www.pwc.com/id
Oil and Gas
in Indonesia
Investment, Taxation and Regulatory Guide
May 2024, 13
th
Edition
Photo source: Eni Muara Bakau BV
Cover photo courtesy of: PwC
DISCLAIMER: This publication has been prepared for general guidance on matters of interest only, and does
not constitute professional advice. You should not act upon the information contained in this publication without
obtaining specific professional advice. No representation or warranty (express or implied) is given as to the
accuracy or completeness of the information contained in this publication, and, to the extent permitted by law,
PwC Indonesia, its members, employees and agents do not accept or assume any liability, responsibility or duty
of care for any consequences of you or anyone else acting, or refraining to act, in reliance on the information
contained in this publication or for any decision based on it.
The documents, or information obtained from PwC, must not be made available or copied, in whole or in part, to
any other persons/parties without our prior written permission which we may, at our discretion, grant, withhold or
grant subject to conditions (including conditions as to legal responsibility or absence thereof).
Regulatory information is current to 31 January 2024.
s Contents
Insertion - Indonesian oil and gas
concessions and major infrastructure map
167
Foreword 8
Glossary 4
Energy transition 302
Regulatory framework 433
(Conventional) Upstream sector 544
Gross Split Production Sharing Contracts1205
Downstream sector 1326
Service providers
to the upstream sector
154
7
Industry overview 101
Appendices 160
About PwC | PwC oil and gas contacts
4PwC
Term Definition
AFE Authorisation for Expenditure
APBN Anggaran Pendapatan dan Belanja Negara (State Budget)
ASC Accounting Standard Codification
ATIGA ASEAN Trade in Goods Agreement
BBC Bare-boat charter
bbl Barrel
BBTUD British Thermal Units per Day
Bcm Billion Cubic Metres
BI Bank Indonesia
BiK Benefits in Kind
BKPM Badan Koordinasi Penanaman Modal (Indonesia’s Investment Coordinating
Board)
BOPD Barrels of Oil per Day
BP Migas Badan Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi (Oil and Gas
Upstream Business Activities Operational Agency), now SKK Migas
BPH Migas Badan Pengatur Hilir Minyak dan Gas Bumi (Oil and Gas Downstream Regulatory
Agency)
BPKP Badan Pengawasan Keuangan dan Pembangunan (the Financial and
Development Supervision Agency)
BPMA Badan Pengelola Migas Aceh (Special Oil & Gas Regulatory Body of Aceh)
BPR Branch Profit Remittance
BPT Branch Profits Tax (i.e. on BPRs)
BSCFD Billion Standard Cubic Feet per Day
BUMD Badan Usaha Milik Daerah (Regionally Owned Business Enterprise established
by the Regional Government)
BUK Migas Badan Usaha Khusus Minyak dan Gas Bumi (Oil and Gas Special Executive
Agency)
CBM Coal Bed Methane
CCS/CCUS Carbon Capture & Storage/Carbon Capture Utilisation & Storage
CD Community Development
CITR Corporate Income Tax Return
CNG Compressed Natural Gas
CO
2
Carbon Dioxide
CoD Certificate of Domicile
COP Conference of Parties
COVID-19 Coronavirus Disease of 2019
C&D Tax Corporate and Dividend Tax
DGB Directorate General of Budget
DGoCE Directorate General of Customs and Excise
DGOG Directorate General of Oil and Gas
DGT Directorate General of Taxes
Glossary
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 5
Term Definition
DHE Devisa Hasil Ekspor (Foreign Exchange Proceeds from Export)
DMO Domestic Market Obligation
DPR Dewan Perwakilan Rakyat (House of Representatives)
EIT Employee Income Tax
EOR Enhanced Oil Recovery
ESG Environmental, Social and Governance
E&P Exploration & Production
FCR Foreign Exchange Report
FDC Foreign-owned Drilling Company
FMR Financial Monthly Report
FMV Fair Market Value
FPS Floating Production System
FPSO/FSO Floating Production Storage and Offload (vessel)/Floating Storage and Offload
(vessel)
FPU Floating Production Unit
FQR Financial Quarterly Report
FSRU Floating Storage Regasification Unit
FSU Floating Storage Unit
FTP First Tranche Petroleum
FTZ Free Trade Zone
G&G Geological and Geophysical
GAAP Generally Accepted Accounting Principles
GDP Gross Domestic Product
the Government Government of Indonesia
GHG Greenhouse Gas
GR Peraturan Pemerintah (Government Regulation)
GRR Grass Root Refinery
GS Gross Split
HPP Harmonisasi Peraturan Pajak (the Harmonisation of Tax Regulations)
HS Harmonised System
IAS International Accounting Standards
ICP Indonesian Crude Price
IDR Indonesian Rupiah
IFAS Indonesian Financial Accounting Standards
IFRS International Financial Reporting Standards
JETP Just Energy Transition Partnership
JOA/JOB Joint Operation Agreement/Joint Operating Body
KBLI Klasifikasi Baku Lapangan Usaha Indonesia (Indonesian Standard Industry
Classification)
KEK Kawasan Ekonomi Khusus (Special Economic Zone)
Km
2
Square Kilometre
LNG Liquefied Natural Gas
LST Luxury-goods Sales Tax
6PwC
Term Definition
MBOE Thousand Barrels of Oil Equivalent
MBOEPD Thousand Barrels of Oil Equivalent per Day
MBOPD Thousand Barrels of Oil per Day
MIGAS Minyak Bumi dan Gas Alam (Oil and Natural Gas)
MMBOE Million Barrels of Oil Equivalent
MMBOPD Million Barrels of Oil per Day
MMBtu Million British thermal units
MMSCFD Million standard cubic feet per day
MoEMR Ministry of Energy and Mineral Resources
MoF Ministry of Finance
MRV Monitoring, Reporting, and Verification
MTPA Million Tonnes Per Annum
NBV Net Book Value
NJOP Nilai Jual Objek Pajak (Tax Object Selling Value)
NPWP Nomor Pokok Wajib Pajak (Tax Payer Identification Number)
OECD Organisation for Economic Co-operation and Development
OPEC Organisation of Petroleum Exporting Countries
OSS Online Single Submission
PBB Pajak Bumi dan Bangunan (Land and Building Tax)
PBI Peraturan Bank Indonesia (Bank Indonesia Regulation)
PCO Parent Company Overhead
PE Permanent Establishment
Perppu Peraturan Pemerintah Pengganti Undang-Undang
Pertagas PT Pertamina Gas
PGN PT Perusahaan Gas Negara (State Gas Company)
PHR PT Pertamina Hulu Rokan
PIS Placed Into Service
PMA Penanaman Modal Asing (Foreign Investment Company)
PMK Peraturan Menteri Keuangan Republik Indonesia (Minister of Finance Regulation)
PoD Plan of Development
PP&E Property, Plant & Equipment
PSC Kontrak Kerja Sama - KKS (Production Sharing Contract, one of the types of
Joint Cooperation Contracts)
PSN Proyek Strategis Nasional (National Strategic Projects)
PT Perseroan Terbatas (Limited Liability Company)
PTK Pedoman Tata Kerja (Standard Operating Procedure)
PwC PwC Indonesia, or the PwC global network of firms, as the context requires
RDMP Refinery Development Master Plan
RPT Risk Participation Transaction
RPTKA Rencana Penggunaan Tenaga Kerja Asing (Foreign Manpower Employment Plan)
RTO Regional Tax Office
SA-VAT Self-assessed VAT
SDA Sumber Daya Alam (Natural Resources)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 7
Term Definition
SE Surat Edaran (Circular Letter)
SFAS Statement of Financial Accounting Standards
SKK Migas Satuan Kerja Khusus Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi
(Special Taskforce for Upstream Oil and Gas Business Activities)
SKB Surat Keterangan Bebas (Tax Exemption Declaration Letter)
SKFP GS Surat Keterangan Fasilitas Perpajakan GS (GS Tax Facilities
Letter)
SKUP Surat Kemampuan Usaha Penunjang (Supporting Business Capacity Certificate)
SOE Badan Usaha Milik Negara - BUMN (State-Owned Enterprise)
SPOP Surat Pemberitahuan Objek Pajak (Notification of PBB Objects)
SPPT Surat Pemberitahuan Pajak Terutang (Official Tax Payable Notification)
SSP Surat Setoran Pajak (Tax Payment Slip)
Tc f Trillion Cubic Feet
TKDN Tingkat Komponen Dalam Negeri (Local Content Level)
TPAA Trustee Paying Agent Agreement
TWh Terawatt hours
UK United Kingdom
UoP Units of Production
US United States
USD US Dollar
US GAAP Generally Accepted Accounting Principles (in the United States)
VAT Value Added Tax
WAP Weighted Average Price
WHT Withholding Tax
WP&B Work Program & Budget
8PwC
“Welcome to the 13
th
edition of PwC Indonesia’s Oil and Gas in Indonesia—Investment,
Taxation and Regulatory Guide. In recent years, we have witnessed a rapid transformation
in the macroeconomic landscape, with sustainability taking centre-stage. However, this
shift in focus presents a challenge, as many countries still heavily rely on fossil fuels for
their energy needs and daily necessities, including petrochemical products. Recognising
the need to balance sustainability with energy and petrochemical product demand,
the investment climate for oil and gas has become even more crucial. In response, the
Indonesian government has implemented alternative solutions, such as the establishment
of a carbon credit market to promote emission offsetting. Additionally, there is a growing
emphasis on carbon capture & storage (CCS) as a prominent solution, given Indonesia’s
immense potential in this area. These initiatives align with the government’s broader focus
on energy transition, aiming to strike a balance between energy demand and economic
growth, and the country’s commitment to achieving net-zero emissions by 2060.
This edition of the guide focuses on updating readers on the latest tax, regulatory and
commercial changes since our previous edition, with an additional focus on the energy
transition in Indonesia.
This publication has been written as a general investment and taxation guide for all
stakeholders interested in the oil-and-gas sector in Indonesia. We have therefore
endeavoured to create a publication which can be of use to existing investors, potential
investors, and others who might have a general interest in the status of this important
sector of the Indonesian economy.
This publication is organised into chapters that encompass the following overarching
subjects:
1. Industry overview;
2. Energy transition;
3. Regulatory framework;
4. (Conventional) upstream sector;
5. Gross Split Production Sharing Contracts;
6. Downstream sector; and
7. Service providers.
As the global energy landscape continues to evolve, Indonesia’s oil and gas industry finds
itself at a critical juncture. The world’s shift towards a more sustainable and low-carbon
future presents both risks and opportunities for the industry. Balancing the ongoing
decline in oil and gas production with the need for more sustainable practices poses a key
challenge that requires attention.
Foreword
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 9
To tackle this challenge, SKK Migas has launched a comprehensive Indonesia Oil and Gas
Strategic Plan, known as IOG 4.0. This ambitious initiative aims to achieve a production
target of one million barrels of oil per day (BOPD) and twelve billion standard cubic feet of
gas per day (Bscfd) by 2030. The plan is supported by low-carbon initiatives, including new
regulations, energy management, zero flaring, reduction of fugitive emissions, reforestation,
and the implementation of CCS and carbon capture, utilisation & storage (CCUS)
technologies.
This guide also explores various aspects of the ongoing energy transition, starting from
the evolving global energy landscape to the policy frameworks and regulatory measures
that are shaping the future of the industry. It also delves into the potential of renewable
energy sources, such as solar and wind, and their integration into the existing oil-and-gas
infrastructure. Additionally, the guide emphasises the importance of energy efficiency and
its role in reducing carbon emissions.
Another area highlighted in this guide is the development of CCS technologies. CCS
has emerged as a promising solution for mitigating carbon emissions from fossil fuel-
based industries, including oil and gas. By capturing CO
2
emissions and storing them
underground, CCS can significantly reduce the industry’s carbon footprint and contribute to
global efforts to combat climate change.
The Government has shown its support for the implementation of CCS/CCUS activities,
through the Ministry of Energy and Mineral Resources (MoEMR) Regulation No. 2/2023
issued in March 2023 and Presidential Regulation No. 14/2024 issued in January 2024.
These regulations outline processes for project approval, monitoring, issued in January
reporting, and verification. They also allow for carbon credit monetisation to fund these
projects.
This publication aims to support investors in navigating the Indonesian oil and gas
investment climate, and to support the growth of the industry. Readers should note that
the regulatory content in this publication was current as at 31 January 2024. Whilst every
effort has been made to ensure that all information was accurate at the time of printing,
many of the topics discussed are subject to interpretation, and regulations are changing
continuously. As such, this publication should only be viewed as a general guidebook and
not as a substitute for up to date professional advice. For further guidance on investment
opportunities in the Indonesian oil and gas sector, we recommend reaching out to PwC’s oil
and gas specialists (as listed in Appendix II).
We hope that you find this publication interesting and useful, and we wish all readers
success with their endeavours in the Indonesian oil and gas sector.
”
10PwC
1.1 Global oil and gas overview
As global leaders push for lower carbon emissions and the adoption of
new technologies, the oil and gas industry faces economic challenges
and geopolitical tensions which have driven price volatility in recent
years. The brent crude price averaged USD83 per barrel in 2023
down from USD101 per barrel in 2022. In summary, price volatility in
2023 was influenced by shifting economic growth expectations, tight
monetary policies in advanced economies, and production cuts by
OPEC+, while geopolitical concerns around the Russia-Ukraine and
Middle East conflicts continued to play a part. A summary of oil prices
throughout 2022 and 2023 is presented below
1
.
Oil Prices 2022 and 2023
40
60
80
100
120
0
25
50
75
100
125
Jan 22Mar 22May 22Jul 22Sep 22Nov 22Jan 23Mar 23May 23Jul 23Sep 23Nov 23
Crude oil, Brent (USD/bbl)
Crude oil, West Texas Intermediate (WTI) (USD/bbl)
Indonesia Crude Price (ICP) (USD/bbl)
Source: MoEMR, World Bank, “Pink Commodity Sheet”, 2023
Based on analyses by the International Energy Agency (IEA) and the
US Energy Information Administration (EIA), the global oil supply and
demand was expected to be around 101-102 million barrels per day
(MMBOPD), with an overall excess supply, relatively higher in Q1
2023 compared to Q3 and early Q4 2023. In general, 45% of global
oil demand was coming from the non-OECD countries with growth
of 2.9 MMBOPD year-on-year. In more detail, the global oil demand
growth was led by China (+1.8 MMBOPD) where the September
consumption set another all-time record at 17.1 MMBOPD (the fifth in
2023 and fourth in a row, after earlier records in March, June, July and
August), driven by China’s gradual reopening from stringent COVID-19
measures, ongoing recovery in transportation activity and air travel in
China started to recover as tourism picked up
2
.
Industry
overview
1
1 PwC Internal Analysis, World Bank, “October 2023 Commodity Markets Outlook: Under
the Shadow of Political Risks”, Commodity Markets Outlook, October, 2023.
2 World Bank,"April 2023 CMO: Lower Price, Little Relief," CMO, October, 2023.
10 PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 11
On the other hand, there was an overall oil demand decline by 130 thousand barrels per
day (MBOPD) year-on-year in the OECD, largely due to Europe’s sharp deceleration,
despite US oil demand rising by 220 MBOPD year-on-year to an average 20.5 MMBOPD for
Q3 2023
3
.
On the global oil supply side, OPEC+ members agreed to cut oil production by 1.2
MMBOPD until the end of 2023, which was in addition to production cuts already in place.
This agreement meant production targets would be 3.66 MMBOPD lower each month
relative to actual August 2022 production through the end of 2023
4
. Also, in February 2023,
the EU and G7 implemented price caps on Russia’s oil exports, alongside an embargo on
Russian oil products. These measures aimed to maintain oil flows while reducing Russia’s
revenue, as its oil prices were significantly lower than Brent crude. Consequently, Russia’s
oil revenues dropped notably, prompting it to redirect oil to other markets. However,
transportation constraints posed challenges to maintaining export volumes. Russia
announced a 0.5 MMBOPD reduction in crude oil production from March to June 2023,
potentially due to difficulties in exporting oil products
5
.
Despite OPEC+’s announcement of a production cut in June, its impact on prices was
limited as the reduction was offset by production increases from Iran and the US. While,
additional cuts of 1 MMBOPD by Saudi Arabia since July and 0.3 MMBOPD by Russia
since October further tightened the balance between supply and demand
6
. Moreover,
concerns that the war between Israel and Hamas would escalate into a wider regional
conflict, disrupting oil-supply flows, did not materialise. With no significant unforeseen
outages, world oil supply was firmly on an upward trajectory, with October output
increasing by 320 MBOPD month-on-month. Record output from the United States, Brazil,
and Guyana underpinned last year’s increase to a record 102 MMBOPD
7
. Production
from the world’s top three oil producers – the United States, Saudi Arabia and Russia in
November 2023 were at 19.8 MMBOPD (roughly 1.2 MMBOPD higher than last year),
10.9 MMBOPD (OPEC+ cuts and sharp voluntary curbs have seen it shut in a massive 1.8
MMBOPD) and 10.9 MMBOPD (down 170 MBOPD year-on-year) respectively.
Gas Prices 2022 and 2023
0
10
20
30
40
50
60
70
80
0
10
20
30
40
50
60
70
80
Jan 22
Feb 22
Mar 22
Apr 22
May 22
Jun 22
Jul 22
Aug 22
Sep 22
Oct 22
Nov 22
Dec 22
Jan 23
Feb 23
Mar 23
Apr 23
May 23
Jun 23
Jul 23
Aug 23
Sep 23
Oct 23
Nov 23
Dec 23
Liquefied natural gas, Japan (USD/MMBTU)
Natural gas, US (USD/MMBTU )
Natural gas, Europe(USD/MMBTU)
Source: MoEMR, World Bank, “Pink Commodity Sheet”, 2023
3 World Bank, "October 2023 CMO: Under the Shadow of Political Risks," CMO, October, 2023.
4 US Energy Information Administration (EIA), “What is OPEC+ and how is it different from OPEC?," 2023.
5 World Bank, "April 2023 CMO: Lower Price, Little Relief," CMO, April, 2023.
6 World Bank, "October 2023 CMO: Under the Shadow of Political Risks," CMO, October, 2023.
7 IEA, “Oil Market Report - November 2023," November, 2023.
12PwC
8 World Bank, "October 2023 Commodity Markets Outlook (CMO): Under the Shadow of Political Risks," Commodity
Markets Outlook, October, 2023.
9 IEA (International Energy Agency). “Gas Market Report Q1 2024," January, 2024.
10 IEA (International Energy Agency). “Gas Market Report Q1 2024," January, 2024.
11 World Bank, "October 2023 CMO: Under the Shadow of Political Risks," CMO, October, 2023.
12 World Bank, "October 2023 CMO: Under the Shadow of Political Risks," CMO, October, 2023.
13 “How Natural Gas Can Displace Competing Fuels," UNECE, 2019.
On the other hand, gas prices were heavily affected by the conflict in the Middle East,
resulting in increased volatility. In October 2023, European natural gas prices surged to
USD 14.60/Million British Thermal Units (MMBTU) following the shutdown of a gas field off
the Israeli coast, an explosion at an interconnector in the Baltic Sea, and concerns about
escalating conflict in the region. The European benchmark, Netherlands Title Transfer
Facility (TTF), continued its decline, reaching USD 11.50/MMBTU by December 2023.
The US benchmark (Henry Hub) also experienced volatility, rising to USD 3.30/MMBTU in
January 2023, then dropping to roughly USD 2.20/MMBTU by September 2023. Meanwhile,
Japan’s Liquefied Natural Gas (LNG) fell to USD 14.40/MMBTU in April 2023 and continued
its decline, reaching USD 12.60/MMBTU by December 2023 (see the Gas Prices chart
above)
8
.
Global gas demand grew by an estimated 20 Billion cubic metres (Bcm) in 2023, but it was not
enough to fully recover the losses experienced in 2022, when overall demand had dropped by
60 Bcm. However, global gas demand did return to grow in the second half of 2023, primarily
driven by North America and the fast-growing markets of Asia, the Middle East, and Africa,
including China’s increasing industrial and power sectors by approximately 26 Bcm
9
.
Following the gas-supply shock of 2022, natural gas markets gradually rebalanced in 2023
due to timely policy action, market forces, and favourable weather conditions. Despite
this, the market remained tight on the supply side. Gas supplies stayed constrained as the
increase in global LNG production (up by 13 Bcm) failed to offset the continued decline
in Russian piped gas deliveries to Europe (down by 38 Bcm). LNG production growth fell
short of previous expectations due to a mix of project delays and feed gas supply issues.
Notably, the US contributed 80% of the additional LNG supply and emerged as the world’s
largest LNG exporter
10
.
Meanwhile Russia's gas output declined by a further 8%, after decreasing by 12% in 2022,
as increased exports to China and Central Asia did not fully compensate for the drop in
pipeline exports to European Union (EU) countries
11
.
The decrease in gas supply from
Russia was broadly offset by increases in most other regions, particularly in the US, where
overall production increased by 5% year-on-year. In the US, gas exports rose to reach
350.1 billion cubic feet (Bcf), with approximately two-thirds of the flows directed to Europe
(around 226 Bcf)
12
.
Natural gas serves as a transitional energy source in two ways: as a cleaner alternative
to more polluting fuels and as a reliable backup for intermittent renewables. A United
Nations (UN) study indicates that natural gas has helped renewables by replacing coal and
stabilising intermittent energy sources. This is likely to require more long-term investment
in gas as renewables become cheaper than coal in much of the United Nations Economic
Commission for Europe (UNECE) region. This vulnerability of coal, due to higher carbon
emissions and increasing costs, creates opportunities for gas to displace coal, but success
depends on factors like cost reductions in renewable energy, technological advancements,
and adoption by governments and companies
13
.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 13
While natural gas emits fewer greenhouse gases than coal, investing in it may divert
resources from renewable alternatives, posing long-term challenges to achieving climate
goals
14
.
The year 2023 also marked a notable moment in the commitment to decarbonisation by the
global oil and gas sector. At the 28th United Nations Climate Change Conference (COP28)
in Dubai, a historic step towards decarbonisation was taken as National Oil Companies
(NOCs) initiated the Oil and Gas Decarbonisation Charter (OGDC). Spearheaded by the
COP28 Presidency and Saudi Arabia, this global industry Charter aims to accelerate climate
action and achieve significant impact within the oil and gas sectors. Signatory companies,
representing over 40% of global oil production, include NOCs accounting for over 60%
of the signatories, marking the largest-ever commitment by NOCs to decarbonisation
15
.
At the summit, nearly every country agreed to transition away from fossil fuels, marking
a landmark agreement after 28 years of international climate negotiations
16
.
The power,
utility, and energy industry faces a transformative opportunity to shape its cleaner energy
future while contributing to broader societal goals. Industry leaders can lead the way in
transitioning to cleaner energy by setting net-zero goals and embracing initiatives focused
on Environmental, Social, and Governance (ESG) factors. This journey involves driving
efficiency in energy use as well as balancing reliability with the intermittency of renewables,
embracing innovation while ensuring safety, and managing geopolitical dynamics, all of
which are critical aspects. Additionally, retaining skilled workers, keeping costs down, and
strategically reinventing business models will be essential for continued relevance in the
evolving energy economy
17
.
1.2 Indonesian context
Indonesia’s rich history in oil and gas, dating back over 130 years, includes a significant
legacy since its first discovery in North Sumatra in 1885.
In 1912, the inaugural exploration
was conducted in South Sumatra, leading to the discovery of the Talang Akar Field, which
stood as the largest field before World War II (in 1921). By 1961, the Government signed
its first Production Sharing Contract (PSC) in Aceh and Indonesia had become a member
of OPEC. However, a prolonged period of declining production prompted Indonesia
to suspend its OPEC membership in 2009, rejoining in January 2016 and suspending
membership again in November 2016.
In July 2020, the Indonesian Government made a significant policy change, giving investors
the choice between the old cost-recovery PSC scheme and the Gross Split (GS) system
under MoEMR Regulation No. 12/2020. This sparked more interest in Indonesian blocks.
As of 2021, 17 contractors were actively operating under the GS PSC system, marking a
noteworthy development in the country’s oil and gas landscape. The auction of oil and gas
working areas resumed after a pause during the COVID-19 pandemic in 2021. Noteworthy
tendered areas included South Coastal Plain and Pekanbaru (CPP), Sumbagsel (South
Sumatera), Rangkas, Liman, Merangin III, and North Kangean, encompassing both direct-
tender and regular-tender mechanisms. Furthermore, the Rokan PSC, managed by PT
Chevron Pacific Indonesia, transitioned to PT Pertamina Hulu Rokan (PHR) in August 2021.
14 C. Gürsan and V. de Gooyert, “The Systemic Impact of a Transition Fuel: Does Natural Gas Help or Hinder the Energy
Transition?," Renewable and Sustainable Energy Reviews 138 (March 2021): 110552.
15 “Oil & Gas Decarbonization Charter launched to accelerate climate action,” COP28, December, 2023.
16 “COP28: Key Outcomes Agreed at the UN Climate Talks in Dubai,” Carbon Brief, January, 2024,
17 PwC, “Fueling Our Future: The Industry’s Role in the Transition to Clean and Renewable Energy,” PwC, accessed
2024.
14PwC
18 Energy Institute,” Statistical Review of World Energy 2023”, 2023.
19 INPEX, “INPEX Submits Revised Plan of Development for Abadi LNG Project, Masela Block, Indonesia”,
INPEX, 2023; INPEX, “INPEX Receives Approval for Revised Plan of Development for Abadi LNG Project,
Masela Block, Indonesia”, INPEX, 2023.
20 MoEMR, “Kejar Produksi Migas, Kementerian ESDM Teken 13 WK Migas Sepanjang 2023,” 2024.
21 Pertamina, “Pertamina Temukan 2 Sumber Migas Baru di Jawa Barat”, 2023.
On 2 November 2020, Law No. 11/2020 on Job Creation (“Law No. 11/2020”) was
promulgated, which amended several provisions of Law No. 3/2020. On 30 December
2022, the Government issued Government Regulation in lieu of Law No. 2 of 2022
regarding Job Creation (“Perppu No. 2/2022”), which revoked Law No. 11/2020 and also
amended several provisions of Law No. 3/2020. On 31 March 2023, the Government
enacted Law No. 6 of 2023 regarding the stipulation of Perppu No. 2/2022 into Law
(“Law No. 6/2023”). Amendments and replacements were made among others, regarding
improvements to the investment ecosystem and business activities, employment, ease of
doing business, encouragement to research and innovation, land acquisition, and economic
zones. With the enactment of Law No. 6/2023, it was confirmed that Law No. 11/2020 has
been revoked and is no longer valid.
1921
The biggest
discovery
before
WW II
(Talang akar
Field)
1961
Government
signed first
Production
Sharing
Contract
(PSC) in
Aceh and
Indonesia
joined OPEC
1968
PERTAMINA
was
established
2001
Oil and Gas
law
No. 22/2001
introduced,
revoking law
No. 44
2003
PT
Pertamina
(Persero)
established
2008
List of 17
Negative cost
recovery items
(Ministerial
Regulation No.
22/2008)
Indonesia
withdrew from
OPEC
2011
GR 79
implementing
regulations
- PMK 256
- PMK 257
- PMK 258
2016
Indonesia
briefly
rejoins
OPEC
2018
Pertamina
becomes
holding
company for
oil and gas
State-Owned
Enterprises
(SOEs)
2021
The transfer of the
Rokan Block from
Chevron Pacific
to Pertamina
(Pertamina
Hulu Rokan).
The largest oil
producing block
in Indonesia.
1944
Caltex
Minas -
largest
oil field in
Southeast
Asia
discovered
1962
Pan
American
Oil Company
signed the
first contract
of work with
Pertamina
1978
First
Liquefied
Natural Gas
(LNG) plant
entered
production
2002
Upstream
and
Downstream
bodies BP
MIGAS
and BPH
MIGAS were
established
2004
GR Nos. 35
& 36
regulating
upstream &
downstream
business
activities
2010
GR 79
on cost
recovery
and income
tax for
upstream
sector
2013
SKK Migas
establishment
to replace BP
Migas
2017
Gross Split
(GS) PSC is
introduced
2020
Contractors
given
flexibility to
choose cost
recovery
PSC or GS
Scheme
Significant events in the history of Indonesia’s oil and gas sector
Despite Indonesia’s status as a net oil importer, Indonesia is still a prominent global player
in natural-gas production and LNG. Indonesia’s gas lifting in 2023 managed to reach 6,688
MMSCFD, and ranked 14
th
in terms of global gas production, with a total volume of 59.9
Bcm (equivalent to 2.11 Tcf)
18
.
Moreover, significant projects like the Abadi LNG project are progressing towards
development, with the operator, Inpex, recently submitting an updated development plan
integrating CCS. Later in December 2023, Inpex received approval from the MoEMR for the
revised plan of development (PoD) for the Masela Block
19
.
Throughout 2023, an additional 13 contract areas were signed. Currently there are 170
working areas in Indonesia (refer to Table 1.4 - Key Indicators - Indonesia’s oil and gas
industry)
20
. The upstream oil and gas industry in Indonesia has also made history with
significant discoveries of natural-gas potential. These discoveries were Layaran-1 in the
South Andaman Block (6 Trillion cubic feet (Tcf)) and Geng North-1 in the North Ganal Block
(5 Tcf). Pertamina also discovered two new sources last year, namely East Akasia Cinta
(EAC-001) in the PEP Jatibarang Field area, Indramayu Regency, and East Pondok Aren-1
(EPN-001) with a stratigraphic trap in a mature Tambun Field
21
.
2023
Indonesia aspires to
be a regional CCS
hub, introducing a
regulation (MoEMR
Regulation 2/2023 for
upstream activities
and allowing “CCS
as a service”)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 15
22 SKK Migas, “Dukung Penegasan Kedaulatan, Pemerintah Setujui POD Pertama Lapangan Tuna”, 2023.
23 SKK Migas, “Pemerintah Setujui POD Pertama Lapangan Hidayah”, 2023.
24 SKK Migas, “Presiden Resmikan Proyek Tangguh Train 3 dan Ground Breaking Proyek UCC, AKM dan Blue Amonia
di Papua Barat,” 2023.
25 SKK Migas, Produksi Minyak Jawa Timur 2023 Capai 106 Persen, Lampaui Target Pemerintah,” 2023.
26 SKK Migas, “Presiden Resmikan Proyek Tangguh Train 3 dan Ground Breaking Proyek UCC, AKM dan Blue Amonia
di Papua.
27 MedcoEnergi, “Pemerintah Setujui Amendemen PSC Blok Corridor”, 2023.
In early 2023, Indonesia’s oil and gas sector achieved key milestones, including the approval
of strategic development plans for important blocks. On 2 January 2023, Premier Oil Tuna
BV, the contractor for the Tuna Field in the Tuna Working Area (WK), received the green
light
22
.
Shortly after, on 10 January 2023, Petronas Carigali North Madura II Ltd. secured PoD
approval for the Hidayah Field in the North Madura II Working Area
23
. The first quarter of 2023
also saw additional PoD approvals for the Asap, Kido, and Merah (AKM) Fields in the Kasuri
Block, West Papua, under the operation of Genting Oil Kasuri Pte Ltd. The approval for the
AKM project was carried out during the inauguration of the national strategic project (PSN)
Jambaran Tiung Biru (JBT) and the MDA and MBH Gas Field Project in East Java
24
.
By mid-2023, the Special Task Force for Upstream Oil and Gas Business (SKK Migas)
addressed a gas oversupply issue in East Java. Recently, SKK Migas agreed to reduce
the peak gas production in the East Java region to anticipate the projected oversupply,
estimated to reach 200 MMSCFD from 2024 to 2026
25
.
In November 2023, Tangguh Train 3 was inaugurated, boosting the country’s LNG
production pipeline. Operated by BP Berau Ltd., the Tangguh Train 3 project was
constructed at a reported cost of USD4.83 billion
26
.
In December 2023, the MoEMR approved contract amendments for PT Medco Energi
Internasional Tbk’s Corridor Block, transitioning from a gross split PSC to a cost recovery
model. The MoEMR also granted approval for new gas allocations and prices from Corridor
to several buyers including PT Perusahaan Gas Negara Tbk (PGN), with the gas sales
agreements set to be signed soon. The current daily gas deliveries from the Corridor Block
amount to 700 MMBTU/day, with a majority (83%) sold domestically and 17% exported
to Singapore. The request for a shift to a cost recovery PSC had been in process since
ConocoPhillips was the operator. Other fields, including those operated by PT Pertamina
Hulu Energi, are seeking the Minister's discretion for contract transition
27
.
Photo source: PwC
16PwC
In 2024, SKK Migas identified 15 upstream oil and gas projects that will begin operations in
2024, including CNG initiatives.
Table 1.1 - List of oil and gas projects for 2024
Gas Projects
No Name
Production
Capacity
(MMSCFD)
Company Onstream Cost (USD)
1 West Belut 50 Medco Natuna August 2024 84,045,295
2 Dayung Facility Optimisation 40 Medco Grissik July 2024 12,781,045
3
Compressor Facility South
Sembakung
22.5 JOB PMEP Simenggaris May 2024 12,781,045
4 Peciko 8B 16 Pertamina Hulu Mahakam March 2024 29,496,786
5 Bekapai Artificial Lift 12 Pertamina Hulu Mahakam March 2024 17,553,051
6 SWPG Debottlenecking 8 Pertamina Hulu Mahakam March 2024 4,587,248
7 Akatara Gas Plant 25 Jadestone Energy April 2024 86,327,705
8 Merbau Compressor 8 Pertamina EP November 2024 10,565,948
9 Karang Baru Field 5 Pertamina EP April 2024 7,805,008
Oil Projects
No Name
Production
Capacity
(MMBOPD)
Company Onstream Cost (USD)
1 SP Puspa Asri 0.6 Pertamina EP October 2024 6,399,708
2 Flowline ASDJ-116X 0.094 PHE Ogan Kemering April 2024 10,222,836
3 OPL E-Main 0.128 PHE ONWJ June 2024 3,555,980
Source: SKK Migas, "Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024",
Broadcast January 2024 on Youtube, SKK Migas, 2024
Table 1.2 - List of oil and gas projects for 2023 which carry forward for 2024
Gas Projects
No Name
Production Capacity
(MMSCFD)
Company Onstream
1 AFCP 117 Premier Oil May 2024
2 Mako 120 West Natuna Exploration Ltd. Q4 2025
Oil Projects
No Name
Production Capacity
(MMBOPD)
Company Onstream
1 Forel Bronang 10 Medco Natuna June 2024
2 Banyu Urip Infill Clastic 30 ExxonMobil Cepu Ltd. July 2024
3 Hidayah 25.276 Petronas Carigali Madura II Ltd. Q1 2027
Source: SKK Migas, "Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024",
Broadcast January 2024 on Youtube, SKK Migas, 2024
Table 1.3 - List of Compressed Natural Gas (CNG) initiatives of 2024
No Name Production Capacity Company
1 CNG Mother Station Grobokan 1.8 MMSCFD PT Energasindo Heksa Karya (EHK)
2 Biomethane CNG (Bio-CNG) 387,000 cubic metres PT United Kingdom Indonesia Plantation (AEP Group)
Source: PT Rukun Raharja, “PT Rukun Raharja, Tbk (RAJA) Subsidiary Inaugurates New Compressed Natural Gas (CNG)
Mother Station in Grobogan, Central Java”, 2024; Denis Meilanova, “Pabrik Bio-CNG Komersial Pertama di Indonesia Resmi
Beroperasi”, 2024
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 17
Indonesia aims to become a regional hub for CCS by implementing MoEMR Regulation
2/2023, encompassing cooperation in upstream oil and gas activities, introducing a
“CCS as a service” business model and potential multi-user CCS hubs, pending further
implementing regulations. The framework outlines procedures for the capture, utilisation,
and storage of carbon emissions, including specific requirements for contractors,
monitoring, and closure of CCS activities. Economically, it addresses treating CCS costs
as operational expenses, exploring monetisation through carbon trading or reimbursement,
and underscores the importance of downstream business entities holding specific licences
for monetising injection and storage services. A preliminary analysis on the impact to the
regulations and processes within the oil and gas industry as well as the relevant Presidential
Regulation 14/2024 are discussed further in Chapter 3.
1.3 Resources, reserves and production
Out of 128 basins across Indonesia, 20 have entered to production stage, 8 have been
drilled but not yet entered production, 19 basins indicated hydrocarbons, and 13 basins
were dry holes, while 68 basins have not been explored
28
.
Approximately 75% of exploration
and production activities are in Western Indonesia. In summary, there are 4 oil-producing
regions, which are Sumatra, the Java Sea, East Kalimantan and Natuna, and 6 main gas-
producing regions: East Kalimantan, South Sumatra, Aceh, North Sumatra, South Natuna
Sea and West Papua.
In 2023, notable upstream activities in Indonesia included drilling 38 exploration wells,
making 14 discoveries, with 12 wells still ongoing
29
.
Indonesia saw the addition of several
resources in 2023, including the four carried over PSNs from 2022, the Abadi Masela
Project in the Arafura Sea, Maluku, the Tangguh Train-3 Project in Bintuni, West Papua,
the Jambaran Tiung Biru Project in Bojonegoro, East Java, and the Indonesia Deepwater
Development (IDD) Project in the Makassar Straits, East Kalimantan
30
.
Inpex Masela Ltd., the operator of the Abadi Project, aims to onstream production by
2030. The estimated investment costs for the LNG Abadi project in the Masela Block total
USD20,946 million (not including sunk costs)
31
. Inpex’s timeline includes initiating front-end
engineering and design in 2024, site preparation in 2025, and drilling preparation in 2026.
The Masela Block contract, with a 30-year term and a recent 20-year extension, is set to
conclude on 15 November 2055. Current participating interest (PI) holders include Inpex
Masela Ltd (65%), PT Pertamina Hulu Energi Masela (20%), and Petronas Masela Sdn. Bhd
(15%). The Abadi Masela project is targeted to come onstream in 2030
32
.
The IDD Project operator aimed to finalise the transfer of PI and operatorship by the
first quarter of 2023
33
.
On 25 July 2023, the Eni Group, officially acquired Chevron’s
62% interest, becoming the operator of the IDD Phase II project. The IDD project has a
production capacity of 844 MMSCFD for natural gas and 27,000 BOPD for crude oil. The
project is considered crucial for Indonesia’s goal of boosting gas production to 12,000
MMSCFD by 2030
34
.
28 MoEMR, “20 Cekungan Migas Indonesia Simpan Potensi Besar Penyimpanan Karbon”, 2023.
29 SKK Migas, “Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024”,
Broadcast January 2024 on Youtube, SKK Migas, 2024.
30 SKK Migas, “Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024”,
Broadcast January 2024 on Youtube, SKK Migas, 2024.
31 MoEMR, “Pengembangan Blok Masela Dukung Ketahanan Energi Nasional dan Pencapaian NZE”, 2023.
32 MoEMR, “Pengembangan Blok Masela Dukung Ketahanan Energi Nasional dan Pencapaian NZE”, 2023.
33 SKK Migas, SKK Migas Annual Report 2022, 2022.
34 Eni, “Eni acquires Chevron’s Assets in Indonesia,” 2023.
18PwC
Tangguh Train-3, came online in 2023, elevating Tangguh LNG’s annual production capacity
to 11.4 million tonnes and significantly contributing to the 2030 gas production target
35
.
The Tangguh Train-3 project, an extension of the Train-1 and Train-2 projects, is designed
to allocate approximately 75% of its LNG volume to satisfy the domestic electricity sector’s
requirements. A durable commitment from SKK Migas and BP (Berau) Ltd. is demonstrated
through a long-term contract with PT PLN (Persero) for an annual volume of 60 cargoes,
underscoring their commitment to prioritising domestic energy needs
36
.
Additionally, the government is expediting several upstream oil and gas projects in Papua,
including the completion of Tangguh Train 3, with three additional projects underway: CCUS
Ubadari project, Blue Ammonia downstream project, and the Asap Kido Merah gas field.
The Ubadari CCUS project (UCC) is a crucial component of Tangguh’s expansion and aims
to establish Indonesia’s first CCS Hub, injecting around 30 million tonnes of CO
2
by 2035
37
.
The UCC is part of the PSN for 2023, with an anticipated peak production capacity of
476 MMSCFD and a CCS capacity of 1.8 gigatonnes. The integrated project is projected
to require an investment of approximately USD3.84 billion
38
.
Moving forward, the next
project in the pipeline involves the downstream processing of natural gas into low carbon
ammonia. With a planned production of 875 thousand tonnes per annum of Blue Ammonia,
this product will find applications in co-firing at power plants and in steel factories
39
.
In 2023, Indonesia made two significant discoveries, i.e. Geng North and Layaran. Eni
unveiled the Geng North discovery on 2 October 2023, marking a noteworthy find in deep
waters. Geng North-1 was drilled to a depth of 5,025 metres, revealing a 50-metre gas
column in Miocene sandstone. Preliminary estimates for Geng North indicated a total gas
volume of 5 Tcf with up to 400 million barrels of condensate. This discovery was located
adjacent to the IDD area, which includes several untapped discoveries in the Rapak and
Ganal PSC blocks. Eni recently acquired Chevron’s interests in these blocks, increasing
its ownership and assuming operatorship. Combining these areas was expected to offer
significant benefits for gas development opportunities
40
.
SKK Migas and Mubadala Energy jointly announced a significant gas discovery in the
Layaran-1 Exploration Well in the South Andaman Block, situated approximately 100
kilometres off the northern coast of Sumatra. The well, drilled to a depth of 4,208 metres
in 1,207 metres of water depth, revealed an extensive gas column exceeding 230 metres
in the Oligocene sandstone reservoir. Comprehensive data acquisition, including wireline,
coring, sampling, and Drill Stem Test (DST), has been successfully completed. The well
demonstrated the flow of high-quality gas at a rate of 30 MMSCFD
41
.
35 SKK Migas, “Presiden Resmikan Proyek Tangguh Train 3 dan Groundbreaking Proyek UCC, AKM dan Blue Amonia
di Papua Barat,” 2023.
36 SKK Migas, SKK Migas Annual Report 2022, 2022.
37 SKK Migas, “Presiden Resmikan Proyek Tangguh Train 3 dan Groundbreaking Proyek UCC, AKM dan Blue Amonia
di Papua Barat,” 2023.
38 SKK Migas, “Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024”,
Broadcast January 2024 on Youtube, SKK Migas, 2024.
39 SKK Migas, “Presiden Resmikan Proyek Tangguh Train 3 dan Groundbreaking Proyek UCC, AKM dan Blue Amonia
di Papua Barat,” 2023.
40 Eni, “Eni announces a significant gas discovery in the Kutei Basin in Indonesia,” 2023.
41 SKK Migas, “SKK Migas dan Mubadala Energy Mengumumkan Penemuan Gas Besar di South Andaman,
Indonesia”, 2023.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 19
Another important project is the AKM gas field, which is a component of the 2023 PSN
42
and
is under the operation of Genting Oil Kasuri Pte Ltd, as noted above. AKM is anticipated to
have a daily gas in place of 2,673.7 BSCFD, while the potential reserves are estimated at
2,244.45 billion standard cubic feet
43
.
The estimated production is 330 MMSCFD, with an
investment of USD3.37 billion, and the project is expected to be onstream by Q4 2025
44
.
SKK Migas has proposed two oil and gas projects, namely the North Ganal project (Geng
North) in East Kalimantan and AKM project in Teluk Bintuni, West Papua, to be designated
as national strategic projects (PSN)
45
.
In terms of reserves, Indonesia, holding substantial reserves from west to east, reported
2.27 million stock tank barrels (MMSTB) for oil and 36.34 Tscf for natural gas in 2022
46
.
While in 2023, MoEMR reported oil proven reserves reached 2.41 MMBOPD, while proven
reserves of gas reached 35.3 TCF
47
.
SKK Migas reported a successful increase in reserves by 599.08 million barrels of oil
equivalent (MMBOE) and a 104.5% Reserves Replacement Ratio (RRR) up to November
2023 and updated the RRR to 123.5% throughout 2023. This achievement stems from 33
approved plans of development, with a commitment of around USD 10.769 billion
48
. There
were 40 development plan proposals in 2023 accounting for an overall potential increase in
oil and gas reserves of about 788.29 MMBOE
49
.
Indonesian oil and gas production profile
0
500
1000
1500
2000
Oil Production (MBOEPD) Gas Production (MBOEPD)
PEAK 1995PEAK1977
Source: SKK Migas Annual Report 2022; MoEMR, “Kinerja Sektor ESDM 2023: Perluas Akses Energi, Prioritaskan Kebutuhan
Domestik, Dan Jaga Daya Saing Lewat Transisi Energi”, 2023.
42 SKK Migas, “Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024”,
Broadcast January 2024 on Youtube, SKK Migas, 2024.
43 SKK Migas, “Presiden Resmikan Proyek Tangguh Train 3 dan Groundbreaking Proyek UCC, AKM dan Blue Amonia
di Papua Barat,” 2023.
44 SKK Migas, “Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024”,
Broadcast January 2024 on Youtube, SKK Migas, 2024.
