Angola will award the nine onshore concessions offered in the 2020 round, to winners on September 23, 2021.
The country has meanwhile launched a bid round for the award of eight offshore oil blocks, in the same week the government says it has selected winners for the 2020 awards.
A total of 16 companies, of which 13 are Angolan and three foreign, submitted 45 investment proposals for the exploration of CON 1, CON 5, and CON 6 (onshore Lower Congo) and KON 5, KON 6, KON 8, KON 9, KON 17, and KON 20 (onshore Kwanza Basin) in the 2020 bidding process. The contestants include Monka Oil, Brightoil, Mineral One, PRODIAMAN, Alpha Petroleum, Sonangol P&P, MTI Energy, Tusker Energy, Somoil, AIS, PRODOIL, UPITE Oil Company, Simples Oil Group, Service Cab, Omega Risk Solution, and Intank Group.
Once the award for the 2020 round is over, however, the focus will move to the competition for the eight acreages on offer in the 2021 round.
The 2021 round, announced on September 14, 2021, features three acreages in the Kwanza Maritime Basin (Blocks 7/21, 8/21, and 9/21) and five in the Lower Congo Maritime Basin (Blocks 16/21, 31/21, 32/21, 33/21, and 34/21).
“The tender for the attribution of blocks under bidding takes place under the terms of numbers 1 and 2 of article 45 of Law 10/04, of 12 November (Petroleum Activities Law) and in accordance with Presidential Decree no. 297/10, of December 2nd, (Establishes the rules and procedures of the Limited Public Tenders)”, the National Agency of Petroleum, Gas, and Biofuels (ANPG) says in a release.
Companies that show interest in this tender will be selected, based on their proven experience and accumulated knowledge in the field of hydrocarbon exploration in basins with recognized geological complexity.
To consult data in face-to-face and virtual format, interested companies must register via email: email@example.com
For additional information on the 2021 Bidding process and additional consultation on the legislation, ANPG invites worthy investors to contact the Negotiations Department through the e-mail: firstname.lastname@example.org
South African owned, London listed, Ncondezi Energy Ltd expects to start construction of a 300MW Coal-Fired Plant in Mozambique by the third quarter of 2022.
Financial Close for the project, located in the coal-rich Tete District in the north of the country, is targeted for H1 2022, with 36 months planned construction, meaning that the plant should be up and running by mid-2025.
The company is currently negotiating to exclusively supply power to Electricity of Mozambique (EDM), the Mozambican power utility. But it is looking, down the road, at the regional transmission hub to the country’s Northern Grid, with direct connections into South Africa and Zimbabwe and potential expansion plans into Malawi and Zambia, for which line route optimization is currently underway.
The contract for Engineering, Procurement, and Construction(EPC) of the power plant was signed with China Machinery Engineering Corporation (CMEC) at a virtual signing ceremony on September 9, 2021. The EPC contract confirms CMEC as the main contractor to provide design, engineering, manufacturing, procurement, construction, erection, installation, and commissioning of the Ncondezi 2x150MW coal-fired power station on an EPC turnkey basis. The contract is valid for three years and subject to standard conditions being met before construction can start, including the achievement of Financing Close.
The next phases of the project milestones are to finalize project tariff, finalize Power Purchase Agreement with EDM, finalize Power Concession Agreement with Mozambique Government, and then move to Financing Close.
The Chinese are heavily committed to this. As far back as July 2019, the project promoter had signed a Joint Development Agreement (JDA) with CMEC as EPC and O&M Contractor and the American giant General Electric (GE) as the main technology provider for co-development, construction, and operation.
In December 2019, Ncondezi Ltd received indicative debt terms from the Industrial and Commercial Bank of China (ICBC). In January 2020, it received a Letter of Interest from China Export & Credit Insurance Corporation (Sinosure) and in Aug 2020, received Shareholders Agreement Term sheet confirming CMEC’s intention as lead investor for 60% of the equity investment at financial close.
“COVID-19 lockdowns and increasing scrutiny on the rationale for new fossil fuel power generation have presented added challenges this year, however, the company believes that the project is sufficiently advanced and has the necessary support to effectively navigate them and unlock value through the delivery of key milestones before year-end,” says Hanno Pengilly, Ncondezi’s Chief Executive Officer.
