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TOTAL Reduces Scope of South African Gas Project, Excludes ‘Marine Protected Areas’

French major TOTALEnergies has voluntarily reduced the scope of the license application for natural gas production offshore South Africa, the company says in a response to environmental activist groups.

TOTAL says it has done so “by excluding the area currently classified by the South African authorities as a protected marine area”.

The company did not disclose how much of the natural gas volumes will be impacted by the curb, or what shape the scope reduction will take.

Application for production licence for Block 11B/12B in the deepwater Outeniqua Basin, 175km offshore off the coast of the Western Cape, was made on September 5, 2022, three years after TOTAL discovered massive deposits of gas and condensate in the block with the Brulpadda-1 well, drilled in 2019.

In October 2022, Netherlands based The Bloom association for the protection of the oceans and the South African non-governmental organization (NGO), The Green Connection, launched an international petition against the development of the Brulpadda-Liuperd project, which is primarily intended to supply 200Million standard cubic feet per day (200MMscf/d) to a Gas to Liquids (GTL) Plant operated by the state hydrocarbon firm PetroSA, in Mossel Bay in the Western Cape.

“I can confirm that TOTALEnergies EP South Africa and its partners applied for a production license on September 5, 2022 following which an environmental and societal impact assessment was initiated, in accordance with South African regulations”, Patrick Pouyanne, the CEO wrote in a letter responding to Bloom and The Green Connection. “This assessment will provide a detailed description of the project’s economic, social and environmental impacts, the measures planned to preserve the environment, and the related social and economic benefits. A survey has been launched to map the marine species, including, potentially, marine mammals, to model the potential impact of production activities (especially noise) and to define any measures to be taken”, Pouyanne wrote.

“I would also like to stress that TOTALEnergies E&P South Africa has already voluntarily reduced the scope of the license application by excluding the area currently classified by the South African authorities as a protected marine area”, Pouyanne disclosed.

“Under South African regulations, an information and consultation process on the environmental and societal impact assessment is mandatory. The first public meeting will be held in late 2022, and all stakeholders will be invited to participate. Their observations, expectations and concerns will be considered, including through socio-economic development initiatives.

“Concerning the project’s contribution to reducing greenhouse gas emissions, I would emphasize that this project is expected to supply gas to the South African domestic market. South Africa’s economy is still predominantly based on coal, which accounts for 80% of its current electricity generation. Access to energy, and in particular meeting the growing demand for electricity, is a major concern in South Africa, where load shedding and power cuts have been an almost daily occurrence for nearly 15 years and where air pollution from fine particles linked to coal burning is frequent. The use of gas to replace coal combustion for electricity generation halves CO2 emissions and drastically reduces air pollution. The atmosphere will benefit from the avoided emissions made possible by this gas development project”.

Pouyanne’s letter noted that that TOTAL is positioning itself In South Africa “to contribute to the evolution of the country’s energy mix as part of a just transition that will require a move away from coal, a sharp increase in renewable energies, and the use of gas as a transition fuel”.


Nigerian Gas Flare Programme: What if the Operator Stops Producing, Or the Field Just Shuts… ?

Companies who submitted proposals/bids in the 2020 iteration of the Nigerian Gas Flare Commercialization bid process have a good chance of winning in the ongoing round, the Nigerian Upstream Petroleum Regulatory Commission NUPRC has explained.

“If you submitted a proposal/bid in the 2020 process, please go to the NGFCP portal and do the Status Validation process”, the regulator told a group of American companies at an online seminar.

The Nigerian Gas Flare Commerialisation Programme 2022 (NGFCP 2022) is derived from a legal framework on flare gas reduction -The Flare Gas Reduction (Prevention of Waste and Pollution) Regulation- signed by President Muhammadu Buhari in 2018, which led to government takeover of gas flare sites on producing oil/gas fields with lack of/non implementation of gas flares out project.  That regulation is now part of the Petroleum Industry Act on 2021.

Submission due date for the Statement of Qualification (SOQ) is November 28, 2022. Interested participants are expected to have registered on the portal and made SOQ submissions for eligibility to participate in the bid process by that date.

The NGFCP is expected to be completed in Q1 2023. The Programme design is for small scale modular flare capture equipment that are readily available and easily deployed, hence the Commission.

