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The Energy Axis Comes to the Solution

PARTNER CONTENT/PAID POST

The Energy Axis – a digital platform where suppliers and buyers in the energy industry interact is now online.

It is an e-commerce address to find information on the production, consumption, sales, distribution, and marketing of energy.

It’s as much a place to find a directory of reliable oil and gas service companies; E&P companies (comprising IOCs and NOCs and Marginal field producers), downstream suppliers of petroleum products, as it the venue to source for gas to power players, hydropower projects, and the emerging clean and renewable energy companies, inverter dealers, Installation etc.

Funke Taylor, founder of The Energy Axis

Users also include vendors of tools/products used across the oil, gas and energy value chain: (valves, pumps, pipe, fittings, accessories petrol station consumables, etc), LPG businesses, Energy industry personnel, Power, Transport and logistics businesses.

“On the Energy Axis platform, users benefit from the presence of others as against the traditional fear of others”, says Funke Taylor, founder of The Energy Axis. “It’s an interactive space”.  “They will gain immensely as businesses or individuals from tools, expanded markets, business opportunities, expert views etc.”

The Energy axis platform has come at a good time for businesses looking for expanded market opportunities. The global lockdowns enforced by COVID-19 pandemic have dis-incentivized face-to-face interactions. B to B Marketing has been moved online as trade conferences, exhibitions etc. have been postponed or out rightly cancelled.

The Energy Axis would encourage the traditional companies to strategically digitize; people now go online more to search for products and services; search engines and social media platforms will become very powerful source of business leads”, Ms. Taylor explains.

“The much touted digital transformation is not just about technology”, Taylor says, “It includes people, processes and platforms (like the energy axis)”.

“To our users; We will help you stand out in the crowded energy marketplace “, Taylor pledges.

 

 

 

 


The Three Musketeers of the Energy Transition: The New Emerging Energy Value Chain

All- For-One; One-For-All

Musketeer 1 Big Oil: ExxonMobil, Chevron, Equinor, BP, Shell, TOTAL,  and ENI

Musketeer 2 New Energy: Enel,  Iberdrola , Engie, and Ørsted

Musketeer 3 Energy Africa

There is growing evidence of a new convergence between Musketeer 1: Big Oil  and Musketeer 2: New Energy Companies.

Perhaps not so much convergence but cross-overs and falling by the wayside of others and in the process creating new alliances.

Little attention has been paid to Musketeer 3: Energy Africa, perhaps viewed as the junior musketeer, but nonetheless playing a significant role.

Their- All- For-One; One-For-All requires a further explanation.

Musketeer 1 Big Oil

 

 

 

 

 

 

The company is not having a Merry Christmas and there’s little to cheer about in 2021. It has recently written down between $17–$20Billion in impairment charges, seen its market cap plunge to $140Billion, and is capping capital spending at $25Billion a year through 2025, a $10Billion reduction from  pre-pandemic levels.

Key questions remain: how long can ExxonMobil  afford paying its sacred dividend which is costing $15Billion annually at a time when the company is bleeding red ink? Which key projects- Deepwater Offshore Guyana,  Rovuma LNG Mozambique, or others- will see development spending slowing down or frozen until ExxonMobil can get its house in order? If it can get its house in order!

 

 

 

 

At first appearances the company seems to be weathering the storm somewhat better. The Chevron share has lost some of its glitter but has remained resilient over the last 5 years, continuing to hover in the $90 range. In October 2020, its market cap was $142Billion, surpassing ExxonMobil for the first time.

Why?  Primarily lower debt levels, a constant dividend, and an image of being in control. Spending  in the period 2022-2025 will be $14-16Billion, instead of $19-22Billion: $3.5Billion outside the USA, of which 75% will be dedicated to Tengiz in Kazakhstan and the remaining $1.5Billion elsewhere.

The Tengiz Project deserves some attention, given that it in a time of Chevron’s austerity, it is swallowing up 75% of the international oil and gas  budget. Tengiz currently produces 580,000Barrels Per Day(BPD) and is to be expanded  by some 260,000BPD. Total costing is estimated at $45Billion.

Expiry date for the Tengiz concession is 2033. Will this short timeframe allow Chevron to regain its investment costs? Will Tengiz, with its high development costs,  become a huge white elephant? Leaving Chevron with a legacy to match that of ExxonMobil?