Nigerian independent, Oriental Energy Resources Limited, has announced the commencement of applications for the 2021/2022 University Scholarship Award Scheme from the 1st of September till the 30th of September 2021.
Operating in Nigeria’s south east offshore in Akwa Ibom State, the company targets scholarship applicants specifically from Effiat and Mbo communities as well as applicants who are indigenes of other Local Government Areas of the state.
Applications are Open to only 200-level students currently undertaking undergraduate studies in any recognised university in Nigeria, and are expected to be completed and submitted online through the company’s scholarship application portal at www.oriental-er.com.
“Oriental Energy is committed to sustainable and human capital development in the communities within our area of operations and Akwa Ibom state in general”, says Mustafa Indimi. Oriental’s Managing Director “We will continue to focus on social investments in education, community health and enterprise development that meet the needs of our stakeholders. The university scholarship scheme is one of such interventions.”
Uwem Ite, the Head of Community Relations at the company, adds: “Shortlisted candidates will be invited for an aptitude test after which finalists will be selected for the scholarships on the basis of test results as well as other academic indices submitted by applicants. The deadline for all submissions is Thursday, 30th September, so interested applicants have a full month to take advantage of the opportunity. We look forward to welcoming another batch of bright young persons from Akwa Ibom who will be awarded the scholarship, just as Oriental Energy continues to contribute meaningfully to education sector in the state.”
Since commencement of the scholarship award scheme in 2009, more than 1,500 indigent students in universities across Nigeria have benefited. Among other recent projects, a Science Laboratory Complex built and fully-equipped by the company was handed over in March 2021 to Community Grammar School in Ebughu community, Mbo Local Government Area. The company also delivered a fully-equipped Youths Empowerment Centre in August 2020. Located in Enwang, the centre is a multipurpose printing and reprographics facility under the management of Mbo Youths Empowerment Foundation, with the Paramount Ruler of Mbo LGA as the Chairman, Board of Trustees. Positioned for a sustainable partnership with the communities, Oriental Energy also focuses its social investments on healthcare and empowerment programmes to support social development efforts in Akwa Ibom State.
Partners in Kenya’s two proven onshore acreages have high graded the field development plan for the basin-wide, crude oil project.
Far from the earlier proposed “foundation stage development” involving a 60,000 to 80,000Barrels of Oil Per Day (BOPD) Central Processing Facility (CPF) and an export pipeline to Lamu, the three companies: Tullow Oil (operator), Africa Oil Corp, and TOTALEnergies, have now informed the Government that Blocks 10BB and 13T licenses can deliver production plateau of 120,000BOPD, with expected gross oil recovery of 585Million barrels of oil (MMBO) over the full life of the field.
This resource position, the partners say, “is supported by external international auditors Gaffney Cline Associates (GCA), who have issued a Competent Persons Report (CPR) and confirmed the life of field resource position of 585MMBO”.
The key changes to the development concept have been driven by:
1. Incorporating the production data from the Early Oil Pilot Scheme (EOPS) where 450,000 bbls were produced from Amosing and Ngamia fields. These two fields account for over 50% of the resource distribution, leading to greater confidence in achieving the higher end of the resource distribution range.
2. Optimising the number of wells to be drilled with drilling initially at the crest of the fields to achieve First Oil. Changing the producer to injector ratio from 2:1 to 1:1 leading to improved pressure support and higher resources recovered from the reservoir.
3. Adding the Ekales field into the first phase of production. Ekales is geographically straddled between the Twiga and Amosing fields and ongoing technical work has helped mature our understanding.
As such, the first phase will now include the Ngamia, Ekales, Amosing, and Twiga (NEAT) fields and will target 390MMBO of the overall 585MMBO.
4. Optimising the overall development cost with a facility design capacity of 130,000BOPD and an increase to the pipeline size from 18” to 20” to handle the increased flow rates.
Total gross capital expenditure (capex), which covers both the upstream and the pipeline to First Oil, is expected to be c.$3.4Billion.
