EVN: The Monopoly That Keeps the Lights On and Loses Money Doing It

EVN is the most important company in Vietnam that almost nobody outside the country can name, and it is structurally designed to lose money. Every Samsung phone, every pair of Nike shoes and every Hoa Phat steel coil made in Vietnam runs on electricity that passes through EVN’s wires at a price the Prime Minister approves. The company is simultaneously an industrial policy tool, a social subsidy mechanism, and a balance sheet that the Ministry of Finance would rather not look at too closely. This article explains how the monopoly works, why it bleeds cash, what the 2023 power crisis changed, and what the slow shift towards a competitive market means for anyone building or financing anything in Vietnam. It is part of the Vietnam Company Stories hub.

How did EVN become Vietnam’s electricity monopoly?

EVN was created in 1994 when the government consolidated regional power companies into a single state corporation, and it was elevated to an economic group in 2006. It inherited the entire grid, all state generation and every customer relationship, and no subsequent reform has removed its position as sole buyer and sole transmitter.

The consolidation made sense at the time. Vietnam in the early 1990s had three barely connected regional grids, chronic shortages and no capital markets. A single state entity could borrow from the World Bank, the Asian Development Bank and Japanese development finance, build the 500 kV north-south backbone (completed in 1994, the same year EVN was formed), and electrify the countryside. By the mid-2010s Vietnam had achieved near-universal electricity access, one of the fastest electrification stories in Asia and a genuine EVN achievement.

The structure that delivered that result is the same one that causes today’s problems. EVN sits under direct government control — first the Ministry of Industry and Trade, then from 2018 the Commission for the Management of State Capital at Enterprises, and since that commission was dissolved in early 2025, the Ministry of Finance. Its chairman and chief executive are political appointments. Its tariff is a government decision. Its investment plan is a government plan. It is, in effect, a department of state that publishes financial statements.

That makes EVN a useful lens on the broader question of how state and private capital divide the Vietnamese economy, a theme explored across the state giants versus private empires story. Unlike Vinamilk or Vietcombank, EVN has never been partially privatised at the parent level, and there is no serious plan to do so.

What does the single-buyer model actually look like in practice?

In practice, every power plant in Vietnam — state, private or foreign — sells its output to EVN or an EVN subsidiary under a power purchase agreement, and EVN alone resells it to end users. Generators cannot choose their customer, and customers, until 2024, could not choose their generator.

The generation side has been partially unbundled. EVN’s three generation corporations, GENCO 1, 2 and 3, were carved out in 2012, and GENCO 3 and GENCO 2 were partially equitised in 2018 and 2021 respectively, though EVN retains overwhelming control. The large strategic hydropower plants — Hòa Bình, Sơn La, Lai Châu on the Đà River — remain directly under EVN. Outside EVN, the state-owned Petrovietnam (through PV Power) and Vinacomin (through its coal-fired plants) are the other large generators, followed by a long tail of private and foreign-invested plants, including the build-operate-transfer coal stations financed by Japanese and Korean lenders and the solar and wind farms built in the 2019–2021 rush.

The transmission side is entirely EVN. The National Power Transmission Corporation (NPT) owns and operates all 500 kV and 220 kV lines, and by law transmission was a state monopoly until the 2022 amendment to the Electricity Law opened the door to private investment in some grid assets. Distribution is handled by five power corporations — Northern, Central, Southern, Hanoi and Ho Chi Minh City — all wholly owned by EVN.

A wholesale electricity market, the VWEM, has operated since 2019, in which generators bid into a day-ahead pool. But since EVN’s power trading company is the only buyer, the market functions more as a dispatch-optimisation tool than as a price discovery mechanism. The retail market pilot that was supposed to follow has been repeatedly deferred.

Why does a monopoly with 30 million captive customers lose money?

EVN loses money because its selling price is fixed by the government for social and industrial-policy reasons, while its buying price floats with coal, gas and hydrology. In 2022 and 2023 the average cost of power EVN purchased exceeded the average price at which it was allowed to sell it.

The numbers are stark. EVN reported a consolidated loss of roughly VND 20.7 trillion for 2022 and a further loss of about VND 21.8 trillion for 2023, with the parent company’s accumulated losses reaching somewhere in the region of VND 47 trillion by the end of 2023, according to the company’s own disclosures and Ministry of Industry and Trade audits. The 2022 loss followed a spike in imported coal prices after the invasion of Ukraine; the 2023 loss was compounded by a severe drought that cut hydropower output, forcing EVN to run more expensive coal and oil-fired plants and to buy gas at spot-linked prices.

