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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.

 


Warren Buffet’s Chevron Dilemma

By Gerard Kreeft

Warren Buffet, America’s most foremost and savvy investor, is a major Chevron investor. Berkshire Hathaway, his investment vehicle, owns 8.16% of Chevron, representing $23Billion. His foremost ability is owning stocks that have regular and high dividend returns. The Chevron dividend has for the last 35 years increased incrementally every year. No wonder that Buffet has become the symbol of blue chip stocks.

Is this about to change? Could Chevron give Buffet a black eye? This deserves a short explanation. Buffet has in the past been candid about how his early investments turned out to be duds. Berkshire Hathaway, as Buffet recalls, was originally highly involved in New England’s fading textile industry. Lessons learned from the textile industry have been a strong influence on Buffet’s investment strategy. Could Chevron go the way of the New England textile factories?

Two key factors play a role: Chevron’s lack of diversity of supply and logistically bringing Tengiz oil to the market place.

The Present Situation
Mike Wirth, Chevron’s Chairman and CEO recently revealed that two-thirds of Chevron’s total production of 3Million barrels of oil will, in 2025, come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States will each yield 1Million barrels of oil equivalent per day. Not exactly diversity of supply.

The company’s market cap is now $284Billion. Chevron’s positive image is largely because of its dividend track record: the company has increased dividend payouts for 35 consecutive years.

Chevron management, nonetheless, has suffered important setbacks at the company’s Annual General Meetings in both in 2021 and 2022. Over the objections of management, 61% of shareholders voted in 2021 for a proposal to encourage the US company to reduce its emissions. At the 2022 annual shareholders meeting 39% of shareholders voted for a resolution asking the company to provide quantitative information how a net zero by 2050 will affect key components of Chevron’s financial position, including potential impairments, remaining asset lives and asset retirement obligations.

In 2021, Chevron established a New Energies division devoted to lower-carbon technologies, pledging to spend $10Billion through 2028—about $2Billion per year, or 12.5-14% of Chevron’s projected capital budget. The company’s new energy division is focusing on the following areas:
• Renewable natural gas products;
• Renewable fuel products;
• Hydrogen production;
• Carbon capture and storage.
Will Chevron shareholders see Chevron’s new energy division as a new direction or mere symbolism? Certainly, Europe’s supermajors-BP, Shell, and TOTALEnergies-who have a dash of renewables, have seen their share prices remain stagnant. Is the alternative simply to follow the hydrocarbon route?

The company has indicated that over the next 3 years it will spend some $10.5-$12.5Billion yearly in the USA, mostly in the Permian Basin and Gulf of Mexico. This means that at least 75% of Chevron’s total capital budget over that period is pledged for the U.S. market.

Outside the USA, Chevron will spend $3.5Billion, or 70% of its international budget, to develop its Tengiz asset in Kazakhstan, with the remaining $1.5Billion spent elsewhere. This is not promising for Africa, where Chevron has major operations stretched across the continent, including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt that have received limited funding in order to bankroll Tengiz. Putting so many of its eggs in the Tengiz basket could be a strategic vulnerability: if Tengiz output falls short, Chevron’s market performance will suffer, potentially dramatically.

Tengiz
The Caspian Region, particularly Kazakhstan, has been a key frontier for Chevron since the break-up of the Soviet Union. Tengiz, Kashagan and Karachaganak were all major projects taken on at great risk, but they garnished great financial wealth which in turn generated cashflow for the majors to develop projects around the globe, including Africa.

This is about to change. WoodMackenzie is predicting that, by 2030, annual capital spending on upstream oil and gas projects in the Caspian Region will drop 50% from it’s 2018 peak of $20Billion.

According to WoodMac most of the largest pre-FID (Final Investment Decisions), both brownfield and greenfield, do not generate an IRR(Internal Rate of Return) above 20%. Tax issues, cost overruns and project delays are key constraints. Add carbon neutrality to the mix and you have the ingredients for a perfect storm.

When the Soviet Union broke up in the early 90s and Kazakhstan emerged as a new oil province, Chevron was seen as an ambassador of US goodwill. Chevron’s prize was operatorship of Tengiz (50%) and ExxonMobil gained a 25% share. Chevron also has an 18% share in the large Karachaganak Gas Field.
What once was a sign of great wealth—Kazakhstan’s oil riches—could turn sour very quickly. Both Chevron and ExxonMobil, key developers of Kazakhstan’s prosperity, are also the two key oil majors lacking any serious decarbonization and energy transition plans. While this is most relevant for the Caspian, it is also a warning for Africa where both companies have major projects.

