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How to create a winning monopoly: Become a drilling contractor!

By Gerard Kreeft

The June announcement that Noble Drilling had acquired Diamond Offshore is the latest sign that offshore drillers are finally achieving their long-anticipated goal of having a firm grip on the direction and strategy of the deepwater rig market. And perhaps for the first time also determining the pace and direction of the deepwater marketplace that originally was determined only by the oil majors.

 The Present Situation—the case of the drillers

The current floater supply has declined by 41% to 166 units from a peak of 281 in 2014. Only 16% of current supply is older than 20 years.

The Jackup supply has declined by 8% to 497 units from a peak of 542 in early 2015. 32% of current supply is 30 years old.

Seven drilling contractors–Transocean (37), Valaris (53), Noble (32), Seadrill (36), Shelf (36), Borr (24) and Diamond (12) manage or own 230 high quality assets—virtually creating a monopoly position on the deepwater market. The company that emerges from the merger of Noble and Diamond will now own or manage 44 high quality offshore drilling assets and become an industry leader. No doubt other possible mergers will follow.

Total utilization of 6th & 7th generation drillships is now 90%, an industry record: 84 units under contract, and 8 units ‘available’ and 9 ‘cold stacked’.

Deepwater rig demand has never been higher with 6th and 7th generation drillships pulling in day rates of $500,000 or more.

Before a clamor of a new cycle of rig-building ever starts, certainly those units listed as ‘available’ and ‘cold stacked’ will be brought back into the marketplace. A new building cycle is unlikely because of high costs and a lack of shipyard capacity.

The present situation—the case of the deepwater majors

Oil consumption will be 100Million barrels per day (100MMBOPD) in 2024, according to Rystad Energy.

Much of the deepwater exploration will take place within the Golden Triangle: Latin America (Brazil, Guyana and Suriname), North America (US Gulf of Mexico, and Mexico) and Africa (Atlantic Margin and South East Africa. These three regions plus the eastern Mediterranean area account for 75 percent of the global deepwater rig demand.

A key concern for the operators is the potentially reduced number of global offshore areas available for drilling and the scarcity of offshore rigs.

It is estimated that $228Billion will be spent on deepwater exploration in 2026. 75 projects will be sanctioned in 2026 compared to 27 in 2020.

Andrew Latham, Vice President Energy Research, and Dmitrii Rudchenko, Upstream Data Analyst, both  of Wood Mackenzie, in a timely July 2021  study entitled ‘Deepwater’s Growing EUR Advantage’, explain how deepwater upstream growth is expected to rise from 10Million Barrels oil Equivalent per day (MMBOEPD) in 2021(6% global supply) to over 17 MMBOEPD by 2030(10%).

Latham states that almost half of oil and gas reserves being sanctioned for development over the next 5 years will come from the deepwater. Why? According to Woodmac the out performance is based on reservoir fundamentals. Deepwater reservoirs will produce substantially more oil and gas than shallow or onshore reservoirs.

Estimated Ultimate Recovery in deepwater averages 12MMBOE for oil wells and 43MMBOE for gas wells. Future deepwater oil fields will enjoy twice the average EUR of fields already onstream.

Oil Wells

Brazil with 36Billion barrels of oil reserves has an average EUR of 14 MMBOE per well. Brazil’s early deepwater developments took place in the post-salt plays of Campos Basin where heavier crudes and drilling technologies of the 1980s limited average EUR to 8MMBOE per well. Recent investments in pre-salt in the Santos Basin is 27MMBOE per well.

Angola has 11Billion barrels of oil reserves, 1,000 wells and an average of 10MMBOE.

Nigeria has 37Billion barrels of oil reserves and an average EUR of 16MMBOE.

Guyana has 6Billion barrels of reserves and an average EUR of 24MMBOE.

Gas Wells

Gas basins are approximately half the size of oil basins. Woodmac anticipates development of approximately 1000 deepwater gas wells, of which 700(64%) have already been developed. Average EUR is 43MMBOE.

Up to 2009 the average EUR was 31MMBOE. Now the average has jumped to 90MMBOEPD based on gas discoveries in the eastern Mediterranean, Mozambique, and Mauritania and Senegal.

Woodmac anticipates that almost half of the oil and gas reserves being sanctioned for development over the next five years to be in deepwater. Exploration will doubtless add more. The sector’s outperformance stems from its reservoir fundamentals. Deepwater is no place to tackle marginal rock properties or difficult fluids. With few exceptions, the industry has chosen to develop only its best reservoirs. These allow high flow rates and exceptional estimated ultimate recovery (EUR) per well.

