Substantial hydrocarbons and hydropower resources have allowed Vietnam to be largely energy self-sufficient and supported rapid economic growth. Exploitation of its coal and the harnessing of rivers for hydropower has helped Vietnam meet double-digit growth in demand for power, providing almost universal electricity access to its people.
Development of the country’s oil and gas reserves has seen it become a net crude oil exporter and meet its gas demand in full. High annual GDP growth – at an average of 7-8% over the past 20 years – and increased affluence among a growing population have led to soaring demand for energy.
Challenges now lie ahead, as the most accessible oil, gas and coal resources are close to depletion, while much of the economically feasible hydropower potential has been exploited. As a result the country will be increasingly dependent on imports of coal and oil, and possibly also gas and electricity. Huge investment is required to meet future energy demand in an unfavourable investment climate of low commodity prices. Vietnam needs to attract private investment for the next phase of development as the three state energy champions – PetroVietnam (PVN), Vietnam Electricity (EVN) and Vinacomin – no longer have the resources to finance these investments alone. It also needs to make hard choices over its future power generation mix and the development of its hydrocarbon resources to ensure security of supply and meet its international greenhouse gas commitments.
Over the last three decades Vietnam has emerged as a major oil producer and is now the seventh-largest in the Asia-Pacific region, with production averaging 360,000 barrels per day (bpd). Successful exploration of its shallow-water fields has seen a seven-fold increase in its proven oil reserves to 4.4bn barrels as of end-2015, according to BP. As a result it now has the region’s third-largest reserves, after China and India. Vietnam’s oil reserves are mostly light sweet crude, and it has the highest oil reserves-to-production ratio in the region, at 33.3 years. It also has the region’s sixth-highest proven natural gas reserves, at 21.8trn standard cu feet (scf), according to BP, and its highest reserves-to-production ratio, at 57.9 years, assuming output continues at current levels of around 353bn scf a year PVN puts total proven gas reserves at 12.6trn scf, with total potential resources of 24.4trn scf.
Vietnam’s oil and gas reserves are located almost exclusively offshore in basins in the South China Sea: Song Hong (off the northern coastline); Hoang Sa (off the central coastline); Phu Khanh (off the central and southern coastline); Cuu Long and Nam Con Son (off the southern coastline) and Malay-Tho Chu (in the Gulf of Thailand). Half of its oil reserves are thought to lie in the deepwater Song Hong Basin and the rest are mainly in Cuu Long and Nam Con Son. It is a similar picture in terms of gas, according to PVN, with nearly 40% (9.6trn scf) of total potential resources of 24.4trn scf located in Song Hong and 41% in Nam Con Son (6.6trn scf) and Cuu Long (3.5trn scf).
To date, Vietnam has focused on exploitation of its most accessible oil and gas reserves in the shallow southern basins, with most of its producing fields located in depths of less than 100 metres. At present 17 fields are producing oil and gas. Cuu Long is the core oil production basin and host to all the major oilfields, including Bach Ho, the largest and oldest producing field. Gas production is concentrated in the Cuu Long and Nam Con Son basins, and in the joint development area with Malaysia in the south-west, with gas delivered onshore through three pipelines.
Vietnam’s oil and gas industry remains heavily state-controlled. PVN, a vertically integrated group run by the Ministry of Industry and Trade, is the dominant player, operating through subsidiaries and joint ventures (JVs) in exploration and production (E&P), storage, processing, transportation, distribution, services and crude oil exporting. E&P is undertaken by PVN through its upstream subsidiary, PVEP, via production-sharing contracts (PSCs) with primarily regional national oil companies such as Malaysia’s Petronas, Korea National Oil Corporation (KNOC), Thailand’s PTT, Japan’s JX Nippon Oil & Gas Exploration Corporation, Russia’s Zarubezhneft, Rosneft and Gazprom, as well as many independent minors including UK-based Premium Oil and SOCO International, France’s Perenco, Murphy Oil of the US and Canada’s Talisman. The only international majors present are ExxonMobil and Italy’s Eni, though neither yet has a producing asset. All oil produced under the PSCs is sold to PVN’s subsidiary PV Oil, while gas production and supply is handled by PV Gas.