The Department of Petroleum Resources, the forerunner of the NUPRC, had commenced a bid process of flare gas sites in 2020. But the programme stalled. The NGFCP 2022 is rolling that previous process into this one. Parties who previously participated in the Flare Gas Commercialization Programme stand prequalified as Existing Applicants, subject to provisions of Section 3.6 of the request for qualification (RFQ) for the NGFCP 2022. “Existing Applicants shall remain prequalified subject to validation of updated documents. If the Existing Applicant is a consortium, any change in the composition or status of the consortium invalidates its prequalification status. Kindly note that Existing Applicants are exempt from payment of associated fees with respect to SOQ submission.” Excerpts from the RFQ.

“The flare forecast data that will be provided are underpinned by the Field Development Plan and Work Programme of the producers” the NUPRC responded repeatedly. “Technical due diligence on the sites on offer from historical production profile and the current field development strategy provides a reasonable basis to uphold the credibility of forecast”.

At the webinar attended by over 75 American companies, and jointly organized by the NUPRC and the United States Commercial Service in Nigeria, the regulator explained that 47 gas flare sites were on offer with a total potential output of about 250Milion standard cubic feet of gas per day guaranteed for five years. 14 of these sites can deliver hbetween 0.5 to 2Million standard cubic feet per day (MMscf/d); 19 sites can do 2.1 to 5MMscf/d; nine (9) can produce between 5.1 and 10MMscf/d and five flare sites can produce over 10MMscf/d.

25 (or 53%) of the flare sites are located on land; eight (8) in swamp; 13 in shallow water and one in deepwater.

The NGFCP 2022 seeks small/mid-scale modular technologies and its unique features includes ease of deployment, scalability, mobility, and off-theshelf availability including: • Mini/mid-scale LNG, • Modular LPG facility, • modular methanol/ammonia plant, • Gas-to-liquids facility, • Virtual pipeline solutions. The proposed solution(s) must cater for the full stream of the flare gas composition

The NUPRC fielded a range of questions from the participants, including whether there was a comprehensive gas analysis of the flare gas; if operators in Nigeria need to recover LNG from flare gas at stranded wells or wells that aren’t located near a processing plant and the minimum technical and financial requirements to participate in the bid.

“Gas composition is part of the flare dataset which will be made available in the data room during the Request for Proposal (RFP) phase”, NUPRC  staff explained. “Our typical flare gas composition shows methane content of 70-90% which makes the sites amenable to mini-LNG deployments. Many of the flare sites are not necessarily connected to pipeline infrastructure”, they said, and added that basic (financial and technical) requirements are provided in the Request for Qualification (RFQ) and detailed information will be enumerated in the RFP when issued.

The NUPRC says there are no base formula for license fees rather there are fixed fees which are categorized based on range of volumes.

Pricing is always a key issue in gas offtake. So, it wasn’t surprising that questions were raised about whether any additional flare gas produced by the field above the licensed quantity may be priced at Henry Hub. To which the NUPRC responded: “If available, additional flare gas offtake by Flare Gas Buyer (FGB) over and above the contracted flare volume will be priced at the bid price offered by the FGB as contained in the Gas Sales Agreement (GSA)”.

The NUPRC ventured that it would “implement a streamlined regulatory licensing and permitting processes to facilitate project development”. It promised that Flare is made available under the NGFCP to a Flare Gas Buyer on an “As is Where is” basis. “The Commission shall exercise best endeavor to ensure that the forecasted quantity is made available by the producers”.

Any carbon credit accruable, the NUPRC explained, will be managed in line with the established protocol on carbon credit.

The NUPRC also told the participants that “qualified Applicants who have demonstrated sufficient commitment to progress with the bid process by participating in the RFP phase will be introduced to the producers.

One recurring issue is   What if the operator stops producing for whatever reason, or the production decreases significantly?

This is the point that is often made by oilfield producers, some of who argue that (1) reservoir depletion is not always straight forward (2) gas flares do not happen in projects where there are robust economics of offtake on the ground, in which case the producer himself would have snapped up the opportunity.

