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FPSO Moves to Site for Senegal/Mauritania LNG Project

Section: Gas Monetization · January 23, 2023 · No comments |

Technip Energies has announced the sail away of the Greater Tortue Ahmeyim (GTA) Floating Production Storage and Offloading (FPSO) from China to Senegal and Mauritania.

The FPSO will serve GTA Phase 1 site on the maritime border of Mauritania and Senegal.

The project is based on the development of two offshore gas fields namely Tortue and Ahmeyim. GTA Phase will produce 2.5Million tonnes per annum (2.5MMTPA) of LNG in its first phase of development for which the final investment decision (FID) was taken in December 2018.

The floating facility measures 270 metres in length, 54 metres in width and 31.5 metres in depth. It is as large as two football fields and is of the same height as a 10-floor building. The FPSO includes eight processing and production modules and can accommodate 140 people on board. The key function of the FPSO is to remove water, condensate and reduce impurities in the gas stream before exporting processed gas to the FLNG facility in Mauritania and Senegal.

Technip Energies claims that it has involved “local companies to execute scopes of the project”., as part of the project local content. “Technip Energies will also integrate local personnel into the subsequent phases of the project. Local engineers and technicians, trained throughout the project development phases, will be involved in the various activities related to mooring, tie-in, commissioning and start-up, holding various positions: pre-commissioning, commissioning, Quality, HSE and logistics”.

‘Utorogu LPG Project with Southfield Still on Course’, NCDMB Pronounces

Section: Gas Monetization · January 13, 2023 · No comments |

The Nigerian Content Development & Monitoring Board (NCDMB) has dismissed any misgivings about “the quality” of the proposed agreement among would-be partners in the planned production of 123,000 metric tonnes per annum of Liquefied Petroleum Gas (LPG) from the Utorogu gas and condensate field, onshore western Niger Delta. The board also throws its weight behind the “credibility” of the project sponsor

The (NCDMB) had recently reported it had secured the approval of its Governing Council for a partnership to produce 123,000 metric tonnes per annum of LPG, which is about 10 percent of the country’s current consumption, from the Utorogu Gas Plant. That would mean a partnership between that company on one hand and NPDC and ND-Western, joint operators of the Oil Mining Lease (OML) 34, where the Utorogu field is located.

But the feelers from the industry is that Southfield Petroleum, this same company proposing the Utorogu project had fallen out with Seplat, over a similar proposition and the Seplat management was so angered by the course of events it took the company to court for redress after the company had itself taken Seplat to court, allegedly for breach of contract.

What is the issue? “The deal broke down because they (Southfield) didn’t even show up to build any facility, let alone receive the gas”, Seplat insiders say.

Now that Southfield is in discussion with ND-Western over a similar project, Africa Oil+Gas Report asked the NCDMB if the board was “sure of them” (Southfield)?

Here is the response from Simbi Wabote, NCDMB’s Executive Secretary:

“Southfield Petroleum is a company we are partnering with in order to produce LPG within the Utorogu field. The company is currently in discussion with the a joint venture partners operating Utorogu gas plant, who are ND-Western and NPDC. Before the project will go ahead, they will be sure that there is gas availability and then that commitment has to be on the table. Where we are at now is the Front-End Engineering Design (FEED) for the project itself; but before we will beat our chest that we have secured that project, we’d ensure that all the i’s are dotted and the t’s are crossed.

“It is within the project development funnel and one thing we must understand about investments in general today is that, if you go and speak to Elon Musk and ask him about how many businesses did he invest in and he didn’t succeed, he will probably give you a catalog of what he tried and he didn’t succeed at, but with the ones he succeeded at, he is where he is today. Talk to Bill Gates, talk to Zuckerberg, nobody can tell you that every Investment they’ve been into was a success and that’s the challenge we have in Africa. The averse appetite for risk-taking is even in us as a people. You know about the sense of adventure of Caucasians, you have to think and ask yourself: How many Africans will want to go and climb Kilimanjaro? How many Africans will want to enter the sea and swim with a shark or with a Whale? These are risks that people take in other to understand nature and these are serious risks. But send an African, particularly in Nigerian man, he will hardly want to take any risks as it were”.

The full interview with Mr. Wabote, over a range of issues, was published in the November 2022 issue of Africa Oil+Gas Report monthly. A summary of that interview will be available on this website next week.

North Africa’s Domestic Gas Market Is Larger than its Export..And It Dwarfs Subsahara’s

Section: Gas Monetization · January 12, 2023 · No comments |

It is true: Libya directs about 60% of its gas production to the domestic market, while the rest is exported to Italy, according to statistics from the Libyan Ministry of Oil and Gas.

That piece of information will give Nigeria’s natural gas producers some pause; it’s an epic struggle to find credible natural gas offtakers in Africa’s largest economy.