“The advantage versus non-deepwater is spectacular. Each deepwater well will produce an order of magnitude more reserves than development wells in shallow water or onshore. EUR in deepwater averages 12MMBOE for oil wells and 43MMBOE for gas wells. That compares with the global industry average EUR of less than 1MMBOE per well. This advantage is about to get even better. Future deepwater oil fields will enjoy twice the average EUR of fields already onstream. This is not a symptom of over-optimistic project plans overdue for a dose of reality. It reflects the industry’s recent exploration success, opening the best-performing reservoirs in new basins such as Guyana and Brazil’s Santos.”

According to the study:

”Technology gains and portfolio highgrading also help. Higher EUR means fewer wells are needed. That’s of critical importance because deepwater wells and associated subsea equipment are expensive and typically amount to more than half of project capital expenditure. Fields with fewer wells enjoy lower costs, faster cycle times and better breakeven prices.”

Scenarios facing the drillers and deepwater majors

Woodmac’s June 2023 study “Does the bull market in oil rigs signal a slower transition?”,raises some timely questions:

  • …” a persuasive argument in favour of new builds. The latest eighth-generation rigs can deliver in ultra-deepwater, improve drilling efficiency and reliability, and help meet the industry’s goal to reduce emissions. We reckon current rig rates support new build economics.”
  • …” while we expect to see some new orders, there are plenty of reasons why this upcycle will be more restrained than those of the past. As drilling costs rise, we expect operators will delay investment and reconfigure less advantaged new projects.”
  • “Drilling companies, for their part, will be loath to commit to new builds without long-term contracts, which operators are reluctant to offer. Many rig owners will continue to manage and enhance margins on their existing fleet, while taking the lower-risk option of reactivating the most capable and viable stacked rigs under firm contracts.”
  • ..”the industry’s appetite for drilling will be tempered by uncertainty around future demand. Deepwater exploration wells drilled in 2023 will, if successful, lead to new oil supply around 2030 with payback from perhaps 2035, at best. Investment horizons for deepwater gas exploration are even longer dated.”

Woodmac expects global oil demand to peak in the early 2030s in their base case (approximating a 2.5 °C pathway), gas demand a decade later. However, in the AET-1.5 (accelerated energy transition) scenario), the peak for both comes much earlier.

Woodmac concludes that  rig market is a warning that the energy transition is moving slower than what is needed to limit temperature increases to below 1.5 °C.

 Some Final Questions/Comments

Will dayrates for drillships and other units  continue to skyrocket beyond the $500,000 ceiling?

Can drilling contractors resist starting a new cycle of newbuilds, which in the past helped send the dayrates in a downward trajectory?

Will the drilling contractors and the operators learn to co-commit to ensure that this important sub-market will survive?

The deepwater market is a highly specialized market with its own set of economic drivers: set within the Golden Triangle, consuming a sizeable chunk of exploration budgets and manpower and requiring years of project planning for project realization. Within this setting can deepwater activities continue to be economically feasible in competition with renewable and possibly provide competitive energy costs?

Only if deepwater drilling can show its economic return is competitive with renewables can it survive in the short and medium term.

Will the deepwater market survive the looming energy transition? Much will depend on how the industry reacts within the coming decades.

 Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe.  Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis). His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition


NNPC to Hold 70% of the JV as the ExxonMobil/Seplat Transaction Comes to a Close

Nigeria’s state hydrocarbon company NNPC Ltd will keep 70% of the stake in the resulting Joint Venture, when the sale and purchase transaction between ExxonMobil and Seplat Energy is concluded, expectedly in the next two to three months.

Seplat Energy will be operator.

This is the compromise position of the negotiating parties, two years and three months after ExxonMobil and Seplat Energy separately announced the $1.28Billion purchase, by the latter, of Mobil Producing Nigeria Unlimited (MPNU), the entire operated offshore shallow water business of ExxonMobil in Nigeria.

It is the outcome of NNPC’s blocking of the sale and purchase, enforced by a court injunction. In the event, the Minister of Petroleum Resources, on the recommendation of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC), had withheld consent and there have been arbitration proceedings.

