1(1) What is the composition of power sources for electric ...operating licenses (“IO Non-BBM”)....

Notice: This article is prepared and contributed by the authors shown in this article and therefore Atsumi & Sakai is not responsible for this article in any respect. The information contained in this article is as of the end of 2018 and has not been updated since then and provided as a general guidance information only. This article should not be relied upon as constituting legal advice. 各国の記事は当該記事末尾記載の現地法律事務所弁護士が作成したものであり、渥美坂井法律事務所・外国法共同事業はその内容につき責任を負っておりません。これらの記事は、一般的な説明であり、具体的な案件への適用を意図したものではなく、また、2018年 12月末日時点の情報を元に作成されたものであり、以降の更新は行っておりません。

1 ©2019 Atsumi & Sakai/ Makarim & Taira S.

アラブ首長国連邦（UAE）

◇A Structure and Trends in the Electric Power Industry

1(1) What is the composition of power sources for electric power generation in your

country at the present?

By early 2018, Indonesia had roughly about 60.7 Gigawatt (“GW”) of installed power plant capacity,

produced by PT Perusahaan Listrik Negara (Persero) (“PLN1”) - Independent Power Producer (“IPP”)

power plants, Private Power Utilities (“PPU”) and power plants operating under non-fossil fuel

operating licenses (“IO Non-BBM”). These power plants generated 254.5 Terawatt hours (“TWh”) of

electric power in 2017.

The 60.7 GW total installed capacity is divided among: (1) 41.7 GW (69%) from PLN and its

subsidiaries; (2) 14.2 GW (23%) from the IPPs; (3) 2.4 GW (4%) from the PPUs; and (4) the remaining

2.4 GW (4%) from IO Non-BBM holders.2

Nation-wide, the power generation fuel mix in Indonesia is currently comprised of coal (57.22%), gas

(24.82%), oil (5.81%) and renewables (12.15 %) as shown in the Table below.3

Indonesia’s Electric Power Fuel Mix

2012 2013 2014 2015 2016 2017

Oil 14.97% 12.54% 11.81% 8.58% 6.96% 5.81%

Gas 23.41% 23.56% 24.07% 24.89% 25.88% 24.82%

Coal 50.27% 51.58% 52.87% 56.06% 54.70% 57.22%

Hydro 6.39% 7.73% 6.70% 5.93% 7.88% 7.06% Geothermal & Other New and Renewable Energy sources (“NRE”)

4.96% 4.58% 4.55% 4.54% 4.58% 5.09%

As can be seen above, thermal energy (ie from coal, gas, diesel etc.) remains the largest source of power

in Indonesia. About 85% of electric power consumed in Indonesia is generated by thermal power plants,

and 58% of the nation’s total generation comes from coal-fired power plants. Coal continues to be the

1 PLN is the state-owned electric power company. PLN holds the exclusive right to distribute all generated electric power

to end-users (customer). 2 The Directorate General of Electric Power, Ministry of Energy and Mineral Resources, 2017 Electric Power Statistics,

31st Edition, 2018 Financial Year, p. 1. 3 The Directorate General of Electric Power, Ministry of Energy and Mineral Resources, 2017 Performance Report

(Laporan Kinerja Tahun 2017), p. 36.

インドネシア共和国 / Indonesia



dominant fuel for electric power because of its low cost and availability. Coal mine-mouth power plants

also remain integral to the Indonesian Government’s plans since Indonesia’s large low-rank coal

deposits are often located in remote areas with minimal infrastructure, including hauling roads and

jetties, making transportation of the coal uneconomical.

The use of more eco-friendly (lower carbon) technology, such as supercritical and ultra-supercritical

boilers is a key priority for PLN and the Government in the development of large-scale coal-fired power

plants, particularly on the densely populated island of Java.

Plans to diversify energy sources for electric power have been announced, but progress was slow. The

use of other types of technology, such as integrated gasification combined cycles or carbon capture and

storage, are not included in the 2018 Electric Power Supply Business Plan (Rencana Usaha Penyediaan

Tenaga Listrik – “RUPTL”) as these are not commercially viable yet. The high investment cost and risk

in developing renewable energy sources such as geothermal, wind, solar and other untapped potential

energy sources are still the primary issues for the nation to face in making them commercially viable.

However, the Indonesian Government actively supports the use of sustainable clean/green energy in its

electric power development road map.

While it seems that the Indonesian Government has yet taken the decision to use nuclear as one of its

energy sources for electric power generation, however Indonesia is currently assessing for a potential

first Nuclear Power Plant (“NPP”) development program through feasibility studies. The Indonesian

Government is also considering an NPP project through an open bid mechanism, where presumably,

the contract will use a turnkey approach and the nuclear fuel cycle will use an open cycle as an option.4

1(2) At present, what is the composition of renewable energy source in your country?

Also, please provide us with the government-established target numbers for

renewable energy and composition of methods of electric power generation.

Currently, hydropower and geothermal energy are leading the renewable source energy generation in

Indonesia – with hydroelectric power representing 9% of the 2017 total energy mix, and geothermal and

other alternative energy representing 5% of the 2017 total energy mix.5 Other sources of renewable

energy in Indonesia are including solar power, wind power and bioenergy. Further, the Indonesian

Government is also projecting tidal power opportunities.6

4 The International Atomic Energy Agency, “Country Nuclear Power Profiles 2018 Edition – Indonesia,” (updated 2018),

https://www-pub.iaea.org/MTCD/Publications/PDF/cnpp2018/countryprofiles/Indonesia/Indonesia.htm, accessed 6 December 2018.

5 Climate Bonds Initiative, Green Infrastructure Investment Opportunities – Indonesia, (May 2018), p. 17. 6 Price Waterhouse Coopers (“PwC”), Power in Indonesia 2018 – Investment and Taxation Guide, 6th Edition

(November 2018), p. 108.

https://www-pub.iaea.org/MTCD/Publications/PDF/cnpp2018/countryprofiles/Indonesia/Indonesia.htm



Renewable Energy Resources in Indonesia7

Source Potential Power Generation

Hydropower 75 GW

Geothermal 29 GW

Biomass 33 GW

Solar Photovoltaic (PV) 208 GWp (4.80 kWh/m2/day)

Wind Power 61 (3 – 6 m/s)

Ocean 18 GW

In 2014, Joko Widodo (Indonesia’s incumbent President) launched an aggressive program to build

power plants to generate 35 GW during his five-year term that will end in October 2019. From PLN’s

presentation, by May 2018, the 35 GW power development program implementation progress was the

following:8

By 2019, the actions in implementing the 35 GW program has been relatively slow. Even so, it is

announced that the Indonesian Government has postponed the completion target for the 35 GW

program to 2024 – 2025, also further reducing the new capacity target to be built for only 20 GW at the

end of 2019.