Expiry date for the Tengiz concession is 2033. What will happen then? Given the huge costs, highly sulfur-based oil and low chance of carbon neutrality, Tengiz could become a vast stranded asset. To date Shell has abandoned two Kashagan projects in Kazakhstan because of high costs. Tengiz was for most of its duration Chevron’s crown jewel, providing cash to developing assets elsewhere including Africa. Given Chevron’s current strategy it can only hope that Tengiz can continue to squeeze out more oil.

Caspian Pipeline Consortium (CPC)
An equally troubling problem is the Caspian Pipeline Consortium (CPC) which transports Caspian oil from Tengiz field to Novorossiysk-2 Marine Terminal, an export terminal at the Russian Black Sea port of Novorossiysk. The CPC pipeline handles almost all of Kazakhstan’s oil exports. In 2021 the pipeline exported up to 1.3Million barrels per day(BPD). On July 6, 2022 a Russian court ordered a 30-day suspension of the pipeline because of an oil spill. The CPC appealed the ruling and the suspension was lifted on 11 July of the following week, and the CPC was instead fined 200,000 rubles ($3,300). Also there have been unconfirmed reports that western service companies are refusing to provide repairs and spare parts, which could be seen violating sanctions against Russia.

The incident demonstrates the vulnerability of Tengiz and future production. No doubt this is not the last such incident which involves Russian and Kazakhstan goodwill to ensure that Chevron’s Tengiz Project does not falter. Having to depend on Russian-Kazakhstan goodwill to guarantee Tengiz production has put Chevron’s lack of diversity of oil supply in a very bad light.

Permian Basin
A final sour note for Buffet could be Chevron’s Permian Basin assets. What assurances do we have that Chevron’s Permian Basin adventure will fare better than that of past shale operators?

In a 2021 March report IEEFA (Institute for Energy Economics and Financial Analysis) found the 30 producers generated $1.8Billion in free cash flows in 2020 after slashing capital spending by $20Billion from the previous year.

“Last year’s positive free cash flows were only possible because shale companies cut their capital spending to the lowest level in more than a decade,” said Clark Williams-Derry, IEEFA energy finance analyst and co-author of the report. “Restraining capital spending could help the fracking sector generate cash, but low levels of investment also undermine the industry’s prospects for growth.”

Since 2010, the 30 companies examined by IEEFA had reported negative free cash flows totaling $158Billion.

“The positive free cash flows pale in comparison to the industry’s accumulated debt loads.”

The 30 shale producers owe almost $90Billion in long-term debt, and the reductions in capital expenditures are unlikely to ensure that the industry grows .

If Buffet is seen visiting Tengiz or the Permian Basin. investors should sit up and take notice. It will be, perhaps, an indication that much like the New England textile mills, all is not well in the land of Chevron.

 

 

 


Two Valve Assembly Plants, and a Pipe Threading Factory, On the Cards, in Nigeria

MANUFACTURING

Bell Oil & Gas says it is looking forward to commissioning a multi-million-dollar, integrated facility, located at the Lekki Free Zone in the eastern flank of Lagos, Nigeria.

The facility is on a site with a total size of over 15,000 square metres, according to Kayode Thomas, the company’s CEO.

The first phase of the project “comprises state-of-the-art valve assembly, maintenance, testing, painting and production”, which will deliver “Made in Nigeria valves for the oil and gas industry”, Thomas explains.

The second phase of the facility is for piping, pipe threading, machining and production of pup joints, crossovers and accessories. Thomas says that commissioning is at hand. “The facility will also accommodate our composite pipe fabrication services as well as serve as a storage and logistics base for our entire operation”

Bell Oil & Gas is a Nigerian owned service company which produces, supplies, installs, commissions and maintains a range of composite pipes. It is involved in some of the country’s ongoing large E&P projects including TOTALEnergies’ Ikike oilfield development, Nigeria Liquefied Natural Gas (NLNG)’s Train 7 construction and the ANOH Gas Processing Company’s ANOH midstream gas processing project. It is looking forward to participate in such future projects as the Shell led Bonga Southwest/Aparo, a deepwater oil field project.

