It’s no longer news that the Independent E&P companies have largely left frontier exploration in Africa for the majors.
But we must rejig our confidence in the ability of this species to own the future of the continent’s hydrocarbon industry.
However low the margin is, however high the cost of acquisition and however dire the above ground risks are, the Independents are making the case that assets divested by the majors are theirs to inherit.
A significant seismic shift took place in Angola recently, where Sonangol, the once mighty, former monopoly state hydrocarbon firm (who once played the role of its country’s regulator and commercial entity combined), declared that a bunch of small and, in cases, newly minted minnows, including Afentra, Sirius, Somoil, Sequa and Petrolog, had won the bids to acquire several of its stakes in Blocks 3/05, 15/06, 18, and 31, all producing licences.
The big story of 2022 has however remained Seplat Energy’s announcement about penning an agreement to acquire ExxonMobil’s subsidiary holding the company’s shallow water assets off Nigeria. The invoice is $.1.28Billion.
And while that story was sucking all the oxygen in the room, there was a tiny part of it most of us didn’t notice: the reserved bidder in the chase for those assets, running close behind Seplat Energy, is a consortium consisting of a brand-new Nigerian junior named Chappal and the well-known UK listed Capricorn, (Cairn Energy), the finder of Senegal’s first commercial sized oil field, which was also in the news recently as co-acquirer of most of Shell’s producing assets in Egypt.
The Africa Oil+GasReport 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 international corporations, local entrepreneurs, technical enterprises or financing institutions, for useful analyses of Africa’s oil and gas industry. It has been published by the Festac News Press Limited since November 2001, and since the COVID 19 season, as a monthly digital (pdf) publication, delivered to subscribers around the world. Its website remains www.africaoilgasreport.com and the contact email address is email@example.com. Contact telephone numbers in our West African regional headquarters in Lagos are +2347062420127, +2348036525979, +2348023902519
ION Geophysical Corporation (has completed the reprocessing and reimaging of approximately 19,100 km² of 3D seismic data offshore West Africa for its Mauritania 3D reprocessing programme.
The multi-client project was undertaken through an exclusive agreement with the Ministry of Petroleum, Energy and Mines in Mauritania. It is comprised of 11 vintage seismic surveys and provides a seamless, modern, high resolution data set spanning the Mauritanian offshore coastal basin. This basin is a key part of the frontier MSGBC basin in which several large-scale, offshore, gas fields have been discovered, with an estimated 63trillion cubic feet (Tcf)* in place in Mauritania thus far, ION declares.
“With foreign investment flowing in, field developments expected to come online in 2023, gas favoured as a source of energy for the energy transition, and capacity expected to exceed domestic needs, contracts for LNG export to European and other markets is anticipated”, the company reiterates.
“The MSGBC basin has become one that matters in the global oil and gas landscape, even if it is still today a frontier area. We have an enormous potential and we must find the right solutions to use these resources for the development of the country,” stated Chemsdine Sow Deina, Exploration Director at Societe Mauritanienne des Hydrocarbures (SMH).
“With ION’s delivery of its Mauritania 3D reprocessing program, operators now have a lower cost, lower risk, sustainable solution for evaluating the offshore hydrocarbon potential of Mauritania,” said Chris Usher, President and CEO. “As a result, we anticipate additional discoveries will be made that ensure Mauritania’s long term energy security, as well as exports that fund sustainable economic growth and development.”
The Mauritania 3D reprocessing program was supported by the industry and almost triples the amount of 3D data that ION has delivered this year from approximately 10,000 km2 to 29,000 km2. Final pre-stack depth imaged deliverables are now available. Learn more at iongeo.com/Mauritania.
*Estimate from Mauritania-Senegal: an emerging New African Gas Province – is it still possible? October, 1, 2020. The Oxford Institute for Energy Studies
Making maps from 3-D seismic data on a computer workstation was a completely new experience. It was my first encounter with such technology at work. We turned out much more accurate maps of very complex subsurface structures. And it was easier doing this than the labourious manual system we had been used to!