Unblocking the Sale and Purchase

NNPC and ExxonMobil announced, on Thursday, May 30, 2024, that they had signed a settlement agreement deal on the transaction between Mobil Producing Nigeria Unlimited to Seplat Energy Offshore Limited. Translation: NNPC’s obstruction of the sale and purchase has been annulled.

“Settlement agreement between NNPC Ltd. and Mobil Producing Nigeria Unlimited, Mobil Development Nigeria Inc., and Mobil Exploration Nigeria Inc. signed regarding the proposed divestment of a 100% interest in Mobil Producing Nigeria Unlimited to Seplat Energy Offshore Limited,” NNPC  Ltd. noted in a statement.

With this settlement agreement, ExxonMobil and Seplat can now formally approach the Nigerian Upstream Regulatory Commission (NUPRC), to seek the consent of the Federal Government.

The proposed NNPC – Seplat 70: 30 Joint Venture would be the highest stake by the Nigerian state in a JV producing asset since the government reduced its 80% share in the Shell NNPC Joint Venture to 55% in 1989, to incentivize international partners (Shell, TOTAL and ENI) for the Nigerian Liquefied Natural Gas project.

The assets involved in the Seplat purchase of MPNU are four Oil Mining Leases, (OMLs) 67, 68 70 and 104, as well as the Qua Iboe Terminal, one of Nigeria’s largest export facilities; 51% interest in the Bonny River Terminal and Natural Gas Liquids (NGL) Recovery Plants at the East Area Additional Oil Recovery Project (EAP) and the Oso condensate project.

A 70% share of NNPC in the NNPC/MPNU JV will be clearly against the grain: the widely held opinion is that NNPC Ltd will, indeed, be selling down stakes in the 57 acreages in the Niger Delta in which it is a JV participant.

NNPC holds between 55% and 60% in Joint Ventures in assets that deliver over 80% of Nigerian production. A plan has always been on the table, to sell in such a way that NNPC becomes a less than 50% partner in each of those acreages.  The state hydrocarbon company’s commercial relationships with its partners in these assets have been fraught over the years; where it is the passive partner, it has struggled to pay its cash calls. And its “senior partnership” status has been the reason, critics argue, for the underperformance of these assets, and the ruinously long contracting cycle, of over four years on average, for projects.

Indeed, a multi-phase proposal by a Policy Advisory committee, constituted (then President elect) Bola Ahmed Tinubu, in May 2023, estimated that NNPC’s sell-down of its stakes in the JVs, could pull in close to $34Billion into the Nigerian treasury over five -six years, “if the transaction is properly and professionally managed”.

An initial request by the NNPC, was to take 100% of OML 104 and allow Seplat keep 40% plus operatorship of OMLs 67, 68 & 70. NNPC Ltd changed its mind on that course.

This story was originally published in the March 2024 edition of the Africa Oil+Gas Report. The only addition here is the summary of the statement of settlement.

 


Nigeria’s 2024 Bid Round Continues Roadshow:  NUPRC Releases Time Table, to Wrap Up Q1 2025

The Nigerian Upstream Petroleum Regulatory Commission (NUPRC )’s International Road Show  moved to Miami, in the state of Florida, in the United States on May 14 2024, a week after the agency launched the US leg of the licencing round at the Offshore Technology Conference in Huston.

NUPRC is offering 12 blocks in its second licencing round in 15 months. The commission says that  in addition to these blocks, the seven deep offshore blocks from the 2022/2023 mini-bid round exercise shall also be concluded, bringing a total of 19 oil blocks offered to investors in 2024.

The 2022/2023 ultradeep water mini bid round, which was launched with fanfare in January 2023, was to conclude in July 2023 but was held up by lack of response from the new executive administration which came into power in May 2023.

“The Roadshow  is needed to showcase and provide insight into new investment opportunities in Oil and Gas Exploration in Nigeria”, the regulator remarks in its promotional material, adding that the core objectives were to: “release the requirements for qualification;  present avenues for new business and partnership opportunities; provide exclusive information, data, teasers of oil licenses in proposed 2024 bid rounds; highlight the hydrocarbon potential of the blocks and existing data packages; establish legal, fiscal and contractual framework and commercial terms and ease matchmaking between country representatives and NUPRC”.

The regulatory agency has released a Time Table for the bid round, which notes that registration/submission of Pre-Qualification documents is currently ongoing and will end on June 25, 2024.

