All posts tagged feature

Africa Oil Makes $137.5Million in Seven Months, on Asset It Purchased for $519Million

Section: Farm in, Farm Out · August 31, 2020 · No comments |

Africa Oil Corp. concluded its acquisition – worth $519.5Million – for a 50% ownership interest in Petrobras Oil and Gas BV (POGBV) in January 2020.

Today, seven and half months later, it reports it has received total dividends amount of $137.5Million since the closing of the Prime acquisition on 14 January 2020.

POGBV’s primary assets are an indirect 8% interest in oil mining lease (OML) 127, operated by Chevron, containing the Agbami Field, and 16% interest in OML 130, operated by TOTAL and contains the Akpo and Egina Fields, offshore Nigeria.

The Toronto listed minnow says it has received four dividends from Prime Oil and Gas B.V. (Prime) since the January 2020 purchase. Prime is a company that holds interests in deepwater Nigeria production and development assets.

On August 31, Africa Oil Corp. reported that Prime has distributed the fourth dividend, “a $50Million dividend with a net payment to Africa Oil of $25Million related to its 50% interest”.

The Company has applied $17.7Million of this dividend to pay down the BTG term loan, reducing the outstanding balance to $176.9Million.

Africa Oil Corp. is a Canadian oil and gas company with producing and development assets in deepwater Nigeria; development assets in Kenya; and an exploration/appraisal portfolio in Africa and Guyana. The Company is listed on the Toronto Stock Exchange and on Nasdaq Stockholm under the symbol “AOI”.

In Pursuit of Africa’s Green Deal

Section: ENERGY TRANSITION · August 31, 2020 · No comments |

By Gerard Kreeft

“The call to leave fossil fuels in the ground is a Western narrative and fails to factor in the needs of low-income Africans who would gain from a strategic approach to oil and gas operations, job creation and local enterprise opportunities,”. Quoted by NJ Ayuk, Chair, African Energy Chamber in Upstream.

NJ Ayuk’s remarks are directed to the IMF, IEA, and OECD, who are urging African countries to abandon their oil and gas assets and instead become pro-active and join the Energy Transition.

Solar, wind and hydropower are the symbols of this transition.

Setting the Scene: The External Constraints

While Ayuk’s sentiments may strike a responsive chord it also invites a measured response. The Energy Transition is global and not restricted to Africa. It supercedes national boundaries.

The response from the oil and gas community, given that many of the oil majors work on a global basis, is also done on a global basis. This past six months, with the double curse of an oil trade war and COVID-19, the response was a global lockdown, regardless of where the majors had operations. While this double jeopardy has little to do with the Energy Transition, the global affect factor is omnipresent.

Of importance to Africa is the rate of impairment to oil and gas projects on a global scale. The most radical sign was TOTAL’s writing down two oil sands projects in Canada which it had categorized previously as “proven assets”.

The SPE (Society of Petroleum Engineers ) on behalf of the industry, is responsible for categorizing oil and gas reserves. The category “proved reserves”is the gold standard for indicating a company’s oil and gas reserves. If proven reserves indeed becomes the equivalent of stranded assets this should sound off alarm bells in the board rooms of all the majors.

TOTAL’s strategy is focused on the two energy scenarios developed by the IEA (International Energy Agency). Stated Policies Scenario(SPS) is geared for the short/ medium term; Sustainable Development Scenario(SDS) for medium/long term. The scenarios are in line with the Paris Climate Agreement. Taking the “well below 2^oC ”SDS scenario on board, TOTAL has in essence taken on a new classification system for struggling oil companies seeking a green future.

ExxonMobil is following a similar line. In a recent filing with the US Securities and Exchange Commission, the company indicated that it is possible it will write down its Kearl Project proved reserves in the Canadian Oil Sands of its Canadian affiliate Imperial Petroleum, which account for 20% of the company’s 22.4 BOE ( billion barrels oil equivalent) reported at year 2019.

