All posts tagged feature


NUPRC Calls for Inputs for the Next Phase of Regulations Development

PARTNER CONTENT

The Nigerian Upstream Petroleum Regulatory Commission(NUPRC) has given notice of stakeholder consultation regarding the third phase of regulations development in line with section 216 of the Petroleum Industry Act (PIA) 2021.

The commission invites inputs from Lessees, Licensees, Permit holders, Host Communities, and other stakeholders of the Nigerian Upstream Petroleum sector, between now and January 9, 2023.

1. The matters to which this stakeholders inputs and consultations relate are as follows:

i. Upstream Petroleum Measurement Regulations

ii. Advance Cargo Declaration Regulations

iii. Significant Discovery Regulations

iv. Gas Flare Penalty (Amendment) Regulations

v. Domestic Crude Oil Supply Obligation Regulations

vi. Nigerian Upstream Measurement Regulations

2. Stakeholders are kindly enjoined to follow the link below to download and

review the proposed regulations; https://www.n u p r c.gov. ng/regulation- development-pio-2021/.

3. Accordingly, submissions of inputs to the regulations are hereby requested as part of the process of stakeholder consultation prior to finalization of the regulations, to give meaning to the intent of the PIA 2021

4. All submissions must be made using the format accessible through this link https://WWW.nuprc.gov.nq/wpcontent /uploads/2022/NUPRCRequlation-Comments-Sheet- xlsl.

They must be received at the email address below NO LATER THAN 21 DAYS FROM DECEMBER 19 2022, which means January 9, 2023 (as his publication was put on NUPRC website on December 19 2022).

5. Kindly forward your submissions to the Head Compliance and Enforcement Unit of NUPRC, Kingston Ezeugo Chikwendu on regcon@nuprc.gov.ng, GSM 08077724442 for further necessary action.

Signed:

Engr. Gbenga Komolafe FNSE Commission Chief Executive


Will 2023 see a Revival of the Deepwater Market?

By Gerard Kreeft

Is the deepwater market on the cusp of a revival in 2023? Preliminary signs are promising. Yet to participate in this marketplace requires very deep pockets and stamina. While the drilling fraternity has undertaken the necessary rationalization—witness Saipem selling its land rigs to KCADeutag and the merger of Noble Drilling and Maersk Drilling—the oil majors have indicated that it will be business as usual. How will the deepwater marketplace develop in an ongoing turbulent energy future? Is there room at the poker table for the deepwater players who are being constantly overshadowed by energy scenarios which are predicting the early death of the oil and gas industry and hence the deepwater sub-market? Have deepwater exploration and development been given a premature death sentence?

Two opposing scenarios are currently in play: the re-emergence of the offshore marketplace, in particular the deepwater plays; and the International Energy Agency (IEA) ’s recent prediction that in the period 2022-2027 there will be a sharp growth by 2,400 gigawatts (GW) in installations of renewable power. That renewables are becoming a bedrock of the energy transition is not in doubt. Less sure is whether the deepwater players will have a continuing staying power. How will the oil majors divide their capital budgets between oil and gas projects and renewables? Below an overview of what to anticipate in 2023.

The Current Market Situation

A telling sign for 2023 are the recent robust contracts signed by Transocean and the drillship purchased by Saipem. Tranocean’s Deepwater Corcovado drillship was awarded a four-year contract having an estimated worth of $583Million; the company’s Deepwater Orion drillship signed a three-year contract worth an estimated $456Million.

Saipem, in turn, has announced that it has purchased the Santorini, an ultra-deepwater drillship, from South Korea’s Samsung Heavy Industries to strengthen its offshore drilling fleet amid the growing demand in the market. Saipem disclosed that its purchase option of $230Million will be financed entirely from available cash.

Can the deepwater drillers expect better times in 2023?  The terrain, according to WoodMackenzie, is the fastest growing upstream oil and gas venue: production is expected to hit 10.4Million Barrels of oil equivalent per day (BOEPD) in 2022 and will reach 17MillionBOEPD by the end of the decade.

“Brazil remains the leading deepwater producer, it accounts for around 30% of current global capacity and will continue to grow. Guyana, the most significant new entrant, will be producing 1MillionBOEPD within the next five years. In total 14 other countries will contribute to the deepwater supply mix in the coming years.”

