China's first standalone oil & gas five-year plan shifts the focus from volume to security and transition

Security first, with the transition running alongside

Crude import dependence above 70% and rising geopolitical risk keep energy security at the top of the agenda. China's domestic oil and gas supply is set to reach a floor of 440 million tonnes of oil equivalent by 2030, up from 420 million in 2025. With crude output held above 200 million tonnes a year and natural gas adding more than 38 bcm over five years, upstream capital spending is unlikely to fall sharply after 1.94 trillion RMB was invested in 2021-2025. Eight strategic oil and gas bases, including the newly added northern South China Sea base, become the focus of policy and investment. It is also the first oil and gas plan to say that oil demand will peak. Policymakers want the shift to be gradual and controlled, with no sudden shock to the industry, which explains why capacity exits are described as measured.

Peak demand, with refining capacity replaced and upgraded

Industry consensus places China's oil demand peak around 2026, at 770-780 million tonnes. Sinopec's economics research institute projects gasoline and diesel falling from about 50% of oil demand in 2025 to about 42% in 2030, while chemical feedstocks climb from 22% to 30%. Even so, the plan calls for a moderate surplus of refining and petrochemical capacity to support supply security and export competitiveness. Peak demand works as a ceiling on capacity and the moderate surplus works as a floor, so the real story is how production capacity gets replaced. Roughly 15% of refining production capacity sits below the baseline, with 146 million tonnes a year needing upgrades over 2026-2028 and final deadlines for outdated capacity exits at end-2028 and end-2029. Crude distillation units below 10 million tonnes a year and ethylene units below 0.8 million tonnes a year face mandatory upgrade or closure, and refineries of 10 million tonnes a year or more are expected to lift their share of national production capacity from 57% in 2025 to 64% in 2030.

The chemical side points the same way. Europe, Japan and South Korea are set to retire more than 20 million tonnes a year of ethylene capacity over the next decade, and CNPC's economics and technology research institute estimates potential 2030 exports of seven major chemical products at around 35 million tonnes, up more than 20 million tonnes from 2025. With export rebates removed for 249 low-value basic chemical products from April 2026, policy is steering exports toward higher-value, lower-carbon products.

Natural gas takes the bridge-fuel role

Natural gas is the only fossil fuel still positioned for demand growth, although GL Consulting expects annual growth to slow to about 3.5% over the 15th Five-Year Plan period, down from 5.5% in the 14th. Peak-shaving gas power and LNG heavy trucks and waterway transport supply the clearest incremental demand. Import capacity keeps expanding by 2030, with pipeline import capacity rising from 103 to 114 bcm a year and LNG receiving capacity from 170 to 200 million tonnes a year, while LNG expansion is prioritised and new-build approvals stay selective. Terminals shift from import gateways to storage and peak-shaving assets, with gas storage targeted above 13% of consumption by 2030 from 12.7% in 2025. Multi-year contracts with flexible terms are encouraged, which raises procurement flexibility and puts pressure on take-or-pay agreements.

Pipelines become multi-energy networks

For the first time, the nationwide unified pipeline network extends beyond oil and gas to include green hydrogen, ammonia and methanol. The plan names a 1,200 km hydrogen pipeline from Ulanqab to the Beijing-Tianjin-Hebei region as the first strategic cross-regional hydrogen line, and calls for pilots of hydrogen blending in gas pipelines and methanol transport through refined-product pipelines within three to five years. Existing pipeline assets are likely to be revalued as they take on multipurpose roles, and ageing oil and gas fields are set to become integrated hubs combining power, heat, storage and carbon.

The trade implications are significant. Green hydrogen costs in northwest China are estimated at roughly half overseas levels, and pipeline access lowers the cost of moving that supply toward coastal export markets. The economics still need time, green hydrogen in northwest China costs about half the overseas level, so pipeline access helps exports, although green fuels still cost more than fossil fuels and large-scale use is further away. As green fuels scale after 2030, trade pricing is likely to shift from oil price toward carbon price and electricity price.

CCUS receives its first national target

The plan sets the first quantitative CCS/CCUS target in a national five-year plan: 10 million tonnes of CO2 injection a year by 2030, more than triple the roughly 3 million tonnes of 2025, with regional clusters in Dongying and Yulin leading the build-out. Economics remain the constraint, low carbon prices have yet to make the business model work, and cost reduction depends on carbon pricing and on aggregating CO2 sources across sectors.

Where the opportunities and risks sit

GL Consulting's impact assessment sees pipeline and network operators and gas power plants for grid balancing as the strongest beneficiaries, followed by LNG terminals, gas storage, hydrogen, CCUS and AI-based oil and gas services. Traditional small and mid-sized refineries score lowest. Private and foreign investors gain ways in through midstream infrastructure and upstream exploration, and large integrated refining and new-materials companies look better placed than independent refineries that focus on fuel. The end-2028 and end-2029 capacity clearance deadlines are the events to watch.

Some things remain uncertain: whether households will accept higher gas prices, whether gas storage can earn a return, and whether carbon prices will be high enough to bring CCUS costs down. The order of events matters too, with policy reform first over the next one to two years, infrastructure and capacity changes in years three to five, and new technology at scale after that.

The 15th Five-Year Plan for Oil & Gas Development changes the question put to the industry, from how much to produce and import to what role oil and gas play in a system that is peaking and decarbonising. For companies operating in China, sector value increasingly sits in structure, meaning integrated refining and materials, multi-energy pipeline and storage infrastructure, and market access, with volume growth playing a smaller part. For investors and traders, the clearest opportunities over the next three to five years look concentrated in pipeline and gas storage infrastructure, integrated refining and chemicals leaders as legacy capacity clears, and early positions in hydrogen, ammonia, methanol and CCUS as carbon and electricity prices begin to shape trade economics.

The above content is the major conclusions and highlights extracted from the "Oil & Gas 15th FYP: China Pivots from Supply Growth to Energy Security and Green Transition" chapter of the latest China Policy Perspective (produced by GL Consulting).

The full chapter includes detailed sector-by-sector demand and cost modelling, provincial risk mapping, and strategic recommendations for investment, trading and capital allocation.

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