Finally there is the Deloitte study entitled “The Great Compression: Implications of COVID-19 for the US shale market”. Deloitte is forecasting impairments of up to $300Billion; and 30% of shale operators are technically insolvent.

The Deloitte study notes: “New telecommunicating norms, regionalized trade and supply chains and the stable business profile of new energies have fast forwarded the spector of peak demand to the present”.

What the study is really concluding is that the oil and natural gas infrastructure is crumbling before our eyes and being replaced by new energy which is reliable and stable!

For the service sector both Rystad Energy and the Boston Consulting Group have little good news. At the beginning of this year, according to Rystad, ultra-deep day rates were moving to the mid- $250, 000 –$260, 000 for spot work, and expecting to cross the $300 000 threshold for work with long lead times. Now further rate drops could push day rates to a level of the offshore driller’s operating expenditures.

The Boston Consulting Group, in a recent study, concluded that in 2021 the service sector will be asked to reduce costs between 20 -25%.

An African Response

Africa has 10% of the world’s oil reserves and 8% of the natural gas reserves.

African countries are also revising their energy plans. Angola’s Council of Ministers approved a revised hydrocarbon exploration strategy that will be in effect until 2025. The strategy aims to guarantee a baseline production of over 1MMBOPD (Million barrels per day) by 2040 and the discovery of 17.5Billion bpd of oil (barrels per day) and 27 tcf of natural gas. Currently the country’s production is 1.2MMBOPD.

In a mature petro-economy where oil assets are starting to age, perhaps a bold strategy. Yet the Government with this plan is admitting that production will be halved compared to the 1.8MMBOPD of a decade ago.

Angola’s goal of 1MMBOPD of production is not guaranteed. A writ from the Angolan Government having such a strategy is dependent on factors beyond its control. Is there any guarantee that a portion of these potential reserves will not become stranded assets?

What about the majors, in particular TOTAL, which has a dominant position in Africa. In the past months TOTAL’s strategy was to reduce spending, sell marginal North Sea assets, buy Tullow’s Uganda assets at fire sale prices, and seek financing of its Mozambique LNG project.

The speed of bringing projects to market will not be determined by the Government of Angola, but rather TOTAL’s pursuit of following the IEA norm of well below 2^oC.

Clark Butler, author of the IEEFA’s (Institute for Energy Economics and Financial Analysis) reports in a study “Oil Supermajors’Trajectory Towards Renewables Needs to Scale Up and Speed Up” that TOTAL must drastically increase its renewables and decrease its carbon intensity if it is to meet its climate goals. This can only mean reducing its carbon footprint and yes, in Africa, and in this case Angola will be thrown under the bus.

Is Angola the exception? Not likely. Other African producers have varying energy and environmental policies. Africa is a house divided. Many countries, Many policies.

An African answer can possibly be found in the long-delayed African Continental Free Trade Area (AfCTFA) which kicks in next year. Then 1.2Billion people across 55 nations needing access to an integrated regional energy market supported by local supply chains and intra-African trade will take place.

Highlighting the agonies of the oil and gas sector tends to blot out the march that renewables are making. Again take Angola and the goals that are being set:

The Laúca Hydropower Plant, once completed will reach an installed capacity of 2, 070 MW, becoming one of the largest hydropower plants in Southern Africa, alongside the Cahora Bassa Hydropower plant, in Mozambique.
The Baynes Hydroelectric Dam. Located on the Cunene River on the border between Angola and Namibia, the 600-megawatt dam is planned for commencement of construction in 2021, with an estimated cost of $1.2Billion and a completion date scheduled for 2025. Of the 600 MW to be produced by the plant, 300 MW will be directed to Angola and Namibia, respectively.
Improving the access to energy services in rural areas based on renewable sources.

Dr Akinwumi A Adesina, President of the African Development Bank
Develop the use of the new renewable technologies connected to the grid, enhancing the establishment of new markets and reduction of regional asymmetries.
Promote and accelerate the private and public investment in the new renewable energies.

