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LPG Production to Commence in Mozambique in 2024

Sasol says it will start the first, in-country production of Liquefied Petroleum Gas (cooking gas) in Mozambique by March  2024.

The product is part of the deliverables of the field development plan for the Production Sharing Agreement (PSA) in the northern region of Mozambique’s province of Inhambane.

That FDP aims to optimally develop the light oil and gas resources contained in the Inhassoro, Temane and Pande fields.

The LPG processing facility has capacity for 30,000 tons of LPG per annum. “The equipment is being installed in the factory under construction for the production of the field”, according to Radio Mozambique. Mateus Mosse, director of Cooperative Relations at Sasol. says that the pace of the work is satisfactory and believes that the deadlines established for the completion of the works will be met.

“What Sasol will produce in terms of cooking gas corresponds to around 60 to 70% of the country’s demand. It is true that the economy is growing, this could perhaps reduce demand to 50%, but it is already significant in terms of contribution to the country”, Mosse told the country’s government owned radio  “Let’s stop importing 50% of the cooking gas that the country needs, as there is a lot to gain. First, we will stop importing a significant amount of cooking gas; second, we will have a Mozambican company buying gas from Sasol and reselling it; we will have other distribution companies and cooking gas resellers purchasing in the country”, he said.

In 10 Months of Barging Crude, Newcross Distances itself from the ‘Jinx’ in Eastern Nigerian Onshore’s NCTL Pipeline

Of the four Nigerian owned, acreage holding producers who inject their crudes into the Nembe Creek Trunk Line (NCTL), Newcross E&P Ltd has emerged the one with the truest grit.

In August 2022, it exited the line, which has lain prostrate since 2021 and contracted a shuttle tanker MV Bryanston, to ferry its barged crude to the Bonny Terminal.

Since its December 2022 gross output of 5,074BOPD (Net-2,283BOPD) from the Oil Mining Lease (OML) 24, Newcross has maintained gross production higher than 10,000BOPD for the entire…

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NCDMB, NNPC, Oil Majors, in League to Streamline Contracting Process

By Abdulwaheed Sofiullahi, Reporter, SOEs

The Nigerian Content Development & Monitoring Board (NCDMB) has formalized a Memorandum of Understanding (MoU) with some of the country’s hydrocarbon producers, including state owned NNPC Ltd as well as five International Oil Companies (IOCs).

The MoU is aimed at reducing the contracting cycle to a maximum of 180 working days.

The agreement, released on September 26, 2023 at the NNPC Towers in Abuja, focuses on the efficiency goals outlined in the Petroleum Industry Act (PIA), to establish an industry framework for optimizing the contracting cycle.

Key highlights of the framework in the MoU include reductions in the contracting cycle for open competitive tenders, selective tenders, and single sourcing tenders to 180, 178, and 128 working days, respectively, compared to the existing best effort performance of 327, 333, and 185 working days, respectively.

“An optimized contracting cycle is poised to enhance the ease of conducting business, lower costs, and drive efficiency, ultimately leading to increased production, higher revenues, and improved profitability”, according to a statement issued after the signing.

Signing on behalf of NCDMB was the agency’s Executive Secretary, Simbi Kesiye Wabote. The NNPC Ltd was represented by its Executive Vice President, Upstream, Oritsemeyiwa Eyesan.  The participants described the MoU as a forward-looking step that will significantly enhance the nation’s crude oil production.

Representatives of IOCs, including the Managing Directors and Country Chairs of Shell, ExxonMobil, Chevron, TOTALEnergies, and ENI, pledged their commitment and support for the MoU’s implementation for the mutual benefit of all parties.

“This framework aligns with the Nigerian Upstream Cost Optimization Program (NUCOP) and is in accordance with the directive from the President for NNPC Ltd. and NCDMB to collaborate with the industry to improve the petroleum sector’s performance”, the statement added.


Sasol: Pilot Successful, Green Hydrogen Production Starts Early 2024

Sasol, the South African synfuels giant, expects to commence consistent production of green hydrogen in early 2024, once the 69 Megawatt Msenge Emoyeni Wind Farm, in the Eastern Cape, begins supply of renewable energy to Sasol’s Sasolburg site via a wheeling arrangement.

The company says it has proven the concept, when it produced its first green hydrogen, under a pilot phase, using a 3MW solar photovoltaic facility in its factory in Sasolburg, in the country’s Free State province,  in June 2023.

