The issue: Namibia’s oil story is also a gas story

Namibia’s offshore petroleum discoveries have attracted significant international attention and positioned the country as one of Africa’s most closely watched frontier petroleum jurisdictions. Yet, as exploration success moves toward appraisal, development planning and eventual production, a central commercial question is becoming increasingly important: how will Namibia monetise the gas associated with, or discovered alongside, its offshore resources?

The answer will determine more than the design of upstream projects. Gas commercialisation may influence whether Namibia captures long-term domestic benefits from its petroleum sector, including reliable power generation, industrial development, port and logistics activity, local content, skills transfer and new infrastructure investment. In other words, gas is not an afterthought to the oil story; it may be the missing link between offshore discovery and broader economic transformation.

The Industrial Gas Users Association of South Africa (IGUA-SA) 2023 Annual Report describes Namibia as a potential major regional gas player, referencing Kudu and more recent offshore discoveries such as Venus, Graff and Jonker, and indicating that Namibia could become a significant global gas player within the next decade. The Standard Bank strategic discussion document similarly treats Namibia’s Orange Basin as a distinct regional opportunity, while noting that a wider gas position may be de-risked through further appraisal and could ultimately support a shared “Namibia LNG” development in the 2030s. Recent updates in Trade & Industry, Oil & Gas as well as Energy policies and market reports in all SADC countries have now reinforced the same theme: gas commercialisation must be treated as a national & regional value chain question, not merely as an upstream technical issue.

Global LNG conditions: Opportunity, but not automatic bankability

Namibia’s gas strategy will need to be assessed against global LNG fundamentals. The 2025 International Gas Union (IGU) World LNG Report records that global LNG trade grew to 411.24 million tonnes in 2024, while global liquefaction capacity reached 494.4 MTPA by year-end. It also notes that a significant wave of liquefaction capacity is expected between 2026 and 2028, with around 170 MTPA of additional capacity scheduled over that period. For a new entrant, this creates both opportunity and competition.

The opportunity is that expanding LNG capacity, deeper spot markets and the growth of flexible infrastructure may create a more accessible route to monetisation for emerging gas jurisdictions. The competition is that pre-FID projects must still secure offtake, demonstrate cost competitiveness, manage carbon intensity and satisfy lenders that the project can withstand price volatility and execution risk. The same IGU report observes that project development remains exposed to delays and cost overruns arising from geopolitics, trade policy, inflation and labour shortages.

Flexible infrastructure is especially relevant for Namibia. The IGU report notes that floating solutions for LNG regasification, storage and production are characterised by faster and more flexible deployment and lower upfront investment than onshore facilities, making LNG imports and exports more accessible for smaller or remote demand centers. It also records that Floating Storage and Regasification Units (FSRUs) have become important for new markets because of their lower upfront investment, faster construction timelines and ability to respond to short-term demand fluctuations. For Namibia, this makes FLNG, FSRUs, small-scale LNG and phased infrastructure credible options to evaluate alongside large onshore LNG concepts, depending on reservoir size, gas composition, distance to shore, domestic demand and regional offtake.

Recent global gas reports add further nuance. The International Energy Agency’s (IEA) Gas 2025 medium-term report states that global gas markets are expected to undergo major changes by the end of the decade as a new wave of LNG production capacity reshapes market dynamics, improves supply security and may make gas more affordable for price-sensitive import markets. The IEA’s Gas Market Report, Q1 2026, similarly notes that global LNG supply growth returned to double-digit growth in the second half of 2025, supported by new projects in the United States, Canada and Africa, and that further LNG supply growth is expected in 2026 even though geopolitics and weather may continue to create price volatility.

Shell’s LNG Outlook 2025 points in the same strategic direction, forecasting that global LNG demand could rise by around 60% by 2040, largely driven by Asian economic growth, the decarbonisation of heavy industry and transport, and the electricity demand associated with artificial intelligence and digital infrastructure. For Namibia, this means the LNG window is real, but it is not automatic. New LNG supply may improve market liquidity, but it also raises the threshold for new projects: cost, emissions intensity, shipping distance, customer credit, project execution and fiscal stability will determine whether Namibian gas can compete.

The Namibian perspective: From discovery to domestic value

From a Namibian perspective, gas commercialisation should be considered across the full value chain. Offshore resources may be monetised through reinjection, offshore power and operations, gas-to-power, domestic industrial use, regional sales, LNG or FLNG export, small-scale LNG, marine bunkering, fertiliser or ammonia production, and other industrial applications. Each route requires different infrastructure, regulatory approvals, offtake commitments and risk allocation.

