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Afentra’s Angola Acquisition: So Far, Still Far

By Sully Manupe, in Windhoek

Afentra has made significant progress trying to win upstream assets in Angola. But the company admits that none of the two deals leading to ownership is likely to be consummated by December 31, 2022.

The sale and purchase agreement with Sonangol Pesquisa e Producao S.A. (Sonangol) to purchase non-operating interests in offshore Block 3/05 (20%) and Block 23 (40%), is subject to a number of conditions precedent (the ‘CPs’), including the receipt of governmental approvals and the extension of the Block 3/05 Production Sharing Agreement until at least December 31, 2040. The Company remains in discussion with all relevant parties in this regard, as the Block 3/05 contractor group continues to progress conversations with the  ANPG, the country’s oil and gas regulatory body, Afentra notes in a release. “Nevertheless, the PSA extension is now unlikely to be finalised before December 31, 2022 and the Company, together with Sonangol, are working on extending the long stop date for the Sonangol Acquisition in order to facilitate satisfaction of the remaining CPs to enable completion in Q1 2023”.

Afentra also signed an SPA with INA – Industrija Nafte d.d. (‘INA’) to purchase a 4% interest in Block 3/05 and an up to 5.33% interest in Block 3/05A offshore Angola (the ‘INA Acquisition’). ”The transaction is now with the Ministry awaiting Governmental approval, and formal completion is anticipated to occur in early 2023”. In this particular case, “given the progress made to date, there is not considered to be any requirement to extend the long-stop date pursuant to the INA Acquisition at this time, as set out in the Company’s admission document”.

Afentra says that Block 3/05 “production for the first nine months of 2022 has been stable and in-line with expectation at 19,160Barrels of Oil Per Day (BOPD) gross. This is equivalent to ~4,600BOPD net to Afentra upon completion of the Sonangol and INA Acquisitions”. in due course.

Savannah Terminates SPA With PETRONAS in Chad, Cameroon

British producer Savannah Energy and Malaysian state-owned PETRONAS have mutually agreed to terminate the Sales and Purchase Agreement (SPA) for the latter’s Chad and Cameroon portfolios.

“Completion of the proposed acquisition remained subject to satisfaction of certain conditions precedent which has not yet been satisfied”, Savannah says in a statement, “and Savannah and PETRONAS have, therefore, mutually agreed to terminate the SPA with immediate effect”.

The agreement was initially announced exactly a year ago to the date of termination (December 13, 2021). Savannah signed an SPA with PETRONAS at the same time it did with ExxonMobil. The ExxonMobil sale has been concluded, but the PETRONAS transaction failed.

If both had been concluded, Savannah would be holding a 75% controlling interest in the Doba Oil Project and an effective c. 70% indirect controlling interest in the Chad-Cameroon export transportation system.

Instead, Savannah now owns a 40% interest in the Doba Oil Project (comprising interests in seven producing fields) with a combined gross 2P Reserve base of 142.3Million barrels (MMbbls) as of October 1, 2022 and expected 2022 gross production of 28, 000Barrels of Oil Per Day (BOPD) and an effective c. 40% indirect interest in the Chad-Cameroon export transportation system comprising a 1,081 km pipeline and the Kome Kribi 1 floating storage and offloading facility, offshore Cameroon.

The remaining 25% interest in the Doba Oil Project is held by the national oil company of Chad, SHT Petroleum Chad Company Limited (“SHT”). The remaining 30% interest in the Chad-Cameroon export transportation system is held indirectly by affiliates of SHT together with the Republic of Chad and the national oil company of Cameroon, Société Nationale Des Hydrocarbures. For reference, in 2020 the Doba Oil Project produced an average gross 33,700BOPD and the Chad-Cameroon pipeline transported a gross 129,200BOPD.

Tullow Chases the Same Fortune as ENI; Takes More Position in Cote D’Ivoire

By Marcus Michelangelo, in Accra

Tullow Oil has signed Production Sharing Contract for new offshore exploration licence in Côte d’Ivoire in order to chase leads in the country’s segment of the Tano Basin.

Tullow will operate the CI-803 licence with 90% equity, the remaining 10% is held by PetroCi. CI-803 covers an area of 1,345 square kilometres and is adjacent to licence CI-524 which is also held by Tullow (90%, operator) and PetroCi (10%).

Tullow produces hydrocarbon in the Ghana segment of the basin, but its forays in Cote D’Ivoire have not delivered commercial results.

