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‘You Can’t Come Clean with African Cooking Without Investment in LPG Infrastructure’, Sahara Argues

The Sahara Group has described the dearth of adequate infrastructure for cooking gas as the most daunting challenge to ramping up clean cooking across Africa.

It also thinks that this challenge offers a great business opportunity.

Ijeoma Isichei, Head, Business Development (Gas), Sahara Group and a senior manager at WAGL Energy Limited (An NNPC Limited and Sahara Energy JV), has advocated investment in bulk storage, transportation, filling facilities, LPG cylinders, seamless distribution, and retailing, through industry-led expansion programs, support from developed economies, and well-established public-private-partnerships, among others.

Ms. Isichaei, noted that there was “limited storage infrastructure to support the growing demand for LPG in Africa, making the region reliant on imports and shipping”.

She spoke in Paris, at the Summit on Clean Cooking in Africa, organised by the International Energy Agency (IEA).

LPG (Butane), also known as cooking gas, is widely regarded as an efficient and clean-burning cooking fuel used by almost three billion people.

CITAC estimates that the demand for LPG in the Sub-Saharan region would almost triple by 2035, compared to current levels. According to the World Bank, regional economic blocs on the continent have set ambitious targets for LPG penetration and consumption to drive almost exclusive LPG deployment for cooking by 2030.

IEA estimates “that wood and charcoal represent the primary cooking fuels of 1Billion people in Africa,” Isichei referenced. This is not healthy. “I believe that opportunity lies in the greatest challenge,” Isichei declared.

Isichei called for more LPG advocacy platforms that would serve as a meeting point for governments, the private sector, and international organizations to give traction to global clean cooking solutions. “I propose more public and private partnerships. A clear example would the partnership between Sahara Group and Petroci, the Côte d’Ivoire National Oil and Gas company towards the construction of 12,000 Metric Tonnes LPG storage facilities in Côte d’Ivoire.










She added that multi-stakeholder collaboration would also help improve awareness and LPG adoption as against biomass and kerosene and accelerate alignment of policies required to make LPG production, storage, transportation, and distribution seamless across Africa.

SONATRACH Awards Construction of 20 Gas Trains to Baker Hughes & Co

Algeria’s state hydrocarbo firm Sonatrch has awarded Baker Hughes and Marie Technimont  the supply of 20 compression trains based on Frame 5 gas turbine and BCL compressor technology.

The plants are to be installed across three gas boosting stations within the Hassi R’ Mel gas field. Located 550 km south of Algiers,

Hassi R’ Mel is the largest gas field in Algeria and one of the largest in the world, representing a key source of energy supply for Algeria and Europe.

Baker Hughes, itself a large American oil and gas engineering contractor, claims that its proven technology solutions are expected to play a central role in the project by boosting and stabilizing the pressure of natural gas and increasing production at site, “which will enhance Algeria’s domestic energy system and economy as well as Europe’s energy security”

Packaging of the compressor trains, as well as manufacturing of the compressors and testing of the trains, will take place at Baker Hughes’ facilities in Italy.

The new gas-boosting stations are part of Algeria’s ambitious plan to strengthen its role in the global energy market and its commitment to natural gas as a key energy source for socio-economic development. Algeria became the second-largest gas supplier to Europe in 2023, according to Bloomberg NEF, further strengthening the country’s role in enhancing the energy security of the continent, particularly in Italy where Algeria represents the biggest single source of import.

The Hassi R’ Mel Project is part of a broader strategic collaboration between Algeria and Italy, which includes recently signed agreements to foster bilateral cooperation and provide financial support for Algeria’s gas production as part of the Mattei Plan. The Mattei Plan seeks to promote cooperation between Africa and Italy along five main policy pillars: education and training, agriculture, health, water and energy.


Invictus Signs a Second Gas to Power MoU from Untested Zimbabwean Asset

MoUs are statements of wishes and the company still has to prove economic commerciality of the Mukuyu wells with flow rates…

Australian minnow, Invictus Energy, has signed a second Memorandum of Understanding for sale of gas from its hydrocarbon asset onshore Zimbabwe.

The deal to provide natural gas for a 50MW Gas-to-power project for Eureka Mine, one of Zimbabwe’s largest gold mines, comes three months after an updated MoU with expanded mandate was signed for Mbuyu Energy, a Zimbabwean consortium led by IPP developer Tatanga Energy, a deal which envisages delivery of up to 1,000MW of electricity, if consummated, “with demand for an estimated 1.4Trillion cubic feet of natural gas”, Invictus claims.

