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With TOTALEnergies’ Purchase, Chappal Clinches the Second Set of E& P Assets in Niger Delta

By Marshal Gungubele, in Lagos

The Nigerian E&P independent Chappal Energies has again been announced as the beneficiary of a divestment of upstream assets by a major European company.

Seven months after the news broke, of the sale of Equinor Nigeria Energy Company (ENEC) to the company, TOTALEnergies has announced the sale of 10% of its equity in Shell operated onshore and shallow water assets to the same firm.

The size and quality of the two sets of assets are significant.

The sale of Equinor Nigeria Energy Company (ENEC) involved a 53.85% ownership in Oil Mining Lease (OML) 128, including the unitised 20.21% stake in the Agbami field, operated by Chevron. That deal was announced in November 2023 and it is close to approval by the Nigerian authorities. With 92,000Barrels Per Day in June 2024, Agbami is the second largest producing field in Nigeria, after Bonga.

The sale of TOTALEnergies’ 10% interest in the Shell Petroleum Development Company (SPDC) JV licenses in Nigeria to Chappal Energies, announced July 17 2024, involves:

  • All TOTALEnergies’ rights and obligations in 15 licenses of SPDC JV, which are producing mainly oil. Production from these licenses represented approximately 14,000Barrels equivalent per day in Company share in 2023.
  • 10% participating interest in the three (3) other licenses of SPDC JV which are producing mainly gas (OML 23, OML 28 and OML 77). In this case, though, TOTALEnergies will retain full economic interest in these licenses, which currently account for 40% of Nigeria LNG gas supply.

The transaction was concluded for a firm consideration of $860Million. Closing is subject to customary conditions, including regulatory approvals.

SPDC JV is an unincorporated joint venture between Nigerian National Petroleum Corporation Ltd (55%), Shell Petroleum Development Company of Nigeria (30%, operator), TOTALEnergies EP Nigeria (10%) and NAOC (5%), which holds 18 licenses in the Niger Delta.

Chappal Energies, a relatively new company, had come up among the top three bidders of two of the most prized upstream assets up for grabs in the Nigerian market in the last four years. In the event, it had won the two bids.

What’s in a name?

  • Chappal Petroleum Development Company (CPDC), (not Chappal Energies), created in 2020, made it to being the reserve bidder for the Nigerian shallow-water oil blocks that ExxonMobil agreed to sell to SeplatEnergies in February 2022.
  • Chappal Energies, registered in Mauritius in 2022, is the company that has won the two bids, to purchase the entire shares of Equinor Nigeria(November 2023) and TOTAL’s 10% in the SPDC/TOTAL/NAOC/NNPC Joint Venture (July 2024).

Our understanding from market sources is that Chappal Petroleum Development has no longer been active, since Ufoma Immanuel and Victor Imevbore, the company’s core founders and directors, stepped down in 2022. Immanuel and Imevbore are, however, both directors of Chappal Energies.

Austin Avuru, former CEO of SeplatEnergies, was Chair of Chappal Petroleum Development when it bid for ExxonMobil. But he is not involved in Chappal Energies, as he has cast his lot with the Platform Petroleum/Pillar Oil Consortium.

The Chappal brand, whether it be Chappal Petroleum Development or Chappal Energies, has shown that it could handily win a keenly competed, prized upstream asset bid, in Nigeria.

This piece is updated from our piece Watch these Chappals, published in the November 2023 edition of the paid monthly Africa Oil+Gas Report.


Norwegian Player Moves to Grab a Piece of ReconAfrica

Oslo headquartered BW Energy has signed a Letter Agreement with Reconnaissance Energy Africa Ltd (ReconAfrica) to acquire approximately 16.8Million common shares and 16.8Million warrants for a total consideration of $16Million in ReconAfrica’s announced equity raise.

By participating in the equity raise, BW Energy will also receive a 20% non-operating interest in the onshore Petroleum Exploration License 73 (PEL 73) where ReconAfrica will provide BW Energy with a carry of $6.4Million based on the intended initial work programme.

BW Energy has also committed to certain contingent payments to ReconAfrica based on specific field development milestones.

PEL 73 is located in northeast Namibia, covering an area of approximately 25,341 sq km. Two exploration wells are planned to be drilled in the Damara Fold Belt Basin in the second half of 2024.

The wells are targeting a combined un-risked resource potential of 489Million barrels of oil based on the most recent prospective resource report by Netherland, Sewell & Associates Inc. (NSAI). After the two initial exploration wells, the partnership plans a three dimensional 3D seismic survey of the Kavango Rift Basin in the second half of 2025, which may result in two additional exploration wells.

“The transaction will enable BW Energy to expand its footprint in a strategically important energy region and further our position as a leader in Namibia’s development towards energy independence,” said Carl Krogh Arnet, the CEO of BW Energy. “The data and insights gained through ReconAfrica’s exploration campaign will further our understanding of the geology and petroleum system in Namibia and help de-risk planned exploration and development of our Kudu license.”