In 2021, however, the Italian explorer ENI reported the discovery of a massive tank of oil and gas in their first wildcat in Côte d’Ivoire. Baleine-1X was drilled in 1,200metre water to a TD of 3445metres, targeting Cretaceous sands in the Tano,which is a Transform Margin.  The company currently carries a figure as high as 2Billion BOE as ultimate recoverable reserves in the Baleine Structure.

Tullow’s managers, clearly sat up and took notice. Houston based Vanco (now defunct) had held the acreage in 2007 and just fell short of drilling this major prospect, supported by amplitude and a large ‘gas cloud’, according to a report by GeoExpro. In 2013 and 2014Lukoil drilled the Capitaine EastIndependence and Orca fields nearby, finding sub-commercial volumes of oil in Upper Cretaceous sands, GeoExpro explains

Tullow’s management is convinced it can deploy the geoscientific skill sets that helped ENI to nail the Baleine mega structure. “Significant prospectivity has been identified within the proven Cretaceous turbidite plays, similar to the plays which are producing in the adjacent TEN and Jubilee Fields. The work programme for the initial two and a half years includes reprocessing of existing 3D seismic data, along with prospect evaluation. In CI-524, a number of drill candidates are being matured while preparations continue for an exploration well to be drilled during 2024”.

Smarting from a Stalemate in Nigeria, ExxonMobil Exits Chad and Looks to Wind Up in Eq. Guinea

By Macson Obojemuinmoin, in Kribi

The US major remains fully engaged in Angola but is unsure of investment decisions in Mozambique

It is official. ExxonMobil is done with Chad; one of the four sub-Saharan African countries in which it has operated upstream hydrocarbon assets for the last 30 years.

The company has finalized the sale of its entire upstream and midstream asset portfolio in Chad and Cameroon, including operatorship of the upstream assets (through the sale of Esso Exploration and Production Chad Inc., its subsidiary, and the former operator) for $407Million. Savannah Energy, the buyer, now owns a 40% interest in the Doba Oil Project (comprisinginterests in seven producing fields) with a combined gross 2P Reserve base of 142.3Million barrels (MMbbls) as at October 1, 2022 and expected 2022 gross production of 28, 000Barrels of Oil Per Day and an effective c. 40% indirect interest in the Chad-Cameroon export transportation system comprising a 1,081 km pipeline and the Kome Kribi 1 floating storage and offloading facility, offshore Cameroon.

ExxonMobil didn’t own any upstream asset in Chad. Themajor’s involvement with the country was in the form of the Chad-Cameroon pipeline and the production terminal off the coast of Kribi.

WITH CHAD GONE, ExxonMobil still has shallow water assets for sale in Nigeria and Equatorial Guinea. The former is held up in regulatory challenges. The latter is struggling for the right buyers.

The Nigerian sale in which ExxonMobil is disposing off Mobil Producing Nigeria Unlimited (MPNU), a wholly owned subsidiary, was blocked by the state hydrocarbon company NNPC, with which ExxonMobil has been in arbitration.

ExxonMobil’s Angolan and Mozambican assets are in deepwater. The company has shown no indication, in public, of willingness to divest these. In November 2022, ExxonMobil reported a discovery in Block 15, its sole asset in Angola. The Bavuca South-1 well is part of the Angola Block 15 redevelopment project, aimed at producing approximately 40,000 barrels of oil per day to help offset natural production declines. It is also staying on in deepwater Nigeria, where it has only recently renewed its licences.

The supermajor’s entry into Mozambique is far more recent and whereas there has been significant front end-loading work on a 15Million Tonne Per Annum Liquefied Natural Gas (LNG) project it is leading, the ferocious armed insurgency happening close to the site of the project in Cabo Delgado Province in the north of Mozambique, is holding up Final Investment Decision.

Will The Forthcoming Nigerian Bid Round Fully Open Up the Benin Basin?

By Marcus Michelangelo, in Accra

The proposed bid round of a few, select deepwater acreages in the Benin Basin scheduled for late 2022, has thrown up the question again: Will Nigeria join the rank of countries who have made large discoveries and have developed, or are developing, assets in the West African Transform Margin (WATM)?

Ghana’s Tano Basin, from which Tullow Oil has produced over 400Million barrels of crude from the Jubilee field since 2010 and Cote D’Divoire’s Tano Basin, from which the Baleine structure, a massive hydrocarbon accumulation was discovered by ENI in 2021 and under development, are in the WATM.

