President Joko Widodo’s desire for renewable energy to play a more significant role in the country’s sustainable energy future was borne out the commitment he made at the UN Climate Change Conference in December 2015 for renewables to account for 23% of primary energy consumption by 2025. Indonesia’s need to harness its renewable energy potential as part of a more diversified energy mix is unquestionable if it is serious about playing its part in addressing global warming. The country is the world’s fifth-largest emitter of greenhouse gas emissions. There is no doubt either about the country’s potential. Hydro-power and geothermal resources are estimated to represent 75 GW and 29 GW in potential power capacity, respectively, in addition to 32 GW of biomass capacity and 9.3 GW in wind power.
There is some scepticism about the ability of Indonesia to deliver on these lofty ambitions within this timeframe. In 2015 the country added just 80 MW of renewable energy capacity, and will need to do much better if it is to meet its ambitious target of 25% of new power generation from renewables by 2025. As of the end of 2015 alternative energy accounted for just 10% of a total installed capacity of 53 GW, split between 4.3 GW of hydropower and 1.44 GW of geothermal. According to the Electricity Supply Business Plan for 2015-24, which was designed by Perusahaan Listrik Negara (PLN), the state-owned power producer and operator, electricity consumption is expected to more than double to 464 TWh by 2025, based on annual demand growth of 8.7%.
According to PLN, 20% of the 70.4 GW that the country will require over the next decade will come from renewable energy. Hydropower is expected to contribute 9.3 GW in additional capacity, with a further 4.8 GW from geothermal. Development of some 200 MW of solar photovoltaic (PV) and small hydro is expected to provide power to remote islands, reducing diesel-fired generation. The share of renewables is expected to be increased in PLN’s new strategy for the period up to 2025 and will include 970 MW of wind and 800-1000 MW of solar.
However, implementing the right price incentives and regulatory framework to spur development of the country’s renewable energy resources is continuing to prove a challenge for the Widodo administration. Arguably the greatest challenge for the government is striking the right balance between setting a price that will attract investment while also ensuring affordability. While some support mechanisms have been introduced, including feed-in tariffs (FITs) for small-scale hydro and biomass, and competitive tenders for geothermal concessions with a ceiling price, they have failed to deliver the expected results. In recognition of this, FITs were raised for hydro and biomass projects of less than 10 MW in June 2015, while the current auction system for geothermal is under review. Support mechanisms are also expected for wind and solar in 2016.
Covering The Costs
At the root of the problem is PLN’s ability to pay for the additional costs related to its obligation to buy this power under long-term power purchase agreements (PPAs) at rates set by the government, but without a credible and stable source of revenue to do so. This comes at a time when PLN is struggling to strengthen its finances, which are critical to the success of the government’s power sector development plans, not only in terms of delivering its share of new sector infrastructure but also reassuring independent power producers (IPPs) of its creditworthiness as an off-taker. While electricity tariffs have been increased since 2014, they are still below the cost of production, placing pressure on PLN. The government supports the utility through subsidies, under which the company recovers its operating and financing expenses and earns a predetermined margin, which is set annually. PLN’s earnings before interest, taxes, depreciation and amortisation (EBITDA) would be negative if not for these subsidies, which amounted to Rp57trn ($4.2bn) in 2015, compared to an EBITDA of Rp49trn ($3.6bn), which included the subsidy, according to Fitch Ratings. In an economic report from March 2016 the World Bank noted, “The lack of a clear and reliable source of funds to cover the difference appears to be an obstacle for PLN and private investors.”
To address this issue, the government introduced a performance-based regulation in October 2015 that allows pass-through of uncontrollable costs, including those associated with PLN’s purchase of renewable energy. The government is also looking at a number of reliable sources of revenue for PLN to cover incremental costs. One such scheme involves the creation of a new entity to act as an aggregator, procuring electricity from renewable sources, as outlined by Presidential Regulation No. 4 of 2016, which was passed in January 2016. According to the Ministry of Energy and Mineral Resources (MEMR), the government is considering establishing a new PLN subsidiary to take over all existing renewable energy PPAs and sign all future PPAs. This entity would be financed by an energy security fund, which has yet to be established. Until then, the development of small projects of less than 10 MW appears to be on hold, as PLN has been reticent to sign new PPAs under the increased FITs. In March 2016 Luxembourg-based hydropower developer Velcan Energy announced it had halted construction of its 7-MW Sukarame hydropower plant in Sumatra as it had been informed by the MEMR that PLN was refusing to sign a PPA, claiming that the tariff was too high. In a press release, Velcan stated, “This situation [has resulted] in 119 small hydropower projects being stalled.”