To date Shell has abandoned two Kashagan projects in Kazakhstan because of high costs.

This is not promising for Africa where Chevron has major operations stretched across the continent:  major projects in Angola and Nigeria and interests in Equatorial Guinea, receiving very limited funding in order to bankroll Tengiz.

 

 

 

 

Equinor’s recent top management shuffle has signaled that renewable energy, offshore wind energy, will be the company’s growth engine. By mid 2021, Equinor’s Renewables Division will have its own  reporting structure. It’s the most obvious sign yet  that in the future offshore wind energy could be spun off as a separate company.

The key indicator is the development of Dogger Bank, located in the North Sea and expected to produce some 3.6 GW of energy, enough to light up 6Million households. It is the company’s showcase project.

Together with SSE Renewables, the joint partners of the project since 2017, Dogger Bank is heralded to become the world’s largest offshore wind farm.

More recently ENI has purchased a 20% stake in the Dogger Bank A & B Project. Why? So that, according to ENI chief executive Claudio Descalzi,  it can develop the skill sets needed to better understand offshore wind energy works.

Shell has recently entered a 15-year Power Purchase Agreement (PPA) for 20% of Dogger Bank A and B. With this stake, Shell will use 480 MW of the wind farm for power offtake.

Equally important is Equinor’s Empire Wind and Beacon Wind assets off the US 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.

 

 

 

 

 

 

 

 

What is BP’s current status in the Energy Transition and what can we anticipate in 2021? Two encouraging signs:

  • BP’s 50% participation in Equinor’s Empire and Beacon Wind assets off the US East coast, a strategic partnership which could grow very quickly;
  • BP and Ørsted announced that they will jointly develop a full-scale green hydrogen project at BP’s Lingen refinery in Germany. The two firms intend to build an initial 50 MW electrolyser and associated infrastructure, which will be powered by renewable energy generated by an Ørsted offshore ‎wind farm in the North Sea and the hydrogen produced will be used in the refinery.‎

Key questions remain:

  • BP announced that it will be spending $5Billion per year to green itself and by 2030 will have 50 GW of net regenerating capacity.  To date the company has a planned pipeline of 20 GW of green generating capacity. What actions can we anticipate in 2021?
  • BP has announced it wants to reduce its oil production by 2030 by 40%. Which BP  assets will become stranded  assets?  BP’s 20% share in Russia’s Rosneft?
  • What about BP’s assets in Africa where the company has a considerable footprint. Some examples:
  • In Algeria BP has helped to deliver two major gas developments at Salah Gas and In Amenas, both of which are joint ventures with Sonatrach and Equinor.
  • BP currently produces, with its partners, close to 60% of Egypt’s gas production through the joint ventures the Pharaonic Petroleum Company (PhPC) and Petrobel (IEOC JV) in the East Nile Delta as well as through BP’s operated West Nile Delta fields.
  • In Angola BP is the operator of blocks 18 and 31 and have non-operated interest in blocks 15, 17 & 20, as well as the Angola LNG plant in Soyo.
  • In Mauritania and Senegal, BP and its partners are developing  the  Greater Tortue Ahmeyim  gas field with a 30-year production potential.  The field has an estimated 15Trillion cubic feet of gas and is forecast to be a significant source of domestic energy and revenue.

Many of these projects are natural gas related and could provide the bridging fuel needed for the energy transition.

Between 2016-2019 Shell spent $89Billion in total investments, of which only US$2.3Billion was devoted to green energy. In 2019, Shell’s overall operating costs came to $38Billion and capital spending totaled $24Billion.

 

 

 

 

 

 

 

 

IEEFA(Institute for Energy Economics and Financial Analysis) recently 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.

At present Shell is undertaking a major cost-cutting operation, dubbed ‘Project Reshape’ across its three major divisions:

  • 35% -40% cuts at the Upstream division where focus will be reduced to 9 core hubs such as Gulf of Mexico, Nigeria and the North Sea.
  • Integrated gas division, which includes the company’s LNG business, deep cuts are anticipated.
  • Downstream, the review is focusing on the company’s 45,000 service stations, designed to play a key role in the energy transition.

Will this be enough? By all accounts Shell is taking an incremental, testing-the -waters approach. Expect no mega-deal such as the British Gas takeover of 2015. Instead fiscal discipline in order to be able to continue paying its somewhat reduced, but still royal dividend of 4%.

