Saudi owned ACWA Power has led a consortium of companies to sign a project agreement to develop a 1.1GW wind project in Egypt, at an investment value of $1.5Billion.
The consortium, comprising Hassan Allam Holding, will work together during the development phase to complete the site studies and secure the financing of this facility.
Located in the Gulf of Suez and Gabal el Zeit area, this wind project is the largest single contracted wind farm in the Middle East region and one of the largest onshore wind farms in the world.
“The project will be designed to use state-of-art wind turbines with blade heights of up to 220 metres, which helps in achieving the best use of the designated land plots in the most efficient way”, ACWA claims in a statement.
“When complete, the project will mitigate the impact of 2.4Million tonnes of carbon dioxide emissions per year and provide electricity to 1,080,000 households.
The signing ceremony of the agreement took place at the headquarters of the Egyptian General Authority for Investment and Free Zones, Cairo, in the presence of Mohamed Shaker El-Markabi, Egypt’s Ministry of Electricity and Renewable Energy; Majid Bin Abdullah Alkassabi, Saudi’s Minister of Commerce; Issam bin Saad bin Saeed, Minister of State and Cabinet member for Shoura Council affairs; Hala Al Said, Egypt’s Minister of Planning and Economic Development; Mohamed Abdel Wahab, CEO of the General Authority for Investment and Free Zones “GAFI”; Osama Asran, Egypt’s Deputy Minister of Electricity and Renewable Energy; Gaber Desouky, CEO of the Egyptian Electricity Holding Company (EEHC);. Amjad Saeed, Advisor to the Minister; Eng. Sabah Mashali, Chairman of the Egyptian Electricity Transmission Company; Mohammed El Khayat, Chairman of New and Renewable Energy Authority; and Mohammad Abunayyan, Chairman of ACWA Power.
“This milestone wind project falls within the framework of the Egyptian government’s strategy to diversify its energy sources and leverage the country’s rich natural resources, especially in renewable energy”, The statement by ACWA adds. “The 1.1GW wind project confirms Egypt’s commitment in spearheading the use of renewable energy sources to reduce the impact of carbon emissions produced by conventional energy sources, as Egypt gears up to host the United Nations Climate Conference (COP 27) in November 2022, the foremost international forum to discuss countries’ efforts in addressing climate change”.
Nigeria has awarded Petroleum Prospecting Licences (PPLs) for 37 undeveloped discoveries (aka marginal fields) in the country’s prolific Niger Delta Basin.
At a glittering ceremony witnessed by over 300 guests in Abuja, the country’s political capital, 37 of the 57 oil and gas fields offered in a bid round launched two years ago were issued with the PPLs, having satisfied all conditions for award.
As of the date of the ceremony on June 28, 2022, 41 fields had been fully paid for, but four of those fields are having one challenge or the other in terms of partner relationships for the fields’ development.
Each of the 57 fields on offer was provisionally awarded to more than one company and each group of “potential awardees” were meant to set up a Special Purpose Vehicle (SPV), some incorporated joint venture (IJV) that will then operate the fields.
The Nigerian Upstream Petroleum Regulatory Commission NUPRC, which is superintending the award exercise, has said that those who had not paid signature bonus as of February 2022 were deemed to have been disqualified.
As 41 fields have been duly paid for, there are 16 fields that are still open, in varying degrees, for awards.
Timipre Sylva, Nigeria’s Minister of State for Petroleum, gushed with pride as he spoke at the ceremony. “The implementation of the Petroleum Industry Act (PIA 2021) is in top gear”, he declared, referening the new petroleum regulation that governs the industry. “Consequently, the new awardees should note that their assets will be fully governed by the provisions of the PIA 2021”.
Mr. Sylva told the awardees to “ensure that good oilfield practice is employed, environmental considerations and community stakeholders’ management are not neglected”, as they develop their assets. “It is my strong belief that the awardees would take advantage of the current attractive oil prices to bring these fields into full production within a short period to increase production, grow reserves and reduce cost of production.
Egyptian General Petroleum Corporation and Baker Hughes Partner to Reduce Emissions from Flaring Operations
Baker Hughes’ flare.IQ technology to support Egypt’s decarbonization targets by managing and reducing methane emissions at an Alexandria-area refinery
Flare emissions management project is Phase 1 of wider flare recovery initiative in Egypt
Partnership marks first downstream deployment for flare.IQ in Egypt and comes ahead of COP27 in November 2022, to be hosted in Sharm El-Sheikh
Baker Hughes and Petrosafe, a subsidiary of the Egyptian General Petroleum Corporation (EGPC), have announced a contract that will mark the first deployment of Baker Hughes’ flare.IQ technology in refinery operations in Egypt to help reduce emissions from oil and gas flaring operations.