“The flare forecast data that will be provided are underpinned by the Field Development Plan and Work Programme of the producers” the NUPRC responded repeatedly. “Technical due diligence on the sites on offer from historical production profile and the current field development strategy provides a reasonable basis to uphold the credibility of forecast”.

Considering that security issues in the Niger Delta, Nigeria’s hydrocarbon producing region, has dominated the headlines of recent, it was a little surprising that questions around t it did not vigorously come up, but they did come up. “Our Nigerian partners in other projects in the Deltas have refused to move forward because of this”, one participant pointed out. The NUPRC’s explanation was that the government was “committed to tackling the issue and as such major projects in oil and gas are currently in execution within the region”.

So, “are gas processing equipment needed for this project”?, someone wanted to know. The NUPRC was ready with an answer: “Considering that flare gas originates from natural gas produced in association with crude oil, it is generally wet gas and require some treatment/processing to handle heavy ends. There is however little or no sulfur and minimum CO2 content in the enlisted flare gas being offered and as such gas desulfurization and CO2 removal will not be required”.


Mozambique’s first LNG cargo departs for Europe

The first shipment of liquefied natural gas (LNG) produced from deepwater offshore Mozambique, has departed from Coral Sul Floating Liquefied Natural Gas (FLNG) facility.

The Italian explorer ENI, as Delegated Operator of the Coral South project on the Coral South Field in Area 4 in the deepwater Rovuma basin, describes the event “as a new and significant step forward in ENI’s strategy to leverage gas as a source that can contribute in a significant way to Europe’s energy security, also through the increasing diversification of supplies, while also supporting a just and sustainable transition”.

Area 4 is operated by Mozambique Rovuma Venture S.p.A. (MRV), an incorporated joint venture owned by ENI, ExxonMobil and CNPC, which holds a 70% interest in the Area 4 exploration and production concession contract. In addition to MRV, the other shareholders in Area 4 are Galp, KOGAS and ENH, each with a 10% participation interest. ENI is the Delegated Operator for the Coral South project and all Upstream activities in Area 4.

The first commercial discoveries of gas in Area 4 were made by ENI in 2021, months after Anadarko “opened” the Rovuma basin with discoveries in Area 1. The announced shipment indicates it has taken 12 years for the discoveries in Rovuma to reach the market.

“Coral South is a landmark project for the industry and firmly places Mozambique onto the global LNG stage”, ENI says. “The project, sanctioned in 2017, comes on stream after just 5 years, in line with the initial budget and schedule, despite the disruptions caused by the COVID pandemic”, ENI says.


Nigerian Gas Investment-Seven Thematic Areas

By Ed Ubong

Nigeria declared A Decade of Gas on March 29, 2021. We like to think of that declaration in the following areas.

Gas For Power-The most important area is that gas must provide power and electricity for Nigeria. The Gas for homes-we are keen to seeing that Nigeria’s gas is used for cooking.

Gas for industries-The third thematic area is that gas must drive Nigeria’s industrialization.

Gas for Exports– This is very important from a foreign exchange perspective. Nigeria must play in the regional and international markets with respect to gas.

These four areas that are the end products of gas, require three sets of enablers.

The first one, we call it Infrastructure for gas. We must build the required pipelines that would ensure that gas can be utilized in country. We must also support virtual operators that can move gas without pipelines to where it is needed while we are building those pipelines.

We also talk about the OB-OB-OB pipeline, the link between the East and the West, a project that has been going on for maybe over a decade. Significant gas resources sit in the Delta, significant demand sits in the West. As a matter of urgency, we must connect this two.

The second enabler is Regulatory framework, pricing, and security, having to do with the infrastructure and the business climate that supports gas investment. All these must be in place for investors to be able to support us as we move on to the decade of gas initiative.

The third enabler is the human capacity- we must build for the gas sector; train new professionals and retool all professionals who are able to do the switch from oil to gas as we sort of continue the transition.

So, what has happened since Nigeria declared a decade of gas on March 29, 2021?

About Gas to power, the ministry of power has started implementation of the Siemens project. Pricing for electricity has increased (Tariffs have gone up). There are reports by the country’s power distribution companies, called DISCOs, that Nigerians have been paying for electricity, meaning that the receivables have increased. The area we have not had a positive report is that of the payables which is what needs to flow from the DISCOs who collect it to the generating companies (GENCOs) who generate it. That has not increased. What has then happened? We are still between 5,000MW, or slightly above that. But the GENCOs insist that they have installed capacity that is over 12,000MW. There’s a lot of work going on, and lots more to do.