Indexed oil & gas production growth by resource theme, 2022-2030

Source: ‘Global deepwater production to increase 60%’, WoodMackenzie, November24, 2022

According to WoodMackenzie the sector remains under the control of a small number of key players: “Petrobras and the seven majors dominate deepwater production, operating 22 of the top 25 deepwater assets. Petrobras’ deepwater portfolio is around twice as big as its nearest peer, Shell, which stands out among the majors for leading production and cash flow. ExxonMobil and TOTALEnergies show the highest rates of growth this decade.”

According to a recent Valaris investor presentation 2023 and beyond will provide the drillers market conditions not seen for many years:

At present the deepwater drillship fleet has been rationalized to 158 units from a peak of 281 in late 2014; the jackup supply has declined to 493 units from a high of 542 in 2015. Yet one-third of the jackups are more than 30 years old and have a limited use for the future.

Majority of the deepwater rigs are very modern, only 16% of current supply is older than 20 years;

Because of improved market conditions, rationalization of the offshore fleet utilization for both drillships and jackups is above 90%.

Average dayrates for drillships signed in the third quarter of 2022 have more than doubled to $402,000 from $193,000 in the fourth quarter 2020. Average dayrates for jackups signed in the third quarter of 2022 is $97,000 compared to $71,000 in the fourth quarter of 2020.

The Oil Majors

BP

A key component of BP’s strategy is building an investment structure, which requires only a few skilled accountants. The company has either sacked employees or will be delegating BP’s headcount to its joint ventures. The goal is to become lean and mean, reducing costs and, hopefully, increasing margins. In short becoming an investment vehicle.

A key strategy is to decrease its oil production by 40% by 2030. In Angola  BP has merged its upstream activities with ENI to form Azule Energy, which could become a model for other African countries.

To date the company has initiated a series of joint ventures to speed up its transition.

  • BP and Ørsted have partnered to develop zero-carbon ‘green hydrogen’ at BP’s Lingen Refinery in north-‎west Germany, BP’s first full-scale project in a sector that is expected to grow rapidly. The 50 MW electrolyser project is expected to produce 1 ton of ‎hydrogen per hour – almost 9,000 tonnes a year – starting in 2024. The project could be expanded to up to 500 MW at a later stage to replace all of Lingen’s fossil fuel-based hydrogen.
  • BP and Equinor revealed that BP will become a 50% partner of the non-operated assets Empire Wind (offshore New York State) and Beacon Wind (offshore Massachusetts). BP and Equinor will jointly develop four assets in two existing offshore wind leases located offshore of New York and Massachusetts that together have the potential to generate power for more than 2Million homes.
  • BP joined Statkraft and Aker Offshore Wind in a consortium bidding to develop offshore wind energy in Norway. The partnership—in which BP, Statkraft, and Aker Offshore Wind will each hold a 33.3% share—will pursue a bid to develop offshore wind power in the Sørlige Nordsjø II (SN2) licence area.

Chevron

Two-thirds of Chevron’s production in 2025 will come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States will each yield 1MillionBOEPD.

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.

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.

Eni

ENI states that 90% of exploration capex is spent on near fields and proven basins. Some $11Billion in the last 10 years has been spent on its dual exploration model—near fields and proven basins. The company states that it only requires three years—from first discovery of oil to market—twice as fast as the industry average. The company produces 1.7MMBOEPD, has a balance sheet which has an economic leverage of 20%, and has, according to its website,  an Internal Rate of Return(IRR) of 34%, the highest of all its peers  for the period 2012-2021. Also, its RRR(Reserve Replacement Ratio) of 110% for the period 2012-2021 is the highest compared to its industry peers.

A key ENI strategy  is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets and at the same pursuing new strategies as part of its energy transition plan.  A key example is Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’ upstream assets, LNG and solar business. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2Billion barrels equivalent of net resources and growing to about 250,000BOEPD of equity oil and gas production over the next 5 years. It holds stakes in 16 licences (of which 6 are exploration blocks) and a participation in Angola LNG JV. The company also participates in the New Gas Consortium (NGC), the first non-associated gas project in the country.

Equinor

Equinor’s has two pillars: natural gas and its growing offshore wind portfolio. Does the company have the financial depth and ability to achieve maximum leverage for both pillars?

Equinor’s offshore wind portfolio is pledged to grow to 12–16 GW of installed capacity by 2030. Renewables will receive more than 50% of capital investments by 2030.