7 Directorate General of New and Renewable Energy and Energy Conservation, MEMR, 2016 EBTKE Statistics (Buku

Statistik EBTKE 2016). 8 PLN presentation in the IPP Summit 17 – 18 July 2018.

[VALUE] (1,007 MW) [VALUE] (2,130

MW)

[VALUE] (16,687 MW)

[VALUE] (16,687 MW)

6% (2,114 MW)

Progress in the 35 GW program as at May 2018

Planning Procurement

Contracted (PPA) not yet under construction Contracted (PPA) under construction

Reached Commercial Operation Date



Additionally, it is essential for all the investors in Indonesia’s electric power sector to understand that

the electric power planning in Indonesia is primarily based on a RUPTL. RUPTL is a document which

projects the 10 (ten) years electric power generation plan for each of the PLN’s operating areas (or

Wilayah Usaha). RUPTL document will be reviewed annually. RUPTL is sourced from the General

Electric Power Plan (Rencana Umum Ketenagalistrikan), comprising the National Electric General

Power Plan (Rencana Umum Ketenagalistrikan Nasional – “RUKN”) as well as the Regional General

Electric Power Plan (Rencana Umum Ketenagalistrikan Daerah – “RUKD”). The content of RUPTL

includes, but not limited to, the predictions of electric power demands, future expansions, electric

power production, and fuel mix. More importantly, RUPTL maps out the strategic infrastructure

projects to be built by both PLN and IPP investors, and the procurement method for the IPPs. Therefore,

RUPTL should be carefully considered when investing in the sector.9

Published in early 2018, the 2018 – 2027 RUPTL sets a target for Indonesia to achieve a full percentage

(100%) of electrification ratio by 2024. Unfortunately, once again, the target of 78 GW new power

generation capacity by 2026 has been reduced to 56 GW by 2027. Therefore, PLN and IPP investors at

this time are only expected to construct 56 GW of generating capacity by 2027, a significant reduction

compared to the proposed 78 GW in the 2017 RUPTL.

A decrease in the anticipated national average energy demand growth rate constitutes as one of the

backgrounds for PLN to reduce those numbers set for the capacity generation. The average energy

demand growth rate drops from 8.3% in the 2017 RUPTL to 6.9% in the 2018 RUPTL, causing a

decrease in the estimated total demand for electric power in 2026 from 483 TWh to 407 TWh,

accounting for a 15.7% decrease. The 21.9 GW reduction in plant capacity gas-fired power plants

(including gas machine and combined-cycle power plants) saw the largest cut of 10.1 GW from 21.9 GW.

This also represents a decrease in predicted gas consumption for the power sector from over 3,300

billion British thermal units per day (“BBTUD”) in 2026 to around 2,000 BBTUD in 2027.10

As projected in the Table below, the 2018 RUPTL also aims for the 23% energy mix from renewables

power generation in 2025 as targeted by the 35 GW program. However, knowing that the power

generation from renewables has been particularly low, achieving the 23% target by 2025 should means

that the renewable power generation in 2018 RUPTL must be at least amounted to 25% of the fuel mix

by 2025.

Further, since the draft 2015 – 2034 RUKN sets a fuel mix of roughly 50% from coal, 24% from gas,

25% from renewables and 1% from diesel fuel, this fact indicates a shift of focus back to coal powered

generation.

9 PwC, Alternating Currents: Indonesian Power Industry Survey 2018, 2nd Edition, (July 2018), p. 12. 10 PwC, Power in Indonesia 2018, p. 75.

Notice: “This article is prepared and contributed by the authors shown in this article and therefore Atsumi & Sakai is not responsible for this article in any respect. The information contained in this article is as of the end of 2018 and has not been updated since then and provided as a general guidance information only. This article should not be relied upon as constituting legal advice.” 各国の記事は当該記事末尾記載の現地法律事務所弁護士が作成したものであり、渥美坂井法律事務所・外国法共同事業はその内容につき責任を負っておりません。これらの記事は、一般的な説明であり、具体的な案件への適用を意図したものではなく、また、2018年 12月末日時点の情報を元に作成されたものであり、以降の更新は行っておりません。


Electric Power fuel sharing targets in the 2018 – 2027 RUPTL (in GWh and percentage)11

Fuel Type 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Hydropower 18,944

(6.92%)

17,594

(5.98%)

18,051

(5.70%)

19,784

(5.82%)

20,028

(5.54%)

23,749

(6.17%)

27,967

(6.82%)

43,135

(9.91%)

44,385

(9.54%)

46,700

(9.30%)

Geothermal 14,700

(5.37%)

16,532

(5.62%)

17,741

(5.52%)

19,299

(5.67%)

22,382

(6.19%)

23,666

(6.15%)

26,179

(6.39%)

50,782

(11.66%)

50,006

(10.74%)

49,201

(9.80%)

Other Renewables 419

(0.15%)

2,494

(0.85%)

2,906

(0.91%)

3,180

(0.94%)

3,204

(0.89%)

3,260

(0.85%)

3,545

(0.86%)

6,319

(1.45%)

6,591

(1.42%)

6,631

(1.32%)

Gas 57,049

(20.84%)

68,137

(23.15%)

76,069

(24.02%)

73,548

(21.62%)

80,047

(22.12%)

83,660

(21.75%)

85,745

(20.92%)

96,548

(22.17%)

98,120

(21.08%)

103,476

(20.62%)

Fossil Fuels 11,634

(4.25%)

11,429

(3.88%)

7,053

(2.23%)

3,639

(1.07%)

1,679

(0.46%)

1,713

(0.45%)

1,834

(0.45%)

1,826

(0.42%)

1,893

(0.41%)

2,007

(0.40%)

Coal 169,632

(61.95%)

176,517

(59.99%)

194,250

(61.33%)

220,081

(64.70%)

234,455

(64.80%)

248,560

(64.63%)

264,618

(64.56%)

236,841

(54.39%)

264,429

(56.81%)

293,902

(58.56%)

Import 1,433

(0.52%)

1,550

(0.53%)

907

(0.29%)

612

(0.18%)

-

(0.00%)

-

(0.00%)

-

(0.00%)

-

(0.00%)

-

(0.00%)

-

(0.00%)

Total 273,811

(100%)

294,253

(100%)

316,707

(100%)

340,142

(100%)

361,796

(100%)

384,609

(100%)

409,887

(100%)

435,452

(100%)

465,423

(100%)

501,918

(100%)

11 2018 – 2027 PLN’s Electric Power Supply Business Plan (Rencana Usaha Penyediaan Tenaga Listrik PLN Tahun 2018 – 2027) (“2018 RUPTL”), attached to MEMR

Decree Number 1567/K/21/MEM/2018, p. V-63.