There are signs of green shoots:

  • NortH2Vision in which Shell and Gasunie have combined forces to create a mega-hydrogen facility, fed by offshore wind farms, which by 2030 could produce 3-4 GW energy and possibly 10GW by 2040.
  • Completing the largest PEM electrolyser in the world at the Rheinland refinery in Germany (10 MW).
  • Biofuels using alternative feedstocks such as forestry, agricultural and municipal wastes.

Shell’s  incremental, cautious approach may be too little too late. What is urgently required is a forward-looking strategic green roadmap.

 

 

 

TOTAL’s energy production in the period 2020 -2030 “will grow by one third, roughly from 3Million Barrels of Oil Equivalent Per Day (BOEPD) to 4MillionBOEPD, half from LNG, half from electricity, mainly from renewables”, according to  Patrick Pouyanné, Chairman and CEO.

This is the first time that a major operator has wittingly or unwittingly translated its renewables to BOE. The golden rule was that RRR(Reserve Replacement Ratio) was always used  to assess a company’s hydrocarbon reserves. According to Rystad, the RRR rate for the industry is 7%, a historic 20 year low. The norm is 100%.

This author has for some time argued that oil companies also include other fuels in their reserve count—be that wind or solar– to create a basket of energy reserves, thus increasing one’s reserve count and buttressing up one’s  fossil reserves and adding value to your offshore assets.

That the petroleum classification system  is in need of drastic repair is also reflected by the action taken by TOTAL in the summer of 2020. TOTAL 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’. Have proven reserves become the equivalent of stranded assets?

TOTAL’s strategy is focused 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, TOTAL has in essence taken on a new classification system.

By embracing this strategy TOTAL is the only major to have seen the direct benefit of using the Paris Climate Agreement to  enhance  the investment climate thus supporting its deepwater portfolio in Africa and expanding its renewable energy base.

 TOTAL has confirmed, on the renewables front, that it will have a 35 GW capacity by 2025, and has the ambition of adding 10 GW per year after 2025. Translated, that could mean creating an additional 250 GW by 2050. The vision is there, now the implementation.

A key to TOTAL’s success is its ability to step into projects at an early stage, some examples :

  • 50% portfolio of installed solar activities from the Adani Green Energy Ltd., India;
  • 51% Seagreen Offshore Wind project in the United Kingdom;
  • Major positions in floating wind farm projects in South Korea and France.

Total’s fiscal and technical discipline will ensure that its offshore portfolio and renewables  find traction in Africa.

 

 

 

 

 

 

 

ENI’s 20% purchase for a  stake in the Dogger Bank A & B Project is  an early indication of ENI’s green future. Why? So that, according to ENI chief executive Claudio Descalzi,  it can develop the skill sets needed to better understand offshore wind energy works.

ENI is also teaming up with Enel to develop two green hydrogen projects.The partners plan to produce two pilot projects; each pilot project will feature electrolysers of around 10MW.

ENI has confirmed that it will virtually be starting green projects from scratch.

Eni has pledged to reach 15 GW  by 2030 and 55 GW by 2050,  mainly by building its own capacity. The company’s 2050 strategic plan to reduce its carbon footprint includes the following goals:

  • Natural gas will account for 85% of upstream production;
  • 80% reduction in scope 1 emissions (from company assets) scope 2(indirect emissions);
  • and scope 3 (entire value chain).

Musketeer 2 New Energy: Enel,  Iberdrola , Engie, and Ørsted

 

 

 

 

Enel has announced that it is to invest €160Billion over the next 10 years to meet the demand for green energy and electrification. Over the next three years, about €40Billion will be spent, half of this on renewables.

Enel said almost half of its investments will be directed to developing infrastructure and networks, while the rest will be allocated to power generation. The company expects to have about 120 GW of installed capacity by 2030, almost three times more than the current level.

Expect more development projects from the international oil companies and Enel.

 

 

 

 

 

 

Spain’s largest energy group has projects in Europe(Germany, UK, and Spain), USA, and Brazil.

