ExxonMobil and partner Sonangol E.P. are about to boldly go where no man has gone before (that’s the last Star Trek quote I promise), as it gears up to spud the highly anticipated Arcturus 1 NFW in the frontier Namibe Basin, offshore southern Angola. After initially being slated for late 2024, the Valaris DS-9 drillship became available earlier than anticipated and arrived onsite on Block 30, in >2,000m water depth, on 23 July 2024.
ExxonMobil has remained tight-lipped on the play type for Arcturus (named after the fourth brightest star in the night sky). However, with Azule Energy targeting oil in the Early Cretaceous, pre-salt carbonates of the Piambo prospect in H2 2024/2025 on Block 28, located >100km north in the Namibe Basin, there is an increased likelihood of a similar carbonate structure being targeted with Arcturus 1.
The US major signed the Risk Service Contracts (RSCs) for adjacent Blocks 30, 44 and 45 in October 2020. The government has amended the terms of the RSCs to incentivise exploration on the frontier blocks. This includes a deduction of the 40% investment premium on the petroleum income tax for the licences, as well as eight-year exploration periods (extended from six years).
Blocks 30, 44 and 45 have never previously been licensed, with two ODP wells on Block 45 constituting the only prior drilling in the area. PGS (now TGS ) completed a 14,013 sq km MC3D seismic survey over the blocks in August 2020. Across the border in Namibia, ExxonMobil also operates the underexplored PEL 86, PEL 89 and PEL 95 licences in the Namibe Basin. This acreage contains Sintezneftegaz’s Kunene 1 NFW (2008, 5,052m TD, 772m WD, P&A gas shows) and Chariot Limited ’s Tapir South 1 NFW (2012, 4,879m TD, 2,134m WD, P&A dry). Despite the failure of this earlier round of Cretaceous clastic and carbonate exploration in northern Namibia, success at Arcturus 1 could see a renewed focus on this area in the years to come.
If you’ve been following Nigeria’s latest oil & gas bid round, you may be wondering what on earth is going on. Hopefully I can help clear things up a tad by presenting the current situation for the ever-changing 2024 Licensing Round.
After an impromptu soft launch for the tender in late April, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) opened the pre-qualification period on 13 May, initially making 12 blocks available. However, 5 of these blocks (PPLs 267, 268, 3008, 3009 & PML 51) have now been removed from the tender due to ongoing litigation for the offshore areas. Then, in a surprise move last week, the NUPRC decided to add 17 extra deepwater blocks to the round, due to new multi-client seismic data availability, presumably from TGS and PGS.
If the waters weren’t sufficiently muddy at this point, the regulator has also decided to re-launch the suspended 2022/23 Mini Bid Round, which will now follow the same timeline as the 2024 Licensing Round. This throws a further 7 deepwater blocks (PPLs 300-306) into the mix, under the 2024 bidding terms. The Mini Bid Round petered out last year without any awards, after the ill-timed tender coincided with a change in government in mid-2023, as Nigeria’s new President was sworn in. 29 local firms and 5 IOCs (TotalEnergies, Shell, Chevron, Eni & PetroNor E&P ASA) pre-qualified for this round back in 2023, so will not be required to do so again for any of the 31 bid blocks now on offer in total.
To summarise, we’re only in the early stages of bidding and we’ve already seen the blocks on offer go from 12 down to 7, then back up to 14 (with the re-opening of last year’s round), and up again to 31. Furthermore, the bidding schedule has now been tweaked to grant a further 10 days for companies to pre-qualify. Lastly, bear in mind if you want more information that the NUPRC is also using separate websites for the 2 concurrent tenders ( https://br.nuprc.gov.ng, https://br2024.nuprc.gov.ng).
The NUPRC will be hoping that its confusing licensing processes will not become baffling in more ways than one, particularly as it has now slashed its signature bonus requirements for the 2024 Licensing Round to attract investors. Signature bonuses for deepwater acreage once reached the dizzying heights of ~US$200 million in Nigeria; however, this entry bonus has now been lowered to US$7-10 million (dependent on the environment) to reduce the front-end fiscal load.