45 Aditya Perdana, “Proyek Strategis Nasional Gas Bumi Bisa Bantu Pembangunan IKN”, 2023.
46 SKK Migas, SKK Migas Annual Report 2022, 2023.
47 MoEMR, “Peluang Investasi Migas Indonesia Masih Menjanjikan”, 2023.
48 SKK Migas, “SKK Migas Berhasil Tambah Cadangan 599,08 MMBOE Dan Capaian RRR 104,5%”, 2023.
49 SKK Migas, “SKK Migas Minta Pimpinan KKKS Berkomitmen Laksanakan Program Kerja 2024”, 2024.
20PwC
As Indonesia’s oil and gas fields matured over the last two decades with no significant
new reserves found, managing the natural decline in production has posed an increasing
challenge. In 2022, the realisation of oil lifting was 612 MBOPD, accounting for 87.1% of
the target, while gas production reached 6,490 MMSCFD, exceeding the target at 110%.
In 2023, oil lifting reached 606 MBOPD, slightly below the target of 660 MBOPD (refer to
Table 1.4 - Key Indicators - Indonesia’s oil and gas industry below). Moreover, Pertamina
also succeeded in increasing oil lifting through the Rokan Block, which contributes 26.8%
of national production and operates under the Gross Split model for 20 years, achieving a
level of oil and gas lifting of over 59 million barrels in 2023. This marked an increase of 1.7
million barrels compared to the previous achievement of 57.3 million barrels in 2022
50
.
Meanwhile, Indonesia’s gas lifting in 2023 managed to reach 6,688 MMSCFD, surpassing
the target of 6,160 MMSCFD. Indonesia managed to rank 14
th
, the same rank as 2022 in
terms of global gas production, with a total volume of 59.9 Bcm (equivalent to 2.11 Tcf). At
the same time, in terms of global consumption, Indonesia ranked 26
th
with a total volume
of 38.78 Bcm (equivalent to 1.34 Tcf). In terms of reserves, Indonesia was still ranked 26
th
globally (with proved reserves of 44.2 Tcf) and fourth in the Asia Pacific region (behind
China, Australia, and India), according to BP’s Statistical Review of World Energy (refer to
the figure Share World of Gas 2023 - Rank Based on 2023 Production
51
).
Table 1.4
Key indicators - Indonesia’s oil and gas industry
Indicator 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Reserves
Oil (Million Barrels)7,410 7,550 7,370 7,305 7,251 7,535 7,512 3,770 4,170 3,950 4,171 4,703
Proven 3,740 3,690 3,620 3,603 3,307 3,171 3,154 2,480 2,440 2,245 2,271 2,413
Potential 3,670 3,860 3,750 3,702 3,944 4,364 4,358 1,290 1,730 1,700 1,900 2,290
Gas (Tcf) 150.70150.39149.30151.33144.80143.70135.55 77.29 62.39 60.61 54.83 54.76
Proven 103.35101.54100.26 97.99102.00101.40 96.06 49.74 43.57 41.62 36.34 35.30
Potential 47.35 48.85 49.04 53.34 42.80 42.30 39.49 27.55 18.82 18.99 18.49 19.46
Production
Crude oil (MBOPD) 918 825 789 786 831 804 772 745 708 659 612 606
Natural gas
(MMSCFD)
8,149 8,130 8,218 8,078 7,938 7,620 7,764 7,235 6,665 6,662 6,490 6,688
New contracts
signed
39 14 7 12 2 0 11 6 0 2 5 13
Source:
Reserves of oil and gas are obtained from DGOG, MoEMR
2012-2023 Crude Oil Production: Perfomance Report Directorate of Oil and Gas 2023
2012 - 2022 Gas Production: SKK Migas Annual Report 2022
2023 Gas Production: SKK Migas Site
New Contracts Signed 2021: MoEMR, Statistik Migas 2021
New Contracts Signed 2022: MoEMR, Statistik Migas 2022
New Contracts Signed 2023: Press Conference - Performance of the Energy and Mineral Resources Sector in 2023
50 “Jadi Produsen Minyak Terbesar Di Indonesia, Lifting PHR Tembus 59 Juta Barel Selama 2023,” Energia, 2024.
51 Production & Consumption: BMI (Fitch Solution), “BMI Data Tools - Production & Consumption”, 2024; Reserves:
The Energy Institute, “Statistical Review of World Energy 2023,” 2023.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 21
To pursue the lifting target, SKK Migas, together with the PSC contractors in the upstream
oil and gas sector, undertook various efforts to boost production. One of them was
completing the construction of several oil and gas projects. For instance, the Jambaran
Tiung Biru gas field. Furthermore, it also optimised oil and gas fields that could provide
additional condensate. One of them was the development of Tangguh Train-3, which is now
in operation and capable of producing LNG
52
.
Share of World Gas 2023 - Rank Based on 2023 Production
United States
Russia
Iran
China
Canada
Qatar
Australia
Saudi Arabia
Norway
Algeria
Turkmenistan
Malaysia
Egypt
Indonesia
United Arab Emirates
Reserves at the End of 20202022 Production 2022 Consumption
0% 5% 10% 15% 20% 25%
Source: Production & Consumption : BMI (Fitch Solution), BMI Data Tools - Production & Consumption, 2024; Reserves:
The Energy Institute, Statistical Review of World Energy 2023 2023, PwC Internal Analysis
Pertamina entities contributed roughly 50% of Indonesia’s oil and gas production (see the
pie chart below). The major crude oil and natural gas producers (as PSC operators) as of
2023 were as follows:
Indonesia’s Major oil and gas producers 2023
Source: SKK, “Lifting Minyak & Kondensat 15 KKS Besar”, 2023;SKK, “STATISTIK MIGAS 2022”, 2023
27%
12%
4%
4%
3%
2%
2%
2%
15%
19%
13%
8%
5%
5%
4%
3%
3%
23%
Oil Gas
27%
2%
4%
13%
52 Dwitri Waluyo, “Mengejar Target Produksi Minyak Bumi,” Indonesia.go.id, 2023.
BP Berau
Medco E&P (Grissik) Ltd.
PT Pertamina EP
Pertamina Hulu Mahakam (PHM)
JOB Pertamina - Medco Tomori Sulawesi Ltd.
ENI East Sepinggan Ltd.
ENI Muara Bakau B.V
PetroChina International Jabung Ltd.
Premier Oil Indonesia
Medco E&P Natuna
Others
Mobil Cepu Ltd.
PT Pertamina Hulu Rokan
PT Pertamina EP
Pertamina Hulu Energi ONWJ Ltd.
Pertamina Hulu Mahakam (PHM)
PT Pertamina Hulu Energi OSES
PetroChina International Jabung Ltd.
Medco E&P Natuna
PT Pertamina Hulu Kalimantan Timur
PT Pertamina Hulu Sanga Sanga
Others
22PwC
World’s top LNG exporters 2023
Source: Global Energy Monitor (GEM), 2023
Indonesia’s relevance in seaborne LNG is critical to maintain its reserves and production
level. Indonesia managed to maintain its position as the sixth largest exporter of LNG in
2023, with a capacity of 23.3 million tonnes per annum (MMTPA), behind the US, Australia,
Qatar, Russia and Algeria (Figure World’s Top LNG Exporters 2023). Indonesia’s LNG
liquefaction and regasification capacities are presented below.
Table 1.5 - List of Indonesian LNG liquefaction terminals
Location Project Capacity (MMTPA) 2023 Operator
East Kalimantan Bontang 22.5 PT Badak LNG
West Papua Tangguh 11.4 BP Tangguh
Central Sulawesi Donggi Senoro 2 PT Donggi Senoro LNG
Maluku Abadi LNG 9.5 (planned) Inpex
South Sulawesi Sengkang 2 (planned) PT Energi Sengkang
Table 1.6 - List of Indonesian LNG regasification terminals
Location Project
Capacity (MMSCFD)
2023
Operator
West Java
Nusantara Regas
Satu
500 PT Nusantara Regas
North Sumatera Arun Regas 405 PT Perta Arun Gas
South Sumatera Lampung LNG 240 PT PGN LNG
Bali Tanjung Benoa LNG 50 PT Pelindo Energi Logistik
West Java Jawa-1 300 PT Jawa Satu Power
North Sulawesi Sulawesi Regas Satu 24 PT Sulawesi Regas Satu
There was a gradual recovery in upstream activities in 2022, and this positive trend
continued to gain momentum in 2023.
Exploration activities also showed an upward
trajectory, increasing from 30 to 38 wells in 2022. In 2023, Indonesia achieved the highest
number of wells drilled since 2017, 38 wells.
20.0%
16.7%
6.7%
5.4%
5.0%
4.7%
2.6%
2.6%
12.4%
United States of America
Australia
Qatar
Russia
Algeria
Indonesia
Nigeria
Malaysia
Egypt
Trinidad and Tobago
Others
18.9%
5.0%
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 23
In addition, more development wells were developed in 2023, from 260 to 799 wells. The
Full Tensor Gravity (FTG) Survey hit 2023’s target 129,305 square kilometres (Km
2
). The
Tensor Gravity Survey was first introduced in 2021, with the realisation at 101,920 Km
2
.
Although more exploration wells were drilled and surveys showed positive result, there
was a setback in 3D Seismic operations. The survey declined from 3,790 to 1,432 Km
2
in
2023. The exploration and exploitation activities in 2023 are constrained by well drilling for
development due to safety stand down, rig availability, labour force, and flooding at the
location
53
.
Table 1.7
Key indicators - Indonesia’s oil and gas industry exploration activities
2022
Realisation
2023
Target
2023
Realisation
% 2023 vs
2022
% of 2023
Target
2D Seismic Km 1,950 934 25 1.3% 3%
Survey Full Tensor Gravity
Gradiometry (FTG) Km
2
18,814 129,305 129,305 687% 100%
3D Seismic Km
2
3,790 2,282 1,432 38% 63%
Development Wells Wells 760 919 799 105% 87%
Exploration Wells DrillingWells 30 57 38 127% 67%
Workover Wells Wells 639 834 834 131% 100%
Well Service Activity Activity 30,229 33,182 33,412110.5% 101%
Source: SKK Migas, "Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024",
Broadcast January 2024 on Youtube, SKK Migas, 2024.
In response to increasing energy demands, Indonesia developed the Long-Term Plan (LTP)
Target for 2030. The goal was to achieve a production level of 1 MMBPOD and 12 BSCFD
by 2030, requiring increased investment and collaboration among stakeholders. SKK Migas
then developed the Indonesia Oil & Gas (IOG) 4.0 strategic plan to enhance production,
national capabilities, sustainability, and environmental continuity through various initiatives.
One notable IOG initiative focused on the transformation from resources to production. As
part of this strategy, the drilling of the Gulamo exploration well for Unconventional Oil (NUO)
commenced in the Rokan Block managed by PHR. Additionally, the MoEMR announced
plans for a second NUO Exploration Well in the Rokan Block, named the Kelok Well, slated
for November 2023. The potential of these two wells alone is estimated to be at least 80
million barrels of oil, while the oil potential in place in the Rokan Block itself is about 1.26
billion barrels
54
.
53 SKK Migas, “Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024”,
Broadcast January 2024 on Youtube, SKK Migas, 2024.
54 MoEMR, “Pengeboran Sumur MNK di Rokan Jadi Showcase Investor Migas Dunia”, 2023.
24PwC
Another pivotal IOG initiative focused on the implementation of Enhanced Oil Recovery
(EOR) techniques to bolster oil production. Recent years saw extensive studies conducted
to ensure the effectiveness of EOR methods and formulas. Notably, the waterflood method
was explored in the Rokan contract area at the Minas Field (PHR) and in the Mahakam
contract area at the Handil Field (Pertamina Hulu Mahakam)
55
.
In December 2023, SKK
Migas approved two projects in the Rokan working area with a total investment of IDR 5.18
trillion. These projects encompass the Chemical EOR (CEOR) at Minas Field Phase-1 and
Steam Flood EOR at Rantaubais Field Phase-1. The adoption of CEOR at Minas Field on
a commercial scale, utilising Alkali-Surfactant-Polymer (ASP) injection chemicals, marked
a historic milestone. The Phase-1 CEOR development at Minas Field added 2.24 million
barrels of oil reserves and achieved peak production of 1,566 BOPD
56
.
Furthermore, the government aimed to reduce emissions and increase production through
CCS/CCUS
57
(discussed further in the Energy Transition chapter). CCUS, especially in
conjunction with EOR through CO
2
-EOR, offers potential for permanent CO
2
storage. While
Indonesia’s oil fields show promise, detailed studies are necessary to assess economic
feasibility and identify CO
2
sources. Initial research in South Sumatra indicates viable CO
2
-
EOR injection options. However, CCUS projects remain in the pilot phase due to high costs,
leaving considerable potential for CO
2
injection untapped
58
.
In addition, Pertamina, through PT Pertamina EP (PEP) Regional Java Subholding Upstream
Pertamina, successfully confirmed additional hydrocarbon reserves with two exploration
wells in West Java Province. The first, East Akasia Cinta (EAC)-001 in PEP Jatibarang
Field, Indramayu Regency, yielded oil at 30 BOPD, gas at 2.08 MMSCFD, and condensate
equivalent to 15.05 BCPD. The second, East Pondok Aren (EPN)-001 in PEP Tambun Field,
Bekasi Regency, flowed oil at 402 BOPD and gas at 1.09 MMSCFD. These efforts were
part of Pertamina’s aggressive exploration strategy, showcasing a new concept involving
stratigraphic traps
59
.
As for Coal Bed Methane (CBM), Indonesia holds 6% of the global reserve, estimated at
453 Tcf, surpassing natural gas reserves. Commercialising CBM is a challenge and no block
has yet entered production.
In 2023, despite the government’s termination of 50 cooperation blocks for oil and gas
contracts, including 11 non-conventional blocks like Shale Gas or CBM
60
,
NuEnergy Gas
Limited’s unit, Dart Energy (Tanjung Enim) Pte. Ltd, obtained the environmental permit for
Indonesia’s Tanjung Enim plan of development between September and October 2023. This
could lead to the country’s first CBM development. On 10 February 2023, NuEnergy signed
a heads of agreement with Laras Energy, later extended on 10 August 2023, outlining the
supply and sale commitment by NuEnergy and the purchase commitment by Laras Energy
for CBM produced from Tanjung Enim’s POD 1.
55 SKK Migas, SKK Migas Annual Report 2022, 2023.
56 SKK Migas, “Jelang Tutup Tahun 2023, Dua Proyek EOR (Enhanced Oil Recovery) di Wilayah Kerja Rokan Dengan
Investasi Rp 5,18 Triliun Disetujui SKK Migas”, 2023.
57 Ministry of Industry,”POTENSI TEKNOLOGI CCS, CCUS DAN EMISI GRK DI INDONESIA”, accessed 2024.
58 Sugihardjo, “CCUS-Aksi Mitigasi Gas Rumah Kaca Dan Peningkatan Pengurasan Minyak CO
2
-Eor,” Lembaran
Publikasi Minyak Dan Gas Bumi 56, no. 1 (April 1, 2022): 21-35.
59 Pertamina, “Pertamina Temukan 2 Sumber Migas Baru di Jawa Barat”, 2023.
60 MoEMR, “11 Blok Migas Terminasi Simpan Potensi MNK”, 2023.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 25
1.4 Downstream sector
Indonesia once again recorded a significant demand for crude oil. This is evident from the
import of crude oil and natural gas which reached 15,263.4 tonnes in 2022
61
and increased
to 52,144.1 tonnes in 2023
62
.
Despite that, Bank Indonesia (BI) reported that the trade deficit
balance for oil and gas declined to USD1.89 billion (5,011.4 thousand tonnes) in December
2023, in line with the decrease in oil and gas imports amid an increase in exports
63
.
Indonesia is also actively working to optimise the use of its domestic natural-gas resources.
In 2023, the share of domestic gas utilisation increased slightly to 3,745 Billion British
Thermal Units per Day (BBTUD), compared to the 2022 level of 3,683 BBTUD. Notably,
the industrial sector remains a major consumer, accounting for a significant portion of the
demand at 1,515.8 BBTUD
64
.
While Indonesia is considered an attractive market for downstream investors, Pertamina
holds a significant position in the refining industry, operating six out of the nation’s seven
refineries. The seventh refinery is owned by the Research & Development (R&D) Agency of
the Ministry of Energy and Mineral Resources (MoEMR). Combined, these refineries had an
installed capacity of 1.031 MMBOPD in 2021. In response to increased oil consumption in
2022, Pertamina boosted its existing refinery capacity to 1.058 MMBOPD.
Pertamina aims to increase its refining capacity from 1.15 to 2.0 MMBOPD. This expansion
plan is facilitated through the Refinery Development Master Plan (RDMP), which focuses on
upgrading and expanding existing capacities and Grass Root Refineries (GRR). Pertamina’s
RDMP encompasses Cilacap, Dumai, Balongan, Balikpapan, and the GRRs will be located
in Tuban and Bontang
65
. Finding the right partners for Tuban and Bontang GRRs
continues to be a challenge for Pertamina
66
.
Pertamina also has a majority share in the PT Trans-Pacific Petrochemical Indotama
(TPPI)
Tuban refinery
67
. The Government aims to reduce gasoline subsidies by restricting
distribution in certain areas and promoting non-subsidised fuels such as Pertalite,
Pertamax, and Pertamina Dex. The Government also allows investments from multinational
giants such as Shell, ExxonMobil, Total, and BP in the non-subsidised fuel distribution
market.
In the industrial fuels sector, Pertamina continues to be a major player, yet foreign and
local competitors have made significant strides in expanding their market share through
fuel imports. Compounded by Indonesia’s burgeoning economy, the demand for fuel
consistently outpaces the country’s refinery capacity and its crude oil/natural gas
production.
61 The Indonesian national statistics agency (BPS - Badan Pusat Statistik), “Volume Ekspor dan Impor Migas (Berat
bersih: ribu ton) 1996-2022”, 2023.
62 BPS, “Volume Impor Migas-NonMigas (Ribu Ton)”, 2023.
63 BI, “SURPLUS NERACA PERDAGANGAN BERLANJUT”, 2024.
64 MoEMR, “Kinerja Sektor ESDM 2023: Perluas Akses Energi, Prioritaskan Kebutuhan Domestik, Dan Jaga Daya Saing
Lewat Transisi Energi”, 2023.
65 PT Pertamina (Persero), Pertamina Annual Report 2022, June 12, 2023.
66 BMI (Fitch Solution), “Indonesia Oil and Gas Report Q1 2024”, 2023.
67 Indonesia Oil and Gas Report Q1 2024 (Fitch Solution, 2023).
26PwC
1.5 Contribution to the economy
Indonesia’s heavy reliance on imported fuels and crude oil poses risks to energy security
due to fluctuating global prices. In 2022, rising fossil fuel prices led to significantly higher
energy subsidies than budgeted
68
.
The energy subsidy saw a substantial increase from
IDR152.5 trillion to IDR502.3 trillion, culminating in a realisation of IDR551.2 trillion in 2022.
By August 2022, the Ministry of Finance signalled that nearly the entire gasoline subsidy
allocation had been utilised, raising concerns about potential fuel-price hikes. In response
to the escalating energy subsidy costs, the president implemented an average 30%
increase in fuel prices in September 2022
69
.
The trend in energy subsidies reversed in 2023.
The MoEMR reported that Indonesia’s energy subsidy realisation in 2023 reached IDR159.6
trillion, surpassing the set target of IDR145.3 trillion, but much lower than 2022. The energy
subsidy covers various components, including fuel oil (BBM) for diesel and kerosene,
Liquefied Petroleum Gas (LPG), and electricity. The 2024 target for energy subsidies is
set at IDR186.9 trillion, with BBM and LPG subsidies at IDR113.3 trillion and electricity
subsidies at IDR73.6 trillion
70
.
The Ministry of Finance (MoF) also reported a reduction in subsidies for fuel and 3 kg LPG,
amounting to IDR95.6 trillion, marking a 17.3% decrease. The decline in energy subsidies,
particularly for fuel and LPG, is attributed to various policies. Notably, the targeted
distribution transformation for LPG initiated on 1 March 2023, played a significant role.
Furthermore, measures such as customer registration through MyPertamina and restrictions
on subsidised fuel purchases also contributed to the decline
71
.
As Indonesia seeks to diversify away from fossil fuels, it is expected that the fuel demand
in the long term will slow. Demand for transport fuels also showed slower growth rates
due to the government’s ongoing efforts to cut fuel subsidies. Fitch forecasted that
Indonesia’s fuel consumption will grow 1.4% annually between 2023 and 2032, with total
volumes staying below or around 2.1 MMBOPD in 2032. The decarbonisation target for fuel
switching in the road transport sector is ambitious and will bring about major reductions in
fuel consumption. The national objective is to reach carbon neutrality by 2060, which will
require emissions reduction measures to be introduced in most fuel-intensive sectors
72
.
The rapid global growth of electric vehicles (EVs) is causing a potential disruption to the
traditional oil market, with more countries and consumers embracing EVs and shifting from
oil to electricity as the primary energy source
73
. While the EV market is projected to expand
in Indonesia due to increasing consumer awareness and government incentives, as well
as the government’s plans for Indonesia to become a battery and EV hub for the region,
given Indonesia’s significant reserves of critical minerals needed for batteries, such as
nickel, cobalt, copper and others, the EV adoption in Indonesia currently lags behind global
markets. Nevertheless, industry leaders and policymakers are preparing for a future where
EVs could have a significant market presence, driving a shift towards sustainability and
technological advancements
74
.
68 Institute for Essential Service Reform (IESR), “Indonesia Electric Vehicle Outlook 2023”, 2023.
69 MoEMR Strategic Study, “Realisasi Subsidi Dan Kompensasi Energi 2022 Melesat Tiga Kali”, Laporan Harian KESDM,
January 4, 2023; The Economist Intelligence Unit (EIU), Energy Report Indonesia Q4 2022, June 1, 2022.
70 MoEMR, “Jaga Daya Beli, Menteri ESDM Targetkan Alokasi Subsidi Energi 2024 Rp186,9 Triliun”, 2024.
71 Ministry of Finance (MoF), “Press Conference - Performance and Realisation of State Budget 2023”, Broadcast
January 2024 on Youtube, MoF, 2024.
72 BMI (Fitch Solution), “Indonesia Seeking To Slow Down Fuel Demand Growth And Cut Imports”, 2023.
73 World Economic Forum (WEForum), “Electric vehicles: an analysis of adoption and the future of oil demand”, 2023.
74 PwC, “Key drivers and future expectations for electric vehicles in the Indonesia market”, 2023.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 27
In 2021, Indonesia’s government Non-Tax State Revenue (PNBP - Penerimaan Negara
Bukan Pajak) from the oil and gas sector rebounded to IDR95 trillion, surpassing the target
by 26.67%, largely due to high oil prices driven by global geopolitical factors. Entering
2022, following more stability in oil and gas prices, the oil and gas revenue reached a level
of IDR148.7 trillion from a target of IDR139 trillion
75
.
In 2023, the realisation of Non-Tax State
Revenue in the oil and gas sub-sector reached IDR117 trillion, indicating a decrease from
2022, but still 113% of the target set of IDR103.6 trillion
76
.
The export revenue from oil and gas grew to 4.35% of total exports in 2021 but
experienced a decline to 3.75% in 2022 and 2023, marking the lowest level in the
past decade (refer to figure Oil and Gas exports as a % of total Indonesian exports).
Concurrently, the contribution of the oil and gas industry to Gross Domestic Product (GDP)
saw a decline from 3.46% in 2021 to 3% in 2022 and 2.49% in 2023 (refer to Oil and Gas
products as a % of total Indonesian GDP).
Table 1.8 - State budget
Year
Total State
Revenue
Oil and Gas
Revenue
% of Contribution
from Oil & Gas
(IDR Trillion)
2013 1,438 204 14.19%
2014 1,551 217 13.99%
2015 1,505 78 5.18%
2016 1,555 44 2.84%
2017 1,666 82 4.91%
2018 1,942 143 7.38%
2019 1,959 127 6.49%
2020 1,699 69 4.07%
2021 1,736 95 5.47%
2022 1,846 149 8.05%
2023 2,462 117 4.75%
Source: MoF, “APBN Kita December 2023”, 2023; MoEMR, “Capaian Kinerja Sektor 2023”, 2024
75 MoEMR Strategic Study, “Realisasi Subsidi Dan Kompensasi Energi 2022 Melesat Tiga Kali”, Laporan Harian KESDM,
January 4, 2023; The Economist Intelligence Unit (EIU), Energy Report Indonesia Q4 2022, June 1, 2022.
76 MoEMR, “PNBP Migas Sumbang Rp 117 Triliun ke Kas Negara”, 2024.
Photo source: PT Pertamina (Persero)
28PwC
Oil and gas exports as a % of total Indonesian exports
Source: Bank Indonesia (BI)
Oil and gas products as a % of total Indonesian GDP
Source: Bank Indonesia (BI)
Investment in Indonesia’s upstream oil and gas sector showed improvement.
In 2023, there
was a 12% increase from 2022, reaching USD13.7 billion (refer to Table 1.9 - Upstream
Oil & Gas Investment). Oil and gas operations in Indonesia also contribute significantly
to the job markets. According to SKK Migas, in 2022, the number of Indonesian Workers
(TKIs) employed in upstream oil and gas activities stood at 18,924, with 145 expatriate
employees.
The utilisation of Indonesia’s workforce experienced a decline from 2015 to 2021 due to
factors such as falling oil prices and the impact of the COVID-19 pandemic (refer to the
figure Indonesian Workers and Expatriates Headcount in Oil and Gas). This decline was also
brought about by efficiency programmes by PSC Contractors and the completion of various
oil and gas projects. Consequently, recruitment for vacant positions was generally delayed,
prompting contractors to focus on enhancing the development of Indonesian workers
through more efficient methods like in-house training and online modules
77
.
Total contribution to
Indonesian exports
Percentage of exports from
oil and gas sector to total
exports
15.31%
13.57%
10.05%
7.99%7.85%
8.19%
5.48%
4.00%
4.35%
3.75%3.75%
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
20132014201520162017201820192020202120222023
USD Million
5.45%
4.82%
3.34%
2.94%2.88%
3.10%
2.78%
2.15%
3.46%
3.00%
2.49%
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
20132014201520162017201820192020202120222023
IDR billion
Year
Oil and gas industry
contribution to GDP
Percentage of oil and gas
industry contribution to GDP
77 SKK Migas, SKK Migas Annual Report 2022, 2023.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 29
Table 1.9
Upstream oil and gas investment (in million USD)
Type of operation 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Exploration 1,8771,7351,3451,078 565 546 600 578 600 700 900
Administration 1,1991,1571,286 702 944 873 700 643 800 800 600
Development 4,3064,0482,1161,322 7051,3101,7001,6801,4002,6002,800
Production 11,96012,33610,8838,1568,0538,1898,7007,6008,1008,1009,400
Total Expenditure19,34219,27615,63011,25810,26710,91811,70010,50110,90012,20013,700
Source:
2009 - 2021: Calculated by PwC based on BP Migas/SKK Migas Annual Reports 2022: BUMI Buletin SKK Migas January
2023 Edition.
2023: SKK Migas, “Press Conference - Upstream Oil and Gas Performance Achievements of Year 2023 and Targets 2024”,
Broadcast January 2024 on Youtube, SKK Migas, 2024.
Indonesian workers and expatriates headcount in oil and gas
Source: SKK Migas Annual Report 2022 (released on 2023)
Indonesian Workers
Headcount
Expatriates
Headcount
100
600
1100
1600
0
5000
10000
15000
20000
25000
30000
35000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Photo source: PT Pertamina (Persero)
Indonesian workers Expatriates
30PwC
2.1 The need for energy transition and challenges
Energy is a crucial input to all economic activity, and a secure and
affordable energy supply has been a key enabling factor for global
economic growth that has lifted millions out of poverty. Over the period
from 1900 to 2022, global per capita Gross Domestic Product (GDP)
has increased from ca. USD 2,200 to ca. USD 12,800
78
. Over the same
period, global primary energy consumption increased from ca. 12,000
TWh to ca. 167,788 TWh
79
, with the proportion of fossil fuels in the
primary energy supply at ca. 82% in 2022
80
. About three-quarters of
global greenhouse gas emissions come from energy use, with around
74% being carbon dioxide (CO
2
) and the remainder from gases like
methane (CH4), nitrous oxide (N2O), and F-gases. The climate science,
coordinated under the aegis of the Intergovernmental Panel on Climate
Change, is unequivocal in its conclusion that anthropogenic GHG
emissions are responsible for global warming and climate change.
The Paris Agreement at Conference of Parties 21 (COP21) calls for
keeping global warming to well below 2
o
C above pre-industrial levels
and pursuing all efforts to limit it to 1.5
o
C above pre-industrial levels
recognising that this would significantly reduce the risks and impacts
of climate change. The Glasgow Climate Pact, agreed at COP26,
emphasised the urgent need to address global warming and climate
change. It reiterated the goals set in COP21 to limit global warming to
well below 2°C above pre-industrial levels and pursue efforts to limit
it to 1.5°C. This includes rapid reductions in global CO
2
emissions by
45% by 2030 compared to 2010 levels, aiming for net zero emissions
by around mid-century, and reducing other greenhouse gases
81
. Most
countries worldwide have agreed to transition away from fossil fuels,
the primary cause of climate change.
This requires significantly accelerated action in this decade itself,
considering that with all committed policies and actions, we are
estimated to be on track for ca. 2.7
o
C
82
, while even considering all
current pledges and targets, which are yet to be fully translated into
policies and action, we are estimated to hit ca. 2.1
o
C of warming.
Energy transition
2
78 World Bank, "October 2021 Commodity Markets Outlook: Urbanization and Commodity
Demand", Commodity Markets Outlook, October, 2022; Natasha Turak, "OPEC+ agrees to
stick to oil production plan, defying U.S. pressure", CNBC, 2021.
79 World Bank, "April 2022 Commodity Markets Outlook: The Impact of the War in Ukraine
on Commodity Markets", Commodity Markets Outlook, 2022.
80 Max Roser et al., “Economic Growth”, Our World in Data, 2023.
81 COP28: Key outcomes agreed at the UN climate talks in Dubai", Carbon Brief, January,
2024; COP 28: What Was Achieved and What Happens Next?", United Nation Climate
Change (UNCC), 2023.
82 https://climateactiontracker.org/publications/no-change-to-warming-as-fossil-fuel-
endgame-brings-focus-onto-false-solutions/
30 PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 31
At the same time, energy security continues to be a major concern across the globe. While
the energy transition is key to averting catastrophic global warming and climate change,
this cannot be to the detriment of the unfinished development agenda in the developing
countries of the world which are historically and currently below developed countries, and
even global averages, in terms of per capita incomes, energy consumption and emissions.
It is essential to ensure that the transition doesn’t reverse decades of progress in economic
and social development. If not, the loss of social and political license for the many difficult
decisions that have to be implemented for a rapid and deep energy transition, will derail the
transition.
The B20 Energy, Sustainability & Climate (ESC) Task Force, for which PwC Indonesia was
the knowledge partner, highlighted the key areas of focus if a just energy transition is to be
achieved, in its policy paper submitted to the G20 in 2022. These are summarised in Table
2.1 below.
Tabel 2.1 - B20 ESC TF policy recommendations
Policy recommendation
Policy
Action No
Policy Action
Enhance global cooperation
on accelerating the transition
to sustainable energy use by
reducing carbon intensity of
energy use through multiple
pathways
1.1
Enhance the pace of energy efficiency improvement across
the transport, buildings, and industrial sectors
1.2
Progressively reduce the carbon intensity of electricity
by reducing emissions from coal fired generation and
accelerating renewable energy deployment, according to
national circumstances
1.3
Accelerate the mitigation of carbon emissions from hard-to-
abate sectors
1.4
Progressively enhance the quantum, predictability & ease of
financing flows to developing countries
1.5
Support climate technology innovation by supporting start-
ups, and research universities with technology, financing,
skilled manpower, knowledge & facilities sharing
Enhance global cooperation
on ensuring a just, orderly,
and affordable transition
to sustainable energy use
across developed and
developing countries
2.1 Ensure an orderly transition in primary energy sources
2.2
Ensure MSMEs participation in energy transition activities
with financing and capacity building
2.3
Assist transition readiness by ensuring human capital ability
to accommodate change (e.g., transfer knowledge, upskilling
& workshop)
2.4
Ensure sustainable practices for mining of essential minerals
for energy technologies
Enhance global cooperation
on enhancing consumer
level access and ability to
consume clean, modern
energy
3.1
Accelerate deployment of integrated electricity access
solutions, including off grid with community participation
and grid-based electrification to expand energy access and
enhance economic prosperity
3.2
Facilitate adoption of technology by households and MSMEs
for efficient, clean, modern energy usage
3.3
Ensure broad basing of the transition by addressing
affordability barriers in developing countries
Source: B20 Energy, Sustainability & Climate Task Force ESC TF) , "B20 Summit Indonesia 2022 : Energy, Sustainability &
Climate Task Force Policy Recommendation", Broadcast November 2022 on Youtube, Kemkominfo, 2022
32PwC
2.2 Energy transition in Indonesia
Indonesia has demonstrated strong and consistent economic growth over this century, with
GDP at constant 2010 prices increasing from IDR 4,122 trillion in 2000 to IDR 11,710 trillion
in 2022, supported by primary energy-supply expansion of 836 MBOE. 78% (652 MBOE)
of this expansion was from coal, reflecting natural-resource endowment and a national
policy stance favouring domestic-resource exploitation for economic development and job
creation. This strong and consistent growth has resulted in a more than tenfold increase of
per capita GDP over the same period from ca. USD 770 (IDR 6.5 million)
83
to ca. USD 4,788
(IDR 71 million)
84
. However, this also indicates how much further Indonesia has to go in its
ambition to become a developed economy.
In pursuit of the required growth, the primary energy supply will have to be expanded, but if
the expansion continues to be from fossil fuels, the consequent greenhouse gas emissions
growth will lead to Indonesia failing to achieve its international treaty obligations under the
Paris Agreement and failing to secure the international support promised for its transition
under the Indonesia – Just Energy Transition Partnership.
Primary energy supply mix
Source: PwC, “The Energy Transition,” PwC, accessed 2024.
83 Based on average exchange rate of USD/IDR in 2000 of 8,421
84 Based on average exchange rate of USD/IDR in 2022 of 14,849
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 33
The scale of Indonesia’s challenge in planning and implementing its energy transition can
be seen from the two graphs below which show the dependence on fossil fuels in the final
energy consumption basket.
Fossil Fuel Dependence in FEC (2022) and Sectoral Fossil Fuel Dependence (2022)
Source: PwC, “The Energy Transition,” PwC, accessed 2024.
Indonesia will have to simultaneously transition its final energy consumption and primary
energy supply mix by applying the four levers of transition – energy efficiency, electrification
of the economy, decarbonising electricity generation and replacing residual fossil-molecule
demand with alternative fuels. The Just Energy Transition Partnership (JETP) scenario that
has been finalised in the recently released Comprehensive Investment Policy and Plan
considers energy efficiency (minimum energy performance standards for appliances and
machinery across households, industry and commercial sectors), electrification of the
economy (Internal Combustion Engine (ICE) vehicles to Electric Vehicles (EVs) in transport,
process heat in industries and electrification of cooking), and decarbonising electricity
(significant shift to baseload and variable RE (Renewable Energy), biomass co-firing).
The JETP was established in Indonesia during the G20 Summit in Bali on 15 November
2022, with a catalytic USD 20 billion funding agreement between the government, the
International Partners Group (IPG) and the Glasgow Financial Alliance for Net Zero
(GFANZ) to transition Indonesia’s electricity sector. In Indonesia, JETP has developed the
Comprehensive Investment and Policy Plan (CIPP) to guide power sector planning and
policymaking.
The CIPP outlines a potential pathway for the on-grid system (JETP Scenario) with an
emissions target of no more than 250 MT CO
2
in 2030; a renewable energy generation share
of 44% by 2030; and achievement of net zero emissions in the power sector by 2050. On-
grid generation and net capacity changes for each technology can be seen below.
1186 mboe
34PwC
Source: Just Energy Transition Partnership (JETP) Secretariat and Working Groups, “Just Energy Transition Partnership for
Indonesia (JETP Indonesia) Comprehensive Investment and Policy Plan,” 2023
In terms of investment costs, at least USD97.1 billion between 2023-2030 and USD580.3
billion between 2023-2050 is required to realise the JETP Scenario, excluding the full extent
of just transition assessments and interventions, projected to cost at least USD0.2 billion by
2030. Average annual investment for respective technologies can be seen below.
Source: Just Energy Transition Partnership (JETP) Secretariat and Working Groups, “Just Energy Transition Partnership for
Indonesia (JETP Indonesia) Comprehensive Investment and Policy Plan,” 2023
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 35
To support the power sector, around 6,000 km of transmission lines are needed by
2030, increasing to around 15,000 km by 2040. For transmission, around USD42 billion
of cumulative capital investment is projected by 2040, and USD9 billion is needed for
distribution network investment.
Specifically for dispatchable renewables: Hydropower is expected to make up 12% of
the energy mix by 2030, with an expansion driven by the addition of 8 GW of new plants,
reaching a capacity of 65 GW by 2050. Geothermal capacity is set to expand by 3 GW by
2030 and nearly 22 GW by 2050. Bioenergy is projected to constitute 7% of the total coal
generation mix by 2030, increasing to 9% beyond 2040 as retired coal plants are repurposed.
Investment requirements for dispatchable renewable power total almost USD197 billion
cumulatively by 2040, with hydropower alone needing at least USD100 billion.
Beyond 2030, minimal investment is directed towards new on-grid fossil-fuel plants, but
up to USD10 billion is projected for repurposing coal power plants to enhance flexibility.
Repurposing coal and gas plants for bioenergy or hydrogen requires an average annual
investment exceeding USD7 billion during 2046–2050.
Meanwhile, variable renewable energy (VRE) comprises 60% of power-capacity
additions through 2040, led by the growth of solar PV to 100 GW by 2040 and close to 265
GW by 2050. Wind power complements this growth, also accelerating to nearly 30 GW
in 2040 and almost 45 GW in 2050, even though its expansion is limited due to resource
availability. Achieving these levels of installed capacity requires nearly USD25 billion
cumulative investment in solar PV and wind by 2030 and almost USD80 billion by 2040.
It is noted that the success of this pathway is conditional upon integration measures and
investments to expand and upgrade transmission grids, system flexibility to integrate
variable renewables and policy enhancements, among others.
The combined effect of this planned transition is expected to peak and then reduce the
demand for all three major fossil fuel sources – coal, oil and gas. Oil and gas demand as
feedstock for industrial processes will likely continue or grow.
Primary energy supply mix
20
40
60
80
100
120
200020102020203020402050
Passenger vehiclesTrucksNon-road transport Other
Cars
Trucks
Peak in ICE vehicle sales
Two/three-wheelers
Oil demand
1 000
2 000
3 000
4 000
5 000
6 000
200020102020203020402050
Power Buildings Industry Other
bcm Power
Boilers in buildings
Peak year in gas capacity additions
Natural gas demand
Source: IEA, “World Energy Outlook 2023”, 2023
However, these use cases and transition consumption of fossil fuels will likely have to be
abated to minimise their GHG emissions and environmental impact.
MMBOPD
36PwC
2.3 Oil and gas demand
The demand for oil and gas in Indonesia is significant, with the country’s oil and gas market
expected to grow. The Indonesia Oil and Gas Market is projected to reach 635.23 thousand
barrels per day in 2024 and grow at a Compound Annual Growth Rate (CAGR) of 1.60% to
reach 687.70 thousand barrels per day by 2029
85
. Indonesia has one of the largest proven
oil reserves among Southeast Asian countries, and the country is seeing rapid economic
growth, which is expected to drive up the demand for petroleum and petroleum-derived
products in the future. The country’s gasoline consumption is also on the rise, with demand
expected to reach a record high of 670,000 barrels per day in 2023, up from 635,000
barrels per day in 2022
86
. Additionally, Indonesia produced 2.2 trillion cubic feet of dry
natural gas in 2020, mostly from offshore fields not associated with crude-oil production.
Despite some challenges and disruptions, Indonesia’s oil and gas market is poised for
growth, presenting significant opportunities for industry players
87
. However, it is important
to note that Indonesia’s oil consumption has experienced fluctuations over the years,
influenced by various factors such as economic growth, government policies, and global oil
prices. The country’s oil demand is expected to evolve in response to these factors
88
.
In Indonesia, both gasoline and petrochemicals are significant in the energy and
industrial sectors. The country’s reliance on fossil fuels, including gasoline, is evident in
its energy consumption, with petroleum accounting for a notable share. Additionally, the
petrochemical industry in Indonesia is a vital part of the economy, with a promising market
due to the large population and the demand for petrochemical products. The government
has expressed ambitions to reduce the import of petrochemical products and develop the
domestic petrochemical industry to meet the growing demand. Therefore, while gasoline
is primarily used as a fuel, petrochemicals play a crucial role in various industrial and
consumer products, making them both important in the Indonesian context.
The Indonesian petrochemicals market is significant, as the country's demand for
petrochemical products is consistently proportional to its large population. The
government aims to reduce the import of petrochemical products and develop the
domestic petrochemical industry to meet the growing demand. Indonesia's reliance
on fossil fuels, including gasoline, is evident in its energy consumption, with petroleum
accounting for a notable share. The Indonesian government aims to be totally self-
sufficient in petrochemicals by 2027, indicating a significant focus on the development
of the petrochemical industry in the country. While the demand for gasoline is driven by
the transportation sector, the increasing demand for petrochemicals is fueled by various
industrial and consumer applications, reflecting the diverse usage of petrochemical
products in the Indonesian economy.
85 Mordor Intelligence. “Oil and Gas Industry in Indonesia Size & Share Analysis - Growth Trends & Forecasts
(2024 - 2029)”, 2023.
86 Mohi Narayan, “Indonesia 2023 gasoline demand, imports likely to exceed 2022 records,” 2023.
87 Mohi Narayan, “Indonesia's 2024 oil and gas lifting estimated below targets - upstream regulator,” 2023.
88 IEA, “Country Analysis - Indonesia”, accessed in 2024.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 37
2.4 Role of CCS/CCUS in transition
In the wake of global efforts to combat climate change, nations worldwide are exploring
innovative solutions to reduce greenhouse gas emissions. Indonesia, a country rich
in natural resources, faces the challenge of balancing economic development with
environmental sustainability. It is well acknowledged that Indonesia has enormous potential
for geological formations that can be used to store carbon emissions. With technology in
carbon capture & storage (CCS) as well as carbon capture, utilisation & storage (CCUS)
activities, it is hoped that Indonesia can find the right balance and achieve its global
commitments being pledged pursuant to the Paris Agreement. The idea of CCS and CCUS
is novel to the public, but their technological history extends a century back. However,
the application of these technologies is not risk-free. The risks could manifest into harm,
damage, and injuries in early periods and at periods much later. Having said that, it is
without a doubt that effective and clear legal standards and frameworks must be in place
not only to facilitate the creation of incentives but also to efficiently protect the community
from any foreseeable risks.
In 2024, there is significant momentum for the implementation of CCUS in Asia. Several
developments and initiatives are underway in various Asian countries to promote CCUS
technology:
• Japan and China: The Japanese Government has launched the Asia CCUS Network to
support capacity development and promote collaborative projects in the region. China
has included large-scale CCUS demonstration projects in its 14
th
Five-Year Plan
89
;
• Asian Development Bank (ADB): The ADB has been working with its developing
member countries to identify new opportunities in CCUS, prepare regulatory
frameworks, and grow a research network to create opportunities for low-carbon
development
90
;
• Southeast Asia: Interest in CCUS in Southeast Asia has been growing, with plans for
several potential projects in countries such as Indonesia, Malaysia, Singapore, and
Timor-Leste. Singapore has identified a key role for CCUS in its long-term emissions-
reduction strategy
91
.
89 CCS Knowledge, “Momentum of Large-Scale CCUS in Asia,” 2022.
90 Asian Development Bank (ADB), “Enabling CCUS Implementation in Asia,” 2024.
91 IEA, “Carbon capture, utilisation and storage: the opportunity in Southeast Asia,” 2021.
Global CCS Institute, “2024 Australia and Southeast Asia Forum on Carbon Capture and Storage” 2024.
Photo source: PT Medco Energi Internasional Tbk
38PwC
In this context, the Indonesian government has introduced a legal framework to regulate
CCS and CCUS activities particularly within the oil and gas sector. It was started by the
issuance of the MoEMR Regulation No. 2 of 2023 (MoEMR Regulation No. 2/2023) which
is aiming to provide general guidelines for CCS/CCUS projects. This regulation aligns with
Indonesia’s commitment to the Paris Agreement and aims to facilitate the country’s energy
transition while also encouraging an increase in oil and natural-gas production.
At the outset, MoEMR Regulation No. 2/2023 regulates the implementation of both
CCS and CCUS activities which preceded by obtaining approval from the government
authorities. The approval process itself requires contractors
92
to submit detailed proposals
covering technical, economic, safety, and environmental aspects, either to:
(i) MoEMR through SKK Migas or the Aceh Oil and Gas Management Agency (Badan
Pengelola Migas Aceh or BPMA), if the CCS/CCUS is part of the first field development
plan; or
(ii) SKK Migas or BPMA, if CCS/CCUS is part of the next field development plan(s).