 

 

 

 

 

Up to 2021 the company  will spend between  €11Billion – €12Billion on investments across a broad swath of sectors including solar, wind (on and offshore), hydro plants, biogas and marine technology. Some examples:

  • Storengy, Engie’s gas storage arm, will provide hydrogen storage capacity for Europe’s future hydrogen market;
  • Construction of two solar power plants with a combined generation capacity of 30 MW in Burkino Faso;
  • Ocean Winds, joint venture between EDP Renewables (EDPR) and ENGIE are combining their offshore wind assets with 1.5 GW under construction,  0 GW under development, with the target of reaching 5-7 GW of projects in operation or construction, and 5-10 GW under advanced development by 2025;
  • 126 biomass plants by 2030 capable of producing 4TWh of power.
  • Together with ArianeGroup, developing liquid hydrogen fuel for maritime sector;

By 2025 Engie, through its affiliate Power Corner, will have installed 1000+ mini-grids across Africa reaching 2Million people.

 

 

 

 

The Danish Offshore Wind Farm giant has since 2016 seen its share price more than quadruple. In 2016 it had a stock price of $35 and has now climbed above $140.  It has a market cap of approximately €65Billion.

Currently the company has an installed capacity+ FID(final investment decision) of almost 20 GW and a build-out plan for new awards to reach 25-30 GW in the coming 15 months.

The company has projects in Taiwan, Japan, South Korea, throughout Europe (UK, Germany, Netherlands, Denmark, France, Poland, and Belgium) and the USA.

Musketeer 3 Africa

The increased speed of the Energy Transition is not necessarily good news for Africa. The greening of Europe, for example, could in the short and medium term have a boomerang affect .

The greening of Europe by the  majors could  mean reducing oil and  gas activities in Africa. Are  Africa’s oil and gas assets competitive and worthy of development, compared to other global projects?

The oil and gas majors are choosing  low carbon prospects and natural gas projects on a massive scale  leaving many potential prospects in doubt.

Energy scenarios released by both BP and TOTAL are predicting a sharp decrease of oil production, adding to the view that exploration budgets of the majors will not be a priority item. Instead as TOTAL has explained low cost, high value projects are the goal. Squeezing more value out of its various African assets to ensure a prolonged life cycle.

How will oil and gas prospects in Africa be judged? Do the various governments have the management skills to properly assess their energy scenarios?

Many of Africa’s new fledging  state oil companies, have been proxies to the international oil majors. In the process not developing technical knowledge, capability and expertise to manage and implement oil and gas projects.

Being hostage to the whims of the oil majors is no formula to ensure that a country’s oil and gas assets are to be developed. Certainly when the window of opportunity to develop oil and gas assets  could be closing within the next 20-25 years.

Rystad, the Norwegian energy research  company has recently reminded the investment community that the oil and gas majors are actively pruning their oil and gas assets and that the world’s largest oil and gas firms could sell or swap oil and gas assets of more than $100Billion in order to adjust and transform to cleaner sources of energy.

The Rystad Energy Study covers a wide geographical spread  and includes  ExxonMobil, BP, Shell, TOTAL, ENI, Chevron, ConocoPhillips, and Equinor. The eight companies may need to divest combined resources of up to 68Billion barrels of oil equivalent (boe), with an estimated value of $111Billion and spending commitments in 2021 totalling $20Billion.

The key criteria for determining whether a major would benefit from staying in a country are the company’s cash flow over the next five years, the potential growth in its current portfolio, and its presence in key E&P growth countries towards 2030. Based on this, Rystad claims that majors may seek to exit 203 country positions and, as a result, reduce their number of country positions from 293 to 90.

Conclusions

  1. Sustainable Development Scenario(SDS) based on a  well below 2C is   the new  classification norm, replacing the Hydrocarbon Classification System  which instead of measuring provable reserves is now  synonymous for stranded assets.
  2. Musketeer 1 Big Oil is a house divided: Exxon Mobil having to finance major projects in Angola, Mozambique and Guyana and facing its own financial meltdown; Chevron using most of its international funding to prop up Tengiz in Kazakhstan, leaving little future funding for Africa.
  3. Shell is clustering its upstream activities in nine hubs, which includes Nigeria and the Gulf of Mexico; BP is reducing by 40% its oil production. This does not bode well for Africa.
  4. TOTAL and ENI with their African operations could play key roles in further developing Africa’s Green Transition. Their oil and gas operations will be extended and no doubt their host governments will be demanding green solutions.
  5. Equinor, with its increased offshore wind portfolio, could see the start or emergence of new players: A combination of Equinor/BP and Musketeer 2 New Energy players such as Enel,  Iberdrola , Engie, and Ørsted.
  6. Many of Musketeer 2 New Energy players have limited or no African experience. Certainly It is imperative that both Eni and Total, together with host African governments introduce New Energy companies to these African markets.
  7. Additional practical measures for Musketeer 3 Energy Africa:

Developing a mini-Norwegian system of having a Sovereign Wealth Fund and ensuring that the state be a participant in all concessions.