Notice: “This article is prepared and contributed by the authors shown in this article and therefore Atsumi & Sakai is not responsible for this article in any respect. The information contained in this article is as of the end of 2018 and has not been updated since then and provided as a general guidance information only. This article should not be relied upon as constituting legal advice.” 各国の記事は当該記事末尾記載の現地法律事務所弁護士が作成したものであり、渥美坂井法律事務所・外国法共同事業はその内容につき責任を負っておりません。これらの記事は、一般的な説明であり、具体的な案件への適用を意図したものではなく、また、2018年 12月末日時点の情報を元に作成されたものであり、以降の更新は行っておりません。


Within the next 2 (two) years, according to the 2018 RUPTL, around 1,300 Megawatts (“MW”) of

renewable power projects are presumed to be in progress12. Therefore, investment opportunities in

Indonesia in renewable energy power generation facilities for 2018 – 2020 are considerable.

2 Please explain the structure of the market for electricity in your country.

The common structure of the current Indonesian electric power supply industry is shown below.13

Under Law Number 30 of 2009 on Electric Power (“Electric Power Law”), PLN, a state-owned

enterprise, is the only authority in the country having the priority to provide electric power across the

area in the Republic of Indonesia – factually as the sole owner of transmission and distributions

facilities/assets in the country. In carrying out its duty to fulfil the national demand for electric power,

PLN usually produces electric power from its own power plants, including from its subsidiaries. PLN

also serves as the single off taker, purchasing electric power from IPPs. Besides PLN and IPPs, other

power producers are relatively captive power sources, including industries that produce power for their

own uses, industrial estate companies, and some smaller companies, including cooperatives which

directly sell their electric power to the consumers.

For the most part, PLN builds and owns electric power infrastructure in the country where almost all

types of power plants are owned by PLN, eg coal-fired and oil-fired steam power plants, gas turbines

and geothermal, hydroelectric, as well as diesel power plants. PLN’s subsidiaries (ie PT Indonesia Power

and PT Pembangkitan Jawa Bali), manage most of those generation facilities.14

However, in recent years, about half of the new capacity came from the private sector or IPPs under

particular PPAs, which have increased in number since the 35 GW program was introduced. The

12 PwC, Alternating Currents: Indonesian Power, p. 11. 13 International Atomic Energy Agency, “Country Nuclear Power Profiles 2018: Current electric power market,” (Fig.3). 14 The International Atomic Energy Agency, “Country Nuclear Power Profiles 2018.”



presence of IPPs as investors is essential to achieve the national energy target since it is almost

impossible for PLN to take on all the tasks alone. Therefore, it is necessary to create a proper investment

climate to increase the development of NRE in Indonesia.

In contrast, the Renewable Energy Country Attractiveness Index (RECAI) report from EY in 2017

reveals that Indonesia ranked 38th in the top 40 most attractive countries in 2015 and 2016 and even no

longer categorized in the top 40 by 2017. Furthermore, although PLN signed 70 contracts with IPPs in

2017, barely 17 projects started the construction phase in 2018, while approximately 46 projects are now

considered failed and should be re-evaluated, or even halted by the government.

The failure of the projects was presumably due to financial issues, for example, non-approval loan and

the unattractive Internal Rate of Return (IRR). Many also convinced that the proposed Feed-in Tariff by

the government was much lower than the Local Average Generation Cost (Biaya Penyediaan Pokok –

“BPP”), resulting some projects in economically difficult positions, and also affected the

implementation for the Build, Own, Operate, Transfer (“BOOT”) scheme in most NRE sectors, except

for the waste-to-energy sector. Given this, it is reasonable for the government to prioritize affordability

over high cost green energy.15

In spite of the above, according to the information currently available in the market, the government is

currently planning to amend the Negative List of Investment (Presidential Regulation (“PR”) Number

44 of 2016 on the List of Business Fields which are Closed to Investment and Business Fields which are

Conditionally Open to Investment – “Negative List of Investment”), and there has been some

suggestion that power generation above 10 MW will no longer be subject to foreign shareholding

restrictions (currently it is limited to 95%, except for PPP which is 100% but only during the term of the

concession). This can be seen as an important step by the government in reforming the electric power

market and making it even more ‘investor-friendly’, placing emphasis on the partial liberalization of the

energy market, decentralized energy planning and increasing transparency.

Furthermore, we understand that in recent practice in dealing with PLN, PLN will require that it

becomes the majority share ownership and is involved in the management of the project company. This

scheme is usually implemented by PLN through its subsidiaries PT Indonesia Power, PT Pembangkitan

Jawa-Bali and PT Pembangkitan Jawa-Bali Investasi, in which PLN will directly assign its subsidiary

through a letter of assignment. Recent development in the expansion of coal-fired, renewables and mine

mouth power plants show that PLN and its subsidiaries will require the “piggyback” or “numpang

gendong” scheme (the term is informally used by PLN). Under this scheme, PLN through its

15 The Purnomo Yusgiantoro Center, “Brief Notes for Indonesia’s Feed-in Tariff (FIT) Implementation,” (27 September 2018), http://www.purnomoyusgiantorocenter.org/2018/09/27/brief-notes-for-indonesias-feed-in-tariff-fit-implementation/, accessed 6 December 2018.

http://www.purnomoyusgiantorocenter.org/2018/09/27/brief-notes-for-indonesias-feed-in-tariff-fit-implementation/



subsidiaries will require at least 51% of the shares in the project company with the actual capital

investment of only 10% of the shares. The remaining capital must be borne by the other private

sponsors. It is not entirely clear on how this mechanism will work and at the moment, we understand

most of the investors are still on the ‘wait and see’ situation for more certainty in the investment climate

especially in the power sectors. From our experience, the new green fields IPP projects are slowing

down since the implementation of this mechanism plus the recent news and information indicating that

there has been an overcapacity of electric power in Java Island. Nevertheless, the demands from the

investors in the electric power sectors are still very high and the trends in the Indonesian electric power

sectors now are that the investors are looking for the acquisition of the existing power plants rather than

commencing a new green fields IPP with PLN.

3 When an independent power producer (IPP) sells electricity, do they conclude a

power purchase agreement (PPA)? Who are the typical purchasers? Is it possible

to negotiate the terms of the PPA?

In brief, an IPP company (holding a specific license to provide electric power for public use (ie Izin

Usaha Penyediaan Tenaga Listrik - “IUPTL”)) must sign a PPA with PLN to kickstart the project and it

is the cornerstone operational agreement for an IPP. Commonly, the purchaser is PLN, as the sole

off-taker of the electric power generated by the IPP company. However, the IPP company can also sell

the electric power it generates to another integrated IUPTL (IUPTL terintegrasi) holder, eg an IPP

company in industrial estate. The Electric Power Law and Government Regulation (“GR”) Number 14 of

2012 on The Electric Power Supply Business as amended by GR Number 23 of 2014 open up private

participation such as through IPPs in the supply of power for public use and for transmission and

distribution. However, this is yet limited to the power generation business field. For distribution, PLN

still retains the 'first priority' to supply electric power for public use.