When an NNPC team led by Mr. Jim Orife came for a high-level JV meeting in Chevron offices in San Ramon, California, United States, I was chosen to present to them the fascinating results of the work we were doing. I had never seen my bosses so proud of their staff. I remember Mr. Orife calling me aside afterwards and saying “Ï have always said this to all my staff, no matter where you are, your biggest godfather will always be your competence and dedication to duty.”
I have preached the same sermon to all my staff and mentees to this day.
When my scheduled three-month tenure drew to a close in October 1987, Chevron sent a special request to NNPC, asking that I be allowed to spend three extra months to enable me finish the work I was doing. The request was granted, and I stayed on till January 1988.
Outside of work, it was pure excitement. I drove six hours from Sam Ramon to L.A. and spent a weekend in Disneyland and a full day at Universal Studios. I spent two working days at the Chevron Research Center in La Habra California, staff of which included Nobel Prize recipients. Nights out in Oakland and San Jose were regular weekend events. I spent a weekend driving through the Wine region north of San Francisco, to the Redwood Park in the Northern most part of California with my Chevron Colleague, Greg Croft. I drove across from Sam Ramon to the fun city of Reno, Nevada and made frequent tourist trips all around the Bay Area. Perhaps next only to my four years in UNN, those six months in California completed the excitement that youthful and early adult life was for me.
I was confused, this was a start-up Nigerian Company that could fold up within a year. NNPC had been exciting but I was beginning to doubt if the reward system had room for so called “exceptional performers”.
When I returned to Lagos in January 1988, the GM Exploration at Chevron invited me to his office and revealed to me that his principals in San Ramon were very impressed with my performance. He offered me a job in Chevron and told me he was leaving the offer open for a twelve-month period. Whenever I made up my mind, I was to return to his office to conclude discussions with him.
At this point I was generally perceived as a high flyer with a very bright future in NNPC, even though I had never earned a promotion ahead of my peers. I was sent on more training attachments to Shell’s Seismic Processing centre in Port Harcourt in 1990 and subsequently to Western Atlas Seismic Processing centre in London in 1990/91. The high point of my career in NNPC was winning the GMD’s award in 1991 “for exceptional performance”.
In September of that year, seven of us geologists were selected to go to the University of Ibadan for a one-year postgraduate diploma in Petroleum Engineering. This was a programme meant to convert us from Geologists to Petroleum Engineers. Midway into the programme, I got an offer that was to change my professional trajectory and instill an entrepreneurial mindset in me.
Prof. Jubril Aminu, as Petroleum Minister, had awarded eleven oil blocks to prominent Nigerians in 1990/91 on discretionary basis, to promote indigenous participation in the sector. One of the recipients was Mr. Kase Lawal, a young, Houston based international businessman. His company, Paclantic Petroleum (a subsidiary of his Houston headquartered CAMAC Group) had been awarded OPL 204. He was setting up shop in Nigeria and looking for a couple of people to hire. Originally from Ibadan, he contacted his kinsman in NNPC (Dr. Olu Ayoola, who retired later as GED Upstream) to recommend two people he could hire. Dr. Ayoola gave him two names: Mr. George Osahon, who was a highprofile Deputy Manager and I (just becoming an Assistant Chief Geologist). He warned him, however, that he was unlikely to be able to hire us out of NNPC.
We interviewed with Mr. Lawal and he made us offers. My offer was a handsome naira salary plus a dollar component of $36,000 per annum! An official car was also thrown into the bargain and I was going to be the Exploration Co-ordinator of Paclantic (whatever that meant), while Mr. Osahon would be my boss as the General Manager. Now, I was confused, this was a start-up Nigerian Company that could fold up within a year. NNPC had been exciting but I was beginning to doubt if the reward system had room for so called “exceptional performers”. I was on the same rank with all my peers, including those that had been training under me.
I am usually not strong on risk taking and I do not gamble, so I took the offer letter to Mr. Ofurhie. Surprisingly and without hesitation, he said I should take the job. I reminded him that he had previously advised me that if I ever decided to leave NNPC, I should only go to one of the IOCs. He simply ordered me to accept the offer and assured me that if the company folded up, I would get another job as I was well regarded in the industry. I left his home and went straight to Mr. Lawal to accept the offer. On March 2nd, 1992 I assumed duty in Paclantic as Exploration Coordinator, while still running my Post Graduate Programme at the University of Ibadan.