MEANWHILE, IN PORT HARCOURT, THE LARGEST CITY IN THE NIGER DELTA BASIN, Tag Energy says it will commence the construction of a 3,000 square feet factory for the design, production, and repair of valves of all types and sizes by the year 2025.

The company ordinarily does flange management services; providing solutions for bolting requirements, including torquing, tensioning, stress analysis, and joint integrity quality assurance and quality control (QA/QC), with services catering to “high-integrity sealing of flange joints at chemical plants, refineries and offshore installations, as well as general industrial sites”.

Tag also supplies, services and repairs valves, mostly in engineering facilities in the oil industry. As the company builds the manufacturing facility, it has taken charge, as part of its CSR, of training young people in the eastern Niger Delta at its new valve service centre in Port Harcourt. Tag will “offer paid internships to qualifying students to produce a steady stream of skilled resources for the industry, further reducing our dependence on foreigners for ongoing maintenance and support activities”, says Yemi Gbadamosi, the company’s Chief Executive

 


Senegal’s New Fortune Favours the Locals

Senegal’s Revised Petroleum Code has introduced a provision that goods and services that could be adequately fulfilled by the local private sector must include majority Senegalese ownership of such companies.

The new law calls for a partnership between an international firm and a local entity, maintaining local ownership of at least 5%, in projects in which the local private sector may lack the technical or financial capacity for.

And regarding goods and services which the local private sector is chronically incapable of providing, foreign entities can fulfill these specific industry requirements independently of local partners.

Local Content Development Fund

The Petroleum Code’s Decree 2021-248 of the Revised Petroleum Code formalizes the operations of a Local Content Development Fund under both the Ministry of Finance and Ministry of Petroleum and Energies, funded by levied fines and other budgetary appropriations. The fund’s objectives are to develop more robust local content development guidelines in partnership with private companies and to improve local capacity through technical training and support for SMEs. Chairing this and acting as enforcer for all local content decrees is the National Local Content Monitoring Committee (CNSCL) created by Decree 2020-2047 – a body with the objective of achieving a 50% local content ratio for Senegal by 2030.

The law mandates international oil companies to submit annual content plans outlining their use of local contractors, suppliers and service providers, and justifying any international preferences for the above in terms of lower price or superior standards. It instructs all oil and gas industry service providers and sub-contractors to open a local subsidiary in the country and to submit all tender bids through a centralized government platform.

Originally published in the April 2022 edition of Africa Oil+Gas Report

 

 


BW Energy Reports High Production Cost in Gabon

The Norwegian junior, BW Energy has reported gross production from the Tortue field offshore Gabon, averaged approximately 10,700 barrels of oil per day in the second quarter of 2022, amounting to a total gross production of approximately 975,000 barrels of oil for the period and in line with expectations.

But a key data in the company’s operational update is that “production cost (excluding royalties) was approximately $35 per barrel”, in the subject quarter.

BW Energy does not go any length to explain the reason for such a high number, but it notes that “the overall production cost includes approximately $1Million related handling of the COVID 19 pandemic in the period.

“Second quarter revenue is expected to reflect approximately 32,500 barrels of quarterly Domestic Market Obligation (DMO) deliveries with an under-lift position of around 247,000 barrels at the end of the period”, the company explains.

There were no BW Energy liftings from the Gabon operations in the quarter.  “BW Energy had a cash balance of $123Million at 30 June 2022, compared to $111Million at 31 March 2022. The increase is due to the previously communicated April payment of $114Million for the Company’s March lifting, offset by continued investments in the Hibiscus / Ruche development project.

At the start of the period, the Company had commodity price hedges for a remaining total volume of 1.04Million barrels for 2022 and 2023, of which 37% is for 2022, BW Energy notes. “These were a combination of swaps and zero-cost collars that will allow for future cash flow stability for ongoing development projects. BW Energy has recognised unrealised crude oil hedge losses in the amount of $4.1Million for the second quarter”.


NNPC Gets a Court Injunction Against ExxonMobil Sale of its Nigerian Assets

A Federal High Court in Abuja has fixed, for July 15, 2022, the hearing of a motion against the sale of shares of ExxonMobil’s Nigerian unit to any third parties.

The court, presided over by Justice S. B. Belgore, had on July 6, 2022, granted an injunction sought by Nigerian National Petroleum Company (NNPC) Limited, restraining Mobil Producing Nigeria Ltd and Mobil Development Nigeria Plc from selling, trading, allocating, transferring, or disposing of their shares in their interests covered by or connected to the Joint Operating Agreement between them and the NNPC.