The increase in capex from the previous design is due to a bigger facility processing capacity, additional wells to be drilled, and larger diameter crude oil export pipeline, which delivers a 30% increase in resources whilst lowering the unit cost to $22/bbl (previously c.$31/bbl).
The revised concept also allows greater flexibility in adding additional fields into production without significant modifications to the project’s infrastructure.
Tullow Oil, the London-listed independent that runs the largest oilfield operations in Ghana, has declared a profit after tax of $93Million for the First Half of 2021.
Most of the money was made from the proceeds of crude oil production from the West African country.
“The start of drilling in Ghana is one of the most tangible examples” of the significant achievements made during the period, the company explains.
Tullow’s gross (operated) production in Ghana averaged c.107,000Barrels of Oil Per Day (BOPD), with c.70,600BOPD(net: c.25,100BOPD) from the Jubilee field, “slightly ahead of expectations due to good facility uptime and well performance”. Gross production from the TEN fields averaged c.37,000BOPD(net: c.17,400BOPD).
Working interest production from Ghana averaged c 42,500BOEPD in 1H 2021, three times the WIP from Gabon (c.14,800BOEPD). Overall Group working interest production averaged 61,230 BOEPD, with Equatorial Guinea and Cote d’Ivoire contributing 2,100BOEPD and 1,800BOEPD respectively.
Operating costs during the period averaged $12.9/bbl, “a year-on-year increase primarily due to lower production and increased costs related to extended COVID-19 operating procedures”.
Tullow reports underlying operating cash flow of $218Million and free cash flow of $86Million during the period and congratulates itself on reduced administrative expenses of $23Million in 1H 2021, “down c.50% year-on-year”.
The company’s spent $101Million on capital investment and $37Million on decommissioning.
But its net debt at 30 June 2021 was around $2.3Billion, it says, with gearing of 2.6x net debt/EBITDAX; and “liquidity headroom and free cash of $0.7Billion.
Tullow says it completed a comprehensive debt refinancing with $1.8Billion of five-year Senior Secured Notes issued and a new $500Million revolving credit facility.
Shell’s unveiling of its Refhyne Hydrogen Project, located at its Energy and Chemicals Park in Rhineland, Germany has attracted much attention. Plans are underway to expand the capacity of the electrolyzer from 10 Megawatts to 100 Megawatts. Shell also intends to produce sustainable aviation fuel (SAF) using renewable power and biomass in the future. A plant for liquefied renewable natural gas (bio-LNG) is also in development.
As part of the Refhyne European consortium and with European Commission funding through the Fuel Cells and Hydrogen Joint Undertaking (FCH JU), the fully operational plant is the first to use this technology at such a large scale in a refinery.
“Shell wants to become a leading supplier of green hydrogen for industrial and transport customers in Germany,” according to Huibert Vigeveno, the company’s Downstream Director. “We will be involved in the whole process — from power generation, using offshore wind, to hydrogen production and distribution across sectors. We want to be the partner of choice for our customers as we help them decarbonize.”
Shell has a target to become a net-zero-emissions energy business by 2050. The company plans to transform its refinery footprint to five core energy and chemicals parks, reducing the production of traditional fuels by 55% by 2030.
Does Shell’s goal for its energy and chemical parks fit within the verdict brought down by the Dutch courts ordering Shell to cut by 2030 its CO2 emissions by 45% compared to 2019 levels? Is Shell still in charge of its energy transition scenariosor is it desperately playing catch-up to ensure that its influence and strategy has an impact on the swiftly changing energy landscape?
In Shell’s latest energy scenario update, four conclusions are stated:
• Energy needs will grow
• Energy system will be transformed-speed is the issue
• Transformation will have costs and benefits
• Action accelerators are necessary to meet climate aspirations.
Shell in its Sky 1.5 Scenarioanticipates a rapid and deep electrification of the global economy, with growth dominated by renewable resources. Global demand for coal and oil peak in the 2020s and natural gas in the 2030s.
In the sectors that are more difficult to electrify, liquid and gaseous fuels are progressively decarbonized through biofuels and hydrogen.