Clear definitions  of regulatory power: does Government’s  regulatory regime  give the Ministry of Natural Resources a clear mandate as opposed to the goals of state oil company?

Improved fiscal and tax incentives to encourage new exploration companies to participate.

High on the list of priorities should be knowledge transfer and development of local talent, which the majors should provide.

To date the international multilateral agencies- be that the World Bank, African Development Bank, or the International Monetary Fund- were reluctant to throw new petro-economies a life line, based on oil and gas potential.  This should be re-evaluated so that both oil and gas and renewables can be used to evaluate a country’s financial needs.

  1. There is mounting evidence that the Energy Transition is showing a trend break: the western industrialized countries such as Western Europe, Japan, South Korea, and Taiwan where the Musketeer 2 New Energy Companies are finding lucrative markets; and developing countries of Africa where few of the Musketeer 2 companies are found.

 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 NetherlandsHe writes on a regular basis for Africa Oil + Gas Report.


Cameroon Makes Steady Returns from Crude Export Pipeline

Cameroon received $57Million (or XAF30.71Billion) as transit fees from January 1 to October31, 2020 on the Chad –Cameroon oil pipeline.

The 1,070 kilometre evacuation facility, which pumps crude oil from three fields in the southwest of landlocked Chad to a floating facility 11 km off the Cameroon coast town of Kribi, has been delivering returns to Cameroon since first oil was achieved in 2003.

Cameroon’s Pipeline Steering and Monitoring Committee (PSMC), reports that the revenue is up by 2.5% year-on-year. Over the same period in 2019, the country collected $55Million (XAF29.97Billion) as transit fees.

PSMC reports that 39.91Million barrels of crude oil were transported from the Komé-Kribi terminal in southern Cameroon in the first 10 months of the 2020 fiscal year, compared with 38.79Million barrels during the same period in 2019. This represents an increase of 3%.  

“This improvement is the result of increased production from new shippers in Chad, namely PétroChad Mangara, China International Petroleum Company Inc. Chad and Overseas Private Investment Corporation.

The construction of the pipeline was led by ExxonMobil in the early 200s. But the American major has since exited Chad. 

 


Tullow Gets Licence Extensions, Even though It Will Leave Kenya

By Bunmi Aduloju

The Kenyan government has granted the application of Tullow Oil and its Joint Venture partners for tenure extension for Blocks 10BB and 13T, even though the London listed company is working on selling its stakes in the asset

The country’s Ministry of Mines and Petroleum approved  the work programme and budget for 2021, in which the partners  pledge to re-assess Project Oil Kenya and design an economic project at low oil prices whilst preserving the phased development concept of the Field Development Plan. Tullow announced this extension on December 8, 2020.

The company had reported, three months ago, that its farm-down process in Kenya had been suspended “pending a comprehensive review of the development concept and strategic alternatives”.

The company had also noted, in earlier briefs, that it would use the extended time frame, when granted, to work on “submitting an updated Field Development Plan by end of 2021”.

The phased development concept proposes that the Amosing, Ngamia and Twiga fields should be developed as the Foundation Stage of the South Lokichar development. This stage would include a 60,000 to 80,000BOPD Central Processing Facility (CPF) and an 892km export pipeline to Lamu.  The installed infrastructure from this initial phase can then be utilised for the optimisation of the remaining South Lokichar oil fields, allowing the incremental development of these fields to be completed at a lower unit cost post-First Oil.

Tullow Oil’s suspension of its planned farm down, however, doesn’t mean that the company has a future in Kenya. The farm down process will restart, after government has agreed on a new template for development, sometime in 2022.

 

 


Angola’s Regulator Issues Tender Notice for Environmental Study of the Kassanje Basin

The NATIONAL AGENCY FOR OIL, GAS AND BIOFUELS (ANPG) makes public, under the terms of paragraph 1 of article 69 and of annex VI, of Law 9/16, of 16 June, Law on Public Contracts, the Limited Tender for Previous Qualification for the Provision of Environmental Impact Study Services, Restoration and Repopulation of the North and South lots of the Kassanje Basin is opened, within the scope of the Petroleum Potential Study Project of the Interior Basins of Angola.

