Algeria occupies a rare position in the international natural gas market. It is Africa’s largest gas producer, a major supplier to Europe and one of the few exporters able to deliver gas through both pipelines and liquefied natural gas terminals. Its location directly across the Mediterranean gives it an advantage over more distant LNG producers, while its established fields and transport network allow gas to move from the Sahara to Italy and Spain.
The country’s position, however, depends on more than the size of its reserves. Algeria must maintain production from mature fields, develop new resources and meet fast-growing demand from its own power system. The central question is no longer whether Algeria has enough gas underground. It is whether investment, field management and infrastructure can preserve a large export surplus while domestic consumption continues to rise.
Hassi R’Mel Remains the Centre of Algerian Gas Production
The Hassi R’Mel field is the foundation of Algeria’s natural gas industry. Located south of Algiers in Laghouat Province, it has supplied the country for decades and acts as a major gathering and dispatch point for gas produced across the Sahara. Other producing areas include the Berkine, Illizi, Ahnet, Reggane and Timimoun basins, but Hassi R’Mel remains central to production, processing and long-distance transport.
Algerian dry natural gas production reached a record level of about 3.7 trillion cubic feet in 2023. New projects, field expansions and a lower requirement to reinject gas into oil reservoirs helped make more supply available. This growth strengthened Algeria’s role after European buyers began looking for alternatives to Russian pipeline gas.
The production record does not remove the problem of field maturity. Hassi R’Mel and several other large deposits have operated for many years, which means reservoir pressure naturally declines. Sonatrach is therefore carrying out a major boosting programme at Hassi R’Mel. Compression and related facilities are intended to protect output, meet domestic needs and support export contracts rather than create an entirely new production centre.
This distinction matters. Algeria’s near-term gas strategy is partly defensive: it must invest heavily simply to slow decline at existing assets. New discoveries and developments can add supply, but maintaining the performance of the current system is equally important.
Mediterranean Pipelines Give Algeria a Strategic Export Advantage
Algeria’s strongest commercial advantage is its direct connection to southern Europe. The Enrico Mattei pipeline, commonly called TransMed, carries gas to Italy through Tunisia. The Medgaz pipeline runs under the Mediterranean directly to Spain. Together, these routes allow Algeria to reach two major European gas markets without liquefying the gas or using LNG tankers.
TransMed has an annual design capacity of roughly 1.18 trillion cubic feet, while Medgaz can transport about 378 billion cubic feet per year. The older Maghreb-Europe Gas Pipeline was built to move Algerian gas to Spain and Portugal through Morocco, but Algerian deliveries through that route stopped in 2021. The line later began operating in reverse so that Spain could supply Morocco.
Pipeline exports are supported by LNG facilities at Arzew and Skikda. Algeria’s operational liquefaction plants have combined nominal capacity of more than 1.2 trillion cubic feet per year. LNG gives Sonatrach flexibility to serve buyers beyond the fixed pipeline network, although Europe remains the main destination.
In 2023, Algeria exported about 1.9 trillion cubic feet of natural gas. Approximately 1.2 trillion cubic feet moved through pipelines and about 672 billion cubic feet was exported as LNG. This mix shows why Algeria is difficult to replace in the Mediterranean market. It can provide regular pipeline supply while using LNG cargoes to respond to different contract and market conditions.
The country is also trying to expand its role as a continental gas corridor. In June 2026, construction work officially began on the Algerian segment of the Trans-Saharan Gas Pipeline. The planned route would connect Nigerian gas to Algeria through Niger and then link with the system around Hassi R’Mel. The Algerian section is a significant step, but the complete cross-border project still depends on financing, security, construction and coordination across all three countries.
Domestic Gas Demand Competes With the Export Business
Natural gas is not only an export commodity for Algeria. It is also the main fuel supporting the domestic economy. Gas accounts for most of the country’s primary energy consumption and underpins nearly the entire electricity system. Gas-fired and combined-cycle plants have expanded as population, urban development, air conditioning and industrial activity have increased power demand.
Domestic energy prices are heavily subsidized, which makes gas and electricity affordable but can also encourage consumption and reduce incentives for efficiency. As local demand grows, a larger share of production must remain inside the country. This creates a direct tension between domestic energy policy and export revenue.
Algeria has generally produced enough gas to serve both markets, but the margin cannot be taken for granted. Between 2014 and 2023, dry gas consumption averaged about 1.6 trillion cubic feet per year, equal to almost half of average production during the same period. Demand can also rise sharply during hot summers, when electricity use increases.