In practice, PLN provides a template PPA which ‘evolves’ from project to project. PLN ‘updates’ its PPA

template based on past projects with the terms and conditions that PLN has agreed to. Therefore, an

old-day PPA is very different from a recent PPA, while recent PPAs may be slightly different from each

other, as PLN either includes provisions which benefit PLN and remove provisions which do not. The

PLN procurement team provides the initial draft PPA in the Request For Proposals (RFP). However, the

template is not a standard non-negotiable document. On the contrary, although it is common in the

RFP that PLN only allows minor deviation to the PPA template, the parties need to negotiate the draft

PPA. Without a doubt, PPA is the cornerstone and long-term agreement (the maximum term is 30

years) between the IPP company and PLN and therefore, ideally, every aspect of it must be negotiated

with PLN in all aspects, ie all technical, financial, commercial and legal clauses. Some of PLN’s new

provisions for PPAs are the Project Cost Account (or Project Development Cost Account – a specific

account in which the IPP must show PLN that it has sufficient financial resources to be able to develop



the project) and an increase in the value of Bank Guarantees from previous PPAs. This may be PLN’s

way of mitigating the risk of development failure due to an IPP’s lack of financial resources from the

beginning.

Furthermore, in 2017, the Indonesian Government issued Minister of Energy and Mineral Resources

(“MEMR”) Regulation Number 10 of 2017 on the Principles of Power Purchase Agreements, as

amended first by MEMR Regulation Number 49 of 2017 and lastly by MEMR Regulation Number 10 of

2018 (“MEMR Reg PPA”) establishing the legal minimum standard provisions of the PPA. MEMR Reg

PPA sets out the principles of PPAs between PLN as the purchaser and IPPs as the sellers in the electric

power system. The regulation aims to provide legal certainty in the power supply business by revising

provisions of PPAs on risk allocation and force majeure. IPPs and PLN must both cover certain risks.

However, MEMR Reg PPA has now removed government force majeure from the types of risk that both

IPPs and PLN must cover. In practice, the allocation of the risk of government force majeure may

significantly affect the bankability of IPP projects. Under previous PPAs, government force majeure was

one of the types of risk PLN bore. It will be interesting to see how this provision is implemented under

the new model PPAs, ie whether PLN will accept the risk of government force majeure or not. If not,

certain assurances will have to be created to comfort the providers of loans to project companies.

In addition, government force majeure events and force majeure due to changes to the laws no longer

relieve either PLN or IPPs from their obligations under their PPAs, as both are removed from the

MEMR Reg PPA. Despite this, the PPA is still negotiable, as the MEMR Reg PPA expressly states that

any provisions which are not covered by the MEMR Reg PPA will be determined through

business-to-business negotiations between PLN and the IPP company.

The MEMR Reg PPA covers all types of power plant, including coal-fired, gas-fired, oil-fired,

geothermal, hydro, and biomass power plants. While, PPAs with intermittently new and renewable

energy power plants, mini-hydro power plants (below 10MW), biogas power plants, and municipal

waste-to-energy power plants will be covered by specific MEMR Regulations – which are yet to be

issued.

Below is a summary of some provisions that a PPA must include according to MEMR Reg PPA. These

are the minimum requirements and do not eliminate the transactional nature of a PPA:

No. Provision Detailed Explanation

1. The term of the PPA The term of a PPA may be up to 30 (thirty) years as of the

Commercial Operation Date (“COD”), depending on the type of

power plant. The form of business cooperation is typically




Build-Own-Operate-Transfer (BOOT).

2. IPP company’s rights

and obligations (as the

seller)

1. The IPP’s rights are:

• to receive payment for sales of electric power;

• to obtain incentives for any acceleration of the COD, if

requested by PLN; and

• to receive the deemed dispatch, if PLN’s network is

disrupted for reasons other than force majeure.

2. The IPP’s obligations are:

• to design, finance, build, own, operate and transfer the

ownership of the power plant;

• to provide security under a performance bond (jaminan

pelaksanaan) and a performance guarantee (jaminan

kinerja);

• to pay a fine for any failure to achieve the guaranteed

performance (jaminan kinerja) as well as a fine for a delay

in the COD;

• to submit a monthly power supply plan;

• to supply electric power to PLN according to the electric

power supply plan and maintain the supply during the

term of the PPA;

• to obtain all the required licenses and approvals including

with regard to the local content requirements;

• to pay fines in accordance with the applicable provisions of

the PPA.

3. PLN’s rights and

obligations (as the

purchaser)

1. PLN’s rights are:

• to receive a reliable and sustainable supply of electric

power from the power plant; and

• to obtain all approvals required for the PPA.

2. PLN’s obligations are:

• to provide IPPs incentives to accelerate the COD, if

requested by PLN;

• to purchase the electric power supplied by the IPPs in

accordance with the PPAs which have been entered into for

a certain term;




• to pay for deemed dispatches, if the PLN network is

disrupted for reasons other than force majeure; and

• to maintain and preserve the reliability of the grid

receiving the electric power.

4. Risk Allocation

PLN will bear the following risks:

• the required power/load;

• limited transmission capacity; and

• force majeure.

The IPP will bear the following risks:

• land acquisition related matters;

• licenses, including the environmental license;

• fuel supplies;

• construction schedule accuracy;

• power plant performance; and

• force majeure.

5. Project Implementation

Guarantee

The IPP must provide performance security for completing the

following stages and activities:

Stage 1: reaching the financing date;

Stage 2: reaching the commissioning date; and

Stage 3: reaching the COD.

6. Fuel Supply

Fuel for electric power plants can be supplied by either the IPP or

by PLN. If the fuel is supplied by PLN, the following conditions

apply:

1. the IPP must guarantee that the specific fuel consumption

(SFC) or specific heat rate (SHR) will be in accordance with

the PPA;

2. the IPP must always monitor the relevant coal procurement

costs under a contract aimed at achieving effective and

efficient procurement costs; and

3. gas suppliers must ensure the continuity of their gas supplies,

otherwise they will be fined under the deliver-or-pay

arrangement.




7. Transaction

All payments in power purchase transactions must be in

Indonesian Rupiah, unless a Bank Indonesia exemption is

obtained.

- If the seller fails to deliver power to PLN, the seller must pay

a fine to PLN for a certain period.

- If PLN fails to take the power, PLN must pay a fine to the

seller for a certain period.

- The fine is determined according to the investment

component.