We need a healthy gas-based industry GBI, featuring a good number of companies who compress, transport, and deliver gas at a competitive value to the industrial patch. We are not yet there in that space.

Gas for Home Cooking. The Nigeria Liquefied Natural Gas (NLNG) Limited has made a commitment to increase the LPG it supplies to the domestic market from about 350 to 450,000 tons. But the reality is that cooking gas prices have gone up. The players in the LPG say that there still exists multiple taxation across the LPG value chain that makes it difficult for this pricing to come down. This is the one sector of the gas value chain that is deregulated. So ideally, this is one sector that should work because everybody is talking about regulation but this sector is fully deregulated, and we still see challenges. Foreign exchange supply is a big issue. When you are in the gas value chain, you pay multiple VAT across all the value chains. These are still issues that we need to address and I think the conversations are still going on.

Then we talk about Gas for industries. We’ve seen significant MoUs being signed and led by the Ministry of Petroleum and NNPC on Ammonia production plants, different short-term projects that will need to be built to drive the industrial sector. We’ve also looked around, and no new industrial cluster has emerged. As Shell I’m trying to build an industrial cluster in Bayelsa, I’m being slightly held up by the EIA, but this is a place where you already have the largest gas processing facility in Africa. Getting an EIA should be a tick in the box because that has been done multiple times. What then has the industry been saying over the past three or four months? “We do not have enough gas”.

The message is that we have cranked up significant activity. Because the President has made a declaration, investors have gotten excited, but we need to begin to look at how we close the fundamentals. What has changed in those enablers I spoke about and their significant advocacy work from the Ministry of petroleum resources? The Petroleum Industry Act (PIA) was passed. It is the single biggest achievement of this government from the perspective of the Nigerian Gas Association. And why is this important? Because investors always ask us, “What is the framework that would allow us to work in Nigeria?” And we used to respond: “A Petroleum Industry Bill is being debated at the National Assembly”. But since August 2021, that narrative has changed. We say, “This is a copy of the Petroleum Industry Act. It is your one stop regulation for your investment.”  This has taken a significant amount of uncertainty out of that space. We are now in the process where the various parts of that act need to be implemented.

Infrastructure for gas. We have excitedly launched the construction of the AKK (Ajaokuta-Kaduna-Kano) pipeline. Real success for the industry will be when the first leg of the AKK Ajaokuta to Abuja is commissioned. Gas must get to Abuja before 2023. We also talk about the OB-OB-OB pipeline, the link between the East and the West, a project that has been going on for maybe over a decade. Significant gas resources sit in the Delta, significant demand sits in the West. As a matter of urgency, we must connect this two. This project has sat as 98% for a long time. The industry is asking the various parastatals what we need to do to enable the 2% to close so that gas can flow from where there is abundance to where it is needed, connecting supply and demand. The third bit is around the natural gas infrastructure. As we try to build pipelines, we must ensure that the investors who put in 3 or 4Million dollars are the lowest investors on the scale, but they have significant impact because they can compress gas, drop it and transport it to areas where there are no pipelines. We need to enable them and that enabler from what we hear from them, is that they need a pricing. We need a healthy gas-based industry GBI, featuring a good number of companies who compress, transport, and deliver gas at a competitive value to the industrial patch. We are not yet there in that space.

The third bit, the human capacity development which is the final enabler. At the NGA, we have trained about 1000 people and we have virtual online seminars. But it is nowhere near enough and since then I’ve been looking at signing an MOU with OCTAN, the NCD MB and also with the PTF on how we can accelerate those trainings to a wider range of people, and how we can retool some of the investors that are already in. In this limited timeframe we still need to do more.

Abridged version of a paper delivered by Ed Ubong, President of the Nigerian Gas Association and Managing Director of Shell Nigeria Gas (SNG), the downstream gas distribution subsidiary of the UK major. Ubong spoke at the Nigerian International Energy Summit, in Abuja.