Invictus says it finished 2023 by declaring dual discoveries during in its Mukuyu-2 drilling campaign, in what it described as a transformative year for the Company and its shareholders.

But MoUs are more of statements of wishes and Invictus still has to prove economic commerciality of the Mukuyu wells by running Drill Stem Tests (DSTs) which will show flow rates and the deliverability of the reservoirs.

Invictus  has signaled it is awaiting Petroleum Production Share Agreement (PPSA) with the Republic of Zimbabwe,  and has been engaging the responsible cabinet level Ministers, but its recent statements also indicate there’s much more to be done to reach commerciality: “The upcoming working programme includes a well test at Mukuyu-2, preparation for three dimensional (3D) seismic over the Mukuyu gas field and preparing long lead items for a new high impact exploration well, the location of which will be determined following full interpretation of the acquired CB23 infill seismic survey programme”..


ExxonMobil Invites Contractors to Prep for the Vast Rovuma LNG Project in Mozambique

ExxonMobil has launched several tenders for Front End Engineering Design for gas gathering and subsea as well as basic improvement in the installed camp facilities; on its huge Rovuma LNG project in Mozambique.

Those are, of course, secondary to the FEED contract for the actual LNG plant itself, which currently features a competition between Saipem, Bechtel, and an alliance of JGC and Technip Energies, all contesting for the job, with the winner expected to deliver the main engineering, procurement, construction and commissioning contract.

The supermajor is on course of taking Final Investment Decision on the 18Million tonnes per annum Liquefied Natural Gas Plant which will monetise trillions of cubic feet of gas in the Area 4 concession in deepwater Rovuma Basin.

In one of the new tenders, the work scope involves  engineering, procurement and construction contract providing a 2,500-person construction camp in Cabo Delgado province, expanding the existing 500-bed pioneer camp at Afungi to accommodate an extra 700 beds, construction of a permanent camp able to house about 2500 beds and providing operations, maintenance and security services for both the pioneer and permanent camps, during and after their construction periods as well as clearing and grubbing — the removal of trees, shrubs, stumps and rubbish — in ‘strategic’ zones that cover a total estimated area of 418,000 square metres. The contractor will also be handling engineering, procurement, fabrication, shipping, construction, installation, commissioning and project management of these work scopes.

A second tender calls for a FEED plus optional EPCI contract for the subsea-to-shore gas gathering facilities, involving the deepwater installation of subsea manifolds, foundations, control distribution systems, flying leads and rigid well jumpers, as well as installation of umbilicals in onshore, shallow water, and deepwater domains. This tender includes the EPCI of pipelines in onshore, shallow water and deepwater environments and deepwater in-field flowlines, rigid jumper spools and other subsea kit. This bid covers dredging, relocating corals and seagrasses and escarpment crossings and also includes mechanical completion, pre-commissioning and commissioning support of the subsea hardware, including the two main umbilicals — running from the gas field to shore — and nine in-field umbilicals which are being secured by ExxonMobil under a separate EPC contract.

ExxonMobil has been reported as saying it would take a final investment decision in 2025 on the project, which rolled off to the back of the burner in 2021 due to fatal attacks by Islamist insurgents on Palma town and its environs in Cabo Delgado province, including the Afungi construction site for its LNG trains — and those for TOTALENERGIES’ smaller 13Million TPA Mozambique LNG project.



French Major Expands Gas Development Partnerships with Algeria

French major TOTALEnergies and Algerian state hydrocarbon company SONATRACH have signed a Memorandum of Understanding aimed at concluding a hydrocarbon contract in the north-east Timimoun region, under the aegis of Law n°19-13 governing hydrocarbon activities.

This Memorandum of Understanding outlines the realization of a work programme for the appraisal and development of gas resources in the North-East Timimoun region, in synergy with existing processing facilities for production from the Timimoun field, to reduce costs and emissions.

“This Memorandum of Understanding reflects our shared willingness to expand our strategic partnership with SONATRACH”, said Julien Pouget, Senior Vice President Middle East & North Africa, Exploration & Production at TotalEnergies.

The two companies had earlier in 1Q 2024,  extended their cooperation in the field of liquefied natural gas (LNG) by extending their contractual relationship until 2025.