Efforts are also being made to address long-standing issues such as a lengthy permit process involving various government ministries and local government authorities and a lack of coordination between policymakers, local authorities and PLN. “There are discrepancies on regulatory frameworks from central to regional governments; both say different things and apply different rules,” Hwang Ju Won, director of domestic firm Meyz Consulting, told OBG. However, some progress has been made to streamline the permit process, thus reducing time and costs for developers, with the establishment in April 2015 of a one-stop service under the Investment Coordinating Board.
The government is also attempting to resolve obstacles to developing the world’s third-largest geothermal resources, which could provide a clean base load alternative to coal-fired power. The principal impediment to private investment is the high upfront capital costs for exploration, which have to be borne by the developer. To prove reserves at least three wells must be drilled, costing between $7m and $10m per well, according to Surya Darma, chairman of the Indonesia Renewable Energy Society. With a success ratio of no more than 50-60%, commercial banks are averse to providing financing given the risks involved, requiring developers to cover all costs until first production, which generally takes six to seven years, Darma told OBG. At the Asian Power Utility Forum in April 2016 in Jakarta, Peter Wijaya, vice-president for commercial and business development at Star Energy, told delegates, “Funding for exploration is tough – investors have to take on the full risk. As a result, IPPs like Star Energy have to keep a tight rein on exploration costs, with more budget spared for low-risk, established fields rather than exploring untapped ‘greenfield’ projects.”
Given the location of Indonesia’s geothermal resources, the country may require foreign know-how to speed up exploration. Darma told OBG, “The best solution would be for the government to do the exploration, but it does not have the financial resources or institutional capacity to do so.”
However, in February 2016 the MEMR announced it was drafting a new regulation that would see certain working areas assigned without a tender to a state-owned company for exploration. Once reserves are proven, the working areas would then be offered to investors. Limited auctions would also be held, providing investors with the freedom to choose the location where they wish to conduct preliminary surveys and exploration, as well as an assurance of rights to future development if successful. Last but not least, the new tendering scheme to be introduced will see investors awarded concessions based on their investment commitments in exploration and their development timetable.
This would replace the current competitive tender system with a ceiling price, which since its introduction in June 2014 has often led to price bids below the ceiling price. As recently as March 2016 Pertamina Geothermal Energy (PGE), the geothermal arm of state oil and gas company Pertamina, won the rights to explore and develop up to 165 MW of capacity at the Gunung Lawu field in East Java, with a bid of $0.10 per KWh. The ceiling price, which stands at almost $0.16 per KWh for the plant when commissioned in 2016, is set to rise to $0.19-0.20 per KWh by 2020. Meanwhile, in February 2016 PGE reached an agreement with PLN after lengthy discussions for the sale of power from the future Kamojang IV plant at $0.094 per KWh and a price of $0.06 per KWh for output from the existing Kamojang I, II and III plants, after the expiry of the original PPA at the end of 2015.
Prices at these levels could pose a problem for foreign investors, whose technology and expertise is required to carry out seismic surveys due to the complexity of subsurface geology. The Jakarta Post reported in February 2016 that after renegotiating its PPA with PLN for its 220-MW Muara Laboh project, Supramu Santosa, CEO of Supreme Energy, said, “As long as the price is right, people will want to explore. But the price should not just be determined by PLN as the issue has a bearing also on the government’s long-term energy sustainability plan.” While not divulging the price, the local developer said the agreement reflected the government’s commitment to boost geothermal development.
Despite these issues, Indonesia expects steady capacity additions over the coming years. In January 2016 the MEMR announced that a further 1751 MW of new geothermal capacity would be installed by the end of the decade through a combination of expansion of existing plants and greenfield development. The most notable addition will be the 330-MW Sarulla project in North Sumatra, which is being developed in three 110-MW phases under a 30-year concession by a consortium of US-based Ormat, Japan’s Itochu and Kyushu Electric Power, and local investor Medco Energy. When completed in 2019 it will be the world’s largest geothermal project.
Much of the new development is being spearheaded by PGE, which in 2015 announced plans to invest $2.5bn to double its current installed capacity of 437 MW. Planned additions by 2020 include 90 MW at Karaha in West Java, 110 MW at Ulubelu, 165 MW at Lumut Balai, 110 MW at Hululais and 55 MW at Sungai Penuh, all in Sumatra, and two 20-MW units at Lahendong in Sulawesi. Other projects earmarked for commissioning by the end of 2019 include the 70-MW Liki Pinawangan Muara Laboh, 220-MW Rantau Dedap and 220-MW Gunung Rajabasa projects by Supreme Energy, France’s Engie and the Sumitomo Corporation, respectively. In addition, in March 2016 the MEMR announced plans to auction 19 working areas in 2016: eight through open tenders and 11 through direct offers to state-owned companies. In total, 27 working areas with a combined capacity of 1535 MW are to be auctioned off by the end of 2017.
