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POWER UTILITY | Karen Mesina, Indonesia
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Mission impossible: Indonesia may be setting ambitious energy targets

Its policy loophole isn't the only roadblock Indonesia has to tackle.

Indonesia pledged to reduce emission by 26% in 2020 in its Intended Nationally Determined Contribution (INDC), where the Indonesian government shifted its policy from coal to more environmental friendly gas generation. If implemented, demand for gas would increase to support the shift in the generation mix. What impact would this have on other energy players and what regulatory changes must be done? Will this affect Indonesia’s energy targets? These are among the sectoral topics discussed in the Jakarta leg of the 2017 Asian Power Utility Forum held in Ritz-Carlton Mega Kuningan in April 6, which was attended by over 30 key representatives from the Indonesian power market.

According to Stefan Robertsson, principal at The Lantau Group, the lack of policy or regulatory framework supporting Indonesia's targets should not be deemed as the only problem in the industry. Sometimes, he said, official forecasts are part of it too.

Official projections and targets can often look “aspirational”, and/or are long term with no definite framework how these can be achieved. Secondly, retail pricing policies can impact fuel mix. Few Asian countries have robust “cost pass through” regimes. “Regulated retail tariffs with less clear cost pass-through and/or result in low/subsidized tariffs tend to creates disincentives for offtake of higher cost generation. Third is that wholesale pricing regulations can be a problem. Not every MWh of electricity is created equal. There is often only a single 24/7 base load tariff, and if the benchmark for wholesale pricing is base load power, than the outcome will favour base load power,” he said.

Fourth point is that there is not enough government support for upstream, which will make downstream electricity targets hard to meet. Lastly, there is not much regulatory support for RE to begin with. In Q2 2017 there is almost no regulatory and policy support for RE anywhere in SE Asia.

Policies and regulatory framework for RE in SE Asia are lacking. In Malaysia, 450MW of solar projects awarded through bidding in 2016, and a second round of solar bidding is planned in 2017 with 460MW quota. In Minor Mekong, there is not feed-in tariff or developed RE schemes. In Vietnam, existing wind FiT i.e. US$ 7.8/MWh is too low to generate interest. No solar FiT exists, despite the country having plenty of prospective projects. New solar FiT and revised wind FiT have been imminent for a long time.

In the Philippines, quotas for FiT paid to new solar and wind projects were announced in 2014. Quotas filled up in 2015 and no new plans have been announced since then. Thailand on the other hand moved away from FiT and tariff adders supporting SE Asia’s No.1 solar power program. Last batch of solar power quota bid out in 2015/16 were not very interesting commercially whilst the next phase of solar policies is unknown. Its wind program is up in the air – land rights for projects have been repealed. In Indonesia, most recent FiT was announced in 2016, but only lasted for a few months. Current requirement for RE projects are to beat PLN’s average cost of electricity, and not even enough to beat marginal cost.

Liberalising the gas industry

Indonesia seeks to liberalise the mid-stream and downstream gas industry, but many sector-specific issues remain. The acquisition of land during construction and associated licensing/permitting procedures have been a recurring issue as they are time consuming and the ownership may be in dispute or may overlap with protected forest areas or other business concession areas. In addition the process of land registration is subject to government regulation.

“Foreign ownership restrictions are also present in certain services. The updated negative investment list issued through Presidential Decree No. 39/2014 places restrictions on certain oil and gas services including (some) construction, installation works, design and engineering support services, or technical inspections. This may make it harder for companies to find the necessary expertise to develop oil and gas projects,” Robertsson said.

Restrictions on hiring foreign workers are also in place. The Decree No.31/2013 issued by MoEMR is leading to a tighter scrutiny of foreign worker permits, as the government tries to encourage the hiring of more Indonesian workers. This could lead to businesses finding it harder to find the relevant skill/expertise that require specialized knowledge, like the oil & gas industry.

Creditworthiness of off-takers are also on the line. Gas off-takers may include companies which rely on government subsidies due to government imposed regulated prices below market prices (such as PLN and PIHC). Like PLN projects, developers and suppliers may need to secure Letters of Guarantee from the Ministry of Finance.

Prices are not responsive to international gas price fluctuations. There is also a public perception that gas is more dangerous than liquid fuels, hence there appears to be some hesitation for consumers to convert to gas.

Updates on renewables

Agung Wiryawan, director at PwC discussed that in 2015, Indonesia had approximately 55.5GW installed capacity of power plants which generated 228TWh of electricity. Demand for electricity in Indonesia is expected to grow by around 8.5% p.a. in the next ten years. The Government projected that demand will reach 457TWh by 2025. To meet this demand, the Government planned to develop 35GW of additional electricity generation capacity between 2015 and 2019, and a further 45GW by 2025.