By the terms of that deal, SONATRACH will be delivering two million tonnes of LNG to TOTALEnergies at the port of Fos-Cavaou, near Marseille, which will contribute directly to the security of energy supply in France and Europe.

Nigeria’s Gas Price Hike “The bulk of the debts accumulated by Gencos arose post privatization of PHCN”

The establishment of a new pricing framework for natural gas for strategic sectors such as Power is considered a win for upstream gas producers, but that in itself, doesn’t tell the whole story.

In the aftermath of the price announcement, Africa Oil+Gas Report caught up with Eberechukwu Oji, Chief Executive Officer of ND Western, the Nigerian independent firm whose Joint Venture with NNPC E&P Ltd (NEPL) is the largest supplier of natural gas to Nigeria’s domestic market.

Excerpts from the short conversation between Oji and Toyin Akinosho, publisher of AOGR …

AOGR The Government’s increase of the Domestic Base Price (DBP) to $2.42 per Million Metric British Thermal Units (MMBTU). This means increased price of the commodity for power Generation Companies (Gencos) to $2.42 per thousand cubic feet. The price of gas sold to Gencos had been at $2.18 since 2021. Is this good? Plus, no one said anything about willing seller willing buyer. This is still “Price Control”. Is it good or am I getting it all wrong?

Oji: The increment in the Domestic Base Price (DBP) from $2.18/MMBTU to $2.42/MMBTU for the power sector is indeed a positive development for upstream gas suppliers. While the price may not fully reflect the true cost of gas production, it indicates a positive response from the government and regulatory bodies to the concerns of upstream producers. With thermal energy accounting for a substantive portion of Nigeria’s power generation, incentivizing gas production is crucial for meeting the country’s energy needs. 

Regarding the concept of willing buyer and willing seller, it is our view that we need to be deliberate, as a country, to attain a free gas market as quickly as possible. That being said, the DBP directly applies to the regulated strategic sectors in line with PIA. Thus, agreements based on willing buyer/willing seller principles may not be directly affected by the DBP.

You are right, this is still price control. We need to move to willing buyer willing seller as quickly as possible.

Is it possible for you to put yourself in the shoes of Transcorp Power, or, say, Geregu Power? Is this not a little too high for these electricity generation companies?

Considering the perspective of Gencos, it’s understandable to anticipate potential challenges from the price increment, especially from electricity consumers. It’s crucial to recognize that the affected Gencos operate within a regulated value chain, with a tariff model that allows approved fuel cost as a pass-through. Thus, the gas price increment may not necessitate an adjustment to the Gencos’ cost component in the tariff model. However, the gas price increment may warrant an upward review of the consumer electricity tariff.

There is a lot of talk of Legacy debts (and Transcorp owes you a lot of that). Were these debts owed by the old PHCN before the takeover by the Private Gencos? Or were these debts incurred in the course of the last 11 years post privatisation?

The bulk of the debts accumulated by Gencos arose post privatization of PHCN. For most of our own customers, these debts dates as far back as 2014, post the privatization of PHCN.

This increase, which is really an incentive, is coming less than a month after the incentives rolled out on Non-Associated Gas, by the President. Wouldn’t you then call this a month of good tidings?

The recent increase in the DBP, coupled with incentives for Non-Associated Gas, reflects a positive trend in the Nigerian government’s prioritization of the gas sector. However, the gazette by the FGN on incentivizing Non-Associated Gas (NAG) production speaks to greenfield developments in onshore and shallow water locations. There is a need to seek clarity from the regulators on what this means for brown fields as we expect to have access to these incentives in order to fulfil the aspiration of the FGN in increasing the nation’s gas production. These efforts are warmly received by gas producers, underscoring the pivotal role of the gas sector in ensuring energy security, driving electricity generation, and fostering economic development.

As we have always advocated without incentivising upstream gas production, all the beautiful gas plans of the government collapses.

Editor’s note: The Nigerian government announced, the day after the gas price hike, that it had approved an increase of 300 per cent electricity tariff for Band A consumers in the country. Accordingly, power distribution companies (DisCos) will be allowed to raise electricity prices to ₦225 ($0.15) per kilowatt-hour from ₦68 for urban consumers this month effectively from April 1, 2024.