Based on the evaluation of the proposal, MoEMR or SKK Migas/BPMA (according to
their respective authorities) may approve or reject the CCS/CCUS plan submitted by the
contractors. The cooperation contract
93
will be amended to reflect the approved proposal.
Furthermore, the regulation mandates monitoring, reporting, and verification (MRV) of CCS/
CCUS activities to ensure compliance with standards and good practices. It also outlines
closure conditions, emphasising safety and environmental considerations.
In addition to this, the newly issued Presidential Regulation No. 14 of 2024 (PR No.
14/2024) focuses on the implementation of CCS activities, recognising yet reemphasising
Indonesia's potential as a carbon storage hub. It offers two schemes for CCS activities:
1) integration into oil and gas operations and requires cooperation contract amendments
for CCS inclusion, and 2) exploration and storage operation permits for designated
non-working areas. PR No. 14/2024 further outlines a more detailed process for CCS
implementation plans, including evaluation by SKK Migas and approval by the MoEMR.
It also addresses carbon-storage licenses which are not being a pre-requisite for
implementing CCS under MoEMR Reg No.2/2023, prioritising domestic storage capacity
and international cooperation.
Moreover, the regulation introduces carbon transportation licensing and emphasises tax
incentives to encourage investment in CCS projects. PR No. 14/2024 is elaborative enough
for businesses to start considering the development of CCS projects and complements
MoEMR Reg No. 2/2023 perfectly. However, challenges persist regarding international
carbon trading and regulatory enforcement as there are still requirements that need to be
fulfilled for international carbon trading to be conducted.
92 Business entities or permanent establishments that are stipulated to carry out exploration and exploitation
in a work area based on a cooperation agreement with SKK Migas or BPMA.
93 Cooperation contract means a production sharing contract or other forms of cooperation contract in
exploration and exploitation activities which is more profitable for the state and the results of which are
used for the greatest prosperity of the people.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 39
SKK Migas Work Procedure Guidelines No. PTK-070/SKKIA0000/2024/09 (PTK 070)
provides a comprehensive technical framework for CCS/CCUS activities. It emphasises
health, safety, and environmental protection, along with compliance with national and
international standards. PTK 070 outlines the responsibilities of SKK Migas and contractors,
emphasising risk management and MRV throughout the project lifecycle. It also addresses
data collection, geological studies, and integrity evaluations for CCS/CCUS facilities.
Additionally, PTK 070 highlights monetisation strategies for CCS/CCUS implementation and
the classification of goods and equipment used in these activities.
In conclusion, Indonesia’s current legal framework for CCS/CCUS activities reflects its
commitment to environmental sustainability and economic development. As in many parts
of the world, the implementation of CCS/CCUS in Indonesia could enable continued fossil
fuel consumption with responsibility while reducing CO
2
emissions. As elaborated above,
while regulations provide more clarity and guidance on the implementation of CCS/CCUS
activities, challenges such as:
a) whether risk allocation of the development of CCS/CCUS projects has been distributed
and managed fairly since the timeline of potential damages/injuries may extend multiple
millennia beyond the lifetime of humans or even corporate entities. Addressing this, it is
important to ensure that the legal framework strikes the right balance between potential
liability issues and the related issue of compensation for CCS related damages and the
economic value of the CCS/CCUS projects from the contractors’ point of view.
In this context, the questions might specifically be whether at the end of the verification
of plans to close CCS/CCUS projects, releasing contractors’ obligations is the best
option and whether the 10 years of monitoring that has been set by the regulations
is sufficient to guarantee the possibility of CCS related damages. The current legal
framework on CCS/CCUS implies the application of rules of negligence instead of strict
liability;
b) whether the Indonesia government provides sufficient incentives for contractors and
investors (as applicable) to run CCS/CCUS projects and does monetisation of projects
provide a profitable return on investment to attract more investors to participate in the
projects. From a carbon trading perspective alone, the contractors or investors may
see insufficient domestic market price for carbon. Not to mention limited insurance
providers for insuring the CCS/CCUS projects which therefore increases the project
costs;
c) whether in its implementation, regulatory requirements and enforcement as set forth
in the relevant legal framework are carried out by parties with full responsibility. The
devil will be in the details, especially in the approval and MRV processes, which will
be crucial for the development of CCS/CCUS projects. While it is recognised that the
risks of CCS/CCUS activities are foreseeable considering the advanced technologies,
for developing countries like Indonesia regulators should be equipped with sufficient
technical knowledge and power to enforce sanctions (as applicable) and to take
decisions in a timely manner so as not to delay investment.
40PwC
Moving forward, stakeholders must collaborate to address these challenges and unlock the
full potential of CCS/CCUS technologies. By fostering innovation, promoting investment,
and ensuring regulatory compliance, Indonesia can pave the way for a sustainable future
while contributing to global climate-action efforts. Furthermore, Indonesia’s legal framework
for CCS/CCUS activities lays the foundation for a transition towards a low-carbon
economy. As the country navigates this path, it must continue to prioritise environmental
stewardship while fostering economic growth and energy security.
As the first country in Asia to enact a legal framework for CCS, and the regulations may
provide opportunities for investors to participate in CCS or CCUS projects in Indonesia. The
country has also been proactive in promoting energy transition in Southeast Asia through
the development of these regulations, which are seen as a catalyst for neighbouring
countries in the region
94
.
MoEMR and SKK Migas’ efforts to promote CCS and CCUS investments are notable.
They has taken the lead in promulgating regulations to support the development of these
technologies
95
. The regulations in Indonesia address key aspects such as the establishment
of legal and regulatory frameworks, monitoring, reporting and verification requirements, and
the creation of a carbon credit scheme and carbon trading market.
Indonesia’s proactive approach and the comprehensive nature of its regulations
demonstrate its commitment to advancing CCS and CCUS technologies, which could have
a significant impact on the region’s energy transition and climate change mitigation efforts.
As a closing remark, the journey towards widespread CCS/CCUS implementation in
Indonesia is multifaceted and requires the concerted efforts of government, industry, and
civil society. By leveraging legal frameworks, promoting technological innovation, and
fostering international collaboration, Indonesia can play a pivotal role in global efforts to
mitigate climate change while ensuring sustainable development for the future
96
.
94 Morgan et al., “Indonesia’s New Regulation on CCS and CCUS: A Step Rather than a Leap?,” Lexology, 2023.
95 “Indonesia’s New CCS/CCUS Regulations: Promoting Energy Transition in Southeast Asia,” Indonesia’s New
CCS/CCUS Regulations: Promoting Energy Transition in Southeast Asia, 2023.
96 Arma-Law, “Indonesia introduces CCS and CCUS regulations”, 2024.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 41
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide41
42PwC
Photo source: PwC
42 PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 43
Regulatory
framework
3
The law regulating oil and gas activities is Law No. 22. The objectives
of Law No. 22 (Article 3) are to:
a. Guarantee effective, efficient, highly competitive and sustainable
exploration and exploitation of oil and gas;
b. Assure accountable processing, transport, storage and
commercial businesses through fair and transparent business
competition;
c. Guarantee the efficient and effective supply of oil and gas as a
source of energy and to meet domestic needs;
d. Promote national capacity;
e. Increase state income; and
f. Enhance public welfare and prosperity equitably, while
maintaining the conservation of the environment.
3.1 Oil and Gas Law No. 22/2001
Law No. 6 of 2023 on the Stipulation of Government Regulation in
Lieu of Law No. 2 of 2022 on Job Creation
On 30 December 2022, the President of the Republic of Indonesia signed Government
Regulation in Lieu of Law No. 2 of 2022 on Job Creation (Perppu No. 2). Perppu No. 2
revoked and completely replaced Law No. 11 of 2020 concerning Job Creation (Law No.
11/2020) that was previously declared legally defective and conditionally unconstitutional by
the Indonesia Constitutional Court based on the Constitutional Court Decision No. 91/
PUU-XVIII/2020 (MK-91 Decision) since it was issued without a proper formality process. On
31 March 2023, Indonesia’s House of Representatives approved into law the Perppu No. 2
as Law No. 6/2023 (the Job Creation Law).
In general, the provisions stipulated in the Job Creation Law are not substantially different
from those stipulated in Law No. 11/2020. The Job Creation Law essentially amends several
laws, one of which is the oil and gas law, namely Law No. 22 dated 23 November 2001
(Law No. 22). The laws that are amended by the Job Creation Law relating to the oil and gas
sector and mentioned in this guide are:
1. Law No. 22;
2. Investment Law No. 25/2007 (Law No. 25/2007);
3. Company Law No. 40/2007 (Law No. 40/2007);
4. Environment Law No. 32/2009 (Law No. 32);
5. Forestry Law No. 41/1999, as amended by Law No. 1/2004 and Law No. 18/2013
(Law No. 41);
6. Shipping Law No. 17/2008.
For ease of reference, the above-mentioned regulations will be referenced throughout this
guide with the intention that they have been amended by the Job Creation Law.
44PwC
In the past few years, especially after the
Constitutional Court decision in 2012
to disband the upstream regulator (BP
Migas - Badan Pelaksana Kegiatan Usaha
Hulu Minyak dan Gas Bumi), there has been
an expectation that Law No. 22 will be
amended. A draft amendment to Law No.
22 became available in 2023.
The draft law reaffirms that Indonesia's oil
and gas resources are national assets under
State control. The Central Government is to
act as the holder of all mining authority and
to establish a “special executive agency”,
which will be a state- owned enterprise
(BUK Migas - Badan Usaha Khusus Minyak
dan Gas Bumi). BUK Migas will be granted
authority by the State to do business
activities in the upstream (independently
and/or through a cooperation with
contractor(s)) and downstream sectors.
Whilst Law No. 22 requires a maximum of
25% Domestic Market Obligation (DMO) for
both oil and gas, the draft law also contains
the same DMO percentage.
The draft law, while obviously still subject
to further review, appears to focus on
locking-down State control over oil and gas
resources. Although not a significant shift,
there seems to be a stronger emphasis on
this outcome. Practically, these changes,
especially the relaxation of contractual
terms, may raise concerns among investors.
Obviously progress of the draft law should
be monitored.
3.1.1 Control of upstream and
downstream activities
According to Law No. 22, the Government
regulates upstream oil and gas activities
(generally via a PSC) as the grantor of the
relevant concession. Law No. 22
differentiates upstream business activities
(between exploration and exploitation) and
downstream business activities (processing,
transport, storage and commerce) and
stipulates that upstream activities are
controlled through ”Joint Cooperation
Contract (JCCs)” (predominantly PSCs)
between the Business Entity/Permanent
Establishment (PE) and the executing
agency (SKK Migas) (Article 6). Downstream
activities are controlled by business
licences issued by the regulatory agency
(BPH Migas – Badan Pengatur Hilir Minyak
dan Gas Bumi) (Article 7). SKK Migas and
BPH Migas thereby supervise upstream
and downstream activities respectively to
ensure:
a. The conservation of resources and
reserves;
b. The management of oil and gas data;
c. The application of good technical
norms;
d. The quality of processed products;
e. Workplace safety and security;
f. Appropriate environmental management
such as preventing environmental
damage;
g. The prioritisation of local manpower,
goods and services and domestic
engineering capacities;
h. The development of local communities;
and
i. The development and application of oil
and gas technology.
Upstream and downstream business
activities may be carried out by SOEs,
regional administration-owned companies,
cooperatives, small-scale businesses
or private-business entities. Upstream
business activities can include branches of
foreign incorporated enterprises as a PE.
However, upstream entities are prohibited
from engaging in downstream activities,
and vice versa (Article 10) except where
an upstream entity must build transport,
storage or processing facilities or other
downstream activities that are integral to
supporting its exploitation activities
(Article 1).
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 45
3.1.2 GR-79 as amended by GR-
27 on cost recovery and income
tax for the oil and gas sector
GR No. 79 (GR-79), issued on 20 December
2010, introduced the initial framework for
cost recovery and tax arrangements in
the upstream sector. Many implementing
regulations have been issued, although
some regulations are still pending. For more
on this, see Chapter 4.4.2.
Addressing concerns raised by the
upstream industry with regard to the
application of GR-79, the Government
enacted GR No. 27 (GR-27) on 19 June
2017 as lastly amended by GR No. 93 (GR-
93) on 31 August 2021. The key provisions
of GR-27 are discussed in Chapter 4.4.2.
3.1.3 MoEMR Regulation No.
8/2017 as lastly amended by
MoEMR Regulation No. 12/2020
and GR- 93 on GS PSCs
With the stated aim of incentivising
exploration and exploitation activities, the
Government since 2017 has introduced
a “gross production split” model for how
upstream business activities should be
conducted going forward. We elaborate this
model further in Chapter 5.
3.1.4 Restrictions on foreign
workers
Currently, by the revocation of Regulation
No. 31/2013 by the enactment of MoEMR
Regulation No. 6/2018, there is no particular
position that is closed to expatriates, unless
such activities are restricted under general
manpower regulations (e.g. human resource
director, occupational safety specialist, job
analyst, etc.).
3.1.5 Local content requirements
Law No. 22 mandates that the Business
Entity or PE carrying out Oil and Natural Gas
business activities must give priority to use of
local manpower, domestic goods, services,
as well as engineering and design capabilities
in a transparent and competitive manner.
As the implementing regulation of Law
No. 22, the MoEMR issued Regulation No.
15/2013 on the Use of Domestic Products
for Upstream Business of Oil and Natural
Gas. The regulation further stipulates
that any procurement activity must be in
accordance with the Domestic Product
Appreciation Book (APDN Book) published
by the MoEMR, which lists, among other
things, the goods and/or services that are
categorised as mandatory, maximised or
empowered for use of domestic products.
The method of calculation of the Local
Content (TKDN - Tingkat Komponen Dalam
Negeri) is as follows:
a. Goods will be calculated based on the
ratio of domestic components in the
goods and the entire costs of finished
goods;
b. Services will be calculated based on
the ratio between the service cost of
domestic components in the services
and the total costs of services; and
c. Combination of Goods and Services
will be the ratio of entire domestic
components costs in the combined
goods and services against the entire
combined costs of goods and services.
In addition, the status of the goods and/or
services’ provider will also determine the
TKDN value. The MoEMR divides the status
as follows: (i) a Domestic Company (owned
at least 50% by an Indonesian entity(s)); (ii) a
National Company (owned 50% or more by
foreign entities); and (iii) a Foreign Company.
46PwC
the National Energy Council (DEN - Dewan
Energi Nasional) was established in June
2009 with the task of formulating and
implementing a House of Representatives-
approved National Energy Policy,
determining the National Energy General
Plan and planning steps to overcome any
energy crisis or emergency.
National energy policy
GR No. 79/2014 was issued on 17 October
2014 regarding the National Energy Policy,
as originally formulated by DEN.
The National Energy Policy covers the
overall management of energy and seeks to
address issues such as:
a. The availability of energy to meet the
nation’s requirements;
b. Energy development priorities;
c. The utilisation of national energy
resources; and
d. National energy buffer reserves.
The National Energy Policy aims to achieve
an optimal energy-resource mix at 2025 and
2050 target dates as follows:
Table 3.1
Energy Source 2025 2050
New and
renewable energy
minimum
23%
minimum
31%
Crude oil
less than
25%
less than
20%
Coal
minimum
30%
minimum
25%
Natural gas
minimum
22%
minimum
24%
Source: PR 22/2017
DEN is chaired by the President and
Vice- President with the MoEMR as
Executive Chairman. DEN has 15 members,
including the Minister and Government
officials responsible for the provision,
transportation, distribution and utilisation
of energy; and other stakeholders (two
from academia; two from industry; one
technology representative; one environment
representative; and two from consumer
groups).
Furthermore, the requirement on TKDN is
regulated under SKK Migas Work Guidelines
(PTK - Pedoman Tata Kerja) No. PTK 007
concerning Procurement Guidelines for
Goods or Services.
3.1.6 Licences
Business licensing in the oil and gas sector
is regulated in GR No. 5/2021 (GR-5)
which is the implementing regulation of
Law No. 22/2001 (as amended by the Job
Creation Law). GR-5 recognises Risk-
Based Business Licensing, which is a
business license based on the level of risk
of business activities, and the level of risk
determines the type of business license.
The government has mapped the risk level
according to business fields or Indonesian
Standard Industry Classification (KBLI -
Klasifikasi Baku Lapangan Usaha Indonesia),
which has been implemented in the Risk-
Based Online Single Submission (OSS)
System.
The Online Single Submission Risk Based
Approach (OSS RBA) accommodates
licensing in various business sectors
based on the level of risk and scale of
business activities. This system integrates
all business licensing services under the
authority of the minister/agency head,
governor, or regent/mayor. The requirements
and obligations for obtaining a business
license of each KBLI are regulated in the
attachment of GR-5 and the technical
ministry regulation (this refers to MoEMR
Regulation). For more of this, see section
6.1.2.
3.2 Other relevant laws
3.2.1 The Energy Law No.
30/2007
The Energy Law No. 30/2007 dated 10
August 2007 provides a renewed legal
framework for the overall energy sector, with
an emphasis on economic sustainability,
energy security and environmental
conservation (Article 3). Under this Law,
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 47
3.2.2 Investment Law No.
25/2007 and Company Law No.
40/2007
Form of business
Under Law No. 22, foreign investors can
enter the upstream oil and gas sector
through two avenues: either by establishing
a branch of a foreign company (referred
to as a PE) or by incorporating a limited-
liability company in Indonesia (known as PT
- Perseroan Terbatas).
The "ring-fencing" principle, outlined in
Article 13 of Law No. 22, dictates that only
one Production Sharing Contract (PSC)
can be granted per PE or PT, necessitating
separate entities for each operational area.
For instance, following the enactment
of Law No. 22, Pertamina had to create
subsidiaries and form PSC agreements with
SKK Migas for each operational area.
Investment Law No. 25/2007 (Law No. 25)
dated 26 April 2007 applies to PTs operating
in the downstream sector (including foreign
investment companies (PMA – Penanaman
Modal Asing).
Law No. 25 allows investors to repatriate
profits and pay interest and dividends in
foreign currencies as well as for capital
facilities. These facilities include the
exemption from Import Duty and the
exemption or postponement of Value Added
Tax (VAT) on imports of capital goods
needed for production.
Please also note that the authority to
issue certain licences is now delegated
from MoEMR to Indonesia’s Investment
Coordinating Board (BKPM - Badan
Koordinasi Penanaman Modal), including for
trading, refineries, storage, general surveys
and various support services.
Positive investment list
On 2 February 2021, a positive investment
list was issued through Presidential Decree
No. 10/2021 (as amended by Presidential
Decree No. 49/2021).
The regulation has three appendices that
consist of a business activities priority list,
cooperatives and small enterprises business
activities list, and business activities with
certain requirements list.
As a rule of thumb, any business activities
that are not included in the positive
investment list are open for foreign
investment.
As per Presidential Decree No. 10/2021,
restrictions on foreign ownership apply
only to National and/or International Sea
freight for specific goods business activity
within Indonesia's oil and gas sector, with a
maximum foreign shareholding capped at
49%.
Legislative responsibilities:
environment and others
Law No. 40/2007 imposes corporate social
responsibility and environmental obligations
on companies undertaking business
activities in the natural resources field, with
the costs to be borne by the company
(Article 74).
Sanctions for non-compliance are covered
in all related legislation. On 4 April 2012, the
Government issued GR No. 47/2012
providing explanation of this responsibilities,
but it has not been regulated in more detail.
Investment Law No. 25 outlines
requirements for PT companies, such as
giving priority to Indonesian manpower,
creating a safe and healthy working
environment (Article 16), implementing
corporate social responsibility programs
(Article 15), and ensuring environmental
conservation (Article 16).
48PwC
Investors exploiting non-renewable
resources must also allocate funds to
site restoration that fulfil the standards of
environmental responsibility (Article 17).
Sanctions for non-compliance with
Article 15 include restrictions on business
activities, and the freezing of business
activities (Article 34 of the Investment Law).
3.2.3 Environment Law No.
32/2009 and Forestry Law No.
41/1999
Environment law
In October 2009, Law No. 32 was issued
and entities are required to comply with
standard environmental quality requirements
and to secure environmental approval before
beginning operations. Sanctions can include
the cancellation of operating permits, fines,
and/or imprisonment.
Forestry law
Law No. 41 prohibits oil and gas activities
from being conducted in protected forest
areas except where a Government permit is
obtained. GR No. 23/2021 allows projects,
including for oil and gas activities, to take
place in protected forests where they are
deemed strategically important.
Under GR No. 23/2021 the utilisation of
forestry areas for non-forestry activities is
permitted in both production forests and
protected forests subject to obtaining an
PPKH (Persetujuan Penggunaan Kawasan
Hutan) from the Ministry of Forestry. The
PPKH holder will be required to pay various
non-tax State Revenues pursuant to
these activities and will need to undertake
reforestation activities upon ceasing its use
of the land. The issuance and validity of the
PPKH permit depends entirely on the spatial
zoning of the relevant forest areas.
The use of a forestry area will often also
require land compensation transfers
or compensation payments to local
landowners.
3.2.4 Regulating export proceeds
and foreign exchange
BI has issued regulations in 2023
concerning export proceeds and foreign
exchange, namely Bank Indonesia
Regulation (PBI - Peraturan Bank Indonesia)
PBI No. 7/2023.
PBI No. 7/2023 stipulate that exporters
of natural resources that have a Foreign
Exchange Proceeds from Exports from
Natural Resources Exported Goods (DHE
SDA) with an export value of equal or more
than USD250,000 (or its equivalent) in
their Export Customs Declarations (PPE
- Pemberitahuan Pabean Ekspor) must
deposit at least 30% of its DHE SDA in the
Indonesian financial system, for a minimum
period of three months since the placement
of the deposit.
The DHE SDA deposit can be placed in one
of the following instruments:
a. A special account opened at the
Indonesian Export Financing Agency
(LPEI - Lembaga Pembiayaan Ekspor
Indonesia) or at a foreign exchange
bank;
b. Banking instruments, e.g., foreign
exchange time deposit;
c. Financial instruments issued by
LPEI, i.e, promissory note in foreign
exchange; and/or
d. Financial instruments issued by BI, i.e,
conventional open market operation
term deposit in foreign exchange in BI.
Pursuant to BI Regulation 7/2023, DHE
SDA deposited in the above banking and
financial instruments have several benefits
for the exporters, among other things, for
funds deposited into a special account, it
could be used for a forex swap transaction
between the exporters and the banks and
such instruments may also be used by
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 49
the exporters as a loan security (in Rupiah
currency). Furthermore, according to
GR 36/2023, DHE SDA deposited in the
special account may be used by exporters
for the payment of export duty and other
levies in export sector, loan, import,
profits/dividends, and/or other needs for
investment (e.g. transfer of DHE SDA to
another party).
Administrative sanctions, in the form of
suspension of export services/facilities,
will be imposed to the exporters of natural
resources for non-compliance of the
following obligations:
a. Failure to deposit DHE SDA on special
accounts;
b. Failure to deposit DHE SDA of at least
30% of their export proceeds and
below 3 months; and/or
c. Failure to create an escrow account on
or transfer overseas escrow account to
LPEI and/or certain banks conducting
activities in foreign exchanges.
GR 36/2023 introduces heavier penalties
than GR 1/2019 on exporters failing to
comply with the regulation. The requirement
for the exporters to deposit at least 30%
of their DHE SDA for a minimum of three
months may cause concerns for the
exporters (including Indonesian mining
companies) in managing their cash flows.
For the oil and gas sector concerns with the
PBIs include:
a. Inconsistency with the “contract
sanctity” of the PSC which provides
that the contractor may freely lift and
export their production share and retain
the proceeds of any sale abroad;
b. Potentially reducing liquidity for
contractors and impacting development
activities;
c. The effect on trustee paying agent
mechanisms for gas/LNG sales and
associated financial covenants; and
d. The cost of minimum periods of deposit
and/or mandatory conversions into
Rupiah. 3.2.5 Mandatory use of
Indonesian Rupiah
On 31 March 2015, Central Bank of
Indonesia (BI) issued Regulation No. 17
(17/3/PBI/2015) as implementing guidance
for Law No. 7/2011 regarding the mandatory
use of the Rupiah for cash and non-cash
transactions in Indonesia. Circular Letter (SE
- Surat Edaran) No. 17/11/ DKSP17) was
issued on 1 June 2015.
From 1 July 2015, any cash or non-cash
transactions made within Indonesia must
use and be settled in Rupiah. All price
quotations of goods and services must also
be in Rupiah, and dual currency quotations
are prohibited.
Through circular letter SE-17, BI clarified
the following infrastructure projects as
exempted from the mandatory use of
Rupiah rules:
a. Transportation;
b. Road construction and irrigation
systems;
c. Infrastructure for water supplies;
d. Power utilities including power plants
and transmission systems; and
e. Oil and gas projects.
To obtain the exemption, the project owner
should seek confirmation from the relevant
Ministry and obtain a waiver letter from BI.
On 1 July 2015, the MoEMR and BI issued
a press release (No. 40/SJI/2015) outlining a
framework to classify transactions into three
main categories (for the energy sector), as
a transition towards the mandatory use of
Rupiah. The categories are:
• Category 1 – Transaction proceeds
which can be directly converted
to Rupiah (e.g., leases and salary
payments to local employees – six-
month transition);
• Category 2 – Transaction proceeds
which require time to be converted
to Rupiah (e.g., long-term service
contracts). These can continue to
use foreign currency subject to future
amendments to the contracts;
50PwC
• Category 3 – Transaction proceeds
where it is fundamentally difficult
to use Rupiah (e.g., salaries paid to
expatriates, drilling services and the
leases of ships). These may continue
to use foreign currency for a maximum
ten-year period.
The MoEMR and BI have formed a task
force to set guidelines and procedures for
the implementation of PBI No. 17/3/
PBI/2015, especially for Category 3 types of
transactions.
3.3 Key stakeholders
3.3.1 The MoEMR
The MoEMR is charged with creating and
implementing Indonesia’s energy policy,
ensuring that the related business activities
are in accordance with the relevant laws
and regulations, and awarding contracts.
Presidential Decree No. 97/2021 stipulates
the functions of the MoEMR, which include:
a. Formulating and determining the
development, control, and supervision
policies of oil and gas;
b. Implementing policies in the field of
development, control, and supervising
oil and gas;
c. Implementing of technical guidance
and supervising the implementation of
policies in the field of guidance, control,
and supervision of oil and gas;
d. Implementing research and
development in the field of energy and
mineral resources.
3.3.2 Special Task Force for
Upstream Oil and Gas Business
Activities (SKK Migas)
SKK Migas controls upstream activities
and manages oil and gas contractors on
behalf of the Government through JCCs.
Under Law No. 22 (Articles 44 and 45), all
of Pertamina’s rights and obligations arising
from existing Cooperation Contracts, for
and on behalf of the Government, were
transferred to SKK Migas.
Based on MoEMR Regulation No. 2/2022,
SKK Migas has the following roles:
a. To provide advice to the MoEMR with
regard to the preparation and offering of
work areas and JCCs;
b. To act as a party to JCCs;
c. To assess first field development plans
in a given work area and to submit
evaluations to the MoEMR for approval;
d. To approve development plans (other
than those mentioned in point c);
e. To approve work plans and budgets;
f. To report to the MoEMR and monitor
the implementation of JCCs; and
g. To appoint sellers of the State’s portion
of petroleum and/or natural gas to the
Government’s best advantage.
Photo source: PT Pertamina (Persero)
50 PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 51
3.3.3 Downstream Oil and Gas Regulatory Agency (BPH Migas)
BPH Migas was established on 30 December 2002 to assume Pertamina’s regulatory role in
relation to downstream activities (Articles 46 and 47 of Law No. 22). BPH Migas is charged
with assuring sufficient natural gas and domestic fuel supplies and the safe operation
of refining, storage, transportation and distribution of gas and petroleum products via
business licences.
BPH Migas’ regulatory, development and supervisory roles are set out in the following table:
Table 3.2 - Regulatory, development and supervisory roles
Regulatory and Development Areas under BPH Migas Supervisory Areas under the MoEMR
• Business licences
• Type, standard and quality of fuels
• Utilisation of oil fuel transportation and storage facilities
• Exploitation of gas for domestic needs
• Strategic oil reserves
• National fuel oil reserves
• Masterplan for a national gas transmission and distribution
network
• Occupational safety, health, environment and Community
Development (CD)
• Price setting including the gas selling price for households
and small-scale customers
• Utilisation of local resources
• Business licences
• Type, standard and quality of fuels
• Occupational safety, health,
environment and CD
• Employment
• Utilisation of local resources
• Oil and gas technology
• Technical rules
• Utilisation of measurement tools
Source: GR No. 36/2004
BPH Migas is also responsible for the supervision of fuel oil distribution and transportation
of gas through pipelines operated by PT companies.
Table 3.3 - Supervision of fuel distribution and transportation of gas
Supervision and Distribution of Fuel Oil Transportation of Gas by Pipelines
• Supply and distribution of fuel oil
• Supply of fuel oil in remote areas
• Allocation of fuel oil reserves
• Market share & trading volumes
• Settling of disputes
• Development of transmission segment and
distribution network area
• Determination of natural gas pipeline
transmission tariffs and prices
• Market share of transportation and distribution
• Settling of disputes
Open access to gas pipelines
In line with Decision of the MoEMR No. 2700K/11/MEM/2012 regarding the National
Core Plan for Gas Transmission and Distribution Network, in 2018 BPH Migas outlined a
plan to auction concessions for the construction of gas pipelines between Natuna – West
Kalimantan, West Kalimantan to Central Kalimantan and Central Kalimantan to South
Kalimantan on the basis of open (third party) access. BPH Migas rules supporting open
access have existed since 2008 and stipulate that the owners of gas pipes must allow
access by third parties.
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3.3.4 House of representatives
(DPR - Dewan Perwakilan
Rakyat) and regional
governments
Commission VII of the DPR is in charge of
energy, mineral resources, research and
technology, and environmental matters. This
includes oversight of oil and gas activities,
the drafting of oil and gas related legislation,
the control of the state budget (APBN) and
control of related Government policy. It also
advises the Government of the oil and gas
sector’s contributions to the APBN.
Regional Governments are involved in the
approval of PoD through the issuance of
local permits and land rights. In addition,
the Regional Governments have the right to
be offered a 10% participating interest of
a PSC. For more detail on this, please see
Chapter 4.1.8.
3.3.5 PT Pertamina (Persero)
On 18 June 2003, PT Pertamina (Persero)
was transformed from a state-owned oil
and gas enterprise governed by its own law
into a state-owned limited liability company.
In recent years, Pertamina has expanded
its scope to include gas, renewables and
upstream operations both within Indonesia
and abroad. It now has upstream operations
in Vietnam, Malaysia, Sudan, Qatar and
Libya, and provides aviation fuel services
at ten international airports. Pertamina has
also entered into several Joint Operations
(JOs) within Indonesia.
PGN operates a natural gas distribution
pipeline network and a natural gas
transmission pipeline network. Its
subsidiaries and affiliated companies are
involved in upstream activities, downstream
activities, telecommunications, construction
and a floating storage and regasification
terminal.
With the issuance of GR No. 6/2018, the
Government formalised the establishment
of a National State-Owned Enterprise
(SOE/BUMN - Badan Usaha Milik Negara)
holding company in the oil and gas sector,
combining the business of PGN with
Pertamina and appointing Pertamina as
the holding company of SOEs serving the
oil and gas industry. In February 2018,
Pertamina became the major shareholder
of PGN, by acquiring the Government's
controlling 56.97% stake while PGN
continues to be a publicly listed company.
Following the acquisition, Pertamina and
PGN integrated and streamlined the gas
distribution business previously held by
PGN and PT Pertamina Gas (Pertagas), a
wholly-owned subsidiary of Pertamina. In
December 2018, PGN acquired Pertamina's
51% controlling interest in Pertagas, and
became the sub-holding entity for gas
operations.
3.3.6. Notable industry
associations
The Indonesian Petroleum Association (IPA)
was established in 1971 in response to
growing foreign interest in the Indonesian
oil and gas sector. The IPA’s mission is
to be the voice of the upstream oil and
gas industry in Indonesia and to work
collaboratively with all stakeholders to
promote the industry for the benefit of
government, investors, communities,
employees, customers and the environment.
Other industry associations include drilling
company associations (APMI – Asosiasi
Perusahaan Pemboran Minyak, Gas dan
Panas Bumi Indonesia), national oil and gas
company association (ASPERMIGAS
- Asosiasi Perusahaan Minyak dan Gas),
oil and gas entrepreneurs association
(HISWANA MIGAS - Himpunan Wiraswasta
Nasional Minyak dan Gas Bumi) and KADIN.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 53
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide53
54PwC
(Conventional)
Upstream sector
4
As previously mentioned, the government introduced the Gross Split
(GS) Production Sharing Contract (PSC) model for upstream business
activities, intended to be implemented for new PSCs from 2017/2018
onwards. However, it's worth noting the flexibility introduced in 2020,
as discussed in Section 1.2.
The GS PSC regime has significantly altered the fundamental principles
and regulatory framework of the conventional cost recovery model in
the upstream sector, which had been established for over 40 years.
The GS system is discussed in Chapter 5. This chapter covers the
traditional, or conventional, cost recovery PSC system, which is still the
main system in force in the Indonesian upstream oil and gas sector.
4.1 Upstream regulations
Activities in the oil and gas upstream sector are regulated by Law
No. 22, its implementing regulation GR No. 35/2004 (GR-35), and the
amending GR No. 34/2005 (GR-34), as well as GR No. 55/2009
(GR-55), GR-27 (as an amendment to GR-79), and GR-93. A summary
of Law No. 22’s key sections is set out below.
4.1.1 Work areas
Upstream business activities, including exploration and exploitation,
are conducted within designated regions known as "work areas".
These areas are formalized following approval by the Ministry of
Energy and Mineral Resources (MoEMR), in consultation with SKK
Migas and relevant local government authorities, and are specified in
a Joint Cooperation Contract (JCC).
A work area can be offered either through a tender or a direct offer
(see below).
Following the issuance of MoEMR Regulation No. 08/2017
(Regulation-08) regarding GS PSCs in January 2017, direct offers
or tenders for new acreage must be awarded under the GS
mechanism. However, on 15 July 2020, the MoEMR issued Regulation
No.12/2020 (Regulation-12), which constitutes the third amendment to
Regulation-08, providing an option for oil and gas investors to choose
either a conventional cost recovery PSC or a GS PSC. Hence, this
provides legal certainty and flexibility for oil and gas investors.
The key features of a GS PSC can be found in Chapter 5.
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Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 55
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide55
56PwC
Each business entity or Permanent Establishment (Contractor) is permitted to hold only one
work area, adhering to the "ring-fencing" principle. The Contractor must return the work
area, either in stages or in full, as commitments are fulfilled according to the JCC. Once
returned, the work area becomes open for allocation.
4.1.2 Awarding of contracts –
direct offers or tenders for new
acreage
Direct offers for new acreage
Under a direct offer, a company that
performs a technical assessment through a
joint study with the DGOG receives the
right to match the highest bidder during the
tender round.
Pertamina can apply for a direct offer,
with MoEMR approval, when: (1) the area
is an “open” area; (2) the Contractor is
transferring its PSC interest to a non-
affiliate; or (3) the area has expired or has
been relinquished.
MoEMR Regulation No. 23/2021 regulates
that expiring PSCs can be managed by
either:
a. PT Pertamina (Persero);
b. The existing Contractors (via an
extension); or
c. A JO between the PSC Contractor and
PT Pertamina (Persero).
Tenders for new acreage
The majority of new acreage is awarded
through a tendering process.
The tendering steps are as follows:
a. Register as a tender participant by
obtaining the official bid information
package from the DGOG as the
MoEMR representative. The fee for the
bid information package is USD5,000,
and is non-refundable;
b. Purchase an official government
data package for the particular
block being tendered to support the
technical evaluation and the proposed
exploration program to be submitted
together with the tender. The fee for the
data package will vary depending on
the nature of the block;
c. Attend a clarification forum a few days
prior to the tender date;
d. Submit two identical copies of the
complete bid documents by the tender
closing date;
e. The evaluation and grading of the
tender bid document is carried out
by the MoEMR Oil and Gas Technical
Tender Team for New Acreage.
Bid evaluations consider technical
evaluation (major evaluation), financial
evaluation (second evaluation)
and performance evaluation (third
evaluation); and
f. The winner of the tender is determined
by the DGOG after a recommendation
from the Tender Team.
Photo source: ENI Muara Bakau B.V
56 PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 57
No. Subject Remark
1. Application Form A completed application form.
2. Work Programme and
Budget (WP&B)
A proposed WP&B for six years of exploration activities (a
sample WP&B for a tender is provided below ).
3. Technical Report and
Montage
The geological and technical justification for the proposed
exploration programme, including a seismic survey commitment
and the completion of one exploration well.
4. Company profiles Profile describing the current business activities and human
resources of the participant and of its parent company.
5. Financial statements and
financial projections
Annual financial statements of the participant and the parent
company of the participant for the last three years, audited by a
certified public accountant.
Financial projections of the participant for the next three years.
A statement letter from a bank confirming the participant’s
ability to finance all work programme commitments for the first
three years.
6. Statement letter that new
entity will be established
to sign the PSC
-
7. Statement letter
expressing support from
the parent company
-
8. A statement regarding
bonuses
A statement confirming the participant’s ability to pay any
required bonuses.
9. Copy of bid bond A bid bond expressing a bank’s undertaking to guarantee and
provide funds in respect of the offer from the participant for
100% of the value of the signature bonus valid for six months.
10. All Consortium AgreementFor a consortium bid agreement between and/or among the
consortium members together with confirmation as to which
member of the consortium is the designated operator.
11. A statement agreeing to
the PSC Draft
A statement agreeing with the terms of the draft PSC agreement
which will be signed by the winning bidder.
12. PSC Draft A draft of the PSC agreement.
13. Original receipt of
payment
A copy of the payment receipt for the bid information document.
14. Copy of data package
payment
A copy of the proof of purchase of the official government data
package.
15. Copy of notarised deed/
articles of establishment
A copy of the participant’s notarised articles of incorporation.
16. A compliance statement A letter stating the participant’s compliance with the results of
the bidding process.
Table 4.1 - Tender document checklist
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4.1.3 General surveys and oil
and gas data
In order to delineate work areas
effectively, a general survey Geological
and Geophysical (G&G) is a prerequisite.
However, any survey undertaken by
a business entity must be at its own
expense and risk, and only after obtaining
permission from the MoEMR.
Data obtained from general surveys and
exploration and exploitation activities
automatically become the property of
the State. Therefore, any utilisation,
transmission, surrender, or transfer of this
data, whether within or outside Indonesia,
requires explicit permission from the
MoEMR. Furthermore, data resulting from
exploration and exploitation activities must
be surrendered to the MoEMR (via SKK
Migas) within three months of collection,
processing, and interpretation.
Prior to a work area being returned to the
Government, the oil and gas data can be
kept confidential for between four years
(basic data), six years (processed data) and
eight years (interpreted data). Once the
work area is returned, the data is no longer
confidential.
4.1.4 JCC
Upstream activities are executed via a
JCC, defined under Law No. 22 to be a
PSC or other form of JCC (such
as a Service Contract, Joint Operation
Agreement (JOA), or Technical Assistance
Contract (TAC)) concerning exploration and
exploitation activities, which is signed by
the business entity or PE with SKK Migas
(the executing agency).
The JCC contains provisions stipulating as
follows (Article 6):
a. That ownership of the oil and gas
remains with the Government until the
point of delivery;
b. That ultimate control over operational
management remains with SKK Migas;
and
c. That all capital and risks shall be borne
by the Contractor.
The JCC also contains provisions that
stipulate (Article 11):
a. “State revenue” terms;
b. Work areas and their reversion;
c. Work programmes;
d. Expenditure commitments;
e. Transfer of ownership of the results of
the production of oil and gas;
f. The period and conditions for the
extension of the contract;
g. The mechanism for the settlement of
any disputes;
h. Any domestic supply obligations (a
maximum of 25% of production is
generally earmarked to meet domestic
demand) (Article 22);
i. Post-mining operation obligations;
j. Workplace safety and security;
k. Environmental management;
l. Reporting requirements;
m. Plans for the development of the field;
n. Development of local communities;
and
o. Priority for the use of Indonesian
manpower.
Historically, there were two categories of
contracts for Indonesia’s petroleum
industry. The first category referred to the
bundle of rights and obligations granted
to investors in return for investing, in
cooperation with the Government, in oil
and gas exploration and exploitation (i.e.
PSCs; TACs; and Enhanced Oil Recovery
(EOR) Contracts). The second category
referred to the agreements entered
into by participants in a PSC, TAC or
EOR regarding how they will conduct
petroleum operations, such as JOAs and
Joint Operation Bodies (JOBs). Since the
passing of Law No. 22, most new contracts
have been in the form of PSCs.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 59
4.1.5 Activity, expenditure and
bonus commitments
Contractors are required to begin their
activities within six months of the effective
start date of the JCC and to carry out the
work program during the first six years of
the exploration period.
The Contractor is responsible for meeting
all financing requirements, and bears full
risk if exploration is not successful. This
financing is expected to be denominated
in USD. Any costs incurred by Contractors
are subject to recovery from the
Government.
Annual exploration expenditure
requirements are outlined in the Production
Sharing Contract (PSC) for both the initial
six years and any extensions. While the
annual commitment is stipulated in the
PSC, specifics must be endorsed by SKK
Migas through annual work programmes
and associated budgets (for PSCs with
cost recovery mechanisms). Additionally,
the Government usually mandates the
Contractor to obtain a performance bond
to cover the initial three contract years of
activity. Any excess expenditure can be
carried forward, but under-expenditure
requires consent from SKK Migas for
adjustment.
Failure to carry out the required obligation
may lead to the termination of the JCC,
and any under-expenditure may need to
be paid to the Government along with
the forfeiture of any related performance
bonds.
The bid usually includes a commitment to
pay bonuses to SKK Migas (and
increasingly the Government is requesting
a bond to cover the signing bonus as
part of the bid). These bonuses are of two
types:
a. Signature Bonuses – payable within
one month of the awarding of the
contract. These bonuses generally
range from USD 1 million – USD 15
million.
b. Production Bonuses – payable if
production exceeds a specified
number of barrels per day, e.g. USD
10 million when production exceeds
50,000 bbl./ day, or cumulative
production.
GR-79, as amended by GR-27, stipulates
that bonuses are not cost-recoverable
(see comments below). Therefore, in
accordance with the uniformity principle,
bonuses would also not be tax deductible.
The bonuses to be paid and the amount
of committed expenditure stated in a PSC
are usually negotiated and agreed by the
Contractor and SKK Migas before signing
the PSC.
4.1.6 Contract period
Joint Cooperation Contracts (JCCs) are
valid for a maximum of thirty years from the
date of approval. Upon reaching this limit,
the Contractor has the option to request an
extension from the MoEMR for a maximum
period of twenty years per extension (as
per Article 14). Extension requests can be
submitted no earlier than ten years and
no later than two years before the JCC
expiration date.
The maximum thirty-year period
encompasses both the exploration
and exploitation phases. Typically, the
exploration phase lasts for six years and
can be extended for an additional four
years at most (as outlined in Article 15).
If no commercial discoveries are made
during the exploration phase, the JCC is
terminated. Upon expiration of the contract
period, the Contractor is required to return
the remaining work area to the MoEMR.
4.1.7 Amendments to a JCC
A Contractor may propose amendments
to the terms and conditions of a JCC.
These may be approved or rejected by
the Minister based on the opinions of SKK
Migas and their benefit to the State.
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4.1.8 Participating interests-
transfers
A contractor has the option to transfer part
or all of its participating interest, subject to
prior approval from the Ministry of Energy
and Mineral Resources (MoEMR) and/
or SKK Migas, depending on the terms
outlined in its Production Sharing Contract
(PSC). However, the transfer of a majority
participating interest to a non-affiliate
is prohibited during the first three years
of the exploration period. The taxation
issues associated with PSC transfers are
discussed in Chapter 4.5, including under
GR-79, as amended by GR-27.
Upon making a commercial discovery,
the Contractor is obligated to offer a 10%
participating interest (at the Net Book Value
of the expenditure incurred up to that date)
to a Regionally Owned Business Entity
(BUMD - Badan Usaha Milik Daerah). This
requirement was established by MoEMR
Regulation No. 37 of 2016. Under this
regulation, the Contractor must bear the
financial obligations associated with the
10% participating interest of the BUMD and
recoup the investment through oil and gas
production without any uplift.
If the offer is not taken up by the BUMD, the
Contractor is required to offer the interest
to a nationally-owned company. The offer
is declared closed if the nationally-owned
company does not accept the offer within a
period of 60 days from the date of receiving
the offer. In practice, these timeframes may
not be observed strictly.
