Petrovietnam: From Offshore Oil to the LNG Import Age

Petrovietnam is what a national oil company becomes when the oil starts running out but the state still needs it to do everything. It drills, refines, distributes fuel, runs gas pipelines, generates electricity, builds offshore structures for foreign wind farms, and has now been told to build a nuclear power plant. Along the way it lost billions on failed investments, saw its leadership prosecuted, was pushed out of its own waters by Chinese pressure, and became the anchor of Vietnam’s LNG import strategy. This article traces how the group works, where its money comes from, and what its new role means for investors and operators in Vietnamese energy. It is part of the Vietnam Company Stories hub.

How did Petrovietnam start, and why did Bạch Hổ matter so much?

Petrovietnam was created in 1975 as a general department for oil and gas, but the company as an economic force dates from 1981, when the Vietsovpetro joint venture with the Soviet Union was formed, and from 1986, when Vietsovpetro produced the first oil from the Bạch Hổ field off Vũng Tàu. For the next twenty years Bạch Hổ carried the state.

Bạch Hổ, meaning White Tiger, was unusual: its oil sat in fractured granite basement rock rather than in conventional sandstone, which most Western geologists had dismissed as unlikely to hold hydrocarbons. Soviet engineers drilled into the basement anyway and found one of the largest fields in Southeast Asia. At its peak in the early 2000s, it was producing on the order of 250,000 barrels a day, and with associated fields it accounted for the great majority of Vietnamese crude output.

The revenue transformed the state’s finances. Crude exports were the largest single hard-currency earner through the 1990s, and oil-related taxes, royalties and Petrovietnam’s own profits contributed roughly a quarter of the state budget at the peak in the mid-2000s. Vietnam had no refinery until 2009, so it exported crude and imported refined products, a trade that made Petrovietnam the largest company in the country by revenue and the closest thing Vietnam had to a sovereign wealth engine.

The dependence on a single field had an obvious expiry date. Vietnamese crude output peaked at about 20 million tonnes, roughly 400,000 barrels a day, around 2004, and has declined since to about 8 million tonnes. Bạch Hổ is now in late life, producing a fraction of its peak, and the group’s subsequent history is largely the story of what it tried to do about that.

What does the Petrovietnam group actually consist of?

The parent holds controlling stakes in a dozen major subsidiaries spanning the value chain: PVEP for exploration and production, PV Gas for gas transmission and LNG, Bình Sơn Refining for the Dung Quất refinery, PV Oil for fuel distribution, PV Power for generation, PTSC for offshore engineering, PV Drilling for rigs, and PVFCCo and PVCFC for fertiliser.

Several of these are large listed companies in their own right. PV Gas, ticker GAS, is one of the most valuable companies on the Ho Chi Minh City exchange, with a near-monopoly on gas transportation from the southern offshore fields to the power plants and industrial users around Ho Chi Minh City, and a profit stream that has funded much of the group’s dividend to the state. PV Power, ticker POW, is the country’s second-largest generator after EVN. Bình Sơn, PV Oil, PTSC and PV Drilling are also listed, giving investors partial exposure to the group even though the parent is wholly state-owned, a structure examined in the wider stock market upgrade story.

Upstream remains anchored in joint ventures with foreigners. Vietsovpetro, now shared with Russia’s Zarubezhneft, still operates Bạch Hổ and neighbouring fields. Other production comes from blocks operated by or with Japan’s Idemitsu and Mitsui, Thailand’s PTTEP, Russia’s Gazprom and Rosneft, Malaysia’s Petronas, and, for the giant Blue Whale gas field off central Vietnam, ExxonMobil, whose project has been stalled for years over gas pricing and offtake.

The group also carries the residue of its diversification years: stakes in shipbuilding, insurance and construction that were meant to be divested under repeated government equitisation plans and have only partly been sold.

What happened during the corruption purge of 2017 and 2018?

In 2017 and 2018 the anti-corruption campaign led by then General Secretary Nguyễn Phú Trọng reached the top of Petrovietnam. Former chairman Đinh La Thăng, by then a Politburo member, was sentenced to a combined 30 years in prison, and former construction subsidiary chief Trịnh Xuân Thanh was seized in Berlin and sentenced to life.

The charges related to the group’s expansion in the late 2000s under Thăng’s chairmanship. Petrovietnam had invested VND 800 billion in Ocean Bank, a private lender that later collapsed and was taken over by the State Bank for zero dong, wiping out the investment, an episode covered in the bad-debt and zero-dong banks story. Its construction subsidiary PVC, run by Trịnh Xuân Thanh, had lost more than VND 3 trillion on projects including the Thái Bình 2 power plant, which ran years over schedule. Investments in Venezuela, where Petrovietnam had committed to a heavy-oil joint venture that never produced meaningful returns, and in loss-making fibre and ethanol plants added to the write-offs.