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Wondering why you’ve never heard the phrase “Lower Congo Limbo” before? Probably because I just made it up! And no, I’m not referring to the afterlife, but the familiar dance we see the majors do in mature petroleum provinces, where the well-explored shallower waters only have smaller-scale ILX growth opportunities left to offer. The offshore Lower Congo Basin in the Republic of Congo and Angola certainly falls into this category. Considering the current checklist of the majors sees them chasing large-scale prospects, in the hope of finding ‘advantaged’ barrels, they’re forced do the limbo, moving lower, lower, lower out into the ultra-deepwater where the risks are great, but the rewards can be even greater.
TotalEnergies , in partnership with PETRONAS , Woodside Energy and SNPC , began its ultra-deepwater (>2,000m WD) foray in Congolese waters with the spudding of its Niamou Marine 1X NFW on the Marine XX block on 24 May. After concluding a DST in TotalEnergies’ Venus 2A appraisal in the Namibian Orange Basin in late April, the Odfjell Drilling -managed Deepsea Mira semi-sub remobilised to the Lower Congo Basin to test the pre-salt Niamou anticline. The ~900 sq km four-way dip closure definitely offers scale, with a pre-drill unrisked mean resource estimate of ~1.76 Bbo.
Some 110km to the south in Angola, Azule Energy (in partnership with Equinor and Sonangol E.P. ) is also pushing the boat out with its first NFW, Kianda 1, on the newly awarded ultra-deep acreage (Blocks 46 & 47). Drilling is unlikely to materialise here until later on in 2025, but when it does, the Eni / bp JV will be hoping to succeed where TotalEnergies failed on the adjacent Block 48, with the dry Ondjaba 1 well P&A in 2021 in world record water depths (3,628m WD). The Kianda anticline offers the prospect of a large structural trap with the potential to warrant an independent FPSO development on Block 47 in a success case. Chevron will be keeping a close eye on this Azule well, as it closes in on the award of Blocks 49 & 50 further south.
During some of the insightful talks at the Frontier Energy Network | The Leading Energy Network ‘s thoroughly enjoyable Africa Energies Summit last week, key news in Côte d’Ivoire emerged, cementing the country’s place as an African oil & gas exploration hotspot, second only to Namibia. The news of Shell ‘s planned country entry via applications for blocks CI-602, CI-603 and CI-707 was discussed by PETROCI , whilst Eni also provided additional color on its nearby Calao discovery, confirming its gas-rich nature (5 Tcf and 500 MMboe of associated liquids).
Having recently shed light on the oil & gas exploration exodus by IOCs in Mauritania over the last five years ( https://bit.ly/3VberUL), I decided to produce a similar comparison for Côte d’Ivoire’s licensed blocks. Countries with significant oil & gas potential, like Mauritania, which may be feeling unloved by the industry at present, can take heart from the Ivorian journey, which is a clear example of the cyclical nature of this sector and how quickly fortunes can change.
In late 2019, the presence of TotalEnergies in the ultra-deepwater Abidjan Margin, alongside the Kosmos Energy / bp partnership in the unexplored acreage to the west, painted a healthy picture for E&P in Côte d’Ivoire. Fast forward two years and the impacts of the COVID-19 pandemic on frontier licenses was plain to see, following a string of relinquishments which saw 17 blocks returned to the state. However, the notable inflection point came after Eni’s major Baleine discovery in Q3 2021 shifted the eyes of the industry back on offshore Côte d’Ivoire. Murphy Oil Corporation entered in June 2023 (picking up five blocks) and Eni’s discovery on CI-205 in early 2024 has triggered PSC talks from both Eni and Shell for seven frontier blocks, which should further the exploration of the Late Cretaceous turbidite play surrounding Calao. As a result, the country’s petroleum licensing landscape has now come full circle in less than five years.
Eni looks set to continue its basin master approach in the Ivorian Basin by picking up four new offshore exploration blocks surrounding its latest discovery in Côte d’Ivoire, dubbed as the Calao field. This tactic was first employed concurrent with the discovery of the country’s largest ever field on block CI-101, Baleine (2.5 Bbo & 3.3 Tcf in-place), with Eni picking up the bordering CI-401, CI-801 and CI-802 exploration licences in 2021/22 to secure nearby growth potential in the eastern waters of the Abidjan Margin.
Then came the news of Côte d’Ivoire’s second largest discovery, Calao (1-1.5 Bboe preliminary resource estimate), drilled by Eni’s Murène 1X NFW on block CI-205 over 100km west of Baleine. Prior to announcing the Calao light oil, condensate and gas find in early March 2024, Eni had submitted expressions of interest for blocks CI-504, CI-526, CI-706 and CI-708 and was given the green light to commence PSC talks on 28 February. Should the four PSCs be signed, it would see the company pick up acreage previously discarded by bp , Kosmos Energy , TotalEnergies , and indeed Eni itself (CI-504 relinquished in Q4 2022), taking its Côte d’Ivoire block count to 11.