4.1.9 Occupational health
and safety, environmental
management, and CD
Contractors must adhere to relevant laws
and regulations concerning occupational
health and safety, environmental
management, and community development
(CD). For PSC contracts signed on or after
2008, the Contractor is explicitly tasked with
implementing CD programmes throughout
the PSC's duration.
Contractors can contribute to CD through
various means, including providing physical
facilities, empowering local enterprises
and the workforce, and conducting
community-focused activities. These CD
efforts should be done in consultation with
the Local Government, with priority given
to communities nearest to the work area.
Additionally, Contractors are responsible for
funding CD programs.
For PSCs executed prior to 2008,
expenditure on CD is usually cost
recoverable. CD expenditure during
the exploitation which was non-Cost
Recoverable (non-CR) according to GR-79,
becomes cost-recoverable under GR-27
(see comments on GR 27 in Chapter 4.4).
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 61
4.1.10 Reservoir extension and
unitisation
When a reservoir extends into another
Contractor’s work area, an open area, or
the territory/continental shelf of another
country, it must be reported to the MoEMR
or SKK Migas. Unitisation arrangements
may be formalised in these cases. If the
reservoir extends into an open area that
later becomes a work area, unitisation
must be formalised. However, if the open
area remains unchanged for five years,
a proportionate extension of a contract’s
work area can be requested. All unitisation
requests require approval from the MoEMR.
4.1.11 Non-profit oriented
downstream activities allowed
The activities of field processing,
transportation, storage and sale of the
Contractor’s own production are classified
as upstream business activities. These
should not be profit oriented. The use of
facilities by a third party on a proportional
cost sharing basis is generally allowed
where there is excess capacity, SKK
Migas’s approval has been obtained, and
the activities are not aimed at making a
profit. If such facilities are used jointly with
the objective of making a profit, these will
represent downstream activities, and will
require the establishment of a separate
business entity under a downstream
business permit.
4.1.12 Share of production to
meet domestic needs
Contractors are responsible for meeting
domestic demand for crude oil and/
or natural gas. According to regulations
GR-35 and GR-27 (amendment of GR-
79), the Contractor's share of production
earmarked for domestic demand is capped
at a maximum of 25%. Additionally, GR-
27 introduces a DMO (Domestic Market
Obligation) holiday incentive for oil,
which can be issued by the MoEMR with
approval from the MoF.
4.1.13 Land title (Articles 33-37
of Law No. 22 and Section VII of
GR-35)
Rights to working areas are a “right to the
sub-surface part” and do not cover land
surface rights. Land-rights acquisitions can
be obtained after offering a settlement to
the owners and occupiers in accordance
with the prevailing laws (Article 34).
A consideration for land is based upon the
prevailing market rate. Where a settlement
is offered, land titleholders are obliged
to allow the Contractor to carry out their
upstream activities (Article 35).
Upstream and downstream activities are
not permitted in some areas unless
consent has been granted by the relevant
parties (such as the relevant government
and/or community). Restricted areas
include cemeteries, public places and
infrastructure, nature reserves, state-
defence fields and buildings, land owned
by traditional communities, historic
buildings, residences or factories.
Resettlement might be involved as a
condition for the granting of any consent.
Section VII of GR-35 sets out detailed
provisions regarding the procedures for
resettlement.
A Contractor holding a right of way for a
transmission pipeline must permit other
Contractors to use it after consideration
of relevant safety and security matters. A
Contractor planning to use a right of way
can directly negotiate with another
Contractor or party that holds the relevant
rights of way and, if agreement between
the parties cannot be reached, the
MoEMR/SKK Migas can be approached to
resolve the matter.
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4.1.14 Use of domestic goods,
service, technology, engineering
and design capabilities
Under the cost-recovery scheme, all goods
and equipment purchased by Contractors
become the property of the Government.
Importation of goods requires approvals
from the Ministry of Energy and Mineral
Resources (MoEMR), Ministry of Finance
(MoF), and other relevant ministries.
Imports are permitted only if the required
products are not domestically available at
the necessary quality, efficiency, guaranteed
delivery time, and after-sales service
standards.
Management of goods and equipment falls
under the jurisdiction of SKK Migas. Surplus
goods and equipment may be transferred
to other Contractors with government
approval, ensuring responsible use of cost
recovery funds. Surplus inventory resulting
from poor planning is not eligible for cost
recovery, aligning with GR-79 as amended
by GR-27.
This position is supported by GR-79, as
amended by GR-27.
SKK Migas is required to surrender excess
goods and equipment to the MoF if the
equipment cannot be used by
another Contractor. Any other use of such
goods and equipment, including through
donation, sale, exchange or use for capital
participation by the State, destruction or
rental, requires MoF approval, based on a
recommendation from SKK Migas/MoEMR.
All goods and equipment used for upstream
activities must be surrendered to the
Government upon termination of the JCC.
For greater detail on the treatment of
inventory; property, plant and equipment
(PP&E); and tendering for goods and
services, please refer to these respective
titles in Chapter 4.2.4.
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 63
4.1.15 Manpower and control of employee
costs and benefits
Contractors are encouraged to prioritise hiring local
manpower, but they may employ foreign workers for
specialised expertise not readily available among Indonesian
personnel. The number of expatriate positions is regulated
by SKK Migas and undergoes annual review. The current
manpower laws and regulations applying to the employees
of a Contractor are dealt with in Chapter 3.1.4 above.
Contractors are required to provide development, education
and training programs for Indonesian workers.
During the annual work plan and budget review, SKK Migas
evaluates training programmes, salary and benefit costs,
and plans for localising expatriate positions. Contractors
must submit annual manpower or organisational charts for
both national and expatriate workers (RPTK and RPTKA)
for SKK Migas' approval. SKK Migas controls the salaries
and benefits which can be paid and the costs which can
be recovered through salary caps. In an effort to offset
any inequity in salary caps, PSC operators may offer
employee benefits such as housing loan assistance, car loan
assistance, and long-service allowances etc., which are cost
recoverable if approved by SKK Migas.
PSC operators, under the guidance of SKK Migas, must offer
a pension for employee retirement, or severance payments
for general terminations (referred to as the Tabel Besar or
Big Table). A Big Table scheme is a form of defined benefit
whereby an employee is given a certain number of months’
pay based on their years of service.
Accordingly, some PSC operators have established defined
contribution pension plans, managed by a separate trust,
under which the PSC operator and the employee contribute
a percentage of an employee’s salary. Pension contributions
are charged as recoverable costs. Some PSC operators also
purchase annuity contracts from insurance companies.
Pension contribution accruals cannot be cost-recovered until
they are fully funded (i.e. paid).
Some PSC operators have opted to manage their pension
plans by funding them using bank time deposits, with the
interest earned reinvested and used to reduce the future
funding. All pension schemes require PSC operators to
prepare an actuarial assessment of the fair value of the
assets and the future pension liabilities, whether fully funded
or unfunded. Historically, any unfunded liability is maintained
off balance sheet for PSC basis Financial Reporting.
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4.1.16 Jurisdiction and reporting
JCCs are subject to Indonesian law. Contractors are obligated to report discoveries and the
results of the certification of oil and/or gas reserves to the MoEMR/SKK Migas. Contractors
are required to perform their activities in line with good industry and engineering practices,
which include complying with the relevant provisions on occupational health and safety and
environmental protection, and using EOR technology, as appropriate.
4.1.17 Dispute mechanism-arbitration
SKK Migas has established a special dispute resolution mechanism, PTK 051, for PSC cost
recovery disputes. This mechanism guides SKK Migas and Contractors in deferring cost
recovery based on audit findings, Financial Quarterly Report (FQR) analysis, Authorisation
for Expenditure (AFE) audits, and questioned expenditures.
Prior to the deferral of cost recovery, discussions shall be held with successive tiers of
management of SKK Migas and the Contractor for a period of six months from the issuance
of an audit report. Any deferred cost recovery shall be settled within 90 working days
through a maximum of three discussions. In the event that discussions fail, the Contractor
may exercise its rights in accordance with the PSC.
Photo source: PwC
64 PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 65
4.2 Production Sharing Contracts (PSCs)
4.2.1 General overview and commercial terms
Production Sharing Contracts (PSCs) are the predominant agreements used in Indonesia's
upstream sector. In a conventional PSC, the Government and the Contractor agree to split
production revenue based on predetermined percentages. Operating costs are recovered
from production through Contractor Cost oil formulas defined in the PSC. Additionally, the
Contractor has the right to separately dispose of its share of oil and gas, with ownership
passing at the point of export or delivery.
Regulation-08 introduces a PSC scheme based upon the sharing of a “Gross Production
Split” without a cost recovery mechanism, later amended by MoEMR Regulation No.
52/2017, MoEMR Regulation No. 20/2019 and MoEMR Regulation No. 12/2020 (refer to
Chapter 5 for more detail).
Generations of conventional PSCs
PSCs have evolved through five “generations”, with the main variations between them
relating to the production sharing split. The second and third generation PSCs issued after
1976 removed the earlier cost recovery cap of 40% of revenue, and confirmed an after-tax
oil equity split of 85/15 for SKK Migas and the Contractor, respectively. The third generation
of the late 1980s introduced First Tranche Petroleum (FTP) and offered incentives for
frontier, marginal and deep-sea areas. In 1994, to stimulate investment in remote and
frontier areas (the Eastern Provinces), the Government introduced a 65/35 after-tax split on
oil for contracts in that region (fourth generation). In 2008, a fifth generation of PSCs with
a cost recovery mechanism was introduced. While the after-tax equity split is negotiable,
the latest model limits the spending available for cost recovery (via a “negative list”
regulated under GR-79 as amended by GR-27) and offers incentives in other areas such
as via investment credits. More details on cost recoverable items and the negative list are
provided in Chapter 4.2.2.
Key differences between the later and earlier generations are as follow:
a. Rather than a fixed after-tax share, recent PSCs have introduced some flexibility
regarding the production sharing percentage offered;
b. PSCs now prescribe a DMO for natural gas;
c. SKK Migas and the Contractor are both entitled to FTP of 20% of the Petroleum
production;
d. The profit sharing percentages in the contracts assume that the Contractor is subject to
tax on after-tax profits at 20% (i.e. not reduced by any tax treaty);
e. Certain pre-signing costs (e.g. for seismic purchases) may be cost recoverable
(although this is less clear for recent PSCs);
f. MoEMR and/or SKK Migas must approve any changes to the direct or indirect control
of the PSC entity; and
g. The transfer of the PSC’s participating interest to non-affiliates is only allowable:
• With the MoEMR and/or SKK Migas’ approval; and
• Where the Contractor has retained a majority interest and operatorship for three
years after signing.
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Relinquishments
The PSC sets out the requirements for areas
to be relinquished during the exploration
period. Specific details are set out in the
contract, but the parties must consult
with SKK Migas, and the areas must be
large enough to enable others to conduct
petroleum operations.
Commercial terms
The general concept of a PSC is that the Contractor bears all the risks and costs of
exploration. If production does not proceed, these costs are not recoverable, but if production
does proceed then the Contractors can claim a share of production to meet cost recovery, an
investment credit (where granted) and an after-tax equity interest in the remaining production.
The terms of a PSC include that:
a. The Contractor is entitled to recover all allowable current costs (including production
costs), as well as amortised exploration and capital costs;
b. The recovery of exploration costs is limited to production arising from the contracted
“field” with an approved PoD – effectively quarantining cost recovery to the initial and
then subsequent “fields” (earlier generation PSCs did not “ring fence” by PoD and/or
by field);
c. The Contractor is required to pay a range of bonuses including a signing, education
(historically) and production bonus. The production bonus may be determined on a
cumulative basis. These bonuses are not cost-recoverable or tax deductible;
d. The Contractor agrees to a work programme with a minimum exploration expenditure
over a certain number of years;
e. All equipment, machinery, inventory, materials and supplies purchased by the
Contractor becomes the property of the State once landed in Indonesia. The
Contractor has a right to use and retain custody during operations. The Contractor has
access to exploration, exploitation and G&G data, but the data remains the property of
the MoEMR;
f. Each Contractor shares its production, less deductions for the recovery of the
Contractor’s approved operating costs. Each Contractor must file and meet its tax
obligations separately;
g. The Contractor bears all the risks of exploration;
h. Historically, each Contractor was subject to FTP of 15% (for fields in Eastern Indonesia
and some in Western Indonesia pursuant to the 1993 incentive package) or 20% (for
other fields). This was calculated before any investment credit or cost recovery. Recent
contracts provide for the sharing of FTP of 20%;
i. The Contractor is required to supply a share of crude oil production to satisfy a DMO.
The quantity and price of the DMO oil is stipulated in the agreement. Recent contracts
require a gas DMO;
j. After commercial production, the Contractor may be entitled to recover an investment
credit historically ranging from 17% to 55% of costs (negotiated as part of the PoD
approval) incurred in developing crude oil production facilities; and
k. The Contractor is required to relinquish portions of the contract area based on a
schedule specified in the PSC.
Pre-PSC costs
The recipient of a PSC will typically incur
expenditure before the PSC is signed. This
pre-PSC expenditure cannot be transferred
to the PSC, and so will generally become
non-recoverable.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 67
Cost recovery principles
Basic cost-recovery principles include allowing the following items:
a. Current-year capital (being the current-year depreciation charges) and non-capital
costs;
b. Prior years’ unrecovered capital and non-capital costs;
c. Inventory costs;
d. Head office overheads charged to operations; and
e. Insurance premiums and receipts from insurance claims.
Over time, several principles and regulations have been developed by entities like SKK
Migas/BP Migas/Pertamina and the Indonesian Tax Office (ITO). For instance, PSC
Contractors typically receive an after-tax equity share of 15% from oil production. However,
this share is subject to meeting the Domestic Market Obligation (DMO), leading to a
reduced return for Contractors. Additionally, Field Development Plans (FTPs) allow the
Government to claim a share of production before full cost recovery by Contractors.
Since 1995, PSCs have mandated that Contractors are responsible for site restoration,
including clearing, cleaning, and restoring sites upon completion of work. Funds allocated
for abandonment and site restoration are recoverable once spent or funded, with unused
funds retained in a joint account, and are not refundable to the Contractor.
In 2017, the MoEMR issued Regulation No. 26/2017 (as later amended by MoEMR
Regulation No. 47/2017, No. 24/2018, and No. 46/2018) stipulating the mechanism for
PSC Contractors to recover (unrecovered) “Investment Costs” upon the expiration of the
PSC. Investment costs are referred to as capital expenditure incurred over the PSC term
by PSC Contractors with the objective of maintaining an equitable level of production for a
maximum of five years before PSC expiration, subject to SKK Migas approval.
In summary, MoEMR Regulation 26 stipulates that; for (conventional) PSC, an unrecovered
investment costs can be carried forward to the extended (conventional) PSC.
PSC accounting principles
The PSC outlines the accounting principles to be applied by the Contractor. Under relevant
clauses of the PSC, operating, non-capital and capital costs are defined, together with the
related accounting method to be used for such costs. This differs from Generally Accepted
Accounting Principles (GAAP) and Indonesian Financial Accounting Standards (IFAS). Most
companies, however, do not prepare financial statements compliant with IFAS, and instead
prepare PSC statements adjusted at the head office level to comply with GAAP. SKK
Migas issued PTK 059 as general guidance on PSC accounting. However, detailed PSC
accounting must make reference to the specific PSC agreement.
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Photo source: PwC
4.2.2 Equity share - oil
Investment credits
An investment credit is available on direct
development and production capital costs, as
negotiated and approved by SKK Migas.
In recognition of the delayed generation of
income inherent in the exploration process, a
credit ranging from 17% to 55% of the capital
costs of development, transport and production
facilities has historically been available. Second-
generation PSCs allowed a rate of up to 20% for
fields that commenced commercial operations
after 1976.
The investment credit must be taken in oil or gas
in the first year of production, but can generally
be carried forward.
Under earlier PSCs, investment credits were
capped where the share of total production
taken by the Government did not exceed 49%.
This condition was eliminated in later-generation
PSCs.
Under GR-79/27, the Minister has the authority
to determine investment incentive credits. The
criteria for such credits are not however specified
in GR-79/27.
Cost oil
The expenses which are generally allowable for
cost recovery include:
a. Current year operating costs from a field or
fields with PoD approval, intangible drilling
costs on exploratory and development
wells, and the costs of inventory when
landed in Indonesia (as distinct from when
used – although this has changed in recent
PSCs). The Contractor can also recover
head office overheads (typically capped at
a maximum of 2% of current year costs)
provided the cost methodology is applied
consistently, is disclosed in quarterly reports
and is approved by SKK Migas (see further
guidance below under Management and
Head Office Overheads);
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 69
b. Depreciation of capital costs calculated
at the beginning of the year during
which the asset is Placed Into Service
(PIS) (although for recent PSCs only
monthly depreciation is allowed in the
initial year). The permitted depreciation
methods are either the declining
balance or double declining balance
method, based on the individual asset
amount, multiplied by depreciating
factors as stated in the PSC. Generally
the factor depends on the useful life of
the asset, such as 50% for trucks and
construction equipment, and 25% for
production facilities and drilling and
production equipment. Title to capital
goods passes to the Government upon
landing in Indonesia, but the Contractor
can claim depreciation; and
c. Unrecouped operating and depreciation
costs from previous years. If production
is not sufficient to recoup costs, these
may be carried forward to subsequent
years with no time limit.
In December 2010, GR-79 increased the
number of non-CR items to 24. However,
the list of non-items CR was then revised
under GR-27 to 22 items effective from 19
June 2017. The list of non-CR items under
GR-27 is as follows:
a. Costs charged or incurred for personal
and/or family members, management,
participating interest holders and
shareholders;
b. Establishment or accumulation of a
reserve fund, except costs for field
closure and restoration deposited in
the joint account of SKK Migas and the
Contractor in an Indonesian bank;
c. Granted assets;
d. Administrative sanctions such as
interest, fines, and surcharges, as well
as criminal sanctions in the form of
penalties related to the tax law and
implementing regulations, as well
as claims or fines resulting from the
Contractor’s actions;
e. Depreciation of assets which do not
belong to the Government;
f. Incentives, payments of pension
contributions and insurance premiums
for foreign manpower, management
and shareholders and/or their family
members;
g. Expatriate manpower costs which do
not comply with the procedures of the
RPTKA or Expatriate Manpower Permits
(IMTA - Izin Mempekerjakan Tenaga
Asing);
h. Legal consultant’s costs which have no
direct relation to oil operations in the
context of PSC;
i. Tax consultant’s fees;
j. Marketing costs of oil and/or gas of
the Contractor’s entitlement except
marketing costs for gas as approved by
SKK Migas;
k. Representation costs, including
entertainment costs in any name and
form, except if accompanied by a
nominative list and the relevant tax ID
number (NPWP - Nomor Pokok Wajib
Pajak);
l. Training costs for expatriate manpower;
m. Merger and acquisition costs or
Participating Interest costs;
n. Interest expenses on loans;
o. Employee Income Tax (EIT) borne by
the Contractor, except when paid as a
tax allowance, or third party EIT which
is borne by the Contractor or grossed
up;
p. Procurement costs which are not in
accordance with the arm’s length
principle and costs exceeding the
approved AFE by more than 10%,
except for certain costs which are
specifically regulated by the MoEMR;
q. Surplus materials purchased due to
poor planning;
r. Costs incurred due to the negligent
operation of Place Into Service (PIS)
facilities;
s. Transactions which are written off,
contrary to the terms of the tender
process or against the law;
t. Bonuses paid to the Government;
u. Costs incurred prior to the signing of
the relevant cooperation contract; and
v. Commercial audit costs.
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Sharing of production oil
Crude production in excess of the amounts received for FTP, cost recovery and investment
credits is allocated to the Government and the Contractor before tax (but adjusted by the
DMO supply obligations).
Since a PSC involves the sharing of output, the production to be shared between the
Government and Contractor is made up of:
a. Cost oil;
b. Any investment credit; and
c. Equity oil.
Management and head office overheads
The Contractor has exclusive authority to conduct oil and gas operations in its work area,
and is responsible to SKK Migas for the conduct of those operations. In practice, SKK
Migas exercises considerable control through its approval of the Contractor’s annual work
programs, budgets and manpower plans.
Some general and administrative costs (other than direct charges) related to head office
overheads can be allocated to the PSC operation based on a methodology approved by
SKK Migas. A Parent Company Overhead (PCO) Allocation Cap ((PMK – Peraturan Menteri
Keuangan) 256 dated 28 December 2011) was introduced in 2011, and seeks to
govern the cost recoverability and tax deductibility of overhead costs. PMK-256 stipulates
a general cap for PCO allocations of 2% p.a. of annual spending for cost recovery and
tax deductibility purposes. However, the amount that a PSC can actually recover will be
dependent upon approval from SKK Migas, and may be lower than 2%. The overhead
allocation methodology must be applied consistently, and is subject to periodic audit by
SKK Migas. For producing PSCs, SKK Migas will often travel abroad to audit head office
costs. Please refer to Chapter 4.5 for further discussion.
GS PSCs have a slightly different approach regarding the charging of direct and indirect
head office expenditure to PSC operations. See further discussion in Chapter 5.
FTP
Under pre-2002 contracts, Contractors and the Government were both entitled to claim
FTP, and received petroleum equal to 20% of the production before any deduction for
operating costs. The FTP was then split according to their respective equity shares as
stated in the contracts.
Under later PSCs, the Government was entitled to take the entire FTP (although at a lower
rate of 10%) without sharing with the Contractor.
For recent PSCs, the FTP of 20% is once again shared with the Contractor.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 71
Equity share – oil
Any oil that remains after investment credit and cost recovery is split between SKK
Migas and the Contractor. Second and third generation PSCs involve an oil split of
85/15 (65/35 for frontier regions) for SKK Migas and the Contractor respectively. This is
an after-tax allocation, being what the Contractor is entitled to lift after paying taxation
at the grandfathered rates (i.e. the tax rates in effect when the PSC was signed). This is
summarised as follows:
Table 4.2 - Summary of after tax oil splits
Post 2002 PSC
(%)
1995 Eastern
Province PSC
(%)
1995 PSC
(%)
1985 - 1994
PSC
(%)
Pre-1984
PSC
(%)
Tax rate 42.4/40/37.6* 44 44 48 56
Share of production after tax:
Government Varies 65 85 85 85
Contractor Varies 35 15 15 15
Contractor’s share of
production before tax:
Varies
35/(100-44) 62.50
15/(100-44) 26.79
15/(100-48) 28.85
15/(100-56) 34.09
* The general combined Corporate and Dividend (C&D) tax rate fell to 42.4% in 2009, 40% in 2010 and 37.6% in 2020.
Sources: GR-79/2010 as amended by GR-27/2017, Pre-1984 PSC, 1985 - 1994 PSC, 1995 PSC, 1995 Eastern Province
PSC, 2002 - 2023 PSC.
DMO
According to the PSC, after the commencement of commercial production the Contractor
should fulfil its obligation to supply the domestic market. The DMO (for oil) is calculated at
the lesser of:
a. 25% of the Contractor’s standard pre-tax share or its participating interest share of
crude oil; or
b. The Contractor’s standard share of crude oil (either 62.50%, 26.79%, 28.85% or
34.09% - as described in the table above) multiplied by the total crude oil to be
supplied and divided by the entire Indonesian production of crude oil from all petroleum
companies for the PSC area.
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In general, a Contractor is required to supply a maximum of 25% of the total oil production
to the domestic market out of its equity share of production. The oil DMO is to be satisfied
using equity oil, exclusive of FTP.
It is possible for the oil DMO to absorb the Contractor’s entire share of equity oil. If there is
not enough production to satisfy the oil DMO, there is no carry-forward of any shortfall.
Generally, for the first five years after commencing commercial production, SKK Migas pays
the Contractor the full ICP value for its oil DMO. This is reduced to 10% or 25% of that
price for subsequent years (depending upon the generation of PSC). The price used is the
Weighted Average Price (WAP).
Historically there was no DMO obligation associated with gas production. However, under
GR-35 and recent PSCs, a DMO on gas production has been introduced.
In July 2021, the MoEMR issued regulation No.18/2021 prioritising the use of crude oil for
domestic needs. The issuance of this regulation was in line with the Government’s broader
policy objective of reducing crude oil imports.
In summary, MoEMR Regulation No. 18/2021 requires Pertamina to prioritise the
procurement of crude oil from domestic sources over importing. In this regard, PSC
contractors are obliged to offer or include Pertamina in tenders for their portion of crude
oil before exporting, pursuant to business-to-business negotiations (presumably meaning
that the crude need not be sold at below “market” value). It is also stipulated that the
negotiations must be conducted within 20 days.
The tax implications of MoEMR Regulation No. 18/2021 include that crude sales at market
price could lead to a gain or loss for PSC Contractors based on any variation between the
negotiated price (with Pertamina) and the ICP. Any gains generated could be subject to the
prevailing Income Tax rates (including Branch Profits Tax (BPT) - if applicable).
Valuation of oil
For the purpose of calculating a share of production, and for tax purposes, oil is valued
using a price reference known as the ICP. Under a PSC, the Contractor receives oil or
in-kind products in settlement of its costs and its share of equity. This makes it necessary
to determine a price to convert oil into USD in order to calculate cost recovery, taxes and
other fiscal items such as under/over lifting. The ICP is determined monthly by the MoEMR
based on the average daily prices of international indices from the preceding month.
The monthly tax calculations are based on the ICP and on actual Contractor lifting. The
actual year-end annual PSC Contractor entitlement (cost plus equity barrels) is based on
the average ICP for the year. The average ICP during the respective year is known as the
WAP.
73
Photo source: bp Indonesia
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide
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4.2.3 Equity share – gas
Sharing of production - gas
The provisions for the sharing of gas production are similar to those for oil except for the
equity splits and DMO. When a PSC produces both oil and gas the relevant production
costs will be allocated against each according to the proportion of production in value
terms in the year or some other means of allocation as approved by SKK Migas. The costs
of each category that are not recouped can either be carried forward to the following year
or taken against the production of the other category in the same year only.
The main difference between oil and gas production relates to the equity split. The majority
of PSCs are based on an 85/15 after-tax split for oil. For gas, the after-tax split is usually
70/30 for the Government and the Contractor respectively although some older PSCs are
based on an after-tax split of 65/35. After the 1995 incentive package, Eastern Province gas
Contractors use an after-tax split of 60/40.
These provisions result in the following entitlements:
Table 4.3 - Summary of after tax gas splits
Post 2002 PSC (%)
1995 Eastern
Province PSC
(%)
1995 PSC
(%)
1985 - 1994
PSC (%)
Pre-1984
PSC
(%)
Tax rate 40/37.6* 44 44 48 56
Share of production
after tax:
Government Varies 60 70 70 70
Contractor Varies 40 30 30 30
Contractor’s share of
production before tax:
Varies
40/(100-44) 71.43
30/(100-44) 53.57
30/(100-48) 57.69
30/(100-56) 68.18
* The general combined C&D tax rate fell to 42.4% in 2009, 40% in 2010 and 37.6% in 2020.
Sources: GR-79/2010 as amended by GR-27/2017, Pre-1984 PSC, 1985 - 1994 PSC, 1995 PSC, 1995, Eastern Province
PSC, 2002 - 2023 PSC.
If the natural gas production does not permit full recovery of natural gas costs, the excess
costs shall be recovered from crude oil production in the contract area. Likewise, if excess
crude oil costs (crude oil costs less crude oil revenues) exist, this excess can be recovered
from natural gas production.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 75
Illustrative calculation of entitlements
An illustration of how the share between the Government and Contractors is calculated is
presented in the tables below.
Table 4.4
Illustrative calculation of entitlement for old PSC
Assumptions:
Contractor’s share before tax = 34.0909%
Government’s share before tax = 65.9091%
WAP per barrel = USD 60
C&D tax = 56%
Description Formula used
Year to
date
bbls USD
Lifting:
- SKK Migas USD [a1] = bbls x WAP 2,500 150,000
- Contractors USD [a2] = bbls x WAP 4,500 270,000
Total lifting [A] 7,000 420,000
Less : FTP (20%) [B] = 20% x [A] 1,400 84,000
Total lifting after FTP [C] = [A] - [B] 5,600 336,000
Less :
- Cost recovery
Cost in bbls = cost in USD :
WAP
4,000 240,000
- Investment credit
Cost in bbls = cost in USD :
WAP
100 6,000
Total cost recovery [D] 4,100 246,000
Equity to be split [E] = [C] - [D] 1,500 90,000
SKK Migas’ share :
- SKK Migas’ share of FTP 65.9091% x [B] 923 55,380
- SKK Migas’ share of equity 65.9091% x [E] 989 59,340
- DMO 25% x 34.0909% x [A] 596 35,760
SKK Migas’ entitlement [F] 2,508 150,480
Over/(under) SKK Migas’ lifting[G] = [a1] - [F] (8) (480)
Contractor’s share :
- Contractor’s share of FTP 34.0909% x [B] 477 28,620
- Contractor’s share of equity34.0909% x [E] 511 30,660
Less :
- DMO 25% x 34.0909% x [A] (596) (35,760)
Add :
- Cost recovery 4,000 240,000
- Investment credit 100 6,000
Contractor’s entitlement [H] 4,492 269,520
Over/(under) Contractors’ lifting [I] = [a2] - [H] 8 480
Note: SKK Migas on behalf of the Government
76PwC
Illustrative calculation of C&D taxes for Contractor’s entitlement in old PSC
Description USD
Contractor’s share :
- Contractor’s share of FTP 28,620
- Contractor’s share of equity 30,660
- Cost recovery 240,000
- Investment credit 6,000
Less : DMO (35,760)
269,520
Less : Lifting price variance (26,949)**
Contractor’s net entitlement: 242,571
Less : Cost recovery (240,000)
Add : Actual price received from
DMO
22,908*
Contractor’s taxable income 25,479
Less : 56%
- Corporate tax (45%) 11,465
Combined effective
tax rate :
- Dividend tax (11%) 2,803
= C&D tax/
Contractor’s taxable
income
C&D tax (56%) 14,268 = 14,268/25,479
= 56%
Contractor’s net income 11,211
* DMO comprised of two items : Quantity in barrels USD Price of DMO
- Old oil (40% of total DMO in
barrels)
238 1,42810% From WAP
- New oil (60% of total DMO in
barrels)
358 21,480WAP
Actual price received from DMO 596 22,908
** Calculation of lifting price
variance :
USD
Entitlement by using WAP 269,520
Entitlement by using ICP 242,571
Lifting price variance 26,949
@ The entitlement is calculated by using the monthly ICP during the respective year
Table 4.5
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 77
Illustrative presentation of old PSC in SKK Migas FQR format
Description USD
Gross revenue/lifting 420,000
Less : FTP (20%) 84,000
Gross revenue/lifting after FTP 336,000
Cost recovery :
- Cost recovery 240,000
- Investment credit 6,000
Total cost recovery 246,000
Equity to be split 90,000
SKK Migas’ share :
- SKK Migas’ share on FTP 55,380
- SKK Migas’ share on equity 59,340
- Lifting price variance 26,949
- Government tax entitlement 14,268
Add: DMO 35,760
Less: Domestic market adjustment (22,908)
Total SKK Migas’ share 168,789
Contractor's share :
- Contractor’s share on FTP 28,620
- Contractor’s share on equity 30,660
- Lifting price variance (26,949)
Less: DMO (35,760)
Add: Domestic market adjustment 22,908
Less: Government tax entitlement (14,268)
Add: Total recoverables 246,000
Total Contractor's share
251,211
78PwC
Domestic gas pricing
Gas pricing in domestic supply contracts
is determined through negotiations on a
field-by-field basis between SKK Migas,
buyers and individual producers, based
on the economics of a particular gas field
development. Historically, all domestic gas
had to be supplied to Pertamina under a
gas supply agreement. Pertamina in turn
then sold the gas to the end-user. Prices
were fixed for a designated level of supply
for the duration of the contract.
Under Law No. 22, individual producers can
sell directly to end users based on contract
terms and conditions negotiated directly
between the producer and the buyer (with
assistance from SKK Migas). However, there
continues to be Government involvement in
steering contracts towards certain domestic
buyers, rather than producers’ preference to
export due to more favourable pricing and
terms.
Take-or-pay arrangements have been
negotiated in some circumstances.
Although this concept has long been
accepted, the policy regarding its treatment
from a tax, accounting (revenue recognition)
and reporting perspective varies in practice.
PSC Contractors and potential investors
should also consider the credit risk inherent
in any domestic gas sales arrangements
when negotiating contract terms and
conditions and how they might protect
themselves.
MoEMR issued Regulation No. 15/2022
and Regulation No. 10/2020 stipulating
a maximum gas price of USD6/MMBTU
at the plant gate for gas buyers in
certain industries. Industries covered by
Regulation No. 8/2020 include the fertiliser,
petrochemical, oleochemical, steel, ceramic,
glass and rubber glove industries, and
this was expanded under Regulation No.
10/2020 to the power generation sector
(including PT PLN (Persero) as gas buyer).
The MoEMR will determine the necessary
adjustments to the gas purchase price
from the gas producer and/or to the related
distribution costs, including liquefaction,
compression, pipeline transmission and
distribution, and transportation based on
recommendations from SKK Migas or the
Special Oil & Gas Regulatory Body of Aceh
(BPMA - Badan Pengelola Migas Aceh) and
the supervisory body for gas distribution.
Further, Regulations No. 15/2022 and
No. 10/2020 clarify that the adjustments
to the gas price will not affect the gas
producer’s entitlement to proceeds based
on existing gas purchase agreements with
gas buyers. Instead, these adjustments
will be accounted for as a reductions in the
Government entitlement when performing
the current year equity split calculation.
Detailed provisions regarding the calculation
of the entitlement to gas price adjustments
will be further regulated through technical
guidance from SKK Migas or BPMA.
Over/(under) lifting
Lifting variances will occur each year
between the Contractor and the
Government. These under-/over-lifting
amounts are settled with the Government
in cash or from production and can be
considered as sales/purchases of oil or gas
respectively. The individual members of the
PSC may in turn have under-/over-
lifting balances between themselves, which
will be settled according to joint venture
agreements, but generally in cash or from
production in the following year.
Under MoF Regulation No. 118/
PMK/02/2019 as lastly amended with MoF
Regulation No. 51/2023 any under-lifting
position between the Contractor and the
Government should be settled in cash
within 17 days (subject to the time taken
for the examination and processing of the
request) after the Directorate General of
Budget (DGB) verifies the request from SKK
Migas. There is no specified period for the
settlement of any over-lifting position. In
practice though, the amount is most often
settled when the year-end FQR is finalised
in March of the subsequent year.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 79
Integrated LNG supply projects
Indonesia currently has three operating LNG facilities, namely PT Badak LNG, BP Tangguh
LNG, and PT Donggi Senoro LNG.
Historically, Indonesia has utilised a traditional integrated LNG seller/buyer supply chain
structure. The LNG supply chain is generally structured as follows:
Natural Gas
Producers
Regastification plants
located in Taiwan,
Japan, and Korea
Owned and operated
by a Buyers Consortium
Sales proceeds paid to
trustee by buyers
consortium
Net LNG proceeds
remitted to Producers
reffered to as netback
to field proceeds
TPAA pays any debt
service costs associated
with plant constructions
and shipping /
liquefaction costs
LNG net back to field proceeds
distributed and taxed as
prescribed under PSC Contract
to PSC Contractors and
Government of Indonesia
(GoI)/Pertamina/BP Migas
Gas distribution
network state
controlled-gas and
utility companies
Trustee Paying
Agent Agreement
(TPAA)
Natural Gas
Producers
The Producers
are the PSC
Contractors and
GoI/Pertamina/
BP Migas
Gas Supply
Aggreement
between Producers
and Government
A locally incorporated
company involving
Producers and Buyers
operated on a cost
reimbursement or
not-for-profit basis
Long-term Charther
arrangements
administered by
Producers on CIF
or FOB terms
15 - 20 years, take-or-
pay terms and prices
linked to crude/fuel
oil with a floor price
Gas
Liquefaction
Plant
Ship Charter
Agreements
Long-term
LNG Sales Contrast
between Pertamina/
BP Migas and Buyers
For Bontang, PT Badak NGL was established as a continuation of the upstream operations
of several PSCs to process gas into LNG on a not-for-profit basis. A number of sales
contracts were initially entered into under fixed long-term supply arrangements and at
minimum prices in order to reduce the risk for the Producers. The initial contracts carried
Cost, Insurance, Freight (CIF) terms. From the late 1980s the shipping arrangements were
changed to allow buyers and/or others to participate in long-term shipping charters on a
Free on Board (FOB) basis.
The Bontang and Tangguh LNG projects were effectively project-financed with an implied
Government guarantee which enabled lower financing costs. A trustee-paying agent
arrangement was also established to service this debt and the related O&M costs. These
processing and financing costs are first netted off against LNG proceeds with the net
proceeds then released back to the PSC entitlement calculation (i.e. under the so-called
“net back to field” approach). The Tangguh LNG facility uses a similar concept to Bontang,
and is operated by BP Tangguh on behalf of the gas producers, but without a separate gas
processing entity.
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Non-integrated LNG projects
Non-integrated projects involve the legal/investor separation of gas extraction and LNG
production assets. Issues under this model focus on the gas offtake price to be struck
between the PSC Contractors and LNG investors. Under a non-integrated LNG model the
investors in the LNG plant separately require a designated rate of return on their investment
in order to service project finance etc. (i.e. unlike the “net back to field” approach outlined
above for integrated projects which effectively allows financiers to benefit from the value of
the entire LNG project).
The non-integrated LNG structure is relatively new to Indonesia, and as such it is difficult
to assess the Indonesian tax implications. Withholding Tax (WHT), VAT, tax rate differentials
(and associated transfer pricing) and PE issues need to be considered. In addition, any
offshore project company would need to consider its tax treaty entitlements.
An example of a non-integrated project is the Donggi Senoro LNG plant in Sulawesi. The
Donggi Senoro LNG plant is owned by Medco, Mitsubishi Corporation, Kogas and
Pertamina, but Mitsubishi does not have a participating interest in the two PSCs that supply
gas to the LNG plant.
4.2.4 Other PSC conditions and considerations
The procurement of goods and services
Procurement of goods and services by oil and gas Contractors is regulated so as to give
preference to Indonesian suppliers. For purchases in excess of certain values, specific
procedures must be complied with, including the calling of tenders and approval by SKK
Migas.
Guidance No.PTK-007/SKKIA0000/2023/S9 (PTK-007) on the Management Framework for
the Supply Chain for Cooperation Contracts (Pedoman Tata Kerja Pengelolaan Rantai Suplai
Kontraktor Kontrak Kerja Sama) is the current referred guidance on procurement of goods
and services.
In general, all purchases are done by either tender or direct appointment (with certain
requirements) and only vendors with Oil and Gas Support Business Capability Certificate
(SKUP - Surat Kemampuan Usaha Penunjang Migas) and (SPDA - Sertifikat Pengganti
Dokumen Administrasi) are considered qualified and able to bid. A PSC Contractor can
procure goods and services by itself but require SKK Migas approval at the preparation
of procurement list and planning stage if the package is worth over IDR50 billion or USD5
million.
Changes in the scope or terms of a contract which can increase the contract value must be
approved by SKK Migas, as follows:
a. For contracts where the appointment of the supplier was carried out through approval by
SKK Migas and where the overruns exceed 10% of the initial contract or above IDR200
billion or USD20 million; and
b. For contracts where the appointment of the supplier was made by the Contractors and
where the cumulative amount of the initial contract plus overruns exceeds IDR200 billion
or USD20 million.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 81
All equipment purchased by PSC Contractors is considered the property of the Government
from the time when it enters Indonesia. Oil and gas equipment may enter duty free if used
for operational purposes (please see further discussion in Chapter 4.4.8 below). Imported
equipment used by service companies on a permanent basis is assessed for Import Duty
unless this is waived by the BKPM. Import duties on oil and gas equipment ranges from
0% to 29%. The position for temporary imports of subcontractor equipment is covered in
Chapter 4.4.8.
Inventory
Under the PSC, spare parts inventory is separated into capital and non-capital. Non-capital
inventory is charged to cost recovery immediately upon purchase or landing in Indonesia.
A counter-entry account is usually maintained to track the physical movements and use of
non-capital inventory. For later generation PSCs, however, inventory is charged based on
usage.
Under SKK Migas guidelines, any excess or obsolete inventory must be circulated to other
PSCs and receive SKK Migas approval before any amounts (capital inventory) can be
charged to cost recovery. Under PTK 007, any dead stock and surplus materials above 8%
of non-capital inventory is not recoverable.
If inventory is transferred or sold to another PSC the selling price must be at carrying cost.
Generally, the sale of inventory is not subject to VAT. If a PSC Contractor cannot dispose
of the inventory a write-off proposal (WOP) must be submitted to SKK Migas for approval.
Once approved, the inventory is usually charged to cost recovery (if not yet charged) and
transferred to a SKK Migas warehouse or facility, or held by the Contractor on behalf of
SKK Migas.
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide81
82PwC
PP&E
Under the PSC framework, PP&E, including
land rights, purchased or acquired in
Indonesia, become the property of the
Government. However, the Contractor
retains the right to use these assets until
approved for abandonment by SKK Migas.
The NBV of such property, as reflected in
the PSC financial statements, represents
expenditure by the Contractor which has
not yet been cost recovered. Intangible
drilling costs of unsuccessful exploratory
wells are charged to operating expenses as
they are incurred. If commercial reserves
are determined in the contract area
and the exploratory wells subsequently
become productive, the associated costs
are capitalised. Additionally, the tangible
costs of successful development wells are
capitalised.
Depreciation is calculated from the time
when the asset is PIS. Earlier generation
PSCs allow a full year’s depreciation during
the initial year, whereas later generation
PSCs require a month-by-month approach
so that an asset PIS in December is only
allowed one month’s depreciation during
the initial year. Under PTK 033, PIS approval
is required prior to the commencement
of depreciation. PIS approval should be
submitted together with the AFE Close-out
Report in order for the final depreciable
project cost to be agreed. Exhibit C to
the PSC describes the category method,
and useful life for the purposes of PSC
depreciation.
Site restoration and abandonment
provision
PSC Contractors that signed contracts
after 1995 must include in their budgets
provisions for clearing, cleaning and
restoring sites upon the completion of work.
For PSCs signed from 2008 onwards any
cash funds set aside in a non-refundable
joint account for abandonment and site
restoration are cost-recoverable. Any
unused funds will be transferred to SKK
Migas. According to PTK 040, cash funds
must be placed into a State-Owned
Bank under a joint account between SKK
Migas and the PSC Contractor. The PSC
Contractor shall be liable if the funds are
not sufficient to cover the costs of site
restoration and abandonment.
It has been suggested that any
abandonment and site restoration costs
and liabilities related to PSCs signed before
1995 remain SKK Migas’s responsibility.
However, consistent with PSCs signed since
1995, SKK Migas may at some point require
the Contractor to contribute to the cost of
restoration and abandonment activities.
Based on MoEMR Regulation No. 15/2018
regarding the post-operation of oil and
gas upstream activities, Contractors are
obligated to conduct post-operation
activities using post-operation activity
funds and to submit a post-operation
activity plan to SKK Migas. Contractors are
also obligated to reserve post-operation
activity funds, which must be deposited
in a joint bank account of SKK Migas and
the Contractors, in accordance with the
estimated post-operation activity costs
(referred to as the “Abandonment and Site
Restoration” or “ASR” fund).
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 83
4.3 Upstream accounting
The table below shows some of the key standards relating to upstream oil and gas
companies under PSC accounting, GAAP in the United States (US GAAP) and IFRS.
Table 4.6
Accounting in Upstream Oil and Gas Business
Key standards reference and comparison between PSC accounting and US GAAP and IFRS
Area PSC US GAAP IFRS*
Depreciation of capital
costs
Accelerated depreciation
with a full year’s
depreciation in the year
of acquisition
Units of
production
Method not specifically
determined: to be allocated on
a systematic basis over useful
life, reflecting the consumption
of assets' benefits
Non-capital/controllable
stores
Expensed upon
receipt (except for later
generation PSCs which
are charged to cost
recovery as they are
consumed).
Expensed as
consumed
Expensed as consumed
Obsolete stores or idle
facilities
Written-off only when
approved by SKK Migas
Expensed/
impaired when
identified
Expensed/impaired when
identified
Deferred taxes Not provided
Accounting
Standard
Codification
(ASC) 740
International Accounting
Standards (IAS) 12 treatment
Contingent liabilities
Recognised when
settled or approved by
SKK Migas
ASC 450 IAS 37 treatment
Severance and retirement
benefits
Recognised when paid
or funded
ASC 715 IAS 19 (Revised) treatment
Decommissioning and
restoration obligation
Recorded and recovered
on a cash basis, if
specifically provided for
in the PSC
ASC 410
treatment
Provision to be provided under
IAS 37 treatment
PSC licence acquisition
costs
Expensed (generally not
cost recoverable)
Capitalised
Capitalised as long as meeting
IFRS asset recognition criteria
Exploration and evaluation
- dry holes
Expensed Expensed Expensed
Exploratory wells-
successful:
Tangible costs
Intangible costs
Capitalised
Expensed
Capitalised
Capitalised
Not specifically addressed;
Capitalised as long as meeting
IFRS asset recognition criteria
Development - dry holes Expensed Capitalised
Not specifically addressed;
capitalised as long as meeting
IFRS asset recognition criteria
under IAS 38 or IAS 16
84PwC
Accounting in Upstream Oil and Gas Business
Key standards reference and comparison between PSC accounting and US GAAP and IFRS
Area PSC US GAAP IFRS*
Development wells-
successful:
Tangible costs
Intangible costs
Capitalised
Expensed**
Capitalised
Capitalised
Not specifically addressed;
capitalised as long as meeting
IFRS asset recognition criteria
Support equipment and
facilities
Capitalised Capitalised Capitalised
* Currently, IFAS do not significantly differ from IFRS, except for the effective date of the application of new standards as they
are issued.