This initial phase of a broader flare recovery partnership will be implemented at the APC Refinery in Alexandria. The Egyptian Ministry of Petroleum and Mineral Resources (MoPMR) aims to reduce emissions and improve the efficiency of oil and gas operations as part of its ambitious aim to reduce greenhouse gas emissions from this sector.
Methane is one of the most harmful forms of emissions — 86 times more potent than carbon dioxide over a 20-year period*. Incomplete combustion of flared gas is one of the major source of methane emissions across the oil and gas industry. By using flare.IQ technology from Panametrics, a Baker Hughes business, EGPC will further digitalize its emissions management infrastructure and pull critical information about its flare systems, substantially reducing emissions by ensuring a higher-efficiency flare combustion rate.
The contract comes at a significant moment as Egypt prepares to host the 27th UN Climate Change Conference (COP 27) in November and contributes to the Global Methane Pledge.
“Our flare recovery partnership with Baker Hughes is an important step in Egypt’s Petroleum Sector Modernization program as we start implementing MoPMR projects included within Egypt’s Climate Change Strategy 2050, as announced in May 2022,” said H.E. Tarek El-Molla, Minister of Petroleum and Mineral Resources. “Phase one of the partnership, the deployment of flare.IQ, will support our flare recovery ambitions, which is one of our Nationally Determined Contributions (NDCs), in support of the Paris Agreement objectives. We look forward to seeing the impact of flare.IQ help improve the quality of life for residents near the Alexandria plant and anticipate extending the scope to include other refineries across Egypt.”
“Better understanding and managing emissions is central to the oil and gas industry’s efforts to reduce greenhouse gas emissions. Our partnership with MoPMR demonstrates how Baker Hughes continues to collaborate with our customers in taking positive action in emissions management,” said Rami Qasem, executive vice president of Digital Solutions at Baker Hughes. “This partnership with MoPMR supports its ambitious low-carbon strategy, and further underlines Egypt’s commitment to be at the forefront of tackling emissions in the oil and gas sector, as we approach COP 27.”
The contract follows the memorandum of understanding that was signed by the two companies in February 2022. The partnership between Baker Hughes and EGPC aims to establish and drive a flare recovery initiative to support emissions recovery and reduction across Egypt’s upstream and downstream oil and gas operations.
A Baker Hughes Statement says: “Part of the Baker Hughes Climate Technology Solutions portfolio, flare.IQ is fast, accurate, reliable, easy to deploy and cost effective. It has a proven track record in optimizing flare operations, achieving steam savings and significantly reducing methane emissions”.
Tanzania is looking to amend its nine-year-old Model Production Sharing Agreements (MPSAs) for its upstream hydrocarbon assets and then launch an acreage licencing sale.
The country’s Petroleum Upstream Regulatory Authority (PURA) is conducting reviews of the hydrocarbon code as well as the salability of the MPSAs, after which it hopes to launch a bid round of 23 acreages in the onshore and offshore terrains in the second quarter of 2023.
Tanzania introduced MPSA in 1989, as its own way of clarifying the terms and conditions it offers for investors interested in hydrocarbon acreages and how the government/ investor revenue share is caliberated in Production Sharing Agreements (PSAs). The 1989 MPSA was amended in 1995 and the 1995 MPSA was amended for 2004 and then 2008 and then 2013.
The 2013 MPSA has lasted the longest.
Tanzania holds close to 60Trillion cubic feet (Tcf) of gas, most of it in deepwater Rovuma Basin, located in the far reaches of the Indian Ocean. It has a modest gas-based industry which feeds off its 8Tcf of gas onshore and shallow water.
About 50Tcf or 83% of the gas reserves are a result of the discoveries in deepwater Rovuma basin between 2011 and 2014. Tanzania has launched two bid rounds since the MPSAs were promulgated in 2013 which have not attracted investor interest
The ongoing review of the MPSAs will update the fiscal regime in accordance with the global trends in trade, fuel prices over the past decade and estimates for the next decade, the institutional changes in Tanzania and current legal system, including the Petroleum Act of 2015, which is said to be unfavourable to investors.