The BW Kudu project remains the most important historical lesson. The South African Gas Master Plan base case report records that the Kudu gas field, offshore southern Namibia, has proven and probable recoverable reserves estimated at more than 3.3 tcf, but that transporting gas by pipeline from Kudu to South Africa’s East Coast has proven commercially challenging, with studies showing marginal technical and commercial viability. The same report notes that the Namibian Government has indicated a preference to use natural gas for indigenous requirements rather than exportation to South Africa. This history is important: reserves alone are not sufficient. A gas project becomes bankable only when there is a credible route to market, a creditworthy offtaker, a viable tariff or price structure, and a deliverable infrastructure plan.

The more recent Orange Basin discoveries may change the scale of the opportunity, but they do not remove the need for disciplined commercial structuring. Standard Bank’s 2025 discussion document refers to Galp’s 2024 exploration and appraisal campaign in PEL 83, noting that four wells were successful light oil and gas discoveries and that Galp was establishing the feasibility of a single development concept for the north-west element of Mopane. The same document records subsequent 2025 drilling success at Mopane-3X, with light oil and gas condensates found across different drilling targets. These developments reinforce the need to address associated gas early in field development planning, rather than leaving it as a late-stage technical issue.

The practical Namibian question is therefore: what combination of domestic and export markets can support a bankable gas project? Gas-to-power could enhance Namibia’s energy security and ignite plus support aggressive industrialisation, but it will require policy alignment, such as establishment of special economic zones, credible PPAs, grid connection, dispatch arrangements and tariff design. LNG or FLNG could also unlock export revenue, but will require long-term offtake, storage infrastructure, shipping, liquefaction technology, environmental approvals and fiscal stability. Small-scale LNG may make Namibia an attractive destination for mining, logistics, marine and industrial customers, but will need policy and regulatory updates, investment and aggregators, storage, trucking or rail solutions, and customer conversion strategies.

In Namibia, the National Upstream Petroleum Local Content Policy, circulated in final draft form in March 2025, is important in this context. It expressly covers the upstream and midstream segments of the petroleum sector, and to an extent downstream activities directly related to Namibian oil and gas production, while allowing the Minister to expand its scope to other segments of the petroleum value chain and the broader energy sector. It also envisages local content plans, compliance reporting, monitoring by the Ministry of Mines and Energy and prioritisation of local goods, services, skills, technology transfer and Namibian participation across the value chain. Gas commercialisation therefore has to be structured in a way that is bankable and locally developmental: domestic power, logistics, fabrication, industrial gas, port services and long-term operations and maintenance should form part of the commercial design from inception.

Kudu remains a practical warning in this respect. Reuters reported in April 2024 that BW Energy had postponed FID on the long-delayed Kudu gas-to-power project to 2025, with the project having struggled for years mainly because of cost and technical complexity. The same report referred to proven reserves of around 1.3 tcf, an intended 800 MW power development with an initial 420 MW phase, and associated pipeline, power plant, transmission and LNG facility elements. The lesson for Orange Basin gas is that technical discovery must be translated into an integrated commercial package: upstream development, midstream infrastructure, power or industrial demand, financing and government support need to be sequenced together.

Kudu as a route-to-market case study

Wood Mackenzie notes that offshore gas developments such as Kudu face a longer and more complex route to commercialisation than oil projects because gas requires coordinated transport, processing and power infrastructure before production can become commercially viable. This distinction is central to Namibia’s gas policy debate: oil can often move to market through export-oriented systems, while gas must either find a bankable domestic market, connect to regional demand, or be liquefied for export.

The domestic-use pathway is particularly infrastructure intensive. Wood Mackenzie records that if gas is intended for domestic utilisation, complexity increases significantly because the project requires a pipeline to shore, onshore processing facilities, and integration into industrial and power demand. It also emphasises that the power market must be supported by reliable, paying customers. For Kudu specifically, the development would require a pipeline of roughly 200 kilometres to transport gas onshore, with BW Energy expected to carry much of the development burden.

This supports a more cautious interpretation of Kudu’s role. Rather than treating Kudu as a single-project solution to Namibia’s gas ambitions, it should be viewed as a sequencing project: a potential first anchor around which Namibia can gradually build gas-to-power demand, shore-side infrastructure, transmission capacity, local skills and later regional or export optionality. Wood Mackenzie’s comparative analysis suggests that offshore gas developments rarely create domestic gas markets on their own, particularly where fields are deepwater and far from major population or industrial centres. In its analysis of around 15 African offshore gas-producing countries, eight first built domestic demand through smaller onshore or nearshore gas projects, while another five were driven mainly by LNG export projects.