I disengaged from Allied on July 01, 2002, after ten exciting years. This, whole narrative about my education and professional training is meant to situate the author in proper context for the benefit of readers especially as it relates to my bonafides as an entrepreneur
I settled fully into the job in July 1992, upon graduation from U.I. My first task was to interpret the available seismic data over OPL 204. The block was completely barren, lying at the edge of the cretaceous and beginning of the Niger Delta. There was no prospect within the acreage that could be proposed for drilling. Fortunately, Kase had applied for a deep offshore block as the terrain was opened up for exploration in 1991. A number of IOCs were hot on the race for the few blocks that were on offer. In June 1992, Kase’s company, Allied Energy Resources was awarded OPL 210. The next hurdle was to secure a technical/financial partner to fund the initial work programme for the block. While Kase was working the corridors of power to secure the block, Conoco had indicated interest in farming in if he was successful in getting the property. But after initial evaluation, they declined to farm in. Next candidate was the Statoil/BP Alliance, which had also been awarded two blocks, OPLs 217 and 218. After some tough negotiations, they agreed to farm in for a 40% working interest, but assuming 100% financial responsibility for working the asset. Allied Energy was paid enough money to offset the statutory signature bonus with a decent sum to spare. As part of their responsibility to help develop internal capacity within Allied, the partner was also expected to pay some “Upkeep” stipend to Allied. With this partnership agreement in place, Mr. George Osahon and I set out to build Allied Energy from scratch.
We hired four smart, young men, a geophysicist, a geologist and two petroleum engineers, equipping them with a full 3-D Seismic workstation, drilling and reservoir engineering software suites and arranged rotational attachments for them and myself to the Statoil study team in Stavanger, Norway. The Allied team participated fully in the design and planning of what turned out to be, the first deep offshore well in Nigeria, the OYO-1 well which was drilled successfully as a commercial discovery in 1995. During this period, the block had been covered with full 3D Seismic data. Through the evaluation of the seismic data, and the successful well and the planning for its appraisal and development, the compact technical team in Allied had honed its skills and grown in confidence. The plan was that in ten years from 1993, we would have grown in technical and management capacity to take over operatorship of OPL 210. The first test of this plan came in 1997. Cavendish Petroleum, awardee of OPL 453 (one of the earlier 11 discretionary awards) had, along with her Technical Partner Conoco drilled a well, Obe-1 and made a modest discovery. Not material enough for Conoco they decided to exit the block. Because we (CAMAC) had a minority (2.5%) stake in the block, we had access to all the data Conoco acquired, including the Obe-1 well data. After a detailed evaluation of the seismic and well data, we proposed to Kase that we could farm into the field as technical partner to Cavendish. So, in a mere five years, Allied had developed enough capacity to provide technical partnership support to another indigenous company. It was an interesting development, as Allied got into partnership with Cavendish using the exact same structure Statoil had with us. This time, Allied had 40% working interest and 80% commercial interest. Just as Statoil had paid us, Allied paid Cavendish a farmin fee and a monthly stipend to cover their office running costs.
We prepared the full Field Development Plan (FDP) for the Obe field, including the production profile and projected commercial rewards. We presented this as a commercial proposal to Tuskar Resources, a small Irish Oil Company listed in Dublin but also trading on the London Stock Exchange (LSE). The deal was for Tuskar to inherit our full commercial interest in the Obe field in what amounted to a reverse take-over of Tuskar by Allied. By the time the deal closed, Allied owned 67% of Tuskar Resourceswhich was trading at about 1.5 pence per share at the time with a market cap of about ten million pounds sterling. Deal done, Allied raised debt funding from some London banks and we proceeded to develop the field and put it on production in 1999. As planned, the field was doing about 4,000 bopd and utilizing a small FPSO with 45,000-barrel storage capacity. By the time the field came on production, Tuskar share price had risen to over 10 pence with a market cap of about seventy million pounds sterling. The story of how this great enterprise was eventually squandered has been told somewhere else.
