All posts tagged farm in-farm out


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.

 


FAR Takes All in The Gambia, Looks for Well Heeled Partners

In spite of two disappointing dry holes in the space of three years, Australian minnow FAR has taken 100% ownership in two Blocks in The Gambia.

FAR Ltd has  acquired an additional 50% interest in Block A5, where it sank money in Samo-1 and Bambo-1 and Block A2, both offshore the Northwest African country.

The interest was acquired from Petroliam Nasional Berhad (PETRONAS), the Malaysian state hydrocarbon company which had co-financed the two wells.

But while FAR takes up all the stakes, it “has initiated a process to find partners to fund the forward exploration programme” and convinced its host Government to remove the Commitment to drill an exploration well during the next two-year contract term

FAR keeps seeing its disappointing drill programme in the Gambia in bright terms: “new laboratory analysis has positive implications for the Panthera Prospect directly up-dip of Bambo-1”, the company explains.

FAR shook up its executive management in March 2022, ousting its CEO Catherine Norman and replacing her with Independent Chairman Patrick O’Connor to oversee the business during a period of transition and “bringing in fresh perspective”.  The next two-year license term for Blocks A2 and A5 is due to commence on 1 October 2022 and “the removal of the commitment to drill an exploration well results in a significant reduction in expenditure and allows for a detailed geoscience review incorporating the results of the recent Samo-1 and Bambo-1 wells to ensure future exploration wells are located optimally”.

Data room Opened

FAR says it has opened a data room “for suitably qualified parties to consider participation in a Joint Venture to undertake the geoscience review and ultimately to drill additional exploration wells. FAR expects new partners to fund the costs of the work programme”, adding that “subject to the satisfaction of certain conditions, including Government approval, incoming participants in the Joint Venture may assume Operatorship.

“The 100% interest in Blocks A2 and A5 and the revised investment obligation enhances FAR’s ability to seek farm-in partners to the project while controlling any potential corporate action and process”.

 


BW MaBoMo Starts Move to Gabon for 2023 First Oil

BW Energy has announced the sail away of the BW MaBoMo (formerly Hibiscus Alphaoffshore production facility.

The production facility is currently onboard a heavy-lift vessel in transit to the Dussafu license offshore Gabon where it will be installed to produce oil from the Hibiscus and Ruche fields.

The BW MaBoMo is expected to arrive on the field at the end of September 2022 for installation and hook-up with first oil planned late in the first quarter of 2023. The Hibiscus / Ruche development is expected to add up to 30,000 barrels per day of gross production once all the initial six horizontal production wells are on stream.

The platform left the Lamprell yard in Dubai on August 8, 2022, following completion of the yard scope with some minor outstanding upgrades, which were executed offshore in preparation for the sail away.  The BW MaBoMo is a former jack-up drilling rig which has been repurposed as an offshore production facility with 12 well slots. It will be connected to the BW Adolo FPSO via a 20 km pipeline.

“By repurposing existing oil and gas production assets we extend their economic lifespan, shorten the time to first oil while also significantly reducing the field development investments and CO2 footprint. We are very pleased to have completed the conversion project with excellent HSE results and only minor adjustments to schedule and budget in a highly challenging environment due to COVID-19, supply chain disturbances, geopolitical tension and commodity inflation,” said Carl K. Arnet, the CEO of BW Energy.

 


Fadahunsi Is the New Business Opportunity Manager for Shell Nigeria’s BSWA Development

Shell has appointed Olaposi Fadahunisi as the Business Opportunity Manager for Bonga South West Aparo, the company’s-and Nigeria’s-next large sized oilfield development.

The new role moves Fadahunsi from Shell Petroleum Development Company (SPDC) which operates the company’s onshore assets, back to Shell Nigeria Exploration Production Company, the company’s subsidiary focused on frontier (mostly deepwater) assets, where he has been for most of his 24 years with the company.

A trained Engineer who started his oil industry career as a Drilling Rig Tour Pusher with the Italian contractor Saipem, Mr. Fadahunsi has worked in engineering and project management roles with Shell since 1998, until his last two roles, which were business development related.

For 10 years from September 2008 to July 2018, Posi, as he is fondly called by industry colleagues, was Shell Nigeria’s Deepwater Business Opportunity and Non Operated Ventures Manager, a role he played in SNEPCO. From July 2018 to May 2022, he was Domestic Gas Business Opportunity Manager, a job domiciled in SPDC.