Renewable energy could eventually reduce some of this pressure. Algeria has excellent solar resources, especially in the Sahara, but renewable generation still represents a small part of the national power system. Until large solar programmes, storage and transmission projects are developed at scale, natural gas will remain the main source of electricity and the principal balancing fuel.
New Investment Must Do More Than Replace Declining Output
Sonatrach remains the dominant company across Algeria’s gas value chain. It controls production, processing, pipeline transport, LNG facilities and most export relationships. Foreign companies participate mainly through partnerships and production contracts, bringing capital, technology and experience to complex fields.
The government has renewed efforts to attract international investment. Five hydrocarbon contracts were signed following the Algeria Bid Round 2024, and a new bid round was launched in 2026. The offered areas include established producing regions and less-developed basins where new exploration could support future gas supply.
The investment programme has two goals. The first is to maintain output from mature assets through compression, infill drilling and improved recovery. The second is to bring additional conventional and tight gas resources into production. Large unconventional resources may offer long-term potential, but water use, infrastructure costs, local opposition and technical requirements make rapid shale gas development uncertain.
Flaring is another major issue. Algeria flared an estimated 289 billion cubic feet of gas in 2023, placing it among the world’s largest flaring countries by volume. Capturing more of this gas could increase useful supply while reducing emissions, especially where fields are close to existing pipelines and processing plants. Sonatrach has identified flare-gas recovery and methane reduction as part of its wider investment and transition plans.
Algeria’s Gas Position Depends on Maintaining Its Surplus
Algeria will remain an important natural gas supplier because it combines large resources, established production, LNG capacity and direct pipeline links to Europe. Its challenge is not market access. It is preserving enough production above domestic demand to use that access fully.
Hassi R’Mel boosting work, new exploration contracts, lower flaring and additional regional infrastructure can support the sector. At the same time, mature fields and rising electricity consumption will absorb more investment and supply. Algeria’s future export strength will therefore be determined by how quickly new and recovered gas can offset decline and domestic growth.
Natural Gas in Angola: LNG Exports and the Move Beyond Associated Gas
Article excerpt: Angola is moving from oil-linked gas production toward dedicated offshore fields that can supply LNG exports and support domestic power generation.
Angola’s natural gas industry developed as an extension of its offshore oil sector. For many years, most available gas was produced alongside crude oil, then reinjected into reservoirs, flared or sent to the Angola LNG plant in Soyo. Gas production therefore depended heavily on oilfield activity rather than on projects designed specifically to develop gas reserves.
That structure began to change in March 2026, when the Quiluma field delivered the first production from Angola’s New Gas Consortium. It was the country’s first non-associated gas development, meaning the resource was developed primarily for gas rather than as a by-product of oil. The project gives Angola a more stable source of feedstock for LNG exports and may establish a model for future offshore gas investment.
Angola’s Gas Sector Grew From the Offshore Oil Industry
Angola held an estimated 4.6 trillion cubic feet of proved natural gas reserves at the start of 2025. This is a meaningful resource base, but marketed production has remained modest compared with the scale of the country’s oil industry. Between 2014 and 2023, dry natural gas production averaged about 166 billion cubic feet per year, while domestic consumption averaged only 36 billion cubic feet.
Most production came from associated gas at offshore oil fields. Some of this gas was reinjected to maintain reservoir pressure and support crude oil recovery. Another share was flared because offshore gathering, processing and transport infrastructure was not always available.
This connection to oil created a basic weakness. As Angola’s mature oilfields declined, the volume of associated gas available for commercial use could also fall. It was difficult to build a stable long-term LNG business when much of the feedstock depended on oil production decisions and reservoir needs.
The Sanha Lean Gas Connection project helped address the supply problem. Developed by Chevron’s Angolan subsidiary, the subsea system began delivering gas in December 2024 from Block 0 to Soyo. The wider project is designed to provide up to 600 million standard cubic feet per day when fully developed, strengthening feedstock supply for Angola LNG.
Soyo Turned Unwanted Gas Into an Export Industry
The Angola LNG plant at Soyo is the centre of the country’s commercial gas sector. The facility was created partly to capture offshore gas that might otherwise be flared. It can process gas, remove liquids and produce LNG for shipment to international markets.
The plant has liquefaction capacity of about 5.2 million tonnes per year, equal to roughly 250 billion cubic feet of gas. Angola LNG is owned by a consortium that includes Chevron, Sonangol, TotalEnergies and Azule Energy. It shipped its first LNG cargo in 2013, but technical problems forced a long shutdown before commercial operations restarted in 2016.