“Globally, the world is proceeding towards achieving the stretch Paris ambition-temporarily rising above and then limiting average global warming to 1.5C above pre-industrial levels before the end of the century-accelerated decarbonization now”.
Before returning to Shell…a short summary of the competition.
The Remainders: ExxonMobil and Chevron, two companies who continue to believe that decarbonization is only being done within the confines of the hydrocarbon world. CCS (Carbon Capture and Storage) is only understood to at least give a pretense that the companies are tuned in to the energy transition. Look forward to both companies developing a closer relationship to maintain economies of scale.
First Adapters: TOTALEnergies, in the summer of 2020, took the unusual step of writing off $7Billion impairment charges for two oil sands projects in Canada. Both projects at the time were listed as ‘proven reserves’. By declaring these proven reserves as null and void, TotalEnergies, with one swoop of the pen, cast aside the Petroleum Classification System which was the gold standard for measuring oil company reserves.
The company simply decided that these reserves could never be produced at a profit. Instead, TOTALEnergies has substituted renewables as reserves that can be produced profitably.
TOTALEnergies’ strategy is based on the two energy scenarios developed by the International Energy Agency (IEA): Stated Policies Scenario (SPS) is geared for the short/ medium term; and Sustainable Development Scenario(SDS) for medium/long term.
Taking the “Well Below 2 Degrees Centigrade” SDS scenario on board:TOTALEnergies has in essence taken on a new classification system. By embracing this strategy, the company is the only major to have seen the direct benefit of using the Paris Climate Agreement to enhance its renewable energy base.
Decentralizers: Will BP become the first super-major to become an investment vehicle that is both green and can guarantee shareholders a handsome return on investment? BP 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 becoming lean and mean, reducing costs and hopefully increasing margins. In short, an investment vehicle.
BP is promising returns in the range of 12% -14% in 2025 –up from around 9% today, financed by a $25Billion divestment fund and a pipeline of 25 oil and gas projects. Oil production will also be reduced to 40% by 2030. To date, the company has initiated a series of joint ventures in order to speed up its transition.
New Energy Giants: New boys on the block, who will provide green leadership and challenge the oil majors.
Engie: in 2021, will spend €11-12Billion on investments across a broad swath of sectors including solar, wind (on and offshore), hydro plants, biogas, and developing gas and power lines, and will have 33GW of global renewable installed capacity by 2021.
Enel: Enel’s strategic plan outlines total investments of €190 billion by 2030 and tripling renewable capacity to 145GW.
Ørsted: By 2030, Ørsted will have an installed capacity of 50GW.
Iberdrola: In the period 2020-2025, Iberdrola will be spending €75 billion on renewable energy and has a pending target of 95GW of installed wind capacity.
RWE: By 2022, RWE will have 28.7GW of installed wind and solar capacity.
Vattenfall: In the Nordic countries Vattenfall has low emissions with practically 100% of the electricity produced based on renewable hydropower and low-emitting nuclear energy.
Shell: In Search of its Soul?
Shell’s energy prognosis is certainly in line with other sources who are sounding alarmed about global warming and the need for rapid de-carbonization. Yet how will this affect Shell as a company? Is the company nimble enough and has the dexterity to ensure it will be a force for good in the next phase of the energy transition? The signs are not encouraging.
In 2020, IEEFA (Institute for Energy Economics and Financial Analysis), evaluated Shell’s green progress. According to Clark Butler, the author of the report, Shell must shift at least $10Billion per annum or 50% of total capital expenditures from oil and gas and invest in renewable energy if they are to reduce their carbon intensity in line with their own stated goals.
Between 2016-2019, Shell spent $89Billion in total investments, of which only $2.3Billion was devoted to green energy. In 2019, Shell’s overall operating costs came to $38Billion and capital spending totaled $24Billion.
How will Shell’s re-branding affect the company’s three major divisions- Upstream, Integrated Gas, and Downstream?
Upstream is still on the operating table but the immediate signs are not encouraging. Shell’s Nigerian assets-onshore, and shallow water- are already on the auction block, encouraging Nigeria’s independents to pick up potential assets. Shell, meanwhile, will instead move further downstream to ensure continuity of its gas-related and trading activities in Nigeria. Helping the company to portray a greener image.
