In 2025, China’s engagement in countries signed up to the Belt and Road reached its highest level since the initiative’s launch, driven by a sharp uptick in oil and gas deals.
Energy engagement, including both investment and construction contracts, reached USD 93.9 billion last year – more than double that of 2024, according to a report by the Green Finance and Development Center. Oil and gas alone accounted for roughly USD 71.5 billion of the total, tripling previous records and making up 74% of overseas energy engagement, the highest fossil-fuel share since 2014.
While this macro-data appears to signal a major return to oil and gas, a closer look reveals a more nuanced structural shift. In harmony with host government goals, Chinese firms are trying to capture more value from energy resources, spanning production, processing and power infrastructure. Rather than simply securing direct equity stakes in oil and gas fields, they are leveraging service-driven engineering, procurement and construction (EPC) models, in which a single contractor has total responsibility for a project.
Yet this shift leaves a significant question mark over the future. It remains to be seen whether the long-lived, carbon-intensive assets that formed much of China’s energy engagement last year can ultimately survive tightening global environmental regulations, changing trade rules and localised governance challenges.
Megadeals in Nigeria and Congo
The 2025 figures do not signal a broad, high-volume wave of new oil and gas projects. Instead, the boom was highly concentrated, with two deals accounting for about 60% of the USD 71.5 billion total: the Ogidigben industrial park in Nigeria, and oil and gas development in the Republic of the Congo.
The USD 20 billion Ogidigben project is planned to involve gas processing and supporting infrastructure, power generation, aluminium smelting and the production of fertiliser, petrochemicals and methanol. China National Chemical Engineering International Corporation’s role in the project is tied to development, financing and construction, rather than acquiring an equity stake in upstream assets.
Meanwhile, the Republic of the Congo signed a USD 23 billion agreement with China’s Wing Wah to develop the Banga Kayo, Holmoni and Cayo oil and gas permits, including onshore fields and associated production infrastructure. While anchored in upstream oil and gas production, it incorporates processing infrastructure for LPG (liquid petroleum gas), butane, propane, LNG (liquefied natural gas), on-site power generation and water management systems. It is not clear where the outputs will be sold, though Congo’s oil sector is already export-oriented, with China among its major markets.
The commercial logic for Chinese firms is not simply to secure hydrocarbons for domestic use as fuels and feedstocks. It is also to build infrastructure, sell equipment and engineering services, and participate in a long-term project cycle that aligns with host-country priorities, such as Nigeria’s ambition to use gas for domestic industrial development.
Divers and shifting financial models
One reason these projects are moving forward now is demand from host countries, which takes different forms.
In Nigeria, the logic is primarily downstream industrialisation: gas is not only treated as an export commodity, but as a feedstock for fertilisers, petrochemicals, power generation and industrial production. In Congo, the Wing Wah agreement is more directly tied to upstream oil and gas production, while also including gas-based derivatives intended for both domestic use and exports. In both contexts, Chinese companies can offer something that is politically attractive: not just capital, but an integrated package of EPC, equipment and project delivery.
Across the BRI, construction contracts accounted for about 60% of Chinese engagement in 2025, compared with about 40% for investment, according to the report. The pattern was even more pronounced in energy, where construction deals made up around 80% of engagement. Within oil and gas, the picture is not uniform: major investments remain, but gas-related activity was largely construction-based, with no gas-related equity investments identified. This indicates that in the 2025 surge, Chinese firms were prioritising service delivery – such as construction, equipment supply and financing – while choosing carefully when to take on the risks of owning a share of the oil or gas itself.
This project-delivery model is highly relevant as western public-finance institutions and export credit agencies have tightened restrictions on fossil-fuel projects. The Clean Energy Transition Partnership, launched at the COP26 climate conference in 2021, commits signatories to end new direct public support for the international unabated fossil-fuel energy sector, except in limited circumstances consistent with the Paris Agreement. That, in turn, has helped create space for actors outside this sphere willing to provide project delivery, equipment and financing.
But it does not mean western capital has disappeared from oil and gas. Western companies remain active, especially in offshore and integrated gas segments where they see stronger strategic or commercial fit. When Shell, for example, completed the sale of its Nigerian onshore subsidiary in 2025, it said the move would help focus its Nigerian portfolio on deepwater and integrated gas positions.
Western capital’s appetite for large, politically complex, or risky onshore fossil-fuel infrastructure has, however, narrowed. Chinese firms are well positioned to operate in this space given their experience in EPC, equipment supply and large-scale project delivery. State-owned enterprises tend to be more active in construction-oriented engagement, while private firms appear more likely to take direct investment exposure in selected cases, the report notes. This allows Chinese firms to capture returns through service contracts and project delivery, while taking full ownership or direct resource exposure more selectively.
The BRI financial model has evolved. The early era of large, sovereign-backed loans has given way to a more constrained environment due to host-country debt pressures and a more cautious Beijing. The current model is more selective; in some cases, risks are shifted toward project revenues, private developers, resource-backed arrangements or local partners, notes Yan Liang, senior fellow at Boston University’s Global China Initiative.
Emerging regulatory and trade challenges
For host countries, gas-based industrial projects can offer a clear development case. They can support fertiliser production, power supply and local manufacturing, while reducing dependence on imported industrial inputs. This is why they can often retain domestic political appeal even as international climate finance moves away from fossil fuels.
However, these enduring, carbon-intensive assets face shifting trade and regulatory environments. The European Union’s Carbon Border Adjustment Mechanism (CBAM), an import tax on goods with a large carbon footprint, entered its definitive period in 2026, directly affecting commodities like fertiliser and aluminium. If projects such as Ogidigben produce goods that fall under CBAM’s scope and seek access to European markets, carbon intensity could become a trade-competitiveness issue. Over time, carbon-related border measures and buyer standards may influence market choices, potentially pushing exports towards destinations with fewer carbon-related border costs.
China’s own trade policy could reinforce that possibility. In May, China expanded zero-tariff coverage to the 53 African countries with which it maintains diplomatic relations. For producers facing tighter access to European markets, China could therefore become an even more important destination.
Additionally, localised environmental governance remains a critical issue. Large gas, petrochemical and oil projects require strong regulation on emissions, water use, methane leakage, pollution control, land use and community impacts. In countries where regulatory capacity is limited, the risks are not only climate-related but also local. Pollution, weak disclosure, uneven benefit-sharing and long-term liabilities may outlast the original political enthusiasm for these projects.
While the scale of 2025, with its rare megadeals, is unlikely to be repeated, the underlying pattern will persist: Chinese firms may continue to pursue oil and gas projects where host-country industrialisation plans, project-level returns and risk-sharing structures make them commercially attractive.
Last year’s surge represents an evolution toward a more diversified model that integrates fossil resources with local industrial infrastructure. Its ultimate success depends on whether it can deliver genuine developmental gains without burdening host nations with opaque financing and obsolete, high-emission assets. That is the central tension in China’s new overseas oil and gas push: it may help build the industrial systems host countries want, but may also lock them into assets whose economic and environmental future is increasingly uncertain.