Oil production declined from a peak of 424,000 bpd in 2004 to 362,000 bpd in 2015, according to BP, as a result of waning output from ageing fields and in the absence of any major new fields coming on-line.
This is exemplified by developments at Bach Ho, which saw first production in 1986. Production there, as well as at the Rong, Nam Rong-Doi Moi, Gau Trang and Tho Trang fields – all of which are operated by Vietsovpetro, a JV between PVN and Zarubezhneft – averaged 115,000 bpd between 2010 and 2014, accounting for around one-third of total output. However, it is expected to fall to an average of 94,000 bpd over 2015-19, Vietsovpetro said in June 2015.
Production has also tailed off at the Te Giac Trang field in Block 16-1 – operated by Hoang Long Joint Operating Company, comprising PVN (41%), SOCO International (28.5%), PTT Exploration and Production (28.5%), and Opeco (2%) – from 42,126 bpd in 2012 to 34,032 bpd in 2015. SOCO attributed the fall to a slowdown in investment and the higher water cut coming from older producing platforms, which was only partially offset by the entry into commercial production of the new H5 well in August 2015. The same partners, through Hoan Vu Joint Operating Company, also operate Block 9-2’s Ca Ngu Vang field, which saw production fall slightly to around 7000 bpd in 2015.
In early 2015 PVN said it expected production to continue to fall in the next few years as major new discoveries were unlikely and the drop in oil prices would impact its operations and field development activities. In October 2015 BMI forecast a 13% fall in crude production from 344,110 bpd in 2014 to 300,320 bpd by 2024. “Natural decline rates at the flagship Bach Ho field will see output peak in 2017 and decline thereafter. Additionally as production fails to keep up with rising demand from the expanding domestic refining capacity, Vietnam will become a net crude importer from 2018,” it said.
While Vietnam remains a net crude oil exporter for now, exports have significantly declined since the commissioning in 2009 of Dong Quat, Vietnam’s only refinery. As a result crude oil exports account for a narrowing share of total exports. In 2014, crude oil accounted for 5% of the country’s total exports of $150bn, down from 10.8% in 2009, and yielded a narrow surplus of $95.7m in oil-related external trade. Exports will continue to fall as declining production is used to feed new refining capacity in order to end Vietnam’s dependence on oil product imports.
Since first production in the early 1980s, annual gas output has risen steadily to an average of around 353bn scf, reaching 377.9bn scf in 2015. Continued growth in production will now depend on the government’s commitment to monetise its gas resources, which have to date principally served as a feedstock for power generation in the south, given that all of the country’s coal reserves and much of its hydropower potential lie in the north and centre. The development of Vietnam’s gas resources has been a secondary story to the exploitation of its oil reserves, with inexpensive associated gas from the Cuu Long Basin providing feedstock for generation in the south.
As a result, while gas production first started in the early 1980s from the Tien Hai C field in the Song Hong Basin, the second field in the northern basin only entered service in August 2015 to meet local industrial demand. The Thai Binh field in Block 102 was developed by Petronas, the Singapore Petroleum Company and PVN, with the gas being delivered onshore through a 25-km pipeline.
Associated gas from fields in the Cuu Long Basin was first delivered to the mainland in 1995 with the commissioning of the 116-km Bach Ho pipeline designed to supply the Phu My gas-fired power complex, a major source of power for southern Vietnam and Ho Chi Minh City. The pipeline is now running at 60-70% of capacity due to declining production in the basin, according to PVN. The last gas field to come on-line in the Cuu Long Basin was Su Tu Trang in Block 15-1, which began production in 2012.