By 2001, there was talk of government action towards awarding marginal fields to companies organised around experienced and/ or retired professionals. In my nine years at Allied, I had been at the forefront of the advocacy for indigenous participation in the Upstream Oil and Gas Sector in Nigeria. I had written and spoken extensively on the subject. I had also gained extensive experience, not just in starting up and organising an oil and gas company but in the commercial and entrepreneurial side of things. Nothing was going to stop me from participating in the imminent marginal fields licensing round. My days in Allied were numbered.
I disengaged from Allied on July 01, 2002, after ten exciting years. This, whole narrative about my education and professional training is meant to situate the author in proper context for the benefit of readers especially as it relates to my bonafides as an entrepreneur. My experience, over eighteen years, in setting up Platform Petroleum and Seplat Petroleum (now Seplat Energy), constitutes my personal account and views on the challenges of entrepreneurship in Nigeria.
Excerpted from ‘My Entrepreneurship Journey’, a Memoir by Austin Avuru, founding CEO, Seplat Energy. The book is due to be released in August 2022 by Radi8 Publishers
Norwegian geophysical company PGS says it has been awarded “a significant acquisition contract, consisting of several four-dimensional (4D) seismic surveys, by an international oil company offshore West Africa.
Acquisition is scheduled to start early November 2022 and expected to complete early May 2023.
The contract effectively secures work for the company’s flagship acquisition vessel, Ramform Vanguard until next summer season.
“Combining the Ramform acquisition platform and our GeoStreamer technology will provide the client with high quality 4D data,” says President & CEO in PGS, Rune Olav Pedersen.
Canadian junior ReconAfrica is about to drill its first seismically defined hydrocarbon well in the Permian aged Kavango Basin onshore Namibia.
The 8-2 well is the first of an initial four well drilling programme, which will test two of the Basin’s three play types; oil prone Karoo Rift Fill and Intra Rift Fault Block plays, determined by interpretation of parts of the 1,211 kilometres of two dimensional (2D) seismic data acquired within the company’s over 34,000 square kilometre licensed area.
Jarvie-1, the company owned 1000 HP drilling rig “is now on the first drilling location (8-2) rigging up and scheduled to spud on or before June 25, 2022”, ReconAfrica says in a release.
ReconAfrica has just completed the second phase of its 2D seismic acquisition (761 km) with plans for the next phase of 2D seismic acquisition, which is anticipated to comprise in excess of 1,000 kilometres of 2-D seismic, making 2,211 kilometres of 2D seismic altogether. This (second phase) will be an extensive programme and subject to permitting, the Company anticipates on the ground acquisition to begin the fall of 2022.
8-2 will be drilled to a planned depth of approximately 2,800 metres (9,184 feet) and is designed to test potential conventional oil and associated natural gas reservoirs in clastic rocks (sandstones) in the Karoo Rift Fill, the Company’s primary play. The well will also be drilled deeper into the Pre-Karoo Mulden and Otavi formations. These intervals correspond to zones in the Company’s first well, the 6-2, (a non-seismically defined stratigraphic test) which is approximately 6.5 kilometres to the East, that had good oil and gas shows. It is anticipated the well will reach total depth within 60 days from the initial spud. Netherland, Sewell & Associates, Inc. (“NSAI”), the Company’s independent qualified reserves evaluator, has estimated an unrisked gross 799Million barrels of original oil in place (OOIP) for the well 8-2. The estimated unrisked gross prospective resource, (P50 case) with a projected 17% primary recovery, is 138Million barrels of oil for this well. Prospective resources are the arithmetic sum of multiple probability distributions.
“These estimates are based on un-risked prospective resources that have not been risked for chance of discovery and chance of development. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development”, ReconAfrica cautions. “There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by applying future development projects”.
The newly constructed 10,000Barrels Per Stream Day (BPSD) capacity Omsa Pillar Astex Company (OPAC) Refinery, located in Kwale, in Nigeria’s Delta State, has been unable get sufficient crude oil to refine as the company doesn’t operate its own oil producing field.
The refinery is sitting idle three months after the regulator signed off on its Licence to operate.