It had used the pilot project to repurpose an operational electrolyser to use renewable electricity to split water into hydrogen and oxygen. The green hydrogen produced in Sasolburg will be used in mobility applications.

“There is a demand for green hydrogen to decarbonise the mining industry, and in other mobility applications,” declares Sasol CEO Fleetwood Grobler.

“Once operational, the (69MW) Msenge wind farm together with the Sasolburg solar farm will provide sufficient renewable power to commercialise green hydrogen in South Africa”,  Grobler assures.

“This is a huge step forward in the energy transition, not just for Sasol but also for South Africa,” Grobler explains.




Fuel for Thought: Liquefied Petroleum Gas


By: Gorgui Ndoye

The past several years have shown that a range of fuel options for power generation is an important hedge against instability. Fuel flexibility is a hallmark of Capstone microturbines, which can run off a variety of sources, from natural gas and propane to methane, hydrogen, and more.

Today we’re spotlighting liquefied petroleum gas (LPG), a widely available fuel that is an excellent alternative to diesel and other expensive, “dirty” fuels. This primer explains the types of commercially available LPG and how they can integrate into Capstone microturbine systems.

What is LPG?

Using LPG in Microturbines

LPG is a mixture of propane (C3), butane (C4), and small quantities of various other hydrocarbons, such as propylene and butylene.

LPG is transferred and stored as a pressurized liquid; however, its boiling point is such that it evaporates easily under ambient temperature and pressure. The molecular composition of LPG determines the dew point, heating value, density, and many other properties, as well as the percentage of contaminants. These values determine whether a fuel can be used in an engine or turbine. For this reason, it is important to know the composition of the LPG before designing the fuel delivery system. Because the LPG composition can vary significantly between fuel types, Capstone enhanced the fuel capabilities of the C200 and C1000 series microturbines to use a variety of LPG.

The four most common commercially available types of LPG are Special Duty Propane (HD-5), Commercial Propane (HD-10), Propane-Butane Mixtures (PB Mix), and Commercial Butane. LPG can also be mixed with conditioned air to make an LPG/Air Mixture. The addition of air may alter the overall fuel properties to a more desirable level for operation. Capstone’s microturbines can run using HD-5, PB Mix, or LPG/Air Mixtures.

When comparing LPG to Natural Gas (NG), it’s important to note the heating value difference. NG has an average heating value of 1,000 Btu/scf. SD-5 is roughly 2,500 Btu/scf, and Commercial Butane is over 3,000 Btu/scf. Therefore, the heating value of LPG is 2.5 to 3 times greater than NG. So, LPG requires much lower volumetric flow rate to achieve the same engine output. LPG is also stored as a liquid, which compresses the fuel volume 250:1—without costly cryogenics required by LNG. These factors offer a small footprint for LPG compared to NG’s need for pipelines and large infrastructure, and LPG can be transported easily and stored in tanks, making it a good diesel replacement.

Using LPG in Microturbines

  1. Special Duty Propane

Special Duty, or HD-5, Propane is defined as greater than 90% propane and less than 5% propylene. This grade is ideal for all types of engines and turbines due to the burn’s cleanliness and the low level of contaminants relative to diesel.

All Capstone microturbines have a version that can operate using HD-5 Propane.

  1. Propane-Butane Mixtures.

Twenty-three Capstone C65 microturbines provide prime power to Southern California Edison’s Avalon site on Catalina Island

Propane-Butane Mixtures,  or PB Mix, have no standard specification for their compositions and can be a problem for gaseous fuel operation due to the low dew point of butane. The higher the concentration of butane, the lower the dew point falls, and the more heat tracing and insulation needed with the fuel delivery system. This causes a higher risk of fuel condensation, which may lead to engine problems. The LPG-capable C200 and C1000 series microturbines were designed with a versatile fuel system. This includes internal heat tracing and fuel line insulation, which reduce the risk of condensing vapor from heavier fuels. The goal of the heat tracing and insulation is to maintain the supplied inlet fuel temperature without needing to increase the fuel temperature or vaporize condensed liquids.

The LPG-capable C200 and C1000 microturbines are approved to operate using a Propane-Butane Mixture of up to 40% butane. This does not mean that PB Mixtures containing greater than 40% butane are disqualified. Capstone applies the same limitations towards propylene, limited to less than 5%, as well as all other contaminants listed in the Special Duty Propane specification.