Production in the Nam Con Son Basin – from the 2.08trn scf of recoverable reserves in the Lan Do and Lan Tay fields developed by Rosneft, ONGC Videsh and PVN – began in 2003 with the commissioning of the 400-km Nam Con Son-1 pipeline, which links to Phu My, has a capacity of 247bn scf and accounts for most of Vietnam’s gas supply. Since 2006 it also transports output from the 862bn scf of recoverable reserves in the Rong Doi and Rong Doi Tay fields developed by PVN and a South Korean group led by KNOC, and since September 2013 production from the 1.27 tcf of recoverable reserves in the Moc Tinh and Hai Thach fields owned by Bien Dong Petroleum Operating Company, a JV between Gazprom and PVN.
Construction of the Nam Con Son-2 pipeline is under way, with the $400m first phase being financed in July 2014 by a syndicate of 11 foreign banks. The pipeline, which comprises a 325-km offshore section and will have a capacity of 247bn scf, is designed to transport output from fields in blocks 05.2, 05.3, 04.3 and 04.1, including Dai Hung and Thien Ung, to Phu My. It is scheduled to be commissioned in 2017.
In the south-west, the PM3 block in the joint development area with Malaysia was developed by Petronas, Talisman and PVN. Around 78bn scf per year from PM3-CAA and Block 46-Cai Nuoc is supplied to a power and fertiliser complex in the Ca Mau province through a 330-km pipeline opened in 2007.
The south-west basin of Malay-Tho Chu should be the site of Vietnam’s next major gas-to-power development, following PVN’s acquisition in 2015 of Chevron’s majority stake in blocks B, 48/95 and 52/97. Following the discovery of estimated recoverable reserves of 3.8trn scf, PV Gas, Chevron, PTTEP and Mitsui Oil Exploration agreed in March 2010 to deliver 226bn scf per year of gas through a 400-km pipeline to feed a 4-GW power generation complex at O Mon, as well as the existing Ca Mau complex. Total investment in the fields, pipeline and 4 GW of gas-fired capacity was estimated at over $10bn. The projects were originally to start in 2014 but were delayed by disagreements over price, and first gas is now expected in 2019 or 2020. A pipeline is being developed onshore to transport gas from these fields to Ca Mau to O Mon and on to Phu My through Ho Chi Minh City. Connecting pipelines across southern Vietnam are also being developed. A 71bn scf-per-year pipeline running from Phu My to Nhon Trach and Hiep Thuoc began operating in 2008.
In the South China Sea, the Ca Voi Xanh gas project being developed by ExxonMobil could be the next major field to come on-line thereafter. The field will produce an estimated 375m scf per day (scfd) of gas and 3000 bpd of liquids, and is scheduled to enter production in 2021. The US oil giant said that it “continued to advance resource and technical definition, commercial negotiation, and execution planning activities” in 2015, and had drilled an appraisal well to further assess the resource.
Little progress has been made to date in exploiting the country’s onshore unconventional gas resources. Vietnam’s state coal producer Vinacomin, Australia’s Linc Energy and Japan’s Marubeni signed a business cooperation contract in 2008 to jointly undertake a trial underground coal gasification project at Tien Dung in Hung Yen province in the Red River Delta Basin. In 2012 Vinacomin said that the government had not yet approved the project. Linc Energy said on its website the three partners remain committed to the project and Linc will continue to work with the other partners during the approval process.
Existing and projected gas production from the Cuu Long and Nam Con Son basins is sufficient to meet demand in south-east Vietnam up to 2025, according to Nguyen Anh Duc, general director of the Vietnam Petroleum Institute, PVN’s research and development arm. “The development of smaller fields will compensate for reduced production in the southeast up to 2025, but after that we will need to import liquefied natural gas (LNG),” he said.
To bridge the expected supply-demand gap, Vietnam has been looking at importing LNG. PV Gas began construction of the first of two planned LNG import terminals in southern Vietnam in December 2014, but in April 2016 announced that it had halted work on the 128m-scfd facility at Thi Vai in Ba Ria Vung Tau province pending the results of a feasibility review. The project had been expected to be operational in 2018, but PV Gas said its development now was no longer considered urgent.
