Wantana Somcharoenwattana, Business Development Manager, Wärtsilä Power Plants
April 15, 2014 | 4 Comments
The SPP programme was originally initiated to promote energy efficiency in the industrial sector. In the past, boilers were mostly used in industry as a source for process steam and hot water. To promote the replacement of those conventional boilers with more efficient technologies, the government developed the SPP scheme for cogeneration plants fuelled by natural gas or coal. Recently, renewable energy for potential on-site generation has been included in the SPP scheme.
SPP cogeneration can provide an economical and reliable source of electrical and thermal energy for industry, increase overall system efficiency by contributing to the grid during peak load times, avoid big investment costs for large centralised power plants, and reduce transmission and distribution losses.
To qualify as a SPP cogeneration, a plant must utilise 5 percent of waste heat; and must demonstrate performance achievement through primary energy saving (PES), with PES ≥10 percent to get the full FiT (THB0.36/kWh).
The SPP scheme offers two types of contract: a ‘firm' contract for 20–25 years, and a ‘non-firm' contract for five years. Under such a contract, the SPPs sell electricity to EGAT, but they are also allowed to sell electricity directly to industrial customers. Both contracts allow the sale of up to 90 MW to EGAT based on their guaranteed generating capacity. A firm contract will receive a capacity payment and an energy payment, while a non-firm contract will receive only an energy payment.
As of December 2013, the majority (70 percent) of SPPs under operation are natural gas-based CHP plants which are running under firm contract. The rest are coal or lignite-based cogeneration plants (12 percent) and renewable energy plants (18 percent).
An example of the electricity tariff for firm SPP natural gas-based cogeneration includes a capacity payment (CP), an energy payment (EP) and a fuel saving (FS) payment.
The CP represents the base capacity payment (CPo) of the long-run avoided cost of an EGAT large combined-cycle power plant, which is valued at THB420/kW and adjusted for exchange rate variations compared to the base exchange rate of that month.
The EP represents the base price of gas (EPo) per kWh, adjusted for fluctuations in the gas price (Pt) at the time it is purchased from the Petroleum Authority of Thailand (PTT).
The FS payment represents the efficiency of the cogeneration plant compared to separate conventional electrical and thermal generation through the PES principle. A fuel saving incentive ranges between THB0–0.36/kWh, depending on the PES achievement. To get the full incentive of THB0.36/kWh, the plant must achieve a minimum PES of 10 percent.
For a non-firm gas cogeneration contract, the tariff includes only the EP, which is based on the price of natural gas price announced every month by EGAT. The EP will be adjusted by a factor based on the selling time during on and off-peak times. The non-firm tariff is commonly lower than that of a firm contract, as shown in Figure 1.
Under both contracts, electricity tariffs are based on the passed on fuel cost, as depicted in Figure 2. Therefore, the more the gas price increases, the more the SPP electricity tariff income increases. This is one reason why the SPP cogeneration market in Thailand provides a secured project cash flow even in a high gas price environment.
Figure 2 shows the trend of natural gas price increases over the last three years. The electricity tariff for SPP gas cogeneration moves in the same direction as the natural gas price, so there is no negative impact on SPP in a high gas price situation because the tariff has been constructed in such a way that the impact is absorbed.
Since the initiation of the framework, the SPP scheme has grown to its third iteration, SPP3. The status of total SPP projects as of December 2013 is given in Table 4. The total amount of SPP in operation is now 6675 MW (80 projects), while 49 projects (5313 MW) are under implementation and construction, which means that SPP licences have been released for 11,988 MW (129 projects). In addition, around 2012 MW (28 projects) currently under the PPA signing process will also be added to the system.
SPP firm contracts are mostly for natural gas-based cogeneration plants; the rest use commercial fuel. The average capacity of a SPP firm contract is in the range of 110 MW–120 MW. For SPP non-firm contracts, renewable energy will generally be suitable for this dispatching profile, generating up to its availability. The majority of new and coming SPP non-firm renewable plants are solar PV projects.
SPPs have been continuously added to the grid over the past decade. Figure 3 shows the progress of SPP generating capacity additions to the grid during the past decade, from 2001 to 2013. The total SPP generating capacity added to the grid is now 3525 MW. The development of SPP plants is now dominated by natural gas-fueled cogeneration and, to a lesser extent, renewable energy — see Figure 4.
Along with the SPP programme, the government has also released the Very Small Power Producer (VSPP) programme to support the generators that are small and selling less than 10 MW to the grid. The average size of a VSPP project is generally below 10 MW. The majority of VSPP projects in operation are small renewable energy plants (1471 MW). There are also natural gas-based cogeneration plants, however these are present in a small number (113 MW) because the generation cost of high natural gas prices in a small-scale project may not always be competitive with the grid electricity tariff.
The total amount of VSPP projects in operation is now 1585 MW (476 projects) and 2142 MW (412 projects) are under implementation and construction, which means VSPP licences have been released for 3727 MW (888 projects).
In addition, 1244 MW (313 projects) currently undergoing the PPA signing process will also be added to the system. The total capacity of VSPP projects in operation, construction and PPA process will be 4971 MW (1201 projects), and the majority will be solar power plants with a total capacity of 2465 MW (572 projects), as shown in Table 5.
A Bright Future
In summary, DG in Thailand has been significantly developed through national energy polices and government supporting schemes over the past decade and it will continue to have a bright future for the next 20 years.
Various measures have been initiated and applied to encourage investors, such as the FiT programme, government funding programme and energy efficiency funding. As a result, even high penetration of DG in the country can be expected.
However, these successful stories of DG development so far illustrate good progress when viewed from the generation side. In terms of grid operation, transmission and distribution for DG, challenges remain. Integration of DG into the system, fluctuation of renewables dispatching profiles, system stability and reliability are key challenges when there is high penetration of renewables-based DG.
The Thai government has foreseen these key obstacles and has started to explore options to cope with future generation by appointing a Thailand Smart Grid Committee and drawing up a roadmap. Nevertheless, the Smart Grid roadmap is still in its initial phase of foundation and framework study. The completion of a Smart Grid for full-scale integration would therefore be quite some time in future — planned for 2028–2032.
Wantana Somcharoenwattana, Business Development Manager, Wärtsilä Power Plants, Thailand. www.wartsila.com