Planned products include Diesel (AGO), which is in high demand, Naptha, Kerosene and Fuel Oil.
OPAC is depending on crude supply from the state hydrocarbon company Nigerian National Petroleum Company (NNPC) Ltd, based on the government’s assurance to support modular refineries with feedstock, as documented in the Petroleum Industry Act (PIA).
OPAC and NNPC have been engaged in discussions since 2019 and OPAC has submitted documents to NNPC, for review.
NNPC officials had been expected to visit the refinery but they haven’t.
The question: Why the delay? Perhaps NNPC is wary of signing off 10,000Barrels of crude a day for payment in local currency Naira. Perhaps? NNPC sources declined to comment. NNPC officially, didn’t respond to inquiry from Africa Oil+Gas Report.
The facility has passed all reliability tests and won the approval of the Nigeria Midstream and Downstream Petroleum Regulatory Authority (NMDPRA) after a refinery and an effective refinery commissioning exercise. It had been okayed to receive crude for refining and it has the approval to sell products, documents sighted by Africa Oil+Gas Report indicate.
Nigerian hydrocarbon companies, whether operating upstream or downstream, do not take on NNPC in public, so comments from companies who have challenges with NNPC are always difficult get on record.
OPAC is the first functional modular refinery without its main promoters being operators of a producing oilfield, serving as guaranteed feedstock even though it is strategically located close to the MIDWESTERN Crude/Gas Gathering Facility in Kwale, where a combined 30,000 Barrels of Oil Per Day (BOPD) is gathered from several marginal fields and sent to the Brass and Forcados terminals.
The two fully functioning modular refineries in the country, completed before OPAC, are the 11,000BSPD Ogbele Refinery, (owned by Niger Delta E&P) supplied by the Ogbele field and the 5,000BSPD Waltersmith Refining & Petrochemical facility (built by Waltersmith Petroman), primarily supplied by the Ibigwe field.
Indeed, the Walter Smith Refinery receives 2,000Barrels of crude every day from SEPLAT Energy operated Ohaji South field, nearby, as the Ibigwe field does not deliver up to 3,000BOPD of its own currently. In any case, the entire crude produced in SEPLATS’s Ohaji South (about 7,000BOPD) is processed in a SEPLAT owned Early Production System (ELPS), sitting right inside the Ibigwe field Flow station, so there’s extremely beneficial relationship between SEPLAT Energy and Waltersmith.
Mozambique’s Energy Regulatory Authority (ARENE) will, by the end of July 2022, launch a tender to find strategic partners interested in developing solar power generation projects in Lichinga, Niassa Province, and Manje, Tete Province.
Each of the proposed solar power plants will have the capacity to generate 30 megawatts.
The tender will be part of the government’s Renewable Energy Auctions Programme (PROLER).
The public presentation of the environmental pre-feasibility study is scheduled for June 29, 202, so is the definition of the scope and terms of reference and consultation of all parties interested and affected by the project.
Launched in September, 2020, as part of the promotion of increased electricity generation capacity in the country, PROLER was developed by the Ministry of Mineral Resources and Energy with the support of the European Union.
By launching auctions under a public tender regime, the Mozambican government hopes to confer transparency and competitiveness on the renewable energy sector, thereby attracting the best possible national and international investors.
The modern Viking—in this case Norway—in actual fact continues its warring ways like that of historic times. Not with the sword but with the strength of Norway’s abundant oil, natural gas, hydro-electrical power and offshore wind energy. The country’s bounteous natural resources coupled with a small population of only 5.5Million people has resulted in Norway being anointed with one of the highest per capita incomes in the world.
Norway is Europe’s second-largest oil and gas producer behind Russia. It is playing a major role in helping the European Union shift away from reliance on Russian fuel after Moscow’s invasion of Ukraine.
The Norwegian sovereign wealth fund, built on the back of oil and gas profits, has over $1Trillion in assets, including 1.4% of global stocks and shares, making it the world’s largest sovereign wealth fund.
The Norwegian state’s participating interest is split in two parts. The first is linked to Equinor, the state hydrocarbon firm. The second is linked to the state’s direct financial interest (SDFI) in the petroleum industry. The SDFI system is a fund into which the surplus wealth produced by Norwegian petroleum income is deposited.