The order restrains “sale of assets covered in Oil Mining Lease 68, Oil Mining Lease 69, Oil Mining Lease 70 and Oil Prospecting Licence 94, to anybody, person (s), company, consortium or entity howsoever described pending the determination of the claimant/applicant’s motion filed on the 5th of July or when the judicial tribunal is duly constituted and can make interim preservation orders.”

NNPC has stepped up, in public, its determination to take over the subject ExxonMobil assets since Seplat Energy Plc, Nigeria’s largest homegrown, private sector led energy company, announced in February 2022, that it had entered into an agreement to acquire the entire share capital of Mobil Producing Nigeria Unlimited (“MPNU”) from Exxon Mobil Corporation, Delaware.


Ghana’s Taxman on the Chase After Nigerian E&P Company for Debt

Nigerian independent Oranto Petroleum, with its partner Stone Energy, has still not honoured an outstanding surface rental invoice of $67,438.36 on a Ghanaian upstream acreage.

Ghana’s Public Interest Accountability Committee says that the debt had been incurred since February 2013.

But the Ghana Revenue Authority GRA explains that Oranto hasn’t paid, even when contacted.

“GRA must find and compel Oranto/Stone Energy to pay the outstanding invoice with applicable penalties for the period during which it has been in default”, the PIAC warns in its latest (2021) annual report.

“GRA has indicated that Oranto has been located in Angola, Chad, and Mozambique. It has subsequently made contact with the Company but no payment has been made”, PIAC explains in the report.

PIAC pleads with the Tax agency: “GRA should collaborate with the relevant authorities in these jurisdictions to retrieve the principal together with the interest. GRA must take this step 7 Authority, since the issue has assumed a crossborder dimension, it has escalated beyond the GRA, and is being handled at the ministerial/governmental level, as a matter of principle”.


OPEC Secretary General meets Nigerian President Muhammadu Buhari

By OPEC Secretariat

The President of Nigeria, HE Muhammadu Buhari, received OPEC Secretary General, HE Mohammad Sanusi Barkindo, and an accompanying delegation from the OPEC Secretariat in Abuja, Nigeria.

The meeting took place in part to honour Barkindo’s two-term tenure as Secretary General of OPEC.

In attendance were HE Timipre Sylva, Nigeria’s Minister of State for Petroleum Resources and Head of its Delegation to OPEC; Mele Kyari, Group Managing Director of Nigerian National Petroleum Corporation (NNPC) and the country’s National Representative to the Organization; and other senior officials of Nigeria’s petroleum industry.

During the meeting, President Buhari said: “Welcome back home!” adding, “We are proud of your distinguished achievements at OPEC. You were able to successfully navigate the Organization through turbulent challenges.”

Minister Sylva echoed the President’s remarks, thanking the Secretary General for his six years of leadership.

The Minister said: “Mr Barkindo has steered the heavily loaded Declaration of Cooperation (DoC) ship through … turbulent waters, against all formidable obstacles,” adding, “He spearheaded the historic ‘Algeria Accord’ in September 2016, which paved the way for the equally historic DoC between 23 oil-producing countries – a feat that had never been achieved in the oil industry.”

“Mr Barkindo is a strong believer in multilateralism and cooperation,” Minister Sylva highlighted.

In return, the Secretary General said: “I and my colleagues from the OPEC Secretariat are deeply honoured by your audience, Mr President, as well as of the honourable Minister Sylva and other senior officials of the Nigerian oil and gas industry.”

He also briefed the President on oil market developments and the vital role played by the Declaration of Cooperation in stabilizing the global oil market over the past six years.

Barkindo’s term as Secretary General ends on 31 July 2022. Also today, he delivered a keynote address at the Nigerian Oil and Gas Conference and Exhibition in Abuja, which runs from 4-7 July 2022.

Nigeria joined OPEC in 1971. The country marked its 50th Anniversary in OPEC last year.


Afreximbank: Recent Actions Call for Caution Around Africa’s Energy Bank

By the Editorial Board of Africa Oil+Gas Report

Africa Export Import Bank  (Afreximbank) recently signed a Memorandum of Understanding in Luanda, Angola, seeking to create an investment fund in the energy sector for member countries of the Africa Petroleum Producers Organisation (APPO).