 “The Benin Basin has yielded success in the Proximal shelf/Shelf Margin play domain”, says Joe Ejedawe, an award winning earth science scholar retired from AngloDutch major, Shell, “but little exploration has taken place in the deep-water turbidities domain, which may be more prospective”.

His comments are a veiled reference to the Ogo discovery in Oil Prospecting Lease (OPL) 310 and the producing Aje field in Oil Mining Lease (OML) 113.

Both fields sit adjacent to each other on the shelf margin.

The Nigerian Upstream Petroleum Regulatory Commission (NUPRC), classifies 40 leases in the country’s concession map, as part of the offshore Benin Basin. Three of these are in the shallow water, or what, in more precise terms, is called the shelf margin. These three include Optimum Petroleum operated OPL 310, Sunlink’s OPL 311 and the Folawiyo operated producing block: OML 113.

The remaining 37 such leases are in deepwater. Nine of these are under licence, with the remaining 28 leases open.

It’s important to note that while NUPRC classifies these assets as in the Benin Basin, a cretaceous basin (which is why the number ‘3’ is the first of the three numbers describing them), operators of some of the nine deepwater leases under licence, have explored them as part of the tertiary Niger Delta.

In the heyday of second round of active drilling in the Nigerian deepwater, Shell drilled Bobo in OPL 322, Petrobras drilled Erinmi-1 in OPL 324, Phillips drilled Onigun-1 in OPL 318.

The results were not altogether encouraging and, in spite of the high profile of these companies and the fact that crude oil prices were heading up(between 2003 and 2007), most of them gave up the assets in this corner, which they defined as outer toe thrust of the Niger Delta.

Ejedawe, who compiled the first paleo-river trends in the Niger Delta as a basis for reservoir prediction in the Niger Delta, cautions against a literal definition of basin type based on numbering that could be arbitrary. “I associate those wells more with the Niger Delta than the Benin Basin”, he emailed in response to our query. “The tectonic boundary is defined by the fracture zone, which separates the Niger Delta from the Transform margin. Added to that, is the dominance of the deltaic build out of the Niger River which dwarfs the transform margin input in the Tertiary. So you have two play complexes – Cretaceous and Tertiary”, Ejedawe said.

“The wells you referred to were drilled with the Tertiary as the main objective and no consideration was given to the Cretaceous. The wells were drilled in the Niger Delta, and the underlying premise was to continue in the prevailing success of the Tertiary of deep water Niger Delta.

“For the transform margin, the main focus is the Cretaceous, and this is where the Cretaceous turbidites come in. To understand the Cretaceous turbidite distribution we have to look at the paleo geomorphology of the basin and tie that to the tectonic pattern”, he advises.

If the Nigerian government is keen on using its   2022 bid round to get investors to look at new plays, it could vigorously market the Benin Basin, which is the next most prospective basin in the country after the Niger Delta.

“There is work to be done to fully resolve the exploration potential of the Benin basin”, Ejedawe argues. “The industry should find some time to have a very public brainstorming session”.



Nigeria Appoints Transaction Adviser, Names the Four Select Blocks for Bid Round

The Nigerian government has appointed a transaction adviser for the upcoming bid round of select acreages.

The consultant, a subsurface evaluation service company named Petro-Vision, is involved in pre-Financial modelling for the licencing sale.

The government is offering Oil Prospecting Leases (OPLs) 312, 313, 314 and 318, confirming our exclusive report in the August 2022 edition of the monthly Africa Oil+Gas Report. The acreages are all in the deepwater Benin Basin, considered the most prospective basin in the country after the Niger Delta.

The licencing round, which is being prepared for launch before Christmas 2022, will be the first open lease sale of exploratory tracts to be superintended by the Nigeria Upstream Petroleum Regulatory Commission (NUPRC), the new regulator established by the Petroleum Industry Act (2021). It follows, closely, the conclusion of the marginal field bid round (featuring small, undeveloped discoveries), which was launched by the Department of Petroleum Resources, the defunct regulatory agency, in mid-2020.

The selection of these OPLs: 312, 313,314 and 318, suggests that the authorities want to follow up on the leads generated by the existing discoveries in the Benin Basin. OPL 312 is located directly south of Oil Mining Lease (OML) 113, which hosts the Aje producing field. OPL 313 is sited directly south of OPL 310, in which the Ogo field, a large oil and gas accumulation, was discovered in 2013. OPL 314 is a neighbouring acreage east of OPL 313 and OPL 318 sits below (meaning ‘located south of’) OPL 321, once held by the Korean National Oil Company.