PV Gas also said it is awaiting PVN’s approval for a feasibility study it submitted in 2015 for a second facility, with a capacity of 9.6m tonnes per annum (tpa), at Son My in Binh Thuan province. The second LNG import terminal will be developed in three stages by 2030, with the first phase involving a 3.6m-tpa receiving terminal to start up in 2019 or 2020. In June 2014 PV Gas signed an agreement with Shell for LNG supply to the Thi Vai terminal and a memorandum of understanding to cooperate on the development of the $1.34bn Son My LNG terminal. Earlier, in March 2014, PV Gas and Gazprom had inked an agreement for LNG supply to the Thi Vai.
In the view of consultancy The Lantau Group, the LNG terminals will only happen if the government decides to take the first steps towards creating a competitive gas market. LNG delivered under long-term contracts would not be competitive with uncontracted piped gas from the fields in south-east Vietnam, and while competitive on a spot basis an LNG terminal would not be built based around spot supply given a thin market and price volatility. An LNG terminal would, however, provide a national gas reference price and enable PVN to choose between buying from domestic gas producers or LNG.
Into The Deep
To address falling oil output and meet growing gas demand, Vietnam needs to venture into its untapped deep waters. The drilling of its first offshore well in 2015 was a first step, but the appetite of PVN and international players for such risky undertakings in the current low price environment has been much reduced (see analysis). As a result, Vietnam is focusing on the development of marginal fields in the Cuu Long Basin to sustain crude output. While production is falling at most of its key fields, PVEP believes that the basin still holds significant oil resources in smaller prospects. While development of these fields is not economic on a standalone basis, falling production is leaving spare processing and transmission capacity, allowing for them to be tied into existing infrastructure and reducing costs.
PVEP said in October 2015 that PVN had approved a study it had conducted over four years to develop all oilfields in Cuu Long until 2030, with a focus on marginal fields, to maximise existing processing and transport systems. The study covers more than 40 structures. PVN and its JV partners have already tied in some marginal fields with existing facilities in the basin, such as the Hai Su Den and Hai Su Trang structures, which were connected to the Te Giac Trang system in 2013. Vietsovpetro has also tied in operations of some small fields with existing larger systems in Block 09.1 and is seeking to work with operators of other nearby fields to tie in with its facilities.
Many of Vietsovpetro’s marginal fields have reserves of 7.33m-29.32m barrels of crude oil, according to the company. PVEP is also willing to cooperate with foreign investors in marginal fields. Further gas development will largely depend on government commitment to monetising these reserves by biting the bullet on the issue of prices.
Vietnam is a net oil exporter but a net importer of oil products, due to a lack of refining capacity. Imports account for around 70% of its fuel requirements with the remaining 30% supplied by its sole refinery, which is operated by Binh Son Refining and Petrochemical (BSR), a wholly-owned subsidiary of PVN. Commissioned in 2009, the Dung Quat refinery, in the central province of Quang Ngai, has a current throughput capacity of 145,000 bpd.
Domestic consumption of petroleum products has grown at a compound annual growth rate of 7.5% over the last 20 years, exceeding even China, according to a report by ANZ, and is forecast to continue to rise on the back of a booming economy, most notably in manufacturing. In 2015 oil consumption rose 8.4% to 422,000 barrels of oil equivalent per day (boepd), according to BP’s Statistical Review of World Energy 2016. JX Nippon Oil & Energy, which in April 2016 acquired an 8% stake in Petrolimex, the country’s dominant retailer, foresees petroleum product demand rising to 660,000 boepd in 2030.
The retail sector is dominated by state companies. Petrolimex controls around 50% of the market, reporting total sales of oil products in 2014 of 9.83m tonnes, while PVN holds a 16% share. Competition is set to grow after Japan’s Idemitsu Kosan announced in April 2016 that it had applied to set up a JV with Kuwait Petroleum International (KPI). Idemitsu Q8 Petroleum aims to open its first retail station in Hanoi in early 2017, and will source its supply from the future Nghi Son refinery in the province of Thanh Hoa. Idemitsu and KPI both hold 35.1% stakes in the 200,000-bpd refinery, which will become Vietnam’s second refinery upon its scheduled commissioning in early 2018. With a view to meeting domestic demand in full, Vietnam is developing a series of new refineries, as well as a planned expansion of Dung Quat. In addition to Nghi Son, several other refineries are planned, including one in the Van Phong economic zone in the central province of Khanh Hoa by Petrolimex, in a possible JV with JX Nippon Oil & Energy. Thailand’s PTT and Saudi Arabia’s Aramco are studying a planned 400,000-bpd complex in the province of Binh Dinh (see analysis).