“The Rise of Gas”; Valuable Knowledge Base, Compelling Narrative

By Afolabi Oladele

Charles Osezua’s The Rise of Gas: From Gaslink to the Decade of Gas, gives a magisterial account of Nigeria’s entry into the comity of oil and gas producing nations, beginning not from Oloibiri as many historians of the sector like to note, but from the Dahomey Basin and then Akata, close to Eket, all the way to the country’s chequered history of gas exploration, waste and utilisation.

The author’s story began with what now seems like a prophetic utterance when late Aret Adams ran into the younger man in Kaduna and called him “Gas Man.”

Aret Adams was speaking in prophetic tones, given Mr. Osezua’s pivotal role, not only in policy formulation driving the development of Nigeria’s gas resources, but more as a serial entrepreneur who has invested in the entire spectrum of gas production and utilisation.

For these reasons, the name, Charles Osezua, will be written in bright lights.

In this book, his account begins in the 1970s and runs its course up to 2023 when energy transition is making daily headlines.

Charles Osezua, author of ‘The Rise of Gas’

On Monday July 31, 2023, President Bola Ahmed Tinubu (BAT) unveiled his economic plan to the nation in the wake of the removal of the fuel subsidy. He declared in his speech that “We have made provision to invest ₦100Billion between now and March 2024 to acquire 3,000 units of 20-seater CNG-fuelled buses.”

What is CNG and what does it portend for the Nigerian gas industry and economy?

This book will provide you with the answers, narrating succinctly how the country could have been using CNG-fuelled vehicles almost four decades before President Tinubu’s pronouncement. It will also chronicle for you, in broad strokes the:

  • irony of a country constrained to import gas and deal with years and years of gas scarcity on account of flagrant flaring of gas; and
  • missed opportunities to harness the stranded gas due to several policy somersaults and reversals across different administrations, the most painful of which Charles Osezua details in Chapter 4 of this riveting book. Ibrahim Badamasi Babangida’s administration’s suspension of a federal government gazette set Nigeria’s gas industry and utilisation back several decades; and all this in spite of the evolution of a Gas Pricing Policy which was predicated on a comprehensive nine-month market survey conducted across all states of the federation, covering industrial clusters with clear data on the potential for gas utilisation.

The book outlines the sad and disheartening story of the nation’s years of burning money that predated the Gas Master Plan.

It is also the story of a young man from “a small village in Ekpoma, with a father who was a farmer and a mother who was an energetic farm produce trader,’ who rose to the pinnacle of Nigeria’s gas industry, undeterred by the failures of national policy.

Driven by what he witnessed as a young man, the tongue of flame leaping into the air in Ugbelli, he was inspired to pursue a course of study that would help address what appeared to be an anomaly. He went on to study Natural Gas Engineering in the US.

On completion of his studies, he joined the Nigerian National Petroleum Corporation (NNPC) where he rose to become a champion, focused on the articulation of policies to monetise the country’s enormous gas resources, starting with the elimination of gas flares, and enhancing the terms for gas development.

Engineer Osezua was years ahead of his time, as the nation is only now waking up to address the issues, he raised regarding gas being the future revenue earner for the country. Many of his works are documented in articles and position papers. These gave him the moniker, Gas Man.

He left NNPC, and his entrepreneurial passion took him first to being part of the group that birthed the Lagos Business School and subsequently, the creation of ground-breaking gas utilisation companies amongst which are great successes like Gaslink and Egbaoma Gas Processing plant.

Gaslink is discussed extensively in this book, and its transformational impact on the seven industrial areas of Lagos provides proof of what could have been replicated on the national scale where Nigerian industries provided with reliable energy supply and feedstock would have produced a range of petrochemical products including fertilizers, ammonia, etc.

The book is funny in parts, tear-inducing in others but at the end, what emerges is composite of what has held Nigeria back for decades thanks to the short-sightedness of our leaders and Policymakers.

This book is a valuable knowledge base for everyone involved in the gas value chain, from students to oil industry workers technocrats and policymakers as we proceed with the transition agenda.

As Chinua Achebe once wrote, “a man who does know where the rain began to beat him cannot say where he dried his body.” Engineer Charles Osezua in this book has shown us where the rain began to beat us and where and what we must do to begin to dry our body as a gas producing nation.

Above is the foreword to the book.

“The Rise of Gas”, published by Radi8,  is set for a public presentation on Tuesday, April 9, 2024, at the Nigerian Institute of International Affairs (NIIA) in Lagos, Nigeria.