Finally, a small footnote to congratulate Dr Akinwumi A Adesina, President of the African Development Bank on his re-election for a five-year term. Under his leadership “Light Up and Power Africa”became a key theme of the Bank.

The Bank Group has approved a 125% increase in the General Capital of the Bank raising its capital to $208Billion from $93Billion, the largest in the history of the Bank.

In the next five year period of his Presidency oil and gas assets should be viewed as a currency to finance the next step of the energy transition ensuring that Africa can design and build its own Green Deal.

Kreeft, BA ( Calvin University ) and MA (Carleton University, Ottawa, Ontario, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. He writes on a regular basis for Africa Oil and + Report.

Nigeria Will Reduce Taxes on Onshore, Shallow Water Licences in New Petroleum Law

Section: In the news · August 31, 2020 · 1 comment |

By Toyin Akinosho, Publisher

Nigerian authorities are “not unmindful that the industry players are of the view that the current level of taxation on onshore and shallow water operation is excessive”, Timipre Sylva, the Minister of State for Petroleum Resources, has declared.

“Therefore, proposed petroleum industry bill (PIB) should include the significant lowering on these taxes for new investments and for existing operations”, he explained.

Mr. Sylva announced that in the new law, which will soon start undergoing a series of readings at the country’s parliament, “lowering of royalties is contemplated, particularly for low levels of production per field”, adding, “it is therefore our hope that the future is more positive and attractive for the Nigerian petroleum industry after the passage of the PIB”.

The Minister, who spoke as a guest of the Nigerian Association of Petroleum Explorationists (NAPE), the largest grouping of oil industry technical personnel, contended that “in the short term, the government will need a maximum fiscal environment to deal with the COVID-19 crisis”.

For this reason, he said, “we are proposing in the new law, a grandfathering”, which, in his view “will preserve current government while also guaranteeing investors return. It also guarantees that investors can continue with existing operations while earning favourable returns”.

The proposed PIB framework shall, he said, “be based on core principles of clarity, dynamism, neutrality, open access and fiscal rules of general application”.

At the same time, investments in new equities “will be encouraged with attractive competitive terms in order to achieve economic growth. Investors in existing assets will be able to sign conversion contracts to obtain better terms for existing production and be able to explore and produce parts of the existing blocks under the new terms. Investors that also want to continue operating under current fiscal terms can elect to do so (I already mentioned that)”.

Sylva, a former governor of the country’s third largest oil producing state, (Bayelsa), explained at the discourse that “Host communities will be adequately covered to foster sustainable prosperity within the communities, provide direct social and economic benefits from petroleum operations to the host communities”.

Oriental Proposes Sale of Equity in Nigerian Assets

Section: Farm in, Farm Out · August 3, 2020 · 1 comment |

Oriental Energy Resources has commenced a marketing campaign of certain interests in its existing offshore Nigeria assets to qualified prospective partners, having recently obtained Government approval for its legacy block Oil Mining Lease (OML-115) for a new twenty-year term under terms which include a zero-relinquishment provision.

OML-115 includes an oil discovery adjacent to the Okwok Field, and several large potential exploration prospects defined by a block-wide circa $40Million state of the art four-component 3D seismic survey acquired in 2012, the same seismic data set that was used to define Oriental’s recent successful exploration well Ebok-45, that has tapped a significant new pool of light oil in acreage adjacent to OML-115.

Oriental is an indigenous offshore (marginal field) operator and oil producer, and the 100% interest owner of OML-115 and the Ebok Field in OML-67, and the 88% interest owner of the Okwok Field in OML-67. In Oriental’s nearly 30-year history, it has partnered with Conoco, Nexen, Mobil-NNPC, Addax Petroleum, Energy Equity Resources, and Afren Plc.

Oriental’s recent Ebok-45 Deep Discovery promises to deliver a potential recoverable reserve of a similar or greater scale than both Ebok and Okwok Fields.