Gas Exporters Meet in Cairo

The 24th Ministerial Meeting of the Gas Exporting Countries Forum GECF is being held on the 25th of October 2022, in Cairo, the Arab Republic of Egypt.

Tarek El Molla, the host country’s Minister of Petroleum and Mineral Resources, will chair the Meeting in his capacity as President of the GECF Ministerial Meeting for 2022.

The Ministerial Meeting is the supreme governing body of the Forum and meets once a year in accordance with the GECF Statute.

The GECF was established in 2001. In 2008, it was transformed into an international governmental organisation headquartered in Doha, the State of Qatar.

“Energy security and affordability have moved to the top of the priority list of policymakers, with sustainability taking a backseat”

The GECF comprises of 19 member countries, with Algeria, Bolivia, Egypt, Equatorial Guinea, Iran, Libya, Nigeria, Qatar, Russia, Trinidad and Tobago, and Venezuela as Members, and Angola, Azerbaijan, Iraq, Malaysia, Mozambique, Norway, Peru, and the UAE as Observers.

Together, they represent 72% of the global proven natural gas reserves, 43% of marketed production, 55% of exports by pipeline, and 50% of LNG exports.

Mr. El Molla has promised, as host and chair, “to provide a constructive dialogue that will contribute to fulfilling the objectives of the Forum and all its member countries while focusing on the future role of natural gas in the energy transition process as a reliable and affordable source of energy.

“Energy security and affordability have moved to the top of the priority list of policymakers, with sustainability taking a backseat”, observes Mohamed Hamel, Secretary General of the Gas Exporting Countries Forum. “Another energy crisis, that faced daily by three billion people lacking access to modern energy services, continues unabated and has even worsened. Furthermore, the IPCC Sixth Assessment Working Groups’ reports have once again underlined the urgency of mitigation and adaptation to climate change”.

Mr. Hamel, who is Algerian, notes that Natural gas markets are going through a rapid and substantial restructuring in terms of physical flows, investment, and contractual arrangements. From being the market of last resort, Europe has become the preferred destination for LNG cargoes. In the event, “some developing countries are no longer able to satisfy their gas import needs, a situation that creates economic havoc, lowers the standard of living of their people, and gives rise to political and social instability.

“Against this backdrop, the 24th GECF Ministerial Meeting is a great opportunity to exchange views, and explore ways and means to strengthen the Forum and expand its membership. It is also an opportunity to reemphasise the crucial role of natural gas in sustainable development, and as an enabler of the energy transition – a transition that is smooth, cost-effective, just, and leaves no one behind”, the secretary general declares.

“It is all the more a great opportunity that the 24th GECF Ministerial Meeting is held in Cairo, the Arab Republic of Egypt, a very important country for natural gas markets, with a thriving, dynamic and innovative industry.  It is also a wonderful coincidence that Egypt is set to host COP 27 in Sharm El Sheikh in 2022”.

Activists Finally Move Against TOTAL’s Brulpadda Gas Project

Netherlands based The Bloom association for the protection of the oceans and the South African non-governmental organization (NGO), The Green Connection, have launched an international petition against the development of a major gas project by TOTALEnergies off South Africa.

The target is the Brulpadda-Liuperd project, which is primarily intended to supply 200Million standard cubic feet per day (200MMscf/d) to a Gas to Liquids (GTL) Plant operated by the state hydrocarbon firm PetroSA, in Mossel Bay in the Western Cape.

The gas and condensate reserves are located in 1,800 metres of water in Block 11B/12B in the deepwater Outeniqua Basin, 175km offshore off the coast of the Western Cape. It is just the right place and context for South Africa’s passionate, well-funded, activism against fossil fuels.

“They know that these are complicated waters with a risk of oil spills,” warns Swann Bommier, The Bloom’s Advocacy and Campaigns Officer. “It’s a spectacular place from a biodiversity point of view, which is on the migration route of whales and sperm whales. It is also a living environment for dolphins, leatherback turtles and seals”, observes Claire Nouvian, president of The Bloom.

TOTALEnergies has been luckier than most operators in South African offshore. It had felt so surreal to observers that the French major had managed to drill to two wells, almost back-to-back, in deepwater South Africa, in contrast to the successful legal challenges against other offshore Energy projects in the country.