Equinor has chosen a series of joint ventures to develop its offshore wind portfolio. The first, Dogger Bank, heralded to become the world’s largest offshore wind farm, is being developed together with SSE Renewables based in the UK. Located in the North Sea, the project will produce some 3.6 GW of energy, enough to power 6Million households. More recently, Eni has purchased a 20% stake in the Dogger Bank A & B Project.

The second is Equinor’s Empire Wind and Beacon Wind assets off the USA’s east coast. In September 2020 it was announced that BP was buying a 50% non-operating share, a basis for furthering a strategic relationship. The two projects will generate 4.4 GW of energy.

By 2030 the company will be spending more than one-half of its capital spending on low carbon energy to become a leader in offshore wind technology.

ExxonMobil

For 2023 the company has stated that its capital investments will range between $23Billion-$25Billion. Over a six year period ExxonMobil will invest some $2.5Billion per year in low carbon solutions: CCS (Carbon Capture and Storage) hydrogen initiatives and biofuels. The company will invest 70% of its capital budget in the Permian Basin (USA), Guyana, Brazil and LNG projects. By 2027 production is anticipated to be 4.2MillionBOEPD.

Shell

Annual capital expenditures in the near term, according to Shell, could be in the range of $21-23Billion. The company has stated that its renewables and energy solutions will be $2-3Billion compared to previous targets of $1-2Billion. This pales in comparison to the $3Billion earmarked for marketing, $4Billion in integrated gas, $4-5Billion in chemicals and products as well as $8Billion in upstream investments. For the period 2025-2030, Shell lumps together the capital budgets devoted to three categories:

  • Growth which entails renewables and marketing will receive 30% of Shell’s capital budget;

 Transition which entails Integrated gas and chemical & products will receive 30-35% of Shell’s capital outlay; and

  • Upstream will get 30-35%.

Predicted Internal Rates of Return per category vary between 10-25%.

TOTALEnergies

TOTALEnergie’s capital expenditures for the period 2022-2025 is anticipated to be between $13Billion-$16Billion per year: 50%  ($6.5Billion-$8Billion) on hydrocarbons and only 25% ($3.25Billion-$4Billion) on renewables.

Much of TOTALEnergies’ hydrocarbon budget will be devoted to Africa in which  low-cost, high-value projects are the goal. Squeezing more value out of  various African assets to ensure a prolonged life cycle.

A prime example is TOTALEnergies’ Mozambique LNG project, which is expected to cost $20Billion and produce up to 43Million tons per annum.

In Angola the company produces more than 200,000 boepd(barrels of oil equivalent per day) from its Block 17 and Block 32, and non-operated assets including AngolaLNG.

In Namibia TOTALEnergies has made a significant discovery of light oil with associated gas on the Venus prospect, located in block 2913B in the Orange Basin, offshore southern Namibia.

In South Africa the company is focused on its two South African assets: Brulpadda(drilled to a final depth of more than 3,600 meters) and Luiperd, the second discovery in the Paddavissie Fairway in the southwest of the block.

Key Takeaways

Deepwater production is expected to hit 10.4MillionBOEPD in 2022 and will reach 17Million BOEPD by the end of the decade.

  1. Wood Mackenzie’s AET-2(Accelerated Energy Transition) scenario states that oil and gas demand in 2050 will be 70% lower than today. From 2023 onward oil demand drops with year-on-year fall of around 2Million barrels per day (bpd). Total oil demand by 2050 is down to 35MillionBPD. What affect will such long-term reductions have on future deepwater investments and strategies? Will the deepwater plays continue to be a strategic part of the energy world?
  2. Further long-term investments and rationalization will have to be done if the deepwater sector is to be a strategic energy player. Already the deepwater drillers—Saipem and Nobel Drilling+Maersk Drilling– have rationalized their deepwater fleets. Of the oil majors only BP and Eni have joined forces in Angola to form the JV Azule Energy. Will others follow?
  3. Closer examination of the oil major plans reveals that in 2023 it will be business as usual. Continued higher oil prices have postponed any thought of possible future mergers and rationalization among the oil majors. Be that at a project or at a corporate level.
  4. Finally, the IEA’s recent report which states that “renewables are set to account for over 90% of global electricity expansion over the next five years, overtaking coal to become the largest source of global electricity by early 2025,” should be a sharp warning to all energy players.
  5. In conclusion ‘Fasten Your Seat Belts’, we are headed for turbulent weather.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe.  Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis). His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com


Petrofac Partners Mozambique to Develop an Elite Hydrocarbon Workforce

PARTNER CONTENT

Petrofac, the UK based engineering service provider for the oil industry, has formed a Joint Venture (JV) with Empresa Nacional de Hidrocarbonetos (ENH), the Mozambican state hydrocarbon firm, for the provision of training services.