The purpose of the fund is to invest parts of the large surplus generated by the Norwegian petroleum sector, mainly from taxes of companies but also payment for licenses to explore for oil as well as the state’s direct financial interest and dividends from Equinor which is 67% owned by the state. The fund now has started dumping its shares in oil and gas companies and instead prescribing renewables to ensure it’s on the right side of history.
Yet the term ‘green’ has, since the Russian-Ukraine conflict, been given a serious re-think. Natural gas is now considered relatively green. Norway is, of course, more than happy to ensure that Norwegian natural gas can be substituted for Russian gas and thus ensure that Norway’s sovereign wealth fund continues to grow and Equinor in turn, has the funding required to ensure its future green growth.
The Greening of Natural Gas
While Norway can continue its green journey, the legitimacy of greening natural gas has ramifications far beyond the Norwegian Treasury. Christian Ng, Research & Stakeholder Engagement Leader, Debt Markets, described in a recent IEEFA (Institute for Energy Economics and Financial Analysis) how green has achieved a green status.
The key question according to Ng is “how do we ensure that green-branded businesses and products are true to label and deserving of green energy finance?” According to her, green taxonomies play an important role.
“A taxonomy is a system for categorizing things based on their scientific characteristics. A green taxonomy specifies business activities that are low-emitting and environmentally sustainable, and therefore eligible for green finance. In the energy space, this typically refers to renewables like solar, wind and geothermal. It also specifies the environmental criteria, such as emissions thresholds, that the activity must satisfy to qualify for the green label.”
For banks and investors, Ms. Ng continues, “a taxonomy provides the parameters for what they can and should invest in if they want to call it a green investment. Wanting certainty that they are investing in clean and sustainable technologies; they rely on taxonomies to guide them.
“Therefore, a key role of green taxonomies is to efficiently channel and unlock new pools of capital towards proven, environmentally clean and sustainable assets, to address the global climate crisis.”
Ng argues that both Europe and China have developed a common ground taxonomy: a comparison exercise of their respective taxonomies to identify commonalities and differences. The European and Chinese approach is a counter measure to taxonomies tailored to national or regional contexts which in terms of methodology, metrics and technical criteria can differ significantly from market to market, leading to comparability issues for capital providers.
Within this debate natural gas has become a key issue. According to Ng in October 2021 the South Korean government added LNG to its near-final green taxonomy. Likewise, in November 2021 the European Commission signaled that the EU is considering a role for natural gas as part of its green taxonomy. Other Asian markets have indicated similar intensions meaning gas or LNG would qualify for green bonds and loans under these taxonomies.
Yet China, according to Ng, has indicated that its long-term policies exclude fossil fuel electricity projects, sending the right signals to the market. The precedent was set in 2015. Then China’s first green taxonomy categorized “clean coal” as a green project that qualified for the issuance of green bonds, drawing widespread criticism. No doubt the 2015 incident sent China a signal to take green more seriously.
In the short-term China has chosen natural gas as the fuel of choice. In 2020 China created PipeChina, an overarching national gas pipeline company to rationalize and distribute natural gas on a country-wide basis. PipeChina is the most visible sign that China sees natural gas in the short term as a fuel of choice if it is to achieve its goal of CO2 neutrality by 2060 or earlier. China has at present 22 LNG import terminals and plans to construct 24 more by 2025.
Another piece of the puzzle is international financial participation. Ng indicated that Yi Gang, the governor of the People’s Bank of China, …” stressed that government funding alone would not be sufficient for China to meet its net zero goals – forecast to require an estimated $22Trillion from 2021 to 2060 – and therefore, market participants must be encouraged to step in and fill the gap”.
In other words, multi-lateral funding will become a necessity. The Chinese approach is based on two premises:
1.) In the short-term natural gas as its fuel of choice; and
2.) In the long-term be prepared to move towards cleaner, low carbon fuels (wind and solar) in order to achieve green financing.
The green debate continues over two key issues:
1.) Whether natural gas should be seen as sustainable, and
2.) If gas has a role in decarbonizing the economy, should it be seen as a green investment?