The implication for investors, government and financiers is that Kudu’s bankability will depend less on reserves alone and more on the synchronisation of the full value chain. This includes the field development plan, subsea pipeline, shore base and receiving infrastructure, gas processing, gas-to-power plant, transmission capacity, offtake creditworthiness, tariff design, environmental approvals, and government support. The same article reports that Kudu remains in late pre-development, with appraisal drilling and Front-End Engineering Design (FEED) work underway, a field development plan targeted around mid-2026, final investment decision expected later in 2026, and gas-to-power production near Luderitz targeted around 2027 at an initial 400MW to 420MW, with potential expansion to approximately 800MW.

For a C&C audience, the route-to-market lesson is clear: Kudu will require an integrated bankability package, not merely an upstream development plan. Relevant transaction documents are likely to include gas sales agreements, power purchase agreements, grid connection and transmission arrangements, government support undertakings, implementation agreements, direct agreements with lenders, construction contracts, O&M arrangements, port and land-use agreements, local content plans, and risk-allocation provisions dealing with delay, curtailment, change in law, tariff pass-through and market-demand risk.

The South African perspective: Demand anchor, regional offtake and cautionary tale

South Africa is relevant to Namibia’s gas story for three reasons. First, it is a potential demand centre for regional gas. Secondly, it provides a cautionary example of what happens when demand, infrastructure and policy timelines are misaligned. Thirdly, South Africa’s own Orange Basin and offshore potential may eventually interact with Namibian developments, particularly if shared regional infrastructure becomes commercially viable.

The South African Gas Master Plan base case report notes that South Africa’s natural gas market is small, at approximately 2.6% of the country’s total energy mix, but has the potential to stimulate economic growth, development, stability and job creation. The report also notes that nearly 90% of South Africa’s existing natural gas demand is supplied by a single entity, Sasol Gas, making alternative supply options economically important. It further recognises that one way of breaking the demand-supply impasse is to create anchor natural gas demand through a gas-to-power programme.

IGUA-SA’s 2023 Annual Report is more urgent in tone. It states that high demand for natural gas already outstrips supply and that South Africa is becoming more reliant on natural gas for its future energy requirements while the outlook for supply appears more constrained. It identifies six key challenges, including declining Sasol supply, lack of integrated gas infrastructure plans, lack of gas industrialisation plans, absence of a clear investment framework and misaligned timelines. IGUA-SA also notes that current natural gas supply is heavily dependent on a rapidly depleting Mozambican resource, while longer-term upstream opportunities exist on the East and West Coast, including the Orange Basin.

Standard Bank’s 2025 document frames this as a “gas cliff”, stating that from June 2028, the termination of Sasol’s supply of natural gas and methane-rich gas from the Temane-Pande Gas fields in Mozambique to third parties in South Africa would threaten industries, jobs and potentially force users to switch to more polluting fuels. It also notes that LNG import terminals at Matola in Mozambique and Richards Bay in KZN South Africa could address different parts of the supply gap, but that Utility gas-to-power IPP demand is be needed to support and anchor terminal project finance.

For Namibia, the South African position matters because regional offtake could improve scale and bankability. However, it also warns against relying on demand that is not matched by bankable commitments, infrastructure readiness and regulatory certainty. If South African industrial users, traders or power producers are to become credible customers for Namibian gas, the contractual architecture will need to address delivery point, gas quality, transportation, currency, indexation, take-or-pay obligations, network access, credit support and political risk.

The SADC Regional Gas Master Plan strengthens the regional angle. It identifies a large opportunity for the region to unlock domestic gas resources while meeting energy needs and supporting a lower-carbon development path, and it identifies pipeline infrastructure as relevant where gas resources are close to demand, including from the Orange Basin to the Western Cape. It also suggests that LNG terminals should initially be developed to replace current industrial gas volumes using existing infrastructure as far as possible, after which LNG could be used to substitute diesel in peaking plants on an aggregated basis.

The National Energy Regulator of South Africa (NERSA) policy appendix summarising existing strategic initiatives notes that the SADC plan includes priority projects applicable to South Africa, namely the East Coast to South Africa corridor and the Walvis Bay to Cape Town corridor, and records the risk of an acute shortage of gas for Sasol and industrial customers in the inland region as Pande and Temane Gas Fields decline in Mozambique. This creates a potential strategic interface between Namibian gas, Western Cape demand, South African industrial users and regional LNG optionality. This also aligns with the South African Industrial Development Strategy which focuses on decarbonisation, diversification and digitisation in the competitive global manufacturing and industrial sectors.

Legal and commercial issues for corporate and commercial teams

Natural Gas commercialisation is a corporate and commercial issue as much as an energy policy issue. The projects that emerge from Namibia’s offshore discoveries will likely require joint ventures, farm-ins, unitisation or coordination arrangements, infrastructure sharing, gas sales/supply agreements, processing and transportation agreements, EPC and O&M contracts, port and land arrangements, financing documents and government support arrangements.