Designed to support nationalisation goals across the country’s expanding energy industry, ENH’s stake in the JV has been determined at 51% and Petrofac’s at 49%. The partnership will provide training and competence management solutions for Mozambique’s domestic onshore and offshore developments, as the country continues its transformation from a natural resource producer to an energy and industrial giant, and the largest LNG producer in sub-Saharan Africa.

Mozambique has bought into the localization story in oil and gas industries around the continent, but as it has very few indigenous firms with any real capacity, the authorities are focusing more on workforce training, than contracts-for-localfirms.

On the website of the INP (Institute of Petroleum), Mozambique’s E&P regulatory agency, there are several stories tracking numbers of Mozambicans slated to work on both planned and ongoing gas monetization projects.

Petrofac, in a statement announcing the partnership, declares that it has “a 20-year track record of developing national workforces through the delivery of technical, regulatory, and academic training”.


Angola’s Hydrocarbon Output Slumps for the Third Consecutive Month

By Angolan National Petroleum and Gas (ANPG) Agency

Translated directly from Portuguese

Angola produced 32,590,947 barrels of crude in October 2022, corresponding to a daily average of 1,051,321 barrels of oil (BOPD) against a forecast of 1,123,215BOPD.

It was 3% less than the 1,091,371BOPD produced in September 2022, which was 7% less than the 1,174410BOPD produced in August 2022, which itself was less than the July 2022 output of 1,177,153BOPD.

Associated gas produced (outside the Cabinda Association) during October 2022 was 69.140Billion cubic feet (bcf), a 10% drop from the 76.6Bcf of gas output in September 2022, which on its own was a 14% slide from the 89.5Bcf produced in August 2022. Naturally the volume of gas made available to the Angola LNG plant in Soyo, dropped 17% to 498MMscf/d from 599MMscf/d in September 2022, which itself was an 18% plunge from 730MMscf/d in August 2022.

1,096MMscf/d was injected, and 300MMscf/d utilized for power generation at oil facilities and the remainder used in oil operations and disposal.

The ALNG Factory produced 2,614,487barrels of oil equivalent (BOE), or 84,338BOEPD in October 2022, with LNG production of 68,188BOEPD, 6 898BOEPD of Propane, 5,311BOEPD of Butane and 3,942BOEPD Condensates.

Associated gas production of the Cabinda Association was 700MMscf/d in October 2022, from which 349,578barrels of LPG (averaging 11,277Barrels Per Day) was extracted and divided into daily production of propane of 6,387barrels and butane of 4,674barrels.

The total production of crude oil, condensate and LPG was 32,940,525BOE, or average of 1,062,598BOEPD; the operational efficiency of the facilities was 89.18% against a forecast of 91.18%.

Angola’s crude oil exports for October 2022 were 33,619,013barrels (or 1,084,484BOPD) against 996,774BOPD predictted. The ANPG lifted around 7,252,023 barrels (22% of total withdrawals), Sonangol P&P lifted 4,859,517barrels (14% of total withdrawals) and the Sonangol EP lifted 1,759,442barrels (5% of total withdrawals).

Rig Activity/Well Count: In October 2022, TEN (10) drilling units were in operation, five (5) of which were drillships, namely West Gemini, Sonangol Libongos, Valaris DS-09, Sonangol Quenguela and Transocean Skyros and one (1) semi-submersible rig Scarabeo 9. There was one ground probe FALCON HP-1000, one (1) Tender SKD Jaya, one (1) Tension Leg Platform TLP-A; one (1) Jack Up Shelf Drilling Tenacious Probe. These 10 units carried out work in twenty (20) wells, including four (4) intervention operations, fiftteen (14) drilling/completion operations and one (1) evaluation, making a total of 8,754 metres of drilling.

Completed in the month: Four (4) development wells (producers), one (1) injector development well, and two (2) interventions in producing wells.

