LNG in Vietnam's power sector [NGW Magazine]
Hanoi last year prepared the Power Development Plan-8 (PDP-8) which was sent to the ministry of industry and trade (MOIT) in November, from where it will then go to the prime minister’s office for approval.
The PDP-8 is expected to get the final green light from the prime minister’s office during the first quarter of this year, said Vi Le Nhuan from the Institute of Energy, which comes under the MOIT. Vi was speaking at an industry webinar mid-December.
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The PDP-8 indicates a move away from fossil fuel-based power generation towards renewables and LNG. It considers the 2021-2030 period with a vision to 2045. The plan envisages electricity production of 537 TWh in 2030 and 959 TWh in 2045, with commercial electricity at 478 TWh in 2030 and 861 TWh in 2045.
The annual growth of commercial electricity demand is expected to be 8.3%/year this decade and 3.5%/yr during 2031-45. Total installed capacity is set to more than double from 2019 levels to 138 GW in 2030 and reach 222 GW in 2040.
Out of the total installed capacity of 56 GW at the end of 2019, gas had a 13% share, with coal being the dominant fuel with 36%. However, PDP-8 has cancelled or postponed up to 17 GW of coal-fired capacity, or nearly half of the pipeline up to 2030.
The PDP-8 sees LNG-based power at 128.5 GW compared with just 16 GW in PDP-7R. Gas-based power projects will be the key source of power generation in the coming years, Vi said. North Vietnam is expected to have 27 GW of LNG-based projects, north central to have 14 GW, mid-central to have 21.9 GW, south central to have 22.1 GW with south Vietnam to have 46.15 GW. The share of gas and oil in the power mix will be 19% by 2030, which is forecast to rise further to 24% by 2045 as against 15% in 2020, he said, adding gas will be the dominant fuel and oil will have a very minor share.
Potential for land-based and floating LNG terminals
Vietnam has a 3,260-km shoreline and, according to Vi, there are many locations fit for development of deep-sea ports. Land-based LNG terminals would be recommended for power plants with capacity bigger than 3 GW while floating storage and regasification unit (FSRU) would be recommended for power projects smaller than 3 GW, Vi said.
North and south Vietnam are suitable for FSRU-based projects. There are four FSRU-based power projects under consideration in PDP-8: Hai Phong and Thai Binn projects each with 4.5 GW; the Ben Tre power project with capacity of 3-4.8 GW and the 3-GW Ca Mau project.
LNG demand expansion
Although domestic gas production is expected to increase over the next few years, there is a shortfall in demand that the government is anticipating will be filled by LNG. About 14.6bn m3/yr of domestic gas is likely to supplied to power plants by 2025, almost double the 7.7bn m3/yr now. This is expected to then fall to 9.2bn m3/yr by 2030 and again to 7.7bn m3/yr during 2035-2045.
Demand for LNG in Vietnam’s power sector is expected to reach 8.5mn metric tons (mt)/year by 2030, the country's industry and trade ministry said in September last year. The ministry expects demand for LNG in the power generation sector to reach 1.2mn mt/yr by 2025. At present, Vietnam does not import any LNG. The southeast Asian country is promoting gas-fired power as it moves away from coal and oil-based generation. However, coal is expected to retain its dominant position. The ministry sees demand for coal in power generation reaching 35mn mt/yr in 2025 and 45mn mt/yr by 2030.
In the period of 2021-2025, it is planned to build three to four LNG terminals with estimated capacity of 1-3mn mt/yr. During 2026-2035, Vietnam plans to build about five to six LNG terminals with the capacity of around 3mn mt/year each.
The visibility of strong growth in the sector has attracted many global players, especially from the US, as well as local investors. In June last year, PetroVietnam Power, a subsidiary of state-run PetroVietnam, announced plans to build four gas-based power plants. In the same month, the Vietnamese government said the US major ExxonMobil was looking to invest in gas-to-power projects. US-based AES Corporation and state-run PetroVietnam Gas, another subsidiary of PetroVietnam, signed an agreement last year to develop the Son My LNG terminal.
AES was granted approval by Vietnam’s government last year to develop a 2.2-GW combined-cycle gas turbine power plant in the south-central Binh Thuan province. The Son My 2 plant will have a 20-year power purchase contract with the government and is expected to achieve financial close in 2021 and begin commercial operations in 2024.