A Pre-Bid Conference, scheduled for May 28, 2024 in Lagos, has been postponed. Evaluation of submissions/publication of prequalified applicants are scheduled to run from June 28 to July 2, 2024.

Technical and Commercial Bid: July 4-December 13, 2024– Data access, data purchase, evaluation, bid reparation and submission are scheduled to run from July 4 to November 29, 2024. Technical bid evaluation, publication of pre-qualified companies will run from December 2, 2024 to December 9, 2024. Commercial bid conference will hold on December 13, 2024.

Ministerial Approval/Contracting: December 16 2024 to January 29, 2025-Ministerial approval of awardees, December 16, 2024 to December 20, 2024. Contract negotiation and signing: December 20, 2024 to January 10, 2025. Award of Licence: January 12, 2025 to January 29, 2025.

Nigeria holds 36.966 Billion Barrels of Oil, which ranks her 2nd in Africa, 8th in OPEC and 11th in the world, the NUPRC promotional material explains. “Nigeria is also richly endowed with 208.83 Trillion cubic feet (Tcf) of Natural Gas reserves with upside potential estimated at 600 Tcf”.

Find below, the full schedule of events in the bid round calendar:

 


Sonatrach Inks MoU with ExxonMobil on Exploration Studies in two Basins

Algeria’s state hydrocarbon firm Sonatrach has signed a memorandum with ExxonMobil to explore opportunities in the Ahnet and the Gourara basins in the south of the country.

It’s a preliminary agreement, jointly signed in Algiers by Rachid Hachichi, Sonatrach’s chief executive and John Ardill ExxonMobil’s head of exploration. The deal did not give a figure for the scale of the investment or for the potential reserves in the two basins.

Sonatrach has recorded one undeveloped gas discovery each in the two basins: OTS-2 (Oued Tesa Araret-2), located on the perimeter Tidikelt (Block 338a) in the Ahnet Basin and TNK-1 (Tinerkouk-1) well on the perimeter Hassi Mouina (block 321b) in the Gourara Basin.

The state-owned firm had a 100% stake in the OTS-2 in the Ahnet Basin at the time of the discovery. It produced gas from two reservoir formations encountered at depths of less than 1200 metres. The gas flows on a 32/64″ choke were respectively 9743 cubic metres per hour with a wellhead pressure of 1280 psi and 5737 cubic metres per hour with a pressure of 682 psi, according to a Rigzone report.

The TNK-1 (Tinerkouk-1) discovery in the Gourara Basin was made in partnership with StatoilHydro. The well produced gas from the Carboniferous reservoir about twenty meters thick. The gas flow were approximately 6971 cubic metres per hour with a pressure of 1109 psi on a 32/64″ choke. This well is.

The new agreement is symbolic in the sense that it is with an American supermajor. Sonatrach. After struggling to attract interests from international majors since its Hydrocarbons Laaw of 2005, which has now been extensively reviewed in the last five years, Sonatrach had managed to W win over European players including ENI and TOTAL. This deal with ExxonMobil,  “opens up new development prospects for the Algerian mining sector and demonstrates the willingness of both companies to establish responsible and sustainable exploitation of natural resources”, says Hachichi.

Ardill said ExxonMobil would contribute its “cutting-edge capabilities” and said the agreement was a “first important step in creating a partnership that will further unlock the development potential of Algeria’s resources”.

 

 


Afentra Now Holds a Decent Minority Stake in Angola’s ‘Block 3/05 Series’

Angolan authorities have approved the purchase, by Afentra Plc, of a 12% non-operating interest in the country’s Block 3/05 and a 16% non-operating interest in the country’s offshore Block 3/05A.

The approval is pursuant to the agreement between Azule Energy Angola Production B.V. and Afentra’s wholly-owned subsidiary, Afentra (Angola) Ltd.

The sale and purchase were announced on the July 19 2023, so the process of ministerial consent has taken 10 months.

“The Azule acquisition increases Afentra’s interest in Block 3/05 to 30% and in Block 3/05A to 21.33%, with payable cash consideration at completion of $28.4Million”, Afentra reports.

The initial cash consideration of $48.5Million was reduced by impact of cash flow adjustments as of the transaction effective date of 1 October 2022.

Afentra announced that the combined gross production for the first four months of 2024 ending 30 April 2024 for Blocks 3/05 and 3/05A has averaged ~23,000BOPD (Net: ~6,800, BOPD).