The tariff design deepens the problem. Vietnam’s retail tariff structure charges industrial users less than the average cost of supply during off-peak hours, and charges households on a six-tier escalating scale that keeps the first tiers very cheap. The government has explicitly used low industrial tariffs as a competitiveness tool to attract foreign manufacturing, as the Samsung Vietnam story illustrates: an average industrial tariff of roughly 7 to 8 US cents per kilowatt-hour is among the lowest in Southeast Asia. That subsidy is real, and EVN is the entity that pays for it.

There is a second, subtler loss. Because EVN’s balance sheet was weakening, its ability to borrow for grid investment on reasonable terms diminished exactly when the country needed the most grid investment in its history. Loss-making utilities do not build transmission lines quickly, and the consequence arrived in June 2023.

What happened when the lights went out in June 2023?

In late May and June 2023 northern Vietnam suffered rolling blackouts that shut factories in Bắc Ninh, Bắc Giang and Hải Phòng for hours or days at a time. The World Bank estimated the economic cost at roughly $1.4 billion, about 0.3 percent of GDP, and it triggered the most serious reckoning in EVN’s history.

The immediate causes were a heatwave that pushed demand to record levels, a drought that left the northern hydropower reservoirs near dead storage, several coal units out of service, and a shortage of coal at some plants. But the structural cause was a grid that could not move enough power from the south, where the solar boom had created a surplus, to the north, where the industrial parks were. The 500 kV north-south backbone was operating at its limit, and a third circuit that had been on the planning books for years had never been financed.

The political response was fast. The Prime Minister ordered an inspection of EVN and the Ministry of Industry and Trade; the inspection found failings in planning, fuel procurement and reservoir management. EVN’s chief executive Trần Đình Nhân was removed in 2023 and several senior officials at the system operator were disciplined. The National Load Dispatch Centre, the body that physically runs the grid, was transferred from EVN to the Ministry of Industry and Trade in 2024 and renamed the National Power System and Market Operator, a symbolic break in EVN’s control of dispatch.

The most visible response was the 500 kV Quảng Trạch–Phố Nối transmission line, about 520 kilometres of double-circuit line across nine provinces. Normally such a project would take three to four years. Under direct prime ministerial pressure it was built in roughly six months and energised in August 2024, with provincial authorities clearing land at a pace that would have been unthinkable without the blackouts as motivation. It is now the clearest example in Vietnam of what the state can do when it decides something is a national priority.

How has the government tried to fix EVN’s finances since 2023?

The core fix has been price. Retail tariffs rose 3 percent in May 2023, 4.5 percent in November 2023, 4.8 percent in October 2024 and a further 4.8 percent in May 2025, bringing the average tariff to about VND 2,204 per kilowatt-hour, and EVN returned to a profit in 2024.

Alongside the increases, the rules for setting tariffs were loosened. A 2024 decision allowed EVN to adjust the price every three months if costs moved by 3 percent or more, and a 2025 decree shortened the interval to two months and gave EVN authority to implement increases of under 5 percent without a separate government decision. The declared goal is a cost-reflective tariff by the end of the decade; the practical reality is that each increase is still a political event, announced with careful messaging about the impact on households and inflation.

EVN has also pushed cost onto its suppliers where it could. It negotiated lower transitional tariffs with the solar and wind projects that missed the feed-in tariff deadlines, held back payments to projects with incomplete acceptance paperwork, and resisted pricing terms sought by the new LNG-fired plants. The wider dispute over those renewables tariffs is told in the solar boom story; from EVN’s side, every cent per kilowatt-hour paid to a generator is a cent it may not be allowed to recover from customers.

The reported turnaround should be read carefully. EVN’s 2024 profit came from the tariff increases, favourable hydrology after the 2023 drought, and softer international coal prices, not from a change in the fundamental structure. A bad hydrological year combined with a spike in LNG prices would push the company back into loss unless tariffs move in step, and the accumulated deficit from 2022 and 2023 has not been fully recovered.

What is the Direct Power Purchase Agreement and why does it matter?

The DPPA mechanism, enacted by Decree 80 in July 2024, lets large electricity consumers buy power directly from renewable generators instead of only from EVN. It is the first breach in EVN’s retail monopoly and was pushed hardest by foreign manufacturers under pressure to source clean energy.

There are two forms. In the physical DPPA, a generator sells to a consumer over a private line, bypassing EVN’s grid entirely; this is rare and mostly relevant to rooftop or adjacent-site projects. In the virtual DPPA, the generator sells into the wholesale market, the consumer buys from EVN at a market-linked price, and the two settle the difference under a bilateral financial contract, with EVN charging for use of the grid. This is the model used by Samsung, Apple’s suppliers and other multinationals with corporate renewable-energy commitments.

For EVN, the DPPA is double-edged. It removes some of its most profitable industrial customers from the retail base, at least for the renewable portion of their consumption, while leaving it responsible for balancing the system when the sun sets. But it also relieves EVN of the obligation to finance every new generation project itself, and it gives foreign investors a reason to keep building factories in Vietnam rather than in Malaysia or Indonesia, which is the outcome the government most wants.