** New PSCs signed from 2011 capitalise intangible costs
4.3.1 Statement of Financial Accounting Standards (SFAS) 66/IFRS
11 – joint arrangements
Oil and gas companies often use joint arrangements to spread risks, share costs, or bring
specialised skills to projects. These arrangements can take various legal forms, such as
formal joint-venture contracts or governance arrangements outlined in company formation
documents. What distinguishes joint arrangements is the presence of joint control.
Unanimous consent is generally required for financial and operating decisions in order for
joint control to exist. An arrangement without joint control is not a joint arrangement.
Under SFAS 66/IFRS 11, for unincorporated JOs, participants must account for their
interest in a JO as a share of assets, liabilities, revenue and costs. A joint venture
participant uses the equity method to account for its investment in a joint venture.
In Indonesia's oil and gas industry, upstream joint working arrangements typically take
the form of joint arrangements. While some companies establish JOs through separate
vehicles, such instances are rare and generally fall under SFAS 66/IFRS 11. Midstream and
downstream joint-working arrangements usually involve separate vehicles and incorporated
entities.
Photo source: PwC
84 PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 85
4.4 Taxation and customs
This section sets out the industry-specific aspects of Indonesian taxation and customs
law for (conventional) upstream Contractors, and includes an analysis of some common
industry issues. Taxation obligations common to ordinary taxpayers are not addressed,
however (please see our annual PwC Pocket Tax Guide for discussion of this area).
Issues around the taxation of GS PSCs are outlined in Chapter 5.
4.4.1 Historical perspective
“Net of tax” to Gross of tax
The modern regulatory era dealing with the framework of oil and gas activities in Indonesia
began with the passage of the Oil and Gas Mining Law No. 44/1960 on 26 October 1960.
Pursuant to Law No. 44, the right to mine Indonesian oil and gas resources was vested
entirely in Indonesian SOEs. Law No. 44 did, however, allow for SOEs to appoint other
parties as Contractors.
Pertamina, established as a State Enterprise through GR No. 27 of 1968 and Law No.
8/1971, gained authority over appointing private enterprises, including overseas entities,
as Contractors under oil and gas mining arrangements. This marked the start of PSC and
similar contractual setups.
From the early 1960s until the late 1970s, PSC entities were entitled to take their share of
production on a “net of tax” basis (i.e. with the payment of Indonesian Income Tax made on
their behalf by the State/Pertamina).
In the late 1970s, this changed to a "gross of tax" basis to comply with US foreign tax
credit rules. Consequently, PSC entities became responsible for calculating taxable income
and paying Income Tax directly. Despite this shift, there was an expectation that PSC
entities would maintain a "net of tax" entitlement.
Uniformity principle
As the change from a “net of tax” to a “gross of tax” basis was not meant to disturb the
“desired” production sharing entitlements (i.e. the after-tax take), it became necessary to
adopt the so-called “uniformity principle” in relation to the calculation of taxable income.
This principle, as outlined in MoF Letter No.S-443A of 6 May 1982, provides that the
treatment of income and expenditure items for cost recovery and tax deductibility purposes
should be identical (with limited exceptions such as for signing/production bonuses). This
long-standing principle has now been recognised (at least partially) in GR-27 which requires
that there be a general “uniform treatment” between cost recovery and tax deductibility.
Uniformity therefore meant that the calculation of Income Tax for PSC entities differs to the
calculation applying to other Indonesian taxpayers. Significant differences include:
a. That the taxable value of oil “liftings” is to be referenced to a specific formula (currently
ICP) as opposed to an actual sales amount (gas “liftings” generally reference the Gas
Sales Agreement Contract price);
b. That the classifications for intangible and capital costs are not necessarily consistent
with the general Income Tax rules relating to capital spending;
86PwC
c. That the depreciation/amortisation rates applying to these intangible and capital costs
are not necessarily consistent with the depreciation rates available under the general
Income Tax rules;
d. That there is a general denial of deductions for interest costs (except where specially
approved) whereas interest is usually deductible under the general Income Tax rules
as long as within a 4:1 debt equity ratio to the five year restriction under the general
Income Tax rules;
e. That there is an unlimited carry forward of prior year unrecovered costs; and
f. That no tax deductions will arise until there is commercial production as opposed to a
deduction arising from the date of the spending being expensed or accrued under the
general Income Tax rules.
4.4.2 GR-79, as amended by GR-27 and GR-93 (GR-79/27/93)
GR-79 was the first dedicated regulation dealing with both the cost recovery and tax
arrangements for this important industry. Notwithstanding the issuance of a number
of implementing regulations for GR-79, many issues remain unclear. The table below
summarises the issues which remain unclear, as well as the status of the respective
regulations etc.
Table 4.7
Article Unclear Area Regulation Pending
Guidance
Pending
Article 3, Article 5,
Article 12
Definition of the principle of
effectiveness, efficiency and
fairness, as well as good
business and engineering
practices
Article 7 Ring fencing by field or well
Article 8
Minimum Government Share
of a Work Area
Yes, per Article 8(2) -
from the Minister
Article 10 FTP amount and share
Investment incentives (form/
extent)
Article 12
Limitations on indirect
charges from Head Office
See our comments on
head office costs
Article 13
Negative lists - transactions
procured without a tender
process or cause a loss to
the state
Article 14
Income from by-products
(sulphur/electricity)
Article 17
The use of reserve funds
for abandonment and site
restoration
Yes, per Article 17(4)
Article 18
Severance for permanent
employees paid to the
undertaker of employee
severance funds
Yes, per Article 18(2)
- procedures for the
administration of
employee severance
Yes, per Article 18(1)
Minister to determine
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 87
Article Unclear Area Regulation Pending
Guidance
Pending
Article 19 (See also
Article 7)
Deferment of cost recovery
until a field is produced -
Ring fencing by field
Policy with regard to
the PoD to secure State
Revenue
Yes, per Article 19(2) –
Minister to determine
policy
Article 22
Procedures to determine the
methodology and formula
for Indonesia’s crude oil
price
Yes, per Article 22(2)
Article 24
DMO fee for delivery of
crude oil and gas
Issued as MoF Reg. No.
137/2013
Yes, per Article 24(9),
to be determined by
Minister
Article 25
Tax assessment for foreign
tax credit purposes
Issued as DGT
Regulation No.29/
PJ/2011 on Income Tax
Payments
Article 26
Maximum amount of
deductions and fee/
compensation paid by the
Government
Yes, per Article 26(2)
from Minister.
Article 27
Guidance on the procedures
for payment of income taxes
on PSC transfer and uplift
income
Issued as PMK-257 in
2011 (see below)
Article 31
Form and contents of
annual income tax return
Issued as DGT
regulation (PER-
Peraturan Dirjen
Pajak)-05/2014 (see
below)
Article 32
Tax ID registration for PSC
(so called “Joint Operation”
tax ID number)
Yes, per Article 32(1)
Article 33
Procedures to calculate and
deliver government share
in the event of tax payment
in kind
Yes, per Article 33(3)
PMK-70/2015 (see
below)
Article 34
Standard and norms of
costs utilised in petroleum
operations
Yes, per Article 34(2)
Article 36
Independent third party
appointment to perform
financial and technical
verification
Article 38
Transitional rules and
adjustment to the GR
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Effective date
GR-79 stipulates that:
a. It is effective from its date of signing.
This means that GR-79 operates from
20 December 2010 (but see below);
b. It applies fully to JCCs, consisting of
PSCs and Service Contracts, signed
after 20 December 2010; and
c. JCCs signed before 20 December 2010
continue to follow the rules relevant
to these JCCs until expiration. This is
except for areas on which pre-GR-79
JCCs are silent or which are not clearly
regulated. In these cases, Contractors
should adopt the “transitional” areas
covered in GR-79 within three months
– a provision which has caused
considerable unrest to many holders
of pre-GR-79 PSCs. This is primarily
because the transitional provisions (at
Article 38b) apply in respect of eight
significant areas as follows:
i) Government share;
ii) Requirements for cost recovery and
the norms for claiming operating
costs;
iii) Non-allowable costs;
iv) The appointment of independent
third parties to carry out financial
and technical verifications;
v) The issuance of an Income Tax
assessments;
vi) The exemption of Import Duty and
Import Tax on the importation
of goods used for exploitation and
exploration activities;
vii) The Contractor’s Income Tax
in the form of oil and gas from the
Contractor’s share; and
viii) Income from outside of the JCC
in the form of uplifts and/or the
transfer of JCC/PSC interests.
Whilst the exact scope remains unclear,
some holders of pre-GR-79 PSCs have
been concerned that the transitional
rules could result in the largely retroactive
operation of GR-79. This was particularly
noting that there is uncertainty as to how
to determine what areas were “not yet
regulated or not yet clearly regulated”.
Photo source: PwC
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Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 89
Amendment of GR-79 (i.e. GR-27 and
GR-93)
GR-27
On 19 June 2017, the President signed
GR-27, which amended GR-79. The main
changes were as follow:
a) Article 10 in regard to State Revenue
including Government Share and FTP
This Article was amended to allow
for a range of upstream “incentives”
including:
i) A DMO holiday (albeit with no time
limit specified);
ii) A range of tax incentives, where
these are in accordance with the
prevailing tax laws; and
iii) A range of non-tax State revenue
incentives, which may include the
use of State-owned assets for
upstream activities.
The elucidation indicates that this
amendment targets the incentives
embedded in historical PSCs such as
investment credits and DMO holidays.
This will not extend to general tax
concessions.
These amendments also included a
new Article 10(a) to allow for a “sliding
scale” equity split to be determined by
the MoEMR. It is unclear at this stage
how this scale will interface with the
splits shown in the PSCs themselves
(although see discussion on Article 38
below).
b) Article 11 regarding to recoverable
costs
This Article has been amended to
positively confirm the recoverability of
LNG processing costs.
c) Article 13 regarding non-recoverable
costs
This Article has been amended to
remove a number of items from the list
of non-CR spending being:
i) Tax allowances related to EIT
(which appears to be EIT where
remitted on a grossed up basis);
ii) Interest formally approved for cost
recovery; and
iii) CD during an exploitation phase.
As a result, spending on these items
should now be cost recoverable,
at least to the extent that this is in
accordance with the requirements of
the relevant PSC;
d) Article 16 in regard to depreciation
This Article has been amended to allow
for the residual value of assets that are
“no longer able to be used” to be cost
recovered outright. Under the previous
arrangements, and Exhibit C of most
PSCs, this spending would continue to
be depreciable based upon the original
useful life of the asset.
e) Article 25 dealing with the Income
Tax calculation
This Article has been amended to
include:
i) A new Article 25(7a) which requires
that Assessments arising from a
tax audit are to be issued within
12 months of the receipt of a
“complete” tax return (previously
there was no formal timeline except
in the case of a tax refund).
The intent/impact is not clear,
particularly noting the joint-audit
framework with the Financial and
Development Supervision Agency
(BPKP - Badan Pengawasan
Keuangan dan Pembangunan) and
SKK Migas. It is possible, however,
that this amendment will mean less
of a role for the DGT in its Income
Tax related audits; and
ii) New Articles 25(12) and (13), which
provide that Income Tax on FTP is
to be due when the “accumulated”
FTP exceeds the relevant cost
recovery balance.
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This amendment is not entirely clear,
but could mean that FTP is to be
accumulated as non-taxable income
until the exhaustion of all unrecovered
costs (and thus an equity oil position) at
which point the entire accumulated FTP
becomes taxable.
f) Article 26 dealing with Tax Facilities
This Article has been amended to
include new Articles 26(A) to (E) to
provide specific tax facilities, as follow:
i) “duty/import tax exemption” in
relation to physical imports by
PSCs during both the exploration
and exploitation phases;
ii) Reductions in Land and Building
Tax (PBB - Pajak Bumi dan
Bangunan) of 100% (during the
exploration phase) and up to 100%
(during the exploitation phase);
Note that MoF approval is required
for these import-related and PBB
incentives during exploitation (the
incentives during the exploration
phase appear to be automatic);
iii) Income arising from charges from
the shared use of assets by PSCs
is to be exempt from WHT and
VAT. Interestingly, the amendment
does not formally provide that the
income itself is otherwise exempt;
and
iv) “Indirect head office allocations”
do not constitute Income Tax
“objects” or VAT-able “supplies”.
This appears to be a formalisation
of the long established principle set
out under MoF letter S-604 issued
in 1998, which has been challenged
by the DGT in recent years.
The consequence of this amendment is
presumably to render cost allocations
exempt from WHT and VAT. There
is however no elaboration on the
meaning of a “head office” and so it is
unclear how widely this incentive can
be extended to affiliate charges from
overseas.
g) Article 27 dealing with Uplifts and
Participating Interest transfers
This Article has been amended to
include:
i) A new Article 27(1a) which provides
that taxable income arising from
uplifts, after being reduced by Final
Income Tax, is non-taxable; and
ii) A new Article 27(2a) which provides
that taxable income arising from
PSC transfers, after being reduced
by Final Income Tax, is non-
taxable.
In these cases, the consequence of the
after-tax income becoming non-taxable
is presumably that no further tax should
apply to the after tax income. This
should therefore now formally exclude
the levying of BPT on the after-tax
income from PSC transfers, presumably
in both direct and indirect transfer
scenarios.
It should also be noted that the BPT
on PSC transfers was introduced via
PMK-257, and so was arguably never
part of the original GR-79 architecture.
It is anticipated that a complementary
amendment to PMK-257 may be issued
to ensure complete clarity on this
matter. Timing of issuance is however
unclear.
h) Article 31(2) dealing with PSC
Transfer Reporting
This Article has been amended to
require that the value of a PSC transfer
be reported to both the DGOG of the
MoEMR, and the DGT. Previously GR-
79 reporting only took place to the DGT.
i) Article 37 and 38 dealing with
Transitional Provisions
The transitional provisions provide that:
i) For PSCs signed before GR-79 but
post Law No. 22/2001: the relevant
PSC holders should elect to either:
• Continue to follow the provisions
of the relevant PSC (i.e. exclusive
of any GR-27 adjustments); or
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 91
• “Adjust” their PSC to comply
with GR-27 (although with no
guidance on the adjustments
mechanism). This election is to
be made within six months of
the issuance of GR-27 (i.e. by
mid December 2017 – which has
obviously already passed, and
with no guidance on the selection
mechanism);
ii) For PSCs signed post GR-79 but
prior to GR-27 issuance, the
outcome appears to be similar to i),
although presumably with any
election to "opt-out" of GR-27 still
leaving the PSC holder subject
to the rules under the PSC as
impacted by GR-79 (although this
is not clear).
The most likely interpretation of these
transitional provisions is that GR-27
operates to “immediately” amend GR-79
on all matters outlined in GR-27. However,
GR-27 will still not apply to the extent that
GR-27 is inconsistent with the provisions
of the relevant PSC. These inconsistencies
can then be overcome only by the PSC
Contractor agreeing to amend the PSC so
as to render the PSC entirely consistent with
GR-27.
Whilst the range of PSC–specific matters
requiring PSC amendments is debatable, it
may not extend to the BPT due on a PSC
transfer, as the taxation of PSC transfers is
not typically prescribed in PSCs. As a result,
BPT on PSC transfers appears to have been
removed effective from June 2017,
irrespective of the position taken on any
GR-27 related election (although this should
be confirmed as part of any transaction
advice).
The package of amendments under GR-27
should, on balance, be viewed positively
by the industry, and particularly for newer
PSCs. However, all PSC holders will
need to carefully weigh up the economic
implications before making an election to
opt-in to GR-27.
GR-93
On 31 August 2021, the Government
of Indonesia issued GR No. 9 (GR-9),
which provides updated guidance on the
Income Tax treatment on transfers of PSC
participating interests (PIs) in both direct
and indirect transfers. GR-93 came into
effect on the same date (i.e. 31 August
2021) and revoked several articles in GR-
79/27 and GR-53. Other provisions of GR-
79/27 and GR-53 remain operational.
Key highlights are as follows:
• GR-93 covers transfers of PSCs falling
under either the cost recovery or GS
framework;
• GR-93 provides some clarity on a
number of long-standing issues,
especially on the “tracing rules” in the
case of transfers via share sales (i.e.
“indirect” transfers); and
• GR-93 also provides clarity on certain
transactions that are exempt from PSC
transfer tax (particularly in indirect
transfers);
Please refer to the PSC transfer section
below for more details.
Photo source: PwC
91Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide
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State revenue and payment of tax
The Income Tax payments of a PSC entity were historically counted by the Government as
oil revenue rather than as an Income Tax receipt. The Income Tax was also remitted to the
DGB as opposed to the ITO.
On 31 March 2015, the Minister of Finance issued PMK-70 amending the previous
PMK-79/2012, as a further implementing regulation of GR-79. PMK-70 outlines updated
procedures for remitting and reporting “State Revenue” arising from PSC activities. The
following high level points are noted:
a. PMK-70 was issued in response to the dissolution of BP Migas (replaced by SKK
Migas) and amends the terminology in the previous PMK-79/2012 accordingly;
b. Similar to PMK-79/2012, most of the terms in PMK-70 are consistent with GR-79;
c. State Revenue is formally defined as Government Share and the Corporate and BPT
(i.e. the so-called Corporate and Dividend (C&D) Tax);
d. Final lifting is to be calculated at year end with procedures on how to settle over/ under
liftings to be separately regulated;
e. Income Tax for PSC Contractors to consist of the monthly and annual C&D Tax; and
f. If requested, the C&D Tax must be paid “in-kind” based on the ICP (for oil) or the WAP
(for gas) of the month when the tax is due. The possibility of tax being paid in-kind
is not altogether new although the PMK is the first guidance on a calculation/value
mechanism.
With the introduction of PMK-70 Income Tax payments of PSC Contracts are therefore
generally now on an equal footing with general taxpayers. Under GR-79, a facility also now
exists for a Tax “Assessment” letter evidencing the payment of Income Tax. Prior to this the
DGT issued a Temporary Statement.
C&D Tax payment procedures are as follows:
a. For cash payments:
i) The tax payments are to be remitted into the (general) State Treasury account
rather than into the Oil & Gas accounts (i.e. the MoF account #600.000411980
at the BI). The payment/remittance is still in USD and the transfer shall be made
via a “Foreign Exchange” Designated Bank (i.e. Bank Persepsi Mata Uang Asing);
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Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 93
ii) A tax payment slip is to be completed. DGT Regulation No.25/PJ/2011 provides
different tax payment codes for Petroleum Income Tax, Natural Gas Income Tax
and BPT; and
iii) The monthly and annual C&D Tax payment deadlines are the 15th of the following
month and the end of the 4th month following year end. Tax will be considered
paid when the funds are received into the State Treasury account (i.e. the tax-
payment slip SSP (Surat Setoran Pajak) will be marked with NTPN (Nomor
Transaksi Penerimaan Negara) and NTB (Nomor Transaksi Bank).
b. For in-kind payments:
i) The payment deadlines are the same as for cash payments;
ii) Contractors and SKK Migas will record the in-kind payments in a “minutes of in-
kind handover” (berita acara serah terima) to be signed by both parties; and
iii) The SSP shall be completed based on the minutes of in-kind handover including
the hand-over date. PMK-70 provides two attachments – Template for the Minutes
of Handover and Attachment II – SSP specifically for (in-kind) C&D Tax.
c. Where C&D Tax is overpaid, the overpayment should be settled in accordance with
the prevailing tax laws meaning that tax refunds could be subject to a tax audit (the
historical practice has been that PSC entities simply offset overpayments against future
C&D Tax instalments). The instructions in PER-05 for completing the Annual Corporate
Income Tax Return (CITR) do not result in the disclosure of under or over payments in
the main CITR form;
d. The C&D Tax reporting procedures include the following requirements:
i) Operators must prepare monthly and annual State Revenue Reports using the
template provided in PMK-70 and submit to the DGT (generally the Oil & Gas
Tax Office), the DGB (specifically the Directorate of Non-Tax State Revenue in
this case), and SKK Migas. PMK-70 is silent on the reporting obligations during
exploration (i.e. where no State Revenue obligation should exist); and
ii) The reports should include the relevant SSP and payment evidence. This will be
the transfer evidence (for cash payments) or the minutes of in-kind handover (for
in-kind payments).
e. Any late payment or reporting is subject to administrative sanctions under prevailing
tax laws. The reports also require the declaration of Government Share and (as outlined
above) extend the reporting obligations to the DGB, the DGT and SKK Migas.
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide93
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Cost recovery/tax deductions
GR-79/27 requires that there be a “uniform treatment” between cost recovery and tax
deductibility. This is pivotal as it appears to formally enshrine the long-standing “uniformity
principle”. To satisfy uniformity the amount should still:
a. Be spent on income producing activities;
b. Satisfy the arm’s length principle (for related party transactions);
c. Be consistent with good business and engineering practices; and
d. Be approved by SKK Migas and be included in the relevant WP&B.
GR-79/27 also outlines two items of spending that are not allowed for cost recovery. For
this list please refer Chapter 4.4.2 above.
Indirect taxes
Indirect taxes, regional taxes and regional levies are stated as cost recoverable. Indirect
taxes include VAT, Import Duty, PBB, regional taxes and regional levies. These PBB and
regional taxes/levies have generally been exempt (or at least reimbursable) in the past.
Import Duty and other import taxes (such as VAT and Article 22 Income Tax) related to
exploration and exploitation activities are also generally exempt (see below).
PBB for Post GR-79-PSCs
On 12 April 2013, the MoF issued Regulation No.76/PMK.03/2013 (PMK-76) on PBB for the
oil and gas sector, replacing Regulation No. 15/PMK.03/2012 (PMK-15). The effective date
of PMK-76 was 12 May 2013. PMK-76 has led to a major change in the PBB regulatory
framework for PSCs. PMK-76 has gone through several amendments, most recently by
MoF Regulation No. 234/PMK.03/2022 (PMK-234).
General PBB regime
Pursuant to Article 5 of PBB Law No. 12/1994 (Law 12) the PBB tax rate is 0.5% of a
“deemed” tax base. The “deemed” tax base ranges from 20% up to 100% of the “object
value” (being a statutory value called Tax Object Selling Value (NJOP - Nilai Jual Objek
Pajak)). The taxable event is the tax base of land and buildings “held” as at 1 January
each year. PBB should be paid within six months of the receipt of an Official Tax Payable
Notification (SPPT - Surat Pemberitahuan Pajak Terutang). Whilst an SPPT is not an
assessment, it is still a legal notice from the Tax Office against which taxpayers can object.
PBB and PSCs
Article 11(4)(f) of GR-79 indicates that indirect taxes (including PBB) should be cost
recoverable. Post GR-79 PSCs accommodate this by requiring indirect taxes to be
cost recovered (in earlier PSCs the Government bears all taxes except Income Tax).
On 1 February 2012, the MoF issued PMK-15 updating the PBB procedures (including
overbooking) applicable to the PSC sector. The key features were:
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 95
a. That PMK-15 was effective on 1
February 2012 and cancelled all
previous regulations relating to the PBB
compliance for PSCs;
b. That the Tax Office should issue the
SPPT by the end of April of each fiscal
year;
c. That the PBB due should be settled
through an overbooking made by the
DGB from the oil and gas revenue
account into the Tax Office/DGT
account (i.e. PBB is not paid by the
PSC Contractor); and
d. That the taxable base value will be
covered by further regulations.
On 12 April 2013 the MoF replaced PMK-
15 with PMK-76. PMK-76 specifically
references GR-79 and changes the PBB
treatment as follows:
a. For pre GR-79 PSCs the overbooking
process continues to apply; and
b. For post GR-79 PSCs the overbooking
does not apply and the PSCs are
required to self-remit the PBB and claim
as cost recovery.
With the automatic overbooking entitlement
for post-GR-79 PSCs withdrawn, the DGT
began directly to “assess” post-GR-79
PSCs.
On 30 September 2013, the DGT issued
SE-46 to provide further clarification on
the completion of the Notification of PBB
Objects (SPOP - Surat Pemberitahuan
Objek Pajak) for the “offshore” components
of these objects. Perhaps the most
significant aspect of SE-46 was to clarify
that the NJOP should only extend to areas
“utilised” by the PSC interest holder.
Whilst the term “utilisation” was not defined,
the intent appeared to be to reduce PBB
exposure for these PSCs going forward.
This outcome left post-GR-79 PSCs
exposed to PBB liabilities.
On 10 December 2019, the MoF issued
PMK-186, which became effective on 1
January 2020, and introduced the following
changes:
a. An updated classification of “Tax
Objects”; and
b. New procedures to determine the Sales
Value of these NJOP.
PMK-186 applies to PBB Objects in, among
others, the oil and gas sector and other
sectors which are:
a. Located within Indonesian waters; and
b. Not PBB Objects of a Village or Town.
PBB objects
For “Other Sectors”, the definition of “land”
has now been clarified to include Indonesian
waters used for storage and processing
facilities, and thereby extends to the various
categories of vessels used on these waters.
The definition of “buildings” has now
also been clarified to include technical
constructions planted or attached
permanently on “land” within Indonesian
waters. This includes pipelines, and storage
and processing facilities such as Floating
Storage Offload (FSO), Floating Production
System (FPS), Floating Production Unit
(FPU), Floating Storage Unit (FSU), Floating
Production Storage and Offload (FPSO), and
Floating Storage Regasification Unit (FSRU).
Please refer to our comments in Chapter 7
(Service Providers to the Upstream Sector)
for more details on the development of PBB
issues pertaining to FSRU/FPSO/FSO, etc.
Further, this clarification confirms the recent
DGT position during tax audits that PBB
should now cover these assets.
NJOP calculation
PMK-186 sets out the procedures to
calculate the NJOP for assets falling into the
above sectors. For land, the NJOP varies
according to the characteristics of use
(e.g. productive, not yet productive, non-
productive, onshore/offshore etc.). This is
obviously relevant for oil and gas.
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Bookkeeping and tax registration
A PSC entity is automatically entitled
to maintain its books, and calculate its
Income Tax liability, in English and using
USD. However, a PSC entity should still
file a notification (three months before the
relevant accounting period) with the Tax
Office.
Transactions denominated in currencies
others than USD are to be converted into
USD using the exchange rate as the date of
the transactions.
VAT and WHT continue to be calculated
in Rupiah irrespective of any USD
bookkeeping notification.
GR-79/27 does not affect the bookkeeping
requirements as set out above. However,
GR-79/27 also indicates that:
a. Contractors shall carry out their
transactions in Indonesia and settle
payment through the banking system in
Indonesia; and
b. Transactions and the settlement of
payments (referred to in paragraph
a) can only be conducted outside of
Indonesia if approval from the MoF is
obtained.
A Contractor is required to register for its
own tax ID number. Registration of the JCC
itself should be carried out by the operator
of the particular JCC. This development
is similar to that applying to existing JOB
arrangements.
Operators are responsible for transactional
taxes (including WHT and VAT) meaning
that the transactional taxes should continue
to be reported under the Operator’s tax ID
number.
For buildings, the NJOP for all sectors is
based on the “New Acquisition Price”. This
is defined as all costs incurred to acquire
the Tax Object at the time of assessment,
less depreciation based on the physical
condition of the Tax Object.
PBB reduction for post-GR-79 PSCs
On 31 December 2014, and in response
to the above, the MoF issued Regulation
No.267/2014 (PMK-267) which provided tax
incentives for exploration PSCs in the form
of a PBB reduction.
The reduction was granted on the sub-
surface component, and can amount
to up to 100% of the PBB due on that
component. This incentive is applicable
from 2015 onwards where the Contractor
fulfils the following requirements:
a. Its PSC was signed after 20 December
2010 (i.e. the effective date of GR-79);
b. A SPOP (notification of PBB objects)
has been submitted to the DGT; and
c. A recommendation letter has been
provided by the MoEMR which
stipulates that the PBB object is still at
the exploration stage.
The reduction is granted annually for a
maximum of six years from the PSC signing
date and can be extended by up to four
years (subject to a recommendation letter
from the MoEMR).
On 27 August 2019, the MoF issued
Regulation No. 122/PMK.03/2019 (PMK-
122) which provides incentives including a
PBB reduction of up to 100% (effectively
a PBB exemption). These incentives apply
during both the exploration and exploitation
periods, although their application during
the exploitation period is subject to an
approval from the MoF after reviewing the
project’s economics.
From an administrative perspective,
the incentive requires a “confirmation
letter for the tax facilities” for both the
exploration and exploitation phases. Such a
confirmation letter should be issued by the
Head of the Regional Tax Office (RTO).
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 97
PSC transfers
GR-79/27 provides that transfers of PSC/
JCC interests will be taxed as follows:
a. During the exploration stage, a final
tax of 5% of the gross proceeds will
be levied. However, the transfer will be
exempted if it was undertaken for “risk
sharing purposes” and the following
criteria are met:
i) Less than the entire PSC interest is
transferred;
ii) The PSC interest has been held for
more than three years;
iii) Exploration activities have been
conducted; and
iv) The transfer is not intended to
generate a gain.
b. During the exploitation stage, a 7% final
tax on gross proceeds is due except for
any transfer to a “national company” as
stipulated in the JCC (i.e. Indonesian
participation).
GR-79 via PMK-257 introduced the imposition
of BPT on PSC transfers (either direct or
indirect). This imposition of BPT appears,
however, to have been removed under GR-27
starting in June 2017 (see above).
As briefly mentioned above, GR-93, which
was issued on 31 August 2021, provides
some further clarity on the long-standing
issues pertaining to the PSC transfer tax:
a. GR-93 now looks to define a PSC
interest as “immovable property”.
This “immovable property” concept
is more consistent with international
tax law suggesting (perhaps) greater
recognition of the applicability of tax
treaty protections for indirect transfers.
However, the definition goes beyond
most treaties to include shares in the
entities which hold the immovable
property;
b. Notwithstanding a), GR-93 more clearly
distinguishes between “direct” and
“indirect” transfer scenarios. Note in
particular the new annual remittance
mechanism for indirect transfers, i.e. on
the 10th of the following month of the
end of fiscal year (e.g. for a fiscal year
ending 31 December, the remittance
takes place on 10 January);
c. In terms of indirect transfers, GR-93
makes it clear that the Transfer Tax can
apply on an “unlimited” tracing basis
(including multi-tier share ownership)
and so goes beyond the “in substance”
indirect transfer guidelines that currently
exist. However, there is no specific relief
on “day-to-day” share trading, leaving
the scope of taxation via on-market
share trading activity unclear;
d. GR-93 now provides that the transfer
consideration in indirect-transfer
scenarios will be set as a percentage
of the transferred ownership (%)
multiplied by the fair market value
(FMV) of the Indonesian PSC assets.
There is, however, no guidance on how
to determine the FMV in this case.
Perhaps most surprisingly, this FMV
default appears to apply even to arm’s-
length transfers;
e. GR-93 provides a number of new
Transfer Tax exemptions, as follow:
i. For transfers taking place pursuant
to approved “book-value” business
restructuring transactions (e.g.
mergers, spinoffs, takeovers, etc).
This suggests that PSC transfers
falling within the recently issued
Minister of Finance Decision
No.56/2021 covering SOE business
restructuring transactions are now
protected;
ii. For transfers taking place pursuant
to any other “restructuring”
provided that the restructuring is:
a) Not “profit-oriented”; and
b) Does not lead to a change in
the ultimate “parent entity”
This exemption appears to
be available for multinational
corporations (MNCs). However,
requirements that the MNCs must
also satisfy, include the filing of
various approvals and financial
statements;
98PwC
iii. For transfers made as part of
“local transactions”, such as share
sales between Indonesian entities
subject to 0.1% final tax, where
any Income Tax outcome otherwise
falls within the “ordinary” tax rules
f. GR-93 indicates that a new MoF
Decision will be issued and provide
further guidance in a number of areas.
Therefore, until this occurs, PMK- 257
will remain in force to the extent that it
is consistent with GR-93.
Overall, the issuance of GR-93 provides
some clarity around the areas of
contention regarding indirect transfers,
but arguably still without the level of
precision that this area warrants. GR-93
however now provides some “welcome”
exemptions, especially for local oil and
gas investors.
Head office costs
Head Office costs are recoverable subject
to:
a. The cost-supporting activities taking
place in Indonesia;
b. The Contractor provides audited
financial statements of the head office
and an outline of the method of cost
allocation this (as approved by SKK
Migas); and
c. The head office allocation does not
exceed a ceiling determined by MoF
Regulation No.256/PMK.011/2011
being a maximum of 2% of spending
(subject to approval from SKK Migas)
being cumulative spending during
exploration and annual spending
thereafter.
Post-lifting costs
Certain post lifting costs, including for
transporting natural gas (such as marketing
costs approved by SKK Migas) and
other post upstream activities may be
recoverable.
Tax calculation, payment and audit
For JCCs signed after GR-79, the Income
Tax rate could be either the rate which
prevailed at the time of signing, or the rate
that prevails from time to time (i.e. may be
subject to changes based on the changes
in the Tax Law). This appears to breathe life
into the Income Tax rate “election” which is
included in Law No. 22 (see below).
For JCCs signed before GR-79, the Income
Tax rate is that which prevailed when the
JCC was signed. This grandfathering
is consistent with the retention of the
uniformity principle.
If the Income Tax payment is reduced,
including via a change in the domicile
of the Head Office (for example due
to a favourable tax treaty) the after tax
“government share” shall be adjusted to
ensure the pre-treaty split. This enshrines
the recent trend in PSCs to counter tax
treaty use.
Income Tax payments are subject to tax
audit by the DGT. The DGT will issue any
assessments after carrying out an audit.
Contractors should be prepared for the
tight deadlines that apply in a tax audit
context and any associated tax dispute
proceedings. This includes a 30-day time
limit for producing documents, especially
those that might be held at the Head Office.
Apart from providing documents on time,
there are also obligations to provide (written)
responses to DGT enquiries on time.
Expatriate costs
Expatriate costs are recoverable but should
not exceed a ceiling determined by the MoF
(in coordination with the MoEMR). MoF
Regulation No.258/PMK.011/2011 (PMK-
258) provides details on the applicable
cap which is dependent on the role and
region that the expatriate comes from as
per the table below. Remuneration is not
well defined but seems to cover short-term
compensation only.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 99
Table 4.8
Position
classification
Rates for expatriates who hold a passport from
Remarks
Asia, Africa, and
Middle East
Europe, Australia,
and South America
North America
(USD) (USD) (USD)
Highest Executive 562,200 1,054,150 1,546,100
1
st
Ranking
position in
Contractor of
Oil and Gas
Cooperation
Contract
(President, Country
Head, General
Manager)
Executive 449,700 843,200 1,236,700
2
nd
Ranking
position in
Contractor of
Oil and Gas
Cooperation
Contract (Senior
Vice President,
Vice President)
Managerial 359,700 674,450 989,200
3
rd
Ranking
position in
Contractor of
Oil and Gas
Cooperation
Contract (Senior
Manager, Manager)
Professional 287,800 539,450 791,200
4
th
Ranking
position in
Contractor of
Oil and Gas
Cooperation
Contract
(Specialist)
Although the cap applies for cost recovery and tax deductibility purposes, the Article 21/26
EIT withholding obligation is subject to the prevailing income tax law meaning the Article
21/26 WHT is based on the actual payment.
100PwC
4.4.3 Income tax rates
Various eras
The introduction of the uniformity principle (and its maintenance in GR-79/27) necessitated
that the Income Tax rate should be “grandfathered” to the rate applying at the time that the
PSC (or extension) was entered into. This is because the production sharing entitlements
set out in the PSC are grossed-up to accommodate the Income Tax rate applying at the
time. These rates then need to apply for the whole life of the PSC.
MoF Decree No.267 of 1 January 1978, and MoF Decree No.458 of 21 May 1984, provide
“loose” implementing guidelines on the levying of Income Tax against PSC entities. Decrees
No.267 and No.458 discuss taxable income in terms of a share of oil and gas production
(or lifting). Deductions are discussed in terms of associated exploration, development and
production costs.
For entities holding an interest in a PSC signed before 1984, the applicable Income Tax
rate should be 45%. This rate was reduced to 35% in 1984, and then to 30% in 1995 up to
2008. Further reductions occurred to 28% in 2009, and to 25% starting in 2010 based on
the new Income Tax Law No. 36/2008, effective from 1 January 2009.
The general assumption in the early years of PSC licensing was that PSC entities would be
foreign incorporated. On this basis, the after tax profits of a PSC entity were subject to a
further BPT. This tax was due at the rate of 20% giving rise to a total Income Tax exposure
of (say) 56% for pre-1984 PSCs (i.e. 45% plus (55% x 20%)). In the relevant PSC this was
shown as a (gross of tax) production share of 0.3409 for oil (i.e. 15%/1-.56%) and 0.6818
for gas (i.e. 30%/1- .56%).
To maintain a consistent after-tax take, adjustments to the gross-of-tax share have been
made over the years in response to changes in Indonesia’s general Income Tax rate.
Additionally, in certain PSC bidding rounds, the net-of-tax Contractor take has increased to
(up to) 25% for oil and 40% for gas, resulting in variations in the gross production-sharing
rates. These calculations can be summarised as follows:
Table 4.9 - Historical income tax rates and the after tax split calculation
PSC Era
Income
Tax -
General
Income
Tax –
Branch
Profits
Combined
Tax Rate
Prod.
Share (Oil)
After Tax
Production
Share (Gas)
After Tax
Pre-1984 45% 20% 56% 0.3409 15% 0.6818 30%
1984-1994 35% 20% 48% 0.2885 15% 0.5769 30%
1995-2007 30% 20% 44% 0.2679 15% 0.5357 30%
2008 30% 20% 44% 0.4464 25% 0.7143 40%
2009 28% 20% 42.4% 0.6250 36% 0.7140 41.142%
2010 25% 20% 40% 0.6000 36% 0.6850 41.143%
2013-2016* 25% 20% 40% 0.5830 35% 0.6670 40%
*GS PSCs from 1 January 2017
Sources: Pre-1984 PSC, 1984 - 1994 PS, 1995 - 2007 PSC, 2008 PSC, 2009 PSC, 2010 PSC, 2013 - 2016
PSC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 101
BPT – treaty use
The BPT rate can be reduced by a tax treaty. However, with the exception of a small
number of treaties (most notably those with the Netherlands, the United Kingdom (UK),
Malaysia, and Singapore – although there are others) the BPT reduction in a tax treaty does
not apply to PSC activities.
A decrease in the BPT rate might translate into a higher after-tax production share for a
PSC entity. Consequently, Indonesian government authorities pertinent to the matter have
historically contested a PSC entity's right to avail itself of treaty benefits. This contention
led to the termination of the Netherlands’ treaty in the late 1990s, although subsequent
negotiations have taken place. Similarly, there were discussions about canceling other
treaties, including the one with the UK. In 1999, the MoF mandated an increase in the
Government’s production share to offset any advantages derived from treaty concessions
by PSC entities.
Over the last 15 years, PSCs have aimed to address these concerns by incorporating
contractual provisions to nullify the use of treaties. These provisions typically involve
adjusting production shares in accordance with the aforementioned MoF directive. The
typical PSC language is now as follows:
“SKK MIGAS and CONTRACTOR agree that all of the percentages appearing in Section
VI of this CONTRACT have been determined on the assumption that CONTRACTOR is
subject to final tax on profits after tax deduction under Article 26 (4) of the Indonesia Income
Tax Law and is not sheltered by any tax treaty to which the Government of the Republic of
Indonesia has become a party. In the event that, subsequently, CONTRACTOR or any of
Participating Interest Holder(s) comprising CONTRACTOR under this CONTRACT becomes
not subject to final tax deduction under Article 26 (4) of the Indonesia Income Tax Law and/
or subject to a tax treaty, all of the percentages appearing in Section VI of this CONTRACT,
as applicable to the portions of CONTRACTOR and SKK MIGAS so affected by the non
applicability of such final tax deduction or the applicability of a tax treaty, shall be adjusted
accordingly in order to maintain the same net income after-tax for all CONTRACTOR’s
portion of Petroleum produced and saved under this CONTRACT.”
Some older PSC Contractors that are not subject to a “re-balancing” of their production-
sharing entitlement from treaty relief have contested their position with the Indonesian tax
authorities. In the first quarter of 2019, the Supreme Court issued series of decisions
under which it was found, in a majority of cases (but not all), that treaty relief was available
to reduce the BPT in these limited circumstances. That is there was no commercial basis
for an implied after-tax production share. It seems that the Supreme Court’s focus was on
the actual contractual position under the PSCs in question and the individual taxpayer’s
entitlement to the treaty relief.
Readers should note of course that Indonesia’s rules of jurisprudence do not typically
result in binding precedents. Consequently, none of the decisions will necessarily bind
the assessing behaviour of the tax authorities (other than in respect of the assessments
being litigated). It should be noted also that the Tax Court decisions in question, and even
(arguably) the Supreme Court decisions, could still be challenged by the DGT (particularly if
there are two or more “conflicting” Supreme Court decisions on the same/similar dispute).
On this basis these decisions may not represent “settled” law even for the disputes in
question.
102PwC
Indonesian entities – special issues
The “gross of tax” calculation included in the production share assumes a foreign
incorporated PSC holder with a liability to BPT at the rate of 20%.
A PSC however, can be awarded to an Indonesian entity. In such a case, the production
sharing formula will typically be unchanged and so assume a dividend (rather than BPT)
WHT also at the rate of 20%.
Where a PSC is held by an Indonesian entity with Indonesian shareholders, the taxation
of dividends should follow the general taxation rules. Under these rules, for an Indonesian
entity, dividend income is generally tax exempt where the dividends are distributed via
statutory or legal procedures (e.g. the general shareholders meeting, etc.).
It is not clear however, that any PSC related Income Tax reduction will be accepted in
practice.
Oil and gas law election – prevailing tax laws or those prevailing when the
contract is signed
Article 31(4) of Law No. 22 allows parties to a PSC signed from 2001 onwards to choose
which tax laws are to apply:
“The Co-operation Contract shall provide that the obligation to pay taxes referred to in
paragraph (2) shall be made in accordance with:
a) The provisions of tax laws and regulations on tax prevailing at the time the Co-
operation Contract is signed; or
b) The provisions of prevailing laws and regulations on tax.”
However, the exact nature of this election is not clear, including whether the election could
lock-in the uniformity principle. To avoid uncertainty, PSCs often include the following
language:
“It is agreed further in this CONTRACT that in the event that a new prevailing Indonesia
Income Tax Law comes into effect, or the Indonesia Income Tax Law is changed, and
CONTRACTOR becomes subject to the provisions of such new or changed law, all the
percentages appearing in Section VI of this CONTRACT as applicable to the portions of
CONTRACTOR and the GOVERNMENT’s share so affected by such new or changed law
shall be revised in order to maintain the same net income after tax for CONTRACTOR or all
Participating Interest Holders in this CONTRACT.”
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 103
4.4.4 Administration
Regulation
A PSC entity (where foreign incorporated)
is required to set up a branch office in
Indonesia. This branch also gives rise
to a PE. This is the case for all foreign
incorporated PSC interest holders (i.e.
operators and non-operators).
A PSC branch, as a PE, should register
for tax by filing an appropriate registration
application form including the following
attachments:
a. A letter from the branch’s “head office”
declaring the intention to establish
a branch in Indonesia including
information on the branch’s chief
representative;
b. A copy of all pages of the passport of
the branch’s chief representative;
c. A notification letter on the chief
representative’s domicile (issued by a
local government officer);
d. A notification letter on the domicile/
place of business of the branch (usually
issued by a building management
company where the branch is located in
a commercial office building);
e. A copy of the PSC;
f. A copy of the Directorate of Oil and Gas
letter which declares the entity the PSC
holder; and
g. A letter of appointment of the chief
representative from the head office.
Compliance
The registration obligation applies from
the time of commencement of business
activities. Therefore, this includes
the exploration phase (i.e. there is no
entitlement to defer registration until, say,
Commercial operations is declared).
Ongoing tax obligations include:
a. Filing annual Income Tax returns for
each interest holder (although see
comments on GR-79 above);
b. Filing monthly reports on the Income
Tax due on monthly liftings as well as
the remittance of Income Tax payments
(for each interest holder-but obviously
only after production);
c. Filing monthly returns for withholding
obligations (for the operator only);
d. Filing monthly and annual EIT returns
(for each interest holder – noting that
generally for a non-operator this will be
a nil return);
e. Filing of monthly VAT reports (please
refer to our detailed explanation in the
VAT section); and
f. Maintaining books and records
(in Indonesia) supporting the tax
calculations (for the operator only).