Deadline and place for the Submission of Proposals: Until December 18, 2020 at 4:00 pm, at the following address: Rua Lopes de Lima, Urban District of Ingombota, Municipality of Luanda, Torres do Carmo Building – Tower 2 4th floor Tel. ( +244) 226 428 000

Full details in this link.


UNESCO inks Cooperation Agreement with Gas Exporters

United Nations Educational, Scientific and Cultural Organisation (UNESCO) and the Gas Exporting Countries Forum (GECF) have signed a Memorandum of Understanding (MoU) to bring the benefits of collaboration to the world at large.

Shamila Nair-Bedouelle, the Assistant Director-General for Natural Sciences at UNESCO and Yury Sentyurin, the Secretary General of the 20-member coalition of the leading gas exporting countries of the world, signed the agreement, which “will serve as a gateway of opportunities between the two entities in the areas of struggle against climate change, natural resources management, and positive developments across the globe, particularly in the Africa region”, according to a GECF release.

“The partnership will further allow the sides to focus on capacity building, technical support, and shared expertise”, the statement adds.

The GECF comprises of 20 member countries, of which six (6), or 30%, are African countries, including Algeria, Angola, Egypt, Equatorial Guinea, Libya and Nigeria. Other members include Bolivia, Iran, Qatar, Russia, Trinidad and Tobago, Venezuela, Azerbaijan, Iraq, Kazakhstan, Malaysia, Norway, Oman, Peru, and the United Arab Emirates. The GECF member countries  jointly control 71% of the proven gas reserves, 45% of its marketed production, 53% of pipeline, and 60% of LNG exports across the globe. It is headquartered in Doha, Qatar.

The MoU has been signed against a unique backdrop. The world’s overall energy demand is assumed to grow along with the global economy and population growth. The GECF experts forecast that in order to fulfil this increased demand, the world will likely see a symbiosis of conventional and renewable energies to solve climate issues and to meet the needs of nations for affordable energy. Natural gas is expected to shoulder the bulk of this demand on the back of its attributes of being the most environmentally friendly, affordable, flexible, and abundant fossil fuel

Natural gas is projected to become the largest source of primary energy by 2050, from currently 23% to 28%, according to the latest data available from the GECF Global Gas Outlook 2050. Along the way, natural gas is expected to play a vital role in decarbonisation options including natural gas-based hydrogen, also known as the blue hydrogen, with carbon capture, utilisation and storage (CCUS) technologies.

“The mobilisation of science for the benefit of society and the planet is now more urgent than ever. We need science and technology, we need access to science and technology, we need to be able to reduce the knowledge gap between different countries across the world, and therefore this partnership with the GECF is really a beacon of hope and light,” said Nair-Bedouelle, following the virtual signing ceremony. “The GECF serves as a platform for the science policy interface, underpinning the importance of the exchange of scientific knowledge, experience, and dissemination of information through research and production of global outlooks and statistical bulletins”, she explained, adding that UNESCO is “confident that this partnership will further harness the potential of science and technological cooperation to address global challenges, through advocacy and awareness raising at all levels of society and economic sectors towards achieving the sustainable goals of the 2030 Agenda and beyond.”

Scientifically-grounded data and insights are championed at the GECF, whose Secretary General emphasised that technology is key to the envisaged energy transition and climate action such as greenhouse gasses (GHGs) emissions mitigation. “Education and science-oriented exercises play a great role in environmental protection with a view to raise awareness and cultivate a “culture of energy responsible behaviour” or “energy scholarship,” Mr. Sentyurin noted. “The GECF is developing technologies, including ones in relation to reduction of GHGs emissions through the GECF Gas Research Institute, recently established in Algeria, and fully dedicated to discovering new technologies and innovations to achieve the ambitious sustainable development goals in front of us,” the GECF Secretary General added.

“The GECF’s ambition to steward the gas industry into playing a greater role in environmental protection manifests in our Environmental Knowledge and Solutions initiative. This 12-point agenda focuses on many aspects of our activities,” Sentyurin declared, while referring to the 2019 Malabo Declaration adopted by the GECF Heads of State and Government, which calls on the Forum to use natural gas as the core source of energy in the development programmes and climate change policies of developing countries, such as in Africa, to overcome energy poverty and to mitigate CO2 emissions.