About the reviewer, Afolabi Oladele: Following a successful career with 25 years’ experience in the oil and gas industry, primarily with the Nigerian National Petroleum Corporation (NNPC), Mr. Oladele joined African Capital Alliance (ACA) in 1999, retired from ACA after 21 years and worked with many of ACA’s investee companies in several value-adding roles along with full responsibility for the firm’s investor relations. He continues to sit on the Boards of ACA’s oil and gas portfolio as well as financial services companies.





Gas Price Hike: Nigeria Nods Again to Upstream Producers’ Demand

By Lukman Abolade

Nigerian oil and gas upstream producers won the second major incentive in one month, when the government announced the establishment of a new pricing framework for natural gas for strategic sectors such as Power, Commercial, and Gas-Based industries.

The country’s Midstream & Downstream Petroleum Regulatory Authority (NMDPRA) set a new price for natural gas sale to electricity producers at 24 American cents per Million Metric British Thermal Units (MMBTU), or thousand standard cubic feet (Mscf) higher than what had obtained, since the last price regime announced by a former Deputy Minister of Petroleum in 2021.

Under the new pricing regime, the NMDPRA set the Year 2024 Domestic Base Price at (DBP) at $2.42 per Million Metric British Thermal Units (MMBTU).

This means increased price of the commodity for power Generation Companies (Gencos) to $2.42 per cubic feet. The price of gas sold to Gencos had been at $2.18 since 2021. For commercial gas, the government increased the price from $2.50 to $2.92 per cubic feet.

The gas price hike comes exactly a month after the gazetting of President Tinubu’s executive orders, granting tax credit incentives for Non-Associated Gas (NAG) greenfield developments in onshore and shallow water locations, with first gas production on or before 1st January, 2029.

As a debate erupted around the affordability of the new gas prices by electricity generation companies, who are owing gas suppliers a huge amount of debt, the government announced, the day after the gas price hike, that it had approved an increase of 300 per cent electricity tariff for Band A consumers in the country. Accordingly, power distribution companies (DisCos) will be allowed to raise electricity prices to ₦225 ($0.15) per kilowatt-hour from ₦68 for urban consumers this month effectively from April 1, 2024.

By some estimates, government and private electricity producers owe gas producers ssome $ 1.3billion.

This raft of incentives is clearly meant to boost investment in natural gas development, and unlock more from the 200Trillion cubic feet estimated reserves, stored in the prolific Niger Delta basin.

Nigeria has grappled over the years with a stubbornly low quantum of electricity supply (between 3,500MW and 5,000M for a population of 200Million people), largely attributed to challenges thrown up by the national grid. The Transmission Company of Nigeria (TCN) has identified several factors contributing to this situation, notably including reduced gas supply and incidents of vandalism.

Nigeria has 26 Grid connected electricity generating plants, with installed capacity of of 12,199MW, out of which only 3,957MW, or less than 32%, was generated in February 2024, according to the Nigeria Electricity Regulatory Commission(NERC). Although 22 gas-fired electricity plants made up 84% of the installed capacity, they delivered only 50.2% of the power generated during the month. Four hydroelectric plants, which make up just 16% of the capacity installed, produced 49.8% of the power.

Part of the reasons alluded for low generation by gas-fired plants is “shortage of gas”. Some consider this argument to be a stretch, but it is a key reason why government thinks there should be more incentives for gas production.

Farouk Ahmed, Chief Executive of  NMDPRA, explained that “The Domestic Base Price at the marketable gas delivery point under Section 167 (1) and other provisions of the PIA shall be determined based on regulations which incorporate among such other matters, the following principles: the price must be of a level to bring forward sufficient natural gas supplies for the domestic market on a voluntary basis by the upstream producers; the price shall not be higher than the average of similar natural gas prices in major emerging countries that are significant producers of natural gas; lowest cost of gas supply based on three tier cost of supply framework; market related prices tied to International Benchmarks”.



Shell’s LNG China Gamble: Backing the Wrong Horse?

By Gerard Kreeft

Shell’s LNG Outlook 2024 forecasts that China will grow its LNG requirements more than 50% by 2040: rising to23Trillion Cubic FeetTcf (675Billion Cubic Metres (Bcm) in 2040 from 14Tcf(400Bcm) in 2023. Yet Shell’s optimism may be premature.