8. Commissioning and

COD

• The commissioning provisions refer to the regulation on the

procedures for the accreditation and certification of electric

power related matters (MEMR Regulation Number 38 of

2018).

• Power plant operations must be undertaken according to the

relevant grid codes for the local system, or, in the absence of

these codes, with any grid code determined by the Director

General of Electric Power or other existing grid codes.

• IPPs are entitled to incentives related to PLN requests to

accelerate the COD.

• IPPs are subject to liquidated-damages in an amount equal to

the electric power generating cost incurred by PLN as a result

of any delay in reaching the COD.

9. Operating System

(Dispatch) Control

To maintain the reliability of the power system so it is according

to the grid code, a dispatcher must plan and implement an

operating system (dispatch), taking into account its cost and

conformity to the PPA. Monthly dispatch reports must be

delivered to the Director General recording among other things,

any breach of the grid code by PLN or by the IPP.

10. Fines for a Power

Plant’s lack of

Performance

The actual power-plant performance value is measured taking

into account any Availability Factor (“AF”) or Capacity Factor

(“CF”), as well as the relevant heat rate and/or other technical

provisions of the PPA. If this value does not meet the target

agreed to under the PPA, the IPP may have to pay a certain type of

fine, such as a liquidated-damages fine, an AF or CF fine, an

outage-factor fine, a heat-rate fine etc.

11. PPA Termination A PPA can be terminated for the following reasons:




1. the term of the PPA has expired;

2. unilateral termination before the term of the PPA expires (eg

due to a license not being issued, no funding being available,

major unexpected cost overruns, etc.);

3. insufficient funding;

4. bankruptcy; or

5. force majeure.

12. Transfer of Rights

Ownership of an IPP may not be transferred to any other party

before entering the COD stage, unless the transfer is to an

affiliate, 90% of the shares of which are owned by the party

intending to transfer its shares.

A transfer of ownership upon reaching COD requires written

approval from the purchaser. The transfer must be reported to the

MEMR through the Director General.

13. Price Adjustment

The price for the electric power sold may only be adjusted if the

following are adjusted:

1. the regulations on the sale price of electric power;

2. the tax regulations;

3. the environmental protection regulations; and/or

4. the regulations on the cost of energy.

14. Dispute Settlement

Any dispute which arises between PLN and an IPP must be settled

according to the following procedure:

1. amicable settlement; failing which,

2. settlement by appointed experts; and finally,

3. arbitration through the Indonesian National Board of

Arbitration (BANI), The United Nations Commission on

International Trade Law (UNCITRAL) or through another

arbitration institution.

15. Force Majeure

PLN and the IPP are released from their respective obligations if a

Natural Force Majeure event:

• causes a COD delay: a time extension for as long as the

natural disaster continues (including time for necessary

repairs to the project); or

• causes an inability to distribute electric power: a time

extension for as long as the natural disaster continues

(including time for necessary repairs to the project).



4 Does your country have a Feed in Tariff system? How are tariffs determined? Is a

bidding system used?

The rates of the Indonesian Feed-in Tariffs were set using PLN’s electric power basic cost (ie BPP), or in

other words, the marginal production cost that PLN would incur to produce electric power in the region

of the renewable energy project.16 This tariff sets from BPP does not include the transmission cost,

which is determined based on business-to-business negotiations between PLN and the relevant

developer.17

In 2017, MEMR applied the latest Feed-in Tariff for all new renewable energy for electric power

generation under MEMR Regulation Number 50 of 2017 on the Use of Renewable Energy Supplying

Electric Power as amended by MEMR Regulation Number 53 of 2018 (“MEMR Reg. 50/2017”),

which include solar PV, wind, hydro, biomass, biogas, waste-to-energy, geothermal18, ocean energy and,

recently, biofuel.19 This regulation attempted to address the cost to PLN by capping renewable power

purchase prices at 85% of the BPP. The BPP does not differentiate between areas in a region where

there is a main grid despite some areas in that region not being connected. The main grid rate in this

case is the one applied.20

For waste-to-energy projects, if the regional BPP of a pertinent local grid is higher than the national

BPP, the tariff will be capped at 100% of the regional BPP. In particular, for projects in Sumatra, Java,

Bali and other locations in which the local BPP is equivalent to or lower than the national BPP, the tariff

will be determined based on negotiations between the developer and PLN. Regardless of this, in practice,

PLN remains capping the tariff in locations where its regional BPP is already lower than or equivalent to

the national BPP. This move is taken to avoid the BPP to rise in the next year.

In general, there are 3 (three) types of procurement procedure of electric power which PLN follows, ie:

(i) open tender; (ii) direct appointment; and (iii) direct selection. 16 Climate & Development Knowledge Network, “Policy Brief – Indonesian Feed-in Tariffs: challenges & options,”

https://cdkn.org/wp-content/uploads/2015/04/ECN-Policy-Brief-Indonesian-Feed-in-tariff-140304.pdf, accessed 6 December 2018.

17 Global Business Guide – Indonesia, “Legal Updates: Expanded Coverage and New Feed-in Tariff for Indonesia’s Waste

to Energy Projects,” (7 May 2018), http://www.gbgindonesia.com/en/main/legal_updates/expanded_coverage_and_new_feed_in_tariff_for_indonesia_s_waste_to_energy_projects.php, accessed on 6 December 2018.

18 Specifically, the Feed-in Tariff for geothermal energy also remains subject to MEMR Regulation Number 17 of 2014 on

the Purchase of Electric Power from Geothermal Power Plant and Geothermal Steam for Geothermal Power Plant by PLN.

19 The Purnomo Yusgiantoro Center, “Brief Notes for Indonesia’s Feed-in Tariff (FIT) Implementation.” 20 The International Institute for Sustainable Development, Missing the 23 Per Cent Target: Roadblocks to the

development of renewable energy in Indonesia – GSI Report, (February 2018), p. 7.

https://cdkn.org/wp-content/uploads/2015/04/ECN-Policy-Brief-Indonesian-Feed-in-tariff-140304.pdfhttp://www.gbgindonesia.com/en/main/legal_updates/expanded_coverage_and_new_feed_in_tariff_for_indonesia_s_waste_to_energy_projects.phphttp://www.gbgindonesia.com/en/main/legal_updates/expanded_coverage_and_new_feed_in_tariff_for_indonesia_s_waste_to_energy_projects.php



For an open tender, the procedure follows provisions under MEMR Regulation No. 001 of 2006 on the

Procedure for Selling Electric Power and/or Leasing of Networks for Electric Power Supply Business

Activities for the Public Interest, as amended by MEMR Regulation No. 004 of 2007. PLN must publish

an announcement of a public tender for the purchase of electric power by PLN. Afterwards, PLN must

establish a tender committee to handle the pre-qualification and bidding process. The period for

finalizing an open tender is approximately 316 days.