The amendments will also address cost recovery; dispute resolution; local content; responsibility between the two parties in the contract and the exploration period.
U.S. firm AfricaGlobal Schaffer (Washington, DC), in collaboration with U.S. project developer Sun Africa (Miami, Florida), signed a contract with the Government of Angola to develop a $2Billion solar project in four southern Angola provinces.
The project will include solar mini-grids, solar cabins with telecommunications capabilities, and home power kits. In addition to supporting up to $1.3Billion in U.S. exports, the project will help Angola meet its climate commitments, including generating 70% carbon-free power by 2025, a statement in a factsheet from the US White House says.
The Angola facility is heavily supported by the U.S. Department of Commerce and the Export-Import Bank of the United States (EXIM).
It is one of several projects targeted by $200Billion being mobilized by the US government from the private sector in the context of the Partnership for Global Infrastructure (PGII) launched by the G7 leaders “to deliver quality, sustainable infrastructure that makes a difference in people’s lives around the world, strengthens and diversifies our supply chains, creates new opportunities for American workers and businesses, and advances our national security”, says the White House fact sheet.
The Angolan solar project fits into the first of the four priority pillars through which the US will execute the PGII. That pillar involves: tackling the climate crisis and bolstering global energy security through investments in climate resilient infrastructure, transformational energy technologies, and developing clean energy supply chains across the full integrated lifecycle, from the responsible mining of metals and critical minerals; to low-emissions transportation and hard infrastructure; to investing in new global refining, processing, and battery manufacturing sites; to deploying proven, as well as innovative, scalable technologies in places that do not yet have access to clean energy.
It’s no longer news that the Independent E&P companies have largely left frontier exploration in Africa for the majors.
But we must rejig our confidence in the ability of this species to own the future of the continent’s hydrocarbon industry.
However low the margin is, however high the cost of acquisition and however dire the above ground risks are, the Independents are making the case that assets divested by the majors are theirs to inherit.
A significant seismic shift took place in Angola recently, where Sonangol, the once mighty, former monopoly state hydrocarbon firm (who once played the role of its country’s regulator and commercial entity combined), declared that a bunch of small and, in cases, newly minted minnows, including Afentra, Sirius, Somoil, Sequa and Petrolog, had won the bids to acquire several of its stakes in Blocks 3/05, 15/06, 18, and 31, all producing licences.
The big story of 2022 has however remained Seplat Energy’s announcement about penning an agreement to acquire ExxonMobil’s subsidiary holding the company’s shallow water assets off Nigeria. The invoice is $.1.28Billion.
And while that story was sucking all the oxygen in the room, there was a tiny part of it most of us didn’t notice: the reserved bidder in the chase for those assets, running close behind Seplat Energy, is a consortium consisting of a brand-new Nigerian junior named Chappal and the well-known UK listed Capricorn, (Cairn Energy), the finder of Senegal’s first commercial sized oil field, which was also in the news recently as co-acquirer of most of Shell’s producing assets in Egypt.
The Africa Oil+GasReport is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for international corporations, local entrepreneurs, technical enterprises or financing institutions, for useful analyses of Africa’s oil and gas industry. It has been published by the Festac News Press Limited since November 2001, and since the COVID 19 season, as a monthly digital (pdf) publication, delivered to subscribers around the world. Its website remains www.africaoilgasreport.com and the contact email address is email@example.com. Contact telephone numbers in our West African regional headquarters in Lagos are +2347062420127, +2348036525979, +2348023902519
ION Geophysical Corporation (has completed the reprocessing and reimaging of approximately 19,100 km² of 3D seismic data offshore West Africa for its Mauritania 3D reprocessing programme.
The multi-client project was undertaken through an exclusive agreement with the Ministry of Petroleum, Energy and Mines in Mauritania. It is comprised of 11 vintage seismic surveys and provides a seamless, modern, high resolution data set spanning the Mauritanian offshore coastal basin. This basin is a key part of the frontier MSGBC basin in which several large-scale, offshore, gas fields have been discovered, with an estimated 63trillion cubic feet (Tcf)* in place in Mauritania thus far, ION declares.
“With foreign investment flowing in, field developments expected to come online in 2023, gas favoured as a source of energy for the energy transition, and capacity expected to exceed domestic needs, contracts for LNG export to European and other markets is anticipated”, the company reiterates.