The Berlin episode became a diplomatic incident. Thanh had fled to Germany and applied for asylum; in July 2017 he was abducted from a Berlin park by Vietnamese agents and appeared in Hanoi days later, ostensibly having surrendered. Germany expelled Vietnamese diplomats and suspended its strategic partnership. Thanh was convicted twice, receiving life sentences for embezzlement and mismanagement.

The purge continued through the group’s subsidiaries for years, with dozens of former executives prosecuted, and it left a generation of managers cautious to the point of paralysis. Decisions on new investment slowed, foreign partners found approvals harder to obtain, and the group’s reputation with international lenders took the better part of a decade to recover. The episode also shaped the later scrutiny of EVN and the solar sector, described in the solar boom story, where inspections followed the same template.

Why did Vietnam build refineries, and did they work?

Vietnam built refineries to stop exporting crude and importing petrol, a trade that cost foreign exchange and left fuel prices hostage to Singapore benchmarks. Dung Quất, opened in 2009, has broadly succeeded; Nghi Sơn, opened in 2018 with Kuwaiti and Japanese partners, has been a persistent financial problem.

Dung Quất, in central Quảng Ngãi province, was placed there for regional development reasons rather than logistics, far from both the southern oilfields and the northern demand centres. It cost about $3 billion and was delayed for years after foreign partners including Total and Zarubezhneft withdrew, leaving Petrovietnam to build it alone with French and Japanese contractors. Once running, it supplied roughly a third of national fuel demand and its operator, Bình Sơn Refining, became consistently profitable in normal years, though its margins swing violently with crude prices, as the 2020 pandemic losses showed.

Nghi Sơn, in Thanh Hóa, was a different model: a $9 billion joint venture in which Kuwait Petroleum and Japan’s Idemitsu each hold about 35 percent, Mitsui 5 percent and Petrovietnam 25 percent, processing Kuwaiti crude. The government granted it a guaranteed offtake arrangement under which Petrovietnam must buy its output at import-parity prices, and a tax incentive that requires the state to compensate the refinery if import tariffs fall below a set level. Since opening the plant has reported large cumulative losses, and Petrovietnam has had to fund shortfalls and negotiate repeated restructurings with its partners and lenders; in 2022 a dispute over funding briefly disrupted supply and contributed to fuel shortages at petrol stations.

The two refineries together cover roughly 70 percent of domestic fuel demand, which is a genuine strategic gain, but the Nghi Sơn structure illustrates how state guarantees to attract foreign capital can become open-ended liabilities.

How is Petrovietnam building Vietnam’s LNG import chain?

PV Gas built and commissioned the Thị Vải LNG terminal near Vũng Tàu, receiving the first cargo from Shell in July 2023, and PV Power built the Nhơn Trạch 3 and 4 combined-cycle plants, which together are the country’s first LNG-fired generation and reached commercial operation in 2025. This is the template for the gas bridge in the national power plan.

The need is structural. The southern gas fields that have fed the Phú Mỹ and Nhơn Trạch power complex since the late 1990s — Nam Côn Sơn, Cửu Long — are in decline, and the two large new domestic sources, Block B in the Gulf of Thailand and Blue Whale off Quảng Nam, have been delayed for more than a decade. Block B finally reached final investment decision in March 2024, with Mitsui’s MOECO and PTTEP as partners and first gas targeted for 2027 to feed the Ô Môn power complex near Cần Thơ, a project of roughly $12 billion across upstream, pipeline and plants. Blue Whale, with ExxonMobil, remains stalled over gas pricing.

LNG fills the gap in the meantime. Thị Vải has an initial capacity of 1 million tonnes a year, expandable to 3, and PV Gas has signed term supply arrangements alongside spot purchases. A second terminal at Sơn Mỹ in Bình Thuận, a joint venture with AES of the United States, has been planned for years and has yet to reach financial close; other terminals proposed by private groups in the north and centre are at earlier stages.

The commercial difficulty sits at the interface with EVN, whose finances are examined in the EVN story. Nhơn Trạch 3 and 4, costing about $1.4 billion, spent over a year negotiating a power purchase agreement because EVN would not commit to the minimum offtake and fuel pass-through that the plant’s lenders required. The agreement eventually signed in 2024 set a framework that later LNG projects are now trying to replicate, but the episode showed that even a state generator selling to the state buyer cannot assume the terms will be easy.

How has the South China Sea dispute shaped the group?

Chinese pressure has forced Petrovietnam and its partners to abandon or suspend exploration in several blocks within Vietnam’s own claimed exclusive economic zone, most visibly when Spain’s Repsol was ordered to halt drilling in 2017 and 2018 and Petrovietnam later paid compensation reported at close to $1 billion.