It’s a positive gesture, given the financing constraints that await the continent as it tries to monetise its hundreds of billion barrels of crude in this twilight epoch of the fossil fuel era.

Owned by 51 African countries and a clutch of private African and foreign investors, Afreximbank has, in the past few years, played some noteworthy role in the continent’s energy finance.

But in the months prior to the Luanda Memorandum, the Bank has acted in ways that call for a bit of review. Some of the lending and/or proposals to lend that the bank has announced, have been quite intriguing, if not incredulous.

$5Billion is a rather huge amount of money to raise for a project that commits to process a mere 176Million cubic feet per day of natural gas and condensate

A startling call was the $274Million senior reserve-based lending facility to Mars Exploration & Production Company Limited to facilitate that company’s acquisition of 51% equity interest in Oil Mining Leases (OMLs) 123, 124, 126 and 137 from Addax, a Sinopec owned subsidiary in Nigeria.  “The financing package will help boost oil production for the country as it incorporates a $50Million tranche to increase daily production from 25,000 barrels per day to 50,000barrels per day by 2023”, a statement by the bank noted.

As of the time of the bank’s announcement, in November 2021, the Addax acquisition ownership position was in murky waters. It started with the head of the Department of Petroleum Resources (DPR), the country’s regulatory agency-as it then was-sending a letter of revocation of the leases to Addax in late March 2021, and, within 48 hours of said revocation, awarding the licences to the KEL/Salvic Consortium. Then, following the protest of the Chinese Government (owners of Addax), President Muhammadu Buhari overruled the regulatory agency and restored the licences to Addax.  From this cloudy scenario came the request for financing by Mars Exploration & Production Company Limited, who then reportedly held 51% partnership in the licences, to 49% held by KEL/Salvic Consortium. At the time Mars was negotiating the transaction with Afreximbank, the case was in court and the presidency was under pressure by the NNPC to cancel the deal.

Fast forward to January 2022 and Mars Exploration had lost the assets. The Nigerian Upstream Petroleum Regulatory Commission (NUPRC), one of the two successor agencies to the DPR,  declared the award null and void.

It looks rather odd that such a high profile institution as Afreximbank should have been so anxious to play the financier role for asset acquisition in such hazy circumstances.

ON DECEMBER 8, 2021, AFREXIMBANK REPORTED signing a Memorandum of Understanding (MoU) with UTM Offshore Limited, to raise $5Billion for the development of Nigeria’s first floating liquefied natural gas (FLNG) project.  The deal is in two parts and would see the continental bank raising $2Billion to support the first phase with a commitment to fund the second phase of the project by another $3Billion.

Promoters of the UTM LNG have a seemingly compelling public narrative: they have been granted a License to Establish (LTE), also by DPR, for the installation of an FLNG unit on ExxonMobil operated Oil Mining lease (OML) 104; it has awarded the pre-Front End Engineering Design (Pre-FEED) contract to JGC Corporation of Japan and appointed KBR Owners Engineer. UTM also says that Vitol, a major global energy and commodities trader, has joined the consortium as an off-taker for the LNG. And then there is the sentiment about being be the first of such a project developed by an African company on the continent.”

But $5Billion is a rather huge amount of money to raise for a project that commits to process a mere 176Million cubic feet per day of natural gas and condensate, from reservoirs located in about 120 metres of water and deliver just 1.2Million Metric Tonnes Per Year (1.2MMTPA) of LNG. A comparable project is in operation almost round the corner from the UTM project. It cost all of $1.2Billion to install Africa’s first Floating LNG project: neighbouring Cameroon’s Hilli Episeyo, designed to produce 2.4 MMTPA of LNG, (twice the volume of LNG that UTM project will deliver) with a storage capacity of 125,000 cubic metres. The 294 m long floating plant is moored 14 km off the coast of Kribi in Cameroon.

Okay, the Hilli Episeyo is a converted floater.

So, let us consider an FLNG project with a new build vessel: The Coral South FLNG, project, which involves upstream drilling in ultradeep (>2000metre WD) waters, off Mozambique, with capacity of 3.4MMTPA, or 490Million cubic feet per day is projected to cost $5.1Billion, and the projected start date is September 2022. The volume is about thrice the UTM project and the reservoirs are in thousands of metres below the sea level, compared with the shallow water that UTM’s targeted reservoirs are located. Another African Floating LNG project is the Greater Tortue-Ahmeyin FLNG project, to valourise gas reserves in water depths exceeding 2,500 metres, straddling Mauritania/Senegal. The 2.5MMTPA project comes with an invoice of less than $2Billion.