  1. LPG/Air Mixtures

Certain LPG types that are not suitable for microturbines may be approved when mixed with air. Alternatively, the mixture may attempt to match the properties of a more standard fuel, such as NG. LPG/Air mixtures are not standard and may require complex fuel delivery systems. The approval of these fuel types depends on review of the fuel properties and composition. Detailed analysis would be needed to determine feasibility for use in microturbines.

  1. Real-World Application

In March 2023, a 600 kW, C600S, LPG-fueled system was commissioned at a remote food processing facility in Bamako, Mali. Like many land-locked countries, Mali relies on expensive, “dirty” fuels like diesel and heavy fuel oil, so this project was important in demonstrating the benefits of a system whose fuel is less expensive and more environmental.

The new system also improves reliability, which addresses issues of load shedding and blackouts the facility had previously experienced. Because the microturbines also require very little maintenance compared to other technologies like diesel generators, power availability and cost savings were also improved.

Twenty-three Capstone C65 microturbines provide prime power to Southern California Edison’s Avalon site on Catalina Island

“The Mali project is a model for other customers and power companies, showing the benefits of LPG as an alternative fuel,” said Gorgui Ndoye, business development director for Capstone Green Energy. “There is tremendous opportunity to use LPG in many regions around the globe, but it can play an especially important role in Africa as part of the continent’s energy transition.”

Better for Business and the Environment.

It’s difficult to underestimate the positive impact that added reliability and cost savings have on the bottom line. Often, the combination of LPG and microturbines offers significant upside—including cleaner fuel and lower emissions. What’s more, once a customer decides to go with Capstone, we can fast-track and deploy nearly anywhere within three months of order.

The world’s energy landscape won’t become more predictable. Smart power security decisions made today will set businesses up to confidently navigate the future. An LPG-fueled microturbine system could be the answer.



Renewable Energy Wheeled for the first time through Cape Town’s Grid

The first electrons of renewable energy have officially been wheeled via the City of Cape Town’s energy grid, as part of the city’s plans to end power outages, which plagues South Africa.

Growthpoint Properties (JSE: GRT) became the first party to wheel renewable electricity in the city in collaboration with licenced electricity trader Etana Energy (Pty) Limited (Etana), a joint venture in which the South African owned Neura Group and H1 Holdings hold 49% and 26% respectively and UK based Chariot holds a 25% interest.

Wheeling is a process where electricity is bought and sold between private parties, using the existing grid to transport power from where it is generated to end-users that can be long distances apart.

“It creates greater access to affordable renewable energy and contributes to resolving the country’s energy crisis”, UK based Chariot says in a statement.

“As part of the City’s wheeling pilot project, in which Etana was selected as a participating trader, solar energy generated at Growthpoint’s The Constantia Village shopping centre in Constantia is being exported into Cape Town’s electricity grid for use at Growthpoint’s 36 Hans Strijdom office building in the Foreshore”.

Solar power from The Constantia Village was successfully injected into the City’s energy grid for the first time in September 2023.

Etana Energy says it is pleased that the city selected it as a trading partner, and we look forward to providing further energy support to the region for the foreseeable future.

“This electricity licence not only enables us to instigate this trading, but it also has the potential to help to unlock the development of further large renewable projects in South Africa. We are looking to supply greener power across the national grid for commercial and industrial requirements so this early-stage trading is a key step within our longer term plans for this business.”

STAC Marine Wraps Up Purchase of Abo FPSO for $20Million

The Nigerian marine operator STAC Marine Offshore Limited, has finalised the purchase of the Abo Floating Production Storage Offloading (FPSO) vessel from BW Offshore, the Norwegian provider of floating productions solutions.

As part of the transaction, BW Offshore has entered into a bareboat charter with STAC to allow for uninterrupted operations for the client during a transition period of maximum two months. Upon expiry of the bareboat charter, STAC will assume responsibility for operations of the unit.

STAC is a member of the Nigerian Transport Group (STAC).

BW Offshore has managed the Abo FPSO since the Abo deepwater field came on stream in 2003.

In the last five months, it had been seeking to end the contract with ENI, the Italian operator of the field. It has had three short contract extensions between June and September 2023.

This sale of the vessel to a Nigerian firm, effectively removes the responsibility of running the FPSO, from BW Offshore’s shoulders.