Further, PLN may purchase electric power through a direct appointment under the prevailing laws and

regulations, depending on which type of power plant is being procured, ie GR Number 7 of 2017 on the

Indirect Utilization of Geothermal (Energy) for Geothermal Power Plant (“GR 7/2017”), and MEMR

Regulation Number 44 of 2015 on The Purchase of Electric Power by PLN from Municipal

Waste-to-Energy Power Plant (“MEMR Reg. 44/2015”) for Municipal Waste-to-Energy Power Plant.

The mandate given by the MEMR under the relevant regulations to PLN to purchase electric power

from the relevant power plant is deemed as the MEMR's approval for PLN to make a direct appointment

and to agree on the electric power purchase price. The period for finalizing a direct appointment is

approximately 100 days.

The direct selection procedure is provided under MEMR Reg. 50/2017. In this type of procurement,

PLN must conduct a due diligence study on the technical and financial capacity of the IPP candidates

that will operate the power plant and sell electric power to PLN. The due diligence study can also be

conducted by a procurement agent appointed by PLN. In this case, MEMR approval is required for the

electric power purchase price. For a direct selection, the pre-qualification procedure until a contract is

agreed on may take up to 150 days.

In connection with the above, please see below the procurement procedure and Feed-in-Tariff for each

type of NRE power plant:

No. NRE Power

Plant Type

Relevant

Regulation

Procurement

Procedure

Feed-In Tariff

Regional BPP >

national average

BPP

Regional BPP ≤

national average

BPP

1. Solar Power

Plant

(“PLTS”)

MEMR Reg.

50/2017

Direct selection

based on Capacity

Quota21

85% of the regional

BPP

Business-to-Busines

s negotiations

2. Wind Power

21 Under MEMR Reg 50/2017, the capacity quota is the power plant’s maximum capacity offered to a business entity for a

certain term at a determined electric power price.



No. NRE Power

Plant Type

Relevant

Regulation

Procurement

Procedure

Feed-In Tariff

Regional BPP >

national average

BPP

Regional BPP ≤

national average

BPP

Plant

(“PLTB”)

3. Biomass

Power Plant

(“PLTBm”)

Direct selection

4. Biogas Power

Plant

(“PLTBg”)

5. Ocean

Energy

Power Plant

(“PLTA

Laut”)

6. Hydro-Electr

ic Power

Plant

(“PLTA”)

The regional BPP

In Sumatra, Java

and Bali, or in other

systems where the

regional BPP ≤ the

national average

BPP, the tariff will

be based on B2B

negotiations. In

other regions, the

tariff will be the

regional BPP.

7. Geothermal

Power Plant

(“PLTP”)

GR 7/2017 Open tender or

Direct

appointment

8. Municipal

Waste-to-En

ergy Power

Plant

(“PLTSa”)

MEMR Reg.

50/2017 and

MEMR Reg.

44/2015

Direct

appointment22

9. Biofuel

Power Plant

(“PLTBBN”)

MEMR Reg.

50/2017

Direct selection Mutual agreement of the parties.

22 However, under PR Number 35/2018, specific to waste-to-energy, the local government can assign developers from

among region-owned-enterprises (Badan Usaha Milik Daerah - “BUMD”) or hold an open tender for the private sector. If the private sector is not interested and the BUMD is considered not capable, the MEMR can assign the waste-to-energy power plant to a state-owned enterprise based on a recommendation from the local government.



5 Will an IPP take the quantity risk (i.e. the risk that the generating facility may not

be dispatched by the offtaker (in case of PPA) or due to low demand or competition

in the market (in case of sale into market))?

According to the market precedent, PLN will continue paying for the generated electric power as

‘deemed dispatch’ if the PLN network is disrupted whether due to force majeure or not.

In a recent PPA, this payment was to be made during the take or pay period (i) if one or more events or

circumstances affecting PLN's grid system (other than due to an Event of Force Majeure) affect the IPP

company’s ability to provide net dependable capacity or net electrical output for a certain period of

time; or (ii) if a force majeure event affects PLN’s Grid System or other PLN owned facilities

necessitating repairs, the power plant will be ‘deemed dispatched’ to the extent that the IPP company

would have been able to deliver and/or PLN would have been able to accept net electrical output in

accordance with the terms and conditions of the PPA and PLN will continue obliged to pay for net

dependable capacity as per the PPA until the facilities are repaired.

This payment is limited to a certain period under the PPA, eg up to a maximum of 14 days in aggregate

in any contract year and 120 days in the aggregate during the term of the PPA. If a Force Majeure event

caused a long-term interruption (eg 6 months), PLN also had to pay for termination payments to the

IPP.

The MEMR Reg PPA has considerably changed this condition. As now if a Natural Force Majeure event

(the only force majeure event covered by the MEMR Reg PPA) prevents PLN from taking power, the

PPA may instead be extended by the length of time the Natural Force Majeure event and subsequent

repairs have taken. The power plant is not ‘deemed dispatched’ and PLN is no longer required to make

the deemed dispatch payments. No doubt, this will become major concern and issue for sponsors and

also lenders who require regular scheduled loan repayments from the project’s cash flow. So far, no

precedent has been set yet for how this provision should be implemented in practice. For future projects,

PLN will likely insist on the inclusion of this provision in the PPA to conform to the MEMR Reg PPA.

6 Please explain risk allocation and remedies upon occurrence of force majeure in

connection with electric power generation projects. Are there any differences

between the risk allocation and remedies (i) upon occurrence of Political Force

Majeure and (ii) upon occurrence of General Force Majeure?

General

The market practice for force majeure in electric power projects applies the same fairness principle.

Either party will be excused from complying with its obligations and will not be deemed in default of



any obligation under the PPA for as long as its failure to comply with the obligation is due to force

majeure.

Events of force majeure include, but are not limited to:

a) acts of war or the public enemy whether war is declared or not;

b) public disorders, insurrection, rebellion, sabotage, riots or violent demonstrations;

c) explosions, fires, earthquakes, floods, or other natural calamities and acts of God, or the

discovery of hazardous materials or historical artefacts on the Site;

d) strikes or other industrial action by workers or employees of either party and/or its contractors

or subcontractors or any other parties engaged or appointed by either party;

e) with respect to the IPP company only:

• the occurrence of an event of force majeure as specified in paragraphs (a) to (d) above

affecting the coal supplier – as the coal supply will be the IPP company’s responsibility; and

• any Change in Circumstance, ie government/political force majeure, change of law.