As predicted in a recent post ( https://bit.ly/3uZeeK6) on Eni ’s drawn-out negotiations for the Marine XXIV and Marine XXXI areas offshore the Republic of Congo, the major has now been formally awarded the two exploration permits. The gazettal of the awards was achieved on 29 February 2024, wrapping up over four years of protracted contract talks. Despite being part of the original bidding group with Eni in the Congo Licence Round Phase II, LUKOIL has been excluded from the licences, with Eni taking on an 85% operated position, in partnership with SNPC (15%).
Concurrent with Eni’s block awards, the gazettal of three additional exploration permits to two Chinese entities was also achieved on 29 February.
These new entrants to Congo’s E&P sector include:
· China Oil & Natural Gas Overseas Holding Ltd – Awarded Conkouati and Nanga III (onshore)
· Oriental Energy SAU – Awarded Marine XXIXA (shallow-water)
Following on from an earlier post ( https://bit.ly/3I61mVp) looking at imminent Azule Energy block awards in deepwater Angola (now awarded as of end-2023), I thought I’d get the Enverus Global Scout crystal ball out once again and see where Angola’s next deepwater awards are likely to be in 2024. The government’s dual licensing approach of regular bid rounds, alongside direct negotiations, has delivered a steady stream of new Production Sharing Contracts (PSCs – utilised for bid round awards) and Risk Sharing Contracts (RSCs – utilised for direct negotiations) being signed.
In the Kwanza/Benguela basins, Intank Group is in RSC talks with Agência Nacional de Petróleo, Gás e Biocombustíveis for Block 24, located in deep waters directly south of Sonangol E.P. and Afentra PLC ’s Block 23. On 21 December 2023, the Council of Ministers approved a proposal to provide fiscal incentives for the licence, likely in the form of a deduction of the investment premium on the petroleum income tax (a provision used in many of the recent RSC awards in higher-risk, frontier areas). Block 24 was previously operated by bp , which made the Katambi gas and condensate discovery in 2015 but pulled out in 2017 after determining it to be non-commercial. However, this came prior to the introduction of Decree No. 7/18, which brought in terms for the exploration and production of non-associated gas in May 2018.
Moving NW towards the ultra-deep waters of the Lower Congo Basin, RSC negotiations are ongoing with Chevron (in partnership with Sonangol) for Block 49 and Block 50. As with Block 24, draft laws were adopted on 21 December to provide tax incentives for blocks 49 and 50, to encourage exploration investment. The contiguous blocks lie immediately south of Block 48, which was recently relinquished by TotalEnergies after drilling the dry Ondjaba 1 NFW in Q4 2021, in a world record water depth of 3,628m. Chevron previously entered a technical evaluation agreement in Q3 2019 to study the inboard Block 33. Whilst no formal contract was ever signed for Block 33, something in the undrilled waters further outboard appears to have caught the eye of the US major.
Shell has now become the latest major to complete a country exit, relinquishing its deepwater C-10 and C-2 blocks. The withdrawal by January 2024 comes on the back of Shell’s unsuccessful Panna Cotta 1 new-field wildcat, which was P&A in early November 2023, having encountered hydrocarbon shows in deep waters in the south of C-10, after targeting a Late Jurassic/Early Cretaceous carbonate play.
Having been an exploration hotspot in Africa prior to the COVID-19 pandemic, it may now seem like doom and gloom in the MSGBC Basin, with relinquishments galore in Mauritania and bp pulling out of the deepwater Yakaar-Teranga gas project in Senegal. However, despite some deferrals to the Greater Tortue Ahmeyim and Sangomar projects, offshore Mauritania and Senegal, these developments are currently due to come onstream by Q3 2024. Reaching these milestones, allied with the opportunity for bp and Kosmos Energy to launch a new LNG hub at BirAllah in Mauritania and for Kosmos to take on the Yakaar-Teranga project with Groupe PETROSEN , should offer new momentum to propel the MSGBC Basin back into the industry spotlight. Where there’s a will (and ~100 Tcf of gas in-place), there’s usually a way. There’s also plenty of untested prospectivity in the MSGBC Basin; however, as smaller companies struggle for exploration financing, it will take a brave and opportunistic explorer to unlock this potential.