Oil product imports have been growing in recent years as a result of rising demand, but have soared since the entry into force in January 2015 of preferential tariffs on oil product imports for 2015-18 under the ASEAN Trade in Goods Agreement (ATIGA), and the ASEAN-China and ASEAN-Korea free trade agreements (FTAs). In 2015 Vietnam imported 10.06m tonnes, up 18.9% year-on-year (y-o-y), according to Customs data, following a 17.1% rise in 2014. In comparison, oil products from the Dung Quat refinery are subject to the higher import tax rates levied on products from countries with which Vietnam does not have FTAs. This has created operational problems for BSR, which is struggling to sell its products. The state has pledged to introduce a uniform tax rate for all supply sources in line with import rates under ATIGA, providing a level playing field for all suppliers, but has yet to announce when.
Vietnam has significant coal reserves, which have been a key feedstock for domestic power generation, as well as for the cement, fertiliser, chemical and steel industries. At the end of 2015 the country had estimated coal resources of 46.62bn tonnes and 2.26bn tonnes of reserves, according to a March 2016 government report. The northern basin of the Red River Delta is estimated to contain 42bn tonnes of resources, with a further 4bn tonnes located in the north-eastern basin. Until recently this has allowed it to meet domestic demand and export surplus supply. However, domestic demand, particularly from the power sector, is now exceeding production, forcing the country to turn increasingly to imports.
Vietnam produced 41.5m tonnes of coal in 2015, up 1.7% from 40.8m tonnes in 2014, per national statistics, but imports in 2015 surged to a record high of 6.96m tonnes, up 125% y-o-y. The sharp rise was in part due to reduced output by the dominant producer Vinacomin as a result of flooding following heavy rain in July in the northern province of Quang Ninh, the main region for coal production, which led the state producer to miss its 2015 output target of 40.8m tonnes by 3.5m tonnes. Nonetheless, an ever greater volume of imports will be required to meet the country’s needs. In the first quarter of 2016, Vietnam imported 3.55m tonnes of coal, up 255% y-o-y, according to Customs data, while exporting 65,577 tonnes, down 86.8% on the same period in 2015.
Domestic demand is forecast to nearly double to 86.4m tpa by 2020 from an estimated 47.5m tpa in 2016, according to a government report released in March 2016. Coal demand is projected to surge to 121.5m tpa by 2025 and to 156.6m tpa by 2030. This rapid rise in demand is largely driven by the power sector, with coal-fired plants expected to consume 33.2m tonnes in 2016, close to 70% of the country’s estimated total coal consumption.
Consumption by the power sector is expected to rise to 64.1m tonnes or 74.2% of total coal requirement by 2020, increasing to 96.5m tonnes (79.4%) by 2025 and 131.1m tonnes (83.7%) by 2030. In contrast, the country is expected to produce 41m-44m tpa in 2016; 47m-50m tpa by 2020; 51m-54m tpa by 2025 and 55m-57m tpa by 2030, according to the report.
Even allowing for increased domestic production, Vietnam will have to import up to two-thirds of its thermal coal requirements by 2030. Vinacomin said it expects to import 8-10m tpa of thermal coal to feed domestic demand over 2016-20. To meet future demand in the south, the country plans to finish construction by 2020 of the Duyen Hai coal terminal in the southern province of Tra Vinh. The terminal will be capable of receiving vessels of up to 160,000 deadweight tonnes and handling up to 40m tpa of coal, to be allocated to power complexes in the south.
Meanwhile, to reduce the growing supply-demand gap, in September 2015 Vinacomin began exploring for coal reserves beneath the northern Red River Delta region. Coal reserves in the basin are estimated at 210bn tonnes. The goal of the project is to evaluate geologic structure, coal reserves and quality as a basis to select suitable production technologies and to set up a trial project before commercially mining the basin. Exploration and analysis for the potential for coal is expected to run until spring 2019.