Egypt utilizes five times more of its natural gas in-country than it exports. Algeria’s natural gas export is only slightly higher than its domestic utilization. These two countries; the largest producers of natural gas in Africa, are faced with the kind of challenges that the Nigerian government would consider a good problem: how to reduce the appetite for gas at home so as to have more gas to export for foreign exchange?

“Controlling domestic natural gas consumption is a key issue, as potential gas savings can be exported”, Toufik Hakkar, CEO of Sonatrach, the Algerian state hydrocarbon firm, told the MEES. “Growth in gas consumption in Algeria recorded in the past is explained by economic growth and improving citizens’ access to energy, but also through the implementation of several industrial projects that need gas” he explained.

The Egyptian government, in August 2022, moved to limit the country’s use of electricity in order to raise natural gas exports. Government buildings and sports facilities were asked to cut their consumption, including by turning the lights off outside daytime hours; a lower limit of 25°C was put in place for Air conditioners in malls, and retailers were asked to reduce bright lighting in storefront. The government hoped the measures would make available some 15% of the gas that is currently allocated to the nation’s gas-fired power stations, which delver over 40,000MW of electricity. The curb was meant to bring in an extra $450Million a month in revenues. Price increases on natural gas supplied to cement producers and brick kilns came into effect in October 2022, in another move to dampen domestic demand and redirect more gas for export. And the country’s burning of mazut fuel oil in power stations soared to a five-year high

So, what are the figures? What really, are the domestic gas volumes in these countries?

In Egypt, around 7Billion cubic feet of gas is marketed every day, of which 6Billion is sold in the domestic market. Nigeria’s sales in the domestic market is less than a quarter of that, and yet Nigeria is the biggest domestic gas market in Subsaharan Africa, followed by South Africa, which consumes less than 600Million cubic feet a day. For several years the Egyptian government reduced the gas nominated for the country’s two Liquefied Natural Gas facilities, until there was no molecule of gas left to liquefy for export. In 2014, BG (now defunct), famously lamented that it was breaking contracts with customers and lenders because it was unable to export enough liquefied natural gas from Egypt, its largest producing area. Reason: the exports were curtailed because the Egyptian government had ordered the diversion of the company’s natural gas production to domestic purposes.

In 2021, the latest year for which reliable figures are available, Algeria exported 6Billion cubic feet per day of both LNG and piped gas, mostly to Europe. At home, it consumed about 5Billion cubic feet of natural gas per day. Sonatrach’s 2021 report said that the domestic consumption was largely determined by demand from three large national companies:• Sonelgaz • Fertial • Sorfert.

Libya is the small one, but its story fits the pattern. It exports around 250Million cubic feet per day to Italy, but it consumes 375MMscf/d in its power plants and industries. For all of 2022, Libya exported about 88Billion cubic feet of gas through the Green Stream pipeline to Italy. At home it consumed 132Billion cubic feet.

Nigeria is the largest domestic gas market in sub-Saharan Africa; its gas export has significantly dropped in the last two years, but at the best of times its export was about 3.5Billion cubic feet per day, while the domestic consumption was never as high as 1.5Billion cubic feet per day. Which means that, neither the export nor the domestic volumes were up to scratch compared with the two largest North African economies.

Yet, the most vociferous arguments about how gas should be the transition fuel (in the journey to a zero-carbon future) has been the African countries south of the Sahara, who, in most cases don’t have clear line of sight to robust domestic gas markets even in the next decade.

Gas Flare Programme: 139 Applicants Make It to RFQ Phase

Section: Gas Monetization · January 8, 2023 · No comments |

The Nigerian Upstream Regulatory Commission (NUPRC) has rated 139 applicants as “deemed successful and awarded the Qualified Applicant status”, for the Request For Qualification (RFQ) Phase of the Nigerian Gas Flare Commercialisation Programme (NGFCP) 2022

This is less than 50% of the Three Hundred (300) companies who registered their interest to revalidate their prequalification status and submit Statement of Qualification (SOQ) as existing bidders and new participants, respectively.

The Commission says that in consideration of Section 105 (2) of the PIA and similar provisions enabling the Commission in that respect, it “hereby publishes the list of Qualified Applicants who will proceed to the Request for Proposal (RFP) phase of the NGFCP 2022.”

The 139 “Qualified Applicants” will now follow through with the subsequent stages of the Programme towards becoming a Permit Holder/Flare Gas Buyer in line with the applicable statutes.

47 gas flare sites are 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 between 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

In the next phase of the process, which is Request for Proposal (RFP) phase gas composition will be a part of the flare dataset which will be made available in the data room. Typical flare gas composition shows methane content of 70-90% which makes the sites amenable to mini-LNG deployments NUPRC officials assure. Many of the flare sites are not necessarily connected to pipeline infrastructure, but basic (financial and technical) requirements are provided in the Request for Qualification (RFQ) and detailed information will be enumerated in the RFP when issued, regulators have assured.