Eni may finally be able to see the light at the end of a very long tunnel in its contract talks for the Marine XXIV and Marine XXXI exploration licences, offshore the Republic of Congo. An Eni and LUKOIL JV was originally pre-awarded the blocks in Q4 2019, following the Congo Licence Round Phase II. However, the subsequent COVID-19 pandemic and western sanctions on Russian companies amidst the invasion of Ukraine, left Eni to wrap up the protracted negotiations without its partner. The Congolese government approved the Marine XXIV and Marine XXXI block awards on 18 January, with Lukoil now excluded and Eni taking on an 85% operated position, in partnership with SNPC (15%). Finalisation of the awards will now require presidential ratification and gazettal in the coming months.
Eni and Lukoil have still maintained their partnership in the key Marine XII licence, containing the producing Nene Marine and Litchendjili Marine oil & gas/wet gas fields in the Lower Congo Basin. First gas was introduced to the 0.6 mtpa Tango FLNG facility from these fields on 28 December 2023, under the fast-tracked “Nearshore Development” phase of Eni’s Congo LNG project, with the first LNG cargo anticipated in Q1 2024. The second “Offshore Development” phase is forecast to see a second FLNG facility (2.4 mtpa) come online at the end of 2025.
The Congo LNG project and negotiations for Marine XXIV and Marine XXXI are proof of Eni’s continued commitment in-country. However, the company has been rationalizing its non-core production portfolio in recent years, relinquishing five exploitation permits and offloading a further six to Perenco, in a US$300 million deal.
Eni is at it again in Ivorian waters, drilling another high-impact new-field wildcat (NFW) and hoping to find another whale (Baleine), or in this case a bloody great big moray eel (Murène) on block CI-205. The Deep Value Driller drillship, leased by Saipem , seemingly spudded the top-hole of the tentatively named Murène 1X well back in early November 2023 before heading some 130 km to the east to conduct development drilling work on Eni’s Baleine field. The rig has now returned to the ultra-deepwater (>2,000m WD) wellsite in early January 2024 to finish operations.
Only one well has previously been drilled on CI-205, former operator LUKOIL ’s Buffalo 1 NFW (5,410m TD, 2,395m WD), which was P&A in the east of the block in Q4 2011 after encountering wet sands in the main Turonian target and non-commercial oil in tight Albian-age sands. Subsequent G&G work by Lukoil and Atlas Oranto Petroleum (before the block was relinquished in 2016) largely focused on a NE-SW trending channelised Turonian fan, updip of Buffalo 1 and analogous to Murphy Oil Corporation ‘s adjacent Paon field.
However, after Eni was awarded CI-205 in March 2017, additional 3D seismic was acquired by PGS in 2018, granting further coverage over the northern segment of the block, where the Murène prospect appears to have been identified. Eni’s plans on CI-205 have been very hush-hush, but a Late Cretaceous fan objective seems more likely for Murène 1X at this stage, rather than a repeat attempt of Eni’s carbonate success at Baleine. As with the Baleine acreage, CI-205 has been identified as being “consistent with Eni’s Dual Exploration strategy”, which essentially means that the company may look to farm-down some of its interest further down the line in a success case.
You may have heard of an open-door licensing process, as employed with success by Namibia from 1999 to date, but how familiar are you with the open window approach? Such is the popularity of Namibia’s petroleum and mining sectors right now, that the Ministry of Mines and Energy (MME) is having to get a handle on the “massive backlog” of applications for both upstream petroleum licences and mineral rights with a “more efficient and effective” approach.
From 1 January 2024, the current open licensing system will be suspended through to 31 March. To get your foot in the door in 2024, application windows will be introduced between 1 April-31 May and 1 September-31 October. No applications will be accepted outside these windows of opportunity, to grant the MME “ample time to review the applications”. This system will only apply to requests for new acreage; renewals to pre-existing licences will continue to be dealt with on a rolling basis.
Shell and TotalEnergies ’ key offshore oil discoveries have unlocked the Orange Basin, reigniting interest in the country’s petroleum sector. The Buck’s Fizz hasn’t been popped just yet however, as only the long-awaited declaration of reserves, flow rates and development plans by the majors will make success feel like an open-and-shut case. Although a lot hinges on Shell and TotalEnergies, other IOCs are also getting in on the act in the Orange Basin early doors, on both sides of the Namibia-South Africa border.