As an observer organisation to the UNFCCC (UN Framework Convention on Climate Change), the GECF actively participates in the conference of parties, with the most recent statements made at COP24 and COP25. The Forum is also a regular contributor to the discussions of the UN Economic Commission for Europe (UNECE) Group of Experts on Gas, where it analyses natural gas’ leading role in attaining the 2030 Agenda for Sustainable Development.

“This is complemented by our rapidly growing relationships with the G20, BRICS, and others in the spirit of joint action as regards to humanity’s shared mission of sustainable development,” Sentyurin concluded.

 

 

 

 


In Angola, Production Cost of $20-25 Per Barrel is “Fairly Good”

By Macson Obojemuinmen

Sebastião Gaspar Martins, chairman of Sonangol, says that a production cost of $20 to $25 per barrel is “fairly good cost” for Angolan marginal fields, which the government is proposing to offer in a bid round. “When we say high production costs, we are looking at no more than $20-25 per barrel, which is still fairly good. If prices stabilise around $50-55 per barrel by the end of 2020, we might be well within the range to be able to secure gains from the development of marginal fields”.

Angola defines marginal fields as crude oil and gas deposits which, due to costly recovery processes, are not worth the investment under the existing legal and fiscal framework. Several of the prospects found over the years in the country’s deep offshore, were dismissed in the pursuit of more profitable opportunities. A new framework, published in May 2018, considers, as marginal fields, those discoveries with proven oil reserves of less than 300Million barrels (exceptions are considered for bigger reserves in particularly expensive working conditions), standing at or below 800 metres of water depth, that do not give returns to the State of more than $10.5 per barrel, returns for the operator of no more than $21 per barrel and that have an average return on investment after taxes of less than 15%.

“Production costs are essential in deciding whether a project moves forward or not. Deep and ultra-deep waters come with very high production costs and we know that can jeopardise upstream activity in the current industry climate”, Martins explains. “One of the ways to overcome the high costs associated with the development of offshore fields is by utilising new technologies and ensuring high rates of production.
“We currently have some marginal fields (onshore and offshore) where fiscal terms can be improved in such a way that the projects can be viable even with high production costs”.

First published in the September/October 2020 issue of Africa Oil+Gas Report

 


In Senegal, Woodside Wants it All

Barely three months after pre-empting the sale of Cairn Energy’s interest in the Senegalese oilfield development and adjoining discoveries to a third party, Woodside Energy has made the same move on a similar transaction by FAR.

In mid-August 2020, the Australian explorer executed its right of first refusal to Cairn Energy’s sale of its 40% interest to LUKOIL, the Russian giant.

Last weekend, it pre-empted the sale of FAR’s i15% interest to the Indian company ONGC.

If Woodside successfully acquires both Cairn’s and FAR’s interests, its working stake in the Sangomar exploitation area will be 82%, with the state owned Petrosen holding 18%. The working interest in the remaining Rufisque, Sangomar and Sangomar Deep (RSSD) evaluation area (including the FAN and SNE North oil discoveries) will be Petrosen 10%, and Woodside 90%.

That is if the Senegalese authorities approve the transactions, as they are.

But Woodside is not there yet.

Although Cairn Energy PLC shareholders voted in favour of the sale and purchase agreement for Cairn Energy’s stakes on 23 September 2020, the transaction with FAR still depends on the outcome of a shareholder meeting, scheduled for December 21, 2020. “The shareholder meeting documentation expressly contemplated that such authorisation would cover the exercise of a pre-emptive right”, FAR says in a release.

Woodside has offered FAR the exact terms of the FAR/ONGC Transaction, including: • Payment to FAR of $45Million • Reimbursement of FAR’s share of working capital, including any cash calls, from 1 January 2020 to completion • Entitlement to certain contingent payments capped at $55Million.

Woodside says that the acquisition will be funded from current cash reserves.

Woodside CEO Peter Coleman said the acquisition of FAR’s participating interest makes the value proposition for Sangomar even more compelling. “Sangomar is an attractive, de-risked asset in execute phase, offering near-term production. The acquisition is value accretive for Woodside shareholders and results in a streamlined joint venture which will assist in our targeted sell-down in 2021”.


TOTAL Flows 4,330BPD of Condensate in South African Discovery

By Toyin Akinosho

French explorer TOTAL, has finalised a drill stem test on the Luiperd-1X well, its second major discovery on Block 11B/12B offshore South Africa.