The common shares are priced at CAD 1.30 per share. The warrants have a validity of 24 months and are priced at CAD 1.70 per warrant. If specific milestones are met, BW Energy has agreed to further contingent payments to ReconAfrica of up to $125Million as specified below:

  • $22.5Million upon final investment decision of a commercial development
  • $22.5Million 365 days after first oil
  • $5Million 60 days after first sale of commercial hydrocarbon production
  • $25Million upon BW Energy achieving total cumulative Free Cash Flow (“FCF”) of $ 300Million
  • $25Million upon BW Energy achieving total cumulative FCF of $ 600Million
  • $25Million upon BW Energy achieving total cumulative FCF of $ 900Million

The completion of the transaction is subject to the parties entering into a definitive agreement and the fulfilment of customary conditions precedents.

 


Angola Plans to Offer 10 More Blocks in 2025 Bid Round

Angola has joined Egypt in perennial offloading of acreages on the market.

The country’s National Oil, Gas & Biofuels Agency (ANPG) has announced it will launch a limited tender in Q1 2025, offering 10 blocks in the Kwanza and Benguela Basins – including five marginal fields ­–described as a first for the country by the African Energy Chamber (AEC), the advocacy group for investment in the continent’s hydrocarbon resources.

The ANPG has opened negotiations for participation in the upcoming licensing round and companies are invited to contact the regulator ahead of the official licensing launch.

Angola’s 2025 limited tender will feature Block 40, Block 25, Block 39 and Block 26 in the Benguela Basin as well as Block 22, Block 35, Block 37, Block 38 and Block 36 in the Kwanza Basin. Additionally, the country has four onshore blocks available; 11 blocks on permanent offer; and five marginal fields ready for exploration. The marginal fields are situated in producing blocks with proven systems and can be awarded individually. Companies that demonstrate interest will receive an invitation letter once the 2025 tender launches.

Angola holds 10Billion barrels of crude oil in reserves, less than a third of Nigeria’s, but has been close to being head-to-head with the West African country, in terms of production. It has averaged around 1.1Million Barrels of Oil Per Day (1.1MMBOPD) in the last two years, some 200-300,000BOPD shy of Nigeria’s 1.3-1.4MMBOPD in the same period.

And there was a time Angola threatened to overtake the more populated, larger economy, in output. Between 2008 and 2010, Angolan production cruised to 2MMBOPD, at a time when Nigerian output was around 2.5MMBOPD. Both were not sustained.

Angola’s response to the sharp decline, which is caused by field maturation, is to opt for frequent bid rounds. “We have been implementing a series of reforms. We approved a strategy in 2019 to license more than 50 blocks by 2025”, says Alcides Andrade, Board Member of the Angolan National Agency of Petroleum, Gas and Biofuels (ANPG). “So far, we have executed four licensing rounds and awarded more than 30 new concessions. We have another one planned for 2025 where we are projecting to put up another ten blocks offshore,”

Angolan officials were excited, and they announced the event all over the media, when output reached 1.2MMBOPD on June 12, 2024. But production has dropped again.

“The plan is to do everything we can to keep production above one million bpd”, Andrade explained. “We have a diverse range of opportunities for different size companies as well as opportunities in onshore blocks, shallow waters and deepwater opportunities.”

 

 


Angola’s Oldest Upstream Hydrocarbon Producer Adds Two More

By Sully Manope, in Windhoek

US major Chevron has won the final approval of Angolan authorities to operate two more acreages in the country.

By signing risk contracts on Blocks 49 and 50 with the regulator ANPG, and the state hydrocarbon company Sonangol P&P, the San Ramon, California based firm holds four licences, including the shallow water Block O, and the deepwater Block 14.

It’s the farthest deepwater that Chevron has ever gone in the southwest African country.  Blocks 49 and 50 are located in water depths from 2,200metres to 3, 600metres. That’s incomparable with the 400metre to 1,700metre water depths for Block 14, Chevron’s only operated deepwater block in Angola.

“These two Blocks are located in the ultra-deep waters of the Lower Congo Basin and, due to the geological conditions, present increased operational complexity, associated with a high research risk, which is the reason that led to the signing of risky service contracts”, the ANPG says in a press release.

Cheron’s first drilling in Angola was onshore, at Ponta Vermelha, in 1958. The company’s offshore discovery was made in 1966 on the Malongo Field, followed by first oil in 1968. The Takula Field was later discovered in 1971.

Although there hasn’t been exploration yet on the new blocks, let alone clarity for field development, ANPG claims that “the investment in each of these blocks is valued at 3.6Billion dollars, with each of these expected to blocks will produce around 200 thousand barrels/day”.  The Angolans are incurable optimists.

Diamantino Azevedo, the country’s Minister of Mineral Resources, Oil and Gas, challenged Chevron and Sonangol “to complete the exploration stage in record time and thus reach the production phase with additional milestones”.  He made the call, he said, “not because we think it will be an easy task; rather because we believe in your maturity and technological mastery, combined with the long history of achievements in the Angolan oil sector.

“We are aware that Blocks 49 and 50 are located in areas with high research and operational risk, due to the geological conditions in this area of ​​the Lower Congo Basin. Tax incentives are more than justified”, he stressed.

 


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:

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