After years of direct negotiations, Angola is finally on the cusp of formally awarding blocks 18/15, 46 and 47 to Azule Energy . The signing of the Risk Service Agreements (RSAs) for the exploration areas is imminent, following the gazettal of ministerial approval on 20 November. Interest in the deepwater Block 18/15 will be held by Azule (80% + Operator) and Sonangol P&P (20%). Equity in blocks 46 and 47, located in the frontier ultra-deep waters of the Lower Congo Basin, will be split: Azule (40% + Operator), Equinor (40%), and Sonangol P&P (20%).
The fiscal terms for the RSAs were recently enhanced via Presidential Decree on 20 October, which saw the deduction of the investment premiums from the petroleum income tax for Block 18/15 (30% investment premium) and blocks 46 and 47 (40% premium). The state believes these changes are justified, as it hopes the new awards will lead to the collection of ~US$90 million in bonuses and social project contributions, as well as supplement the country’s oil & gas reserves and declining production. The government estimates a combined resource potential of >2 Bbo for the acreage.
The signing of the RSAs would take the Azule-operated concession count to 12 in Angola, as the incorporated JV between Eni and bp vies to become Angola’s largest independent producer. Azule has grand plans over the next four years, forking out a total capex of ~US$7 billion, as it aims to reach a combined equity oil & gas production target of 250,000 bo/d, with 16 exploration wells (9 operated by Azule) also planned to be drilled along the way. This includes the company’s first gas exploration well on Block 1/14, as well as high-impact, frontier drilling on Block 28 in the Namibe Basin, proving that exploration is certainly still alive and kicking in this part of Africa.
Block 4 sits in deep to ultra-deep EEZ waters at the far reaches of the Douala Basin, outboard of Príncipe Island. The acreage lies immediately north of Galp ’s Block 6, where the Jaca 1 new-field wildcat was drilled in 2022, encountering hydrocarbon shows in the Turonian basin-floor fan reservoir. Prospective plays on Block 4 are said to involve tilted fault blocks and turbidite fans.
ERHC Energy, Inc. was originally pre-awarded Block 4 in 2011; however, the company never signed a PSC and things turned sour following the signing of a farm-out agreement with Kosmos Energy in June 2017. Kosmos filed for arbitration in October 2017, claiming ERHC had allegedly made an unlawful attempt to rescind the deal and assign the rights of the PSC to another company. Kosmos’ litigation ultimately led to ERHC being temporarily restrained from selling any Block 4 rights to third parties and making attempts to sign a re-negotiated PSC with ANP-STP. The ensuing litigation, described by ERHC as “debilitating, convoluted and resource-draining” has since ended. However, it has left ERHC in a vulnerable state, with the Houston-based junior now appearing to have renounced its claim for Block 4, allowing ANP-STP to seek a new operator.
What a difference a few years makes. What used to be a playground for the majors, has now turned into a bit of a ghost town offshore Mauritania. Until recently, the MSGBC Basin was seen as Africa’s exploration hotspot; however, this area in NW Africa has now fallen out of favour, leading to a further two country exits in 2023, following the relinquishment of block C-7 by Capricorn Energy PLC in May and TotalEnergies ’ C-15 block by October. Only 3 exploration licences remain, operated by Shell and bp (partnered with Kosmos Energy ), as well as the Greater Tortue Ahmeyim (GTA) LNG project at the border with Senegal. This fall out comes not long after Mauritania’s open-door system had boasted an impressive record of awarding 15 new exploration licences between 2012-2018, securing a whopping US$215.75 million in signature bonuses.
Interest in offshore Mauritania peaked following the discovery of the GTA and BirAllah gas fields by Kosmos in 2015, with the BP/Kosmos JV going on to make a further gas discovery with Orca 1 in 2019, bringing the total GIIP estimate to a hefty ~75 Tcf. However, the JV drilled two dry wells (Lamantin 1 & Hippocampe 1) in 2017, with Total’s Richat 1X NFW in 2019 also unsuccessful. Although these poor results may have had a small part to play in the mass exodus to follow, a few dry wells can’t take sole responsibility for the relinquishment of >100,000 sq km offshore acreage from late 2019 to date. The COVID-19 pandemic certainly played a key role, impacting company strategies and the major’s appetite for high-risk, deepwater exploration. Global competition for E&P dollars has also seen Mauritania lose out to countries such as Guyana, Suriname, Egypt and Namibia, which are drawing significant E&P dollars from ExxonMobil , Capricorn and TotalEnergies.
