Widely regarded as a poster child for power sector development in emerging markets, Vietnam has increased access to electricity from 54% to 98% of the country’s population since 1990, connecting some 55m people in the process. Until now, it has also been successful in meeting double-digit annual growth in demand, resulting from a booming economy and a burgeoning population, largely using indigenous hydrocarbons and hydropower resources. Meanwhile, reform of the state-controlled sector is under way, with the aim of creating a fully competitive and liberalised market.

Way Forward

Vietnam’s power sector is now at a crossroads. Major investment is required to meet soaring demand if the country is to maintain its economic development and continue on the road to becoming an upper-middle-income nation. It also has the task of meeting its international commitments to reduce greenhouse gas emissions, which require a cleaner generation mix, at a time when much of its economic hydropower potential has already been exploited. This comes in a period of financial constraints both for the state and for state-owned utility Vietnam Electricity (EVN), which is paying the price for years of below-market tariffs.

Private sector financing is therefore vital. To achieve its aims, in the view of international financial institutions, Vietnam must shift away from its current focus on thermal power capacity firing largely on imported coal towards cleaner generation based on domestic resources, and must raise tariffs to ensure EVN’s financial stability as the single buyer.

Investment Needs

According to the revised Power Development Plan 7 (PDP 7) approved in March 2016, Vietnam requires total investment – excluding privately financed build-operate-transfer (BOT) power generation projects – of VND3207trn ($143.5bn) for the 2016-30 period, of which 75% is earmarked for generation and 25% for development of the transmission and distribution network. In its Financial Recovery Plan for EVN published in March 2016, the World Bank expects around 50% of total investment – or over 65% of new power plant investment – to come from the private sector via independent power producers (IPPs) or other arrangements. Investment in BOT generation projects alone is forecast at over $25bn between 2014 and 2020. Vietnam will require estimated investment of $15bn per year, far in excess of what has been achieved in the recent past. In 2012 just $2.6bn was invested, excluding private sector investment.

Triple Jump

The investment prognosis is based on expected demand growth of 8-10% per year and annual GDP growth of 7%. This plan foresees the need for total installed capacity to more than triple from 38 GW at the end of 2015 to 130 GW by 2030, for production and imports to rise to 572-632 TWh and for consumption to rise to 506-559 TWh.

The new generation targets, which would require 6 GW to be built every year, are ambitious, given the track record of private investment. “This implies a far more rapid approval and development process for IPP projects than has ever been achieved before,” the World Bank states, adding that the investment target for IPPs to 2020 implies a new project being approved and implemented every three-six months. At present, negotiations over power purchase agreements (PPAs) and BOT concessions typically take at least three years, and since the introduction in 1997 of a public-private partnership decree on such concessions have seen only a handful of projects implemented with foreign investors, most notably the Phu My 2-2 and Phu My 3 gas-fired stations, and the Mong Duong 2 coal-fired plant.

Several issues are constraining investment at the required rate and scale. At the heart of the problem is Hanoi’s reluctance to relinquish control over the development of the power sector and by extension the cost of power. Providing cheap power for industry and the country’s booming manufacturing base to ensure they remain competitive globally, as well as to retail consumers, remains a key factor in sector policy. Ideally Hanoi would develop its power industry on its own terms, but Vietnam’s financial constraints as a result of growing public debt, and the pressing need for new capacity, is forcing its hand.

These factors explain Hanoi’s reticence to date to develop its gas and renewable energy resources, both of which would, in the short term, result in higher-priced power than that currently provided by hydro and coal-fired plants. Its decision in October 2016 to cancel signed agreements with Russia and Japan to build 4 GW of nuclear capacity can be seen in the same light. While this decision was taken primarily on financial grounds, given the high capital costs involved, it also raises doubts about demand growth projections and capacity requirements.


A key constraint is tariffs, which have long been maintained at below cost levels. The policy of low subsidised tariffs to maintain the competitiveness of domestic industry and keep consumers happy is putting pressure on the government and EVN to add new capacity. In 2009 the government committed to the introduction of a market-based approach to price-setting in the medium term. Retail rates have been adjusted in line with inflation, rising 52% in nominal terms between 2010 and 2015, but are still priced below the cost of supply.

The average retail electricity tariff stood at just above $0.08/KWh as of 2016, the lowest in Southeast Asia, and only just above EVN’s average generation cost of $0.075/KWh (excluding transmission and distribution costs). This has depressed sector cash flow and contributed to EVN’s rising debt. In turn it has raised concerns among private sector investors over EVN’s ability to pay for electricity generated as the single buyer, while the current low retail tariffs mean that investors are not confident of negotiating adequate prices for generation projects. By maintaining tariffs at current levels in real terms, with adjustments solely at the rate of inflation, EVN’s financial position would deteriorate, leaving it with unsustainable debt and unable to finance capital expenditure. This would force private sector investors to seek increased government guarantees, but “it will be difficult for the government to extend guarantees to the scale of this investment without impairing its own credit rating and limiting the fiscal space available for other activities,” said the World Bank. “Private investors…will want to see a creditworthy EVN, and so will lenders, who will be expected to provide about $21bn in loans (70% of the expenditure) for the programme’s public sector component.” The World Bank recommended that the government raise tariffs by 10% per annum over 2016-18 to achieve full cost recovery and ensure EVN’s financial stability. However, in November 2016 the government announced that there would be no electricity tariff hikes in 2017.