On 18 February 2014, the DGT issued
Regulation No.5/2014 on the format and
content of the annual income tax return for
PSC taxpayers. In addition to distinguishing
liftings and non-liftings income Contractors
became required to complete and attach
(as appropriate) six special attachments
concerning:
a. Corporate Income Tax for PSC
Contractors;
b. BPT/dividend tax for PSC Contractors;
c. Details of Costs in Exploration/
Exploitation Stage for PSC Contractors;
d. Depreciation Schedule for PSCs;
e. Details of the Contractor’s portion of
their FTP share; and
f. Details of Changes in the Participating
Interests.
Since April 2012, the DGT attempted to
consolidate all PSC Contractors into the Oil
and Gas Tax Office (KPP Migas) which has
specific responsibility for the industry.
104PwC
Joint audits
Pursuant to a Memorandum of Understanding (MoU) entered into between SKK Migas,
BPKP and the DGT, Joint Audits by these bodies have been carried out on all operational
PSCs and non-producing PSCs with an approved PoD since April 2012.
This was the first systematic DGT audit of PSCs meaning that many PSCs experienced a
DGT tax audit for the first time.
Common issues raised by the DGT to date include:
a. Direct/Indirect PSC transfers – the DGT policy in this area continues to evolve. The
“substance over form” concept is being applied with GR-79/PMK-257 tax levied in
a wide range of PSC- transfers scenarios. The DGT regularly reconciles taxpayer
declarations on individual PSC values with public announcement, etc.
b. Long-standing cost recovery in audit findings – the DGT has unilaterally issued tax
assessments despite long- standing cost- recovery audit findings still being subject to
discussions/negotiations with SKK Migas and/or BPKP. This creates risk around the
coordination of work amongst the DGT, SKK Migas and BPKP.
c. General reconciliations between the financial reports and the monthly tax returns – the
DGT often queries discrepancies between the amounts disclosed in financial reporting
and the tax objects disclosed in the monthly WHT and VAT returns. Whilst this type of
request is common with general taxpayers, this should be less relevant for PSC entities
as their financial data may be limited to the FQR.
d. “Head office” overhead allocations – since 1998, WHT and VAT on head office overhead
allocations has been effectively exempted through DGT Letter S-604. While the DGT
appears still to be accepting S-604, the challenge has shifted to satisfying the nature of
the charges as “head office”.
e. Benefits in Kind (BiK) – BPKP/SKK Migas can have a different view on BiK costs with
SKK Migas often allowing cost recovery but the DGT then arguing for an Article 21
Employee WHT obligation.
MoF issued Regulation No. 34/PMK.03/2018 (MoF-34) which stipulates procedures and
guidance for the implementation of Joint Audits conducted by SKK Migas, BPKP and
DGT. MoF-34 probably was issued to accommodate the industry concern over the lack of
coordination amongst the three institutions in performing audits on PSC Contractors. In late
2023, MoF issued MoF Regulation No. 94/2023 (MoF-94) as the amendment to MoF-34.
Whilst most of the changes stipulated in MoF-94 are mainly related to the administrative
procedures of the joint audit process, one of the notable changes introduced in MoF-94
is it seems to provide more room for the DGT to conduct a tax audit separately apart from
the joint audit process. Under MoF-34, a separate tax audit may be carried out under
three conditions, i.e. i) if the Contractor files an overpayment tax return; ii) if the tax return
submitted by the Contractor shows a different tax calculation compared to the FQR; and/
or iii) the Contractor does not file the tax return. These three conditions are removed under
MoF-94.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 105
4.4.5 EIT
For PSC entities (acting as the operator), the taxation arrangements for employees are
largely identical to those for other employers. On this basis, there is an obligation for the
operator to withhold and remit Income Tax, and to file monthly returns, in accordance
with either Article 21 or 26 of the Income Tax law. The Article (and thus the tax rate) varies
according to residency of the employee (please refer to PwC Pocket Tax Guide for further
details).
Industry related tax issues include:
a. The treatment of “rotators” or similar semi-permanent personnel. This mainly relates to
ensuring that the correct tax rates are applied; and
b. The treatment of non-cash “BiK”. The treatment can vary according to the era of the
PSC, whether the personnel are working in designated “remote areas” and whether the
operator claims cost recovery for the relevant benefit.
Further, resident employees without an NPWP are subject to a surcharge of 20% on
Indonesian sourced income in addition to the standard WHT. On this basis, a PSC entity
needs to ensure that all employees (including resident expatriates) obtain their individual
NPWP especially if a PSC entity provides salaries on a net of tax basis.
4.4.6 WHT
For PSC entities (when acting as operator), the WHT obligations are largely identical to
those for other taxpayers. On this basis, there is an obligation for the operator to withhold
and remit Income Tax, and to file monthly WHT returns, in accordance with the various
provisions of the Income Tax law (please refer to the PwC Pocket Tax Guide for details).
For PSC entities, the most common WHT obligations arise with regard to:
a. Land and building rental (i.e. Article 4(2) - a final tax at 10%);
b. Deemed Income Tax rates (i.e. Article 15, for shipping at 1.2% and 2.64%);
c. Payments for the provision of services etc. by tax residents (Article 23 - at 2%); and
d. Payments for the provision of services etc. by non-residents (Article 26 - 20% before
treaty relief - noting tax on services provided by foreign drillers is often remitted by the
driller (see Chapter 7.3 below)).
Ring fencing
Pursuant to MoF Regulation SE No. 75/190, an entity may hold an interest in only one
PSC (i.e. the “ring-fencing” principle). There are also no grouping or similar consolidation
arrangements available in Indonesia. This means that the costs incurred in respect of one
PSC cannot be used to relieve the tax obligations of another.
As noted in GR-79/27, PSCs are now ring-fenced by field rather than contract area. This
narrows even further the focus of the ring fencing principle.
106PwC
4.4.7 VAT
General
The sale of hydrocarbons taken directly
from source has historically been exempt
from VAT. PSC entities had therefore never
constituted taxable firms for VAT purposes,
and were not registered for VAT purposes.
Law No. 7/2021 regarding the
Harmonisation of Tax Regulations (HPP
Law - Harmonisasi Peraturan Pajak) was
signed by the President of the Republic of
Indonesia on 29 October 2021 and came
into effect on the same date.
The HPP Law has made significant changes
to the VAT rules, including the foundational
features which have been in place for
decades. These changes include the VAT
rate and the status of several non-taxable
objects. The new VAT provisions were
effective from 1 April 2022.
Article 4A paragraph 2 of the Law No.
42/2009 regarding VAT (“VAT Law”) has now
been amended by the HPP Law to exclude
the “mining or drilling products taken
directly from the source” from non-VAT-able
goods. This means that, by default, crude
oil and natural gas are regarded as VAT-able
goods, and hence any ”delivery” of these
goods could be subject to VAT.
On 12 December 2022, the Government
issued Regulation No. 49/2022 (GR-49)
which provides further confirmation of the
VAT-exempt status of certain deliveries of
goods. GR-49 now confirms that, whilst still
regarded as VAT-able Goods, deliveries of
crude oil and natural gas (among others)
are exempt from VAT. The VAT exemption
is automatically granted (i.e. there is no
requirement to obtain the Tax Exemption
Declaration Letter (SKB - Surat Keterangan
Bebas)).
From a VAT administration perspective, the
PSC entities making the above VAT-exempt
deliveries will still be required to register as
a VAT-able Firm and issue VAT Invoices (with
“exempt” status) on each relevant delivery.
In addition to the above “raw” mining
products, GR-49 also confirms the VAT-
exempt status of the following types of gas
derivatives:
1) LNG (no change from the existing
treatment); and
2) Compressed Natural Gas (CNG).
Input VAT side
The VAT Law stipulates that any input VAT
related to the delivery of exempted VAT-able
goods will not be creditable. The impact
should arguably be no different compared to
the pre-HPP Law conditions.
Irrespective of the above, in our view there
should be room to argue that the pre-
existing input VAT recoverability mechanism
under the PSC (i.e. either reimbursement or
cost recovery) could still prevail due to the
“lex specialis” status of the PSC.
Changes in the VAT rate
The impact of any change in VAT status also
needs to take into account the proposed
increase in the VAT rate (i.e. to 11% in 2022
and to 12% by 2025).
The increase in the VAT rate may
commercially impact post GR-79 PSCs
(which mostly adopt VAT treatment as cost
recovery) as it may to an extent disturb the
portion of hydrocarbon entitlement between
the Government and Contractors.
In summary, the changes to the VAT
treatment for hydrocarbons still leaves
some areas unclear, and may add to the
tax administration burden on the oil and
gas business in Indonesia. If such tax
administration is not carefully managed,
it may lead to significant tax penalties,
sanctions, etc. (e.g. failure to issue a VAT
invoice may lead to a 1% tax penalty on the
tax base).
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 107
In-country supplies – VAT deferment
Pursuant to Presidential Decree No.22/1989
(PD 22) and its implementing regulations,
VAT payments arising from oil, gas and
geothermal exploration and drilling services
were deferred until the time of payment of
the Government Share (when the VAT was
then reimbursed - see VAT Reimbursement
section). This arrangement effectively
eliminated all but a small cash-flow
exposure to VAT charged in these scenarios.
However, in 1995, an amendment to the
VAT Law aimed to end all VAT deferments
by 31 December 1999. The Indonesian
tax authorities interpreted this amendment
as terminating the deferment available
to Production Sharing Contract (PSC)
entities. Consequently, assessments for all
deferred VAT up to this date were issued in
January 2000. Approximately 30 taxpayers
challenged these assessments through the
Indonesian Court system, resulting in mixed
outcomes.
New PSC entities assume no entitlement to
defer VAT payments. On this basis, the 10%
VAT charged on “in-country” goods and
services will need to be paid, and will not be
refunded unless the Government Share is
achieved (and if permitted under the PSC).
Imports – VAT exemption
See Import Taxes below in Chapter 4.4.8.
VAT reimbursement (pre-GR-79)
PSCs issued prior to GR-79 (see below)
typically provide that Pertamina (now SKK
Migas) is to:
“assume and discharge all other
Indonesian taxes [other than Income Tax
including VAT, transfer tax, import and
export duties on materials equipment
and supplies brought into Indonesia
by Contractor, its Contractors and
subcontractors…….
The obligations of Pertamina [now SKK
Migas] hereunder, shall be deemed to
have been complied with by the delivery,
to Contractor within one hundred and
twenty (120) days after the end of each
Calendar Year, of documentary proof in
accordance with the Indonesian fiscal
laws that liability for the above mentioned
taxes has been satisfied, except that
with respect to any of such liabilities
which Contractor may be obliged to pay
directly, Pertamina [now SKK Migas]
shall reimburse it only out of its share of
production hereunder within sixty (60)
days after receipt of invoice therefore.
Pertamina [now SKK Migas] should be
consulted prior to payment of such taxes
by Contractor or by any other party on
Contractor’s behalf”.
In the past, protection from non-income
taxes in PSCs has generally fallen into
two categories. Firstly, certain taxes were
directly covered by SKK Migas, such
as the Property and Building Tax (PBB).
Secondly, some taxes were initially paid
by the Contractor, such as Value Added
Tax (VAT), which were then reimbursed.
Further, and depending upon the PSC era,
the reimbursement shall only be from SKK
Migas’ share of production (i.e. there is
no entitlement to reimbursement until the
PSC goes into production and reaches the
Government share).
Reimbursement is, in practice, also subject
to the PSC satisfying high standards of
documentation (original VAT invoices,
etc.). Where VAT is not reimbursed for a
documentation related to the concern SKK
Migas had, on occasions, allowed VAT to be
charged to cost recovery.
VAT borne during the exploration phase by
PSC Contractors who do not subsequently
move into production will never be
reimbursed, and so the VAT will become an
absolute cost.
108PwC
On 16 August 2019, the MoF issued Regulation No. 119/2019 (PMK-119) which stipulates
updated VAT reimbursement procedures. PMK-119 cancelled the previous MoF Regulation
Nos. 218/2014 and 158/2016 and is effective from the above issuance date.
While most key features are similar to the previous regulations (i.e. points a) to d)), PMK-
119 provides more clarity on several aspects of reimbursement as outlined in points e) and
f) below.
a. That Government Share is to include the Government’s entitlement to FTP (and hence,
VAT reimbursement can be sought once FTP arises);
b. That SKK Migas may offset a reimbursement entitlement against any Contractor
“overliftings” (previously over-liftings were settled in cash);
c. That there is no timeframe for obtaining the full verification on the reimbursement
request from SKK Migas;
d. That reimbursement entitlement excludes input VAT arising from LNG processing,
unless the PSC stipulates otherwise;
e. That a reimbursement is to be subject to confirmation from the DGT via a “Tax
Clearance Document”. Under the previous MoF Regulations, the availability of an
original Tax Clearance Document was compulsory. PMK-119 however provides a more
relaxed requirement on this point as the term “original” was deleted and there is no
requirement for SKK Migas to verify the validity of the Tax Clearance Document;
f. That whenever reimbursement is specifically regulated under the PSC, the mechanism
should follow the provisions under that PSC (rather than PMK-119). This seems to
be an acknowledgement of the “lex specialis” status of the PSC including perhaps to
accommodate unique VAT reimbursement provisions in some early 2000’s PSCs;
g. That, following the issuance of GR No. 23/2015 regarding the management of oil
and gas resources in Aceh province, any VAT reimbursement related to oil and gas
concessions in Aceh province should now be administered by the BPMA rather than by
SKK Migas; and
h. That the authorised officials (within SKK Migas/BPMA) who can provide
recommendations to the MoF (i.e. DGB) for the payment of VAT reimbursement is
expanded to include, not only the Head of SKK Migas/BPMA, but also the Deputy of
SKK Migas/BPMA.
VAT reimbursements are denominated in Rupiah at the historical exchange rates and so the
reimbursement mechanism carries an exchange risk.
VAT cost recovery (post GR-79)
As noted above most recent PSCs, including those issued post GR-79, have seen the
standard PSC language regarding VAT reimbursement removed in favour of an entitlement
to include all indirect taxes (including VAT) as operating costs of the Contractor (i.e. as a
cost recoverable item).
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 109
4.4.8 Import taxes
On 31 December 2019, the MoF issued two regulations to synchronise a number of existing
import facility regulations applicable to PSC Contractors. These can be summarised as
follows:
Table 4.10 - Summary of import taxes facilities regulations
No Regulation Effective Date Replaces/Amends
1.
MoF Regulation No. 217/
PMK.04/2019 (PMK-217)
– for import taxes facility
(Import Duty, VAT and
income tax). Specific to the
oil and gas sector.
1 March 2020
• MoF Regulation No. 20/
PMK.010/2005 (import taxes
facility for pre-2001 PSCs)
• MoF Regulation No. 177/
PMK.011/2007 ((only) Import Duty
exemption for post 2001 PSCs)
2.
MoF Regulation No. 198/
PMK.010/2019 (PMK-198)
– specific to import VAT
facilities. Applicable to all
sectors including the oil and
gas sector.
23 December 2019
MoF Decree No. 231/KMK.03/2001
as most recently amended by MoF
Regulation No. 137/PMK.010/2018
(import VAT facility)
Sources: MoF-217/2019, MoF-198/2019, MoF-20/2005, MoF-177/2007, MoF Decree-231/2001 (as amended by MoF-
137/2018)
Some of the key features are as follow:
1) PMK-217
Historically the import facilities applicable to PSCs were scattered across various
regulations. With the enactment of PMK-217, the MoF attempted to “pool” the
arrangements under a single regulation which applies to all generations of PSCs (including
GS PSCs).
A summary of the import facilities (which are ultimately unchanged) applied to each
generation of PSC can be outlined as follows:
Table 4.11 - Summary of import tax facilities applicable to Production Sharing
Contracts (PSC)
Incentives
Cost Recovery PSCs - Generations
GS PSCsFully adjusted to
GR-271)
Not adjusted with
Fully GR-272)
Import Duty (exempt) (a) (b) (c)
VAT (not collected) (a) (b) (c)
Article 22 Income
Tax (not collected)
(a) (b) (c)
Source: MoF-217/2019, GR-27/2017
Note:
1) Fully adjusted to GR-27, but can be classified as pre-2001 PSCs, pre-GR-79 PSCs
(2001-2010), post-GR-79 but pre-GR-27 PSCs (2010-2017), and post-GR-27 PSCs
(post 2017)
110PwC
2) Predominantly pre-2001 PSCs, for which:
(a) Facilities apply during exploration only (i.e. up to PoD). Incentives during
exploitation apply according to project economics
(b) Facilities apply during the entire contract period
(c) Facilities apply during exploration and up to the commencement of commercial
production
Other important features of PMK-217 include:
a. Type of goods: applies to imported goods which:
(i) Are not produced locally; or
(ii) Are produced locally but do not meet the required specifications; or
(iii) Are produced locally but in insufficient quantity.
b. Validity period: the validity of the facility is 12 months from approval.
c. “Extended” facility for vendors/suppliers: PMK-217 seems to have extended the
import facility beyond the “project owner” (as the importer of record) to the relevant
suppliers/vendors, provided that the vendor is stated in the application and the relevant
procurement contract is attached to the application.
d. No claw back: goods covered under this facility can be reexported, transferred to other
PSC Contractors or moved to other PSC work areas without triggering any claw back.
This is subject to SKK Migas approval, and a notification should be sent to the Tax
Office.
2) PMK-198
PMK-198 is an updated regulation which confirms the “non-collection” of import VAT for
goods which are also exempt from Import Duty. This is a generic regulation applicable to all
industries, including goods imported in the PSC sector.
Furthermore, confusingly, PSC imports during the exploitation phase still do not appear to
be granted a VAT facility via PMK-198, as no underlying Import Duty exemption exists.
4.4.9 Tax dispute process
Taxpayers are entitled to object against unfavourable tax assessments. Requirements
include that the objection:
a. Be prepared for each assessment;
b. Be in Bahasa Indonesia;
c. Indicate the correct tax amounts;
d. Include all relevant arguments; and
e. Be filed within three months of the assessment date.
The ITO is required to make a decision on an objection within twelve months. Failure
to decide within this timeframe means that the objection is deemed to be accepted. A
taxpayer should pay at least the amount agreed during the tax audit closing conference
before filing an objection. If the objection is rejected, any underpayment is subject to a
surcharge of 30%. This underpaid tax and surcharge is not due if the taxpayer files an
appeal with the Tax Court regarding the decision objected to.
Appeals
Taxpayers are entitled to appeal to the Tax Court against unfavourable objection decisions.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 111
Requirements include that the appeal letter:
a. Be prepared for each decision;
b. Be in Bahasa Indonesian;
c. Indicate all relevant arguments;
d. Be filed within three months of the date of the objected decision; and
e. Attach a copy of the relevant decision that is being objected against.
Based on the Tax Court law, at least the agreed amount of the tax due on the underlying
assessment should be settled before filing an Appeal. However, this payment requirement
now contradicts the Tax Law (i.e. there is a mismatch between the Tax Administration
law and the Tax Court law). In practice, the tax court will not insist on payment in these
circumstances.
The Tax Court will typically decide on an Appeal within 12 months. Any underpaid tax
resulting from a Tax Court decision is subject to a surcharge of 60%.
Request for reconsideration
For Tax Court decisions delivered after 12 April 2002, taxpayers are entitled to file
“reconsideration requests” to the Supreme Court. The Reconsideration Request must be
submitted within three months of receipt of the Tax Court Decision (for the Appeal).
Interest penalties/compensation
Late payments of tax are subject to interest penalties at varying rates based on the Ministry
of Finance interest rates (MIR) issued on a monthly basis. Tax refunds attract a similar
interest rate using the following formula: MIR/12. The interest penalty and compensation
are capped at 24 months.
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide111
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4.5 Commercial considerations
When reviewing a PSC, potential investors should consider the following issues:
Table 4.12
Topics Issues
Abandonment
Costs
• SKK Migas has included an abandonment clause in the PSC since 1995 which
provides that Contractors must include in their budgets provisions for clearing,
cleaning and restoring the site upon the completion of work.
• To be recoverable (and tax deductible), funds should be physically remitted into a
joint bank account between SKK Migas and Contractor. As any funds set aside for
abandonment and site restoration are cost recoverable and tax deductible unused
funds at the end of the contract are transferred to SKK Migas.
• For PSCs which do not progress to the development stage any costs incurred are
considered sunk costs.
DMO Gas
• Historically, there was no DMO obligation associated with gas production.
• GR-35 introduced a DMO obligation on a Contractor’s share of natural gas.
• Recent PSCs have also included the DMO obligation requirement for gas, whose
impact should be carefully observed.
Carry
arrangements
(JOBs)
• Some PSCs (as JOBs), require private participants to match Pertamina’s sunk costs
and to finance Pertamina’s participating share of expenditures until commercial
production commences. These are known as carry arrangements.
• After commercial production commences, Pertamina is to repay the funds provided
plus an uplift of 50%, in which the uplift should be taxable (at 20% final tax from
gross amount).
Head office costs
• The administrative costs of a “head office” can generally be allocated to a PSC
for cost recovery purposes. PMK-256 stipulates a cap of 2% of annual cost
recoverable spending.
• PMK-256 also indicates that the amount that a PSC is able to recover will be
dependent upon approval from SKK Migas, which may be lower than 2%. The type
of approval required depends on whether or not the PSC is in the Exploration or
Exploitation phase as follows:
- Exploration: the approval is to be ascertained from the WP&B, and monitoring
of the allocation cap will be done over the exploration period (i.e. it would not be
adjusted until the end of the exploration period); or
- Exploitation: specific written approval must be obtained from BP Migas and the
cap will be monitored each year (i.e. the WP&B will not be sufficient evidence to
support the allocation once exploitation has commenced).
• Due to uniformity, a tax deduction is also available but allocations above the
permitted cost recovery are not tax deductible. These allocations technically create
WHT and VAT liabilities (i.e. as cross-border payments). Pursuant to MoF Letter No.
S-604 of 24 November 1998, the Government indicated that it would implement
arrangements to “bear” these taxes on behalf of PSC entities.
• However, MoF Letter No.S-604 was arguably never fully implemented and so has
never actually provided a tax exemption. The ITO historically have focused on head
office costs in tax audits.
• Recent development indicates that, Article 26C of GR-27 has now confirmed the
“exemption” of WHT and VAT from indirect head office allocations. This appears to
be a formalisation of the long established principle set out under S-604.
Associated
products
• Later-generation PSCs promote contractors developing associated products from
their petroleum operations. Questions remain as to whether earnings from the
sale of the associated products will be creditable to operating costs (treated as
by-products under GR-79 and credited against cost recovery), or treated as profit
from oil and gas. The commercial feasibility and profitability of additional product
development is subject to a proper review and analysis.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 113
Topics Issues
Interest recovery
• A PSC entity is generally not allowed cost recovery for interest and associated
financial costs.
• Subject to specific approval, Contractors may be granted interest recovery for
specific projects. This facility should be pre-approved and included in the PoD.
However, SKK Migas states that interest recovery is only granted for PoDs that
have been approved prior to the promulgation of GR-79.
• From a taxation point of view, where a Contractor is entitled to cost recovery there
is also an entitlement to tax deductibility.
• The interest-recovery entitlement will generally reference the pool of approved but
un-depreciated capital costs, at the end of an agreed “period” of time. The “loan”
attracting the respective interest is generally deemed to be equal to the capital
spending on the project. Depreciation of the spending is treated as a repayment of
the loan. Consequently, the “interest” in question may not be interest in a technical
sense.
• Interest paid is subject to WHT with potential relief granted under various tax
treaties. As a precaution, most Contractors gross up the interest charged to reflect
any WHT implications.
• Pertamina typically allowed a gross up for Indonesian WHT at the rate of 20%.
Some PSC entities have been successful in reducing this rate via a tax treaty. This
is even though the “interest” may not satisfy the relevant treaty definition.
Investment
credits
• An investment credit is provided as an incentive for developing certain capital
intensive facilities including pipelines and terminal facilities.
• The credit entitles a PSC entity to take additional production without an associated
cost. An investment credit has therefore traditionally been treated as taxable.
• More difficult questions have arisen with regard to the timing of investment credit
claims. For instance, an investment credit should generally be claimed in the first
year of production and any balance should be carried forward (although there are
sometimes restrictions on carrying forward).
Take or Pay
• A gas supply agreement may include provisions for a minimum quantity of gas to
be taken by buyers on a take-or-pay basis. If buyers take less than the committed
quantity of gas they must still pay an amount (as per the agreement) in relation to
the shortfall.
• Take-or-pay liabilities may arise if buyers have taken less than the committed
quantity of gas under the agreements. The shortfall in the gas taken by buyers, if
any, results in a take-or-pay liability for make-up gas to be delivered to buyers in
the future.
• It is unclear whether the tax due should be calculated based on the payments
(based on the committed quantity to be taken by the buyer) or based on the
quantity of gas delivered to the buyer.
Land rights
• Historically, Pertamina (as a regulator which is assumed by SKK Migas) took a
central role in acquiring surface rights for oil and gas development.
• Oil and Gas Law No. 22/2001 requires the Contractor to obtain the relevant land
rights in accordance with the applicable local land laws and regulations.
• The process of obtaining appropriate land rights can be time consuming and
cumbersome although Law No. 2/2012 on acquisition of land for development in
the public interest (and its implementing regulation PR No.71/2012 and subsequent
amendments in PR No.40/2014) seeks to overcome some of the issues.
• Entitlement to the Contract Area under a PSC does not include any rights to land
surfaces, however, given the change in the treatment of indirect taxes (including
VAT and Land & Buildings Tax) under GR-79 this became a material exposure in
2013 and onwards for many PSC holders.
114PwC
Topics Issues
“Net Back
to Field”
Arrangements
• Contractor calculations for transactions involving Trustees or similar arrangements
(e.g. for piped gas/LNG, etc.) typically commence with a revenue figure which
has been netted against certain post-lifting costs (e.g. trustee, shipping, pipeline
transportation, etc.). Once again, this follows the uniformity principle which
generally disallows cost recovery on spending past the point of the lifting.
• Net back to field costs are generally also treated as being outside of a PSC entity’s
WHT and VAT obligations. With the growing involvement of the DGT in joint audits,
this position may be subject to review.
Sole risk
operations
• Typically, all costs and liabilities of conducting an exclusive (sole risk) operation
for drilling, completing and equipping sole risk wells are borne by “the Sole Risk
Party”. The Sole Risk Party indemnifies the Non-Sole Risk Parties from all costs
and liabilities related to the sole risk operation.
• Should the sole risk operation result in a commercial discovery the Non-Sole Risk
Parties have historically been given the option to participate in the operation. If
the Non-Sole Risk Parties agree to exercise their options, the Non-Sole Risk Party
pays to the Sole Risk Party a lump sum amount which can typically be paid either
through a “Cash Premium” or “In-Kind Premium” to cover past costs incurred as
well as rewards for risk taken.
• It is not clear whether these premiums should be treated as taxable liftings income,
other non-lifting income under GR-79/27 or ordinary income, although under GR-
79/27 they are more likely to be treated as other non-lifting income.
Unitisations
• Unitisation is a concept whereby the parties to two or more PSCs agree to jointly
undertake the E&P operations on a defined acreage (which typically overlaps
between the two PSCs) and share risks and rewards from such activity in an agreed
proportion.
• Typical issues under a unitisation arrangement include:
- Re-determination of costs and revenues;
- Maintenance of separate records;
- Ring-fencing;
- Audits; and
- Impact on overall PSC economics
Transfer of PSC
interests
• Historically, transfers of PSC interests had not generally been taxed. This was the
case irrespective of whether the transfer was:
1. Via a direct transfer of a PSC interest (i.e. as an asset sale);
2. As a partial assignment such as a farm-out; or
3. Via a sale in the shares of a PSC holding entity (i.e. as a share sale).
• GR79/27 imposes a 5%/7% transfer tax according to whether the PSC is in the
exploration or the exploitation stage. GR-79/27 still protects partial assignments
such as farm-outs during the exploration stage if that interest has been held for
more than three years and the transfer is not intended to generate a gain. However,
where the transfer is for “non-risk sharing” purposes, the 5% final tax will be
imposed on gross proceeds. GR-79/27 also imposes a 7% final tax on gross
proceeds for transfers during the exploitation stage except where they are to a
“national company”. Please see Chapter 4.4.2 for more details.
• In addition, at least prior to 19 June 2017, PMK-257 stipulates that a BPT applies
to a transfer of a direct or indirect interest in the PSC. The BPT is due at a rate of
20% of the “economic profit” less the 5% or 7% tax already paid on the transfer.
The imposition of BPT was then removed under the application of GR-27 starting
19 June 2017.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 115
Topics Issues
• The overall of GR-79/PMK-257 is however unclear in many areas including:
a. the application to share transfers especially where they fall outside Indonesian
natural tax coverage (essentially GR-79’s rules on tracing powers)
b. how BPT should be accounted for (at least for pre-GR-27 transfer) and which
treaties can be relied on (bearing in mind BPT is ultimately a tax cost for the
vendor entity)
c. is a group restructuring (i.e. with no change of control and therefore no
requirement for SKK Migas approval) meant to be taxed?
d. when does a carry provided as part of the farm-out constitute compensation
for the PSC transfer?
e. when is a contingent payment subject to tax?
f. what is the cost base in calculating the profits for BPT purposes (at least for
pre-GR-27 transfers)?
• In the first quarter of 2019, the Tax Courts have issued several decisions on some
outstanding cases and found:
- transfer consideration: that transfer consideration relevant to a PSC transfer,
in an entity sale scenario at least, should only extend to amounts paid for
the shares in the PSC-holding entity (or higher up the holding structure – this
tracing aspect remains unclear). In other words transfer consideration should
not extend to amounts received for the transfer of a receivable due from a
PSC entity even where carried out as part of the transfer;
- BPT: that PMK-257, as the implementing regulation to GR-79, was technically
incorrect in applying a 20% BPT on the transfer of a PSC interest (in an
entity sale scenario at least). This was because the Transfer Tax component
under GR 79 represented a final tax meaning that no further tax (including
BPT) should be due. The Tax Court felt this position was supported by the
GR-27 amendments to GR-79 where the BPT exposure for PSC transfers was
formally eliminated; and
- treaty protection: that, in an entity sale scenario at least, treaty relief should
be accepted to the extent that a treaty operates to prevent/mitigate the
operation of GR-79 (subject to satisfying Indonesia’s treaty use rules). The tax
treaty relevant to the operation of GR-79 should also be that applicable to the
vendor of the shares (in a context of an entity sale scenario).
As the above outcomes relate to Tax Court decisions it is possible that the DGT
may file appeals to the Supreme Court, so these positions could still change.
There are also some arguable contradictions within the decisions themselves.
These include that in some decisions treaty relief was recognised according to
the legal form of the transaction whilst other decisions appeared to indicate that
the GR-79/27 liability arose at the asset level irrespective of the legal form of the
transaction. Overall, caution should therefore still be exercised in analysing the
impact of these decisions with regard to any individual tax positions.
That aside, in regard to PSC transfer, GR-79/27 has now been amended by GR-
93 on 31 August 2021. Please refer to the PSC Transfer section above for a more
detailed explanation.
Domestic gas
pricing for certain
industries
Following the issuance of Regulation No. 15/2022 and No. 10/2020, the current
gas producers shall negotiate with gas buyers (for gas prices and transportation
tariffs) and with SKK Migas on potential adjustments to the production split
calculation to neutralise the impact of price adjustments on gas producers’
entitlement.
For potential gas investors, the new gas pricing regulation shall be considered
for overall project economics prior to the submission of a PoD if the gas output
might be marketed to certain industries as stipulated in the above regulations.
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4.6 Documentation for planning and reporting
4.6.1 PoD (Articles 90-98 of GR-35)
A PoD (also known as a field development plan) represents development planning on one or
more oil and gas fields in an integrated and optimal plan for the production of hydrocarbon
reserves, considering technical, economic and environmental aspects.
Prior to Law No. 22, an initial PoD only needed Pertamina Director approval. After Law
No. 22, an initial PoD in a development area needs approval from both SKK Migas and the
Minister of Energy and Mineral Resources. Subsequent PoDs in the same development
area only need SKK Migas approval. Generally, the time needed for PoD approval is around
ten weeks, although the process can take in excess of one year for very large projects.
A PoD is typically a complex document that outlines the proposed development of a
particular commercial discovery. The scope and scale of PoDs will vary enormously
depending on the size of the project but will typically cover the following information:
a. Executive summary;
b. Geological findings;
c. Development incentives;
d. Reservoir description;
e. EOR incentives;
f. Field development scenarios;
g. Drilling results;
h. Field development facilities;
i. Project schedule;
j. Production results;
k. Health, Security, and Environment (HSE) & CD;
l. Abandonment;
m. Project economics; and
n. Conclusion.
PoDs that are presented to the Minister (and therefore those that are for the development of
oil or gas discoveries in the first field, as opposed to subsequent fields) must contain:
a. Supporting data and evaluation of exploration;
b. Evaluation of the reserves;
c. Methods for drilling development wells;
d. Number and location of production and/or injection wells;
e. Production testing/well testing;
f. Pattern of extraction;
g. Estimated production;
h. Methods for lifting the production;
i. Production facilities;
j. Plans for use of the oil and gas; and
k. Plans for operations, economics and state and regional revenues.
A PoD revision could be performed in the following conditions:
a. Changes in the development scenario;
b. Significant changes to the oil and gas reserves compared to the initial PoD submitted;
and
c. Changes in investment costs.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 117
4.6.2 AFE
As part of the SKK Migas supervision and
control over the execution of the PSCs,
each of the projects in the exploration and
development phase should prepare an AFE
for SKK Migas approval. For other projects,
BP Migas’s approval is required if budgeted
expenditure is equal to or greater than
USD500,000.
An AFE should include the following
Information:
a. Project information in sufficient detail
to allow for BP Migas’s analysis and
evaluation;
b. Total budgeted costs; and
c. Total costs that have been incurred.
The time required for AFE approval, AFE
revision and AFE close-out is around 10-15
days, although the process is considerably
longer for complex and large project AFEs.
An AFE can be revised:
a. Twice before the project commences or
before the tender has been awarded.
b. Where the project has commenced prior
to reaching 50% of total expenditure
and prior to reaching 70% of physical
completion.
Revisions should be made if the total AFE
costs are projected to over/under-run 10%
or more and/or the individual AFE cost
component is projected to over/under-run
by more than 30%.
4.6.3 WP&B
The WP&B is the proposal of a detailed
action plan and annual budget as
consideration for the condition,
commitment, effectiveness and efficiency
of the Contractor’s operations in a contract
area. The WP&B covers the following:
a. Exploration (seismic and geological
survey, drilling and G&G study),
lead and prospect, and exploration
commitment;
b. Production and an effort to maintain its
continuity:
1. Development plan;
2. Intermittent drilling;
3. Production operations and
workovers;
4. Maintaining production; and
5. EOR projects (Secondary Recovery
and Tertiary Recovery).
c. The costs allocated for those
programmes are as:
1. Exploration;
2. Development drilling and
production facilities;
3. Production and operations; and
General administration, exploration
administration and overheads.
d. An estimation of:
1. Entitlement share;
2. Gross Revenue, Oil and Gas Price,
Cost Recovery, Indonesia Share,
Contractor Share;
3. Unit cost (USD/Bbl.);
4. Direct Production Cost;
5. Total Production Cost;
6. Cost Recovery; and
7. Status of unrecovered cost.
WP&B generally includes the following
schedules:
a. Financial Status Report;
b. Key Operating Statistics;
c. Expenses/Expenditure Summary;
d. Exploration and Development
Summary;
e. Exploratory Drilling Expenditure;
f. Development Drilling Expenditure;
g. Miscellaneous Capital Expenditure;
h. Production Expenses Summary;
i. Production Facilities Capital
Expenditure;
j. Miscellaneous Production Capital
Expenditure;
k. Administration Expenses Summary;
l. Administration Capital Expenditure;
m. Capital Assets PIS Old/New;
n. Depreciation Old/New;
o. Detailed Program Support Listing;
p. Production/Lifting Forecast; and
q. Budget Year Expenditure.
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The WP&B proposal should be submitted to
SKK Migas for approval three months before
the start of each calendar year. Before SKK
Migas grants approval, some changes to
the WP&B proposal may be requested. In
granting approval for WP&Bs, SKK Migas
follows the guidance of GR No. 25/2004
Article 98, which lists certain mandatory
considerations such as: long-term plans;
success in achieving activity targets;
efforts to increase oil and gas reserves
and production; technical activities and
the viability of cost units; efficiency; field
development plans previously approved;
and manpower and environmental
management.
Once approved, the Contractor may revise
the WP&B provided there is reasonable
cause such as:
a. The annual work plan turns out to be
unrealistic; or
b. The estimated cost departs significantly
from the budget.
The proposed WP&B revision must be
accompanied by the reason for the change.
For urgent changes to an original annual
WP&B, revisions may be submitted to SKK
Migas before June.
Generally, the WP&B approval process
takes around 22 working days, although the
process is considerably longer for complex
and large WP&B.
4.6.4 FQR
On a quarterly basis, an operator of a PSC
area should submit its FQR to SKK Migas.
The FQR primarily consists of a comparison
between the budgeted and actual revenue
and expenditures. The FQR should be
submitted to SKK Migas within a month of
the end of the relevant quarter. A typical
FQR consists of a summary front page with
supporting schedules attached.
4.6.5 Foreign Exchange Report
(FCR) and offshore borrowing
Foreign exchange Report including the
offshore loan report to BI
Law No. 24 of 1999 on Currency Flow
and Exchange Rate System and its
implementation regulation, being PBI No.
21/2/PBI/2019 on Foreign Exchange Activity
Report and PBI No. 21/1/PBI/2019 on Bank
Foreign Debts and Other Bank Liabilities
in Foreign Exchange require non-financial
institution companies (including oil and
gas companies) to submit a report of their
foreign-exchange activities in Indonesia
every month to BI.
The foreign exchange report should include
the information about the following:
a. Transaction on the trading of goods,
services, and other transactions;
b. The principal data of the off-shore
borrowing and/or Risk Participation
Transaction (RPT);
c. Plan on withdrawal and/or payment of
off-shore borrowing and RPT;
d. Realisation of withdrawal and/or payment
of off-shore borrowing and RPT;
e. Foreign financial liabilities position and
amendments; and
f. Plan on new offshore loans and their
amendments.
In practice, the above report must be
submitted online through the borrower’s
reporting account in BI’s system. Failure to
submit this report will subject to an
administrative sanction in the form of a
written warning by the BI.
Reporting obligation in relation to
offshore borrowing
• Report to MoF
In relation to offshore borrowing and in
addition to the BI reporting, a borrower
(including an Indonesian oil and gas
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 119
company) is also required to submit a
report to the MoF starting on the effective
date of each of facility agreement and
each subsequent three-month period.
In practice, this report is submitted
concurrently with the reporting obligation to
the BI, which is no later than the 15
th
day of
the month following the date of the facility
agreement. However, the regulation is silent
on the sanctions for noncompliance with
this requirement.
In addition to the above, SKK Migas, under PTK
007, mandates that PSC Contractors must use
a state-owned bank for both the vendor and
payer’s accounts with respect to payments for
goods and services. Please see Chapter 4.2.4
above for further details.
4.6.5.1 Prudential principle on
offshore borrowing for non-bank
corporations
PBI No. 16/21/PBI/2014 (as amended by
PBI No. 18/4/2016) and SE No. 16/24/DKEM
requires all non-bank corporations with offshore
borrowings to implement prudential principles
by fulfilling the following conditions:
a. a minimum hedging ratio being 25% of
the negative difference between current
foreign-exchange assets and current
foreign-exchange liabilities which will be
due between three months and six months
after the end of a quarter;
b. a minimum liquidity ratio of 70%, calculated
by comparing the company’s current
foreign-exchange assets and current
foreign-exchange liabilities which will be
due within three months of the end of the
reporting quarter; and
c. a minimum credit rating of BB- or its
equivalent from credit ratings agencies
approved by the Indonesian Financial
Services Authority.
Photo source: PwC
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Gross Split
Production Sharing
Contracts
5
5.1 Regulation-08 (as amended by
Regulation-52, Regulation-20 and
Regulation-12) - GS PSC features
In 2017, the Ministry of Energy and Mineral Resources (MoEMR)
issued Regulation-08 (as amended by Regulation-52, Regulation-20
and Regulation-12) introducing a PSC scheme based on the “Gross
Production Split” methodology. This represented a landmark change
to Indonesia’s PSC arrangement, moving away from the cost-recovery
mechanism that has been in place for nearly 50 years.
On 15 July 2020, the MoEMR issued Regulation-12 as the third
amendment to Regulation-08. The amendments reflect a gradual shift
away from the emphasis on GS PSCs, arguably in response to the
lukewarm response to the GS PSC format from a number of industry
players.
Regulation-12 gives the MoEMR the authority to choose the contract
type for PSC Working Areas, whether this be in a GS or traditional cost-
recovery format. This discretion is applicable to all new PSCs and to all
extensions of existing PSCs.
At this stage, there are no further details on the extent to which
investors will have the opportunity to negotiate the type of contract with
the MoEMR. As noted earlier, there are some examples of transition
from GS contracts to cost recovery PSCs already having occurred.
The key features of Regulation-08 (as most recently amended by
Regulation-52, Regulation-20 and Regulation-12) are summarised
below:
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Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 121
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide121
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Table 5.1 - GS PSC features
No. Items Description
1. Key Features• A sharing concept based on a gross production and without regard to a cost
recovery mechanism.
• Retention of the following key principles:
a) that the ownership of the natural resources remain with the State until the
point of delivery of the hydrocarbons (as per existing PSCs);
b) that control over the management of operations is ultimately with SKK Migas
(as per existing PSCs – although see below); and
c) that all capital and risks should be borne by Contractors (as per existing PSCs).
• A GS PSC should stipulate at least 17 items, including (but not limited to)
government take, financing obligations, contract term, settlement of disputes,
Domestic Market Obligatio (DMO), contract termination, etc.
2. GS
Mechanism
• This can be illustrated as follows:
Contractor Take = Base Split +/- Variable Components +/- Progressive Components
Government Take = Government share + bonuses + Contractor’s Income Tax
• The Base Split shall constitute the baseline in determining the production split
during the PoD approval. These splits are:
a) for oil: 57% (Government); 43% (Contractor)
b) for gas: 52% (Government); 48% (Contractor)
• The Variable Components are adjustments which take into account the status
of the work area, the field location, the features of the reservoir, supporting
infrastructure, etc.
• The Progressive Components are adjustments which take into account oil price
and cumulative production.
• The “actual” production split shall be agreed on a PoD rather than PSC basis.
• Depending upon field economics the MoEMR has the authority to adjust the
production split in favour of either the Contractor or the Government.
• Experience to date indicates that the production split could be quite flexible in
practice as it is generally subject to commercial negotiation with MoEMR and
SKK Migas.
3. SKK Migas’
Role
• This is limited to control and monitoring of GS PSCs.
• Control means to formulate policies on Work Program and Budget (WP&B) (with
the budget reportedly considered to be “supporting information” rather than
requiring approval). The work program (i.e. not the budget) should be approved
within 30 working days of complete documentation being received.
• Monitoring means to supervise the realisation of exploration and exploitation
activities according to the approved work program. The role of SKK Migas is
limited to the monitoring/approving of the work program rather than the budget.
• The 1
st
PoD must be approved by the MoEMR. The Head of SKK Migas can
approve any 2
nd
PoD. Any difference between the 2
nd
PoD and the 1
st
PoD
should be discussed between the Head of SKK Migas and MoEMR with final
approval by the MoEMR.
4. Title • As indicated, ownership of natural resources remains with the State until the
point of delivery of the hydrocarbons.
• Goods and equipment including land (except leased land) used directly in PSC
operations become the property of the State (as per existing PSCs).
• Any technical data derived from the PSC shall belong to the State (as per
existing PSCs).
5. Taxation • The income tax treatment of Contractors follows specific tax rules for upstream
activities. This is stipulated under GR No. 53/2017 (see below).
• Because relief for costs occurs via tax deductions rather than cost recovery, the
key agency for oversight of this area is the ITO.
6. Procurement• Only the goods and equipment which are directly used in the upstream business
will become the property of the Government.
• GS contractors are obliged to follow the provisions of PTK 007 to the extent
specifically stipulated in PTK-007. If it is not specifically regulated in PTK 007,
then the mechanism follows the provisions in the contract.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 123
No. Items Description
7. Transitional
Provisions
• The operation of existing PSCs continues until expiry. However, Contractors
may unilaterally change the GS scheme.
• An option to change is also available for extended PSCs (if initially signed based
on cost recovery arrangements). We understand that, for extended PSCs,
the option to continue with the existing cost recovery arrangements requires
approval from the MoEMR.
• If the PSC format is changed, any unrecovered costs may be taken as an
additional split for the Contractor.
• Under Regulation-12, a PSC that is about to expire but has not been extended
is not automatically “re-awarded” under the GS scheme.