Effects of Force Majeure

In practice, if the force majeure event occurs before the COD and causes a delay in the project’s

milestone schedule, the milestone schedule will be equitably adjusted to avoid or minimize overall

delays resulting from the force majeure event. However, if it results in a ‘material delay’ in the

completion of the project or causes material damage to the Plant, and there is no insurance for force

majeure (as it is not normally required to be insured for according to Good Utility Practice), or it could

not be insured against before it occurred, the parties will negotiate in good faith a satisfactory solution

to allow the construction or the operation of the power plant to continue, and any extension of the take

or pay period (if reasonably necessary). If they fail to find a solution satisfactory to both parties, PLN

and the IPP company may jointly terminate the PPA.

If a force majeure event occurs:

(i) during the take or pay period: the take or pay period will be extended and proportionately

adjusted for a period of time equal to the period during which the IPP company is affected; or

(ii) during the take and pay period: the PPA will be extended and proportionately adjusted for a

period of time equal to the period during which the IPP company is affected,

provided however, in each case, that the term of the PPA will not exceed 30 years commencing from the

COD.



Deemed To be Commissioned and Deemed Dispatch

If an event of force majeure (other than a Change in Circumstances) affects PLN’s grid system or other

PLN owned facilities necessitating repairs, and the repairs are not completed within a certain period,

the affected unit or power plant (with an agreed to MW capacity) will be ‘deemed to be commissioned’

and ‘deemed to be providing’ net dependable capacity for the power plant with the actual AF deemed to

be 80%.

Subsequently, PLN will compensate the IPP company for the net dependable capacity for the unit or

power plant due to the delayed the net dependable capacity test. If the unit or power plant is then tested

and fails the net dependable capacity test, the deemed commissioned status will cease, and PLN will not

be obliged to make any further payment. If it passes the test and an excess in payment is caused by the

difference between the test results and the agreed MW capacity in the PPA, the payment will be credited

against future payments from PLN to the IPP company.

In addition, during the take or pay period, if an event of force majeure (other than a Change in

Circumstances) affects PLN’s grid system or other PLN owned facilities necessitating repairs, and the

repairs are not completed within a certain period, the power plant will be ‘deemed dispatched’ to the

extent that the IPP company would have been able to deliver and/or PLN would have been able to

accept the net electrical output and PLN will be obliged to pay for net dependable capacity in

accordance with the PPA.

However, the MEMR Reg PPA has considerably changed the above as PLN and the IPP company are

now released from their respective obligations if the Natural Force Majeure event:

• causes a COD delay: a time extension for as long as the natural disaster continues (including time

for necessary repairs to the project); or

• causes an inability to distribute electric power: a time extension for as long as the natural disaster

continues (including time for necessary repairs to the project).

Matters Not Exempted

An event of force majeure will not excuse the IPP company from the following:

a) any late payment;

b) any late delivery of equipment or materials caused by negligence or any omission by the IPP

company or its contractors;

c) any late performance by the IPP company or its contractors due to a failure to engage qualified

subcontractors or to hire an adequate number of personnel or workers;



d) submitting documents and/or drawings for approval by PLN without allowing sufficient time

for their review prior to purchase or manufacture; or

e) responsibility for delays resulting from reasonably foreseeable unfavorable weather or

unsuitable ground or sea conditions or other similar reasonably foreseeable adverse conditions.

Termination due to Force Majeure

Under a recent PPA, an event of force majeure can lead to the termination of the PPA if:

a) (i) it prevents or will prevent the construction of the project or operation of the power plant for a

continuous period of more than 24 months, and the event of force majeure fundamentally

frustrates the economic basis of the transaction under the PPA, or (ii) it is a Change in

Circumstances event of force majeure and the parties fail to find solution satisfactory to them

both, the parties may jointly terminate the PPA.

b) it affects PLN’s grid system or other PLN owned facilities necessitating repairs following a

continuous period of 180 days; in which case, the parties will discuss good faith an alternative

acceptable solution. If within 90 days no solution is reached, either party may terminate the

PPA, and PLN will have the option to purchase the project or all of the shares in the IPP

company, including the company’s title and interest in the project and rights and obligations at

the purchase price determined in the PPA.

Costs and Savings

A change of law is included as a ‘Triggering Event’ under the PPA provided that it will cause any (a)

increase in Costs (the cost of producing electric power including any capital, financing, operation and

maintenance costs, and tax, duty or levy costs imposed on or payable by the IPP company) or result in

Savings (a reduction in costs or expenses related to the project that have been realized by the IPP

company and directly affect the cost of producing electric power).

Note that ‘taxes, duties or levies’ are not considered “Savings” under the PPA. Such savings or

reductions in costs or expenses relating to the project must have already been realized by the IPP

company. For example, the approval of a corporate income tax holiday obtained by an IPP may arguably

not trigger any “Savings” yet as the corporate income tax holiday is currently not yet in effect and will

only apply after the IPP company has generated a profit and no further losses could be set off under the

applicable income tax laws and regulations.

Discussions of the price adjustment resulting from any savings or reduction of cost must commence

within 7 days of the notice for the triggering event. If the content of the notice (including the claim for



Costs or Savings attributable to the Triggering Event) is not disputed by the Parties, the appropriate

components of the price will be adjusted:

• as of the project COD, to reflect all undisputed claims submitted from the date of the agreement

until the project COD; and

• as of the first day of each contract year commencing with the first day of contract year 2, to reflect

all undisputed claims in the preceding contract year.

7 Please explain the components of termination payments for PPA (typically,

intended for project finance).

The components of a PPA termination payment are provided in the Appendix to the PPA and depend on

the cause of the PPA’s termination as follows:

a. Termination by PLN due to an event of default by the IPP company.

PLN will purchase all of the company's rights, title and interests in the project for a price equal

to:

• the total amount outstanding and payable by the company as the outstanding senior debt

and interest due and payable on the calculation date; minus

• the greater of (i) the sponsors’ equity commitment plus the sponsors’ contingent equity

commitment, minus the sponsors’ actual equity contributions, and, (ii) zero.

b. Before the project’s COD, (i) termination by the IPP company due to event of default by PLN; or

(ii) termination by the IPP company or PLN due to a certain construction period force majeure

(political force majeure or other force majeure affecting PLN or PLN’s grid system).

PLN will purchase all of the company’s rights, title and interests in the project for a price equal

to:

• the total amount outstanding and payable by the company as the senior debt and interest

due and payable on the calculation date; plus

• the sum of:

(A) the lesser of (x) the sponsors’ actual equity contribution and (y) the sum of the

sponsors’ equity commitment plus the sponsors’ contingent equity commitment; and

(B) an amount equal to a rate of 15% per annum calculated of the sum of the sponsors

actual equity contributions compounded annually from the date of each sponsor’s

actual equity contribution to the calculation date; less

• the sum of:

(A) the debt service reserve amounts; and



(B) payments made by PLN during any deemed period that have not been used to repay

the senior debt or to meet fixed operating and maintenance expenditures (including

c. After the project COD, (i) termination by the IPP company due to an event of default by PLN; or

(ii) termination by PLN due to political force majeure or other force majeure.

