Already the third-largest geothermal power producer in the world behind only the Philippines and US, Indonesia is counting on tapping into more of this abundant renewable power source to diversify its rapidly expanding power sector. Located along the infamous ring of fire amidst the convening of the Eurasian, Australian, Pacific and Philippine Sea plates, the same geologic forces responsible for the constant menace of earthquakes, tsunamis and volcanic eruptions also provide a powerful and abundant power source ready to be harnessed. Seismic surveys and other studies – many carried out during oil and gas exploration – have revealed 299 potentially exploitable targets for geothermal power stations across most of the country, from Sumatra, Java and Bali, to East Nusa Teggara and Papua.
As of August 2013, the country’s installed capacity of 1341 MW represented a fraction of total domestic potential, estimated at nearly 29 GW by the Indonesia Geothermal Association (IGA). Of this amount, a 2011 Ministry of Energy and Mineral Resources (MEMR) survey projects 16 GW of reserves, of which 2.28 GW were proven, 0.82 GW probable and 12.91 GW possible, with the outstanding 13 GW speculative.
Like other renewable energy power sources, geothermal power has the advantage of utilising a virtually free source of fuel, once the initial investment and infrastructure are completed. However, unlike other renewable technologies, such as wind, solar or hydropower, geothermal power sources are not susceptible to changes in seasonal or daily weather patterns, which can result in highly variable electricity output. Additionally, without the need for fuel transport infrastructure, such as ports, roads or pipelines, power plants can be established in more remote areas and even in isolated regions not currently accessed by the national electricity grid. The Indonesian geothermal industry also has the advantage of a high profile and strong lobbying sector – a product of an affiliation with the oil and gas industry with which it shares many common exploration and exploitation similarities.
In line with the government’s Vision 25/25 energy development plan which is targeting renewable energy to comprise 25% of Indonesia’s primary energy mix by 2025, geothermal power production is expected to take on an increasingly large share of domestic electricity production with a total contribution of 5.7% (9500 MW) of all power production by 2025. The most immediate geothermal expansion plan calls for the addition of 4925 MW through the Fast Track programme II (TFP2) at an estimated investment cost of $12.61bn, according to MEMR. Of this, 465 MW will be derived from development of production of four existing geothermal work areas (GWAs), 1535 MW from new development within 14 existing GWAs and 2925 MW spread over 22 new GWAs.
If successful, the FTP2 programme would help to alleviate the growing electricity supply crunch while at the same time reduce carbon dioxide output by 400 tonnes from 2010 to 2025. The largest of these is the Sarulla 1 plant in North Sumatra with a projected capacity of 3 x 110 MW, although other large projects being developed in new GWAs such as the Muaralaboh and Rantau Dadap in West Sumatra and the Rajababasa in Lampung (all of which boast an installed capacity of 2 x 110 MW) are further along in their development, having already conducted infrastructure preparation and entering into exploration stages.
In spite of the push by the public and private sector to bring more of the country’s geothermal potential online, a number of roadblocks in the form of high development risk and large initial capital expenditures are still slowing process on the construction of new projects. Although geothermal requires little in the way of unit cost and boasts a high capacity usage, these longer term benefits are offset in the short term by higher upfront expenditure which average approximately $3m-$4m per megawatt of installed capacity compared to around $1.5m-$2m per megawatt for coal-fired power plants. These costs differences are further affected by the longer term of development required for exploration and construction time which generally averages around seven years from survey stages to production. Another financing issue relates to purchase power agreements (PPAs) for geothermal projects which are signed before exploration and construction begin, and thus do not take into account full knowledge of the power plant potential prior to its completion and as a result are difficult to assess. Because the majority of new geothermal projects are being developed by independent power producers (IPPs) and not PLN, financing is a key issue as the majority of IPPs are financed approximately 70% through loans.
Perhaps the greatest impediment to the sector is the restrictions on land use which can draw out the permit and approval process for years or even block projects outright. The 1999 Forestry Law and the 2007 Spatial Zoning laws generally regulate and restrict activities from being carried out in protected forest areas, although subsequent ordinances such as government regulation 10 (GR 10) of 2010 allow specific projects including power generation to be carried out in protected forest if they are deemed “strategically important” while GR 28/2011 specifically allows geothermal projects in protected forests. A 2011 memorandum of understanding between MEMR and the Forestry Ministry was also signed for the purpose of accelerating the geothermal permits process within production, protected and conservation forests. Although there has been progress in acknowledging the disconnect between forestry policy and the development of geothermal resources – many of which are located within areas protected by law – solutions for reconciling these conflicts were still being hammered out as of late 2013. Given these obstacles, Indonesia Geothermal Association (INAGA) projects a maximum of 6638 MW of practical and achievable installed geothermal capacity by 2025, roughly two-thirds of the 9500 MW target. This revision takes into account delays already incurred to the developmental timeline, which would require 4600 MW to be installed in 2014-16, about triple the current installed capacity, and the five to seven years required to complete early stage development of each of the 51 GWAs. This figure could be revised, however, if the investment environment improves with a revised power pricing policy, financial support and clarity on development in national parks.
In order to resolve these challenges, the government and the private sector have cobbled together a number of measures designed to facilitate growth in order to meet developmental targets. A number of laws and decrees have been passed since 2010 both mandating the construction of new geothermal power production, requiring state-owned transmission system operator and distributor PLN to purchase power and sweetening the pot for investors through a number of fiscal incentives. New feed-in tariff regulations were implemented in 2012, assuring geothermal power producers (among other renewable producers) a minimum price for their off-take at a range of $0. 10-0.185 per MWh depending on geographic location and voltage. The Geothermal Fund was also established in 2011 and received Rp2trn ($2bn) in funding at the end of 2012 for use by the government investment unit to establish and disseminate high-quality, independently verified exploration data to investors during the tendering process of new work areas. Local news outlets also reported in March 2013 that the fund will also be used to finance soft loans of up to $30m per project.
To address the financing challenges for these projects directly, the INAGA and the banking sector have also suggested increased financial incentives in order to counter the higher perceived risks and lack of ability to assess project feasibility which have restricted the flow of capital to geothermal projects. Some of the options floated at the EBTKE Connex Renewable Energy and Energy Conservation Conference held in August 2013 in Jakarta include further reforms to energy prices to better reflect risk and market conditions, some form of cost recovery such as is present in the oil and gas sector, further tax breaks, reconfiguring of PPA structure and other measures.
Finally, many of the non-financial regulatory issues are included in the new draft bill amending Law No. 27 of 2003 on Geothermal Energy, which went to the House of Representatives in October 2013 and could be enacted by the government in April 2014. Among the key revisions are resolving cross-ministry conflicts by removing the mining classification of geothermal activity, thus allowing development in conservation areas. Other relevant changes involve establishing provisions for shareholding in private geothermal power plants; clarifying government authority to delegate geothermal exploration and exploitation for both state-owned and independent enterprises; confirming the state’s prerogative to revoke geothermal licenses granted by low levels of regional government; and establishing guidelines for regional governmental management of geothermal resources (including an obligation for geothermal concession holders to offer a 10% stake in power plants to regionally owned enterprises or state-owned enterprises after it enters the exploitation stage).
You have reached the limit of premium articles you can view for free.
Choose from the options below to purchase print or digital editions of our Reports. You can also purchase a website subscription giving you unlimited access to all of our Reports online for 12 months.
If you have already purchased this Report or have a website subscription, please login to continue.