With the spectre of an electricity shortfall looming larger with each passing year, the Indonesian government is looking to coal-fired thermal power plants to provide a quick and easy solution. Coal has many advantages over other forms of power generation in Indonesia: it is cheaper, more established technologically and abundant. It is also seen as preferable to diverting dwindling supplies of natural gas away from profitable export operations. To boot, coal prices fell sharply in 2014, mainly due to lower demand from China, and are expected to remain low in the short term. “We would expect to see some minor improvement in the coal price over the second half of 2015 and into 2016 as a consequence of cuts in production,” Abdul Samad, president-director of Al Amoudi Natural Resources, told OBG. The need for inexpensive electricity has intensified further in recent years as state-owned power provider Perusahaan Listrik Negara (PLN) looks to cut costs in the wake of the reduced power subsidies initiated in June 2014.
Coal makes up the bulk of the government’s new 35-GW power generation expansion programme, announced in late 2014. The scheme will be spearheaded by a massive 5-GW thermal power complex in Java, which will rank among the world’s largest coal-fired power complexes. This complex will be part of the largest regional upgrade within the Java/Bali area, accounting for 20.91 GW of the total, followed by Sumatra (8.75 GW), Sulawesi (2.7 GW), Kalimantan (1.87 GW), Nusa Tenggara (0.70 GW), Maluku (0.28 GW) and Papua (0.34 GW). Much will have to go right and little wrong for the country to hit its target with this power development plan, the newest and most ambitious one to date.
When combined with power development initiatives already under way, the surge seems even more ambitious, with a target of nearly doubling capacity by 2024. In March 2015 the Ministry of Energy and Natural Resources (MEMR) revealed more details of the plan to the press, announcing a target of 42 GW of new capacity within just nine years. Projected to require investments of Rp1190trn ($98.4bn), the plan includes 20 GW of coal-fired power plants and 13 GW of gas-powered power plants, with the remaining 9 GW to be made up from renewables, primarily hydro and geothermal. PLN would be responsible for building at least 14 GW of this at an estimated cost of Rp608.5trn ($50.3bn), with construction to begin in 2015 on power plants with a combined capacity of 4.9 GW.
In all, around 60% of the capacity to be added over the next four years will be fuelled by locally sourced low-calorific-value coal. This will shift the country’s power generation mix further towards coal, which PLN projects will comprise 65.6% of the fuel mix in 2020, followed by natural gas (16.6%), geothermal (11%), hydro (5.1%), and oil and other resources (1.7%). The result would be a more pronounced reliance on coal compared to early 2015 levels, when coal amounted to 52%, natural gas 24%, oil fuels 11.7%, hydro 6.4%, geothermal 4.4% and other energy 0.4%. “Generally speaking, coal is the still the cheapest and most efficient means of producing energy today, though there are areas in Indonesia where this is not the case,” Suriyanto, president-director of Enviromate Technology International, told OBG. “Some remote areas only need 20 MW of power, which means that other sources of energy might be a better fit economically speaking.”
Clearing The Path
While PLN is expected to supply about half of the 35-GW total, there are significant opportunities for private companies to build and operate their own plants for the remaining projects and sell electricity back to the government as independent power producers (IPPs). Aspiring IPPs will also benefit from lessons learned from previous fast-track plans, which were delayed due to problems with licensing issuing, land clearing, state-backed loans and technical issues. Some of these issues are already being addressed in 2015 as the government attempts to streamline various bureaucratic processes. The state-owned PLN, for example, now accepts unsolicited bids instead of issuing merely its own tenders for projects.
For mine-mouth power producers, the government sought to clear away obstacles by adopting new ministerial regulations in April 2014, revising a coal pricing regime devised in 2011. Under the new rules, which apply to both IPPs and PLN, the coal price is determined on a case-by-case basis by the director-general of minerals and coal, based on the floor price, but taking into account price escalation, which will be evaluated periodically. The floor price is production cost plus a margin, calculated as 25% of the total production cost. Under the previous regime, for a coal mine to qualify for the “cost plus 25%” pricing regime on coal supplied for mine-mouth power generation, the calorific value of the coal had to be lower than 3000 kcal/kg. This limitation has now been removed, so that coal above the threshold is now eligible for the same pricing treatment as that below it. Other changes included clearer definitions of production cost components, new criteria for being treated as a supplier of mine-mouth power plant coal and new provisions requiring mine-mouth IPPs to bear the royalties payable by coal suppliers on mine-mouth coal supplied to an IPP.
In addition to coal-specific provisions, the government will shorten the permit process from 900 days to around 200 by revising a ministerial decree, Jarman Sudimo, MEMR’s director-general for electricity, told the press in March 2015. Regulations governing electricity pricing by IPPs would also be revamped, he said, along with a review of land purchase laws and due diligence for bid tendering. These moves reflect statements by the minister of energy and mineral resources, Sudirman Said, outlining eight key regulatory issues that needed addressing to speed the development of new power projects: land acquisition, price negotiation between PLN and developers, selecting private developers, permits, contractors’ competence, management capacity, cross-sector coordination and legal matters.
With the clock ticking on the government’s timetable, several large-scale projects already under way should go a long way towards meeting capacity targets. Foremost of these is the massive 5000-MW coal-fired power plant to be built in Cilacap in Central Java, whose output will both supply industrial consumers and feed the PLN grid. Construction on the first, 2000-MW phase of the complex, which will rank among the largest in the world when complete, is set to begin in 2015, with commercial operations following by 2018, according to Indroyono Soesilo, the coordinating maritime affairs minister. The complex and its five 1000-MW units, each equipped with ultra-supercritical boilers designed to operate at higher efficiency, will be built by Jawa Energy with backing from Chinese investors and is to be completed within seven years of the start-up date. Like numerous other large-scale projects, the plant’s plans and financing were drawn up years ago, but progress was held up due to land acquisition issues until 2015.
Indonesian coal giant Adaro Power will also play a significant role in the upgrade, having announced in November 2014 its intent to add 20 GW of new power capacity over the next two decades. To kick off its “20 GW in 20 years” campaign, its subsidiary Adaro Energy is concentrating efforts on its 34% stake in a 2000-MW coal-fired power plant in Batang.
While the government will be leaning heavily on conventional power plants to provide the bulk of the new power production, development plans also call for smaller production increases from the renewable energy industry. Most new production is expected to come from hydropower plants and from geothermal projects, of which five were under way as of the fourth quarter of 2014, with a combined capacity of 645 MW.