Hope does remain however, with gas in high demand and deepwater, high-impact exploration making a comeback, as evidenced by Shell’s ongoing Panacotta 1 NFW on block C-10, targeting a ~1 Bbo carbonate play, with running room on its adjacent C-2 block. The Ministry of Petroleum, Mines and Energy – Mauritania will be hopeful that success here can reignite interest in exploration; however, the government may need to lower its expectations with regards to the contract bonuses and financial commitments it expects to see, given the difficulties in securing exploration funding in the current climate.
Ever heard the phrase “a small Rhino in a big pond”? Me neither. But straying from its habitat in South Africa’s onshore Karoo Basin to the deep waters of Namibia’s Orange Basin, is not a Rhinoceros but Rhino Resources Ltd , sat amongst a host of big players in a global exploration hotspot as operator of the PEL 85 (Block 2914A) licence. After being recapitalised with European and American investment in late 2021, the company has now begun its preparations for a two-well exploration campaign on the undrilled acreage, following Searcher ’s 1,700 sq km MC3D survey over the block in Q4 2022, utilising the Shearwater GeoServices SW Empress vessel. The same vessel has since returned and is currently conducting further MC3D acquisition in the area.
Rhino will almost certainly need to farm-out equity and likely operatorship before launching the drilling programme on PEL 85. In preparation, Rhino recently completed a value-accretive transaction with existing partner NAMCOR NAMIBIA , picking up a further 20% equity to boost its stake to 75%, ahead of what could be a pricey farm-out, given the growing value of the Orange Basin postcode.
This value could keep growing, with Galp on the cusp of spudding its first NFW on the Mopane Complex on the adjacent PEL 83 area to the NW. The SFL Corporation Ltd. Hercules semi-sub (managed by Odfjell Drilling ) is now in Namibian waters and is due to begin drilling in mid-November. Meanwhile, further outboard of Rhino’s block, Shell and TotalEnergies are continuing their exploration programmes on PEL 39 and PEL 56, respectively. The Deepsea Bollsta semi-sub is drilling ahead in Shell’s Jonker 1A exploration well, whilst VANTAGE DRILLING ’s Tungsten Explorer drillship spudded TotalEnergies’ Mangetti 1X NFW on 7 October, with a DST also ongoing in the Venus 1A appraisal well, utilising the Deepsea Mira semi-sub.
While Chevron ’s planned ~US$60 billion acquisition of Hess Corporation is grabbing the headlines, the company’s growth plans in Equatorial Guinea (EG) have slipped under the radar. Equatoguinean NOC Gepetrol confirmed at African Energy Week that the signing of new agreements for deepwater blocks EG-06 and EG-11 is expected by the end of the year. The unnamed company involved appears to be Chevron, which previously held a meeting with GEPetrol in July 2023 to discuss a project proposal for the ex-ExxonMobil acreage.
Chevron would likely take an 80% operated stake in the licences, located in the Rio del Rey (RDR) Basin, alongside GEPetrol with 20% carried equity. EG-06 and EG-11 will add to Chevron’s existing offshore portfolio in EG, which includes four licences. Operatorship of the producing Alen and Aseng fields in the Douala Basin, as well as a non-operated stake in the Alba Complex in the RDR Basin, was picked up via the acquisition of Noble Energy in Q4 2020. Chevron has since affirmed its commitment to EG with the award of the EG-09 exploration licence in late 2021 and the signing of a Heads of Agreement in March 2023 for the Phase II and Phase III expansion of the ongoing Gas Mega Hub project.
Whilst Chevron is growing its business in EG, ExxonMobil marked the start of its phased withdrawal from the country with the relinquishment of EG-06 and EG-11 back in 2021. ExxonMobil is expected to complete its country exit by 2025, when it is slated to hand over control of the adjacent Zafiro Complex to GEPetrol.
Eni is on course to spud its first NFW on the Tarfaya Offshore Shallow permit, following the arrival of VANTAGE DRILLING ‘s “Topaz Driller” jack-up on 1 September for a 90-day drilling contract (US$125,000 dayrate). The well is expected to be targeting oil in an Early Jurassic clastic prospect within the under-explored Tarfaya Basin, offshore southern Morocco.