In Namibia, upstream rights and development approvals will sit within the petroleum licensing framework, while environmental authorisations, local content commitments, port access, electricity regulation and downstream gas regulation will shape the commercial route to market. Namibia’s draft Gas Bill is relevant because it is intended to establish a national regulatory framework for midstream and downstream gas activities, including licensing and safety, while leaving upstream petroleum activities to the petroleum regulatory framework. That distinction will matter where associated gas moves from the upstream development plan into processing, transportation, storage, distribution or domestic sale.

In South Africa, the legal framework remains more developed but also more complex. The Gas Master Plan base case report notes that the Gas Act 48 of 2001 aims to promote the orderly development of the piped gas industry, establish a national regulatory framework and establish a national gas regulator. It also records that NERSA’s maximum pricing methodology includes a pass-through approach for third-party traders and LNG importers, including acquisition cost, trading cost, margin, shipping and/or regasification costs, transmission tariffs and distribution tariffs. In the upstream space, South Africa’s Upstream Petroleum Resources Development Act 23 of 2024 is intended to provide for orderly petroleum development, state and black participation, third-party access to upstream petroleum infrastructure and strategic stock requirements.

The additional reports therefore point to a practical legal conclusion: natural gas commercialisation cannot be left to policy statements alone. In both Namibia and South Africa, legal workstreams will need to convert resource potential and demand forecasts into bankable agreements. That requires early alignment on regulatory approvals, market rules, third-party access, credit support, tariffs, environmental obligations, local content, currency risk and government support. Without this alignment, the region risks repeating the recurring problem seen across regional gas markets: demand exists, resources exist, but the infrastructure and contractual bridge between them is not financeable, as it is not aligned.

For C&C teams, the key contractual issues include:

(i)      conditions precedent for licence approvals, environmental authorisations, land and port access;

(ii)     (ii) gas ownership and entitlement provisions, especially where associated gas is produced with oil or condensate; (iii) gas utilisation obligations, flaring restrictions and reinjection rights;

(iii)    (iv) take-or-pay and ship-or-pay structures;

(iv)    (v) price indexation, price review and change-in-law mechanisms;

(v)     (vi) infrastructure sharing and third-party access;

(vi)    (vii) credit support, parent company guarantees and debt service reserve structures;

(vii)   (viii) lender direct agreements and step-in rights;

(viii)  (ix) local content, skills transfer and supplier development obligations; and

(ix)    (x) decommissioning, environmental liability and abandonment security.

There is also a competition and market-design dimension. Where common infrastructure is required, investors will need clarity on whether pipelines, processing facilities, terminals or storage assets will be privately controlled, subject to negotiated third-party access, or regulated as open-access infrastructure. This is particularly important where one anchor project is expected to unlock a wider gas market for power, industry and transport.

If Namibia wishes to use Kudu as a platform for domestic gas market creation, government and project counterparties will need to settle how infrastructure is owned, how third-party access is managed, how domestic power and industrial offtake are prioritised, and how public-sector support is documented without undermining bankability. These issues are not merely policy questions; they will determine the allocation of development risk across the upstream operator, power offtaker, transmission utility, lenders, government and local industrial users.

Conclusion: Gas must be designed, not assumed

Namibia’s petroleum opportunity is no longer only an exploration story. It is becoming a development, infrastructure and monetisation story. Gas commercialisation sits at the centre of that transition. If Namibia is able to align upstream development, domestic power demand, industrial offtake, port logistics, local content and export optionality, the natural gas program could support an important broader national value chain rather than being treated merely as a by-product of oil development.

The South African experience, together with the recent IEA, Shell, SADC and Namibian policy materials, reinforces the urgency of planning and then decisive intentional implementation. Demand without related infrastructure development commitments creates vulnerability and uncertainty; infrastructure plans without bankable offtakes are difficult to finance; local content without capacity-building can become a bottleneck; and policy ambition without regulatory clarity may delay investment. Namibia has the advantage of being able to design its natural gas framework at an earlier stage, informed by regional lessons and the evolution of global LNG markets.

For investors, licence holders, service companies, financiers and public sector stakeholders, the immediate priority should be to move from discovery enthusiasm to commercial architecture. That means identifying regional anchor demand, testing and solidifying domestic and regional offtake using frameworks such as the Southern Africa Power Pool (SAPP), https://www.sapp.co.zw/, assessing LNG and FLNG options, clarifying regulatory pathways, embedding local content in procurement and skills plans, and building contracts that allocate risk in a manner acceptable to sponsors, government, lenders and customers. In that respect, natural gas commercialisation is not a secondary issue in Namibia’s oil story. It may be the issue that determines whether the story becomes a bankable, inclusive and long-term energy value chain.