“The MSGBC basin has become one that matters in the global oil and gas landscape, even if it is still today a frontier area. We have an enormous potential and we must find the right solutions to use these resources for the development of the country,” stated Chemsdine Sow Deina, Exploration Director at Societe Mauritanienne des Hydrocarbures (SMH).
“With ION’s delivery of its Mauritania 3D reprocessing program, operators now have a lower cost, lower risk, sustainable solution for evaluating the offshore hydrocarbon potential of Mauritania,” said Chris Usher, President and CEO. “As a result, we anticipate additional discoveries will be made that ensure Mauritania’s long term energy security, as well as exports that fund sustainable economic growth and development.”
The Mauritania 3D reprocessing program was supported by the industry and almost triples the amount of 3D data that ION has delivered this year from approximately 10,000 km2 to 29,000 km2. Final pre-stack depth imaged deliverables are now available. Learn more at iongeo.com/Mauritania.
*Estimate from Mauritania-Senegal: an emerging New African Gas Province – is it still possible? October, 1, 2020. The Oxford Institute for Energy Studies
Making maps from 3-D seismic data on a computer workstation was a completely new experience. It was my first encounter with such technology at work. We turned out much more accurate maps of very complex subsurface structures. And it was easier doing this than the labourious manual system we had been used to!
When an NNPC team led by Mr. Jim Orife came for a high-level JV meeting in Chevron offices in San Ramon, California, United States, I was chosen to present to them the fascinating results of the work we were doing. I had never seen my bosses so proud of their staff. I remember Mr. Orife calling me aside afterwards and saying “Ï have always said this to all my staff, no matter where you are, your biggest godfather will always be your competence and dedication to duty.”
I have preached the same sermon to all my staff and mentees to this day.
When my scheduled three-month tenure drew to a close in October 1987, Chevron sent a special request to NNPC, asking that I be allowed to spend three extra months to enable me finish the work I was doing. The request was granted, and I stayed on till January 1988.
Outside of work, it was pure excitement. I drove six hours from Sam Ramon to L.A. and spent a weekend in Disneyland and a full day at Universal Studios. I spent two working days at the Chevron Research Center in La Habra California, staff of which included Nobel Prize recipients. Nights out in Oakland and San Jose were regular weekend events. I spent a weekend driving through the Wine region north of San Francisco, to the Redwood Park in the Northern most part of California with my Chevron Colleague, Greg Croft. I drove across from Sam Ramon to the fun city of Reno, Nevada and made frequent tourist trips all around the Bay Area. Perhaps next only to my four years in UNN, those six months in California completed the excitement that youthful and early adult life was for me.
I was confused, this was a start-up Nigerian Company that could fold up within a year. NNPC had been exciting but I was beginning to doubt if the reward system had room for so called “exceptional performers”.
When I returned to Lagos in January 1988, the GM Exploration at Chevron invited me to his office and revealed to me that his principals in San Ramon were very impressed with my performance. He offered me a job in Chevron and told me he was leaving the offer open for a twelve-month period. Whenever I made up my mind, I was to return to his office to conclude discussions with him.
At this point I was generally perceived as a high flyer with a very bright future in NNPC, even though I had never earned a promotion ahead of my peers. I was sent on more training attachments to Shell’s Seismic Processing centre in Port Harcourt in 1990 and subsequently to Western Atlas Seismic Processing centre in London in 1990/91. The high point of my career in NNPC was winning the GMD’s award in 1991 “for exceptional performance”.
In September of that year, seven of us geologists were selected to go to the University of Ibadan for a one-year postgraduate diploma in Petroleum Engineering. This was a programme meant to convert us from Geologists to Petroleum Engineers. Midway into the programme, I got an offer that was to change my professional trajectory and instill an entrepreneurial mindset in me.
Prof. Jubril Aminu, as Petroleum Minister, had awarded eleven oil blocks to prominent Nigerians in 1990/91 on discretionary basis, to promote indigenous participation in the sector. One of the recipients was Mr. Kase Lawal, a young, Houston based international businessman. His company, Paclantic Petroleum (a subsidiary of his Houston headquartered CAMAC Group) had been awarded OPL 204. He was setting up shop in Nigeria and looking for a couple of people to hire. Originally from Ibadan, he contacted his kinsman in NNPC (Dr. Olu Ayoola, who retired later as GED Upstream) to recommend two people he could hire. Dr. Ayoola gave him two names: Mr. George Osahon, who was a highprofile Deputy Manager and I (just becoming an Assistant Chief Geologist). He warned him, however, that he was unlikely to be able to hire us out of NNPC.