Legal Issues

Various legal and regulatory obstacles also stymie private investment. In a bid to improve the bankability of private investment in infrastructure projects, a decree regulating investment in public-private partnerships, including BOT arrangements, was approved in February 2015.

However, many feel that it has failed to provide sufficient assurance to foreign investors and lenders on key concerns, such as government guarantees on the convertibility of foreign currency, and the use of foreign law as the governing law for concessions. Both are key bankability issues, according to Hoang Phong Anh, partner at tax and law firm DFDL. “The government’s insistence on guaranteeing the convertibility from Vietnamese Dong into foreign currency of only up to 30% of a project’s revenues is a major impediment,” he told OBG. Meanwhile, the new decree allows foreign law to be used as the governing law only if the foreign law is not contrary to Vietnamese law. “Vietnam’s legal and regulatory framework in still in development and subject to constant change, which makes it very difficult for investors,” said Anh.


The same can be said of ongoing market reforms. The hope is that these will provide a transparent and predictable environment that is conducive to private sector investment.

Vietnam has taken the first steps on the road from a centrally planned, government-operated system to a market-driven model. In 2012 it launched the Vietnam Competitive Generation Market (VCGM), according to which state-owned generators are scheduled for dispatch, and sell to a single buyer. In 2015 it initiated a pilot competitive wholesale power market, which is expected to become fully operational by 2021, allowing retailers and qualified large consumers to buy electricity directly from generators. Competition at retail level is set to be introduced in steps between 2021 and 2024.

Many of the implementing regulations to govern the operation of the new market have still to be put in place, as well as how the different PPA structures for IPPs, BOTs, generation companies and multipurpose hydropower plants will be dealt with.

The concern is magnified by uncertainty over the timing of the establishment of an independent market operator. At present, private investors that operate in the power generation sub-sector through BOT concessions are not required to participate in the VCGM, but instead sell their output under long-term fixed-price PPAs to the Electric Power Trading Company, a subsidiary of EVN. This offers a clear long-term revenue stream but low prices without any upside perspective, said Anh. “Some foreign investors may prefer a tariff that would rise in line with improvements in market conditions, maybe indexed to the output price of EVN,” he said. “EVN would argue that if investors do not want the protection of a long-term fixed tariff they should participate in the competitive generation market.”

In the view of Jacques de Beer, project manager at power engineering consultancy Pöyry, once the competitive wholesale market is up and running, future IPP projects may be the subject of competitive bidding for sale into this market. Tariffs negotiated under PPAs should rise as prices in general reach cost-reflective levels with the development of a competitive market and the eventual implementation of a market-based tariff mechanism.


These issues – combined with a long, opaque process for approving projects and Vietnam’s current focus on big-ticket coal-fired projects with long lead times – have made progress on capacity additions slow, creating concern within government about the growing likelihood of significant supply shortages as early as 2018, most notably in the south. It is also creating growing frustration among international investors over the speed of development and the lack of policy clarity.

This could see increasing Chinese investor involvement, in the view of De Beer. “The bottom line is that they have the money and are not too fussed about the terms and conditions,” he said. “In addition they do not have all the environmental strings attached that mainstream banks have, though to their credit this is changing.” The Vinh Tan 3 coal-fired project, which is being developed by China Light and Power with Chinese financing and equipment supply, could be a sign of things to come. “International investors and lenders are slowly accepting local rules and regulations not least because the Chinese are becoming increasingly active,” said De Beer. “They are going to have to figure out how to play before the Chinese lock them out of the game.” In this context, an agreement signed in October 2015 with a consortium of Japan’s Marubeni Corporation and South Korea’s KEPCO to develop the 1200-MW Nghi Son 2 coal-fired project is a positive sign.

Clean Energy

Stricter social and environmental impact assessments are now required for new projects, according to Ministry of Industry and Trade (MoIT) guidelines, and in January 2016 then-prime minister Nguyen Tan Dung declared a moratorium on all new coal-fired plants. “The sector should protect the environment effectively, review development plans of all coal-fired power plants, build no more plants and gradually replace coal by gas, while following strictly international commitments on cutting emissions and promoting the development of renewable energy,” he told VGP news, the official state online newspaper.

