Vietnam model for direct renewable power purchase agreement to be ready soon

By Kim Anh    December 5, 2018 | 04:12 pm PT
Vietnam model for direct renewable power purchase agreement to be ready soon
Vietnam plans to pilot the direct power purchase agreement (DPPA) next year. Photo by Reuters
The direct power purchase agreement model for renewable energy, which has drawn much interest from investors, is set to be completed this month.

A report released at the Vietnam Business Forum (VBF) Tuesday quoted Le Anh Duc of the Electricity Regulatory Authority of Vietnam (ERAV) as providing this assurance.

It will be an agreement (DPPA) between an electricity producer and a corporate customer for power to be sold and delivered to the latter for its operation. It is aimed at encouraging development of renewable energy.

Currently independent power producers sell their electricity to the state-run Vietnam Electricity (EVN), which is also the monopoly distributor.

DPPA has been hot a topic on the agenda for the last two years, and has attracted enormous interest among potential private power producers and energy consumers like Coca-Cola, Heineken and Unilever, who would like their energy sources to be greener to fulfill their global environmental commitments.

"Based on the advice of our consultants, ERAV will undertake preparatory work like determining the regulations that need to be amended or supplemented, and report to the Ministry of Industry and Trade and, if necessary, to the Prime Minister," Duc, director of the electricity market development and human resource training center at ERAV, said.

"At present ERAV is focusing more on selection of the DPPA model before exploring the pilot program in depth."

Speaking about the criteria for the selection of renewable energy plants participating in the DPPA, he said ERAV is considering the possibility of selecting those with a capacity of at least 30 MW.

He said 300 MW is the size of the pilot scheme, less than half of the total installed capacity in the country.

Vietnam plans to pilot the DPPA next year.

The government envisages that by 2021-22 large industrial and commercial power consumers will be able to transact directly with power suppliers. By this time customers will have many options for buying electricity, either directly from power producers or from retail companies.

The two DPPA models proposed by ERAV’s consultants are sleeved and synthetic.

The VBF consortium, which includes many foreign chambers of commerce and business groups in Vietnam, has stated its preference for a sleeved DPPA.

Under this, excess renewable energy produced will be sold through the spot electricity market at the market price. But ERAV has said this is not in line with the country's current power market design.

Under the synthetic DPPA model, 100 percent of the output will be sold through the market. Agreements between buyers and renewable energy generating companies (DPPA contract) will be settled through a financial contract (contract for difference, or CfD).

CfDs will set a fixed price for a certain period and amount of power traded by customers and the power producers. The two parameters need to be agreed to by both parties, but the payment for the CfD is the difference between the price in the contract and the spot price.

Duc explained: "The synthetic DPPA model is appropriate and completely similar to the current design of Vietnam’s wholesale electricity market. Adopting this mechanism will help reduce the work to be done and the issues to be addressed."

Le Hong Hai, another ERAV official, said: "Basically, ERAV is supporting the synthetic DPPA model."

The Ministry of Industry and Trade has finalized a draft circular regulating the operation of the competitive wholesale electricity market, which gives renewable energy producers the option of participating in the electricity market. 

Hai said the circular is expected to take effect from January 1 next year.

The revised Power Development Plan for 2011 – 2020 (revised PDP VII), adopted in 2016, was evidence of the Government's growing appreciation for alternative sources of energy.

Under the plan, power stations in the country are expected to generate a total of 60,000 MW by 2020. Coal-fired stations would account for the largest ration of 42.7 percent, followed by hydropower (30.1 percent), gas-fired plants (14.9 percent) and renewables (9.9 percent).

By 2030 the capacity would soar to 129,500 MW, with the proportion of electricity from coal and gas remaining unchanged, but renewables doubling to 21 percent.

Since early 2017 there has been a sharp rise in the number of solar and wind power plants approved by the Government after the adoption of new feed-in-tariffs (FIT) for on-grid solar projects and for onshore and offshore wind projects.

The governmental Decision 39 on support mechanisms for the development of wind power, effective from November 1 this year, raised the tariffs from 7.8 US cents per kWh to 8.5 US cents for onshore and 9.8 US cents for offshore generation respectively.

The new tariffs are attracting great interest in wind power, but investors are concerned about grid connection and the bankability of the power purchase agreement.

Last September the government had issued a resolution that allows solar power projects in the central province of Ninh Thuan to enjoy a rate of 9.35 cents per kilowatt-hour for a period of 20 years as long as they begin commercial operations by the end of 2020.

This marked an extension of the commercial operation date (COD) deadline from June 30, 2019, set earlier by the government. The new resolution has given investors hope the deadline would also be pushed back in other localities.

Recent innovations in solar power technology that have helped bring down production costs dramatically have made Vietnam’s 9.35 cents tariff attractive to private investors.

Hundreds of private investors had submitted proposals to set up solar farms, but the June 30, 2019, deadline had been too tight, energy experts said.

There are also lingering concerns over infrastructure needed for the solar projects to connect to the national grid, land acquisition, procedural lags, and a lack of master zoning plans for solar power development at the national and provincial levels.

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