Originally recognised as the “Gray Warrior“, a Suezmax tanker constructed in 1976, the vessel underwent conversion at Keppel Shipyard before beginning its operations in April 2003. “Abo FPSO has now reached a commendable milestone, having completed two decades of service on the Abo field. This achievement underscores its enduring contribution to the oil and gas industry in Nigeria”, BW Offshore says in a statement.

Why Less Looks Like More: A Performance Review of Nigeria’s Power Generation Capacity

By Adeniyi Adeoloye

The Nigeria power sector is encumbered right through the entire value chain.

The figures for installed generation capacity, the grid transmission, and what the distribution companies can deliver to the end users, are common knowledge. But there’s a vast gulf between the capacity and the delivery and the specific details of this gap is absent from the conversation.

Many have dismissed the transmission segment as the weak link in the power industry value chain. The call has led to pleas for government to let go of operating it in order to drive efficiency and deliver optimum value. There has been a scathing searchlight on the distribution and transmission links of the sector. But then, the generation segment is as broken.

Nigeria, like many countries, organises its energy mix around energy sources that are abundant within its borders. Hydro power and gas fired plants dominate the energy mix in Africa’s most populous country. Save for the emissions during their construction and location outside demand centres, hydro is largely seen as a clean means of power generation. On the other hand, gas has been given green credentials by the European Union due to its less polluting nature than coal and since labelled a transition fuel. So by and large, the grid emission factor of the power generation systems in Nigeria based on energy source are in relatively good stead.

What are the numbers like? By the tally, there are 23 power generating plants connected to the grid in Nigeria with installed capacity of 10,396 MW and available capacity of 6,056 MW. Of this, gas fired plants account for 8,457.6 MW with available capacity of 4,966 MW while the remainder is hydropower with installed capacity of 1,938.4 MW and available capacity of 1,060 MW. The large chunk of the country’s generation is gas fired.  The ownership of these plants cuts across government and the private sector. Nigerian Bulk Electricity Plc (NBET) undertakes Power Purchasing Agreement (PPA), with the generating companies and sells the energy purchased to the distribution companies via Vesting Contracts. A total of 16 generation companies have PPA with NBET.

Performance of Government Run Power Plants

Government hatched the National Integrated Power Project (NIPP) in 2004 in a bid to stabilize electricity supply in anticipation of the takeoff of the private sector led structure of the Electric Power Sector Reform Act (EPSRA) of 2005. The primary idea of NIPP was to build 7 medium sized gas fired power plants in gas producing states alongside crucial transmission infrastructure required to move the added power to the national grid. The Niger Delta Power Holding Company Limited (NDPHC) was set up to house and manage the NIPP assets with market oriented practice. Available information by NDPHC indicates it owns 10 thermal plants – Calabar (563 MW), Omotosho (500 MW), Sapele (450 MW), Egbema (338 MW), Omoku (225 MW), Alaoji (960 MW), Ihovbor (450 MW), Gbarain (225 MW), Gerugu (434 MW) and Olorunsogo (675 MW). Of this ten, eight of them except Egbema and Omoku have “interim agreement” with government owned Nigerian Bulk Electricity Trading Plc (NBET) that buys power from Independent Power Producers (IPP) and successor generation companies from the unbundling of Power Holding Company of Nigeria (PHCN) and resale to Distribution Companies who deliver to end users and other large consumers who take electricity directly from the grid.

The eight plants having interim agreements with NBET have total contract capacity of 4,257 MW and tested capacity of 1762 MW with average generation capacity of 488.15 MW as at year 2021 according to data by NBET. The data further shows average generation of these plants is a paltry 11% of net contract capacity, and about 27% of tested capacity. Plants with installed contract capacity of 500 and above didn’t perform any better. Alaoji with net contract capacity of 960 MW and tested capacity of 212.33 MW averaged an output of 58. 19 MW.  Olorunsogo (675 MW, 212.67 MW and 23.07 MW), Calabar (563 MW, 339.55, 236.02) and Omotoso (500 MW, 219.61 MW and 43.24 MW) for net contract capacity, tested capacity and average generation capacity respectively. The Ihovbor Plant with contract capacity of 450 MW and tested capacity of 202.34 MW last done in 2021 had average generation capacity of 16.87 MW in year 2021. This is an abysmal low of capacity utilisation. Across board, NDPHC managed plants are poorly performing.