“Oriental has been responsible from Day One to maintain all of its licenses in good standing with the Government, to acquire all permits and licenses for the circa $4Billion Ebok Development and its 45 wells drilled to date”, the company says in a note to investors.

“Since 2015 Oriental has completed the acquisition of 100% of the Ebok Field equity, and is bearing 100% of the Ebok Field production costs” Oriental explains, “as well as the recent deep exploration discovery well costs and of the future planned Ebok exploration and appraisal drilling programme”.

The Okwok Field is currently under development with a well-head and FPSO development solution that has its FDP approved and under way to deliver First Oil in mid-2021. From Oriental’s recent organic exploration successes and the conservative reserve potential Oriental anticipates achieving gross production from the combined Ebok and Okwok Fields of circa 50,000BOPD by year-end 2023 and has set a corporate goal of attaining 100,BOPD by year-end 2028.

This article was originally published in the May 2020 edition of Africa Oil+Gas Report.

Oil Majors in Retreat from Congo, Gabon

Section: In the news · August 3, 2020 · No comments |

By Fred Akanni, Editor in Chef

French oil major TOTAL announced last week it had agreed to sell its stakes in seven oil fields in Gabon, around the time that news filtered in that ENI had proposed divesting stakes in its operated acreages in Congo Brazzaville.

TOTAL will soon announce sale of its stakes in Congo Brazzaville. It’s only a matter of time.

Considering that Shell sold its entire onshore assets in Gabon in 2017, these two announcements tell the story that the majors are winding down in these countries, where new hub size, short term-to-market discoveries have not been made for some time.

ENI’s decision to sell in Congo is surprising, giving the Italian explorer’s penchant for developing hydrocarbon tanks that other majors dismiss as marginal. Indeed, it was only late in 2019 that ENI completed phase 2A of the Néné Marine project by putting a total of 15 wells into production and approved the implementation of phase 2B.

TOTAL, effectively, is completing a second sell off in Gabon to Perenco, the unlisted French independent, in the space of three years.

The Paris based explorer divested its stake in five fields, representing 13,000Barrels of Oil PerDay, positions in exploratory tracts, as well as the Rabi-Coucal-Cap Lopez pipeline network, all to Perenco, for $350Million in 2017. Now it is selling again to the same company, including the operatorship in the Cap Lopez oil terminal. TOTAL is going to receive $290Million and $350Million for these assets, depending on future prices of the Brent crude.

TOTAL claims to “remain fully committed to Gabon through our operated production clusters at Anguille-Mandji and Torpille-Baudroie-Mérou, where we continue to maximize value for all stakeholders,” but that statement is for optics.

The aggressive French player has the biggest, forward looking projects in Africa today.

It is constructing a $20Billion LNG facility in Mozambique, working on financial close for a $12Billion basinwide oil development in Uganda and appraising a large oil, gas and condensate find, a new heartland if you wish, in South Africa.

TOTAL’s portfolios in Angola and Nigeria, each delivers no less than 350,000Barres of Oil Equivalent a Day.

AKK: Why the Viability is Fuzzy and Delivery Timeline in Doubt

Section: Gas Monetization, In the news · August 3, 2020 · No comments |

By Toyin Akinosho, Publisher Africa Oil+Gas Report

At 614 kilometres long, and running through four states, the Ajaokuta -Kaduna-Kano (AKK) National Gas Pipeline in Nigeria is the kind of infrastructure project that is described in the country’s Economic Growth Plan as transformational.

If the theory holds true that gas utilisation projects have a way of following the availability of the core trunk lines. and that every $1 spent investing in gas development and infrastructure will translate to a $3 increase in GDP, we should applaud the inauguration of AKK’s construction.

What has invited so much scrutiny is the Nigerian government’s decision to provide Sovereign Guarantees for the loan taken to construct the Project.