The most significant new project developments have occurred as a result of a regulation issued by the MEMR in 2015 to allow direct appointment for hydropower projects, as well as direct selection by PLN for certain types of projects which result in energy diversification. The regulation also expedites the process for direct appointment and direct selection for the procurement of power projects. This, together with a concerted effort by the central government and PLN to overcome environmental and land rights issues, have seen significant progress on a number of medium- and large-scale hydropower projects. Large-scale projects are developed by PLN alone or in joint ventures under a PPP structure, while medium-scale projects by IPPs are under long-term concessions, with government guarantees.
In 2015 PPAs were signed for a total of 700 MW, including, most notably, the 510-MW Batang Toru in North Sumatra, which is to be developed as a PPP. PLN, meanwhile, advanced with three major projects. In October 2015 it signed contracts worth $234m with a joint venture between Italy’s Astaldi, South Korea’s Daelim and Indonesia’s Wika for the civil works on the 1040-MW Upper Cisokan project in West Java, which will be the country’s first pumped storage plant. Construction began in early 2016 on the $800m project, which will be partly financed by a $640m loan from the World Bank. Construction also began in autumn 2015 on the 110-MW Jatigede plant, also in West Java, which is being built by China’s Sinohydro and is to be commissioned in 2018. In October 2015 PLN received the final permits from the Ministry of Environment, paving the way for construction of the 180-MW Asahan III in North Sumatra.
PLN’s ability to negotiate on a direct appointment basis has seen a growing number of foreign investors push forward with wind projects, even though there is no FIT mechanism in place. In 2015 US-based UPC Renewables, along with local partner Binatek Energi Terbarukan, signed PPAs with PLN for the country’s first two utility-scale wind farms. The PPAs cover the 50-MW Samas project in Bantul, West Java, and the 70-MW Sidrap Park in South Sulawesi. The development of the first of these two projects was further boosted in March 2016 when the Overseas Private Investment Corporation, the US government’s development finance arm, announced it had agreed to provide $120m in debt financing for the construction and operation of the Sidrap wind farm. These will be the first projects out of a portfolio of 1500 MW that UPC Renewables said it is developing with its local partner at 12 sites in Indonesia.
Meanwhile, Singapore-based Asia Green Capital Partners (AGCP) is negotiating a PPA with PLN for the most advanced of three planned wind projects, totalling 182.5 MW. Indo Wind Power Holdings, a subsidiary of AGCP, signed an engineering, procurement and construction contract with Danish turbine supplier Vestas in November 2015 for its 62.5-MW Jeneponto 1 project in South Sulawesi. AGCP is also currently developing the 100-MW Jeneponto 2 wind farm, as well as a 20-MW project on the island of West Timor.
The last 18 months have seen a number of new entrants including Equis, PACE Energy, French developer Akuo Energy and Quantum Energy. The Singapore-based Equis Funds Group has obtained 10 project licences for solar and wind projects, and their first project received a notice to proceed in 2016.
In July 2015 France’s EREN Renewable Energy and CWP Energy Asia launched their joint venture, PACE Energy, to develop wind projects, while in February 2015 Akuo Energy and Pertamina signed a memorandum of understanding for the development of up to 560 MW of wind, solar PV and ocean thermal energy conversion capacity at various sites. Pertamina said it expected to begin construction on this portfolio of projects in 2018, with the initial focus being on remote islands that are highly dependent on diesel fuel for electricity supply. Investor interest in securing first-mover status on prime sites would seem to outweigh the uncertainty over the future regulatory framework and provide PLN with an advantage in PPA negotiations. A wind FIT law has been drafted with the help of the Asian Development Bank and is currently being reviewed by the MEMR.
It is a similar tale for solar PV, with a growing number of investors proposing projects for development even though the future support mechanism and design is still pending. A reversible bidding system with price ceilings was introduced in 2012, but it was then revoked in 2014 by the Supreme Court after a lawsuit by the Solar Cell Association, which was based on the claim that the contract included an obligation to use local content and that the system favoured local bidders. This resulted in the suspension of an ongoing tender for eight projects totalling 140 MW, as well as the 1000 Islands electrification programme. Revocation of this regulation means that PLN should be able to directly appoint developers for solar power projects. However, until new regulation is implemented, further development is on hold. Solar developers are also awaiting clarification on whether they can structure projects as captive power plants and sell directly to firms instead of PLN.
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