The 35 GW programme appears to be progressing, albeit slower than hoped, so a new regulation was enacted to accelerate the development. Presidential Regulation No. 4/2016 was issued to address various issues affecting power project development in Indonesia (especially 35GW programme). In November 2016, Rinaldy Dalimi (member of National Energy Council (“DEN)) said that unless PLN could expedite the financial closure, it was unlikely that any more than 20GW would be achieved as it took around 36 months to build a power plant after the financial issues were settled. As of December 2016, only 0.5GW of the 35GW has reached the Commercial Operations Date. Under the Government’s future plan, fossil fuels are expected to continue to play a dominant role, but an increased focus on renewables.

“Despite the risks in the new regulations, there are also opportunities to deploying renewables.In the past fuel subsidies, low electricity tariffs, complex regulations, legal uncertainties, logistical challenges and extensive cheap coal resources deterred potential renewables investors. Following years of under-investment, Indonesia’s production of renewable energy remains modest. Solar insolation in Indonesia is higher than most other countries. However, the current installed capacity is only around 85MW. The MEMR plans to add 5,000MW of solar power capacity by 2019,” Wiryawan said.

To support the 5,000MW target, several programs and regulatory frameworks have been introduced: Develop Renewable Energy for Villages Program (Program Energi Terbarukan Listrik Desa) with a target of electrifying 10,300 villages by 2019; A capacity quota of 500 MW of solar power to be offered in 2016; Developing regulations for hybrid PV, on-grid PV and rooftop PV, and; Developing a quality standard for solar panels and expert resources.

“The estimated potential of wind energy in Indonesia has historically been regarded as relatively small, primarily due to the relatively low wind velocity. The exception is in the eastern islands, where wind velocity can reach a sufficient level to power small-to-medium scale wind turbines. As of mid-2016, a total of 215MW geothermal capacity was added. Despite this achievement, the Government has not reached its target of installing an additional 270MW capacity,” he said.

Energy balancing challenges

ABB is among the market players committed to assisting the region in hitting its energy targets. Its integrated IT/OT solutions serve 50% of electric utilities in the Platts Top 250 global ranking, 480 million electricity consumers globally, 55% of operating nuclear power plants globally, and 66% of global platinum mining production. Guillaume Ridoux, consultant for ABB’s Enterprise Software product group, discussed the challenges of balancing demand and supply given the current evolution in energy mix and how our portfolio of solutions can help. The increase of intermittent renewable and distributed energy resources requires adapted transmission and resource planning, market design and portfolio optimisation methodology and tools.

With more renewables, planning requires further risk analysis related to system constraints and market see increased needs for balancing services that can be addressed by distributed technologies. “ABB Energy Portfolio Management product group recognises four solution areas to address a rapidly-changing energy business model: power market analytics, energy market intelligence, portfolio planning & operations, and distributed energy resources management,” Ridoux explained.
Indonesian PPAs

Luke Devine, foreign legal consultant and head of energy, mining & infrastructure - Asia Pacific at Baker McKenzie, discussed the evolution of Indonesian power purchase agreement. First internationally debt financed PPAs started in early 1990s. Over time, different “Generations” evolved. Some changes were driven by plant type whilst other changes were just representative of a move from PLN to shift more risk to developers, for instance delaying penalties for late achievement of Commercial Operation. PLN and Sponsors/Lenders were left with discretion to find right "bankability” balance. Government left PLN alone to find right risk allocation, and eventually, only real limiters introduced around the scope of coverage of Government guarantees for those projects entitled to it. Recent PLN modifications include bonding requirements, project development cost account, and PLN is now given the option to buy a project at any time. Performance Bonds are required on signing for aggregate 10% of Project cost (typically broken up into Stage 1: 40% and Stage 2: 60%). If a company fails to reach financial close, both bonds are lost. If the project proceeds past financial close, Stage 1 bond is returned, so only Stage 2 is at risk.

Perry Nagle, director at PT Energy Nusantara Merah Putih, talked about the company's upcoming captive 600MW power plant and LNG receiving terminal. The company is in partnership with Bantaeng Regency government, Sulawesi for the US$980m project. The plant will be used to suport the electricity needs of Bantaeng Industrial zone. The project will be financed on a nonrecourse project financing basis, with a total cost of approximately US$1b. “ENMP is currently finalising a development consortium with an international financial institution and one or more strategic partners to provide development stage financing to complete feasibility and to finalize key agreements,” he said.
 

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