Prior to that he was Subsea Systems Engineer/Project Leader Apr 1998 – Feb 2003); Venture Engineering Team Leader for the Bonga Integrated Project (Jan 2003 – May 2005) and Project Manager for the Bonga NW Deepwater Project(Jun 2005 – Sep 2006), all in Houston, Texas, United States.

 


Norwegian Operator Grabs a Stake in Cote d’Ivoire’s top Hydrocarbon Asset

DNO ASA, the Norwegian oil and gas operator, has entered into a transaction agreement in which RAK Petroleum plc will transfer its ownership of Mondoil Enterprises LLC to DNO. The all-share transaction comprises Mondoil Enterprises’ 33.33% indirect interest in privately-held Foxtrot International LDC whose principal assets are operated stakes in offshore production of gas and associated liquids in Côte d’Ivoire, forming a bridgehead for DNO in West Africa.

“The move into Côte d’Ivoire is an important first step into a highly prospective region offering a broad set of growth opportunities through acquisition of producing fields, development assets and exploration licenses,” said Bjørn Dale, DNO’s Managing Director. The Company is already evaluating other opportunities in the region, he added.

Foxtrot International holds a 27.27% interest in and operatorship of Block CI-27 offshore Côte d’Ivoire containing the country’s largest reserves of gas, produced together with condensate and oil, from four offshore fields tied back to two fixed platforms, meeting more than three-quarters of the country’s gas needs. Foxtrot International also operates an exploration license offshore Côte d’Ivoire, Block CI-12, in which it holds a 24% interest.

In addition to the Foxtrot gas field, which began production in 1999, Block CI-27 contains the Mahi gas field, developed in 2012, as well as the Marlin oil and gas field and the Manta gas field which began production in 2016, following a four-year, $1Billion development campaign by the joint venture. Gas produced from these fields is transported by pipeline to fuel power stations in Abidjan pursuant to a gas sale and purchase (take-or-pay) agreement put into force in June 1999 and subsequently increased to 140 million cubic feet per day with a base price of $ 6.00 per MMBtu, subject to an indexation formula which has lifted the current price to $ 6.47 per MMBtu.

This asset is big deal: In early 2020, the Block CI-27 joint venture embarked on a two-year, $350Million field development and onshore facilities construction project to supply gas to two new power stations

In early 2020, in connection with the signature of amendments and extension of the production sharing contract and the gas sales agreement to 2034, the Block CI-27 joint venture embarked on a two-year, $350Million field development and onshore facilities construction project to supply gas to two new power stations. Cash flow from operations have funded these capital investments. This work is nearing completion following the drilling of three new and two side-track wells; the last well in the programme, a side-track, is currently progressing.

This additional processing and well capacity are slated to increase gas supply to over 230 million cubic feet per day, subject to electricity sector demand and well performance. Drilling of up to another two wells over the period of the extension is planned to maintain the higher production capacity of the license. During the first half of 2022, gross sales averaged 200Million cubic feet of gas and 1,500 barrels of oil and condensate per day. Oil and condensate (and limited quantities of gas) are sold to the local refinery at arms-length prices. www.foxtrot-international.com

The effective date of the transaction is 1 January 2022 and the agreed consideration is $ 117.25Million, covering transfer of 100% of Mondoil Enterprises share capital valued at $ 95Million, comprising 9.09% indirect working interest in Block CI-27 and 8% in Block CI-12 both held through the ownership in Foxtrot International, and $ 22.25Million including $ 21Million in cash and $ 1.25Million in working capital.

Completion of the transaction is conditional upon shareholder approval at an extraordinary general meeting of DNO resolving to issue the consideration shares. The formal notice of the extraordinary general meeting of DNO to be held on 13 September 2022 is attached and provides further information on the proceedings as well as a description of the terms and conditions of the transaction agreement. RAK Petroleum, too, will hold an extraordinary general meeting to seek shareholder approval of the capital repayment plan.

DNO says it has conducted a due diligence of the assets to be acquired supported by third-party assessment of reserves and resources. The transaction has been negotiated by the independent members of DNO’s Board of Directors who, in addition to the attractive business merits also considered the advantage of increasing the Company’s free float to attract institutional investors and of augmenting DNO’s gas exposure to reduce its carbon footprint. Pareto Securities AS has been retained as financial advisor to DNO and has provided the independent directors with a fairness opinion.

 

 

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