Rooftop solar for self-consumption, regularised by Decree 135 in late 2024, works in the same direction. Factories and households can install panels and, in most cases, sell surplus power to EVN at a low price capped at a small share of capacity. It is a signal that the era in which EVN is the only path to a kilowatt-hour is coming to an end, slowly and on the state’s terms.

How much must EVN invest, and who will pay for it?

Vietnam’s power development plan calls for installed capacity to roughly double from about 85 gigawatts in 2024 to somewhere between 183 and 236 gigawatts by 2030, implying capital spending on generation and grid in the range of $130 to $140 billion over the period. EVN cannot fund that from a balance sheet that lost money two years in three.

The division of labour envisaged in the PDP8 power plan is that private and foreign investors build most of the new generation — solar, wind, LNG, and eventually offshore wind — while EVN and NPT build the grid. The grid portion alone is estimated at roughly $15 billion by 2030, and it has to be built in a country where land clearance for a single transmission line can take years unless the Prime Minister personally intervenes.

EVN’s historical funding sources are narrowing. Multilateral lenders have shifted their focus from coal to renewables and grid, which helps, but they also now demand governance reforms. Japanese and Korean export credit agencies, which financed much of Vietnam’s coal fleet, are winding down fossil lending. Domestic banks are constrained by the credit quotas described in the credit quota story and by exposure limits to a single state borrower. EVN has issued domestic bonds, but the amounts are small relative to the need.

Nuclear power adds a further demand. In November 2024 the National Assembly revived the Ninh Thuận nuclear programme, cancelled in 2016, and assigned the first plant to EVN and the second to Petrovietnam. If those plants are built in the 2030s, EVN will be responsible for a project of a scale and complexity it has never attempted, financed largely by foreign government-to-government arrangements with Russia, Japan, South Korea or France.

What could go wrong for EVN and the Vietnamese grid?

The main risks are a repeat of 2023 — a drought, a heatwave and a fuel shortage coinciding in the north — before enough new capacity and transmission is in place, and a political reluctance to raise tariffs fast enough to keep EVN solvent as its input mix shifts towards more expensive LNG.

Demand is the underlying pressure. Vietnam’s electricity consumption has grown at 8 to 10 percent a year for two decades and the government’s ambition of double-digit GDP growth through 2030 implies demand growth of 10 to 12 percent. Every year of delay in a gas plant, a nuclear decision or a transmission corridor is a year in which the margin between supply and peak demand narrows, and the north remains the most exposed region because most of the solar surplus is in the south-central provinces.

Fuel is the second exposure. Domestic coal from Vinacomin is running out of easily mined reserves, and domestic gas fields in the south are in decline, so the marginal fuel is imported: Australian and Indonesian coal, and LNG from Qatar, the United States and elsewhere at prices EVN does not control. The Petrovietnam story describes the LNG import chain being built to feed the new gas plants; the pricing of that gas is a direct pass-through into EVN’s losses if tariffs lag.

Governance is the third. The 2023 inspection, the removal of senior executives and the transfer of the dispatch centre show the state is willing to act, but they also show how personalised and reactive the control of the company remains. Investors who have watched the anti-corruption campaign move through Petrovietnam, the banks and the property sector have no reason to assume EVN is exempt, and a governance shock at the single buyer would ripple through every power purchase agreement in the country.

What does the EVN model mean for founders, investors and operators?

For anyone building in Vietnam, EVN is a counterparty, a regulator and a competitor at once, and the practical lesson is to structure around its constraints rather than to bet on its reform. Cheap, mostly reliable grid power is a genuine advantage; single-buyer risk and tariff politics are the price of it.

For manufacturers, the arithmetic is favourable. Industrial tariffs of about 8 cents per kilowatt-hour compare with 10 to 12 cents in Thailand and considerably more in the Philippines, and the DPPA and rooftop rules now allow a factory to hedge its clean-energy obligations. The 2023 blackouts have made backup generation and site selection in the south or in dual-fed northern parks part of standard due diligence.

For power investors, EVN’s creditworthiness is the whole game. A project’s bankability depends on the terms of an EVN power purchase agreement, on whether the project is inside the approved plan, and on whether the paperwork is flawless enough to survive an inspection. The developers who did best in the 2019–2021 renewables wave were those who completed early, documented everything and sold to Thai or Philippine utilities before the disputes began. Those who cut corners are still arguing with EVN about payment.

For the state, EVN is a policy instrument that is running out of room. The country’s growth model depends on cheap power for export factories, its climate commitments depend on renewables that EVN must integrate and pay for, and its fiscal position cannot absorb indefinite utility losses. The 2023 crisis forced a choice in favour of higher tariffs and a more open market; the next decade will show whether that choice holds when prices rise again.

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