The company has inherited, from the transaction, crude oil stock amounting to 480,000 barrels.

Afentra also disclosed its financial position on completion of the acquisition o Net Debt is expected to be $46.2Million with Crude oil stock of around 840,000barrels.

The Light Well Intervention programme, commenced by the joint venture during 2023, continues into 2024 with a further 45 interventions planned over two campaigns. Lifting Update The Company expects to sell its next cargo of crude oil (~450,000 barrels in June 2024.

“The completion of the Azule Acquisition is the final step in the complex process of acquiring a material equity position in both Block 3/05 (30%) and Block 3/05A (21.33%) through three separate transactions”, Afentra explains in a statement.

“As with the previous two transactions the acquisition structure ensures that Afentra benefits from the net cash flow from the assets while working through the completion process, significantly reducing the cash payment at completion”.

 


Nigeria’s 2024 Bid Round Continues Roadshow:  NUPRC Releases Time Table, to Wrap Up in December

The Nigerian Upstream Petroleum Regulatory Commission (NUPRC )’s International Road Show  moved to Miami, in the state of Florida, in the United States on May 14 2024, a week after the agency launched the US leg of the licencing round at the Offshore Technology Conference in Huston.

NUPRC is offering 12 blocks in its second licencing round in 15 months. The commission says that  in addition to these blocks, the seven deep offshore blocks from the 2022/2023 mini-bid round exercise shall also be concluded, bringing a total of 19 oil blocks offered to investors in 2024.

The 2022/2023 ultradeep water mini bid round, which was launched with fanfare in January 2023, was to conclude in July 2023 but was held up by lack of response from the new executive administration which came into power in May 2023.

“The Roadshow  is needed to showcase and provide insight into new investment opportunities in Oil and Gas Exploration in Nigeria”, the regulator remarks in its promotional material, adding that the core objectives were to: “release the requirements for qualification;  present avenues for new business and partnership opportunities; provide exclusive information, data, teasers of oil licenses in proposed 2024 bid rounds; highlight the hydrocarbon potential of the blocks and existing data packages; establish legal, fiscal and contractual framework and commercial terms and ease matchmaking between country representatives and NUPRC”.

The regulatory agency has released a Time Table for the bid round, which notes that registration/submission of Pre-Qualification documents is currently ongoing and will end on June 26, 2024.

2022-2023 Ultradeepwater Offerings are included

A Pre-Bid Conference is scheduled for May 25, 2024 and Evaluation of submissions/publication of prequalified applicants are scheduled to run from Jun 28 to July 2, 2024.

NUPRC will invite selected companies to participate in the licencing round on July 4, a process that is scheduled to end on July 8. The commission will then open up its portals for data access/ data purchase/evaluation/bid preparation and submission. That process will last for more than three months from July 8 to October 15, 2024.

Nigeria holds 36.966 Billion Barrels of Oil, which ranks her 2nd in Africa, 8th in OPEC and 11th in the world, the NUPRC promotional material explains. “Nigeria is also richly endowed with 208.83 Trillion cubit feet (Tcf) of Natural Gas reserves with upside potential estimated at 600 Tcf”.

Find below, the full schedule of events in the bid round calendar:


Savannah Moves to a Fuller Control of Stubb Creek Oil Field

Savannah Energy, a UK minnow, has signed separate Share Purchase Agreements (SPAs) with Sinopec International Petroleum Exploration and Production Corporation (SIPEC) and Jagal Ventures Limited (Jagal) to acquire 100% of the outstanding share capital of Sinopec International Petroleum Exploration and Production Company Nigeria Limited

SIPEC’s principal asset is a 49% non-operated interest in the Stubb Creek oil and gas field, located onshore Akwa Ibom State, Nigeria. “An affiliate of Savannah, Universal Energy Resources Limited, is the 51% owner and operator”, Savannah explains.

Savannah holds 62.5% equity interest in Universal Energy. A take over of SIPEC will see Savannah controlling Stubb Creek field, a marginal hydrocarbon accumulation which produces 2,700Barrels of Oil Per Day (BOPD).

“The SIPEC SPA will see Savannah Energy SC Limited (a wholly owned subsidiary of Savannah) acquire a 75% equity interest in SIPEC for cash consideration of $52Million, payable on completion and subject to customary adjustments for a transaction of this nature from 1 September 2023”, Savannah notes in the release..