And talking about testing, the data also established year 2015 as the last test date for all NDPHC plants with the exception of Alaoji plant whose capacity test was carried out in June 2021. The lag in test capacity is against what is stated in a March 2022 draft power purchase agreement for brownfield power plants by NBET which states “the Tested Capacity of the Plant shall be verified at least annually by further Capacity Tests that will establish the revised Tested Capacity”. Usually there are diverse reasons to appraise the performance of a plant other than meeting contract guarantees. Performance tests for a brownfield power plant can be done to verify its capacity and heat rate before an acquisition in order to determine its asset worth. Testing is also useful for the goal of maintaining a Power Purchase Agreement, tariff up-gradation as well as to ascertain the performance differences brought by major repairs or component upgrades.

Review of Successor Gencos

Successor Gencos are power generation companies created in the aftermath of the unbundling of PHCN. There are eight of these plants around the country namely: Kainji (760 MW), Jebba (576 MW), Shiroro (600 MW), Egbin (1100 MW), Sapele (1020 MW), Delta (900 MW), Afam IV-V (776 MW) and Gerugu (414MW). Tese are nameplate capacities. With the exception of Kainji, Jebba and Shiroro that are hydro power, the rest are gas fired. Many of the plants have been fully or partially sold, and others under long term concession. All of the plants have Power Purchase Agreement with NBET with total contract capacity of 6,146 MW, last tested capacity of 2,853.72 MW and average generation capacity of 2,010.4 MW in year 2021. The average generation capacity of these plants is 32% of contract capacity and 70% of tested capacity. On a plant by plant basis, the Sapele plant is an overwhelming underperformer given its contract capacity of 1020 MW and test and 2021 average generation capacity of 52.29 MW and 46.39 MW, being last tested in June 2021. This translates to a miserly 4.5% average generation capacity to contract capacity. Afam IV-V didn’t fare any better with contract capacity of 776 MW and test and average generation capacity of 121.9 MW and 66.75 MW respectively and last tested in July of 2021. For context, the output from Afam IV-V is a beggarly 8.6% of its contract capacity.

Test dates for the plants was between June and August 2021. Over two years ago. Still far behind the annual recommendation of NBET. The performance of plants in this category outmatch those of the NIPP plants managed by NDPHC despite the sub par productivity of Sapele, Kainji, and Afam IV-V respectively.

A look at Plants in other Categories

There are five plants that are classified by NBET as having active PPA namely: Okpai operated by Agip, Afam VI run by Shell, Omotosho Electric, Olorunsogo and Azura Edo IPP. All of these plants are gas fired with total contract capacity of 2,188 MW, tested capacity of 1,815.61 MW and average 2021 generation capacity of 1,338.68 MW. The average generation capacity of these plants with respect to tested capacity is 71% and 61% with respect to contract capacity – an indication of better performance. Of plants in this category, Azura Edo IPP with contract capacity of 450 MW and test capacity of 452.6 MW and average generation capacity in 2021 at 420.84 outperforms it peers. In context, average generation capacity with respect to test capacity and contract capacity stands at 92% respectively with last capacity test carried out in June 2022. Shell run Afam VI has contract capacity of 650 MW, tested capacity of 464.96 and average generation capacity of 261.04 MW in 2021 with last test date of July 2021.   In performance terms, the average generation capacity with respect to contract capacity and tested capacity stands at 40% and 71% respectively. For Agip run Okpai with contract capacity of 480 MW, it tested capacity is 464.96 MW with average generation at 261.04 MW. Last tested in July 2021. This translate to 56% and 54% of average generation capacity with respect to tested capacity and contract capacity respectively. Without doubt, Azura leads the pack in terms of production efficiency.

State Government owned plants Ibom Power, Mabon, Omoku FIPL, Trans Amadi FIPL, AFAM (Rivers IPP) FIPL, and Eleme have combined contract capacity of 870 MW, with tested capacity of 451.88 and average generation of 185.09. The average generation capacity of Ibom power of 12.53 MW compared to test and contract capacity of 112.83 MW and 190 MW respectively, translating to 11% of average generation to test capacity is an indication of operation plunging into an abysmal depth. The Mabon and Eleme are new plants in the inventory of NBET with their capacity test yet to be carried out.