Participants in the forthcoming bid round will access seismic data from multiclient data packages acquired by both PGS, the Norwegian geophysical company and the TGS-Petrodata consortium. But the platform on which the packages will be accessed is provided by a company named Maxfront Technologies.

The Benin Basin deepwater mini-bid round (the working title), follows up other measures aimed at attracting investment from local and international operators, as the country desperately tries to rein in declining crude oil output. This year alone production has slumped from 1.4Million Barrels of Oil Per Day in January 2022 to as low as 937,000BOPD in September, which has now inched back up to 1.01MMBOPD in October 2022, according to NUPRC data.

In mid-August 2022, NNPC Limited announced it had concluded Production Sharing contract extension agreements with its partners for five deepwater oil blocks: OMLs 128, 130,132, 133, and 138. The partners included Shell Nigeria Exploration and Production Company (SNEPCo), TOTAL Exploration and Production Nigeria Limited (TEPNG), Esso Exploration and Production Nigeria Limited (EEPNL), and Nigerian Agip Exploration (NAE). “These renewals validate earlier commitment to maintaining a significant deepwater presence in Nigeria, via Esso Exploration and Production Nigeria (Deepwater) Limited,” ExxonMobil tweeted, adding that the agreements are among the first such renewals to be consummated after the passage of the Petroleum Industry Act (PIA).


The Facts, The Figures: Why NNPC’s Divestment is the Place to Go

By the Editorial Board of Africa Oil+Gas Report

For close to 50 years, the company formerly known as Nigeria National Petroleum Corporation (NNPC) has functioned essentially in two key areas of the petroleum industry.

The first is upstream crude oil and natural gas operations.

The second comprises services, midstream, and downstream activity.

A close examination of the performance of this state-owned entity, in these sectors, in those decades, provides us a handy guide to determine the merit of the recent calls for its outright privatization.

In the 49 years since Nigeria inaugurated the Joint Venture scheme between NNPC and multinational companies, six (6) international majors, have effectively produced all of Nigeria’s crude oil and gas output.

These multinationals have been self-regulating, with high standards of efficiency, governance, and application of technology, that, in spite of NNPC, they planned and executed programmes for national production, which grew to a peak of 2.531Barrels per day (crude oil and condensate) in 2010, according to the BP Review of Statistics, an industry bible of production data. It was easy for NNPC, the 57% (average) equity holder of the JVs, to take credit for these numbers.

Now the multinationals have, since 2012, been steadily implementing a withdrawal and are being replaced by Nigerian independents who do not have the same standards, efficiency, governance, and application of technology.

In the same hydrocarbon patch in which these six multinationals could collectively produce 2.5Million Barrels per day, there are now over 30 producing companies, “superintended” by NNPC, collectively struggling to deliver 1.3Million Barrels per day (crude oil and condensates), with heavy sweating. It’s not a challenge of geology, we aver, but above-surface issues.

Throughout what is now known as the golden era of Nigerian crude production, NNPC’s main contribution has been the long, dispiriting stretch of contracting cycles and delayed cash call payments.

Now the NNPC has grown larger in terms of asset footprint, with more acreages handed to them in those last 10 years; the same decade in which the multinationals have retreated and Nigerian production has shriveled.

Eighty-eight percent (88%) of the fiscal contribution of oil and gas to the Nigerian treasury comes from rent: taxes and royalties and only 12% come from revenues accruing to NNPC from its equity in the Joint Ventures as well as share in Petroleum Sharing Contracts. NNPC’s whopping 57% of the main oil and gas producing projects translates to only 12% of the total contributions of oil and gas to the treasury. What this means in simple terms is this. If we assume that Nigeria is producing 2.5 Million barrels per day today, then NNPC’s entitlement will be 1.425Million barrels per day. This volume is what is the Federation volume. It is the one whose proceeds are always consistently underperforming. It is the one that Ahmed El Rufai, governor of the Nigerian northwestern state of Kaduna, alleges, never reaches the Federation account. It is this NNPC equity entitlement, that we aver, contributes just 12% of the total contributions of oil and gas to the treasury, at the best of times.