The Jagal SPA will see Savannah Energy SC Limited acquire a 25% equity interest in SIPEC for cash consideration of $7.5Million (without adjustment), payable on completion, plus $2Million in deferred cash consideration payable in eight equal quarterly instalments post-completion. The transaction consideration is expected to be funded through a new bank debt facility arranged by The Standard Bank of South Africa Limited and the existing cash resources of the Company. Completion under each of the SPAs is subject to the parties’ satisfaction of customary conditions precedent, including certain regulatory approvals, as well as a mechanism ensuring that completion under both SPAs occurs simultaneously.

As at year end 2023, SIPEC had an estimated 8.1MMstb of 2P oil reserves and 227 Bscf of 2C Contingent gas resources. SIPEC oil production is estimated at an average for 2024 of 1.4 Kbopd. Savannah’s Reserve and Resource base will increase by approximately 46 MMboe following completion of the SIPEC Acquisition.

Savannah says it anticipates that, within 12 months following completion of the SIPEC Acquisition, Stubb Creek gross production should increase by approximately 2.7Kbopd to approximately 4.7KBOPD through implementation of a de-bottlenecking programme.

 


With $64Million To Spare, AOC Aims for More of Namibia’s Pie

By Toyin Akinosho

Africa Oil Corp. has offered to acquire from minority shareholders in Impact Oil and Gas Limited up to 8.0% of the issued shares in Impact.

This is expected to lead to AOC holding 39.1% of Impact, as the former currently holds a 31.1% shareholding in the latter.

The move, announced March 18, 2024, is the kind of transaction that any small producing independent, with some decent cash flow, should pay some attention to.

The significance of the proposed buy is derived from Impact’s 19.5% stake in Blocks 2912 and 2913B, the two Namibian offshore leases where the French major TOTAL has discovered the giant Venus field and adjoining accumulations.

With 39.1% holding in Impact, AOC will have around 7.8% of these two acreages.

But we are getting ahead of ourselves.

TOTAL is in the process of concluding a farmin into Impact ‘s stakes in these acreages, a transaction which, when concluded, will leave Impact with 9.5% of these two blocks. The farmin is awaiting the consent of Namibian authorities.

Should that be consummated, and should AOC conclude the 8% acquisition, AOC will have around 3.9% of Blocks 2912 and 2913B.

TOTAL’s Venus accumulation (two billion barrels of oil equivalent recoverable reserves) has moved up the scale of the most likely-to-be -developed of all the several discoveries made in Southern Africa in the last four years.

AOC says that the Offer it is making is at a price of $ 0.728 per Impact share, for a consideration of up to approximately $64Million, which implies a valuation of USD 805 million for 100% of the issued share capital of Impact.

“The share purchase is conditional upon completion of the farm down transaction for Impact’s Namibia assets announced on January 10, 2024. The Offer is made to select minority shareholders and is open for acceptance until April 5, 2024. Africa Oil is under no obligation to purchase any specific number of shares in Impact”.

Roger Tucker, AOC Chief Executive Officer, commented: ” At no upfront cost, we retain exposure to the Venus development, and to the significant follow-on upside potential on Blocks 2912/2913B. Venus is expected to add significant reserves and production to Africa Oil’s portfolio from the late 2020s through the 2030s”.

 

 


TOTAL Takes More Stake in South Africa as It Sweeps for Region wide, “Greater Venus” Development

By Toyin Akinosho

French major TOTALEnergies has grabbed more stake in the South African part of the prolific Orange Basin, in a quest for accelerated appraisal to unlock a commercial project at the field perimeter of the Venus discovery offshore Namibia and encompassing South Africa.

The European giant signed, together with its partner QatarEnergy, an agreement to acquire participating interests in Block 3B/4B, offshore South Africa, from Africa Oil Corp., Azinam (a wholly owned subsidiary of Eco Atlantic Oil and Gas) and Ricocure.

The transaction is coming less than three months after the company took more share in the Namibian part of the same basin.

Just like its last grab in Namibia TOTAL is taking these South African interests along with its partner, Qatar Energy.

The deal had been widely anticipated for some time by analysts. Africa Oil Corp., Eco Atlantic and Ricocure belong to a class of companies who, as a rule, acquire assets and work towards wooing well-heeled companies like TOTAL, to purchase, large, operating stakes in those properties. In effect, these companies treat hydrocarbon assets, in frontier basins, as items of real estate.

