China is closing 2025 with the strongest domestic crude output in its modern history, ending its Seven-Year Action Plan (2019–2025) with measurable gains. National production has risen from 3.8 million b/d in 2020 to an average of 4.3 million b/d in 2025, a roughly 12% increase, driven by accelerated drilling activity, rising unconventional output, and the most significant restructuring of its upstream sector in decades. The expansion reflects Beijing’s strategic aim to strengthen energy security through domestic supply, even as overall demand continues to grow.
The current reshaping of China’s upstream began in 2020, when the government replaced administrative allocation of mining and hydrocarbon rights with a market-oriented bidding and auction framework, later codified under the 2025 Mineral Resources Law. That reform signalled a break from legacy state assignment practices and opened the door for China’s privately owned domestic companies to participate in exploration acreage alongside national champions. In 2025, the Ministry of Natural Resources held six licensing rounds covering 23 blocks, marking the most extensive release of acreage to non-state Chinese operators to date.
These structural changes and rising investment capital have had visible regional effects. Tianjin lifted output from 632,000 b/d in 2020 to 785,000 b/d in 2025, the single largest regional increase, while Xinjiang advanced from 571,000 to 649,000 b/d as deep and tight-reservoir testing expanded. Heilongjiang eased slightly lower from 604,000 to 579,000 b/d, underscoring the maturity of Daqing-era legacy fields and the pressure to replace declining production.
Despite the policy opening to private companies, the industry remains dominated by state-owned enterprises. PetroChina is the largest oil producer, averaging 2.5 million b/d in 2025 and holding around 1.2 million km2 of onshore acreage across the Sichuan, Tarim, Ordos, Junggar, Songliao and Qaidam basins, spanning conventional, tight, and shale developments as the company intensifies unconventional exploration.
CNOOC (China National Offshore Company) has been the standout in output growth, expanding production from 690,000 b/d in 2020 to about 900,000 b/d in 2025, supported by 650,000 km2of offshore acreage across the Bohai Gulf and South China Sea. Although historically an offshore-focused producer, CNOOC has moved to broaden its onshore presence as new plays emerge and the company positions itself against resource concentration risk. Meanwhile, another Chinese oil and gas state-owned major Sinopec (with 600,000 b/d of production in 2025) maintains substantial upstream weight in Sichuan, Tarim, Subei and the onshore Bohai Basin, supported by around 700,000 km2 of onshore acreage and 100,000 km2 offshore, consolidating its role across oil and gas corridors in the country’s southwest and far west.
With the Seven-Year Plan pushing state producers to expand the search for domestic reserves, China’s accelerated exploration is starting to deliver material outcomes. CNOOC’s Bozhong 26-6 discovery in 2023, a shallow-water reservoir in Bohai that happens to be the world’s largest metamorphic-hill play, estimated at 200 million m3 of oil and gas in place, moved from discovery to first production in early 2025 — an unusually fast turnaround for a frontier reservoir. PetroChina’s unconventional program proved equally consequential. In late September 2025, the company confirmed 1.15 billion barrels of shale oil in place in the Gulong zone of the Songliao Basin, expected to peak at 130,000–140,000 b/d, while already in early December PetroChina reported that the block surpassed 1 million tonnes of annual output. In Xinjiang’s Junggar Basin, drilling depths reached 9,056 meters, the basin’s deepest well and the second deepest onshore in China. Sinopec has also entered new resource territory with its Qiluye-1 well in the Sichuan Basin, which tested commercial shale oil and gas at 2,000 meters with state media citing 100 million tons of crude potential, indicating for the first time a commercially viable crude reserve base in Southwest China.
Just as China’s oil and gas resurgence gathers pace, foreign investors have discovered that the door is quietly closing. ConocoPhillips, active in China since the 1980s, now solely retains a 49% stake in parts of the Penglai Oilfield through its Chinese subsidiary after operatorship was transferred to CNOOC in 2014, representing merely a legacy involvement rather than full-scale operation. Chevron, once positioned across multiple offshore PSCs, relinquished its Bohai Gulf and South China Sea blocks and retained interests only in the Chuandongbei sour-gas PSC through its subsidiary, though the final field’s commissioning in June 2025 was described in industry reporting as “the end of Chevron’s legacy” in that project. While foreign companies publicly express interest in participating in China’s new exploration opportunities, Beijing appears largely unmoved by the appeal of foreign capital or technology. No farm-in transactions have been reported, underscoring how geopolitical tension and strict limits on foreign ownership in strategic sectors continue to constrain international access to China’s upstream.
This expansion in domestic production, combined with the opening of acreage to private Chinese firms, might suggest pressure on imports volumes; yet the data tells a different story. China’s seaborne crude imports have held steady at 10.5 million b/d since 2023 (with additional 850,000 b/d of Russian oil delivered through a pipeline), even as national production climbed from 4.0 million to 4.3 million b/d, leaving imports consistently covering around 70–75% of total consumption. The majority of those barrels come from Saudi Arabia, Russia, Iraq, Brazil and Iran, which supply grades tailored to the needs of China’s coastal refining complexes.
Over the past two decades, China’s largest refineries have been designed, expanded or upgraded to process specific imported crude grades – particularly medium and heavy sour barrels – that are more economical for producing fuels and petrochemical feedstock than much of China’s lighter, higher-cost domestic crude. With consumption projected to rise and refinery configurations structurally aligned with foreign grades, imports remain fundamental to supply. New discoveries (whether unconventional onshore or shale, shallow-water or deepwater) require long development cycles before they meaningfully contribute, suggesting that domestic gains will moderate, but not displace import dependence. China is producing more oil at home, but the architecture of its refining system ensures the country must continue buying most of it abroad.
China enters 2026 with a stronger domestic production base, a more diversified set of operators, and momentum in unconventional and offshore exploration. CNOOC’s drilling campaign in Bohai Bay shows no sign of slowing, and the company is likely to add another 40,000 b/d in 2026 after three years of stable growth. PetroChina is still willingly meeting the targets set in Beijing, yet its own reports highlight the uncomfortable trade-off behind the acceleration: its resource base has shrunk by a net 200 million barrels in the past three years, indicating production is exceeding the speed of reserve additions. The faster China accelerates its upstream push, the sooner – and sharper – the turn towards its inevitable decline will be.
For now, however, the trajectory remains upward. China has cemented its position as the world’s sixth-largest oil producer, lifting output by around 100,000 b/d year-on-year in 2025, and another nationwide increase of at least 70,000 b/d appears within reach thanks to CNOOC’s and PetroChina’s ambitious drilling targets. Lasting shift or high-speed prelude to slowdown, China’s upstream revival is heading into the phase that will expose its resilience and potential to grow – or its ceiling.
By Natalia Katona for Oilprice.com
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