The move by The Bloom and The Green Connection comes at a time when TOTAL, is preparing to drill appraisals of the Brulpadda and the Liuperd accumulations, which were discovered in 2019 and 2020.

TOTAL’s application for production licence for Block 11B/12B, submitted in early September 2022, includes a development plan for supply of as much as 700MMscf/d of piped gas to customers located as far as Port Elizabeth in the Eastern Cape. If approved, it will represent some substantial flow of natural gas into the South African economy, almost doubling the supply of Mozambican gas by Sasol to some South African industrial entities.

But The Bloom and The Green Connection argue that South African authorities should only decide on the Brulpadda/Liuperd production license at the end of a public inquiry scheduled for January 20, 2023.

TOTAL has always insisted that its gas project will help displace the heavy use of coal in the South African economy. But the protesters dismiss this claim out of hand.  “Gas is not a transitional energy, we must stop the greenwashing,” they say.


Nigeria’s Gas Export Put on Hold

Nigeria’s 3.5Billion cubic feet per day (capacity) Liquefied Natural Gas (LNG) export, has been halted for now.

Nigeria Liquified Natural Gas (NLNG) Ltd called up a force majeure as a result of the widespread flooding that has disrupted production of gas in the Niger Delta region.

The companies that supply natural gas to NLNG Ltd had declared force majeure, forcing it to make the declaration as well, according to Andy Odeh, the company’s General Manager External Relations.

A force majeure clause in a contract releases a party from fulfilling their contractual obligations when circumstances beyond their control impede them.

The year has been fraught with challenges from the supply side for NLNG Ltd, whose operations make Nigeria the sixth largest LNG exporter in the world.

The company had recently lamented a declining feedstock due to rising crude oil theft which crimp output of gas that is produced in the process of oil extraction. For this reason, LNG exports from Nigeria had slumped by close to 40% year-on-year, as of September 2022.

But the flooding, which has affected over 20 states in the country, is the high mark.“The notice by the gas suppliers was a result of high floodwater levels in their operational areas, leading to a shut-in of gas production, which has caused significant disruption of gas supply to NLNG,” Mr Odeh said.



Mozambique May Be Lucky with Gas Export from its Deepwater Terrain

Twelve and half years after discovery, some of the gas from Mozambique’s deepwater Rovuma basin may finally make it to the market by November 2022.

Max Tonela, the country’s minister of economy and finance, says he expects the first tanker of liquefied natural gas (LNG) to be exported from the Rovuma basin, off Cabo Delgado province, by the end of October 2022.

“We hope that before the end of this month of October the first export of liquefied natural gas produced by the country will take place,” the minister said in an interview with the Portuguese news agency, Lusa.

President Fillipe Nyusi’s government expects about $35Million to be earned from Coral South FLNG Export in 2022.

The sums were calculated based on a four-month cargo export for 2022. Now the window has been reduced to two months.

It has taken five years to get here, since Final Investment Decision (FID) on the 3.4Million Metric Tonne (MMTPA) project was taken in 2017. And it would be the first earnings from production of the deepwater gas reserves that were initially discovered in February 2010.

Mozambique has been earning income from produced natural gas since 2004, when Sasol started pumping gas from onshore Pande and Temane fields to South Africa.

But the deepwater finds from two acreages, totaling at least 100Trillion cubic feet of recoverable reserves, promise much more.

The plans were:

  • Coral South FLNG (3.4MMTPA) FID June 2017, First Gas June 2022
  • Onshore Mozambique LNG (12.9MMTPA) FID taken on June 8, 2019, expected to be Fully Commissioned 2024
  • Rovuma LNG (15.2 MMTPA), FID targeted 3Q 2019, Fully Commissioned 2025
  • Unitised Trains (15.2 MMTPA) FID targeted 2024, Fully Commissioned 2029
  • Prosperidade LNG (12.9 or 15.2 MMTPA) FID targeted 2024, Fully Commissioned 2029
  • Domgas Projects Expected – Gas to Liquids (’GTL), Fertiliser, Independent Power Projects (IPPs), Small-Scale LNG (SSLNG), LNG Bunkering, Methanol to Olefins (MTO)


N-Gas, Transporter of the West African Gas, in Profit Slump

NNPC subsidiary N-Gas, reported a 12% dip in profit to $8.476Million in 2021 from $9.532Million in 2020.