To stimulate private investment in power generation, and at the same time address its social, economic and energy security goals as well as its global and domestic environmental commitments, Vietnam needs to place greater emphasis on cleaner domestic solutions, namely renewables and natural gas, and to reduce its reliance on imported coal. This, according to the Made in Vietnam Energy Plan (MVEP) published in November 2016, would immediately deliver private investment in cleaner energy after a decade of slow action, thereby freeing Vietnam from its reliance on mega-sized coal power plants which require many years of lead-time, unnecessary costs and put greater pressure on public sector borrowing and government borrowing capacity. The report, prepared by the UK’s Economic Consulting Associates on behalf of the Vietnam Business Forum, said this approach “makes it more likely that new generation can be financed in a timely and affordable manner while not leaving Vietnam dependent on a decreasing number of financiers and countries willing to continue to invest in large coal plants and coal mining with resulting geopolitical risks.” The report also warns that “many potential investors have policies preventing them lending for coal-fired projects”, noting that “constraints imposed by the World Bank, Asian Development Bank and other institutions are expanding.”

In contrast, financing of clean energy investments is a booming market in which Vietnam is currently not sharing. Its total clean energy investment in 2014 was estimated at just $67m. More can be done in renewables, including raising the feed-in tariffs for wind and solar, which would make projects bankable and reduce the need for government guarantees, according to the MVEP. The country has taken the first steps with plans under its revised PDP 7 to develop 18 GW of wind and solar by 2030, and is particularly keen on solar following the fall in technology prices in recent years. The report points to the examples of similar emerging markets such as Mexico, India and Brazil which have been able to bring down wind development costs during the last five years with a combination of incentives to attract private investments, developers and foreign direct investors wanting renewables.

The German international development firm GIZ is working with the MoIT to address several issues and create clearer permitting procedures. Licences, for example, are granted by provincial governments, which do not always have a clear understanding of the sector and vary from province to province. Expectations are rising that the feed-in tariff (FiT) for wind will be raised to a level that will incentivise private sector investment. “We are developing a national framework to assist the local authorities but also developers, so that they know what documentation is required,” said Peter Cattelaens, project manager at GIZ. “Despite the low tariff, there has been consistently high interest among international and local project developers, with reports of licences having been granted for a total capacity of 4 GW. Some projects are fairly advanced, so if a higher feed-in tariff was approved that would have a big impact on the pace of development.”


The development of offshore domestic gas for power generation also offers plenty of upsides for Vietnam, according to the MVEP. “The economics of gas development make it attractive to the private sector and projects could be up and running with global support and meeting national security, energy independence and climate change goals,” it read. “The development of gas-to-power is less expensive than imported coal power from the national perspective.” It would provide a major revenue stream to the government from taxes and royalties, the levelised cost of generation is lower, and the cost of continuing on its current coal trajectory would result in major health costs.


According to research firm Wood Mackenzie, new gas-fired, combined-cycle gas turbines (CCGTs) cost less than supercritical and ultra-supercritical coal combustion plants and integrated gasification combined cycle (IGCC) plants, on both a direct comparison of financial costs and from the perspective of society, given the large government revenues that would be generated. The break-even costs of power for greenfield subcritical and super-critical coal-fired technology are around $61-68/ MWh, while the break-even cost for IGCC is around 30% higher, compared to around $61 per MWh for CCGTs. Moreover, using IMF calculations, the MVEP estimates the annual health and environmental impact cost of the current power development plan to be as high as $15bn by 2030.

To date, Vietnam has been reluctant to push ahead with the development of its gas resources, due to concerns over costs and resulting impacts on customer bills. According to the revised PDP 7, development of its two most significant gas resources – Block B and the Ca Voi Xanh field – is designed to deliver an expansion of gas-fired generating capacity of 6.75 GW by 2026. However, the development of both will be expensive, according to industry experts. “Ca Voi Xanh has a very high carbon dioxide content, while Block B will require a lot of exploration wells,” Franz Gerner, energy sector coordinator at the World Bank, told OBG. “It comes down to pricing. The government is reluctant to sign gas supply agreements for $10/mBtu when current gas supply is priced at $3/mBtu. They are not planning 10 years ahead. Maybe in five years these fields will be viable but at the moment the electricity tariff does not cover the cost of gas from them.”

The long-term view is that development of gas resources could provide the government with substantial revenues, which is not the case with projects based on imported fuels. The revenue stream from Block B alone over its lifetime was estimated by Wood MacKenzie in 2013 at $15bn net of royalties, profit share and taxes. This compares to an estimated coal import bill, based on Wood MacKenzie’s mid-2015 price forecasts, of $20bn-25bn, required to fuel 3 GW for the life of the project. “The cost swing from 3 GW of offshore gas to 3 GW of imported coal,” the MVEP report said, “could be as high as $40bn when comparing revenues from gas development to the total cost of imported coal.”