Shell is one of the most adaptive of the IOCs in Canada. Noteworthy is that Canada is the world’s 4th largest oil producer at 4.7Million barrels of oil per day and is also a major producer of natural gas. The Canadian government is determined that Canada will be net-zero by 2050. Shell Canada has divested most of its heavy oil-producing assets in Alberta but is still a large producer of gas. Shell also is an operator of the leading-edge Quest carbon sequestration projects near Edmonton, Alberta. The CO2 is removed from the Scotford heavy oil upgrader. Quest became operational in 2015 and injects 3,600 tonnes of CO2 per day into a deep reservoir. To date, 6.5Million tonnes of CO2 have been stored. Shell is also an operator of the $25Billion LNG plant being built at Kitimat on the west coast of British Columbia. This is the first LNG plant to be built in Canada.
Earlier Shell indicated that it will reduce its Upstream Division to nine core hubs such as the Gulf of Mexico, Nigeria, and the North Sea and no frontier exploration after 2025. If the rush to the global exploration exit continues to pick up speed Shell may well have to reconsider its upstream strategy. Perhaps going so far as to spin the Upstream Division off as a separate entity or joint-venturing with other partners.
Shell’s Integrated Gas Divisioncould prove to be the star asset. For example, Wood Mackenzie’s AET-2 scenario (Accelerated Energy Transition Scenario) predicts that in the following decades market power will slip from OPEC to the giant gas producers such as the USA, Russia, and Qatar.
According to AET-2, the “Era of carbon-neutral gas is born. AET-2 would require $300Billion to support Liquified Natural Gas growth globally and $700Billion to support dry gas development in North America.” Certainly, a sweet sound for Shell’s LNG business.
Downstream could also prove to be a key energy transition asset. Shell’s Refhyne Project, Rhineland Refinery could well become the precedent the company needs to ensure it becomes the leading supplier of green hydrogen, where hydrogen production is powered by renewable energy for industrial and transport customers. Could theRefhyne Projectbecome duplicated many times over to ensure that green technology becomes a key ingredient in the energy transition?
A key remaining issue is how Shell can re-allocate its resources-both financial and technical-and maintain an image of being in control of its energy transition scenarios. Upstream with its huge exploration and development costs is perhaps Shell’s largest impediment to becoming a greener company. Do not be surprised that in the coming months, Shell’s Upstream will find a new home. Freeing up funding needed for Shell’s own energy transition. Also, expect Shell’s Integrated Gas and Downstream and Renewablesto get a serious makeover vastly increasing their budgets to ensure market share and a green future.
Finally, do not be surprised that Shell, under pressure from public opinion and its shareholders becomes CO2 neutral in 2030 instead of 2050.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was the 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 contributes to the Institute of Energy Economics and Financial Analysis (IEEFA).
Crude Oil output crashed to significant lows in five acreages held by Nigerian independents in the western onshore Niger Delta, in August 2021, according to field data seen by Africa Oil+Gas Report.
These acreages, operated as Joint Ventures with state oil firm NPDC, produce the bulk of the hydrocarbons in Nigeria’s western onshore as well as most of the natural gas for the country’s electricity supply.
NPDC/Neconde’s OML 42 output fell to 23,000 Barrels of Oil Per Day (BOPD), from 38,669BOPD averaged in July 2021.
The Norwegian geophysical company, TGS, has announced commencement of a new seismic survey in the MSGBC Basin, offshore Mauritania.
It is a follow up to the North-West Africa Atlantic Margin (NWAAM) two dimensional (2D) seismic acquisition campaign.
The current survey, NWAAM 2021, will comprise 7,500 kilometres of seismic data, with a modern broadband acquisition set-up. The project is being undertaken using the vessel BGP Pioneer
“The survey is designed to illuminate the regional plays in the ultra-deep and deepwater areas with a new azimuth and to provide prospectivity insights of an oil-prone area in relation to recent key wells and the shallow water geology”, TGS says in a release.