The government said it will need $133.3bn in new power plants and transmission networks over the next decade to meet the country's rising demand. Of the total, $96bn would be needed to build new power plants and $37.3bn to enhance the power grid.
Some questions remain
According to US-based Institute for Energy Economics and Financial Analysis (IEEFA), the significant long-term question for PDP-8 is how the proposed LNG projects will develop.
“PDP-8’s aggressive embrace of LNG comes at a time when there are is little clear information concerning Vietnam’s LNG development policies,” IEEFA said in late-September. “This embrace of LNG comes at a time when 80% of Vietnam’s offshore gas output is used for power generation. Domestic natural gas production has been expected to peak by 2026, although the recent announcement of a new offshore gas discovery by Eni may extend this forecast.”
Eni announced last summer that it found resources at Ken Bau in the Song Hong basin, where it operates and wholly owns neighbouring Block 116. Estimates put resources between 7 and 9 trillion ft3 of gas in place with 400-500mn barrels of condensates. “The gas market in Vietnam is rapidly growing, driven by the country’s consistent GDP progress and the consequent development of gas-to-power plants supplied by domestic resources and, in the future, imported LNG. The Ken Bau discovery will potentially provide a fast-track solution to meet the increasing energy demand,” Eni said.
IEEFA stated that despite clear signs of policy commitment, many fundamental questions about how the links in the LNG value chain will evolve in Vietnam have yet to be answered. “At a time when the global gas market is facing existential questions about long-term market structures, this is not a minor issue. As a result, the full cost of integrating a large commitment to LNG into Vietnam’s energy and power markets is not yet fully understood domestically, or by regional analysts,” it said.
One of IEEFA’s biggest criticisms is that there is neither a comprehensive master plan nor a centralised management model for Vietnam’s LNG industry. LNG terminals and gas-fired power projects are governed under two separate sectoral master plans and integrated LNG-to-power projects proposals are scattered across the country. This underscores the need for systematic planning of LNG hubs to ensure that investment in the LNG terminals is linked efficiently to downstream power plants and industrial consumers, it said.
Also, PetroVietnam’s role in the LNG sector is uncertain. Under the PDP-7R framework, PetroVietnam was given tasks such as developing the LNG importing model and partnering with domestic and foreign investors in LNG infrastructure development. This has not materialised in practice, however, IEEFA said.
Citing examples from Bangladesh, Pakistan, Malaysia, and Thailand, PVGas has made the case that it should become the LNG aggregator to handle supply sourcing and distribution in the early stage of the LNG market development. PVGas has been granted the exclusive rights to import LNG through its Thi Vai terminal to fuel the group’s gas-fired power plants, but it remains unclear if those rights will apply elsewhere.
Despite the lack of policy clarity, as mentioned earlier, there has been a surge of interest in integrated LNG-to-power project investments from foreign developers. IEEFA said that this apparent disconnect between planning and execution raises questions about state-owned utility Vietnam Electricity (EVN)’s ability to manage the cost of LNG-fired IPPs.
“Building the necessary LNG infrastructure is destined to be costly. If history is any guide, MOIT will need to drive an extremely hard bargain with gas suppliers and should push back against the fixed contract terms that financially constrained US developers may seek,” IEEFA said.
EVN's infrastructure cost burden
IEEFA cautions that investors will need to pay close attention the question as to how much of the cost of the associated infrastructure – regasification, storage, and transport – will be passed through to EVN.
Disclosures in the preliminary PDP-8 documents suggest that EVN’s LNG prices will only include a pipeline transportation charge but not a charge for the cost of LNG infrastructure. Recent IEEFA research into China’s gas market development experience suggests that this may not be a realistic expectation and that the development of China’s gas market may not favor high-cost American LNG producers over the long term.
“The complex cost structure of US LNG, which includes anything from feedstock costs, liquefaction fees and shipping costs to regasification and pipeline transportation fees, means that any moderate increases in these cost components could easily make US LNG uncompetitive against cheaper pipeline imports, domestic gas or other global LNG suppliers,” IEEFA said.
At this stage, the regulatory and market realities that will determine EVN’s ability to pay for a major shift toward gas-fired power capacity remain in flux. As a result, it will be crucial to track developments in the global LNG market, it added.