The bulk of contribution to the National Treasury from oil and gas comes from the petroleum profit tax (now hydrocarbon tax) and royalties that are paid by Shell, Chevron, TOTAL, ExxonMobil, ENI, Seplat, NDEP, NDWestern, AITEO, Newcross, Amni, Elcrest, First Hydrocarbon Nigeria, Midwestern, Lekoil, First E&P, Conoil, Green Energy, Energia, Waltersmith, Platform, Britannia U, Savannah Energy, Sahara Energy, Oando, Shoreline, Neconde, Heirs Holdings, Oriental Resources, Eroton, NNPC itself and several others.

And there is another point we have to make here. It is its “senior” position in the JVs and its management of the PSCs that has provided NNPC the opportunity to wreak so much havoc (Poor cash call remittances, long contracting cycles, bullying service companies into partnerships with NNPC owned service companies and then insisting the contracts for oilfield service be awarded to those partnerships).

If NNPC was holding a zero percent interest in these JVs, the national purse will feel a more positive impact.

This is why the Africa Oil+Gas Report has always made the argument for the reduction of NNPC equity in the JVs.

The clearest example of the need for NNPC to be less than a 50% shareholder in Nigeria’s oil and gas projects is the Nigeria Liquefied Natural Gas (NLNG) Ltd. Its an incorporated joint venture of NNPC with three European majors (UK’s Shell, France’s TOTAL and Italy’s ENI) in which NNPC has 49% equity. That less than 50% NNPC equity allows these companies a breather to run one of the most profitable hydrocarbon operations (no cash call (payables) issues, no approval challenges for projects, no bullying), with billions of dollars guaranteed as dividends meant for the National Treasury.

Apart from JVs and Production Sharing Agreements in oil and gas production, the NNPC has an extensive network of subsidiaries, some of them service companies, some of them midstream companies, some are in transportation and some are in marketing.

The NNPC runs refineries. It has depots and pipelines for petroleum product storage and distribution.

It has a seismic acquisition and seismic data processing subsidiary chrsitened Integrated Data Services Limited (IDSL); it has an engineering company named NETCO. It has a crude oil marketing division for marketing the Federation crude.

The refineries have not performed above 25% of their capacity since 1997, which is 25 years ago. NNPC’s bungling of its mandate to refine-the Nigerian- crude is one of the most brazen acts of de-industrialisation of the Nigerian economy by any state-owned enterprise.

NNPC, the one-time corporation, now a Limited Liability Company, had three petrochemical plants, each in Warri, Port Harcourt, and Kaduna. The one in Port Harcourt was built as a stand-alone from the refinery. The Warri and Kaduna Petrochemical plants are located inside the refineries.

Nigeria took the bold step to privatize the Port Harcourt Petrochemical plant, named Eleme Petrochemicals. It has been so successful that the 10% equity of it that is owned by the Rivers State Government is probably the state’s largest investment.

The petrochemical plants that remain in NNPC’s control are shabby; they have not sold a bag of petrochemicals for 30 years.

Let us go to crude oil marketing.

Every large oil producer, even lowly Angola, sells its crude oil directly on its own through its state hydrocarbon company.

NNPC is the only such state company that does not market its crude.  It has to allocate to companies who line up every year waiting for an arbitrage opportunity. Nigeria is the only place where you have to allocate crude oil to middlemen to sell.

Even Duke Oil, the NNPC’s crude marketing subsidiary, doesn’t sell directly. It markets through other entities.

The data acquisition and processing company, IDSL and the engineering firm, NETCO, each forms partnership with the competition. By using the weight of the NNPC, they get the contracts that oil companies would have awarded directly to their competition and hand over the work to the competition to do. IDSL, on its own, does not process a single kilometre of seismic data.

NPDC has been delinquent in paying taxes and royalties on most of the assets in which it is 55% or 60% joint venture partner to private producing companies. Most of these assets were assigned to them by NNPC: NNPC novated its equity in several joint ventures to NPDC, but the latter has never paid the equivalent market price for those assets.

NNPC’s Petroleum distribution is probably the most inefficient of all its operations. The petroleum product pipeline system is supposed to ensure the minimal presence of tankers on Nigerian roads. The failure of that system is the reason for some of the most fatal traffic accidents across the breadth of the country.

If NNPC is scrapped today, what will the Federation account lose?

But that’s already a stretch of the argument.

This editorial is part of the Public Service contribution of the Africa Oil+Gas Report.

Panoro Takes More Position in Equatorial Guinea

Panoro Energy has agreed to farm-in to the Kosmos Energy-operated exploratory tract-the Block S offshore Equatorial Guinea for a 12% non-operated participating interest.