Ng concludes: “If gas-fired power is recognized as green, Environmental, Social and Governance (ESG)-focused investors may find themselves inadvertently backing the high methane and carbon fuel and risk being accused of greenwashing. This in turn risks undermining investors’ trust and the purpose of green taxonomies.”
Two powerful groups have opposed the inclusion of natural gas in any taxonomy system:
1.) The UN-backed Net-zero Asset Owner Alliance, which represents about EUR 9Trillion of investment; and
2.) The European Sustainable Investment Forum (EUROSIF), a pan-European sustainable and responsible investment association.
The Chinese can take heart and be assured that in the short-term their natural gas and LNG imports will be given a green stamp. And be further assured that they have a favorite position staked out to develop a future low-carbon world.
The Norwegian Challenge
According to the Norwegian Petroleum Association (see below), Norway produced in 2020, 22% of Europe’s natural gas demands. Additionally, two-thirds of Norway’s total gas resources is still to be produced. No doubt in the short-term natural gas exports from Norway to Europe will be substantially raised.
A very recent example of Norway’s importance to the UK is that Equinor and UK-based Centrica agreed for Norway to provide an additional 1billion cubic metre (bcm)/year to the UK under Equinor’s existing contract with Centrica, lifting the total volume above 10bcm annually. Typically, Equinor exports up to 22bcm /year of natural gas to the UK which covers more than 25% of the UK’s gas demand. Helge Haugane, Equinor’s senior vice president, Gas & Power said that “In a period with a challenging political and macro-economic environment with strong demand for natural gas, we at Equinor are doing what we can to export as much gas as possible to the market”.
The greening of natural gas will help strengthen Equinor’s twin pillars of natural gas and its growing offshore wind portfolio. Will this provide Equinor 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. Yet there is severe competition from a number of key European new energy players.
ENGIE based in France: In 2021 the company spent more than $11Billion 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 50 GW of global renewable installed capacity by 2025.
Enel based in Italy: The company’s strategic plan outlines total investments of $231Billion and tripling renewable capacity to 154 GW by 2030.
Ørsted based in Denmark: By 2030 the company will have an installed capacity of 50 GW of renewable power.
Iberdrola based in Spain: From 2020–2025, the company will be spending $165Billion on renewable energy and has a pending target of 95 GW of installed wind capacity.
RWE based in Germany: By 2030 RWE will have 50 GW of installed wind and solar capacity.
Vattenfall based in Sweden: In the Nordic countries, Vattenfall has low emissions, with practically 100% of the electricity produced based on renewable hydro power and low-emitting nuclear energy.
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.
Clarity of message
No doubt the Equinor share price is enjoying the message being sent out: that the company will be spending more than one-half of its capital spending on low carbon energy by 2030 to become a leader in offshore wind technology. While the investor community may see the low carbon strategy as a clear incentive, the obvious benefit is the simple clarity of the message.
Whether a company is an oil company or an energy company seems less important. That is why aside from Equinor, Chevron, which is on track to make 2022 the 35th consecutive year with an increase in annual dividend payout per share, has maintained its value. Of the oil majors—BP, ENI, ExxonMobil, Equinor, Shell, Repsol, and TOTALEnergies— have been industry laggards between 2018 and 2022 whereas Chevron and especially Equinor stand out very positively.
Table 1: Stock market prices of majors 2018-2022(NYSE)
Note: Values based on January 5, 2018 and April 29, 2022
During these five years, Repsol’s stock is down 12%, BP’s stock is down 33%, Shell is down 23%, ENI down 20%, TOTALEnergies down by 16%, and ExxonMobil remained flat, whereas Chevron’s stock rose by 23%, and Equinor up 48%.
The question remains whether Equinor can continue to maintain its twin portfolio—offshore wind and natural gas—under one roof. For sure, Europe will require much more Norwegian natural gas in the near future. Will the additional funding from European gas revenues be enough to provide its offshore wind division the necessary economies-of-scale to compete with Europe’s new energy companies? Will Equinor’s offshore wind energy division be spun off to create yet more shareholder value? If so then our modern Vikings could open a second economic front in the ongoing battle of the energy transition.