8. Others • The DMO remains at 25% of the Contractor’s entitlement/split and paid by the
Government at ICP.
• Contractors should prioritise the use of local manpower, domestic goods,
services, etc. (note the potential impact on procurement processes).
• Other matters pertaining to Indonesian participation, unitisation, abandonment
and reclamation costs, etc follow prevailing rules.
9. Unrecovered
Costs
Unrecovered investment costs shall be taken into account as an additional split/
take for the existing contractor:
• If a new Contractor joins the PSC, such new contractor should proportionately
bear the unrecovered costs, and the existing Contractor shall deduct that same
portion from its share.
• The reimbursement is included in the new Contractor's operating costs, as
specifically regulated under GR No. 53/2017.
• The settlement of such unrecovered costs should be formalised in a written
agreement between the existing Contractor and the new Contractor.
• The new Contractor shall reimburse the investment costs to the existing
Contractor at least seven days prior to the signing date of the extension or the
new PSC.
• Any late reimbursement will be subject to a penalty of 2.5% per day at a
maximum.
5.2 GR-53 – Tax rules for GS PSCs
On 28 December 2017, the Government issued GR-53 providing an initial outline of the tax
rules for the GS PSCs. The key tax principles are as follow:
a. Pursuant to the preamble, GR-53 flows from Article 31D of the Income Tax Law and,
perhaps surprisingly, from Article 16B of the Value-Added Tax (VAT) Law. As expected,
there is no reference to GR-79/27, meaning that GR-79/27 (as discussed in Chapter 3)
is not relevant to GS PSCs;
b. Pursuant to Article 18, the “Taxable Income” arising from “direct” PSC activities
is calculated as “gross income” less “operating costs” (see below) but with an
entitlement to ten-year tax-loss carry-forward. This ten year period is greater than the
five years available under the general tax law, but represents a significant reduction on
the unlimited carry forward entitlement under conventional PSCs;
c. Pursuant to Articles 18(4) and (5), Taxable Income for “direct” activities is income
relating to the lifting as well as the sale of by-products and other “economic gains”
(see below). The taxable income is taxed at the prevailing rate at the time of signing
the PSC, which is currently 22%. BPT (currently due at 20%) is applicable to after-tax
profits. These rates however are not fixed and so may move with any changes in the
general tax law (although the wording of the actual PSC could be important on this
point).
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However, there is no apparent
prohibition on the utilisation of tax-
treaty relief potentially opening the way
to BPT reductions where relevant treaty
relief is validly available (but see below
for more detailed comments).
Tax calculations are specific to each
contractor, differing from the traditional
PSC approach. In other words,
individual Contractors could validly
calculate taxable income outcomes
different to that derived for the PSC as
a whole. However, a range of issues
may arise in such a case, including how
individual Contractors will ultimately
be tax audited etc. in the absence of
a “PSC-driven” audit process such as
that which currently takes place under
Financial and Development Supervisory
Agency (BPKP) and Special Task Force
for Upstream Oil and Gas Business
Activities (SKK Migas);
d. According to Article 14, taxes are
applied when the contractor receives
the hydrocarbons. This continues the
conventional PSC approach whereby
economic value is initially recognised
upon the Contractor taking title to
their share of hydrocarbons via a lifting
entitlement under the PSC, rather
than necessarily via the sale of the
hydrocarbons. This should also mean
that income from post-lifting activity
(e.g. trading) should not fall within GR-
53;
e. The value of oil is determined using
the Inductively Coupled Plasma (ICP)
(Article 15), while the value of gas
is determined via the price agreed
under the relevant gas sales contract
(Article 16). Again this is in line with
conventional PSCs;
f. Pursuant to Article 19(1), income
separately arising from uplifts is subject
to tax at a final rate of 20% of the uplift
amount. This is consistent with the
taxing outcome under GR-27; and
g. Pursuant to Article 19(2), income
arising specifically from PSC transfers
is subject to tax at 5% or 7% of
the transfer income (according to
whether the PSC is in exploration or
exploitation) with no further tax due on
after-tax income. This means that no
BPT should be due on income from
PSC transfers, which is also consistent
with the revised arrangements under
GR-27 for conventional PSCs. Refer to
our explanation of GR-93 in Chapter
4 (Upstream Sector) for more details
of the PSC transfer tax imposition and
exemption conditions.
In summary, GR-53 provides only the initial
fiscal framework for GS PSCs, with a number
of implementing regulations still to be issued.
While the general fiscal framework appears
broadly in line with that for conventional
PSCs, further regulations are still required
before Contractors can draw more definitive
conclusions.
Nevertheless, the key fiscal differentiators for
GS PSCs include:
a. Contractor-specific tax calculations are
applicable, rather than each Contractor
following a PSC “cut-back” approach;
b. In GS PSCs, the production split is
based on gross production, unlike
traditional PSCs where it occurs after
cost recovery, except for FTP;
c. The Contractor’s GS revenue is subject
to deductions (under GR-53 and the ITL)
rather than cost recovery;
d. There is likely to be an exemption from
all “non-Income Tax” taxes during
pre-production, no incentive during the
post-production period. This means that
essentially Contractors will bear non-
income tax spending (during the post-
production period) at its after-tax cost;
e. A ten-year tax-loss carry-forward
restriction applies (albeit with an
automatic deferral during pre-
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 125
production) rather than the indefinite
period under traditional (cost recovery)
PSCs;
f. There is no apparent “lock-down”
entitlement to a tax rate applicable to
lifting income; although a number of
existing GS PSCs have defined the
ITL as that in place as at the “Effective
Date” of the PSC in question, and thus
“locking-down” the Income Tax rate
to the PSC signing date is apparently
possible; and
g. There are no apparent prohibitions
around treaty use leaving open
the possibility of leveraging treaty
reductions particularly in relation to BPT
(but see below).
5.2.1 GS tax calculation
Key features of the GS tax calculation
include:
a. Similarly to existing PSCs, pursuant to
Article 4, a Contractor’s “gross income”
shall consist of both:
i) Gross income “directly” derived
from PSC activities; and
ii) Gross income arising from
activities “outside” of PSC
activities;
b. Gross income from “direct” PSC
activities is essentially the Contractor’s
share of oil/gas realised from lifting,
less a DMO, plus compensation for the
DMO, plus/minus lifting price variances;
c. Gross income from activities “outside”
of direct PSC activities constitutes
income arising from:
i) Uplifts;
ii) Transfers of PSCs;
iii) Sales of “secondary” (by-)
products arising from upstream
activities; and
iv) Other amounts resulting in an
“economic benefit” (which the
elucidation indicates will extend to
contractual penalty entitlements,
etc.).
As indicated above, items i) and
ii) are subject to specific final tax
arrangements, whilst items iii) and
iv) are simply added to the income
arising from “direct” PSC activities;
d. Pursuant to Article 5, “Operating
Costs” include:
i) “Exploration Costs” including
those arising from exploration
drilling, general and administrative
activities and Geological &
Geophysical (G&G) activities;
ii) “Exploitation Costs” including
those arising from development
drilling, direct production (for oil
or gas), processing activities,
utilities, general and administrative
activities, as well as depreciation
and amortisation; and
iii) “Other Costs” including those
arising from the transportation of
hydrocarbons, post-operational
activities and marketing, as well
as for reimbursements paid to
prior Contractors in the event that
a PSC is terminated pursuant
to the relevant regulations. LNG
processing costs, up to the point
of LNG transfer, are specifically
mentioned in the elucidation. For
both exploration and exploitation,
“general and administrative”
activities include finance costs as
well as “indirect taxes, regional
taxes and regional levies”. Interest
costs nevertheless remain non-
deductible (see comments on
Article 8 below). Indirect taxes are
therefore now also only deductible,
rather than reimbursable,
meaning that GS PSCs are
generally economically inferior
to the “assume and discharge”
arrangements available under
many conventional PSCs.
Although reimbursements for
unrecovered capital costs paid
to prior Contractors are generally
treated as operating costs,
some spending may actually
126PwC
constitute reimbursements of
capital expenditure, and therefore
would be subject to amortisation
(whereas the nature of the costs
being reimbursed is capital
expenditure incurred by the prior
Contractor).
Limitations on deductions
Key features include:
a. that, pursuant to Article 7, the
deductibility of all Operating Costs
(outlined above) are subject to the
satisfaction of a series of general
criteria. These include:
i) that pricing must follow arm’s-
length principles. This opens the
door to more mainstream transfer
pricing requirements for related
party transactions in the upstream
space;
ii) that oil and gas operations must
follow “good” business practices
and be in accordance with the
relevant work programs. It is
however not clear how detailed the
residual work program approval
process is required to be. This is
noting that, if strictly enforced,
this could be seen as effectively
creating a de facto uniformity
principle;
iii) that depreciation is subject to
the asset in question being held
by the State. This is similar to
conventional PSCs;
iv) that direct “head office” charges
must relate to activities that
cannot be “procured locally”.
This requirement will hopefully be
supported by guidelines on how
to measure/determine what can
or cannot be “procured locally”
as this could otherwise be quite
subjective in practice.
In addition, “indirect” head office
allocations must be within MoF
guidelines and be supported
by financial information (e.g.
audited financial statements of
the relevant head office entity).
Neither category of head office
costs appears to be limited to
“Operators” potentially leaving
open the possibility for all
Contractors to achieve deductions
for their individual head offices
expenses (where validly connected
to PSC activities);
Indirect head office charges are
also exempt from Income Tax and
VAT under Article 27;
v) that the deductibility of spending
on a range of other items, e.g. BiK,
donations, environmental activities
and foreign manpower, must
comply with existing regulations.
b. that, pursuant to Article 8, there is no
deduction for spending in respect of:
i) administrative sanctions, fines,
etc.;
ii) payments of Income Tax;
iii) incentives, pension contributions,
etc. for foreign manpower, etc.;
iv) the costs of foreign manpower
without a work permit;
v) legal expenses with no direct
relationship to upstream activities;
vi) costs in respect of mergers,
acquisitions or PSC transfers;
vii) spending on consultants,
corporate re-branding,
management changes, etc.;
viii) interest costs;
ix) royalties. The elucidation extends
this to payments allowing
Contractors access to operational
technologies;
x) third party Income Tax where
(effectively) borne by the
Contractor; and
xi) Government bonuses.
Most of these restrictions mirror those
set out at Article 13 of GR-27. This
is except for costs for marketing (as
indicated above), tax consultants and
commercial audits which now seem to
be deductible.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 127
Pre-production/deferred spending
Key features are as follow:
a. Similarly to existing PSCs, pursuant to Article 12, all pre-production spending,
including that otherwise constituting an outright deduction or expense is still
capitalised. Amortisation of this capitalised spending then commences from the
month of commercial production, on a Units of Production (UoP) basis. This deferment
measure helps address concerns about losing the ability to carry forward tax losses
indefinitely under GS PSCs (see comments above);
b. Pursuant to Article 9(1), post-production spending on amounts creating economic
value of less than one year is deductible in the year in which the expenses are incurred;
c. Pursuant to Article 9(2), post-production spending on amounts creating economic
value for more than one year is depreciable (if relating to tangible assets) or
amortisable (if relating to intangible assets);
d. Pursuant to Article 10, depreciation is on a declining balance basis commencing in
the month in which the relevant asset is PIS, and at rates set out in the Attachment
to GR-53. The relevant elucidation defines PIS as the time when the assets are utilised
and have fulfilled the conditions/requirements set out by SKK Migas. Again, the
reference to SKK Migas criteria gives rise to questions around a de-facto uniformity
principle;
e. Pursuant to Article 11, amortisation should be on a UoP basis, commencing from the
month in which the expense is incurred; and
f. Pursuant to Article 13, spending on approved reserves for remediation, etc. is
deductible in the year in which the contribution is made to a specifically approved joint
bank account with SKK Migas, etc. Any ultimate differences between the reserves and
realisation shall be taxable or deductible, as the case may be.
The tax treatment of a Contractors’ expenditure in the context of a GS PSC can be
summarised as follows:
Contractor’s Expenditure
Post-ProductionPre-Production
All expenditure (capital and
non-capital)
Subject to Tax Office’s
audit etc.
Subject to 10 year-tax
loss carry forward from
year of production
Capitalise and amortise
on a UoPbasis from the
month of commercial
production
If non capital expenditure
(<1 year –useful life)
If capital expenditure (>1
year -useful life)
Subject to 10 year-
tax loss carry
forward from year
of expenditure
Deductible in year
of expenditure
Subject to Tax
Office’s audit etc.
If non tangibleIf tangible
Capitalise and
depreciate on
declining balance
from month of PIS
Subject to Tax
Office’s audit etc.
Subject to Tax
Office’s audit etc.
Capitalise and
amortise on a UoP
basis from the
month incurred
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Administration
That, pursuant to Article 22, all Contractors
are required to:
a. Register for tax;
b. File annual tax returns;
c. Remit tax payments, including monthly
tax instalments based on each
Contractor’s lifting for the prior month;
and
d. Report any PSC transfers to both the
MoEMR and the MoF.
That, pursuant to Article 23, Operators are
required to:
a. Deal with the WHT obligations of
the PSC itself. These obligations
presumably extend only to all jointly
incurred costs. A question however
arises regarding remittances for any
individual Contractor-only spending;
and
b. Manage the bookkeeping of the PSC
itself. These obligations extend to
the keeping of the general financial
records, including traditional financial
statements which (presumably) will now
also become key fiscal documentation.
Incentives
Pre-production period
Pursuant to Article 25, for the pre-
production period (i.e. exploration and
development) the incentives include:
a. An exemption from Import Duty on
goods used for oil and gas operations.
However, it is still unclear how this
can be provided without a general
reference, or without placing reliance
on the Customs Law;
b. The non-collection of VAT on the
import or local procurement of goods
and services used in operations. This
is obviously a wide-ranging incentive
which, in relation to in- country
procurement at least, is superior to that
under conventional PSCs;
c. An exemption from Article 22 on
imports of goods on which the
Contractor is entitled to an Import Duty
exemption as outlined in a) above; and
d. A 100% reduction in PBB.
On 15 June 2020, the MoF issued
Regulation No. 67/PMK.03/2020 (PMK-67),
which provides guidelines on the granting of
VAT and PBB facilities for GS PSCs during
the pre-production period. PMK-67 serves
as the implementing regulation of GR-53,
and is effective from 15 July 2020.
In order to obtain such facilities, the
operator needs to submit an application
to the RTO (via the Tax Office where
the operator is registered) enclosing the
following documents:
a. A confirmation letter from the MoEMR
stating that the Contractor is in the
pre-production stage, and providing the
following information:
i. Name of the Working Area;
ii. List of Contractors;
iii. Names of the operators; and
iv. Effective date of the GS PSC or
approval of conversion (from a
traditional cost recovery PSC);
b. A copy of the GS PSC.
The RTO will then issue the GS Tax Facilities
Letter ((SKFP - Surat Keterangan Fasilitas
Perpajakan) GS) within seven working days
of the application being submitted, which
will be effective from:
a. The effective date of GS PSC (for PSCs
signed post-GR-53);
b. The approval date of PSC conversion
into GS format (for converted PSC); or
c. The effective date of GR-53 (for PSCs
signed pre-GR-53).
The SKFP GS is considered to be invalid
in the event that the contract expires, is
terminated or commences commercial
production.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 129
VAT not collected facility mechanism
The operator needs to provide local vendors
with a copy of the SKFP GS and show them
the original prior to the delivery of VAT-able
goods/services. Local vendors will then
issue their VAT invoices with the statement
“VAT NOT COLLECTED IN ACCORDANCE
WITH GR-53”.
The operator (as a VAT collector) is
therefore:
a. Not obliged to collect and pay the VAT
on local procurement of goods and/or
services;
b. Not required to pay the self-assessed
VAT (SA-VAT), in regard to SA-VAT, as
the VAT facility will be stated on the
SKFP.
PBB reduction mechanism
The Contractor needs to submit:
a. The SPOP; and
b. A copy of the SKFP GS to the Tax
Office where the PBB object is
administered.
The DGT would then issue an SPPT based
on the relevant SPOP, which would also
enclose the PBB (100%) reduction amount
based on the SKFP GS.
In the event that the SKFP GS is submitted
after the issuance of an SPPT, the
Contractor will still be eligible for the PBB
reduction facility.
VAT and PBB clawback
VAT and PBB clawback may apply, along
with the associated late-payment penalty,
in the event that such a facility is used not
in the context of oil operations and/or the
utilisation of an invalid SKFP GS.
There are no incentives offered for post-
production activities, meaning that all such
taxes should simply be deductible.
Pursuant to Article 26, where during the
post-production period there is excess
capacity associated with certain upstream
assets made available to other Contractors
on a cost-sharing basis, then the cost-
sharing receipts will be exempt from Income
Tax and VAT provided certain conditions are
met.
Photo source: PT Pertamina (Persero)
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5.3 Other tax considerations/issues
Whilst not an exhaustive list, below are a number of tax considerations relevant to GS PSCs
which are not dealt with in GR-53. Specific advice should be sought where relevant.
Table 5.2 - Summary of other tax considerations/issues not dealt in GR-53
Topics Tax Consideration / Issues
Conversion of
Conventional PSCs
to GS PSCs.
A. Unrecovered Costs
• Pursuant to Article 32(c) of GR-53 and Article 25(d) of Regulation-08 (as
amended by Regulation-52), any unrecovered costs on conversion to GS shall
be converted to additional split (i.e. additional Contractor’s take provided as
compensation for the unrecovered costs).
• Applies whenever a Contractor voluntarily converts to a GS PSC.
• SKK Migas can audit these costs as part of the conversion process.
• Once the additional split is agreed, then the unrecovered costs are no longer
recognised and cannot be brought into the (new) GS PSC. This is consistent
with Article 8(5) of GR-53 which indicates that any costs incurred prior to
signing of a GS PSC are not deductible.
• Currently, there is no specific formula mandated to calculate the “additional
split”. In practice this has been based on negotiations with the MoEMR and/or
SKK Migas.
• Notwithstanding the above, some Contractors have agreed a carried-forward
cost entitlement (via deductibility) with SKK Migas (presumably without any
additional split).
• Should the costs be forfeited as per GR-53, then a question arises on the
accounting treatment. The carrying value may need to be impaired if the costs
cannot be fully recovered over the life of the operations of the GS PSC.
B. Outstanding VAT Reimbursement
• For post GR-79 PSCs, VAT is generally recovered through cost recovery,
meaning that VAT is treated similar to other unrecovered costs (refer to above).
• However, for a pre GR-79 PSC, VAT may be recovered via reimbursement
which has a greater value than recoverable costs (i.e. effectively a 100%
refund to the contractor).
• GR-53 and the MoEMR Regulations are silent on any special compensation
for outstanding VAT reimbursements if a pre GR-79 PSC is converted to GS.
• We expect that this issue would be subject to separate negotiations with SKK
Migas.
PSC Holding
Structure Options
(PE vs PT)
• A PSC entity holding structure, as either a PE or PT, is essentially tax neutral in
respect of revenue and/or deduction recognition.
• Under a PT structure profit repatriation is via dividends where there are
positive Retained Earnings (R/E). Positive R/E takes into account past losses.
• Under a PE structure, profit repatriation is via a deemed BPR arising
simultaneously with the corporate tax liability (unless reinvested into an
Indonesian PT). The deeming approach ignores past losses.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 131
Topics Tax Consideration / Issues
Reduced BPT rate
entitlement
A. Domestic rules
• Article 18(5) of GR-53 indicates that net taxable income (i.e. after Income Tax)
is subject to further “income tax” pursuant to the prevailing tax regulations (i.e.
a BPT)).
• This potentially acknowledge a Contractor’s obligation to pay BPT but only in
accordance with relevant tax laws including those set out under tax treaties.
• This is consistent with the fiscal framework of the GS PSC (under GR-53)
moving towards the general tax rules.
B. Indonesia’s Tax Treaties
• Indonesia has concluded approximately 67 tax treaties. Most of the treaties
provide a general reduced BPT rate. However, the following should be noted:
a. Some treaties provide no restrictions around the application of reduced
BPT rates for Indonesian PSCs. This means that a reduced BPT rate
should be available;
b. Other treaties include restrictions and “non-discrimination” provisions in
respect of a reduced BPT rate for Indonesian PSCs.
For example the protocol to Indonesia/Japan tax treaty provides:
“5(a) …. But such [BPT] shall not exceed 10% of the amount of such
earnings, except where such earnings are those derived by such
company under its oil or natural gas PSCs with the Government of the
Republic of Indonesia or the relevant state oil company of Indonesia”
“5(b) The above-mentioned tax in respect of the earnings of a company
being a resident of Japan which has a PE in Indonesia derived under its oil
or natural gas PSCs with the Government of the Republic of Indonesia or
the relevant state oil company of Indonesia shall not be less favourably
levied in Indonesia of any third state which has a PE in Indonesia derived
under its oil or natural gas PSCs with the Government of the Republic of
Indonesia or the relevant state oil company of Indonesia”
Sources: GR-53/2017, Regulation-08, GR-79/2010, Indonesia’s tax treaties
5.4 GS PSC accounting - PTK-066/2019
In April 2019, SKK Migas issued guidelines for reporting upstream oil and gas business
activities under GS arrangements, known as PTK-066/2019. These guidelines are
applicable to the preparation and submission of the WP&B, FQR and the Financial Monthly
Report (FMR) to SKK Migas by Contractors. The guidelines cover various topics, including:
a. The procedures for the preparation, submission and revision of the WP&B;
b. The accounting policies and descriptions of line items in the WP&B, FQR and FMR for
a GS PSC; and
c. Asset management arrangements.
The guidelines also make clear that the GS PSC should follow the prevailing tax laws and
regulations, which are currently regulated under GR-53. The guidelines will be adjusted
automatically to follow the tax regulations.
132PwC
Downstream
sector
6
6.1 Downstream regulations
Law No. 22 formally liberalised the downstream market by opening
the sector (processing, transportation, storage and trading) to direct
foreign investment, and ending the former monopoly of the state- owned
oil and gas company PT Pertamina (Persero). Whilst the distribution
of downstream products and blending of lubricants had previously
been conducted by multinationals in Indonesia, since Law No. 22 was
enacted, many domestic and multinational companies have established
themselves in the more capital-intensive areas of the downstream sector.
These areas include:
a. Tank farms/storage facilities for bulk liquids and LPG;
b. The distribution of gas by way of pipelines (Citigas and long-
distance pipelines);
c. Proposed refineries and downstream LNG;
d. LNG regasification terminals; and
e. The retailing of fuel (both subsidised and non-subsidised).
We present below a summary of the key sections of the downstream
regulations, as provided in Law No. 22 and its implementing regulations
GR No. 36/2004 (as last amended by GR No. 30/2009).
6.1.1 Operation and supervision of downstream business
Downstream businesses are required to operate through an Indonesian
incorporated entity (hereafter referred to as a PT company), and to
have obtained a business licence (issued by OSS with the approval and
assessment from the Ministry of Energy and Mineral Resources (MoEMR)
and/or government agencies) through a one-door integrated system.
As indicated in Chapter 3, Investment Coordinating Board (BKPM)
and Downstream Oil and Gas Regulatory Agency (BPH Migas) are
responsible for regulating, developing and supervising the operation of
the downstream industry.
6.1.2 Business licences
A separate business licence is required for each of the following
downstream activities (except where the activity is the continuation of
an upstream activity, in which case a licence is not required):
a. Processing (excluding field processing);
b. Transportation;
c. Storage; and
d. Trading (two types of business licences are required – a wholesale
trading business licence, and a trading business licence).
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Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 133
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide133
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It is permissible for one PT company to
hold multiple business licences.
To obtain a business licence, a PT
company must apply for a Risk-Based
Licensing (Perizinan Berbasis Risiko)
approach, conducted through the OSS
platform, which is integrated with
government agencies (e.g. MoEMR and
BPH Migas) by enclosing administrative
and technical requirements which contain,
at a minimum, the following:
a. Name of operator;
b. Line of business proposed;
c. Undertaking to comply with
operational procedures; and
d. Detailed plan and technical
requirements relating to the business.
The business licences are issued in two
stages:
a. A temporary licence for a maximum
period of five years (i.e. three years,
plus two years of extension), during
which the PT company prepares the
facilities and infrastructure of the
business; and
b. A permanent operating licence,
once the PT company is ready for
operation.
6.1.3 Processing
A PT company holding a processing
business licence must submit to the
MoEMR and BPH Migas operational
reports, an annual plan, monthly
realisations, and other reports. The
processing of oil, gas and/or processing
output to produce lubricants and
petrochemicals are to be stipulated and
operated jointly by the MoEMR and the
Ministry of Trade (MoT).
The Oil and Gas Processing Business
License is valid for a maximum of 30 years
and may be extended for a maximum of
20 years at a time.
Non-integrated gas supply chain
The processing of gas into Liquefied
Natural Gas (LNG), Liquid Petroleum
Gas (LPG), and Gas to Liquids (GTL) is
classified as a downstream business
activity, as long as it is intended to
realise a profit and is not secondary to an
upstream development.
This technically allows for a non-
integrated LNG/LPG supply chain concept
by virtue of:
a. Enabling PSC contractors to be the
appointed seller of gas (including the
Government’s share), to be further
processed by a separate entity;
b. Shorter LNG supply arrangements;
and
c. The possible use of an onshore
project company, sponsored by a
shareholder agreement which receives
initial funds for the development and
operation of a LNG processing plant.
In practice, downstream LNG and
miniature LNG refineries have been
impacted by a multitude of regulatory
issues, including a change in the VAT
treatment of LNG, and concerns over the
adequacy of domestic gas supply.
6.1.4 Transportation
Transportation of gas by pipelines via a
transmission segment or a distribution
network area is permitted only with the
approval of BPH Migas, with licences
being granted only for specific pipelines/
commercial regions.
The Oil and Gas Transportation Business
License shall be valid for a maximum
of 20 years, and may be extended for a
maximum of 10 years at a time.
A PT company with a transportation
business licence is required to:
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 135
a. Submit monthly operational reports to
the MoEMR and BPH Migas;
b. Prioritise the use of transportation
facilities owned by cooperatives,
small enterprises and national
private enterprises when using land
transportation;
c. Provide an opportunity to other
parties to share utilisation of its
pipelines and other facilities used for
the transportation of gas; and
d. Comply with the Masterplan for
a National Gas Transmission and
Distribution Network.
BPH Migas has the authority to:
a. Regulate, designate, and supervise
tariffs, after considering the economic
considerations of the PT company,
users and consumers; and
b. Grant permits for the transportation
of gas by pipelines to a PT company,
based on the Masterplan for a
National Gas Transmission and
Distribution Network.
A PT company may increase the capacity
of its facilities and means of transportation
after obtaining special permission.
6.1.5 Storage
A PT company is required to:
a. Submit its operational reports to the
MoEMR each quarter, or as and when
requested by BPH Migas;
b. Provide an opportunity to another
party to share in its storage facilities;
c. Share storage facilities in remote
areas; and
d. Have a licence to store LNG.
A PT company can increase the capacity
of its storage and related facilities after
obtaining permission from BPH Migas.
Transportation or storage activities
that are intended to make a profit, or
to be used jointly with another party
by collecting fees or lease rentals, are
construed as downstream business
activities, and require the appropriate
downstream business licence and permits.
6.1.6 Trading
A PT company must guarantee the
following when operating a trading
business:
a. The constant availability of fuels
and processing outputs in its trade
distribution network;
b. The constant availability of gas through
pipelines in its trade distribution
network;
c. The selling prices of fuels and
processing outputs at a fair rate;
d. The availability of adequate trade
facilities;
e. The standard and quality of fuels and
processing outputs, as determined by
the MoEMR;
f. The accuracy of the measurement
system used; and
g. The use of qualifying technology.
A PT company is required to:
a. Submit monthly operational reports to
the MoEMR, or at any time required by
BPH Migas;
b. Maintain facilities and means of
storage and security of supply from
domestic and foreign sources;
c. Distribute fuels through a distributor, to
small-scale users under the company’s
authorised trademark;
d. Prioritise cooperatives, small
enterprises and national private
enterprises when appointing a
distributor; and
e. Submit operational reports to the
MoEMR and BPH Migas regarding
appointment of distributors.
A PT company holding a wholesale trading
licence can operate a trading business
to serve certain consumers (e.g. large
consumers). The MoEMR, along with BPH
Migas, may determine the minimum
capacity limit of a storage facility or
facilities of a PT company. The PT
company may start its trading business
after fulfilling the required minimum
capacity.
136PwC
A direct user who has a seaport or
receiving terminal may import fuel oil, gas,
and other fuels, and process the output
directly for its own use, but not for resale,
after obtaining specific approval from the
MoEMR.
A PT company operating an LPG trading
business is required to:
a. Control facilities and means for the
storage and bottling of LPG;
b. Have a registered trademark; and
c. Be responsible for maintaining a high
standard and quality of LPG, LPG
bottling, and LPG facilities.
PT companies operating in the business
of gas trading may include those with a
gas distribution network facility, and those
without. The former should only operate
after obtaining a licence to trade gas
and special permission for a Distribution
Network Area. The latter may only be
implemented through a distribution
network facility of a PT company that has
obtained access to a Distribution Network
Area, and only after obtaining a licence to
trade gas.
The MoEMR has the authority to
determine and set technical standards
for gas, and also the minimum technical
standards for distribution and facilities.
6.1.7 National fuel oil reserve
The MoEMR is responsible for setting
policy regarding the quantity and type
of the national fuel oil reserve and may
appoint a PT company to contribute to
building this reserve. The national fuel oil
reserve is determined and supervised by
BPH Migas. The reserve can only be used
when there is a scarcity of fuel oil, and
once the scarcity is resolved, the reserve
must be returned to its original position.
6.1.8 Standard and quality
The MoEMR establishes and regulates
the type, standard, and quality of fuel oil,
gas, other fuels, and certain processed
products for the domestic market. These
standards are determined by considering
factors such as the technology used,
producer capacity, consumer financial
capability, and adherence to safety, health,
and environmental standards.
A PT company operating as a processing
business must have an accredited
laboratory to perform tests on the quality
of the processing output. Likewise, a PT
company operating a storage business
which carries out blending to produce
fuel oil must provide a testing facility on
the quality of the blending output. If the
PT company is unable to provide a self-
owned laboratory, it is allowed to use an
accredited laboratory facility owned by
another party.
Fuel oil, gas, and processing outputs
in the form of finished products which
are imported or directly marketed
domestically must comply with the quality
standards determined by the MoEMR.
For fuels and processing outputs that are
exported, a producer may determine the
standard and quality based on the buyer’s
request. Fuels and processing outputs
specially requested must have their
determined standard and quality reported
to the MoEMR.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 137
6.1.10 Occupational health
and safety, environmental
management, and development
of the local community
PT companies operating with a
downstream business licence must comply
with provisions relating to occupational
health and safety, the environment, and the
development of local communities.
This responsibility includes developing
and utilising the local community through,
amongst other things, local employment.
Such development must be implemented
in coordination with the regional
government, with priority given around the
area of operation.
6.1.11 Utilisation of local goods,
services, engineering and
design capacity and workforce
PT companies operating with a
downstream business licence must
prioritise the utilisation of local goods,
tools, services, technology, and
engineering and design capacity.
In fulfilling labour requirements, a
downstream PT company must prioritise
the employment of Indonesian workers
according to the required competency
standards. Where Indonesian workers do
not meet the required standards
of competence and occupational
qualifications, the PT company must
arrange for training and development
programs to improve those workers’
capacities.
6.1.9 Availability and
distribution of certain types of
fuel oil
To guarantee the availability and
distribution of certain types of fuel oil,
trading businesses are not currently able
to operate in a fully fair and transparent
market.
The MoEMR has the authority to
designate areas of trading certain types
of fuel oil domestically. This may include
trading fuel oil, where:
a. The market mechanism has been
effective;
b. The market mechanism has been
ineffective; or
c. The market is located in a remote
area.
BPH Migas has the authority to:
a. Designate a trade distribution area for
certain types of fuel oil for corporate
bodies holding a trading business
licence; and
b. Determine joint usage of
transportation and storage facilities,
particularly in areas where the market
mechanism is not yet fully effective or
in remote areas.
c. If necessary, the Government, with
input from BPH Migas, may determine
the retail prices for certain types of
fuel oil by calculating their economic
value.
A PT company holding a wholesale
trading business licence that sells certain
types of fuel oil to transportation users,
or that trades kerosene for household
and small enterprises, must provide
opportunities to the appointed local
distributor. The distributors include
cooperatives, small enterprises, and/or
national private enterprises contracted
with the PT company. The distributor may
only distribute the trademark fuel oil of the
corporate body. The PT company must
report the names of its distributors to BPH
Migas and the MoEMR.
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6.1.12 Sanctions
BPH Migas has the authority to determine and impose sanctions relating to a PT company’s
breach of its business licence. Sanctions increase during the time the breach remains
unremedied, and can include a written reminder, suspension of the business, freezing of
the business, and finally, annulment of the business licence. All damages arising out of any
sanction must be borne by the respective corporate bodies.
Any person who commits:
a. Processing without a Processing Business License shall be punished with a maximum
imprisonment of five years and a maximum fine of IDR 50,000,000,000.00 (fifty billion
rupiah);
b. Transportation as without a Transportation Business License shall be punished with a
maximum imprisonment of four years and a maximum fine of IDR 40,000,000,000.00
(forty billion rupiah);
c. Storage without a Storage Business License shall be punished with a maximum
imprisonment of three years and a maximum fine of IDR 30,000,000,000.00 (thirty
billion rupiah);
d. Trading without a Trading Business License shall be punished with imprisonment of
up to a maximum of three years and a maximum fine of IDR 30,000,000,000.00 (thirty
billion rupiah).
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 139
6.2 Taxation and customs
6.2.1 General overview
Goods and services supplied by downstream operators, contractors and their businesses
are generally subject to taxes under the general tax law. Please see our annual publication,
the PwC Pocket Tax Guide, which can be found at http://www.pwc.com/id, for more
details. Most downstream entities pay taxes in accordance with the prevailing law, although
some activities can be subject to different WHT arrangements and a final tax arrangement.
Practical tax issues to be considered before making any significant investment include the
following:
a. Whether any tax incentives are available for the proposed investment;
b. Whether a PE exists in Indonesia either as part of the proposed investment, or prior to
the new investment;
c. The import tax obligations, especially within the transportation and storage industry;
d. The Income Tax treatment of the revenue stream (noting that there could be a different
Income Tax treatment according to the nature of the transaction);
e. Ensuring that contracts specifically cater for the imposition of WHT and VAT, i.e. the
use of net versus gross contracts;
f. Structuring inter-group transactions and agreements to accommodate the WHT and
VAT implications and any transfer-pricing issues that may arise (for example, inventory
supplies and/or offtake, management fees, financing, etc.); and
g. Structuring certain contracts to minimise VAT and WHT implications.
From a customs perspective, issues include the following:
a. Royalties – Customs (the Directorate General of Customs and Excise (DGoCE))
pursuing duty on royalty payments during customs audits;
b. Transfer-pricing adjustments - multinationals making year-end adjustments. The
DGoCE could charge duty on any additional payments, and ignore any credits received
by the importer;
c. Arrangements with no sale to the importer – examples include leased goods, warranty
replacement, imports by branches, ship to A/sell to B. At best, there is a compliance
burden in determining the alternative basis of the customs value. At worst, the duty
liability may increase significantly;
d. Inventory control in Customs Facilities - companies using customs facilities may have
problems in accounting for the physical inventory as compared to the bookkeeping
records; and
e. Transfers of fixed assets under Customs Facilities - the exempted duties may have to
be paid, where the company has not followed the proper procedures.
Thin capitalisation
On 9 September 2015, the MoF issued Regulation No. 169/PMK.010/2015 (PMK-169),
establishing a general Debt to Equity ratio (DER) limitation of four to one for Income Tax
purposes. PMK-169 became effective on 1 January 2016. According to this regulation, if
debt exceeds equity by a factor of four on a monthly basis, the interest on the "excessive
debt" is non-deductible. MoF 169 provides exemptions from the DER rules for certain
industries, including infrastructure, although the definition of infrastructure is not provided.
Most downstream activities are likely subject to the 4:1 DER limitation.
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On 28 November 2017, the DGT issued PER-25/PJ/2017 (PER-25), with additional
implementing guidelines on the DER calculation and filing arrangements. PER-25 also
introduced a general requirement to file an “offshore” loans report. These rules apply
starting from the 2017 annual returns.
On 7 October 2021, the Indonesian Parliament passed the HPP Law, expanding the
methods to determine the limitation on financing costs deductibility. In addition to the
DER method, the HPP Law allows other internationally accepted methods such as using
a percentage of Earnings Before Interest, Taxes, Depreciation, and Amortisation (EBITDA).
However, the implementing regulations for the HPP Law have not been issued to date.
6.2.2 Tax incentives
Tax incentives may be available to certain investors in the following downstream sectors.
Tax holiday for pioneer investors
On 24 September 2020, the MoF issued Regulation No. 130/PMK.010/2020 (PMK-130),
which revokes the previous MoF Regulation (i.e. PMK-150) related to the Tax Holiday
facility. PMK 130 was effective from 9 October 2020.
Under PMK-130, the benefits of the Tax Holiday facility remain largely the same, whereby
taxpayers may enjoy the Income Tax facility in the form of a Corporate Income Tax (CIT)
reduction of 50-100% for 5-20 years, depending on the investment value. The taxpayer can
also enjoy a 50% or 25% CIT reduction for the next two years after the concession period
ends (depending on the initial investment value).
The key highlights under PMK-130 are as follows:
A. General eligibility
Qualifying criteria include:
a. That the business is in a “pioneer industry”. Within the energy sector, this includes
oil refineries or industries and oil refinery infrastructure, including those using the
Cooperation of Government and Business Entity (KPBU - Kerjasama Pemerintah dan
Badan Usaha) scheme, as well as base organic chemicals sourced from oil and gas;
b. That the applicant is an Indonesian legal entity;
c. That the applicant involves a new capital investment plan;
d. That the project involves a capital investment of at least IDR 100 billion;
e. That the project is carried out through an Indonesian legal entity;
f. That the applicant has never had its Tax Holiday application granted or rejected by the
MoF;
g. That the applicant has never been granted with other tax facilities i.e. Tax Allowance,
additional deduction on labour intensive industry, and Special Economic Zones (KEK -
Kawasan Ekonomi Khusus);
h. That the taxpayer satisfies the DER requirement; and
i. That the taxpayer is committed to start realising the investment plan at the latest one
year after the issuance of the Tax Holiday approval.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 141
B. Avenue for companies not listed as pioneer industries
Companies that are not listed as being in a pioneer industry may also apply for the Tax
Holiday facility. In this regard, PMK-130 now stipulates that the applicant can make a self-
assessment to justify why they should be considered as a pioneer industry in accordance
with the form attached to PMK-130.
The self-assessment form contains criteria in the following categories:
a. Possessing a broad local connection (e.g. using main raw materials produced
domestically, production products used domestically etc.);
b. Having added value or high externalities (e.g. hiring a large number of workers,
investment locations etc.);
c. Introducing new technology (e.g. using environmentally friendly technology); and
d. Being a priority industry on a national scale (e.g. supporting national strategic projects,
building infrastructure facilities independently).
In addition, the self-assessment form also sets out a quantitative scoring system. The
taxpayer must obtain a score of at least 80 in the quantitative criteria assessment form. An
assessment will be carried out to evaluate the quantitative criteria self-assessment.
C. National Strategic Project (PSN – Proyek Strategis Nasional)
There are some beneficial provisions relating to investors that carry out a PSN business
expansion/additional investment through a “spin-off”. Under a spin-off scheme, the capital
investment that is counted (and can enjoy benefits) for the Tax Holiday will include the value
of the investment resulting from the spin-off, in addition to the newly invested capital.
The investment value amount to be used to determine the concession period of the tax
holiday will be either:
a. All of the investment value (i.e. the new investment value and investment value resulting
from the spin-off) – if the new investment value is higher than the investment value
resulting from the spin-off; or
b. The new investment value – if the new investment value is lower than the investment
value resulting from the spin-off.
D. Other administrative and procedural matters
Once the application is granted, the taxpayer is required to submit annual investment and
production realisation reports. PMK-130 now stipulates that if a taxpayer fails to do so in
a timely manner (within 30 days of the year’s end), the DGT will issue a warning letter that
may eventually lead to a tax audit.
It should be noted that Tax Holiday applications from OSS system to the MoF under PMK-
130 now may only be submitted up to four years after the effective date of PMK-130, i.e.
until 8 October 2024.
As with PMK-130, domestic shareholders of the applicant must obtain a tax clearance letter
issued by the DGT.
The decision on the start date of utilisation of a Tax Holiday is determined based on the
field audit, which is intended to verify the conformity of the realisation of the investment
plan and the initial main business activity plan. Adjustment on the entitlement of the Tax
Holiday facility may occur as a result of this audit.
142PwC
PMK-130 now provides a time limit of this audit, i.e. at most 45 working days after the audit
notification letter has been delivered to the taxpayer.
Tax allowances
Pursuant to Investment Law No. 25/2007, the Government can provide incentives to
qualifying investments.
On 12 November 2019, the Government issued Regulation No. 78 Year 2019 (GR-78/2019),
which constitutes an amendment to the regulations on the tax allowances available for
companies that invest in certain business sectors and/or regions.
GR-78/2019 is effective from 13 December 2019, and revokes a series of previous GR (i.e.
GR-18/2015, as amended by GR-9/2016).
The principal tax facilities remain the same, with the following updated features:
a. An “investment credit” equal to 30% of qualifying spending, deductible at 5% p.a over
six years, provided that the assets invested in are not being misused or transferred out
within a certain period, except to be replaced with new assets.
The fixed assets should now satisfy the following conditions under GR-78:
a. that they be new, unless originating from a complete relocation from another
country;
b. that they be listed in the new business license as the basis for obtaining a tax
allowance facility; and
c. that they be owned directly by the taxpayer (not through a lease) and utilised for
the main business activity.
b. Accelerated tax depreciation/amortisation;
c. Reduced WHT rates on payable dividends to non-residents; and
d. An extended tax loss carried forward period, of up to ten years.
The application is made through the OSS system prior to the start of commercial production.
The following tables outline the energy-related sectors that are eligible for this incentive:
Table 6.1 - Summary of oil and gas sectors eligible for tax allowance facility
Business Field Scope of Products
Lubricant Manufacturing IndustryAll products included within the relevant Lubricants business
code Lubricant Business Code KBLI
Oil, Natural Gas and Coal Originated
Organic Base Chemical Industry
All products included within the relevant business code (KBLI),
except for products which have been covered for the tax holiday
facility as regulated under PMK-130
Natural and Artificial Gas Supply• Regasification of LNG into gas using a FSRU
• Coalbed Methane (Non-PSC), shale gas, tight gas sand and
methane hydrate
• Refining and/or processing of natural gas into LNG and/or LPG
• Provision and/or processing of artificial gas resulting from coal
gasification
Sources: Investment Law No. 25/2007, GR-78/2019
143
KEK
On 28 December 2015, the
Government issued Regulation No.
96/2015, which was since revoked
by Regulation No. 40/2021 (GR-40)
that provides facilities for those
who invest in a KEK. The facilities
cover Income Tax, VAT, Luxury-
goods Sales Tax (LST), Import Duty,
and excise.
There have been twenty areas
designated as KEKs.
Free Trade Zone (FTZ -
Kawasan Perdagangan Bebas)
in Batam, Bintan and Karimun
Goods entering an FTZ may enjoy
tax facilities such as Import Duty
and excise exemptions. In addition,
other import taxes (i.e., VAT, LST,
and Article 22 Income Tax) are not
collected.
Bonded zone
A bonded zone (Kawasan Berikat)
allows an exemption of Import Duty,
etc. on imports of capital equipment
and raw materials by companies that
produce finished goods mainly for
export.
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide
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6.2.3 Taxation on the sale of fuel, gas and lubricants by importers
and manufacturers
The taxation on the sale of fuel, gas and lubricants by importers and manufacturers are
regulated under MoF Regulation No. 34/PMK.010/2017, which has been amended by MoF
Regulation No. 110/PMK.010/2018 (PMK-34/110). PMK-34/110 requires importers and
manufacturers to collect Article 22 WHT from the sale of fuel, gas and lubricants, as follows:
Table 6.2
Definition Rate
Sale to
Agent/Distributor
Non-Agent/Non-
Distributor
Fuel
Sale by Pertamina and its
subsidiaries to gas stations
0.25% Final Non-Final
Sale by non-Pertamina to gas
stations
0.3% Final Non-Final
Sale other than the above 0.3% Final Non-Final
Gas 0.3% Final Non-Final
Lubricants 0.3% Final Non-Final
On 26 December 2019, the MoF issued Regulation No. 199/PMK.010/2019, which further
amends certain clauses in PMK-34/110. The amendments do not, however, have a
significant impact on the tax-related areas being discussed in this section.
VAT on commercial sales
Producers or importers are considered taxable entrepreneurs, so general VAT rules apply to
their sales, making them subject to VAT. Typically, producers or importers add VAT to their
sales, which can be credited by the purchaser. Subsequent sales also incur VAT.