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


Chevron Hits a Motherlode in the Mediterranean

Chevron and partners are evaluating a commercial sized accumulation of natural gas, encountered in the Narges 1 well, in the Mediterranean Sea offshore Egypt.

Tarek El Molla, the Egyptian Minister of Hydrocarbons, confirmed the discovery to the country’s parliament on Friday, December 16, 2022, but he did not give details of the estimated volume of the accumulation.

The Narges block in the Eastern Mediterranean is one of the assets that Chevron took over in the event of its recent acquisition of Noble Energy, the American independent.

The Middle East Economic Survey (MEES) reported in early December 2022, that the field could hold an estimated 3.5Trillion Standard cubic feet of gas. It also reported that the gas was encountered gas at the prognosed primary target depth of 3980 metres.

The estimated 3.5Tcf volume is about 15% of the ultimate recoverable reserves in the giant Zohr gas field, discovered by ENI in the same Mediterranean in 2015, and the discovery is timely. Africa’s third largest economy has been determined to maximize its exports of natural gas to improve its Foreign Exchange earnings. With gas production averaging 6.5Billion standard cubic feet per day in third quarter 2022, a year-on-year drop of 700Million standard cubic feet per day, the country commenced, last August, a rationing of gas for domestic power production, in order to free up more gas for export.

The Narges block is 45% operated by Chevron with another 45% owned by ENI, the Italian explorer.   Tharwa Petroleum, an Egyptian state hydrocarbon company, holds the remaining 10%.

The Narges-1 probe is being drilled by the drillship Stena Forth, in an acreage which lies some 60 kilometres from the Sinai peninsula, about 80 kilometres east of the nearest Egyptian gas infrastructure and 70 kilometres west of the long dormant Gaza Marine gas discovery offshore Gaza Strip, a Palestinian enclave.

 

 


Sirius, with Funds in Hand, Takes Over Management of Abura Field Redevelopment

Sirius has now fulfilled all conditions needed to access the funding facility for the planned redevelopment of the Abura field in Oil Mining Lease (OML) 65, and will assume key senior management positions within CMESOMS Petroleum Development Company (COPDC) Limited, the organization which “owns” the project.

Sirius holds 30% in COPDC, who in turn has a Finance and Technical Sales Agreement (FTSA) with NNPC Ltd, the licenceholder of OML 65. But Sirius is the one bringing the finances, as well as technical and managerial expertise, to the project.

With these credentials, Sirius takes fuller control of OML 65 redevelopment, with its executives assuming the positions of Managing Director, Finance Director, Executive Director, and Vice-Chairman of COPDC “and will immediately begin to accumulate cash flow entitlements related to the assumption of operational responsibility for existing production at the Abura field”.

Following the approvals previously secured from NNPC regarding the commencement of Phase 1 of the OML65 Approved Work Programme (AWP), Sirius can now start drawing down funds under the senior loan facility of up to $200Million, executed with (the commodity trader) Trafigura, to finance the well drilling, re-entry and completion in OML 65, notably the Abura field, to boost production by as high as 11,000Barrels of Oil Per Day, to reach, around 16,000BOPD.

The project has come a long way, even though it is yet to take off.

The context: In 2019, COPDC, the Nigerian E&P company founded by Hosa Okunbor, who was very well connected to President Muhammadu Buhari, secured an FTSA with the Nigerian Petroleum Development Company (NPDC), an NNPC subsidiary which holds the right to OML 65, located onshore mid-western Nigeria, in the Niger Delta basin.  COPDC had never operated an E&P asset before it was granted the FTSA, a deal it clinched largely as a result of political connections of its principal.

Sirius Petroleum, as of then, was desperate to get in on the action on any bankable hydrocarbon project. The OML 65 revamp, as it were, has provided it the first real opportunity for relevance.

Phase 1 of the AWP will be undertaken in conjunction with Baker Hughes under a Master Services Agreement (“MSA”) which has been executed with Sirius, and will involve the drilling of up to nine wells on the Abura field, intended to produce the remaining 2P reserves of 16.2 MMbbl1.


Uganda to Re- Nationalise Its Electricity Industry

The Ugandan government wants to “minimize expensive private capital” in the electricity sector by bringing it under direct state management and control.

The country’s public officials are disappointed with the execution of the 20-year concessions granted to two companies for generation and distribution and have decided not to renew them.

Eskom’s generation licenses- to run two hydropower stations- will expire in March 2023 and will not be renewed.