With electricity demand expected to double over the next 15 years, huge investment is required to sustain economic growth and ensure the lights stay on. Between 2005 and 2014 electricity demand grew by an average of 12.1% per annum, with consumption almost tripling from 45.6 TWh to 128.4 TWh, and peak demand more than doubling from 9.5 GW to 22.2 GW, according to the 2015 annual report from state power utility EVN. Per capita electricity consumption rose from 156 KWh in 1995 to 983 KWh in 2010 and 1415 KWh in 2014. The industrial sector is the largest consumer of electricity, accounting for 54% of total supply in 2014, according to EVN, with households accounting for 35.6%.
Vietnam tripled its installed capacity from 11.6 GW in 2005 to 34 GW at the end of 2014, with annual production and imports rising from 53.6 TWh to 143.3 TWh. With peak demand at 22 GW it would appear that Vietnam has a significant reserve margin, but the system is increasingly near breaking point, with “brownouts” frequent, notably in the south. Not all generation is available, and over-reliance on hydro-power, the dominant source of generation, leaves the country short of supply in times of drought. Installed hydropower capacity of 13,889 MW at the end of 2014 accounted for 40.2% of the generation mix, followed by coal-fired plants (9759 MW, 28.7%), and 7337 MW of gas-fired capacity, representing 21.6%. Oil-fired capacity (1205 MW) and renewables (1766 MW of small hydro and 52 MW of wind) made up the balance. In 2014 Vietnam also imported 250 MW.
On The Up
Electricity demand growth eased in recent years as a result of the global economic crisis, but is expected to continue its sharp upward trajectory on the back of forecast average annual GDP growth of 7%, and per capita consumption of 1415 KWh as of 2014, just one-third of consumption in China. In the revised Power Development Plan 7 (PDP 7) approved in March 2016, demand growth is forecast to rise 8-10% per annum through to 2030. This will translate into a four-fold increase in consumption to 506-559 TWh and will require total installed capacity to more than triple from around 38 GW as of the end of 2015 to 129.5 GW by 2030, and for production and imports to rise to 572-632 TWh.
Based on these forecasts, Vietnam would need to add 90 GW by 2030 to meet projected demand growth. This target for new capacity is widely viewed as being ambitious, given that the vast bulk of new builds will have to come from the private sector, and given the multitude of administrative, legal and regulatory obstacles to such investment (see analysis).
To encourage investment and ensure greater efficiency and transparency, Vietnam has taken steps to create a competitive and liberalised market, which will result in the breaking-up of the market dominance of EVN. A restructuring and reform process was set out under the Electricity Law of 2005, which outlined three phases of deregulation and privatisation through the introduction of competitive generation in a process scheduled to be completed by 2024. Following the unbundling of EVN between 2008 and 2012, creating generation, distribution and transmission subsidiaries, with accounting, management and functional autonomy, under a holding structure, phase one was launched in July 2012 with the legal unbundling of three gencos and the introduction of the Vietnam Competitive Generation Market (VCGM), in which generators are scheduled for dispatch and sale to a single buyer. The VCGM was launched with participation from 48 generators with combined capacity of 11,630 MW, equal to around 35% of total national installed capacity.
Expansion of competition at the wholesale level, allowing generators to sell electricity to multiple wholesale buyers including qualified large customers, is under way on a pilot basis. For now EVN remains dominant. It owns and operates 60% of installed capacity, as well as the national transmission and distribution grids through the National Power Transmission Corporation and five regional distributors.
In addition, EVN owns the National Load Dispatch Centre, which serves as the country’s system and market operator, and the Electric Power Trading Company, which acts as the single buyer. The majority of its generation portfolio has been unbundled into three wholly-owned generation companies in preparation for their privatisation, with the exception of strategic assets, including large multipurpose hydro-power facilities. EVN is also a majority shareholder of partially privatised plants in the VCGM.