The introduction of HPP Law increased the VAT rate to 11% (since 1 April 2022), and 12%
starting 1 January 2025.
Furthermore, the HPP Law now also excludes “mining or drilling products taken directly
from the source” from the list of non-VAT-able goods (negative list). This means that by
default, crude oil and natural gas are regarded as VAT-able goods and hence, any delivery
of these goods could be subject to VAT.
GR No. 49/2022 (GR-49) confirms that although crude oil and natural gas are considered
VAT-able goods, they are exempt from VAT upon delivery. This exemption is automatic,
eliminating the need for a Tax Exemption Declaration Letter (SKB). However, from an input
VAT perspective, any input VAT incurred for these VAT-exempt goods will not be creditable,
similar to the previous treatment.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 145
From the VAT administration perspective, the trading companies making the above VAT-
exempt deliveries will still be required to register as VAT-able firms, and to issue VAT
invoices (with “exempt” status) on each relevant delivery.
6.2.4 Import duties
Import duty on petroleum
Crude oils are classified under Harmonised System (HS) 27.09 (which covers petroleum oils
and oils obtained from bituminous minerals, crude). Both the general Import Duty rate and
the ASEAN Trade in Goods Agreement (ATIGA) rate for crude oil is 0%.
Refined oil products are potentially classifiable under HS 27.10, which covers:
“Petroleum oils and oils obtained from bituminous minerals, other than crude; preparations
not elsewhere specified or included, containing by weight 70% or more of petroleum oils
or of oils obtained from bituminous minerals, these oils being the basic constituents of the
preparations; waste oils”.
The general Import Duty rate ranges from 0% to 5%, depending on the specific product.
The ATIGA duty rate is 0%. Natural gas is classifiable under HS 27.11, which covers
“Petroleum gases and other gaseous hydrocarbons”. The general Import Duty rate ranges
from 0% to 5%. The ATIGA rate is 0%.
Import duty on fuel
For Import Duty on fuel, one should refer to the 2012 Indonesian Customs tariff book under
MoF Regulation No. 06/PMK.010/2017. The HS codes are:
a. 2710.12, which has a 0% Import Duty in general and for the ATIGA duty rate; and
b. 2710.19, which has a general Import Duty rate in the range of 0% to 5% and 0% for
ATIGA.
In addition, the import of fuel is subject to a 2.5% or 7.5% Article 22 Income Tax, and a
10% import VAT.
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide145
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6.2.5 Royalty on fuel oil supply and distribution and transmission of
natural gas through pipelines
General
A PT company must pay a royalty to BPH Migas, where:
a. It carries out the supply and distribution of fuel oil and/or transmission of natural gas
through pipelines; or
b. It owns Natural Gas Distribution network facilities operating at the Distribution Network
Area and/or Transmission Section.
The Natural Gas Distribution Area/Transmission Section is defined as an area/section of the
Natural Gas Distribution Network/Transmission Pipeline which is part of the Masterplan of
the National Natural Gas Transmission and Distribution Network.
Companies that must pay a royalty on the supply and distribution of fuel oil are:
a. PT companies holding a fuel oil wholesale trading business licence;
b. PT companies holding a fuel oil limited trading business licence; and
c. PT companies holding a processing business licence, where the company produces
fuel oil, and supplies and distributes fuel oil and/or trades fuel oil as an extension of its
processing business.
Companies that must pay a royalty on transmitting natural gas are:
a. PT companies holding the Natural Gas Transmission through Pipeline business licence
at the Transmission Section and/or Distribution Network Area that has owned the
special right;
b. PT companies holding a fuel oil limited trading business licence; and
c. PT companies holding a processing business licence, where the company produces
fuel oil, and supplies and distributes fuel oil and/or trades fuel oil as an extension of its
processing business.
Sanctions
Any late payment of royalties is subject to a 2% penalty.
Tariff
The royalty must be settled on a monthly basis, and is calculated as follows (pursuant to
GR No. 48/2019):
Table 6.3
Volume level per Annum Percentage amount
Fuel Oil Sales
Up to 25 million kilolitres
25 million – 50 million kilolitres
Over 50 million kilolitres
0.25% of the selling price
0.175% of the selling price
0.075% of the selling price
Gas Transmission
Up to 100 billion Standard Cubic Feet
Over 100 billion Standard Cubic Feet
2.5% transmission tariff per one thousand Standard Cubic Feet
1.5% transmission tariff per one thousand Standard Cubic Feet
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 147
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide147
148PwC
6.3 Commercial considerations
When reviewing a potential downstream asset, investors should consider a number of
commercial considerations, including the following:
Table 6.4
Topics Issues
Land rights
• The land where a pipeline is located may not be acquired/owned.
• The process of land registration is time-consuming and subject to GR.
• Land ownership may be disputed and/or overlap with Government-
protected forest areas, or with other businesses’ concession rights (e.g.
timber, plantation or mining).
• Any transfer of land and building rights attracts a duty of 5% of the land
value.
Valuation of
underlying fixed
assets and inventory
• Asset costs may be subject to mark-up.
• Equipment may not be in good condition, and hence the NBV may not
reflect its market value.
• The underlying assets may not have been formally verified. Lack of
fixed asset and physical inventory verification increases the risk of non-
existence.
• Special accounting rules apply for turnaround costs.
• There could be contractual or legal obligations for asset retirement.
• Asset validity (including any assets pledged as collateral) may need to be
verified.
• The deductibility of shareholders’ expenditure (e.g. feasibility study,
etc.) incurred before the establishment of the project company may be
scrutinised by the DGT.
• Unutilised tax depreciation expenses for fixed assets may exist if the
project life is less than the tax useful life.
Underlying
regulations and
permits
• Some of the downstream-related regulations, especially those relating to
the rights of access, taxation, and tariff structure, are in a transitional stage.
• There are no customs regulations supporting storage activities. There could
be import taxes and duties leakage, especially for liquid products.
• The requirement to share storage facilities needs to be defined in more
detail.
• A guarantee by a trading business to have a product constantly available
to the distribution network needs to be defined, to ensure optimal inventory
management.
• The requirement to supply to remote areas needs to be clarified.
Stand-by Letters of
Credit
• There is a potential exposure to non-payment by a customer, if there are no
stand-by letters of credit or other credit protection measures in place.
Contractual
commitments
• Investors need to assess the impact of the following on their deals:
- Gas Sales and Supply agreements.
- Gas Transportation agreements.
- Take-or-Pay obligations.
- Ship-or-Pay arrangements (including the deferred revenue impact and
the correct taxation treatment).
- Potential liquidated damages and other exposures (upsides and
downsides).
- The cash waterfall mechanism.
- Avenues for recourse against contractors.
- Line-pack gas (treatment, exposures and accounting).
- Make-up gas (treatment).
- Guaranteed product supply (contract, other arrangements, etc.).
- Related-party transactions.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 149
Topics Issues
Government
relationship
• The Government may intend to control refineries, as has been the case in
the past.
• Restrictions on the further issue of capital/transfers of shares for a certain
period of time.
• The Government usually keeps the right for first refusal, as well as “tag
along” rights, on any future sale.
• The requirement to pledge a shareholding to the Government to secure
performance may need to be considered.
• The form and content of reports to be filed with the MoEMR and regulatory
bodies needs to be understood.
• Further guidance is needed on how private investors will work with the
Government in maintaining national strategic oil and fuel oil reserves.
• Further guidance is required on how investors may set pricing, and how
any subsidy will be paid to investors until such time that the Government
fuel subsidy is fully removed.
• The designation of trading areas and the requirement to market product in
remote areas needs further elaboration.
• The requirement to distribute to remote areas needs to be further defined.
• Expectations of the regulator’s and the Government’s role in the short,
medium and long terms needs to be understood.
• Product pricing restrictions may be applicable in some areas, based on the
prevailing GRs.
Profitability
• Future operations could be subject to volatility in the supply and prices of
key inputs (other than feedstock), e.g. electricity, water, etc.
• There may be significant volatility in storage and transportation costs of
feed stock and finished product.
• Exposures to commodity price movements need to be considered.
• Counterparty performance assessments need to be undertaken.
• Demand forecasting must be considered.
• Operational performance assessment may be needed.
• Distortion of trading performance through related-party transactions and
other undisclosed arrangements is possible.
• Controls and reporting processes need to be undertaken.
• A review of the cost structure and impact on overall economics may be
required.
Technology
• The licensing arrangements for technology may not have been formalised.
• The operators’ technical expertise/credit strength may be questionable.
• There is a general restriction on the tax deductibility of R&D expenditure
when the R&D activities are not conducted in Indonesia.
• Royalty payments to offshore counterparts may attract duty.
Product mix
• The ability to change the product mix and associated costs may be limited.
• The contractual commitments associated with the product mix may be
significant.
Supply chain
• The continuous availability of feedstock to the refining process is
sometimes not secure.
Environmental issues
• Compliance with existing and future environmental regulations (including
remediation/abandonment exposures) may be lacking.
• Remediation costs for the previous activities of the refinery may be
significant.
• The environmental impact may need to be considered.
Strategic value
enhancement
opportunities
• There may be opportunities to improve crude procurement and inbound
logistics costs.
• There may be opportunities to improve refinery utilisation.
• The opportunities to enhance retail outlet throughput may be limited.
• Branding and value capture opportunities need to be identified.
150PwC
Topics Issues
Competition
• Prioritisation of cooperatives, small enterprises and national companies
to own/operate transportation and distribution facilities may hinder
development in the short-term, due to lack of operational experience and
understanding of the industry, as well as potential capital or financing
constraints.
• Overall market growth and product-specific demand and supply need to be
considered.
• Emerging competition in retail market due to liberalisation needs to be
assessed.
Other potential
taxation issues
• The imposition of WHT on the hire of pipelines.
• The imposition of WHT on the hire of oil/gas tanking.
• The adoption of a split contract for Engineering, Procurement, and
Construction (EPC) contracts can be contested.
• The VAT-able status of LNG (now clarified in chapter 4).
• Any related-party transactions (where transactions with a counterparty
exceed IDR 10 billion in a year) should be supported by transfer pricing
documentation which includes an explanation of the nature of transactions,
pricing policy, characteristic of the property/services, functional analysis,
pricing methodology applied and the rationale for the methodology
selected, as well as benchmarking.
6.4 Market developments in Indonesia
6.4.1 Gas pipeline infrastructure
Despite a decline in the status of oil reserves, there is a rise in Indonesia’s natural gas
reserves. Most research reveals that gas will be Indonesia’s fuel for the future. This is also
supported by the fact that the natural gas market in Indonesia grew tremendously during
the past decade and will keep rising in the coming years. Completion of LNG plants, arrival
of FSRUs, and the increasing demand for gas in power generation and transportation has
doubled Indonesia’s consumption, and it is predicted to keep growing in the future.
Although Indonesia has a large amount of potential in the natural gas sector, it needs a lot
of investment to develop infrastructure on the downstream side. It is challenging for
ventures to build receiving facilities, pipelines and other kinds of distribution infrastructure
for the country, which has an archipelagic shape and land issue matters, but the
opportunities are promising, because the Government wants to encourage households and
industries to utilise more natural gas. If natural gas is being pushed up, infrastructure will be
prioritised. As of now, the construction of a natural gas pipeline for households is included
in strategic national projects, and is planned to begin operating this year.
There used to be two major gas pipeline companies: PT Pertamina Gas and PGN. Following
the issuance of GR No. 6/2018 and the designation of PT Pertamina (Persero) as the
state-owned holding company for oil and gas, the Government’s ownership in PGN was
transferred to PT Pertamina (Persero) in April 2018. Subsequently, PGN acquired 51% of PT
Pertamina Gas shares from PT Pertamina (Persero) in December 2018.
Other gas pipeline companies are privately owned, and their pipelines usually tie in to
PGN’s or Pertagas’s main pipelines.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 151
6.4.2 Open access to gas pipelines and gas allocation, utilisation
and price
The Government recognises the need to expand its pipeline network to raise gas penetration
rates and reduce oil dependency. However, gas marketing development in Indonesia is
hampered by slow infrastructure development, limited access to distribution and transmission
pipelines, and multiple layers of traders, resulting in high gas prices to end users.
By auctioning new open access gas pipelines, BPH Migas hopes to pave the way for the
entire distribution network to adopt open access in due course.
On 25 January 2018, the MoEMR issued Regulation No. 4/2018 (as amended by MoEMR
Regulation No. 19/2021), regarding natural gas businesses in downstream oil and gas
business activities. This regulation replaced the previous regulation, i.e. MoEMR Regulation
No. 19/2009. This regulation amends the Masterplan for the National Gas Transmission
and Distribution Network, and authorises BPH Migas to put gas transmission sections to
a tender process. The tender winner will have a contract for 30 years, while the existing
business entities in the distribution network that do not win the tender have the opportunity
to continue their business for 15 years, with BPH Migas and MoEMR to monitor the
feasibility and the economy of the transmission section results.
The other section of MoEMR Regulation No. 4/2018 abolishes the distribution area system
based on the downstream dedicated system in the form of private gas pipes utilised by
business entities to transmit their own gas, and sets out provisions on licensing required
for engaging in natural gas transmission business activities by pipelines, or by using
facilities other than pipelines (in form of CNG or LNG) in certain transmission segments or
distribution network areas, as well as natural gas storage business activities. The holders
of special rights on certain distribution network areas are obligated to develop and provide
natural gas infrastructure in the form of natural gas pipeline networks, and there is also a
procedure for natural gas customers to obtain permission to develop and operate natural
gas pipelines and supporting facilities for their own interests.
Meanwhile, the provisions and procedures on determination of allocation, utilisation and
price of natural gas are regulated in MoEMR Regulation No. 6/2016:
Table 6.5
PerMen No. 6/2016
Order of priorities for
gas allocation and
utilisation
a. Support the Government’s programme to supply natural gas for transportation,
households (≤50m³/month) and small customers (≤100m³/month);
b. Increase national oil and gas production;
c. Fertilisers;
d. Natural-gas-based industry;
e. Electricity; and
f. Industries which uses gas as fuels.
Buyer
a. SOE;
b. BUMD;
c. Gas-fired power/electricity companies;
d. Companies holding Izin Usaha Niaga Gas Bumi;
e. LPG companies; and
f. End-users.
Gas Price Gas price to be approved by the MoEMR through SKK Migas
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On 29 December 2017, the MoEMR issued
Regulation No. 58/2017 whereby the MoEMR
determines gas prices for power plants and
households based on three components
consisting of gas price, gas infrastructure
maintenance costs, and commercial costs
(7% of gas price) based on proposals from
gas producers. Furthermore, on September
20, 2019, the MoEMR issued Regulation No.
14/2019, amending Regulation No. 58/2017,
which stipulates that the project economic
life assumption for gas infrastructure
maintenance cost is 30 years from the first
gas price determination. The change may
impact the overall economic assessment of
the project, as the assumption of a longer
useful life may reduce the overall gas price
calculation.
The provisions and procedures on
determination of allocation and utilisation, as
well as the price of flare gas, are regulated
under MoEMR Regulation No. 30/2021.
According to the regulation, the utilisation of
flare gas can be carried out by: (i) business
entities which hold a processing business
licence and/or natural gas commercial
business license; or (ii) government
institutions.
The offering of flare gas to the business
entities is carried out by SKK Migas, by
considering the following requirements and
criteria:
a. Offering price;
b. Investment commitment;
c. Onstream period;
d. Implementation guarantee (amounting to
1% of the investment value);
e. Annual tax payment receipt; and
f. An application letter.
Furthermore, MoEMR Regulation No. 30/2021
provides that the MoEMR will determine
the sales price of flare gas for the business
entities in accordance with the proposal from
SKK Migas. On the other hand, if the flare gas
will be sold to government institutions, the
maximum sale price is USD 0.35/MMBTU.
Photo source: PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 153
Documents to be submitted by the oil and gas contractors to obtain allocation:
Referring to Chapter V of MoEMR Regulation 6/2016, there are certain summarised
requirements that must be met, as follows:
1. The contractor applies for the allocation and utilisation of natural gas for domestic
demand to the Minister of Energy and Mineral Resources, through SKK Migas.
2. For domestic sales, documents to be included are:
- a PoD and supporting documents; or
- if a PoD is not yet obtained, a reserves report and production profile, the results of
production tests, any production facility, gas deliverability, estimation of production
split; and
- other documents explaining the potential gas buyers, gas volume, infrastructure for
the distribution.
3. For exports, documents to be included should explain potential buyers, volumes,
infrastructure or delivery methods, and a timeline for deliveries.
4. For new allocations, SKK Migas must submit the application to the Minister 60 days
before delivery time.
5. For extensions, the contractor or gas buyer, through SKK Migas, needs to propose the
new gas allocation and utilisation to the MoEMR at least six months before the end of
the existing gas sales agreement.
6. For increases in volume, the contractor or gas buyer needs to submit a proposal/
request to the MoEMR, as per regulation.
The contractor needs to propose a new gas price at least three months before the
termination date of the existing gas sales agreement. If the contractor wants to propose an
additional gas allocation and utilisation agreement, the contractor needs to submit
a proposal to the MoEMR, as per regulation. The gas price which is used in the contract
is determined by the MoEMR. In addition, the gas purchase contract must include an
additional clause regarding the price review.
Requirements for the contractor to propose a gas price to the MoEMR:
1. Proposed price of gas and the price formula justification.
2. Economic value of gas.
3. Gas resources, distribution and delivery principle, volume in the contract, delivery place
per contract, period of distribution, estimated volume of gas distributed daily.
4. Copy of approval from the MoEMR on allocation and utilisation of gas.
5. Copy of approval PoD and supporting documents.
6. Statistics regarding domestic and international gas prices.
7. Copy of the negotiation on price of gas document.
8. Copy of the contract to purchase and sell gas.
154PwC
Service providers to
the upstream sector7
7.1 Equipment and services – general
As discussed in Chapters 4, 5 and 6, the Government and SKK Migas
set the guidelines and make the final decision on large purchases of
most equipment and services provided to the upstream sector.
Purchases by JCCs are effectively Government expenditure
(except for GS PSCs) and generally must be provided from a
local limited liability company. Foreign companies wishing to sell
upstream equipment or services must therefore comply with the
strict procurement rules set out under SKK Migas Guidance Work
Procedure Guidelines (PTK 007) on Goods and Services Procurement
Guidelines as lastly amended in 2018, and the oil and gas services
activities guidance under the MoEMR Regulation 14/2018. However,
the recent SKK Migas Guidance PTK 066 regarding Gross Split (GS)
may imply that PTK 007 only applies to the conventional Production
Sharing Contract (PSC), while the procurement activities for GS PSC
will be self-managed.
MoEMR Regulation No. 14/2018 requires oil and gas supporting
businesses to conduct registration to obtain an oil and gas supporting
business capacity certificate Supporting Business Capability Letter
(SKUP) for oil and gas supporting business capacity development and
improvement. The SKUP is classified into oil and gas construction
services, oil and gas non-construction services, and oil and gas
supporting industry. The previous Registration Certificate has been
abolished by MoEMR, while the issuance of SKUP that previously
required ten days is shortened to three days after all documentations
and requirements are fulfilled (the issuance process may take more
days in practice). The documents required to obtain SKUP can be
found in the attachment of MoEMR Regulation 14/2018.
7.2 Tax considerations – general
Goods and services provided to PSC contractors are taxed according
to Indonesian tax laws, similar to those applicable in the broader
context (refer to the PwC Pocket Tax Guide published annually and
accessible at http://www.pwc.com/id). Some exemptions exist for oil
field service providers concerning import taxes (Article 22 Income Tax,
VAT, and Import Duty).
154PwC
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 155
Photo source: PT Pertamina (Persero)
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide155
156PwC
In the past, service providers benefited from
a PSC client’s master list facility. Please
see our discussion in Chapter 4.4.8 for an
explanation of the master list facility.
Tax audits on service providers have
intensified in recent years, leading to the
establishment of the Oil and Gas Tax Office.
This office is now the registration point
for PSC taxpayers and numerous oilfield
service providers.
Transfer pricing is increasingly under
scrutiny for oilfield service providers, leading
to frequent annual tax audits.
If service providers operate as Indonesian
entities, a debt-to-equity limitation of 4:1
(see Chapter 5.3 for reference) applies.
7.3 Taxation of drilling
services
A positive investment list (previously known
as negative investment list) is provided
under Presidential Regulation (PR) 10/2021
(as lastly amended by PR 49/2021). In
relation to drilling services, PMA entities
have no certain restrictions upon maximum
foreign shareholding.
For further investment restrictions in the oil
and gas industry see Chapter 3.2.2.
7.3.1 Foreign-Owned Drilling
Companies (FDCs)
FDCs, historically carried out their drilling
activities in Indonesia via a branch
or Permanent Establishment (PE) for
Indonesian tax purposes. The taxation
regime that applies to FDCs PEs is outlined
below:
a. The PE of an FDC is subject to a
general corporate income tax rate
based on a deemed profit percentage
of 15% of drilling income (hence an
effective corporate income tax rate of
3.3% assuming a 22% tax rate), plus a
20% BPT.
b. The 20% BPT rate may be reduced
under a relevant tax treaty. A Certificate
of Domicile (CoD) is required to claim
the benefit of any tax treaty (refer to the
new CoD form and the requirements of
DGT Regulation No. 25 of 21 November
2018).
c. Drilling income is generally accepted
as meaning the FDC “day rate” income
received. Reimbursements and handling
charges (including mobilisation and
demobilisation) may not be taxable
income, depending on whether a de
minimis threshold test is exceeded. The
test is generally applied on an annual
rather than a contractual basis.
d. Other non-drilling income, for example
interest, is subject to tax at normal
rates.
7.3.2 Indonesian drilling
companies
Unlike an FDC, Indonesian and PMA drilling
companies are taxed on actual revenues
and costs, and are subject to an income
tax rate of 22%. The drilling services they
provide also currently attract WHT at 2%,
which represents a prepayment of their tax.
Any imports of consumables or equipment
by the drilling companies will generally
attract Article 22 tax at 2.5%, which
represents a further prepayment of their
annual income tax bill.
7.3.3 VAT and WHT
The provision of drilling services is subject
to VAT, with PSC companies acting as
the VAT collectors. This implies that the
output VAT of the drilling service entity is
directly remitted to the Tax Office by the
PSC companies. Consequently, many
service providers may find themselves in a
perpetual VAT refund position. However, it's
important to note that this VAT is technically
refundable only after a Tax Office audit.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 157
These oblige the use of Indonesian flagged
vessels for local shipping from 1 January
2011. Foreign-flagged vessels for specific
types of activities can obtain permission
in form of a permit to use foreign vessels
Permit to Use Foreign Ships (IPKA) issued
for a by a holder of a Shipping Company
Business Licence Sea Transportation
Company Business License (SIUPAL).
Exempted activities include oil and gas
surveys, drilling, offshore construction
and operational support, dredging, and
salvage and underwater work. Exempted
ships for drilling are jack-up rigs, jack-up
barges, self-elevating drilling units, semi-
submersible rigs, deepwater drill ships,
and tender assist rigs. Ships for oil and gas
geophysical, geotechnical, and seismic
(with electromagnetic or broadband triple
source) survey activities are also exempted
based on this regulation. The permit for
the aforementioned ships can be obtained
by satisfying the requirements set out in
Ministry of Transportation Regulation
Although the current Positive Investment
List does not specifically regulate FPSO/
FSO operations, the Department of Sea
Transportation considers these operations
as shipping activities, requiring a shipping
license. Licensing as a shipping company
presents investment and ownership
challenges. Note that Shipping Law No.
17/2008, lastly amended by the Job
Creation Law, mandates that only a
company majority-owned by an Indonesian
entity can register an Indonesian-flagged
vessel. Therefore, a foreign shareholder
holding a 95% interest would not be eligible
to register as an owner of an Indonesian-
flagged vessel and consequently obtain a
shipping license to operate the FPSO/FSO. 7.3.4 Labour taxes
Foreign nationals working for a Foreign-
Owned Drilling Company (FDC) and
becoming residents for tax purposes are
generally subject to Article 21 – Employer
Withholding Tax (WHT) on a deemed salary
basis, as published by the Indonesian Tax
Office (ITO). However, individual tax returns
should still be filed based on the individual’s
actual earnings.
For rotators or non-resident expatriate staff,
it may be possible to file an Article 26 WHT
return (i.e., as a non-resident of Indonesia)
regarding tax withheld from their salary,
resulting in a tax rate of 20%.
Note that lodging a monthly Article 21 Tax
Return for staff does not exempt individuals
from registering for an Indonesian Taxpayer
Identification Number (NPWP) and filing an
Indonesian individual tax return.
7.4 Shipping/ Floating
Production Storage and
Offloading (FPSO) & Floating
Storage and Offloading (FSO)
services
Large crude carriers/tankers are engaged
to ship oil from Indonesian territorial waters
to overseas markets. Similarly, LNG carriers
carry LNG cargo from the Bontang and
Tangguh plants. Converted tankers are also
used as FPSO or FSO vessels.
The shipping industry is heavily regulated.
Both local and international shipping is
open to foreign investment through a
PMA company with a maximum foreign
shareholding of 49%, which is confirmed
in the Positive Investment List Indonesian
Shipping Law No. 17/2008 (as lastly
amended by the Job Creation Law)
generally adopted the cabotage principles
that were first introduced by Ministry of
Transportation Regulation No.71/2005 (as
amended by Ministry of Transportation
Regulation No. 73/2010).
158PwC
7.4.1 Taxation of shipping/FPSO/
FSO service providers
Export Cargos
Shipping involves the provision of services
and is subject to a WHT on the fees
generated.
The relevant WHT rates are generally:
a. Domestic (Indonesian incorporated)
shipping companies – taxed at 1.2% of
gross revenue.
b. Foreign shipping companies - taxed (final)
at 2.64% of gross revenue.
In this regard:
a. The above WHT rates are only applicable
to gross revenue from the “transportation
of passengers and/or cargo” loaded from
one port to another and, in the case of
a foreign shipping company, from the
Indonesian port to a foreign port (not vice
versa);
b. The 2.64% regime presumes that the
foreign shipping company has a PE in
Indonesia;
c. It may not be possible to take advantage
of a tax treaty to reduce BPR rates;
d. It is unclear whether this (final) WHT rate
can be reduced to reflect the recently
reduced corporate tax rate (i.e. 28% for
2009, 25% for 2010 - 2019 and 22% for
2020 and onward);
e. Tax treaties have specific shipping articles
– which may be relevant;
f. Bare-boat charter (BBC) rentals (i.e. with
no service component) might instead be
subject to 20% WHT (before tax treaty
relief); and
g. BBC payments may alternatively be
characterised as royalties.
With regard to the VAT:
a. Shipping services that include an element
of Indonesian “performance” (i.e. being
performed within the Indonesian Customs
Area) are technically subject to VAT.
This is the case irrespective of whether
the shipping company has a PE, and
irrespective of whether the client is an
Indonesia-based entity, or an offshore
entity;
b. A VAT exemption may be available if it can
be argued that the services involve only a
small proportion of Indonesian presence/
performance and should thus be viewed
as entirely ex-Indonesia (i.e. as entirely
international); and
c. Shipping services provided entirely
outside of Indonesia (say under a separate
international contract) may avoid VAT on a
“performance” basis. However, VAT could
still arise on a self- assessment basis
where the services are “utilised” within
Indonesia. Whilst “utilised” is not well
defined, in practice the ITO deems this to
occur in cases where the shipping costs
are charged to Indonesia.
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 159
FPSO/FSO/Floating Storage and Regasification Unit (FSRU), etc. services
Traditionally, many Production Sharing Contract (PSC) entities have classified their FPSO/
FSO service providers as shipping companies, allowing them to fall under the 1.2%/2.64%
tax regime. However, the current perspective suggests that such services do not qualify as
transportation or shipping services and should instead be subject to the general tax law
provisions.
Further in regard to the Land and Building Tax (PBB), on 10 December 2019 the MoF issued
MoF Regulation No. 186/PMK.03/2019 (PMK-186), which includes an updated classification
of “Tax Objects” for the imposition of Land & Building Tax (PBB). PMK-186 became
effective on 1 January 2020.
Under PMK-186, the definition of “land” now is clarified to include Indonesian waters used
for storage and processing facilities, and thereby extends to the various categories of
vessels used on the waters. Furthermore, the definition of “buildings” is also clarified to
include technical construction planted or attached permanently on “land” within Indonesian
waters. This includes, among other things, the processing facilities such as FSO, FPS, FPU,
FSU, FPSO and FSRU.
PMK-186 has therefore formally confirmed the imposition of PBB on typical vessels such
as those used for FSO, FPU, FSRU, etc., which is consistent with the DGT’s position during
past tax audits.
Despite the issuance of PMK-186, tax disputes persist with the DGT, as taxpayers argue
that these vessels should not be subject to PBB, considering their nature as vessels rather
than "buildings." PMK-186 remains in effect as of the current writing, with no amendments
or revocations to date.
Photo source: PwC
Appendices 160PwC
Appendices
Photo source: PwC
160PwC
Appendix I
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide161
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PwC is organised into lines of service, each staffed by highly qualified experienced professionals
who are leaders in their fields, providing:
Assurance provides assurance over any system,
process or controls and over any set of information
to the highest PwC quality.
• Financial Statement Audit
• Risk Assurance:
- Governance, Risk and Compliance
- Digital Trust Solutions
- Internal Audit
• Capital Markets & Accounting Advisory Services:
- Accounting Advisory Services
- Capital Market Services
- Integrated Financial Reporting
• ESG Reporting and Assurance
Tax services optimises tax efficiency and
contributes to overall corporate strategy through
the formulation of effective tax strategies and
innovative tax planning. Some of our value-driven
tax services include:
• Corporate Tax
• International Tax
• Transfer Pricing (TP)
• Mergers and Acquisitions (M&A)
• VAT
• Tax Disputes
• International Assignments
• Customs
• Investment and Corporate Services
• Tax Technology & Strategy
Advisory implements an integrated
suite of solutions covering deals and
transaction support from deal strategy
through to execution and post-deal
services:
• Business Recovery Services
• Sustainable Infrastructure Advisory
• Energy Transition Advisory
• Corporate Finance
• Economics & Policy
• Forensic Services
• Valuation
• Deal Strategy
• Delivering Deal Value
• Transaction Services
• Environmental, Social & Governance
(ESG) Deals Services
Consulting helps organisations to work
smarter and grow faster. We consult
with our clients in order to build effective
organisations, to innovate and grow,
to reduce costs, to manage risk and
regulations, and to leverage talent.
Our aim is to support you in designing,
managing, and executing lasting
beneficial change:
• Digital Transformation
• Risk
• Strategy
About PwC
Appendices 162PwC
Photo source: PwC
Legal services provides solutions of the
highest quality through the provision of cutting
edge legal solutions to support and facilitate
legal developments in Indonesia. We work with
you to understand your commercial objectives
and offer you seamless end-to-end service
across the lifecycle of your project. Our core
value is providing legal services, putting the
needs and priorities of our clients first, while
continuously improving our approach and
continuing to do business ethically. Our legal
services include:
• Mergers & Acquisitions and Corporate
Advisory
• Finance and Financial Regulation
• Capital Markets
• Regulatory
• Carbon Markets Regulation
For companies operating in the Indonesian
oil and gas sector, there are some compelling
reasons to choose PwC Indonesia as your
professional services firm:
• The PwC network is the leading adviser
to the oil and gas industry, both globally
and in Indonesia, working with more
explorers, producers and related service
providers than any other professional
services firm. We have operated in
Indonesia since 1971 and have over 3,600
professional staff, including 89 partners
and technical advisors, specialised in
providing assurance, advisory, consulting,
tax and legal services to Indonesian and
international companies.
• Our Energy, Utilities and Resources
(EU&R) practice in Indonesia comprises
over 550 dedicated professionals
across our lines of service. This body
of professionals brings deep local
industry knowledge and experience
with international industry expertise and
provides us with the largest group of
industry specialists in the Indonesian
professional services market. We also
draw on the PwC global EU&R network
which includes more than 25,700 people
focused on serving energy, power and
mining clients.
• Our commitment to the oil and gas
industry is unmatched, and demonstrated
by our active participation in industry
associations around the world and our
thought leadership on the issues affecting
the industry. This includes our involvement
with the Indonesian Petroleum Association
(IPA) helping to shape the future of the
industry.
• Our client service approach involves
learning about your organisation’s issues
and seeking ways to add value to every
task we perform. Detailed oil and gas
industry knowledge and experience
ensures that we have the background
and understanding of industry issues, and
can provide sharper, more sophisticated
solutions that help clients accomplish their
strategic objectives.
Appendix II
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide163
PwC oil and gas key contacts
Sacha Winzenried
[email protected]
Daniel Kohar
[email protected]
Antonius Sanyojaya
[email protected]
Joshua Wahyudi
[email protected]
Assurance
Dedy Lesmana
[email protected]
Elvia Afkar
[email protected]
Firman Sababalat
[email protected]
Heryanto Wong
[email protected]
Irwan Lau
[email protected]
Toto Harsono
[email protected]
Yanto Kamarudin
[email protected]
Yusron Fauzan
[email protected]
Aditya Warman
[email protected]
Andi Harun
[email protected]
Dodi Putra
[email protected]
Feliex Taner
[email protected]
Galih Baskoro
[email protected]
Lanny Then
[email protected]
Lukman Chandra
[email protected]
Tody Sasongko
[email protected]
Tax
Alexander Lukito
[email protected]
Otto Sumaryoto
[email protected]
Peter Hohtoulas
[email protected]
Suyanti Halim
[email protected]
Turino Suyatman
[email protected]
Omar Abdulkadir
[email protected]
Raemon Utama
[email protected]
Tjen She Siung
[email protected]
Legal
Danar Sunartoputra
[email protected]
Indra Allen
[email protected]
Fifiek Mulyana
[email protected]
Puji Atma
[email protected]
PwC oil and gas contacts
Appendix II
164PwC
PwC Indonesia
Jakarta
WTC 3
Jl. Jend. Sudirman Kav. 29-31
Jakarta 12920 - INDONESIA
T: +62 21 5099 2901 / 3119 2901
F: +62 21 5290 5555 / 5290 5050
www.pwc.com/id
Surabaya
Pakuwon Tower
Tunjungan Plaza 6, 50
th
Floor,
Unit 02-06
Jl. Embong Malang No.21-31
Surabaya 60261 INDONESIA
T: +62 31 9924 5759
www.pwc.com/id
Advisory
Agung Wiryawan
[email protected]
Julian Smith
[email protected]
Michael Goenawan
[email protected]
Hafidsyah Mochtar
[email protected]
Paul van der Aa
[email protected]
Consulting
Martijn Peeters
[email protected]
Peyush Dixit
[email protected]
Pieter van de Mheen
[email protected]
Ian Chriswanto
[email protected]
Yandi Irawan
[email protected]
Appendix III
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide165
Acknowledgements
We would like to convey our sincere thanks to all of the contributors for their efforts in
supporting the preparation of this publication.
Photographic contributions
We gratefully acknowledge and thank the following companies that have provided
photographs for inclusion in this publication (in alphabetical order):
bp Indonesia
Eni Muara Bakau BV
PT Medco Energi Internasional Tbk
PT Pertamina (Persero)
Project team
Sacha Winzenried
Alexander Lukito
Daniel Kohar
Feliex Taner
Lukman Chandra
Puji Atma
Andrew Halim
Denny Irawan
Fitri Budiman
Hansel Tanuwijaya
Kiran Vergis
Raditya Halim
Sabrina Afiyani
Prasta Pradana
Budi Sunariyanto
Pradhita Audi
Yohanes Djingga
Amanda Normanita
Isfan Batubara
Klara Felicia
Laras Taslima
Evan Adison
Kertawira Dhany
166PwC 166PwC
Appendix IV
Energy, Utilities & Resources NewsFlash| Page 1o f 15
Energy, Utilities & Resources NewsFlash
March2023/ No. 73
Recently UpdatedTax Rules for the Coal Mining
Sector
A s readers may b e awa re,A rticle 3 1D of t he Inc ome Tax Law (“I TL” ) allows
the gove rnm ent to issue sp ecial Inco me T ax rules for c ert ain indust ries. As
outlined in En ergy, Utilities and Mining News Flashes V ol. 39/201 1,
Vol.62/201 7, V ol.63/ 2018 and Vol.6 4/201 8,specific tax ru les have al ready
been issue d fo r:
1.the upst ream oil and gas ( or Pro duction Sharing C ontr act (“P S C”)) sect or
via GR-79, GR-27 a nd GR-53; a nd
2.for the mine ral minin g secto r via GR-37.
In April 202 2, the Gover nme nt issued R egulatio n No.1 5 Year 20 22 ( “GR-
15”) t o pr ovide sp ecial rules i n rela tion to boththe t ax and non-t ax state
revenu e (P ene rimaa n Nega ra Buka n Pajak/P NB P) arra ng ements f or th e
coalmining s ector.
Relevant Concession Holders
The tax and PNB P provisions outline d un der GR-15 a re a pplicable fo r the
holders ofthe following:
1.amining business lice nce (Izin Usaha Pe rtam banga n/“IU P”), which isa
licenceto co nduct c oal minin g activities in a minin g busin ess area ;
2.aspecial mini ng busi ness licence (Izin Usa ha Pert amba n gan
K husus/“IUPK”), which isa licence to con duct co al mining activities in a
state res erve area;
3.aspecial mini ng busi ness licence as a “contin uation of co ntract
operati ons” (“IUP KContinua tion” ), which isa licence g ran ted afte r the
expiration of a C oal Cont ract of Work ( “CCoW”);
4.a CCoW with income tax p rovisions stip ulated in the contr act (i.e., wit h
lex specialis taxp rovisions ); an d
5.a CCoW thatfollows the p revailing tax r egulatio ns (i.e. , withoutlex
specialis tax p rovisions).
CCoWs with lex specialis tax provisions are to be hon our ed until th e en d of
the CCoW peri od an d so a re n ot direc tly impact ed by GR-15. However,
even thes e Cont racto rs are oblige d to f ollow the WHTobli gations as
outlined in GR-15.
_____________________ __
Indonesia Energy, Utilities
& Resources New sFlash
Recently UpdatedTax Rules
for the Coal Mining Sector
P1
New Regulation on Coal
Domestic Market Obligation
P7
GR49-2022 –
Update on VAT
Status for Certain Mining
Products
P10
Decree on Expansion of
Mining Areas
P13
Right to Apply for Mining
Business Licence upon the
Existence of aState
Adm inistr ative Cour t Decision
P14
________________ __
Energy, Utilities & Resources NewsFlash| Page 1o f 5
Energy, Utilities & Resources NewsFlash
March2023/ No. 74
Regulation on Electricity Selling Price, Electricity
Lease Network Price, and Electricity Tariff
On 27 April 2 022, the Mi nistry of Energy & Mi neral R esou rces (“ME MR”)
issued MEMR Reg ulation N o. 10 of 20 22 on Proced uresf orApplication for
Approval of Elect ricity Selling Price a nd Electricity Netw or k Lease a nd
Procedur es for Ap plication f or th e Electricity Tariff Stipul at ion (“ME MR R eg
10/202 2”) whic h pr ovides th e pr ocedu res fo r obt aining a p proval fo rselling
price of electricity a nd leasin g of electricity n etworks as w ell aselectricity
tariffs.
1.To obt ain ap proval for t he elect ricity selling price a nd elec tricity network
lease priceholde rsof business l ice ncesfo r elect ricity sup ply in thepublic
interest t he Izin Usa ha Peny ediaan Ten aga Listrik unt uk Kepentinga n
Umumor “IUPTLU”must meet the elec tricity de mand within their area .
1
They a re pe rmitte d to purch ase elect ricity an d/or le ase el ectricity netwo rk
from b usiness e ntities,as follows:
a)holders of IUPTLU fo r th e gen eratio n of electric p ower;
b)holders of IUPTLU a ndowners of theb usiness a reas;
c)holders of abusiness licenceforelectricity s upply fo r priv ate inte rest
(Izin Usaha Pe nyediaa n T enaga Listrik u ntuk Kep enting a n Sendiri);
d)holders ofabusiness licenceforelectricity business supp orting
services (Izin Us aha Jas a Penu njang Tena ga List rik); a nd /or
e)electric powe r sup ply comp anies f rom other count ries.
The sales price of elect ricity and/ ort heleas eprice ofelec tricity networks
must be appr oved bythe MEMR or gover nors i n accor da nce with thei r
respective auth orities. An IUPT LU holde r who owns a b us iness are a
shallapply fo r such app roval in w riting to the MEMR or g o vernors by
enclosing a dministr ative an d tech nical re quire ments.
2
An e valuation o f
1
Article 2 (1) of MEMR Reg 10/2022.
2
Article 4 of MEMR Reg 10/2022.
The administrative requirements include:
a.Profile and business registration number of the business entity selling electricity;
b.Developer appointment letter or letter of intent; and
c.Data and information on share ownership and company management up to the ultimate beneficial owner.
The technical requirements include:
a.Information related to the technical feasibility of sales price of electricity;
b.Information related to the financial feasibility of sales price of electricity;
c.Official report of self-estimated prices; and
d.Official report of price agreement.
_____________________ __
Indonesia Energy, Utilities
& Resources New sFlash
Regulation on Electr icity
Selling Pr ice, Electr icity
Lease Network Price, and
Electr icity T ar iff
P1
An Update on Carbon
Trading and Carbon Tax
Mechanism for Independent
Power Producers (“IPPs”)
P3
__________________ _
Energy, Utilities & Resources NewsFlash | Page 1 of 4
Energy, Utilities &Resources NewsFlash
October 2023 / No. 76
Special Edition - Responding to Climate Change
and Creating Value through Implementing an ESG
Strategy
Introduction
Climate change is an increasingly urgent global issue with far-reaching
implications for businesses. It encompasses environmental challenges such
as rising temperatures, extreme weather events, and sea -level rise.
Simultaneously, businesses face mounting pressure from stakeholders,
particularly investors, who now factor sustainability criteria into their
investment decisions. Governments worldwide are also introducing
regulations aimed at addressing climate change and sustainability.
Consequently, companies must adapt their practices by embracing
sustainable management and operations in response to climate change's
impacts.
To navigate this landscape effectively, businesses require a structured
approach. One of the most effective methods is through the adoption of an
ESG (Environmental, Social, and Governance) strategy. ESG principles
should permeate a company's strategy, guiding its efforts to mitigate climate
change risks, meet stakeholder expectations, and comply with relevant
government regulations on climate change and other sustainability issues.
This article provides an overview of ESG Strategy as a framework to guide
sustainability efforts and explores the benefits companies can derive from its
implementation. Additionally, it delves into a real-life case study, highlighting
the challenges and opportunities faced by a company in developing an ESG
Strategy.
ESG strategy as a framework for sustainability
An ESG strategy serves as a practical starting point for companies
embarking on their sustainability journey. It offers a comprehensive, top-
down approach that helps companies manage risks - both physical and
transition-related, meet stakeholder expectations, and create long-term
value. Moreover, it guides the integration of ESG components into a
company's operations, culture, and values.
_______________________
Indonesia Energy, Utilities
& Resources NewsFlash
Responding to Climate
Change and Creating Value
through Implementing an
ESG Strategy
P1
___________________
To discuss further, please
contact:
Peyush Dixit
[email protected]
or your usual PwC EU&R
contact.
More insights
Visit www.pwc.com/id to
download or order hardcopies of
reports
1. Investor survey of the
Indonesian oil and gas industry
2. Power in Indonesia: Investment
and Taxation Guide
3. Power Industry Survey
4. Mining in Indonesia: Investment
and Taxation Guide
5. mineIndonesia – survey of
trends in the Indonesian mining
sector
6. Mine 2023: 20
th
edition – The
era of reinvention
7. Energy, Utilities & Resources
NewsFlash
8. Indonesian Mining Areas,
Indonesian Oil & Gas
Concessions & Major
Infrastructure, and Indonesian
Major Power Plants and
Transmission Lines Maps
9. Indonesian Pocket Tax Book
10. The Green Hydrogen Economy:
Predicting the decarbonisation
agenda of tomorrow
11. Next in Energy and Utilities
2024
12. Global M&A Trends in Energy,
Utilities and Resources 2024
13. Investing in Energy Transition
Projects
7
9
8
Investing in
Energy Transition Projects
March 2023
www.pwc.com.au
10 13
1 2
11
3
4 5 6
12
Appendices
Oil and Gas in Indonesia: Investment, Taxation and Regulatory Guide 167
© 2024 PwC. All rights reserved. PwC refers to the PwC network and/or one or more of its member firms,
each of which is a separate legal entity. Please see http://www.pwc.com/structure for further details.
PwC Indonesia is comprised of KAP Rintis, Jumadi, Rianto & Rekan, PT PricewaterhouseCoopers
Indonesia Advisory, PT Prima Wahana Caraka, PT PricewaterhouseCoopers Consulting Indonesia, and
PwC Legal Indonesia, each of which is a separate legal entity and all of which together constitute the
Indonesian member firms of the PwC global network, which is collectively referred to as PwC Indonesia.