TGS has been, perhaps the busiest multi-client seismic survey contractor on the African continent in the last three years. It was the go -to company for the Liberian licensing round, which was launched in 2nd Quarter 2020, because it holds a range of multi-client data across the Harper Basin, the focus of the round, to support the activity.
TGS acquired a keen rival, Spectrum Geophysical, in June 2019 and in 2020 acquired the Senegal North Ultra-Deep offshore three-dimensional (3D) survey, covering an area of more than 5,100km². The stand-alone northern Senegal survey was the continuation of the Jaan 3D seismic survey, which is TGS’ 3D dataset covering the southern portion of the Mauritania, Senegal, Gambia, Guinea Bissau and Guinea Conakry (MSGBC) Basin, offshore north-west Africa.
In Nigeria, between 2019 and 2021, TGS, along with its joint venture partner PetroData, carried out the country’s first regional multi-client Multibeam and Seafloor Sampling (MB&SS) Study, covering an area of approximately 80,000 square kilometres of the offshore Niger Delta and incorporating around 150 cores from the seabed, whose location is based on multibeam backscatter anomalies.
In terms of the ongoing Mauritanian survey, TGS says the project has a 60-day acquisition timeline, with fast-track data available three months after acquisition. The full dataset will be available by Q2 2022.
“Our latest seismic survey offshore Mauritania will provide explorers with the subsurface intelligence needed to assess the hydrocarbon potential of the deep and ultra-deepwater”, TGS says. “We see this project as the natural continuation of our successful NWAAM campaign, one of our flagship projects in Africa”.
Angola has decided to diversify the route to offering acreage licences to E& P Companies.
It would no longer be only through the bid round process.
The country’s National Oil, Gas and Biofuel’s Agency (ANPG) will “negotiate the exploration of available petroleum-based resources throughout the year without the need for bid round announcement”, the agency says in a statement.
Angola is keen on increasing its crude oil reserves, which amounted to Eight Billion barrels proved in 2020, according to BP Review of Statistics, July 2021. The country’s production has struggled below 1.2Million Barrels a day for all of the last eight months. Angola’s energy bureaucrats have always said that the way to improve these figures is by licencing more acreages and putting them to work.
As it is, Angola’s preference has been to award acreage licences through the process of a bidding competition.
But some bid round programmes have failed, in the last 12 years, both in terms of dismal results of drilling the awarded acreages (2009 Bid round of blocks in the presalt, ultradeepwater Kwanza Basin) and the lukewarm attitude to post award negotiations (2014 Bid Round of onshore acreages).
The “new permanent negotiations programme”, approved in late August 2021, will allow the ANPG to proactively promote and negotiate oil and gas concessions independently from the rules and regulations of the Concession Allocation Strategy, which was approved by presidential decree 52/19 of February 18. It will enable the concessionaire to have robust competitive strategies to attract international investment in Angola´s energy sector.
ANPG administrator. César Paxe declares in a statement: “Investors are able to contact ANPG to submit investment proposal on available petroleum-based resources for exploration in Angola, in a fully transparent and compliant process,”
The permanent offer programme will allow for continued negotiations between operators and the concessionaire on fields where the concession period will expire or on concessions that were not included in the concession’s strategy. Under the new program, concessions will remain permanently available for negotiations with potential investors.
Chariot Oil & Gas has signed a contract with Stena Drilling, to use its semi-submersible Stena Don drilling rig for the planned Anchois gas appraisal well within the Lixus licence, offshore Morocco.
Drilling operations are anticipated to commence in December 2021 and are expected to take up to approximately 40 days.
With the drilling, Chariot o wants to unlock the development of the discovered sands by confirming the gas resource volumes, reservoir quality and well productivity.
The probe also seeks to provide a future production well for the development of the field as well as potentially deepen the well into additional low-risk prospective sands with the aim of establishing a larger resource base for longer term growth.
Anchois field’s development plan, so far, envisages two subsea wells tied into a subsea manifold with a 40-km offshore flowline connected to an onshore gas processing facility. From there another 40-km pipeline would link to a trunkline gas system to Europe.