The Global LNG Outlook 2023-2027, published by the Institute for Energy Economic and Financial Analysis IEEFA, casts a more somber analysis for future LNG developments, in particular for China: rising domestic gas production, pipeline gas imports, and renewable power capacity could limit the potential for rapid LNG demand growth over the medium term.

China’s irony is that it is both the world’s largest coal user and the biggest producer of renewable energy. Within this irony it would seem to make sense that LNG could become a strong energy transition fuel. Yet this is not necessarily the case.

How will a floundering LNG market affect Shell’s dominant LNG position? Does Shell continue to have the agility to re-calibrate its strategy?

The Case of China

 Piped Gas Imports: China has a network of seven major gas pipelines, three of which are used for imported gas: Power of Siberia (Russia), Central Asia-China gas pipeline (Turkmenistan) and the Sino-Myanmar pipeline. The other four are supplied by regional China gas fields: Shaan Jing (Shaanxi), Sichuan-Shanghai, West-East (Tarim, Xinjiang) and Zhongxian-Wuhan (Sichuan). In 2022, China increased pipeline gas imports, primarily from Russia, to reduce exposure to skyrocketing LNG prices in the global market.

Piped gas accounted for a 42% share of China’s total gas imports in 2022, up from 35% in 2021, while the share of LNG imports fell to 58%. China has plans to expand pipeline import capacity with Russia by 2.5Tcf (70 Bcm) per year, as well as plans to increase connections with Turkmenistan by 30 bcm per year.

Domestic gas production growth: Domestic gas production in China grew from 5.75Tcf (161 Bcm) in 2018 to 7.5Tcf (209Bcm) in 2021. The continued growth of domestic natural gas production—typically the cheapest source of gas in China—may help restrain LNG demand growth.

Coal: China’s domestic coal output rose 9% to 4.5Billion metric tons in 2022. In January 2023, China lifted an unofficial ban on Australian coal imports, allowing three state-owned firms to import Australian thermal coal and one steel producer to import coking coal. IEEFA expects China coal imports to increase in 2023 as a result. According to media reports, China has approved 260MMT of new annual coal production capacity, bringing total capacity to 5.05Billion metric tons, a 10% increase from 2022. The higher coal capacity could also limit the increase in LNG demand.

Renewables: China has been the world’s largest and fastest-growing producer of renewable power for more than a decade: In 2020, China committed to have 1,200 GW of renewable capacity by 2030, but is on track to meet that goal five years early.

China could have as much as 1,000 GW of solar power alone by the end of 2026, analysts say, out of 11,000 GW needed globally to meet Paris Agreement targets by 2030. The country will build as much new solar capacity this year as the total installed capacity in the U.S., according to the Centre for Research on Energy and Clean Air.

China’s 2020 announcement that it would become carbon neutral by 2060 provided a powerful political signal favouring renewable investments.

Where did it go wrong?

A long-term LNG slow down for China is only a part of the puzzle. According to IEEFA the global demand for LNG is slowing:

Europe, although maintaining a high degree of importing LNG, is also increasing energy efficiency measures and wind and solar projects have become commonplace;

Japan and Korea, historically dependable LNG importers, are increasingly turning to nuclear, and renewables; and

South Asia, including India, Pakistan, and Bangladesh slashed purchases by 16% in 2022 and suppliers often defaulted on contracts to obtain higher prices elsewhere.

“After several years of weak supply growth, IEEFA anticipates that the global LNG market will see a tidal wave of new projects come online starting in mid-2025. The wave will likely crest in 2026, with the addition of 64Million metric tons of annual liquefaction capacity—the most in the history of the global LNG industry. The supply additions will boost global liquefaction capacity by roughly 13% in a single year. Liquefaction projects targeting in-service after 2026 may be entering a much smaller demand pool than bullish market forecasts anticipate. As new supply floods the market, today’s tight markets may give way to a supply glut, with lower-than-anticipated prices, smaller netbacks, tighter margins, and lower profits for LNG exporters.”

According to IEEFA’s forecast in 2023 only 5.8MMTPA (Million Tonnes Per Annum of liquefaction production will be developed, and in 2024 9.1 mtpa. Total LNG production capacity is currently 456 mtpa.

The turning point will be 2025.