The well was opened to flow on November 1, 2020.

After several tests at different choke settings, the well reached a maximum constrained flowrate through a 58/64″ choke of 33Million standard cubic feet per day of natural gas (MMscf/d) and 4,320 barrels of condensate per day (BCPD), an aggregate of approximately 9,820 barrels of oil equivalent per day (BOEPD), according to a report by Africa Energy, a junior partner on the asset.

”The choke configuration could not be increased due to surface equipment limitations”, Africa Energy explains. “The absolute open flow (AOF) potential of the well is expected to be significantly higher than the restricted test rates”.

TOTAL itself had reported the Luiperd-1X discovery last October, stating that the probe intersected 85 metres gross sands of which 73 metres is net good quality pay in the main target interval and thicker than prognosed.

The well reached total depth of approximately 3,400 meters on October 12, 2020, at which point the drill stem testing programme was initiated.

Africa Energy commented: “We are very pleased with the positive test results that show high condensate yield and excellent reservoir connectivity. These results confirm the joint venture’s decision to proceed with development studies and to engage with authorities about commercialization.”

Block 11B/12B is located in the Outeniqua Basin 175 kilometres off the southern coast of South Africa. The block covers an area of approximately 19,000 square kilometers with water depths ranging from 200 to 1,800 metres. The Paddavissie Fairway in the southwest corner of the block now includes both the Brulpadda and Luiperd discoveries, confirming the prolific petroleum system. The original five submarine fan prospects in the fairway all have direct hydrocarbon indicators as recorded on both 2D and 3D seismic data and intersected in the wells, significantly de-risking future exploration.

Africa Energy holds 49% of the shares in Main Street 1549 Proprietary Limited, which has a 10% participating interest in Block 11B/12B. Total E&P South Africa B.V. is operator and has a 45% participating interest in Block 11B/12B.

Africa Energy says it believes Luiperd and Brulpadda can potentially support a significant commercial development.”

 


Accugas Is One of the Top Four  Nigerian Domestic Gas Suppliers

With 113.5Millon standard cubic feet per day (113.5MMscf/d) averaged in 1H 2020, Accugas Limited has indicated itself as one of the top four natural gas suppliers to the Nigerian economy. The company is a subsidiary of the British headquartered Savannah Petroleum, which bought over the assets of Seven Energy in Nigeria. Accugas’ main hydrocarbon property is the Uquo gas field in Oil Mining Lease (OML) 13 onshore eastern Niger Delta basin.

Accugas’ competitors are Chevron. NDWestern and Seplat, the country’s biggest suppliers of natural gas to the domestic market. But unlike Accugas, all of them are in joint venture with either the Nigerian National Petroleum Corporation or its operating subsidiary, the NPDC. Between January and June 2020, the average gross natural gas output of these three JVs ranged from 222 to 320MMscf/d. This means that, on an equity basis, the output of Chevron, Seplat and NDWestern ranged between 99 and 144MMscf/d. By comparison Accugas’ 113.5MMscf/d average, in that period, is competitive.

The company increased its average gross daily natural gas production from the Uquo gas field  by  22.4% compared to the same period last year, from 92.7 MMscf/d (15.4 KBOEPD) to 113.5 MMscf/d (18.9 KBOEPD).

“In H1 2020, Accugas increased gas supply to the Nigeria power sector by 35% versus Q4 2019. This compares to wider industry performance which saw the gas shortage to supply the Nigerian power grid increasing by 33% versus Q4 2019”, Savanah Petroleum says in a statement.

The company achieved an all-time Nigerian Assets gas production record of 177 MMscf/d on 30 May 2020. While Accugas’ customers achieved an all-time record peak contribution of 11.5% of Nigeria’s electricity generation or 486MW on 23 May 2020, with the contributed electricity being exclusively generated from Accugas sales gas.

On 31 January 2020, Accugas entered into the first new gas sales agreement for the business in over five years with First Independent Power Limited, an affiliate company of the Sahara Group, for the provision of gas to the FIPL Afam power plant. Accugas is in the process of working with FIPL to validate the third-party infrastructure required to enable the commencement of gas sales.

In June 2020, Accugas signed a term sheet with a significant new industrial gas sales customer, a subsidiary of a well-respected international company, for an initial quantity of up to 5 MMscfpd of gas for an initial five-year period.

 

 

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