Eni’s NFW lies nearly 30km west of the last well drilled on this under-explored acreage, Galp ’s Tarfaya Offshore 1 NFW, which unsuccessfully targeted three stacked carbonate objectives in 2014. The petroleum system was proven to the SW back in the late 1960s-70s by Esso, with the Morocco Offshore 2 (MO 2) and MO 8 wells, which were drilled on a salt-cored structure. MO 1 tested 2,377 bo/d of 10-12° API oil (believed to have been biodegraded) from the Upper Jurassic, whilst MO 8 recovered 38° API light oil from mid-Jurassic carbonates.
After picking up the 12 contiguous Tarfaya Offshore Shallow blocks in 2018, Eni farmed-out a 30% stake to QatarEnergy in 2019. Eni and the Qatari NOC will be hoping for better fortunes for this high-impact Moroccan probe, after the same partnership drilled two deepwater duds in Kenya (Mlima 1) and Mozambique (Raia 1) in Q1 2022 and Q2 2023, respectively.
Currently googling the word oligopoly? Or maybe you’ve been searching the web to figure out what Perenco is up to? You probably won’t find much, despite the fact that the private (in both senses of the word) company is currently responsible for a sizeable portion of production in Cameroon (>70% of oil & gas output), Gabon (>40%), Republic of Congo (30%), and the DRC (100%).
Would it surprise you to learn that Perenco just picked up its 55th block (Olowi permit) in Gabon? Or that the Perenco-operated African drilling tally for 2022-23 is now approaching almost 100 wells? Well, the award of Olowi is only a small piece of a much larger >US$1 billion puzzle for Perenco along Africa’s Atlantic Margin. The table below highlights just how busy the company has been (and will continue to be) in the African A&D market.
The Olowi exploitation permit award was finally gazetted in late July. After Canadian Natural Resources Limited (CNRL) abandoned its short-lived Olowi oil development in late 2018, Perenco swooped in to take on the challenge of producing not only oil, but also exploiting the 344 Bcf gas cap overlying the oil-bearing Gamba sands. Bringing the shallow-water Olowi field back onstream will form a key part of the company’s plans in the South Gabon Basin. Local gas-to-power is planned via a new Mayumba power plant, whilst Perenco is also on the lookout for partnerships to cobble together the volumes for a future small-scale LNG export project (feasibility proven by Perenco’s Kribi FLNG project in Cameroon). This could see LNG shuttled north to its planned LNG facility (sanctioned in February 2023) at the Cap Lopez oil terminal. However, with Perenco amid a three-well exploration drilling programme on its onshore Ezila, Onémbé and Evaro blocks, success here and nearby may see a gas pipeline from the south to Cap Lopez selected as the favoured exploitation route.
QatarEnergy has completed its acquisition of 40% working interest from operator Shell in block C-10, offshore Mauritania. The Qatari NOC first announced the farm-in agreement in April 2023, with government approval and completion of the deal achieved by July.
QatarEnergy’s return to Mauritania (after previously partnering Total in two onshore blocks until 2014) comes ahead of the drilling of the Panacotta 1 NFW in late 2023. Noble Corporation ’s “Noble Voyager” drillship has been contracted for the deepwater drilling programme, which will target a 1 Bbo carbonate prospect in the south of C-10. The unexplored carbonate play is also thought to extend southwards into adjacent block C-2, which Shell was awarded in February 2023, in partnership with NOC SMH. Shell de-risked the subsalt Cretaceous prospectivity in this area of the MSGBC Basin utilising a recent 3D survey, completed by CGG in Q1 2020.
Panacotta 1 will be next in the line of high impact exploration wells drilled by the majors over the past five years, which have been part-funded by the deep pockets of QatarEnergy. Across the African continent, QatarEnergy has formed strong partnerships with Shell, TotalEnergies , and Eni , acquiring non-operated equity ahead of frontier deepwater NFWs, such as: Brulpadda 1AX & Luiperd 1X in South Africa, Ondjaba 1 in Angola, Venus 1X & Graff 1X in Namibia, Mlima 1 in Kenya, Barracuda 1X in Cote d’Ivoire, and Raia 1 in Mozambique.
My first of an ongoing series of LinkedIn posts, enlightening any Africa E&P spectators on some of the key activity and insights in the sector, which may have flown under your market intel radar.
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