We interviewed with Mr. Lawal and he made us offers. My offer was a handsome naira salary plus a dollar component of $36,000 per annum! An official car was also thrown into the bargain and I was going to be the Exploration Co-ordinator of Paclantic (whatever that meant), while Mr. Osahon would be my boss as the General Manager. Now, I was confused, this was a start-up Nigerian Company that could fold up within a year. NNPC had been exciting but I was beginning to doubt if the reward system had room for so called “exceptional performers”. I was on the same rank with all my peers, including those that had been training under me.
I am usually not strong on risk taking and I do not gamble, so I took the offer letter to Mr. Ofurhie. Surprisingly and without hesitation, he said I should take the job. I reminded him that he had previously advised me that if I ever decided to leave NNPC, I should only go to one of the IOCs. He simply ordered me to accept the offer and assured me that if the company folded up, I would get another job as I was well regarded in the industry. I left his home and went straight to Mr. Lawal to accept the offer. On March 2nd, 1992 I assumed duty in Paclantic as Exploration Coordinator, while still running my Post Graduate Programme at the University of Ibadan.
I disengaged from Allied on July 01, 2002, after ten exciting years. This, whole narrative about my education and professional training is meant to situate the author in proper context for the benefit of readers especially as it relates to my bonafides as an entrepreneur
I settled fully into the job in July 1992, upon graduation from U.I. My first task was to interpret the available seismic data over OPL 204. The block was completely barren, lying at the edge of the cretaceous and beginning of the Niger Delta. There was no prospect within the acreage that could be proposed for drilling. Fortunately, Kase had applied for a deep offshore block as the terrain was opened up for exploration in 1991. A number of IOCs were hot on the race for the few blocks that were on offer. In June 1992, Kase’s company, Allied Energy Resources was awarded OPL 210. The next hurdle was to secure a technical/financial partner to fund the initial work programme for the block. While Kase was working the corridors of power to secure the block, Conoco had indicated interest in farming in if he was successful in getting the property. But after initial evaluation, they declined to farm in. Next candidate was the Statoil/BP Alliance, which had also been awarded two blocks, OPLs 217 and 218. After some tough negotiations, they agreed to farm in for a 40% working interest, but assuming 100% financial responsibility for working the asset. Allied Energy was paid enough money to offset the statutory signature bonus with a decent sum to spare. As part of their responsibility to help develop internal capacity within Allied, the partner was also expected to pay some “Upkeep” stipend to Allied. With this partnership agreement in place, Mr. George Osahon and I set out to build Allied Energy from scratch.
We hired four smart, young men, a geophysicist, a geologist and two petroleum engineers, equipping them with a full 3-D Seismic workstation, drilling and reservoir engineering software suites and arranged rotational attachments for them and myself to the Statoil study team in Stavanger, Norway. The Allied team participated fully in the design and planning of what turned out to be, the first deep offshore well in Nigeria, the OYO-1 well which was drilled successfully as a commercial discovery in 1995. During this period, the block had been covered with full 3D Seismic data. Through the evaluation of the seismic data, and the successful well and the planning for its appraisal and development, the compact technical team in Allied had honed its skills and grown in confidence. The plan was that in ten years from 1993, we would have grown in technical and management capacity to take over operatorship of OPL 210. The first test of this plan came in 1997. Cavendish Petroleum, awardee of OPL 453 (one of the earlier 11 discretionary awards) had, along with her Technical Partner Conoco drilled a well, Obe-1 and made a modest discovery. Not material enough for Conoco they decided to exit the block. Because we (CAMAC) had a minority (2.5%) stake in the block, we had access to all the data Conoco acquired, including the Obe-1 well data. After a detailed evaluation of the seismic and well data, we proposed to Kase that we could farm into the field as technical partner to Cavendish. So, in a mere five years, Allied had developed enough capacity to provide technical partnership support to another indigenous company. It was an interesting development, as Allied got into partnership with Cavendish using the exact same structure Statoil had with us. This time, Allied had 40% working interest and 80% commercial interest. Just as Statoil had paid us, Allied paid Cavendish a farmin fee and a monthly stipend to cover their office running costs.