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.Hewrites on a regular basis for Africa Oil + Gas Report, and contributes to IEEFA (Institute for Energy Economics and Financial Analysis). His book The 10 Commandments of the Energy Transition is being published this June.
The Coral South Project has achieved the introduction of hydrocarbons to the Coral Sul Floating Liquefied Natural Gas (FLNG) plant from the Coral South reservoir offshore Mozambique.
“Following the introduction of gas in the plant, Coral Sul FLNG will now be ready to achieve its first LNG cargo in the second half of 2022, adding Mozambique to the LNG-producing countries”, according to a statement by the Italian player ENI, the Upstream Delegated Operator of Area 4, on behalf of its partners ExxonMobil, CNPC, GALP, KOGAS and ENH.
“Hydrocarbons introduction comes after the safe and timely conclusion of the offshore commissioning activities”, ENI said. “The FLNG arrived at the final operating site offshore Mozambique in early January 2022; mooring and connection to six underwater production wells were finalized in March and May 2022, respectively”.
The Coral South project achieved Final Investment Decision in 2017.
“FLNG fabrication and construction activities started in September 2018 (Hull first steel cut), and were completed in 38 months as planned, despite the Covid-19 pandemic, with a FLNG Sail Away, from South Korea to Mozambique, on November 2021”, the statement added. “While performing the construction activities in Korea, several significant activities were undertaken in Mozambique, with support from the Mozambican authorities, including the ultra-deep waters (2,000m wd) Drilling and Completion and Offshore Installation campaign that involved the highest technological and operational skills.
“Coral-Sul FLNG has been implemented with an energy optimization approach, integrated in the design via a systematic analysis of energy efficiency improvements. These include among others, zero flaring during normal operations, use of thermal efficient aero-derivative gas turbines for refrigerant compressors and generation, use of Dry Low NOx technology to reduce NOx emission and waste heat recovery systems for the process”.
The Coral Sul FLNG is 432 metres long and 66 metres wide, weights around 220,000 tons and has the capacity to accommodate up to 350 people in its eight-story Living Quarter module. The facility is located at a water-depth of around 2,000 metres and is kept in position by means of 20 mooring lines that totally weight 9,000 tons.
Coral Sul FLNG has a gas liquefaction capacity of 3.4Million tons per year (MTPA) and will put in production 16Trillion Cubic feet of gas from the giant Coral reservoir, located in the offshore Rovuma Basin.
Coral-Sul FLNG is the first floating LNG facility ever deployed in the deep waters of the African continent.
Shell-funded impact investment company, All On has announced a $500,000 investment in Greenage Technologies Power Systems Limited to fund the construction and expansion of its charge controllers and inverters manufacturing facility in Enugu State in South-Eastern Nigeria.
Ogechukwu Uchechukwu, Co-founder and Head of Business Development, Greenage Technologies, says the support will help the company reduce the cost of solar energy components through local manufacturing. “This investment will help Greenage realize its aim of becoming Africa’s largest solar electronics manufacturers by doubling its existing manufacturing capacity for inverters, charge controllers, and the possibility to assemble lithium-ion batteries,” he explains.
The funding is a mix of equity and convertible debt that should enable Greenage to expand its manufacturing business through the acquisition and development of a new factory and fund its working capital needs – enabling it to meet the increasing demand for locally manufactured solar systems components.
“We are proud to close another transaction to enhance the localization of the solar supply chain,” notes Wiebe Boer, CEO of All On. “Through this investment All On is lowering the proportion of solar components imported into Nigeria. This investment is at the core of our commitment to investing in youth-driven Nigerian companies like Greenage to accelerate the sector’s growth and contribute to closing the energy access gap.”
Greenage was a USADF/All On Off-Grid Energy Challenge winner in 2018, receiving $100,000 to fund the installation of solar systems in over 40 households and businesses.
All On concludes in the statement: “This additional funding is an indication of All On’s growing confidence in the company’s vision to play an increasingly important role within the Nigerian renewable energy value chain as a manufacturer of solar energy system components”.