The pattern is consistent. Blocks on the outer edge of Vietnam’s continental shelf overlap with China’s claimed nine-dash line. When foreign partners have moved to drill, Chinese coastguard and survey vessels have appeared, and Hanoi, unwilling to risk a confrontation, has quietly instructed the operator to stop. Repsol’s Cá Rồng Đỏ project was the most expensive casualty; Rosneft’s block off the south-east faced similar pressure in 2019 during the Vanguard Bank standoff, and Rosneft later sold its Vietnamese assets to Zarubezhneft.

The effect is a shrinking of Vietnam’s realistic exploration frontier. The shallow-water basins near shore are mature; the promising deep-water acreage is contested. This has accelerated the shift towards imported LNG and towards gas fields in undisputed waters such as Block B, and it has increased the importance of partners with political weight — Japanese, Russian, Indian and Malaysian companies whose governments Beijing has reason not to antagonise.

It has also pushed the group into new lines of business where the seabed is less contested. PTSC, the offshore engineering subsidiary, has become a major fabricator of foundations and substations for offshore wind farms in Taiwan, Denmark and the Baltic, a business that uses its Vũng Tàu yards and marine expertise without depending on Vietnamese hydrocarbons. The offshore wind story describes how PTSC is also now the government’s chosen developer for the first domestic offshore wind projects.

What is the new mandate, and can the group deliver it?

In 2025 the group was renamed the Vietnam National Industry–Energy Group, given responsibility for the Ninh Thuận 2 nuclear plant, designated to pilot offshore wind through PTSC, and confirmed as the lead developer of the LNG chain. It is being asked to become the state’s energy-transition contractor, on top of everything it already does.

The rename is not cosmetic. It reflects a decision at the top of the party that the state needs a champion capable of executing large, complex, capital-intensive energy projects, and that among the state enterprises only Petrovietnam has the engineering depth, the international partnerships and the balance sheet to attempt it. The group reported record revenue of roughly VND 1,000 trillion, about $40 billion, in 2024 and contributed on the order of VND 165 trillion to the state budget, which gives it credibility that EVN, with its recent losses, lacks.

Whether it can deliver nuclear is a different question. Vietnam’s earlier programme, with Rosatom for Ninh Thuận 1 and a Japanese consortium for Ninh Thuận 2, was cancelled in 2016 on cost grounds after a decade of preparation. Restarting it means renegotiating with foreign vendors, rebuilding a regulatory framework, training a workforce and finding financing on the order of $10 billion or more per plant. Petrovietnam has built refineries and power plants, but nothing of that regulatory complexity, and the timeline of the mid-2030s is widely regarded as optimistic.

The offshore wind pilot is more within reach. PTSC has already surveyed a site off the south for a project intended to export power to Singapore in partnership with Sembcorp, and it has the fabrication and marine capability. What it lacks is a tariff, a grid connection framework and, for the domestic project, an offtaker willing to sign. These are the same gaps that drove foreign developers such as Ørsted and Equinor to leave Vietnam, and assigning the project to a state company does not by itself close them.

What does Petrovietnam’s story mean for founders, investors and operators?

For investors, Petrovietnam is accessible only through its listed subsidiaries, each of which carries a different slice of the risk; for operators, it is the counterparty for gas, fuel and increasingly offshore services; for policymakers elsewhere in the region, it is a study in how a national oil company survives the end of its oil.

The listed subsidiaries are the practical entry point. PV Gas offers exposure to the LNG build-out with the cushion of regulated pipeline margins; PV Power to gas-fired generation with EVN as counterparty; PTSC to the regional offshore wind supply chain; Bình Sơn to refining margins. Each has state-controlled governance, limited free float and dividend policies set with the parent’s needs in mind, and each has, at some point in the past decade, been touched by the anti-corruption campaign. The pricing of that governance risk is the central question for any position.

For businesses that depend on the group, the lesson of the 2022 fuel shortage and the Nhơn Trạch negotiation is that even a strong state enterprise operates within political constraints that can interrupt supply or delay contracts. Manufacturers who rely on piped gas around Ho Chi Minh City should understand that the domestic fields are declining and that LNG-linked pricing is coming; distributors who rely on Petrovietnam fuel should understand the stabilisation fund politics.

The wider lesson is about state capitalism in Vietnam. The government has chosen to route the energy transition through two state groups, EVN and Petrovietnam, rather than through a liberalised market, and has given Petrovietnam the harder half of the job. How the group performs on LNG, Block B and the first offshore wind project between now and 2030 will tell foreign investors more about the bankability of Vietnamese energy than any decree.

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