It is so, in part because, this is the first of several gas pipeline projects by NNPC that would come with a loan tag. The state hydrocarbon company constructed the Escravos Lagos Pipeline System and the Oben Ajaokuta gas pipeline from its balance sheet. NNPC has not disclosed that it is borrowing money to construct the 130km, 48 inch Oben-Obiafu /Obrikom pipeline, the biggest such infrastructure in the country.

But with the AKK project, the cash strapped petrostate is staking money from its depleted treasury to shoulder as much as $2.1Billion, net of interest, should there be the most extreme default in paying the loan from The Bank of China and Sinosure, a Chinese export and credit insurance corporation.

The timing and prioritization of the AKK project, in the context of other urgent deliverables in the Nigerian gas grid, the opportunity deliberately thrown away for private sector investment in our infrastructure queue as well as NNPC’s poor record of project delivery, are other issues that make the state’s financing of the AKK quite concerning.

Lenders, as a rule, call for offtake agreements as well as evidence of ability to pay, as preconditions for loans to gas projects.

The NNPC, promoter of this wide diameter (40 inch) line, does not have any Gas Sales Agreement with any factory, manufacturer, or plant, for gas from the project. Instead, it has pledged its entire receivables from gas flows from the existing pipelines today (Escravos Lagos Pipeline System ELPS, Oben-Ajaokuta Pipeline and West Africa Gas Pipeline WAGP) and used that to pledge in terms of the tariff. The tariff-receiving companies are the two gas subsidiaries of the NNPC: Nigerian Gas Processing and Transportation Company and the Nigerian Gas Marketing Company.

NNPC has admitted, in public, that generating the revenue to pay the loan is a tall order. Indeed, the need to convince the lenders it could raise financing for the project, hastened the government’s decision to launch the Gas Transmission Network Code, which takes off in mid-August 2020.

“We didn’t want to burden the National Treasury with funding the construction of the AKK pipeline”, Yussuf Usman, the corporation’s Chief Operating Officer Gas and Power, told a panel session at the Sub Sahara Africa International Petroleum Conference (SAIPEC) in Lagos in late February 2020. “But when we went out to financiers, and told them we would guarantee the loan with payment from the gas in the various domestic gas transmission pipelines, they asked for volumes”, he explained. “The volumes did not add up”, he said. “We knew we had to launch the Gas Network Code so that there would be assured volumes and they can be determined”.

President Muhammadu Buhari declares that the pipeline would provide gas for the generation of power and for gas-based industries to facilitate the development of new industries. The president promises that AKK would “ensure the revival of moribund industries along transit towns in Kogi, Abuja, Niger, Kaduna and Kano states”.

For one, the power plant Mr. Buhari refers to, is still on the drawing board. It was only last February that NNPC received a USAID grant for its feasibility studies.

For another, moribund industries along the AKK corridor notwithstanding, the anticipated industrialization will take time to fledge, but the loan repayment will start being called before any sizeable industrial project takes hold.

Supporters of the AKK project stretch the argument when they compare this project with the ELPS, which some recall, in the original plan, was proposed to be a 12 inch pipeline. “NNPC in its wisdom decided to build a 36” pipeline”, these supporters contend. “As of ten years ago, that capacity, 1Billion standard cubic feet per day (1Bscf/d), was already filled up because gas is about availability”, they enthuse. “Today, we are building a loop around ELPS to double the capacity”, they cheer.

These “facts” have hidden one uncomfortable truth: the ELPS never achieves 100% uptime, so the 1Bscf/d, under NNPC management, has been a façade.

35 years ago, as a young energy reporter for The Guardian of Lagos, I was at the commissioning of the 1,300MW Egbin Power Station in Ikorodu, in the north of Lagos. Tam David West, who was then the Nigerian Minister of Power, said that the nation was anticipating the construction of the ELPS to deliver the gas that would replace the High Pour Fuel Oil, that was being used to fire the turbines at Egbin at the time.

When the ELPS was commissioned 14 years later, the market was ready with, apart from the largest power plant in the country, industrial enterprises along the Ikeja-Ikorodu corridor that were offtakers of natural gas.