Following completion of the transaction, TOTALEnergies will hold a 33% participating interest in Block 3B/4B and assume operatorship, while QatarEnergy will hold a 24% interest.

The remaining interests will be held by existing license holders, Africa Oil (17%), Ricocure (19.75%) and Azinam (6.25%). The transaction is subject to final approvals from relevant authorities.

In Namibia in November 2023, TOTALEnergies s signed an agreement to acquire an additional 10.5% participating interest in block 2913B and an additional 9.39% participating interest in block 2912, from Impact Oil and Gas.

THE INSPIRATION FOR TOTAL’S CONTINUOUS GRAB of assets in both countries, is the Venus discovery and its adjoining prospective enclave.

The 2Billion Barrel (recoverable oil equivalent reserves) Venus accumulation, stored in 3,000metres below the seabed in the South Atlantic Ocean, has inspired, for TOTAL, a regionwide exploration and appraisal strategy in Southern Africa.

TOTAL said  at the Africa Energy Week in November 2023 that it would acquire new seismic data and drill several appraisal wells as well as exploratory upsides.
“Venus has opened a new chapter in TOTALEnergies exploration, with very significant running room over our vast exploration acreage in the area”, said Clement Fleury, lead author of a geoscience paper focusing on the follow up of the play opening discovery.
The company also said it would be launching a regional exploration drilling programme “in the coming years in both Namibia and South Africa”.
Mr. Fleury’s paper added that TOTAL  was working on “intensive exploration and appraisal efforts on blocks 2912 and 2913b in Namibia and taking advantage of its leading acreage position in South Africa”, to sweep the region for leads, prospects and developments.

Located within the prolific Orange basin, 200 km off the western coast of South Africa, Block 3B/4B covers an area of 17,581 km2. Block 3B/4B is adjacent to the DWOB license operated by TotalEnergies (50%) alongside QatarEnergy (30%) and Sezigyn (20%).

“Following the Venus success in Namibia, TotalEnergies is continuing to progress its Exploration effort in the Orange Basin, by entering this promising exploration license in South Africa”, said Kevin McLachlan, Senior Vice-President Exploration of TOTALEnergies.

 


Gabon Formally Takes Over Carlyle’s Assets, Elbows Out M&P

By Toyin Akinosho, in Lagos

The Government of Gabon, after exercising pre-emptive rights over the sale of all of Carlyle owned Assala Energy’s E&P assets in the country to Maurel et Prom (M&P), has finally signed a formal sales and purchase agreement with the latter.

So, it’s done.

The transaction was sealed February 15, 2024, between the state hydrocarbon firm,  Gabon Oil Company (GOC) and Assala Energy Investments Ltd. (Carlyle) regarding GOC’s acquisition of Assala Energy Holdings Ltd and all of its subsidiaries“.

M&P no longer has any line of sight to those assets again. They belong to the Gabonese government.

“This signing has occurred in the context of GOC’s sovereign right of pre-emption”, M&P says in a  statement released  February 16, 2024, “and supersedes the SPA signed by M&P and Carlyle on 15 August 2023”.

The Paris headquartered, Indonesian independent first informed the market of its move to take over Assala’s assets in June 2023, announcing it as a “possible offer for Assala Energy Holdings Ltd”.

M&P reported at the time: “Assala is an onshore oil upstream and midstream company in Gabon with working interest production of approximately 45,000Barrels of Oil Per Day (BOPD)  in 2022”. That volume of crude was extracted from some of six production licences that Assala had operated in Gabon since it entered the country in 2017.  The then proposed acquisition also included a non-operator interest in one production licence, as well as three onshore exploration licences also in Gabon, held since 2019.

M&P says it “confirms and reiterates its wish to remain a trusted partner of the Republic of Gabon, as evidenced by its presence and its projects in the country for nearly 20 years now”.

The company insists it is in a very healthy financial position, “with an expected net cash position at the end of March 2024 (approximately $270Million in cash and cash available, versus $266Million in gross debt), and significant borrowing capacity”.

The planned take over of over 40,000BOPD output in Gabon was meant to increase M&P’s stakes in Central Africa and boost the company’s Pan African Asset base. M&P holds 20% of Seplat Energy in West Africa (Nigeria) and in East Africa (Tanzania), it has recently acquired 20% of the 107Million standard cubic feet per day Mnazi Bay asset, through the purchase of some of the shares of Wentworth Resources, its partner in Mnazi Bay.

 

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