Since the restart, Soyo has given Angola a direct connection to global gas markets. The country exported about 175 billion cubic feet of LNG in 2023. Around three quarters of that volume went to Europe, reflecting the shift in global trade after European buyers reduced their dependence on Russian pipeline gas. Before 2022, Asian markets such as China and India took a larger share of Angolan cargoes.
Angola’s LNG trade is flexible because cargoes are not tied to a single cross-border pipeline. However, the plant’s value depends on dependable feedstock. Angola LNG has often operated below its full potential because upstream gas supply was limited or inconsistent. This is why the new generation of dedicated gas projects matters more than a simple increase in reserve estimates.
Quiluma Begins Angola’s Non-Associated Gas Era
The New Gas Consortium is the most important structural change in Angola’s gas industry. Operated by Azule Energy with Chevron, Sonangol and TotalEnergies as partners, the project develops the shallow-water Quiluma and Maboqueiro fields. Its infrastructure includes two offshore platforms, subsea pipelines and an onshore gas treatment plant connected to Angola LNG.
The Soyo treatment plant was inaugurated in November 2025, and Quiluma began supplying gas in March 2026. Initial production was set at about 150 million standard cubic feet per day. The partners expect output to rise toward 330 million cubic feet per day by the end of 2026, a plateau equivalent to approximately two million tonnes of LNG per year.
The project changes the relationship between gas and oil in Angola. Dedicated gas production can continue even when crude oil output from mature fields declines. It also gives LNG planners a clearer supply profile and may support additional investment in gas discoveries that were previously difficult to commercialize.
Future phases could extend beyond Quiluma and Maboqueiro. Angola has other discovered resources in the Lower Congo Basin, and the Gajajeira-01 well in Block 1/14 confirmed a gas and condensate discovery in 2025. A discovery does not automatically become a commercial project, but nearby offshore and Soyo infrastructure can improve its development options.
Export Growth and Domestic Gas Use Do Not Yet Carry Equal Weight
Most of Angola’s commercial gas strategy remains focused on LNG exports. International sales generate foreign currency, use existing liquefaction capacity and provide a clear market for new offshore supply. The New Gas Consortium was designed mainly to feed Angola LNG, although part of its production may also reach the domestic market.
Natural gas already supports electricity generation through the 750-megawatt Soyo combined-cycle plant, which began operating in 2017. Even so, gas plays a smaller role in Angola’s power mix than hydropower. In 2023, hydroelectric plants generated most of the country’s electricity, while gas accounted for a much smaller share.
The main domestic constraint is not simply fuel supply. Angola’s electricity system is divided into northern, central and southern networks, and transmission and distribution remain uneven. New gas-fired capacity near Soyo cannot solve electricity access problems in distant areas unless the grid is expanded and connected.
Gas could still support industrial development around Soyo and other coastal centres. Reliable supply may create opportunities for power generation, fertilizers, petrochemicals and other gas-based industries. These uses would provide more domestic value than exporting all available gas as LNG, but they require long-term buyers, infrastructure and competitive project economics.
Flaring Reduction Remains Part of the Commercial Case
Angola flared about 65 billion cubic feet of natural gas in 2023. This was far below the country’s 2016 level, partly because the restarted LNG plant created a market for gas that had previously been burned. However, the 2023 volume was still large compared with marketed production.
Reducing flaring can produce both environmental and economic gains. Gas gathering and compression systems allow offshore operators to send more supply to Soyo, use it for power or reinject it where needed. The commercial case is strongest where existing fields can connect to nearby infrastructure without a completely new development system.
The move toward non-associated gas also reduces reliance on flare capture alone. Angola can now plan projects around known gas demand from the LNG plant. This gives developers a clearer route to market and allows the government to evaluate gas resources as a separate industry rather than only as part of oil production.
Angola Now Has a Platform for a Larger Gas Industry
Angola is not yet one of Africa’s largest natural gas producers, but its gas sector has entered a new stage. Angola LNG provides an established export outlet, Sanha adds associated-gas feedstock and the New Gas Consortium introduces dedicated production from Quiluma and Maboqueiro.
The next test is whether these projects lead to a sustained development programme. Stable output from the new fields, further exploration success and reliable operation at Soyo could lift LNG exports and reduce flaring. A broader domestic role will depend on transmission networks, industrial investment and the ability to direct part of the gas supply toward Angolan consumers rather than international cargoes alone.