PLN will purchase all of the company’s rights, title and interests in the project for a price equal to the

sum of a calculation using certain formula provided in the PPA considering the net dependable capacity,

contract capacity and the senior debt component.

◇B Investment in the Electric Power Generation Industry

1 Are there any regulations on foreign companies to invest in electric power

generation projects in your country? If yes, what sort of regulations?

Certain conditions and limits apply to foreign investment in certain sectors, including infrastructure

involving joint cooperation or joint operation schemes for electric power generation projects. These are

imposed under the Negative List of Investment. We understand from the news that the government of

Indonesia is preparing an updated and more relaxed negative list with foreign investment restrictions in

certain sectors which include foreign shareholdings in power plants with a capacity of above 10 MW.

However, as of January 2019, we understand that the draft on updated negative list is still being

discussed and has not yet to come into effect. Therefore, for the purpose of this publication, we refer to

the currently prevailing Negative List of Investment.

Under the Negative List of Investment which restricts investment in certain business fields, foreign

shareholdings in power plants are generally limited to the following:

Capacity Conditions

< 1 MW 100% domestic shareholders

1 – 10 MW maximum 49% foreign shareholding is permitted

> 10 MW

maximum 95% foreign shareholding is permitted (or

maximum 100% if it is a Public Private Partnership, during

the term of the concession)



2 What is the most common form of company (such as LLC) as a project company for

an electric power generation project, and its characteristics? In addition, please

let us know if there is any important restriction on the shareholders agreement

from the legal or other perspective.

The form of project company for an electric power generation project is a limited liability company

(perseroan terbatas) established under Law Number 40 of 2007 on Limited Liability Companies

(“Company Law”). Investors (foreign or domestic) must also observe other Indonesian laws and

regulations issued by the relevant government authorities which impose terms and conditions on the

business activities under their supervision. Any Indonesian company in which foreign investors own

shares is considered a foreign investment company ("PMA Company").

A PMA company must have a purpose and objectives and its business activities may not violate the

prevailing laws or regulations, public order, and/or morality. The purpose and objectives of a PMA

company are those listed in its business license and must be specified in detail in its Articles of

Association. As explained above, the business activities of a PMA Company are subject to certain

conditions, limitations and exceptions under the Negative List of Investment.

A PMA Company must have at least 2 (two) shareholders. For its management, a PMA Company has 3

(three) organs: the General Meeting of Shareholders (“GMS”), the Board of Directors (“BOD”) and the

Board of Commissioners (“BOC”), each of which serves different functions. The GMS is the company

organ with the authorities which are not assigned to the BOD or the BOC, subject to the limitations

imposed under the Company Law and/or the Articles of Association of the company. The BOD has the

authority and is responsible for the management of the company for its best interest, according to its

purpose and objectives, as well as to represent the company in and out of the courts in accordance with

its Articles of Association. The BOC is responsible for the general and/or specific supervision of the

company, in accordance with its Articles of Association, and provides advice to the BOD.

In general, except for the restriction for the transfer of the ownership of an electric power generation

project company (IPP) to any other party before the COD (as will be elaborated below), no specific

provisions or requirements apply to shareholders agreements for electric power generation projects,

other than those under the Company Law which apply generally whatever the business sector.

3 Where a domestic or foreign company intends to sell its equities in an electric

power generation project in whole or in part, does any regulation apply?

Under the MEMR Reg PPA and MEMR Regulation Number 48 of 2017 on Business Supervision In The

Energy And Mineral Resources Sector, the ownership of an electric power generation project company



(IPP) may not be transferred to any other party before the COD, unless the transfer is to its affiliated

subsidiary, 90% of the shares of which are owned by the party intending to transfer its shares. Such a

transfer requires prior written approval from the purchaser (eg PLN) and must be reported to the

MEMR through the Director General of Electric Power. The regulation is silent on transfers of shares

after the project reaches its COD. However, the Sponsors’ Agreement (the generic form is attached as a

schedule to the PPA) will further regulate such transfer of shares from the sponsors after the project

reached COD. Nevertheless, this is a contractual arrangement between the sponsors and PLN.

4 In your country, what is the common method for a sponsor to invest in or provide

funds to a project company other than by way of acquisition of shares (or equity) of

a project company?

Foreign investment in Indonesia, including for electric power generation projects, is commonly made by

(i) acquiring shares in an existing Indonesian company; or (ii) establishing a new Indonesian company

(the company in each of (i) and (ii): the “Project Company”). Meanwhile, the most common method

for sponsors to provide funds to a Project Company as project finance is a common loan arrangement

provided by banks. However, in some cases, the funds are not provided by banks but are institutional

funds provided through the issuance of bonds by the Project Company to sponsors. Although this

scheme is not as common as an acquisition of shares in an existing company or the establishment of a

new company, the issuance of project bonds has been an alternative source of capital for project finance

in Indonesia, with the financing of PT Paiton Energy’s coal fired power plants in Probolinggo, East Java,

being a landmark for this scheme.

◇C Project Finance

1 Please list commonly used project finance schemes used for electric power

generation projects in your country.

Electric power generation projects are mostly financed through some or all of the following finance

schemes and sources of funds:

a. Equity

Equity can usually be provided through (i) shareholders’ participation; (ii) project sponsors

(subordinated debt); and (iii) shareholders loans (subordinated debt). Either the sponsor alone

or a consortium of investors can provide the funding.



b. Debt/Loans

In Indonesia, generally, debt is obtained through (i) bank loans; (ii) bonds (capital market); and

(iii) multilateral agencies.

1. Bank loans

Bank loans are structured based on the expected project cash flow, with a moratorium or

grace period, and an interest payment and principal repayment schedule. Bank loans are

usually fully secured and have recourse to project assets in the event of default. Since

electric power generation projects are capital intensive, they are often funded by a high

proportion of debt (to reduce overall funding costs). To reduce individual exposure, banks

often prefer to be part of a consortium or ‘syndicate’ of banks in which one bank often acts

as the ‘lead bank’.

2. Bonds (Capital Market)

Bonds represent the debt funding obtained for a project from the capital markets. The

benefits of bonds are:

(1) they can be cheaper and quicker than bank loans;

(2) they are less restrictive than bank loans, except regarding disclosure;

(3) the proceeds are disbursed in a single lump sum; and

(4) the investors are disparate (not a club of banks), many of which only hold a small

part of the project loan.

3. Multilateral Agencies

Multilateral agencies usually follow the same debt structure as purely private investors.

For example, multilateral agencies typically lend for long-term projects, are focused on

projects with an economic development impact, and provide technical guidance

throughout the project lifecycle.

c. Other Support

In specific cases, especia

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