And what’s most crucial, the French major, with a healthy balance sheet, can fund the pipeline on its own.

‘Based on your CAPEX Performance, NUPRC May Ask You to Drill or Drop’

Gbenga Komolafe, Chief Executive of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC), spoke exclusively 
to Africa Oil+ Gas Report’s Toyin Akinosho, on a range of issues, focused on increasing the country’s hydrocarbon output.

Excerpts from the conversation…

AOGR: The NUPRC has been reported as holding new licence awardees by the hand and brokering relationships between them and financiers and suppliers and offtakers. That’s a unique engagement in the annals of the industry. How is that coming?

Commission CE: The NUPRC is putting the government’s reputation on the line in asking banks and service providers to support marginal field operators, hence the regulator wants to ensure that the companies involved in the engagements have their corporate governance framework in place before it introduces them to third parties. .Awardees Will Be Helped to Meld their Corporate Governance Framework.

The commission has midwifed the unity of the multiple awardees in each SPV, and encouraged the pulling together of funds.  We brought them together through Petroleum Prospecting Licence (PPL) but development fund needs to be sourced jointly.  Otherwise, weak ones will need to go into carry agreement voluntarily,

If funders don’t see a United front; they will be less compelled to engage he That’s why the commission developed a corporate governance framework for upstream petroleum operations currently at an advanced stage of internal review and stakeholder engagements required for its finalization.

You addressed this issue online at Schlumberger’s 70th Anniversary ….

I took the opportunity of my online address to Schlumberger’s 70th Year Anniversary Parley in Nigeria to ask the company to get on board and participate in services for newly awarded marginal fields. I was asking them to get involved in some sort of pre-export financing. As service providers, they get settled through the crude proceeds.

Schlumberger responded that they don’t do two things: 1) They don’t take equity for services (2) they don’t do commodity. I told them I appreciated the feedback and believe there is room for partnership.

Now, if they (Schlumberger) are not in the business of commodity, who is. We’d talk to Vitol, we’d talk to Trafigura. We’d get everyone around to the table. I worked with commodity traders at the time I headed the NNPC’s Crude Marketing Unit, we bring our legal background, our commercial background to the table. The lesson here is that a regulator must be multi-disciplinary.

Mini Deepwater Bid Round Terminal Date -34 companies, including four oil majors, are prequalified for the ongoing bid round for seven deepwater acreages. The bid round was inaugurated in January 2023 and the final awards were expected to be announced latest by end of April 2023

That terminal date is no longer cast in stone: We work with feedbacks and we are on an ongoing conversation with stakeholders. The Bid round was not timed to end before the exit date of the outgoing administration. There is no transition in the PIA. What the PIA says is that there should be bid rounds. If we get to a point today that we are sure that everything is going smoothly with the awardees of the last bid round, we will put out notice for another round and open the market. Let me repeat this for emphasis: We are not doing this bid round around the political transition.

There are industrywide misgivings about several operators (especially Nigerian independents)  not sweating their assets and as such contributing to dwindling output

 The commission will take operatorship of E&P assets seriously as it determines addition or subtraction to the output of hydrocarbons. We will ask companies to upload their financials on dedicated portals for economic regulation. We will discourage keeping assets stranded in our regulatory focus to optimize oil and gas production through enforcement of the drill or drop provisions of the PIA. Let us know your CAPEX on E&P projects. The PIA allows the regulator to make such an instruction. It enables the commission to measure a company’s financial viability. We want to know what Companies have committed to their assets as CAPEX.

Editor’s note: President Muhammadu Buhari approved the amendment of Deep Offshore Oil block Bid Round calendar after this interview had taken place. The president made the approval in his capacity as the Petroleum Resources Minister.

The NUPRC explained, in a statement, that the move was to accommodate the concerns expressed by both local and international investors over the closeness of the schedule to the terminal date of the present administration in the country. 

The deadline for the submission of Technical/Commercial bids was extended to May 19, 2023. The timeline for concluding activities of contract negotiations and signing is now between July 3 and 28, 2023. The outstanding activities for the conclusion of the exercise include the Technical/Commercial Bid Submission and the Ministerial Consent/Contract Negotiation and Signing. The technical/commercial bid submission involves data access, purchase, evaluation, bid preparation and submission; bid evaluation and publication of results as well as commercial bid conference and announcement of winners,” he added.

The NUPRC statement reiterated that the commission was fully committed to conducting the bid round in a manner that guarantees the achievement of the objectives of the exercise, pointing out that participation is both robust and beneficial to key stakeholders.   

Ghana Earned its Highest Petroleum Revenue in 2022, Despite a Persistent Output Decline

Total petroleum revenue accruing to Ghana in 2022 was the highest for a single year since inception of petroleum production in the country, with a figure of $1.43Billion.

The surge in earnings is in spite of continuing declining of crude oil production for three consecutive years, according to the 2022 annual report by Public Interest Accountability Committee (PIAC).

The 2022 production figure represents the third consecutive year of reduction in annual production volumes since 2010. In 2019, the PIAC explains in the report.

A volume of 71,439,585 barrels was produced in 2019, but declined to 66,926,806 barrels in 2020, representing 6.32% drop. It further declined to 55,050,391 barrels in 2021 (17.75%) and then to 51,756,481 barrels in 2022 (5.98%). The average decline over the three-year period stood at 10%.

The report laments that Surface Rental Arrears continue to rise. It increased from $2.58Million in 2021 to $2.77Million in 2022, 65% ($1.80Million) of which is owed by four (4) contractors whose Petroleum Agreements were terminated in 2021. Efforts made by the Ghana Revenue Authority to retrieve the arrears are yet to yield the desired results.

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