Like many rapidly developing countries, Indonesia faces the dilemma of how to increase electricity-generation capacity while minimising tariffs levied on consumers. On one hand, Indonesia maintains ample domestic coal reserves which have traditionally served as an inexpensive, easy-to-access fuel supply. On the other hand, the world has become increasingly mindful that coal comes with environmental costs which have long-term economic and social ramifications, compelling policymakers to account for these factors when drawing up strategic power plans. Thus, the government of Indonesia has continually adjusted its policies in an effort to support economic growth while ensuring sustainability. “Because of this complexity, it is sometimes not so easy to come up with a certain formula,” Heru Dewanto, president-director of Cirebon Power Energi Prasarana, told OBG in July 2017. “This is not just about electricity capacity building but also a means to an end in terms of national capacity building.”

RESERVES: Central to this debate is renewable energy. Indonesia explored its substantial geothermal potential in the 1970s and began exploiting geothermal wells in the 1980s and 1990s to supply a substantial portion of its electricity mix. According to the 2015-19 Strategic Plan of Ministry of Energy and Mineral Resources (MEMR), Indonesia boasts the potential to harness 29 GW of geothermal energy. Other renewable sources hold the promise of considerably more power production, including a prospective 75 GW of hydropower, 50 GW of biomass and 49 GW of ocean power. Solar photovoltaic power sources are capable of producing on average 4.8 KWh per sq metre per day.

Only a fraction of this potential has so far been tapped for a variety of economic and technical reasons. Challenges include higher costs of production, the intermittent supply from some renewable sources, and isolation of some prime renewable areas from the national grid. As a result, Perusahaan Listrik Negara (PLN), the state-owned power producer and operator, projected 6.4% of total power output in 2017 to come from hydro sources and 4.6% from geothermal with other renewable sources contributing 0.1%.

In the wake of the government’s pledges to boost sustainable energy production, new long-term energy roadmaps were drawn up containing an increase in renewable contributions to the energy mix.

The 2014 National Energy Policy (NEP), formulated by President Joko Widodo’s government, called for renewable energy sources to constitute 23% of the energy mix by 2025. This superseded the previous NEP drawn up in 2006, which targeted more modest gains of 15% spread equally between geothermal, biofuel and other renewable sources. PLN has broadly similar goals in its 10-year electricity development plan, known as the 2016-25 Electricity Supply Business Plan (RUPTL), which was approved by the MEMR.

The RUPTL calls for renewable energy to make up 22.5% of all energy production by 2025. Coal plants will still play a key role in supplying inexpensive baseload power and are expected to account for 50% of total primary energy, while fuel gas will account for 26%. Overall, the RUPTL aims for 125 GW of nationwide installed capacity by 2025. In terms of new renewable capacity, the PLN implementation plan calls for the construction of 14.1 GW of new hydropower, 6.3 GW of additional geothermal power and 1.2 GW of other new renewable capacity.

SUPPORT SYSTEMS: In an effort to attract private investment to the sector, the MEMR rolled out regulations supporting a renewable incentive scheme in 2012. The primary incentive was based on the standard feed-in tariff system used around the world to help power producers offset relatively higher costs of production by offering them higher guaranteed off-take rates. Supporting regulations were slowly rolled out over the next three years, setting rates for solar power in 2013 and hydro in 2014. Further regulations were issued in 2014 and 2015 to adjust the rates of biomass, biogas, municipal solid waste and hydro projects as policymakers sought to balance incentives to producers and costs to consumers. At the end of 2016 these rates varied based on a number of factors including their location, technology used and generation capacity.

Geothermal projects were also supported by a new Geothermal Law passed in 2014 which introduced a new regime with the goal of accelerating development of geothermal exploration and production.

Over the ensuing years policymakers attempted to create an appropriate environment which could foster growth within the sector. However, the resultant patchwork of additional laws and regulations created an uncertain and often confusing framework. Other challenges to development included land use restrictions, particularly for geothermal projects, and domestic content requirements for solar power projects. In the end, differences of opinion among policymakers and the relatively cheaper costs associated with coal led to a decision in early 2017 to scrap the short-lived feed-in tariff scheme in favour of a new regional tariff system.

This model assumes that generous incentive schemes for producers will not be necessary due to the vast potential in productive renewable resources and the falling cost of production due to technological advances. What investors still require is a clear regulatory system that paves the way for future development.

NEW SCHEME: Introduced in January 2017 by the MEMR as Regulation 12, the new scheme stipulates mechanisms for purchasing renewable energy based on electricity production cost benchmarks established in different regions around the country (see analysis). The key theme running through this system is that the price payable by PLN for renewable energy sources should lower – or at least not increase – the existing average cost of generation on the relevant local grid. The net result is that producers will have to compete with traditionally cheaper sources of power including coal, which is the largest contributor to the national grid.

Renewable energy producers will now negotiate with PLN as the single off-taker, using different methods of procurement which vary according to technology and region. Solar and wind projects will be selected on an open tender process based on a quota capacity.

Tariffs paid by PLN to these producers are set at the regional average cost if it is less than or equal to the national average. Where the regional average cost is higher than the national average, payments are capped at 85% of the regional amount.

For hydropower projects, tariffs will be determined in accordance with the direct selection process; or through a benchmark price set at the regional average, where this cost is not greater than the national average, or 85% of the regional average where it exceeds the national cost. Waste-to-energy and geothermal projects will additionally operate on the benchmark system with tariffs set at 100% of regional production costs if the regional average is greater than the national average. If the national average production cost is greater or equal to regional average or the projects are located in Java, Sumatera, Bali or other power system regions, the tariff is based on a mutual agreement between the developer and PLN.

According to the new regulations, biomass and bio-gas projects with more than 10 MW of capacity will operate on a direct selection process, while those with less than 10 MW will utilise a tariff set at a maximum of 85% of regional costs if the regional average is greater than the national and 100% of regional average cost if national average costs are greater than regional.