Indonesia: a new El Dorado for Independent Power Producers in SE Asia

February 2017 | Azam Mohammad, Giovanni Bruni, Rahul Gupta, and Sayak Datta


Rapidly growing power market in Indonesia

With ~53 GW power capacity in 2014, Indonesia expects to add more than 80 GW of new power capacity by 2025. A comparison with other countries reveals that the percentage increase in capacity from 2014 to 2025 is the highest for Indonesia (~156%), higher than that for India and China as shown in Exhibit 1.


Exhibit 1: Additional capacity expected from 2015-2025


Source: World Energy Outlook, 2016; RUPTL 2015-2024

Independent Power Producers' presence in Indonesia is still evolving: big opportunity in the future

To meet its electrification ratio target of 99.7% by 2025, Indonesia is opening up rapidly to Independent Power Producers (IPPs), specifically to foreign power generation specialists. IPPs entered Indonesia first in 1991 and since then we have seen the evolution of three waves with different schemes. The current scheme is based on a competitive auction with substantially lower returns (12-14%), as compared to first generation returns (20%).

As Exhibit 2 demonstrates, as of Dec 2015, the share of IPPs was ~30% but this is expected to increase to ~46% by 2025: ~57% of the additional 81 GW expected between 2016 and 2025 is planned as IPP projects. In terms of the technology split for the additional capacity, coal (steam) and gas (including CCGT) are likely to be ~54% and ~15%, respectively.


Exhibit 2: Indonesia's power capacity


Source: RUPTL 2016-2025

Further, in term of regions, Java-Bali and Sumatra will account for ~54% and 24%, respectively. It is estimated that investments of ~USD 150 B will need to be made by 2025: USD 31.9 B by PLN for power generation, USD 78.2 B by IPPs for power generation, and another USD 43.7 B by PLN for transmission and distribution networks.

However, IPP players should watch out for...

The large amount of investment and scattered archipelago of the country pose certain risks for new IPP players interested in the Indonesian market. Below, we highlight a few key themes that IPP players should look out for.

  1. Granular understanding of different power projects for selective bidding: Given that a large number of projects are currently being tendered across different islands of Indonesia, an IPP player needs to selectively choose the set of project(s) to bid for: key considerations for this include the regional competition, fuel-mix options, level of regional transmission and distribution capabilities, scope of the project (integrated gas solution and power plant versus only power plant)
  2. Stakeholder management, land acquisition, and permits: An IPP player will need to identify a capable local consortium member to manage different government stakeholders and meet the local content requirement for goods and services. Given that land acquisition and securing approval for permits could likely be challenging, the IPP player will need support from the local partner to prevent delay in financial close, commencement of construction, and project completion
  3. Primary energy supply: Although fuel supply has not been a part of the bidding package for many of the recent large gas-fired IPP projects, there are still projects where gas supply and power plant are included. For such projects, securing competitive agreements for the primary fuel will be critical, given the likely misalignment between demand and supply centers and expected shortage of gas supply moving forward (relevant for gas-fired projects)
  4. Tariff negotiation for the Power Purchase Agreement (PPA): The Indonesian Government typically regulates power tariffs. PLN exercises significant pricing authority driven by its 100% ownership of the distribution network and, thus, may have higher negotiating power than the IPP bidding consortium
  5. Government guarantee: Although in the past, some IPP projects were backed by government guarantees, recent trends have suggested that no government guarantee is available for IPP projects (e.g., 1.6 GW Java 1 IPP project)
  6. Absence of minimum electricity dispatch: Recent trends suggest that PLN did not stipulate any minimum electricity dispatch in the IPP RFQs; hence, IPP bidding consortia will need to manage this risk themselves by pricing it into the tariff quoted
  7. LNG supply disruption risk: For recent gas-fired IPP projects, it appears that IPP bidding consortia might be subjected to the risk of LNG supply disruption: with no fuel, the power plant will not be deemed “available” and not be paid for. This implies that IPP bidders will need to negotiate the disruption clauses in advance, include provisions for alternate make-up fuel supply, and price in the risk of disruption in the bid price
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About the authors

Azam Mohammad is a Partner at McKinsey’s Oil and Gas Practice in Singapore.

Giovanni Bruni is a Solution VP at McKinsey Energy Insights in Singapore.

Rahul Gupta is an Expert at McKinsey Energy Insights in Singapore.

Sayak Datta is an Engagement Manager at McKinsey Energy Insights in Singapore.