The Oslo-based minnow already has an interest in a producing asset in the country, operated by Trident Energy.

The current joint venture partnership at Block S is Kosmos Energy (40% and operator), Trident Energy (40%), and GEPetrol (20%). Panoro’s agreed farm-in is on the basis that it will acquire a 6% participating interest from each of Kosmos Energy and Trident Energy, respectively (12% in aggregate).

Block S covers a surface area of 1,245 km2 with water depths ranging from 450 metres to 1,500 metres and is covered by high-quality 3D seismic. The block surrounds the producing Ceiba Field and is adjacent to the producing Okume Complex, which is operated by Trident Energy and where Panoro holds a 14.25%percent non operated participating interest which accounted for 4,714Barrels of Oil Per Day (BOPD) net working interest production for Panoro during the first half of the year, around 60% of Panoro’s total output.

Past exploration activities on Block S have tested and proven the necessary geological play elements which have led to an extensive prospect inventory being identified within tie-back distance to the Ceiba Field and Okume Complex facilities”, Panoro explains in a release. One exploration well is planned to be drilled during 2024.  Panoro’s farm-in is subject to customary approvals.

John Hamilton, CEO of Panoro, says that Block S will significantly expand the company’s acreage position offshore Equatorial Guinea, and our exposure to near field exploration potential. The block is in the immediate vicinity of our producing Ceiba Field and Okume Complex which have to date produced around 465Million barrels of oil, and where we are also partnered with Kosmos Energy, Trident Energy, and GEPetrol

With the new acquisition, Hamilton explains, Panoro will have modest financial exposure to a large inventory of prospects and leads within tie-back distance of existing production facilitiesoffering scope to leverage synergies in the event of a commercial discovery.

Following the recent extension of the Ceiba Field and Okume Complex PSC to end 2040, he says Panoro looks forward to working with our aligned partners and stakeholders to unlock the full potential of our enlarged asset base in Equatorial Guinea.”    

ENI Grabs More Assets in Algeria, as bp Eases Out

Nine years after Islamist militants took 41 foreigners hostage in a deadly raid on a gas field operated by bp in southern Algeria, the British producer has decided to give it all up.

Italian explorer ENI has agreed to acquire bp business in Algeria, including the two gas-producing concessions “In Amenas” and “In Salah” (45.89% and 33.15% working interest respectively).

The transaction is subject to the approvals of the competent authorities.

The “In Amenas” and “In Salah” assets, which are jointly operated with Sonatrach and Equinor, are located in the Southern Sahara and their production of gas and associated liquids began in 2006 and 2004 respectively. In 2021 they produced approximately 11Billion cubic metres of gas, 12Million barrels of condensates and LPG.

“This acquisition has a great strategic value to further contribute to Europe’s gas needs and further strengthens ENI presence in Algeria, a major gas producer and a key country in for ENI”, the company says in a release. The deal “will allow ENI to increase its portfolio of assets in the country and, jointly with the new contracts of Berkine South and Block 404/208 recently signed, will allow new and synergic development opportunities, mainly focused on increasing gas production”.

Following these acquisitions and the development programs underway in the Berkine basin, in 2023 ENI’s production from Algeria will rise to over 120,000 barrels of oil equivalent per day, further confirming ENI as the main international energy company operating in the country.


TGS Finalises the Takeover of ION Geophysical

TGS has announced the closure of its acquisition of the multi-client and processing business of ION Geophysical Corporation (ION).

The purchase “includes substantially all of ION’s global offshore multi-client data library, data processing and imaging capabilities, intellectual property, and Gemini Extended Frequency Source technology and equipment”, TGS said in a statement.

The transaction was concluded as part of ION’s bankruptcy process in the United States Bankruptcy Court for the Southern District of Texas.

ION’s data library consists of over 637,000 kilometres of 2D and over 317,000 square kilometres of 3D multi-client seismic data in major offshore petroleum provinces globally, generating revenues in excess of USD 86M in 2021.

“TGS funded the acquisition from its current cash holdings and employed over 60 ION employees associated with the acquired business as part of the transaction”.

TGS has been in acquisitive mode for over three years. In 2019, acquired a keen rival, Spectrum Geophysical.

Kristian Johansen, CEO at TGS, said the company was “excited about taking over another quality data library, particularly in the South Atlantic”, and pleased to add strong capabilities to our processing business in terms of software, hardware, imaging technologies and people.


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