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. Questions have been raised about whether any additional flare gas produced by the field above the licensed quantity may be priced at Henry Hub. To this, the NUPRC has 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 promises 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 explains, will be managed in line with the established protocol on carbon credit.

All Qualified Applicants shall receive further communications via their respective contact addresses and the NGFCP portal (ngfcp.nuprc.gov.ng) accordingly.

Mozambique to Legalize Village Militias to Fight Terrorists in Gas Rich Province

Section: Gas Monetization · December 29, 2022 · No comments |

The Mozambican parliament has passed the first reading of a government bill that will legalise the “local forces”, which are village militias in the northern province of Cabo Delgado, set up to fight against Islamist terrorists.

Terrorist attacks in Cabo Delgado began in October 2017, and have been characterized by great brutality, including beheadings, mutilations and rapes. As from 2019, rather than rely exclusively on units of the defense and security forces, some villages began to set up their own self-defence units, initially drawn largely from veterans of Mozambique’s war for independence from Portuguese colonial rule.

The government bill makes it clear that the “local forces” are not independent, but fall under the control of the regular armed forces (FADM), which will provide them with logistical support. Introducing the bill, Defence Minister Cristovao Chume said the military chain of command covers the local forces, which are a temporary expedient arising from the crisis of jihadist terrorism.

Local forces began as an offshoot of the veterans of the independence war, the Defence Minister says in a statement. Today, they include many young people determined to defend their villages, and even some demobilized soldiers who had once been members of the main opposition party Renamo.

Both Renamo and the Mozambique Democratic Movement (MDM), the second opposition party, denounced the bill, claiming that it legitimizes a “parallel” paramilitary force, serving the ruling Frelimo Party.

Renamo deputies repeatedly declared that the bill “legitimizes naparamas”. In fact, the bill does not mention the naparamas, which are an independent peasant militia, quite separate from the local forces.

The naparamas first appeared in the late 1980s, fighting alongside the Mozambican army against Renamo, and, for a few years, enjoying considerable successes in Nampula and Zambezia provinces. They reappeared a few months ago to fight against the jihadists in Cabo Delgado. It is not at all clear that the naparamas would disband, even if the government told them to.

Renamo and the MDM argue that the local forces are “unconstitutional”, because the Mozambican constitution states that defence matters are exclusively the domain of the armed forces and the police.

But the government’s bill deals with this problem by bringing the local forces explicitly under the control of the FADM. Indeed, if the bill is not passed, the situation of the local forces would clearly become unconstitutional.

Neither Renamo nor the MDM suggested disbanding the local forces. Instead, they argued that they could be replaced by reservists, or by recalling demobilized soldiers into the FADM.

In the vote, the 161 members of the ruling Frelimo Party present supported the bill, while all 56 Renamo and MDM deputies in the room voted against.

The bill now enters a committee stage, where amendments can be proposed, but it is unlikely to undergo any significant change. The second and final plenary reading of the bill will occur on Friday or Monday

ENI Tops Up Congo’s FLNG Capacity By 300%

Section: Gas Monetization · December 23, 2022 · 1 comment |

By Sully Manope, in Brazzaville

Project will deliver ~440MMscf/d by 2025

Italian producer ENI has launched a second Floating Liquefied Natural Gas (FLNG) project to increase the production of and export from the Republic of Congo.

The company announced it had signed a contract with Wison Heavy Industry for the construction and installation of an FLNG unit with a capacity of 2.4Million Metric tons per annum (2.4MTPA). The FLNG will be deployed offshore the Republic of Congo, widely known as Congo Brazzaville.

This facility will be the second FLNG to be deployed in the country, the first one being Tango FLNG (0.6 MTPA capacity), with LNG production expected to begin in 2023. With the second FLNG, overall LNG production capacity on the Marine XII field will reach 3Million tons/year (3MTPA), which is ~160 Billion standard cubic feet/year or 440MMscf/d in 2025.

The 380 metre long and 60 metre wide vessel will be anchored at a water-depth of around 40 metres and will be able to store over 180,000 cubic meters of LNG and 45,000 cubic meters of LPGs. Preliminary activities have already started, with long lead items ordered and steel cut of cryogenic tanks occurred on December 20th.

“Both initiatives are part of Marine XII gas valorisation plan, in line with ENI’s strategy to leverage gas equity”, the company says in a statement.

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

Section: Gas Monetization · November 23, 2022 · No comments |

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… ?

Section: Gas Monetization · November 22, 2022 · No comments |

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 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.

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

Section: Gas Monetization · November 13, 2022 · No comments |

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

Section: Gas Monetization · October 27, 2022 · No comments |

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.