The AKK is unlikely to be delivering, in the near future, to that sort of market, so its funding should have been differently thought through. And a key question is why NNPC is insistent on throwing itself at this project which started with the Korea National Oil Company proposing to execute-net of Nigerian national treasury-as part of their taking up two deepwater exploration acreages?.

NNPC, as project manager and executor, is itself a poor advertising for the timeous delivery of any project. It has been constructing two similar grid length gas pipelines, planned for four year execution, for over eight years without visible indication of their completion. It has been looping (constructing a parallel line of the same length) the Escravos Lagos Pipeline System since 2012. It has also been constructing the Obiafu-Obrikom Oben (OB3) pipeline since 2012. There is no clear line of sight to completion of these projects. And in none of its reports has there been indication of what the delays on the projects mean in terms of haemorraging value.

These two projects are more urgent, in respect of immediate inflow of investment and cash to the Nigerian economy, than the AKK.

Take a few examples.

The ELPS is the primary ferry from the biggest gas processing plants, aimed at the domestic market. These processing plants; Chevron operated Escravos Gas Processing Plant, Seplat operated Oben Gas Plant, and NPDC operated, with NDWestern, Utorogu and Ughelli plants, have the combined capacity to deliver 1.3Billlion standard cubic feet of gas per day, but persistent downtime on the ELPS ensures the gas volumes cannot fully be pumped into this artery and our power plants, those of them that could offtake, don’t receive what they could. So, while NNPC claims it is doubling the capacity of the ELPS, neither the “original” line, nor the “new” line under construction, combined, is delivering anywhere near 80% of a single line (800MMscf/d).

The Dangote Fertiliser gas offtake agreement (75MMscf/d) with Chevron depends on the flip flop of the ELPS uptime, so does Axxela Ltd’s plan to export gas (30MMscf/d) from the western Niger Delta to Togo. Axxela is even working with NNPC to see how they can complete the looping project. This is the scale of incapacity of a company that wants to “own and operate” one more transmission gas pipeline!

The OB3 gas line is the first attempt to turn our gas transmission lines to a grid. It would deliver gas from the rich reservoirs in the east to the captive markets in the west. It is also the source of the gas that will be pumped into the AKK, because the AKK is to originate from Ajaokuta, which is fed from Oben, the terminal point of the OB3. As it is, NNPC has pushed the completion date of OB3 several times over its eight-year construction span.

A $1+Billion gas production and distribution project that depends on the OB3 is the 600MMscf/d ANOH facility, led by Shell and Seplat. Whereas Shell wants to supply the gas to factories in eastern Nigeria, Seplat wants to pump the molecules into the line, straight to Oben in Edo State, for its offtakers in the west of Nigeria. NNPC even forced itself to construct the short gas lines from the processing plants to the OB3 trunk line. These companies went ahead and took final investment decisions on the midstream part of the project, but are they likely to be idly chewing their thumbs after their plants are completed and they can’t evacuate the gas? Last time I checked; they were scrambling for alternative routes to transport the molecules.

NNPC knows what to do. But if you ask the apparatchiks in the company’s towers to spinoff the Nigerian Gas Transmission Company and the Nigerian Gas Marketing Company and sell hefty stakes to the private sector, they will kick and kick, just as they’ve done with the refineries, holding on to zero value. There is enough gas transportation infrastructure to form a very decent balance sheet for a gas transportation company run efficiently by the private sector. But who cares?

Namibian Minister Delegitimises Kudu Field as A Discovery

Section: Oil patch Sub-Sahara · July 29, 2020 · No comments |

By Akpelu Paul Kelechi

Tom Alweendo, the Namibian Minister of Mines and Energy, does not consider the Kudu gas field offshore the country as an asset.