IEEFA anticipates that roughly 17 MMTPA of liquefaction projects are likely to come online around the world in 2025—more than in 2023 and 2024 combined. New capacity additions will crest in 2026, with an estimated 64MMTPA of capacity coming online in a single year, and continue into 2027, when 37MMTPA of new capacity is expected to begin operating.

Africa’s LNG Future

Much of the new production will come from Qatar, USA and Australia. If 2026 and 2027 will see a sharp upturn in LNG liquefaction production how will this affect Mozambique’s two LNG projects which could potentially add 38.1MMTPA when fully functioning? Long term delays can only threaten project viability. And not proceeding sooner rather than later increases the chances of these projects being listed as stranded assets.

A more immediate threat is that of ENI’s Coral South project in offshore Mozambique which is already in operation. BP has contracted the entire output of Coral Sul for 20 years, having signed a free on board (FOB) contract with the project partners. In July 2022 it was reported that ENI was considering the possibility of deploying a second floating liquefied natural gas vessel in Mozambique. What does this mean for Rovuma and Mozambique LNG?

Shell’s Game Plan

The chief obsession of Wael Sewan, Shell CEO since January 2023, is to drive up the company share price. Yet the share price has barely moved—it was $65 at the start of April 2019 vs $64 February 2024. In his view Shell must mimic Chevron and ExxonMobil. While the Shell share price has remained virtually unchanged, Chevron has seen its share price in the same period increase 23% percent and ExxonMobil 25%

Shell’s total capex for the period 2023-2025 is between $22Billion-$25Billion per year, of which some 80 percent is earmarked for hydrocarbons. Not unlike Chevron and ExxonMobil.

 Sewan is attempting to change Shell’s narrative: that Shell is in the business of producing hydrocarbons, instead of also selling the illusion that its new energy policy matters. Europe’s oil majors, Including Shell, have seen their share prices flounder. Why? Because of their duality of messaging.  The European oil majors in the period April 2019-February 2024 (with the exception of  TOTALEnergies and Equinor), have seen their share prices underperforming badly:

BP  down from $44 to $36;

ENI down from $36 to $31;

TOTALEnergies was up from $56 to $65 ;

Equinor was up from $22 to $25.

The messaging of Chevron, ExxonMobil and now Shell is that they are oil companies, much in the tradition of John D. Rockefeller. This clarity of messaging is resonating with Chevron and ExxonMobil shareholders.

Shell’s Illusion

Prior to Sewan’s leadership, Shell had argued that its Upstream pillar ..”delivers the cash and returns needed to fund our shareholder distributions and the transformation of our company, by providing vital supplies of oil and natural gas.”

Yet Sewan is frank enough to demonstrate that this vision was an illusion. Depending on its upstream portfolio to lead the company to a bright new green future is perhaps central to Shell’s dilemma. Using funding from its upstream division to fund its green energy is in Sewan’s view a non-starter.

Yet Shell’s vision is also a testimony demonstrating how little the Green Alliance—Enel, Engie, Iberdrola, and Ørsted–is understood and viewed. What has set these companies apart is that they have created a huge competitive advantage which will be hard to challenge for newcomers. Moreover, they have moved well beyond simply dabbling in green energy. These companies have become specialists and now moving on to the next level: creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems. Essentially borrowing a chapter from Uber, which does not own taxis or Booking, which does not own hotels.  Some members of the Green Alliance have established  new goals, such as CO2 neutrality by 2040 instead of 2050 to which Shell is pledged.

Yet while the Green Alliance has established its vision, green companies are still under-performing. Renewables have since 2021 taken a sharp nose dive–dropping some 50% based on the S&P Global Clean Energy Index (from 1994 in February 2021 to 1000 in December 2023). Yet what goes down will ultimately come up. Will green energy find a narrative to bolster their stock price and the waiting investor?

Shell’s Options

No doubt Shell will continue to pay out its annual dividend, which shareholders have come to expect. Less certain is its share price which continues to flounder.

Very troubling is the future of the LNG market. China’s rising domestic gas production, pipeline gas imports, and renewable power capacity are already limiting the potential for rapid LNG demand growth over the medium term.

Also troubling is Japan’s falling demand for LNG, marking an important shift in global markets. IEEFA has reported that… “ Japanese utilities — once considered purely consumers of LNG — are increasingly focused on marketing and reselling the fuel abroad, putting them in more direct competition with global suppliers.”