Umeme Limited (UMEME.UG)’s monopoly rights to distribute power in Uganda, will not be renewed when it expires in 2025.

In their place the Uganda National Electricity Company Limited (UNECL), a state-run company which is currently under formation, will manage the generation, transmission and distribution segments of the electricity sector. UNECL, will likely be structured as a Public Private Partnership (PPP) with the state firm as a majority shareholder, according to a statement by the energy, ministry said.

The government hopes, by taking electricity supply back from the private sector, it could enormously reduce costs to consumers.

President Yoweri Museveni has repeatedly complained that expensive private capital was responsible for high electricity tariffs in Uganda, which makes it unaffordable for consumers.


South Africa’s Electricity Chief Has Resigned

By Sully Manope, in Windhoek

André de Ruyter, CEO of Eskom, the South African electricity monopoly, has quit.

The former President of Sasol’s China Ventures had been at one of the country’s most important jobs for three years, having taken charge in January 2020.

The power utility said in a statement that De Ruyter had tendered his resignation on Wednesday, December 14. While he was obligated to only serve a 30-day notice, De Ruyter had reportedly agreed to stay in his position until March 31, 2023. “Mr De Ruyter has agreed to stay for an additional period beyond the stipulated 30-days’ notice to ensure continuity while we urgently embark on a search for his successor. His last day at Eskom will be March 31 2023,” said Eskom board chairperson Mpho Makwana.

The utility says it has no plan for the chairman to become an interim CEO and that a comprehensive executive search will be conducted to find a suitably qualified candidate.

Mr De Ruyter has often said that he took the job as an act of national service in January 2020 and as a critical plank of President Cyril Ramaphosa’s reform agenda. But he has presided over the most challenging period for power outages in the country. “2022 has been the worst year on record for power cuts in South Africa”.

The outgoing Eskom boss has a wide pool of supporters, who point to his forward-looking energy transition plans. “South Africa’s Just Energy Transition Investment Plan  (JET-IP), was lauded at COP27 in Egypt as best-in-class energy transition thinking”, writes Ferial Haffajee, associate editor of the Daily Maverick. The $8.5Billion JET-IP is designed to accelerate the move away from coal in a way that protects vulnerable workers and communities, and develop new economic opportunities such as green hydrogen and electric vehicles.

 


Our Latest Issue/Local Content, Global Insight

The local content sessions at African oil and gas conferences have grown tremendously in the last 15 years.

Now they envelope other sessions of the gabfests in their billowing robes.

What used to be very technically focused conversations around new technologies and innovations have been replaced with bully pulpit exhortations about what companies must do to build local capacity and support local businesses.

Out on the field, governments, even in nascent oil industries, are ringfencing sectors to be supplied only by indigenous enterprises.

From Ghana in the west to Kenya in the east. From landlocked Uganda to coastal Senegal, there is talk of “National Supplier Database”, a term that is curiously not as common in North Africa as it is in Sub-Saharan parts of the continent.

But in this quest for localisation, it is important to ask how the industrial economy has fared. Does having the locals run much of the upstream contracts and, as in the case of Nigeria, seek to take over the entire oil & gas production, translate to growing a vast, diversified, portfolio of refining, gas processing, petrochemicals, tools manufacturing, valve factories that collectively make the oil industry itself a champion of the industrial state?

Can the upstream hydrocarbon sector, as it moves to indigenous control, help create a nexus of industries that can lift more out of poverty than the small technical elite guaranteed by the age old system of simple crude production to export?

This question is at the heart of a two hour plus conversation our team had with Simbi Wabote, the forthright speaking Executive Secretary of the Nigerian Content Development Monitoring Board.

Read the interview here, right in the edition.

The Africa Oil+Gas Report 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 decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions. Published by the Festac News Press Limited since November 2001, AOGR is a monthly publication, delivered in e-copies to subscribers around the world. It is sometimes published in hard copies, for the purpose of distribution at conferences in which the AOGR is a media partner.  Its website remains www.africaoilgasreport.com

and the contact email address is info@africaoilgasreport.com. Contact telephone numbers in our West African regional headquarters in Lagos are +2348028354297, +2349091009800,+2348036525979 and +2347062420127


Afentra’s Angola Acquisition: So Far, Still Far

By Sully Manupe, in Windhoek

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

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

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

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

© 2021 Festac News Press Ltd..