When asked about his country’s contribution to conversations around global crude oil and gas demand and supply, he offered that “Namibia is a relatively new comer to this”. Then he said, surprisingly: “We don’t have a discovery, we have never had a discovery before and over the last couple of years, there have been some Majors doing prospecting in our sectors”.

The statement came in the course of a recent Webinar on Namibian Energy plans. The conversation was organized by African Energy Chamber.

The question that stood un-asked, after the minister claimed Namibia had never had a hydrocarbon discovery was: So, what should the Kudu Gas Field be called if it’s not called a discovery?

The Kudu field, discovered in 1974 by Chevron, is a deep-water field in 600 metres of water. The gas is stored in reservoirs at a depth of 4,400 metres (17,000 feet) and deeper, and they are interbedded with volcanic rock.

A huge challenge is that an estimated 1,3Trillion cubic feet of gas accumulation is not big enough for an LNG project, which is why the development concept has been around gas to power. There’s considerable geologic risk around Kudu, but that’ not to say it’s not sitting there.

There has been a line of investors (including Shell, Tullow), going back the last 30 years who have taken a look at the Kudu field. Till date, the field is undeveloped. But its very presence suggests that Namibia is a hydrocarbon player. Mr Alweendo, instead, prefers to delegitimize the asset. He told the webinar: “I think the prospect of us becoming a player in the upstream is really growing by the day to the extent that now, we have a couple of the major oil companies doing exploration. Therefore, when that time comes when we actually do find something, hopefully we will not just continue to be a consumer but also a producer. But even as a consumer, as small as we are, of consumers have a role to play as well”.

This story was originally published in the June 2020 edition of the monthly, Africa Oil+Gas Report

ENI Will Fastrack First Gas from New Egyptian Discovery

Section: In the news · July 29, 2020 · No comments |

Italian explorer ENI says it is working with partners, “on fast tracking production”, of its new gas discovery in Egypt, “through synergies with the area’s existing infrastructures”.

The company updated its earlier report of the find, in shallow water Nile Delta offshore Egypt.

Bashrush, as the prospect is called, delivered up to 32 MMscfd of gas.

“The test rate was limited by surface testing facilities. The well deliverability in production configuration is estimated at up to 100 MMscf of gas and 800 barrels of condensate per day”, ENI explains.

Located in the North El Hammad concession, the well encountered 102 meters net gas pay “in high quality sandstones of the Abu Madi formation”, the release says.

ENI, together with its partners bp and TOTAL and in coordination with Egyptian Natural Gas Holding Company, “will continue screening the development options of Bashrush”, with the aim of fast-tracking production through synergies with the area’s existing infrastructures.

ENIholds 37.5% interest and the role of Operator through IEOC, its affiliate, while bp holds the 37.5%, and TOTAL holds the 25% of the contractor share in the concession, which is in participation with the Egyptian Natural Gas Holding Company (EGAS).

SEPLAT: Avuru Leaves the Helm after 10 Years, Brown Takes Full Charge

Section: Petroleum People · July 29, 2020 · 1 comment |

Austin Avuru will be handing over the executive running of SEPLAT Petroleum Development Company Plc, to Roger Brown, on the last day of July 2020.

It is exactly the 10^th year to the day the company, a dual listed (London and NSE) independent, received Ministerial consent for the purchase of Shell/TOTAL/ENI’s 45% stakes in Oil Mining Leases (OMLs) 4, 38, and 41, in northwestern Niger Delta basin. That day is widely considered, in company lore, as the foundational date.

Austin Avuru will run a Family Office from August 1, 2020

“In these 10 years, Avuru led the development of a strong organization, the deployment of agile systems, processes and stakeholder relationships that allowed the organization to grow rapidly from a gross production of 22,700Barrels of Oil Equivalent Per Day (BOEPD) as at December 2010 to peaks of 111,368BOEPD gross production as at December 2018 through major drilling campaigns and major new Oil and Gas plants development”, a release by the company says.

