Powering the future: Opportunities & Challenges for IPPs

Powering the future Opportunities & Challenges for IPPs

This contribution was first published in the December 2014 issue of Southeast Asia Infrastructure magazine.


Southeast Asia is a 170 GW electricity generation market with significant growth potential on the back of strong economic development, improving gross domestic product (GDP) per capita and increasing electrification rates in the most populous nations in the region. With the exception of Singapore and the Philippines, which have established power markets, most Southeast Asian countries are single-buyer, state-utility- led markets with some reliance on independent power producers (IPPs) to augment generation capacity.

An overview of IPP opportunities in the region, as well as the challenges and key issues affecting the sector growth



Indonesia’s need for new capacity will continue to be driven by its increasing electricity demand, which is expected to more than double to reach 64 GW by 2022, and by state-owned utility PLN’s commitment to improve its electrification rates to 90 per cent by 2019 from the current level of 82 per cent.

IPPs are expected to account for 70 per cent (12 GW equivalent) of new capacity addition in the near term via the 18 GW revised Fast Track II Programme (FTP2). While coal remains the dominant fuel type in FTP2, geothermal energy is expected to play a significant role in meeting demand, contributing to about 5 GW capacity being identified in FTP2.

Land acquisition remains a challenge. For example, the Central Java 2,000 MW coal IPP, despite the commitment from PLN, has recently announced force majeure due to land acquisition difficulties. Over six geothermal plants totalling 360 MW experienced delays in 2013 due to similar issues.

Furthermore, PLN has moved forward to tender for IPPs without government guarantees. Genting’s 660 MW Banten IPP’s financial closure in 2013 has set a precedent for IPPs achieving financial closure without government guarantees, but whether PLN can attract an attractive long-term tariff, or sufficient bidding interest without government guarantees remains to be seen.



Power demand in Vietnam has outgrown supply over the past five years. A reserve margin squeeze is anticipated in the southern region between 2017 and 2019, partly due to delays and cancellations of large build–operate–transfer (BOT) projects in recent years, despite mitigation measures such as strengthening of the Central– South connection.

The government is also committed to gradually eliminate state-owned utility EVN’s dominance, and to facilitate the entry of private sector players. Some 10 BOT projects totalling 12.3 GW are planned for commissioning between 2014 and 2020.

However, uncertainty in the provision of foreign exchange guarantees has been stalling private sector project development efforts. New regulations governing public– private partnerships (PPPs) are expected to be announced in 2015 and developers are expecting further clarity on foreign exchange guarantee provisions.



Some 5.4 GW of committed generation capacity is currently under development by the private sector to fulfil the country’s energy demand and reserve margin requirements. The government remains committed to incentivise investment in renewables, notably the recent increase of the installation target for solar from 50 MW to 500 MW under the feed-in tariff (FiT) scheme of PhP 9.68 per kWh ($0.22 per kWh equivalent).

The Philippines, together with Thailand, has among the biggest wind energy pipelines in the region – seven projects totalling 421 MW are currently at an advanced stage of development with the expected commercial operation date to be within the second half of next year, while an additional 300 MW is in the early planning stage in the Philippines. The Department of Energy offers an FiT scheme of PhP 8.53 per kWh ($0.20 per kWh equivalent) for wind power projects.

However, grid bottlenecks and frequent outages have added uncertainty and constraints to the ability of power plants to reach their full generation capacity. Furthermore, an understaffed regulator has resulted in delays in the approval of retail contracts; it is also under pressure to reduce the retail tariff, which is among the highest in the region.



To meet the country’s projected peak demand of 52 GW in 2030, Thailand is expected to install over 53 GW of new capacity from 2014 to 2030, pushing the total installed capacity from 35 GW currently to 70 GW in 2030. Thailand is also committed to diversify its electricity mix and consequently reduce its dependence on expensive gas imports, primarily through the expansion of renewables.

To meet the country’s Department of Alternative Energy Development and Efficiency’s (DEDE) renewable generation capacity target of 14 GW by 2021, an estimated 10 GW is required, of which 1.8 GW is expected to be from solar power projects and 1.6 GW from wind.

Thailand is by far the most active country in solar development in the region – over 471 MW of solar capacity, with a total value of $1.3 billion primarily financed by Thai local banks, has successfully achieved financial closure over the past four years.

In terms of challenges, Thailand’s transmission and distribution system would require further upgradation to cope with more connections from wind and solar plants – many past requests for connection were rejected or delayed on the basis that they would destabilise the power grid.



Myanmar has among the lowest electrification rates in the region with a national average of 27 per cent. While the government is targeting to increase electrification rates to 34 per cent by 2016, and to 80 per cent by 2031, it faces challenges such as a weak regulatory/PPP framework and constrained gas availability.

The successful signing of long-term power purchase agreements (PPAs) and the subsequent financial closure of several gas-fired IPPs – notably Zeya & Associates, Toyo Thai and UPP – set a successful precedence for private sector involvement. However, financing has largely been on the balance sheet or with recourse to sponsors.

With constrained gas supply, the private sector and development agencies are also actively exploring the possibility of alternatives including imported coal projects, as well as renewables such as hydro, solar, wind and geothermal projects. Furthermore, the Myanmar Electric Power Enterprise (MEPE) is understood to have requested for a proposal to refurbish or upgrade existing gas assets to improve thermal efficiency.


Cambodia and Laos

Cambodia and Laos rely heavily on IPPs and hydropower to meet their power needs.

Cambodia, in particular, relies on IPPs for 95 per cent of its consumption,while hydro comprises 98 per cent of Laos’s capacity mix.

Both countries are still very dependent on imports from neighbouring countries. In particular, Cambodia still relies on the less economical heavy fuel oil or diesel-fired plant to fuel 33 per cent of its domestic production.

Hence, both countries have the potential for IPP development. Over 5 GW of capacity is planned to be commissioned between 2016 and 2020 in Cambodia while Laos has over 5.4 GW of hydro capacity planned and identified for IPP development by 2020.



Over 6 GW of IPP projects have been awarded over the last 36 months to cater to the need for baseload capacities, taking into account the expiry of the first-generation IPP contracts in Malaysia.

In the near term, the more urgent capacity development requirements lean more towards east Malaysia, particularly in Sarawak where nine sites have been identified for future hydro development.

As observed over the past few years, the increasing influence of state-owned enterprises in the power sector raises concerns over the role of IPPs and private sector participation.



Currently, the city-state is experiencing an oversupply situation. This, coupled with a high gas take-or-pay (TOP) arrangement, has driven market prices down to a shortrun marginal cost level, deterring investment in new capacity in the near future.

With the anticipated reduction of vesting cover level and the likely introduction of an electricity futures market in the first quarter of 2015, the dynamics of Singapore’s energy market is expected to change. These developments warrant prudent market due diligence for investment in new capacity.



Indonesia, Vietnam and Myanmar have a significant need for additional generation capacity. Therefore, these countries present strong opportunities for private sector involvement. The challenges and risks, however, vary across countries and by the nature of individual projects. Private developers should exercise prudence and conduct feasibility or due diligence checks to select the right project. Working with credible project partners, ensuring that the project risk is manageable and having a bankable project structure with guarantees are key considerations that will go a long way towards maximising success.

The article is contributed by Sharad Somani, Head of Power and Utilities, Asia Pacific, KPMG in Singapore and Wenbin Lim, Associate Director, Power and Utilities, KPMG in Singapore. The views expressed are their own.

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