Wait: There’s one more deal we are curious about: Afreximbank  signed a non binding term sheet with Eroton, a Nigerian independent producer of crude oil and gas and operator of Oil Mining Lease (OML) 18, for a prospective $750Million senior secured reserve-based lending facility, the purpose of which, in addition to refinancing Eroton’s current senior bank debt (of approximately $196Million), is to provide funding which will be used by Eroton to acquire an additional 18% interest in OML 18 from two of the other partners the acreage!!!, subject to agreeing documentation and relevant consents, thereby taking Eroton’s interest in OML 18 to 45%.

We are more comfortable with two other deals; one for oil and gas production, the other for power generation (a clear case of an attempt to build infrastructure and ameliorate energy poverty). These two are:

  • A $1.04Billion debt transaction with NNPC comprises a pre-export/shipment finance facility underpinned by a forward sale agreement (FSA) and offtake contracts from the state hydrocarbon firm acting as the borrower and seller. Through the FSA, NNPC will deliver 35,000 barrels of crude oil per day. With the ca. $1Billion to NNPC, it is understandably a pre-export finance facility backed by production.
  • Afreximbank support will also finance, with a $50Million facility, the initial capital required by Geometric Power, a power generation and distribution company, to acquire electrification rights to the Aba Ring Fenced Area and also support the commissioning and commencement of operations of the Aba Integrated Power project in the commercial hub of South-eastern Nigeria. The bank had earlier advised the project sponsor, on restructuring and arranging gap capital in the $332Million recapitalisation funds for the Aba IPP Power Project. Even though our analysts note that, as the Aba IPP project has struggled to be delivered in the last eight years, the merchandising economy and the industry in the city of Aba has gravitated to uptaking natural gas from Shell Nigeria Gas to run their generators in the absence of efficient power supply, and whereas we habour a healthy skepticism about how the Aba IPP has been financed over time, we think that funding a power project at this scale in Africa is always the way to go.

In Africa Oil+Gas Report’s conversations with investment bankers about these transactions, we get feelers like:

  • “It is chunky, but not unusual”
  • “Afreximbank is a well-funded institution with quality risk minded staff. It raised lots of cash recently in the international market. It has a broad and very supportive shareholder base as well, which is capable and willing to provide additional liquidity as needed”.
  • Afreximbank takes a stab at financing projects that are important, but may be such that conventional lenders cannot readily come up with.

Yet our misgivings do not go away. Now, as Afreximbank finds itself at the forefront of Africa’s energy fund scheme, it may want to review its own portfolio choices in order to be a surefooted leader.

This is a slightly updated version of the report we published in the November 2021 edition of the Africa Oil+Gas Report monthly journal, distributed to paying subscribers. The only changes are in the first two paragraphs. The article is republished on this platform for public service purposes.

 


NUPRC Amplifies its Well Audit Process, to Increase Nigerian Crude Production

By John Otoba, in Abuja

The Nigerian Upstream Petroleum Regulatory Commission (NUPRC) is targeting a ramp up of the country’s crude oil output through its routine, technical process engagement with oil producing companies.

Shut in wells are interrogated, reservoir surveillance is scrutinized and enhanced recovery methods are vigorously embraced, the agency says.

“The Commission recognizes that the formulation of all-inclusive strategies to increase crude oil and gas reserves requires thorough consideration of all factors militating against efficient and effective exploration and production operations”, says Gbenga Komolafe, CEO of the NUPRC.

In the six months since he took charge of the new regulatory commission, a creation of the Petroleum Industry Act, “we have become more deliberate and swifter in implementing strategic actions and initiatives aimed at increasing our crude oil and gas reserves and production”, Komolafe explains, adding:

“The Commission has initiated a massive campaign dedicated to the identification of oil and gas wells producing below capacity, through:

  1. Inventorisation of shut-in wells and analysis of the inventory to map the reasons for shut-in and devise measures for quick reopening;
  2. Using well and reservoir surveillance activities in identifying poorly performing wells and workover candidates for quick intervention;
  3. Embracing and adopting new technologies and advanced recovery techniques for unlocking some identified stranded oil and gas resources”.

 

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