Brown has his work cut out. The company has the $700Million Asa North Ohaji South (ANOH) natural gas development project to deliver and the newly merged 30,000BOPD Eland Oil and Gas Plc to bring into strategic fit with SEPLAT. He is taking charge in an unprecedentedly challenging season for the fossil fuel industry.

Brown is a 1992 graduate of the University of Dundee who started out as Financial Advisor at PwC, and grew into reckoning in investment circles in the 12 years he spent at Standard Bank. He joined SEPLAT in 2013 as Chief Financial Officer (CFO), has been on the board of directors for seven of the company’s 10 years.

Prior to joining SEPLAT, Brown was an advisor to the Company since 2010 while he was the Managing Director and head of EMEA Oil and Gas at Standard Bank Group. “During his time at the bank, he was instrumental in providing advice and deploying capital across the African continent in the Oil & Gas, Power & Infrastructure and the renewable energy sectors”, the company had said, while announcing Brown as MD designate in November 2019.

Brown brings to the CEO role, a deep knowledge of the Company in his 6 years as the CFO and a member of the Board. He has strong financial, commercial and M&A experience as well as proven people skills which will be an asset as the Company embarks on the next phase of its growth plan.

Avuru will remain on the bard of the company as a non-executive director. He will also be running a family office, AA Holdings. And he certainly will be very busy in the African investing landscape.

US EXIM Bank Provides the Largest Financing for Moza LNG, with $4.7Billion

Section: Gas Monetization · July 22, 2020 · No comments |

United States’ Export Import (EXIM) bank says it has initiated “the process of providing $4.7Billion in financing a major integrated liquefied natural gas (LNG) project in Mozambique”.

The money is the largest committed by any lender to the 13 Million Tonnes Per Annum project, led by French major TOTAL.

The Mozambique LNG project will cost $20Billion to develop, but TOTAL is borrowing $14.9Billion from 28 financiers.

EXIM bank is one of eight Export Credit Agencies financing the project, the priciest hydrocarbon development on the continent. Other ECAs, aprt from US EXIM Bank, are: Japan Bank for International Corporation (JBIC), Nippon Export and Investment Insurance (NEXI), UK Export Finance (UKEF), Servizi Assicurativi del Commercio Estero of Italy (SACE), Export Credit Insurance Corporation of South Africa (ECIC), Atradius Dutch State Business (Atradius), Export-Import Bank of Thailand (EXIM Thailand)”,

There are also 19 commercial banks involved, of which Standard Bank of South Africa, is leading with $485Million loan. The Africa Development Bank, which is neither an ECA nor a commercial bank, is putting $4000Million in financing.

US EXIM bank’s involvement is primarily to support American contractors involved in the project. It says its funding “will support an estimated 16,700 American jobs over the five-year construction period”. Those jobs are at 68 suppliers located in eight states — Florida, Georgia, Louisiana, New York, Oklahoma, Pennsylvania, Tennessee, and Texas — and the District of Columbia. Follow-on sales are expected to support thousands of additional jobs across the United States.

“As the Mozambique LNG project marks further milestones, we want to underscore EXIM’s continuing commitment to this project,” said EXIM President and Chairman Kimberly A. Reed. “This project continues to serve as a great example of how a revitalized EXIM can help ‘Made in the USA’ products and services compete in a fierce global marketplace and counter competition from countries like China and Russia. It also reinforces EXIM’s strong support for President Trump’s Prosper Africa initiative to unlock opportunities for U.S. businesses in Africa. This authorization will stand as a reminder to companies across the board in all industries: EXIM is open, and we want to work with you to help fill financing gaps in the market to support our great American workers and exporters.”

A US EXIM Bank press release says that the transaction supports the Trump Administration’s Prosper Africa Initiative, “a whole-of-government economic effort to substantially increase two-way trade and investment between the United States and Africa.”

Launched in December 2018, Prosper Africa brings together the resources of more than 15 U.S. government agencies, including EXIM, to connect U.S. and African businesses with new buyers, suppliers, and investment opportunities.