This was a large reversal of the leap in profit from $6.217Million in 2019 to $9.532Million in 2020.

Net cash generated from operations fell from $19Million in 2020 to $6.4Million in 2021.

N-Gas is jointly owned with NNPC by Chevron and Shell and its work is to purchase and deliver Nigerian gas to customers in Benin Republic (Communaute Electrique du Benin (CEB) – Cotonou); Togo (Compagnie Energie Electrique du Togo (CEET) Lome) and Ghana (Volta River Authority (VRA) -Takoradi), under their respective gas sales agreements through the West African Gas Pipeline (WAGP).

This means that it pays upstream suppliers like NDWestern and NPDC for taking their gas and pays the pipeline owners for ferrying the gas through the line.

N-Gas reported a 13% drop in revenue on gas delivery charges on sale of gas to VRA, CEB Cotonou and CEET Lome, from $6.5Million in 2020 to $5.6Million in 2021.

Analysis of the revenue from the delivery charges on sale of gas to these entities over the last three years is as follows

                                                                                                            2021           2020                      2019

                                                                                                            US$’000      US$’000                     US$’000

VRA                                                                                                         3,742             4,639                    4,686

CEB Cotonou                                                                                        1,179             1,222                    492

CEB Lome                                                                                                  644            608                       631

                                                                                                             5,565            6,469                    5,809


N-Gas Limited was incorporated in 2004 as a private limited liability Company. The Company is jointly owned by the Nigerian National Petroleum Corporation (62.35%), Chevron N-Gas Limited (20.00%) and Shell Overseas Holdings Limited (17.65%). The Company’s main activity is to buy and sell natural gas shipped through the Escravos-Lagos Pipeline System (ELPS – NGC) and the West African Gas Pipeline (WAGP) to its customers in the countries of Ghana, Togo and Benin.

N-Gas has executed agreements with upstream producers in Nigeria (Chevron Nigeria Limited Joint Venture (CNL-JV) and Nigerian Petroleum Development Company/ND Western Joint Venture (NPDC/NDW-JV)) and with gas transportation companies (Nigerian Gas Company Limited (NGC) and West African Petroleum Company (WAPCo) ) for the supply and transportation of gas to its customers. The agreement with NPDC/NDW-JV was previously with Shell, ie SPDC-JV but subsequently novated to NPDC/NDW-JV following the divestment of Shell Petroleum Development Company Joint Venture (SPDC-JV) from the asset that is the source of its upstream gas supplies to N-Gas. The Novation agreement which transferred the rights and obligations of the NNPC/SPDC JV parties to NPDC/NDW JV parties in the NNPC/SPDC GPAs, was finally concluded in December 2014 following the execution of the novated Trust Accounts and Security Deeds (TASDs).




ENI Gets two Algerian Gas Fields to the Market, for Europe

Italian major ENI has taken onstream, two gas fields in Algeria that will supply the European market.

It has been a fast-track development.

The assets are “related to the Berkine South contract”, which was signed (with the state hydrocarbon company Sonatrach), in April 2022.

The entire Berkine South acreage itself currently has a production capacity of 35Million standard cubic feet per day of gas (MMscf/d), and approximately 4,000 barrels per day of associated liquids.

With new fields coming on stream and ramped up in the following months, ENI expects the Berkine South gas output to be tripled to 70MMscf/d by the end of 2022.

These molecules are meant for export into Europe.

“The production of the Berkine South, which is the first contract to be signed under the new Algerian hydrocarbon law 19-13, is operated by ENI and Sonatrach”, ENI explains in a statement.

ENI has seen itself, since the Russian/Ukraine conflict started, as the champion of alternative sources of natural gas for Europe. Most of its developments for this purpose, in Africa, are relatively small, but they add up.

ENI has also taken more assets where other European companies are unwilling. In September 2022, the company announced that it had reached an agreement on the acquisition of BP’s operations in Algeria, including “In Amenas” and “In Salah”, “the most important gas production fields operated by international companies in the country”, ENI claims. “Following this operation and the development programmes in the Berkine basin, ENI’s production in Algeria is expected to reach over 120,000 barrels of oil equivalent per day in 2023”.




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