The rest of the country’s installed generation capacity is owned by domestic independent power producers (IPPs) PetroVietnam and Vinacomin, and foreign investors on the basis of build-operate-transfer (BOT) concessions. PetroVietnam, through PV Power, is the second-largest producer, with an 11.4% share of the generation market as of 2014. Vinacomin held a 4.4% share. Power produced by IPPs and BOT concessionaires is sold to EVN.
In the future, according to the detailed design of the country’s proposed competitive wholesale electricity market that the Ministry of Industry and Trade approved in August 2015, most power plants will have to sell their electricity into the market while the power will be bought by the five regional distributors and directly by large consumers. This should eventually lead to more cost-reflective feedstock and electricity prices. Average retail electricity prices are among the lowest in the region and have contributed significantly to the poor financial status of EVN. The uncertainty over the creditworthiness of EVN as the offtaker poses a problem for investors and lenders in power plant projects (see analysis).
Generation Mix Up
One of the main subjects of debate is the country’s future generation mix as the government seeks to balance economic and security of supply considerations with growing environmental concerns and its international commitment to reduce greenhouse gas (GHG) emissions. Under its Intended Nationally Determined Contribution, Vietnam has committed to reducing GHG emissions by 8% by 2030, compared to business-as-usual projections starting in 2010, and by up to 25%, conditional upon assistance from the international community. At present cost remains the determining factor in the development of much-needed generation capacity.
Even allowing for the depletion of the most accessible domestic coal resources, the current low price of imported coal makes it by far the most competitive source of baseload generation. Under PDP 7 the share of coal in the generating mix is expected to rise from 36% in 2015 to 46% by 2020 and 56% by 2030.
Several deals for new plants suggest any shift in policy is unlikely to have an impact in the immediate future. To underline this, a consortium of Saudi Arabia’s ACWA Power and South Korea’s Taekwang Power Holdings have announced the signing of an agreement to build a 1200-MW plant in the province of Nam Dinh on a 25-year BOT basis. Construction of the $2.2bn Nam Dinh 1 project is scheduled to start in 2017. Meanwhile, in October 2016 an agreement was signed with a consortium of Japan’s Marubeni Corporation and South Korea’s KEPCO for the development of the 1200-MW Nghi Son 2 coal-fired project.
One option to reduce the carbon intensity of Vietnam’s power sector is to utilise its abundant renewables resources. The revised PDP 7 is a key step forward in this direction, with a target of installing 6 GW of wind and 12 GW of solar capacity by 2030, along with up to 12 TWh annually being supplied from biomass generation and increases in small hydro capacity. This would see the share of electricity generated from renewable energy rise to 6.5% in 2020 and 10.7% in 2030, and its share of total installed capacity rise to 9.9% in 2020 and 21% by 2030.
One key area that requires greater attention is energy efficiency. Vietnam witnessed a 70% rise in electricity intensity in the 10 years to 2014, with demand growth outpacing that of GDP. In 2004 producing one dollar of GDP required 0.9 KWh of electricity. By 2014 this had risen to almost 1.5 KWh at constant prices, according to the Made in Vietnam Plan published in November 2016 by Economic Consulting Associates. As a result, Vietnam’s electricity intensity now exceeds that of China. Furthermore, projections point to further increases in electricity intensity, to as high as 2.3 KWh for each dollar of GDP by 2030, the plan said.
The Vietnam Energy Efficiency Programme, a 10-year plan to institute measures for improving energy efficiency and conservation across all sectors of the economy, was approved in 2006, but it has failed to achieve the desired results. The main reason is that it is a voluntary scheme without any form of enforcement or sanctions, and without economic incentives either, given the low cost of energy. According to the World Bank, accelerating demand side energy efficiency could avoid the need for up to 10 GW of new generation by 2030.
Major investment is required across Vietnam’s energy sector to address falling hydrocarbons production and meet demand growth. The country has the resources to meet future needs, but its ability and desire to attract private investment with the right regulations and pricing policy, and the choices it makes in resource development, will have a major impact on its economy and its environmental goals.