While it is true that Shell has a significant deepwater upstream portfolio, Shell’s true strength has been its global LNG portfolio encompassing the entire value chain. No doubt Shell will have to address the falling LNG demand in the weeks and months ahead.

Then there is the issue of Shell’s green assets, which under Shell’s present management have been placed on a back burner. What will Shell do with its green assets? Do not be surprised if Shell’s green assets are spun-off in a new venture. Shell’s REFHYNE Project, the Rhineland Refinery in Germany, could well become the precedent that 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 the REFHYNE Project be duplicated many times over to ensure that green technology becomes a key ingredient in the energy transition?

Pay attention to Shell’s Pernis refinery in the Netherlands. One of the largest in Europe, Pernis refinery has a 400,000 b/d capacity and a complexity enabling the processing of many different crude types. The site is already deeply integrated with chemicals production and is being transformed into an integrated energy and chemicals park that will deliver low-carbon products.

 Final Comments

Wael Sewan, CEO of Shell, has seen as his goal the re-positioning Shell as a major hydrocarbon producer. A peer of Chevron and ExxonMobil. Yet in terms of stock market price the Shell share has continued to flounder while Chevron and ExxonMobil have seen their stock market values rise.

A key reason can be attributed to the European majors having a duality of message: wanting to be both an oil producer and seen as representing new energy. The net result: leaving the European oil stocks in the doldrums.

Sewan’s goal has been a singular drive to leaving the image of this duality behind him to become a leading hydrocarbon company. Then to see the global LNG market floundering—viewed as Shell’s growth engine and  intermittent fuel for the energy transition—is a bitter pill to swallow.

Is there a Plan B or C? If so, please contact Shell.

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




Half of Shell’s total flared gas in 2023 from assets in SPDC, SNEPCO

By Lukman Abolade, Senior Correspondent

In 2023, half of UK major, Shell’s combined routine and non-routine gas flaring at its integrated gas and upstream facilities originated from assets managed by SPDC and Shell Nigeria Exploration and Production Company (SNEPCo).

This was contained in its recently released Energy Transition Strategy report, stating that the total routine flaring from its upstream oil and gas assets remained ‘relatively stable in 2023’ compared with 2022, at 0.1Million tonnes, having reduced from 1.1Million tonnes in 2016.

Shell is letting go of some of these assets. On January 16, 2024, the company reached an agreement to sell SPDC to a consortium of five companies, subject to approvals by the Federal Government of Nigeria and other conditions. It will, however, keep SNEPCO, the deepwater subsidiary.

Shell’s Energy Transition Strategy report said its methane emissions include those from unintentional leaks, venting and incomplete combustion, for example in flares and turbines.

It added that its target to maintain methane emissions intensity below 0.2% continued to be met in 2023 as overall methane emissions intensity was at 0.05% for facilities with marketed gas and 0.001% for facilities without marketed gas.

The Company said it also recorded total methane emissions of 41 thousand tonnes compared with 40 thousand tonnes in 2022.

Shell added that the increase was due to venting (maintenance of Prelude asset and operational issues in assets operated by Sarawak Shell Berhad) and an increase in reported emissions from integrated gas assets in Canada resulting from the adoption of enhanced source level measurements in line with OGMP reporting requirements.

On direct GHG emissions (Scope 1, operational control boundary) Shell reduced its emission from 51Million tonnes of carbon dioxide equivalent (CO2e) in 2022 to 50Million tonnes CO2e in 2023 but this was largely due to divestments made in 2022.

Some of the assets include, Deer Park and Mobile refinery, Tunisia Miskar concession, offshore Baram Delta Operations (BDO) PSC and Block SK307 PSC in the Philippines) and handover of operations in OML 11 in Nigeria in 2022; unplanned downtime (e.g. Deer Park Chemicals); reduced flaring from assets including SNEPCo and reduction of activities and purchase of renewable electricity.

These decreases were partly offset by Shell Polymers Monaca having more units online in 2023 and higher emissions from its Pearl gas-to-liquids plant and Prelude floating liquefied natural gas facility with increased production.

The Oil major also announced its strategic shift in power business towards select markets and segments by selling more power to commercial customers, including renewable power, and less to retail customers.

As a result, Shell said it expects lower growth in sales of power overall. and have updated its net carbon intensity target to reflect that change, with a 15-20% reduction by 2030, compared with previous target in 2016, of 20% reduction commitment.



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