We prepared the full Field Development Plan (FDP) for the Obe field, including the production profile and projected commercial rewards. We presented this as a commercial proposal to Tuskar Resources, a small Irish Oil Company listed in Dublin but also trading on the London Stock Exchange (LSE). The deal was for Tuskar to inherit our full commercial interest in the Obe field in what amounted to a reverse take-over of Tuskar by Allied. By the time the deal closed, Allied owned 67% of Tuskar Resourceswhich was trading at about 1.5 pence per share at the time with a market cap of about ten million pounds sterling. Deal done, Allied raised debt funding from some London banks and we proceeded to develop the field and put it on production in 1999. As planned, the field was doing about 4,000 bopd and utilizing a small FPSO with 45,000-barrel storage capacity. By the time the field came on production, Tuskar share price had risen to over 10 pence with a market cap of about seventy million pounds sterling. The story of how this great enterprise was eventually squandered has been told somewhere else.
By 2001, there was talk of government action towards awarding marginal fields to companies organised around experienced and/ or retired professionals. In my nine years at Allied, I had been at the forefront of the advocacy for indigenous participation in the Upstream Oil and Gas Sector in Nigeria. I had written and spoken extensively on the subject. I had also gained extensive experience, not just in starting up and organising an oil and gas company but in the commercial and entrepreneurial side of things. Nothing was going to stop me from participating in the imminent marginal fields licensing round. My days in Allied were numbered.
I disengaged from Allied on July 01, 2002, after ten exciting years. This, whole narrative about my education and professional training is meant to situate the author in proper context for the benefit of readers especially as it relates to my bonafides as an entrepreneur. My experience, over eighteen years, in setting up Platform Petroleum and Seplat Petroleum (now Seplat Energy), constitutes my personal account and views on the challenges of entrepreneurship in Nigeria.
Excerpted from ‘My Entrepreneurship Journey’, a Memoir by Austin Avuru, founding CEO, Seplat Energy. The book is due to be released in August 2022 by Radi8 Publishers
Norwegian geophysical company PGS says it has been awarded “a significant acquisition contract, consisting of several four-dimensional (4D) seismic surveys, by an international oil company offshore West Africa.
Acquisition is scheduled to start early November 2022 and expected to complete early May 2023.
The contract effectively secures work for the company’s flagship acquisition vessel, Ramform Vanguard until next summer season.
“Combining the Ramform acquisition platform and our GeoStreamer technology will provide the client with high quality 4D data,” says President & CEO in PGS, Rune Olav Pedersen.
Canadian junior ReconAfrica is about to drill its first seismically defined hydrocarbon well in the Permian aged Kavango Basin onshore Namibia.
The 8-2 well is the first of an initial four well drilling programme, which will test two of the Basin’s three play types; oil prone Karoo Rift Fill and Intra Rift Fault Block plays, determined by interpretation of parts of the 1,211 kilometres of two dimensional (2D) seismic data acquired within the company’s over 34,000 square kilometre licensed area.
Jarvie-1, the company owned 1000 HP drilling rig “is now on the first drilling location (8-2) rigging up and scheduled to spud on or before June 25, 2022”, ReconAfrica says in a release.
ReconAfrica has just completed the second phase of its 2D seismic acquisition (761 km) with plans for the next phase of 2D seismic acquisition, which is anticipated to comprise in excess of 1,000 kilometres of 2-D seismic, making 2,211 kilometres of 2D seismic altogether. This (second phase) will be an extensive programme and subject to permitting, the Company anticipates on the ground acquisition to begin the fall of 2022.
8-2 will be drilled to a planned depth of approximately 2,800 metres (9,184 feet) and is designed to test potential conventional oil and associated natural gas reservoirs in clastic rocks (sandstones) in the Karoo Rift Fill, the Company’s primary play. The well will also be drilled deeper into the Pre-Karoo Mulden and Otavi formations. These intervals correspond to zones in the Company’s first well, the 6-2, (a non-seismically defined stratigraphic test) which is approximately 6.5 kilometres to the East, that had good oil and gas shows. It is anticipated the well will reach total depth within 60 days from the initial spud. Netherland, Sewell & Associates, Inc. (“NSAI”), the Company’s independent qualified reserves evaluator, has estimated an unrisked gross 799Million barrels of original oil in place (OOIP) for the well 8-2. The estimated unrisked gross prospective resource, (P50 case) with a projected 17% primary recovery, is 138Million barrels of oil for this well. Prospective resources are the arithmetic sum of multiple probability distributions.
“These estimates are based on un-risked prospective resources that have not been risked for chance of discovery and chance of development. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development”, ReconAfrica cautions. “There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by applying future development projects”.