The foregoing is the state of things with the plants based on data from NBET. Cash liquidity constraint is a major issue given collection inefficiency by distribution companies. This has a ripple effect on the sector, leading to inability of operators to pay gas producers. Additionally, the insufficiency of the transmission company to transmit contracted or test generation capacity due to infrastructural gap and vandalism has left the country with more than 20 plants with test capacity of 6,884.76 MW out of contract capacity of 13,461 MW and an average generation of 4,022 MW in 2021 to back up power from the grid with gasoline or diesel generators. The factors causing this inefficient operations has to be reigned in rather than pushing the much needed reform to turn things around into the long grass as done by successive governments. Economic growth, its attendant job creation and prosperity will continue to be an illusion with this sort of underwhelming productivity of the power generating plants.

“Key Parts of a Power Purchase Agreement” According to NBET

Tariff Structure – Provides the details of how NBET will pay for the duration the PPA is calculated.

Risk Allocation – Identifies all project related risks and allocates these risks to parties best able to bear them.

Conditions Precedent – Provides all the conditions precedents (CPs) which either the Buyer (NBET) or Seller (Owner of plant) must satisfy before the PPA can become effective.

Tenor of PPA – A standard NBET PPA has a 20 year tenor. There are clauses within the PPA to handle early termination due to either a Buyer’s or Seller’s default.

Project Documents – All documents that are connected to the PPA such as Engineering, Procurement and Construction, Gas Supply Agreement (GSA), Gas Transport Agreement (GTA), Operations and Maintenance, Long Term Service Agreement, Financing documents e.t.c.

Commissioning & Testing Procedure – Contains a set of guidelines for plant testing and commissioning.

Operation & Maintenance – Contains details of the maintenance and operational obligations of the Seller throughout the tenor of the PPA.

Conflict Resolution – Indicates clear procedures for conflict resolution in case of disputes and/or conflicts on invoices.

Metering – Sets out the rules about metering. However, in case of conflicts between PPA provisions and the metering code, the metering code supersedes.

Liability & Indemnification – Enumerates the parties responsible for certain failures and provides indemnification to both parties.

Insurance – States the required insurance coverage to be put in place by the Seller and how the proceeds will be administered.

Scheduling Notices – Provides a methodology by which the Buyer nominates for the dispatch of Net Electrical Output to be made available at the delivery point by the seller.

Force Majeure – Provides details of events to be considered as force majeure and possible payments during the occurrence of such events.

Adeniyi Adeoloye is a consulting Editorial associate at the Africa Oil+Gas Report.






Mozambique Sees Decline in FDI as TOTAL Holds Up Massive Gas Project

Mozambique experienced a 32% reduction in the flow of Foreign Direct Investment (FDI), totalling $350.4Million in the second quarter of 2023, compared with $460.1Million in the previous quarter.

The raft of investment in the construction phase of gas development projects: by Sasol in its Production Sharing Agreement (PSA) licence onshore inhambane province; by ENI on the Coral South FLNG and TOTAL in the large 13Million Metric tonnes LNG project, have cooled. Sasol has nearly completed the integrated oil and gas projects in inhambane; ENI is now producing from Coral South FLNG and so is no longer in the spending mode and TOTAL hasn’t entirely returned to work in the troubled Cabo Delgado province.

Data contained in the most recent Bank of Mozambique (BdM)’s monthly Statistical Information (SI) report, recently indicates that the decline is largely attributed to almost 50% drop in investments in the extractive industry, especially in Major Projects (GP).

The SI report said: “In the period under review, the flow of FDI in Major Projects totalled $278.8Million dollars, compared to $414.6Million in the previous quarter.”

South Africa remains the largest contributor of FDI inflows into Mozambique (39.1%).

NMDPRA Grants Approvals for CNG Supply, LPG Infrastructure, to Femadec, Novertek Respectively

By Fasilat Oluwuyi, Reporter, Energy Access, Africa Oil+Gas Report

The Nigerian Midstream and Downstream Petroleum Regulatory Authority(NMDPRA) has signed agreements with Femadec and Novertek Energy on Compressed Natural Gas (CNG) and Liquefied Petroleum Gas (LPG).

This was disclosed via NMDPRA’s X account (formerly Twitter) on September 19, 2023.

The Regulatory Authority said it has granted approved to Novertek Energy Limited to construct (ATC) 500MT LPG Depot in the Federal Capital Territory.

“The Midstream & Downstream Gas Infrastructure Fund (MDGIF) of the Authority signed an MoU with Femadec Energy focusing on the provision of Compressed Natural Gas (CNG).

“The Presidential Initiative on Compressed Natural Gas (PICNG) which is the driver for the Federal Government’s “Decade of Gas” initiative was also present at the event., ” NMDPRA said in the statement.

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